Oil and Natural Gas Sector 

Hydraulically Fractured Oil Well 

Completions and Associated Gas during 

Ongoing Production

Report for Oil and Natural Gas Sector

Oil Well Completions and Associated Gas during Ongoing Production

Review Panel

April 2014

Prepared by

U.S. EPA Office of Air Quality Planning and Standards (OAQPS)

This information is distributed solely for the purpose of pre-dissemination peer review under applicable 

information quality guidelines. It has not been formally disseminated by the EPA. It does not represent 

and should not be construed to represent any Agency determination or policy.
ii
iii

Table of Contents

PREFACE........................................................................................................................................................1

1.0 INTRODUCTION ............................................................................................................................2

2.0 DEFINITION OF THE SOURCE ....................................................................................................3

2.1 Oil Well Completions...................................................................................................................3

2.2 Associated Gas..............................................................................................................................5

3.0 EMISSIONS DATA AND EMISSIONS ESTIMATES – HYDRAULICALLY FRACTURED 

OIL WELL COMPLETIONS.......................................................................................................................5

3.1 Summary of Major Studies and Sources of Emissions Data.........................................................7

3.2 Fort Berthold Federal Implementation Plan (FIP) – Analysis by EC/R (U.S. EPA) 2012a)........8

3.3 ERG Inc. and EC/R Analyses of HPDI Data ..............................................................................12

3.4 Environmental Defense Fund and Stratus Consulting Analysis of Oil Well Completions (EDF, 

2014) 15

3.5 Measurements of Methane Emissions at Natural Gas Production Sites in the United States (UT 

Study) (Allen et al., 2013).......................................................................................................................17

3.6 Methane Leaks from North American Natural Gas Systems (Brandt et. al, 2014a and 2014b).18

4.0 EMISSIONS DATA AND EMISSIONS ESTIMATES – ASSOCIATED GAS FROM 

HYDRAULICALLY FRACTURED OIL WELLS....................................................................................20

4.1 Greenhouse Gas Reporting Program (U.S. EPA, 2013) .............................................................21

4.2 FLARING UP: North Dakota Natural Gas Flaring More Than Doubles in Two Years (Flaring 

Up) (CERES, 2013) ................................................................................................................................22

5.0 AVAILABLE EMISSION MITIGATION TECHNIQUES...........................................................23

5.1 Reduced Emission Completions (REC)......................................................................................23

5.1.1 Description..............................................................................................................................23

5.1.2 Effectiveness...........................................................................................................................25

5.2 Completion Combustion Devices ...............................................................................................27

5.2.1 Description..............................................................................................................................27

5.2.2 Effectiveness...........................................................................................................................27

5.3 Emerging Control Technologies for Control of Associated Gas ................................................30

5.3.1 Natural Gas Liquids (NGL) Recovery ....................................................................................30

5.3.2 Natural Gas Reinjection..........................................................................................................35

6.0 SUMMARY....................................................................................................................................43
iv

7.0 CHARGE QUESTIONS FOR REVIEWERS ................................................................................45

8.0 REFERENCES ...............................................................................................................................48

Appendix A....................................................................................................................................................1
1

PREFACE

On March 28, 2014 the Obama Administration released a key element called for in the 

President’s Climate Action Plan: a Strategy to Reduce Methane Emissions. The strategy 

summarizes the sources of methane emissions, commits to new steps to cut emissions of this 

potent greenhouse gas, and outlines the Administration’s efforts to improve the measurement of 

these emissions. The strategy builds on progress to date and takes steps to further cut methane 

emissions from several sectors, including the oil and natural gas sector. 

This technical white paper is one of those steps. The paper, along with four others, 

focuses on potentially significant sources of methane and volatile organic compounds (VOCs) in 

the oil and gas sector, covering emissions and mitigation techniques for both pollutants. The 

Agency is seeking input from independent experts, along with data and technical information 

from the public. The EPA will use these technical documents to solidify our understanding of 

these potentially significant sources, which will allow us to fully evaluate the range of options 

for cost-effectively cutting VOC and methane waste and emissions.

The white papers are available at: 

www.epa.gov/airquality/oilandgas/whitepapers.html
2

1.0 INTRODUCTION

The oil and natural gas exploration and production industry in the U.S. is highly dynamic 

and growing rapidly. Consequently, the number of wells in service and the potential for greater 

air emissions from oil and natural gas sources is also growing. There were an estimated 504,000

producing gas wells in the U.S. in 2011 (U.S. EIA, 2012a), and an estimated 536,000 producing 

oil wells in the U.S. in 2011 (U.S. EIA, 2012b). It is anticipated that the number of gas and oil 

wells will continue to increase substantially in the future because of the continued and expanding 

use of horizontal drilling combined with hydraulic fracturing (referred to here as simply 

hydraulic fracturing) which allows for drilling in formerly inaccessible formations.

Due to the growth of this sector and the potential for increased air emissions, it is 

important that the U.S. Environmental Protection Agency (EPA) obtain a clear and accurate

understanding of emerging data on air emissions and available mitigation options. This paper 

presents the Agency’s understanding of air emissions and available control technologies from a 

potentially significant source of emissions in the oil and natural gas sector.

Oil and gas production from unconventional formations such as shale deposits or plays 

has grown rapidly over the last decade. Oil and natural gas production is projected to steadily 

increase over the next two decades. Specifically, natural gas development is expected to increase 

by 44% from 2011 through 2040 (U.S. EIA, 2013b) and crude oil and natural gas liquids (NGL) 

are projected to increase by approximately 25% through 2019 (U.S. EIA, 2013b). The projected 

growth of natural gas production is primarily led by the increased development of shale gas, tight 

gas, and coalbed methane resources utilizing new production technology and techniques such as 

horizontal drilling and hydraulic fracturing. According to the U.S. Energy Information 

Administration (EIA), over half of new oil wells drilled co-produce natural gas (U.S. EIA, 

2013a). Based on this increased oil and gas development, and the fact that half of new oil wells 

co-produce natural gas, the potential exists for increased air emissions from these operations. 

One of the activities identified as a potential source of emissions to the atmosphere 

during oil development is hydraulically fractured oil well completions. Completion operations
3

are conducted to either bring a new oil well into the production phase, or to maintain or increase 

the well’s production capability. Although the term “recompletion” is sometimes used to refer to 

completions associated with refracturing of existing wells, this paper will use the term 

“completion” for both newly fractured wells and refractured wells. In addition, hydraulically 

fractured coproducing oil wells can generate emissions of associated gas during the production 

phase. These processes and emissions are described in detail in Section 2.

The purpose of this paper is to summarize the EPA’s understanding of VOC and methane 

emissions from hydraulically fractured oil well completions and associated gas during ongoing 

production. It also presents the EPA’s understanding of mitigation techniques (practices and 

equipment) available to reduce these emissions, including the efficacy and cost of the 

technologies and the prevalence of use in the industry.

2.0 DEFINITION OF THE SOURCE 

2.1 Oil Well Completions

For the purposes of this paper, a well completion is defined to mean:

The process that allows for the flowback of petroleum or natural gas from newly drilled 

wells to expel drilling and reservoir fluids and tests the reservoir flow characteristics, 

which may vent produced hydrocarbons to the atmosphere via an open pit or tank.

Completion operations with hydraulic fracturing are conducted to either bring a new oil 

well into the production phase or to maintain or increase the well’s production capability 

(sometimes referred to as a recompletion). Well completions with hydraulic fracturing include 

multiple steps after the well bore hole has reached the target depth. These steps include inserting 

and cementing-in well casing, perforating the casing at one or more producing horizons, and 

often hydraulically fracturing one or more zones in the reservoir to stimulate production. Surface 

components, including wellheads, pumps, dehydrators, separators, tanks, and are installed as 

necessary for production to begin. 
4

For the purposes of this paper, hydraulic fracturing is defined to mean:

The process of directing pressurized fluids containing any combination of water, 

proppant, and any added chemicals to penetrate tight formations, such as shale or coal 

formations, that subsequently require high rate, extended flowback to expel fracture 

fluids and solids during completions.

Hydraulic fracturing is one technique for improving oil and gas production where the 

reservoir rock is fractured with very high pressure fluid, typically a water emulsion with a 

proppant (generally sand) that “props open” the fractures after fluid pressure is reduced.

Oil well completions with hydraulic fracturing can result in VOC and methane emissions, 

which occur when gas is vented to the atmosphere during flowback. The emissions are a result of 

the backflow1of the fracture fluids and reservoir gas at high volume and velocity necessary to 

lift excess proppant and fluids to the surface. This comingled fluid stream (containing produced 

oil, natural gas and water) flows from each drilled well to a respective vertical separator and 

heater/treater processing unit. Fluid may be heated to aid in separation of the oil and natural gas 

and produced water. Phase separation is the process of removing impurities from the 

hydrocarbon liquids and gas to meet sales delivery specifications for the oil and natural gas. Oil 

may go directly to a pipeline or be stored onsite for future transfer to a refinery. If infrastructure 

is present, produced gas can be metered to a sales pipeline. If infrastructure is not available, the

produced gas is frequently sent to combustion devices for destruction (e.g., flares) or is vented to 

the atmosphere. 

Recompletions are conducted to minimize the decline in production, to maintain 

production, or in some cases to increase production. When oil well recompletions using

hydraulic fracturing are performed, the practice and sources of emissions are essentially the same 

as for new well completions involving hydraulic fracturing, except that surface gas collection 

 

1 Backflow is the phenomena created by pressure differences between zones in the borehole. If the wellbore pressure 

rises above the average pressure in any zone, backflow will occur (i.e., fluids will move back towards the borehole). 

In contrast, “flowback” is the term used in the industry to refer to the process of allowing fluids to flow from the 

well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup

and returning the well to production.( http://www.glossary.oilfield.slb.com/)
5

equipment may already be present at the wellhead after the initial fracture. However, the 

backflow velocity during refracturing will typically be too high for the normal wellhead 

equipment (separator, dehydrator, lease meter), while the production separator is not typically 

designed for separating sand. 

2.2 Associated Gas

Associated gas is the term typically used for natural gas produced as a by-product of the 

production of crude oil. Industry publications typically refer to associated gas as gas that is coproduced with crude oil while the well is in the production phase and is vented directly to the 

atmosphere or is flared. One published definition for associated gas is “gaseous hydrocarbons 

occurring as a free-gas phase under original oil-reservoir conditions of temperature and pressure

(also known as gas-cap gas).”

2

Therefore, associated gas can include gas that is produced during 

flowback associated with completion activities and gas that is emitted from equipment as part of 

normal operations, such as natural gas driven pneumatic controllers and storage vessels. 

However, in this paper, the term “associated gas emissions” refers to:

Associated gas emissions from the production phase (i.e., excluding completion events

and emissions from normal equipment operations) that could be captured and sold rather 

than being flared or vented to the atmosphere if the necessary pipeline and other 

infrastructure were available to take the gas to market. 

3.0 EMISSIONS DATA AND EMISSIONS ESTIMATES –

HYDRAULICALLY FRACTURED OIL WELL COMPLETIONS 

For consistency in the review of the various data sources and studies and to better understand 

the data discussions presented below, this section presents an overview of the types of the 

emissions estimation processes and the data that have been used in a number of studies to 

estimate VOC and methane emissions from hydraulically fractured oil well completions and 

recompletions. 

 

2 McGraw-Hill Dictionary of Scientific & Technical Terms, 6E, Copyright © 2003 by the McGraw-Hill Companies, 

Inc.
6

1) For estimating source emissions:

 Gas produced during completions of oil wells. Estimated. This type of data would 

provide natural gas or methane production volumes for a completion. The data may be 

estimated using well characteristics (e.g., flow rate, casing diameter, and casing pressure) 

and established emission factors.

 Gas produced by the oil well annually/daily/monthly. Direct measure or estimated. This 

type of data would be similar to the gas produced during completions but would be 

related to ongoing production of associated gas from the well.

 Gas composition. This data is typically composition results from laboratory analysis of 

the raw gas stream to determine methane and other hydrocarbon volume or weight 

percent for use in converting natural gas or methane emissions estimates to VOC. 

 Duration of completion cycle. Length of the completion process in days.

 Use of control technology. Flares, reduced emissions completions (RECs), other control 

technology or none. This information indicates whether a control device or practice is 

used and, if possible, the amount of produced gas captured and controlled.

2) For estimating nationwide emissions:

 Number of oil well completions conducted annually. This information requires

identification of the number of oil wells conducting completions/recompletions annually. 

 Number of oil wells co-producing natural gas. This involves identifying the population of 

oil wells using a definition of oil well based on some production criteria.

 Number of oil wells completions with emissions controls such as RECs or flaring.

There are several available data sources for the data elements described above. Because 

most of the available data were not collected specifically for the purpose of estimating emissions, 

each source has to be qualified to ensure that the data are being used appropriately. In 

characterizing the nationwide emissions, we analyzed several sources of data and qualify each 

source with respect to the different aspects of the emission estimation process. Therefore, in 

addition to describing the data source and any relevant results of analysis, this paper discusses

the implications of the data and/or results of analysis of the data with respect to the quantity of 

data, quantity of emissions, scope of emissions estimates, geographic dispersion, and variability 

in data.
7

Lastly, methodologies used in the emission estimation process are described, such as a 

discussion of the methodology for deriving emission factors or for identifying national 

populations. 

There is variation in the industry as to how oil wells and gas wells are defined. Some

publications do not differentiate at all between them, while others use the amount of oil produced 

or a gas-to-oil ratio (GOR) threshold as a dividing line between a gas well and an oil well. This 

paper does not attempt to choose a specific definition of “oil well,” but instead describes the 

definitions used in each study or data source. The intent of this section of the paper is to present 

the EPA’s understanding of the available data and its usefulness in estimating VOC and methane

emissions from this source. 

3.1 Summary of Major Studies and Sources of Emissions Data 

Given the potential for emissions from hydraulically fractured oil well completions, there 

have been several information collection efforts and studies conducted to estimate emissions and 

available emission control options. Studies have focused on completion emission estimates. 

Some of these studies are listed in Table 3-1, along with an indication of the type of information 

contained in the study (i.e., activity level, emissions data, and control options). 

Table 3-1. Summary of Major Sources of Information and Data on 

Oil Well Completions

Name Affiliation

Year of 

Report

Activity 

Factor

Uncontrolle

d/Controlled 

Emissions 

Data

Control 

Options

Identified

Fort Berthold Federal 

Implementation Plan (U.S. 

EPA, 2012a)

U.S. Environmental 

Protection Agency 2012 Regional Uncontrolled X

ERG/ECR Contractor 

Analysis of HPDI® Data

U.S. Environmental 

Protection Agency 2013 Nationwide Uncontrolled X

Environmental Defense 

Fund Analysis of HPDI® 

Data (EDF, 2014)

Environmental 

Defense Fund 2014 Nationwide Uncontrolled -
8

Name Affiliation

Year of 

Report

Activity 

Factor

Uncontrolle

d/Controlled 

Emissions 

Data

Control 

Options

Identified

Measurements of Methane 

Emissions at Natural Gas 

Production Sites in the 

United States (Allen et al., 

2013)

Multiple Affiliations, 

Academic and Private 2013

26

Completion 

Events

Both -

Methane Leaks from North 

American Natural Gas 

Systems (Brandt et. al, 

2014a and 2014b)

Multiple Affiliations 2013 Regional Uncontrolled -

Data for Petroleum and Natural Gas Systems collected under the EPA’s Greenhouse Gas 

Reporting Program (GHGRP) or the EPA’s Inventory of U.S. Greenhouse Emissions and Sinks 

(GHG Inventory), are not discussed in detail in this section. The GHGRP does not require 

reporting of vented emissions from hydraulically fractured oil well completions. The GHG

Inventory estimates emissions from oil well completions, but does not distinguish between 

completions/recompletions of conventional wells and completions/recompletions of 

hydraulically fractured wells. 

A more-detailed description of the data sources listed in Table 3-1 is presented in the 

following sections, including how the data may be used to estimate national VOC and methane 

emissions from oil well completion events. 

3.2 Fort Berthold Federal Implementation Plan (FIP) – Analysis by EC/R (U.S. EPA) 

2012a)

On March 22, 2013, the EPA published (78 FR 17836) the FIP for existing, new and 

modified oil and natural gas production facilities on the Fort Berthold Indian Reservation 

(FBIR). In support of that effort, the EPA conducted an analysis of 154 applications for synthetic 

minor New Source Review (NSR) permits that indicated VOC emissions were the most 

prevalent of the pollutants emitted from the oil and natural gas production sources operating on 

the FBIR, which contain equipment that handles natural gas produced during well completions, 

phase separation during production, and temporary storage of crude oil (U.S. EPA, 2012).
9

The EPA FIP established federally enforceable requirements to control VOC emissions

from oil and natural gas production activities that were previously unregulated or regulated less 

strictly. The FIP requires a 90%-98% reduction of VOC emissions from gas not sent to a sales 

line using pit flares, utility flares and enclosed combustors, all technologies which were found to 

be standard industry practice on the FBIR. The analysis included a large dataset of combustion 

control equipment cost information based on three well/control configuration scenarios. 

The FBIR dataset includes: 

 533 production wells from five major operators

 Average controlled and uncontrolled VOC emissions from oil wells for wellhead gas,

heater/treaters, and storage tanks

 Oil production data

 Number of sources; storage tanks, combustors, flares, and if a pipeline is present

 Current capital and annualized cost estimates for combustion and REC control options

 Gas composition data (for each permit application)

 Projected 2,000 new wells or 1,000 well pads per year between 2010 and 2029.

The data provided for the FBIR, although useful, has certain qualifying limitations. For 

instance, the FBIR data is primarily for wells producing from the Bakken and Three Forks 

formations, which limits it to a regional dataset. Also, the FBIR data showed high variability in 

oil well production rates and in product composition. This variability may not be representative 

of other formations. Also, according to the North Dakota Department of Health, the Bakken 

formation typically contains a high amount of lighter end VOC components which have the 

potential to produce increased volumes of flash emissions compared to typical oil production 

wells (U.S. EPA, 2012a). This may be somewhat unique to the Bakken formation and not be 

representative nationally.

Table 3-2 summarizes an analysis performed by EC/R of the FBIR data with respect to 

oil well completion emissions. The analysis estimated completion emissions by multiplying the 

average gas volume per day for each well by a 7 day flowback period. The analysis indicated that 
10

the average uncontrolled emissions from a well completion event are 37 tons of VOC per 

completion event.
11

Table 3-2. Summary of FBIR FIP Oil Well Completion Uncontrolled3 Casing Gas and VOC Emissions

Data from FBIR FIP

Data Element Enerplus EOG QEPc WPXb WPX-2

b WPX-3b XTOd Marathon PetroHunt Average Min Max

VOC Molecular weight 27.0 27.7 NA 28.1 29.6 31.7 24.5 28.5 25.8 27.8 24.5 31.7

Natural Gas Molecular 

weight 37.8 40.5 NA 43.7 45.9 51.0 32.9 41.4 34.3 41.0 32.9 51.0

Gas Constant 

(ft3/lbmol)a 379 379 NA 379 379 379 379 379 379 379 379.0 379

Average Oil Production 

(bpd) - per well 1,181 255 NA 347 420 303 305 2,094 214 639.7 214 2,094

Average Gas Volume 

(Mcf/day) - per well 885 182 NA 250 292 210 305 491 197 351.5 182 885

Average Gas Volume 

(Mcf/completion) 6,197 1,272 NA 1,748 2,042 1,473 2,133 3,439 1,378 2,460 1,272 6,197

Average Uncontrolled 

VOC Emissions 

(ton/completion)

83 19 NA 28 37 31 23 53 16 37 16 83

NA = Not Reported, FBIR FIP = Fort Berthold Indian Reservation Federal Implementation Plan, EOG = EOG Resources, QEP = QEP Energy Co., WPX = WPX Energy, XTO 

= XTO Energy Inc.

a-Value used by North Dakota facilities represents 60°F and 1 atm. For subpart OOOO, this value is based on 68°F and 1 atm.

b-NOTE for WPX:

i. They used three different molecular weights and percent. Therefore, each of these are represented in this table.

ii. They only reported 10% of the VOC emissions because they flare 90% of their casinghead gas emissions. This table represents 100%.

c-The QEP molecular weight and VOC content data for casinghead gas were claimed as copyrighted and were not in the online docket.

d-XTO reported oil production and associated gas production as the same value. Therefore, did not include this gas to oil production ratio in the average.

 

3 Uncontrolled emissions are the emissions that would occur if no emissions mitigation practices or technologies were used (e.g., completion combustion devices 

or RECs).
12

3.3 ERG Inc. and EC/R Analyses of HPDI Data

ERG Inc. and EC/R (ERG/ECR) conducted an analysis of Calendar Year (CY) 2011 

HPDI4data to estimate uncontrolled emissions from hydraulically fractured oil well completions 

for the EPA. For this analysis the following methodology was used:

ERG extracted HDPI oil well data for hydraulically fractured, unconventional oil wells 

completed in CY 2011. Because the HPDI database does not differentiate between gas and oil 

wells, the following criteria were used to identify the population of hydraulically fractured oil 

well completions:

 Identified wells completed in 2011 using HPDI data covering U.S. oil and natural gas wells. 

Summary of the data and the logic for dates used is included in the memo “Hydraulically 

Fractured Oil Well Completions” (ERG, 2013)

 Identified wells completed in 2011 that were hydraulically fractured using the Department 

of Energy EIA formation type crosswalk supplemented with state data for horizontal wells

(ERG, 2013)

 Determined which wells were oil wells based on their average gas-to-liquids ratio (less than 

12,500 scf/barrel were considered to be oil wells)

 Estimated the average daily gas flow from the cumulative natural gas production for each 

well during its first 12 months of production

 The resulting dataset provided 192 data points representing county level average daily 

natural gas production at a total of 5,754 oil well completions for CY 2011.

Emissions in the ERG/ECR analysis were calculated using both a 3-day and a 7-day 

flowback period. The volume of natural gas emissions (in Mcf) per completion event was 

calculated using the average daily flow multiplied by both a 7-day flowback period and a 3-day 

flowback period. The gas volume was converted to mass of VOC using the same VOC 

 

4 HPDI, LLC is a private organization specializing in oil and gas data and statistical analysis. The HPDI database is 

focused on historical oil and gas production data and drilling permit data. For certain states and regions, this data 

was supplemented by state drilling information. The 2011 data was the most current data available when the analysis 

was performed.
13

composition and conversion methodology used for gas wells in the subpart OOOO well 

completion evaluation. The composition values used were 46.732% by volume of methane in 

natural gas and 0.8374 pound VOC per pound of methane for oil wells (EC/R, 2011a).

The analysis of the 2011 HPDI data for oil well completions provided an average gas 

production of 262 Mcf per well per day. Based on this gas production, the average uncontrolled 

VOC emissions were 20 tons per completion event based on a 7-day flowback period and 6.4 

tons of VOC per completion event based on a 3-day flowback period. The average uncontrolled 

methane emissions were 24 tons per completion event based on a 7-day flowback period and 7.7

tons of methane per completion event based on a 3-day flowback period. It was assumed that the 

emissions for an oil well recompletion event are the same as an oil well completion event.

To estimate nationwide uncontrolled emissions for hydraulically fractured oil well 

completions, the average methane and VOC emissions per event were multiplied by the total 

number of estimated oil well completions. For 2011, which was the most recent data available in 

HPDI, the estimated nationwide uncontrolled hydraulically fractured oil well completion VOC 

emissions are 116,230 tons per year (i.e., VOC emissions/completion of 20.2 tons/event times 

the total oil well completion events per year of 5,274) based on a 7-day flowback period and 

36,825 tons per year (i.e., VOC emissions/completion of 6.4 tons/event times the total oil well 

completion events per year of 5,274) based on a 3-day flowback period. The estimated 

nationwide uncontrolled hydraulically fractured oil well completion methane emissions are 

138,096 tons per year (i.e., methane emissions/completion of 24 tons/event times the total oil 

well completion events per year of 5,274) based on a 7-day flowback period and 44,306 tons per 

year (i.e., VOC emissions/completion of 7.7 tons/event times the total oil well completion events 

per year of 5,274) based on a 3-day flowback period. Table 3-3 presents the results of the 

emission estimate analysis for both the 7-day and 3-day completion duration periods.
14

Table 3-3. Summary of Oil Well Completion Uncontrolled Emissions from 

2011 HPDI Data

7-day 

event

3-day 

event

Total number of hydraulically fractured oil well completions in 2011 5,754 5,754

Number of county well production averages (data points) 195 195

Natural Gas production per well, per day, weighted average (Mcf) 262 262

Methane emissions per completion/recompletion event, weighted average (tons) 24 7.7

VOC emissions per completion/recompletion event, weighted average (tons) 20.2 6.4

Uncontrolled Nationwide methane emissions, oil well completions (tpy) 138,096 44,306

Uncontrolled Nationwide VOC emissions, oil well completions (tpy) 116,230 36,825

Note: This estimate does not include recompletion emissions.

As stated earlier, these estimates are for uncontrolled emissions, thus estimates assume no 

control technology applied. National-level data on the prevalence of the use of RECs or 

combustors for reduction of emissions from oil well completion or recompletion operations were 

unavailable for this analysis. 

State level information for Colorado, Texas and Wyoming on oil well recompletion 

counts was used to determine a percentage of producing wells for which recompletions were 

reported. The state level data were obtained for Colorado, Texas and Wyoming for recent years 

(COGCC, 2012, Booz, 2008 and RRCTX, 2013). Based on the state level data, it was determined 

that the average percentage of producing well undergoing recompletion was 0.5%. This includes 

both conventional and hydraulically fractured oil wells (the data did not allow the different types 

of wells to be distinguished from each other). Table 3.4 presents a summary of this analysis. 
15

Table 3-4. Analysis of Texas, Wyoming and Colorado Recompletions Counts

State Data Source Year

Total 

Number of 

Producing 

Wells

Total Number 

of 

Recompletions

Percent 

Recompletions to 

Total Producing 

Wells

Railroad Commission of Texas 2012 168,864 685 0.4

Wyoming Heritage Foundation 2007 37,350 304 0.8

State of Colorado Oil & Gas 

Conservation Commission 2012 50,500 152 0.3

Average Percent 0.5

While the state level recompletion data are recent, the percentage of producing oil wells 

that undergo recompletion in future years may increase due to more prevalent use of hydraulic 

fracturing on oil wells. However, no data have been obtained to quantify any potential increase 

in the oil well recompletion rate. This percentage was not used to estimate the number of 

recompletions of hydraulically fractured oil wells, because the data did not distinguish between 

conventional wells and hydraulically fractured wells.

3.4 Environmental Defense Fund and Stratus Consulting Analysis of Oil Well 

Completions5(EDF, 2014)

The Environmental Defense Fund (EDF) and Stratus Consulting (EDF/Stratus) conducted 

an analysis of HPDI data for oil wells to determine the cost effectiveness of the use of RECs and 

flares for control of oil well completion emissions within three major unconventional oil play 

formations, Bakken, Eagle Ford and Wattenberg. The oil well completion population was 

extracted using the DI Desktop for all oil wells with initial production in 2011 and 2012.

Different filters were applied in each formation in order to identify the hydraulically fractured oil 

wells:

 

5 This analysis is described in the EDF white paper “Co-Producing Wells as a Major Source of Methane Emissions: 

A Review of Recent Analyses” (http://blogs.edf.org/energyexchange/files/2014/03/EDF-Co-producing-WellsWhitepaper.pdf). It is referred to in that paper as the “EDF/Stratus Analysis.” The supplemental materials, including 

the data that was used in the analysis are available at https://www.dropbox.com/s/osrom4w6ewow4ua/EDF-InitialProduction-Cost-Effectiveness-Analysis.xlsx. 
16

 Eagle Ford

o Well Production Type: Oil

 Bakken

o Well Production Type: Oil and Oil & Gas

 Wattenberg

o Well Production Type: Oil

The resulting dataset included 3,694 oil wells for the Bakken formation, 1,797 oil wells 

for the Eagle Ford formation, and 3,967 oil wells for the Wattenberg formation. The assumptions 

EDF/Stratus made while conducting this analysis were:

 Well completions lasted an average of 7 to 10 days and the total gas production 

over that period was equal to 3 days of “Initial Gas Production” as reported in DI 

Desktop (i.e., 3 days of “Initial Gas Production” was equal to the uncontrolled 

natural gas emissions from the oil well completion).

 The natural gas content was 78.8% methane.

Table 3-5 summarizes the results of this analysis. 

Table 3-5. EDF Estimated Uncontrolled Methane Emissions 

from Oil Well Completions Based on Analysis of HPDI® Oil Well Production Data

Formation Wells (#)

Uncontrolled 

Completion Emissions 

(gas Mcf/event)

Uncontrolled 

Completion Emissions 

(MT CH4/event)

Uncontrolled 

Completion Emissions 

(tons CH4/event)

Wattenberga3,967 624 9.5 10.5

Bakkenb3,694 1,183 18.0 19.8

Eagle Fordc1,797 1,628 24.7 27.2

All results represent mean values.

a - Production data was downloaded for all oil wells in the Colorado Wattenberg formation with a first 

production date between 1/1/2010 and 3/1/2013.

b - Production data was downloaded for wells in the North Dakota Bakken formation with a completion date 

from 1/1/2010-12/31/2012. North Dakota does not distinguish between oil and gas wells. All wells with the 

type O&G were assumed to be oil wells.

c - Production data was downloaded for all oil wells in the Texas Eagle Ford formation with a completion date 

between 1/1/2010 and 2/23/2013.
17

The EDF/Stratus Analysis also provided an estimate of uncontrolled methane emissions 

from oil well completions of 247,000 MT (272,000 tons), however, the materials describing the 

analysis do not explain how this estimate was calculated.

3.5 Measurements of Methane Emissions at Natural Gas Production Sites in the United 

States (UT Study) (Allen et al., 2013) 

The UT Study was primarily authored by University of Texas at Austin and was

sponsored by the EDF and several companies in the oil and gas production industry. The study 

was conducted to gather methane emissions data at onshore natural gas well sites in the U.S. and 

compare the data to the EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHG 

Inventory). The sources and operations that were tested included well completion flowbacks, 

well liquids unloading, pneumatic pumps and controllers and equipment leaks. The full study 

analysis included 190 onshore natural gas sites, which included 150 production sites, 26 well 

completion events, 9 well unloading and 4 well recompletions or workovers.

Six of the completion events in the UT Study were at co-producing wells (at least some 

oil was produced). The study reported the total oil produced, the total associated gas produced, 

the potential and actual methane emission, the completion duration, the type of emission control 

used, and the percent reduction from the control that was observed (Note: for two of the 

completion events, data was not gathered for the initial flow to the open tank). The data for these 

wells are summarized in Table 3-6.
18

Table 3-6. Summary of Completion Emissions from Co-Producing Wells

Site 

ID

Oil 

Produced 

(bbl)

Gas 

Produced 

(Mcf)

GOR 

(scf/bbl)

Potential 

Methane 

Emissionsa 

(Mcf)

Actual 

Methane 

Emissionsb

(Mcf)

% 

Reductio

n

Data 

Analyzed

Duration 

(hrs)

REC 

or 

Flare

GC-1 1,594 6,449.9 4,046.36 5,005 106 97.9 Yes 75 Flare

GC-2 1,323 5,645 4,266.82 4,205 91 97.8 Yes 76 Flare

GC-3 2,395 26,363 11,007.52 21,500 264 98.8 Yes 28 REC

GC-4 1,682 24,353 14,478.60 13,000 180 98.6 Yes 28 REC

GC-6 448 13,755 30,703.13 12,150 247 98 Nod164 Flare

GC-7 1,543 5,413 3,508.10 4,320 90 97.9 Nod108 Flare

a – Measured emissions before flare or REC.

b - Measured emissions after flare or REC.

c - Calculated from measured before and after control.

d -Data not used in developing average emissions factor in the UT Study because, in these flowbacks, the study team was unable to 

collect completion emissions data for the initial flow to the open tank.

Using the threshold of a GOR of 12,500 scf/barrel to distinguish oil wells from gas wells, 

wells GC-1, GC-2, GC-3, and GC-7 would be considered oil wells. The average uncontrolled 

methane emissions from those wells were 213 tons (10,237 Mcf) and the average controlled 

(actual) emissions were 3.2 tons (154 Mcf).

6

The average duration of the completion for these 

wells was 72 hours (3 days). It is also worth noting that well GC-3 was controlled using a REC 

and 98.8% of the potential methane emissions were mitigated, demonstrating that RECs can be 

used effectively to control emissions from hydraulically fractured oil wells.

3.6 Methane Leaks from North American Natural Gas Systems (Brandt et. al, 2014a 

and 2014b)

Novim, a non-profit group at the University of California, sponsored a meta-analysis of 

the existing studies on emissions from the production and distribution of natural gas. As part of 

this analysis, Novim estimated emissions from hydraulically fractured oil well completions based 

on data from HPDI®. Novim included wells that were drilled in 2010 or 2011 in the Eagle Ford, 

 

6 These averages do not include well GC-7, because, as noted above, data from this well was not used in the UT 

Study due to the inability to collect all the emissions data.
19

Bakken, and Permian formations (Brandt et. al., 2014a). Different filters were applied in each 

formation in order to identify the hydraulically fractured oil wells:

 Eagle Ford

o Well Production Type: Oil

o Drill Type: Horizontal

 Bakken

o Well Production Type: Oil and Oil & Gas

o Drill Type: Horizontal

 Permian

o Well Production Type: Oil

o Drill Type: All

Using this method of qualifying the well population, Novim concluded 2,969 

hydraulically fractured oil wells were completed in 2011 in the three formations (Brandt et. al., 

2014a). In order to estimate completion emissions, Novim used the O’Sullivan method7in which 

peak gas production (normally the production during the first month) is converted to a daily rate 

of production. The O’Sullivan method assumes that during flowback emissions increase linearly 

over the first nine days until the peak rate is reached. Table 3-7 summarizes the estimated 

uncontrolled methane emissions per completion calculated by the Novim study.

Table 3-7. Summary of Uncontrolled Completion Emissions from Co-Producing Wells

Formation

Uncontrolled 

Methane 

Emissions 

(tonnes/event)a

Uncontrolled 

Methane Emissions 

(ton/event)b

Eagle Ford 90.9 93

Bakken 31.1 31.9

Permian 31.2 31.9

a – 1 Mg = 1 metric tonne of methane

b – Converted to U.S. short tons. 1 tonne = 1.02311 tons (short/U.S.) of methane

 

7 O’Sullivan, Francis and Sergey Paltsev, “Shale gas production: potential versus actual greenhouse gas emissions”, 

Environmental Research Letters, United Kingdom. November 26, 2012.
20

The Novim Study assumes methane emissions from these formations are representative 

of total national methane emissions from hydraulically fractured oil well completions and 

estimates those emissions to be 0.12 Tg (120,000 tonnes or 122,773 tons) per year for 2011.

It should be noted that the methodology in this study, like the ERG/ECR Analysis and the 

EDF/Stratus Analysis, uses gas production from HPDI® to estimate completion emissions. 

However, Novim uses the O’Sullivan method in which the emissions increase linearly through 

the flowback period until a peak is reached, while the ERG/ECR Analysis and the EDF/Stratus 

Analysis assume emissions are constant through the flowback period. 

4.0 EMISSIONS DATA AND EMISSIONS ESTIMATES – ASSOCIATED 

GAS FROM HYDRAULICALLY FRACTURED OIL WELLS 

Given the potential for emissions of associated gas from oil production, available 

information sources have been reviewed as to their potential use for characterizing the VOC and 

methane emission from associated gas production at oil well sites. As was stated previously, the 

term “associated gas emissions” in this paper refers to emissions from gas that is vented during 

the production phase that could otherwise be captured and sold if the necessary pipeline 

infrastructure was available to take the gas to market. 

One methodology for estimating emissions would be to use the GOR of the well, which is 

a common piece of well data in the industry. An emission factor based on average GOR could be 

developed, and then the emission factor could be used to estimate uncontrolled associated gas 

emissions by applying it to known oil production (assuming all gas produced at an oil well is 

included in uncontrolled associated gas emissions). However, research indicates that associated 

gas production from oil wells declines over the life of the well, similar to oil production, but the 

decline is typically at a different rate than the oil production (EERC, 2013). This phenomenon

introduces another variable into the analysis. 

A second approach would be to use gas production reported for the well for economic 

and regulatory reasons. Conceivably, gas production could be used to estimate uncontrolled 
21

associated gas emissions. However, the EPA is not aware of a methodology that would allow the 

Agency to calculate the percentage of produced gas that could be captured if pipeline 

infrastructure were available. Some gas is emitted from equipment as part of normal operations, 

such as bleeding from pneumatic controllers. These emissions would not qualify as associated 

gas emissions as they have been defined in this paper. 

The GHGRP does require reporting of “associated gas venting and flaring emissions.” 

Additionally, the Ceres report contains data potentially useful for basic evaluation of VOC and 

methane associated gas emissions, but does not provide national estimates or per well estimates 

of emissions (Ceres, 2013). Both these sources are discussed in detail in the sections below.

The GHG Inventory does not include a category that specifically covers all associated gas 

emissions. Instead, these emissions are estimated in several categories in Petroleum Systems, and 

in Natural Gas Systems (emissions downstream of the gas-oil separator, and flaring).

4.1 Greenhouse Gas Reporting Program (U.S. EPA, 2013)

In October 2013, the EPA released 2012 greenhouse gas (GHG) data for Petroleum and 

Natural Gas Systems8collected under the GHGRP. The GHGRP, which was required by 

Congress in the FY2008 Consolidated Appropriations Act, requires facilities to report data from 

large emission sources across a range of industry sectors, as well as suppliers of certain GHGs 

and products that would emit GHGs if released or combusted.

When reviewing this data and comparing it to other datasets or published literature, it is 

important to understand the GHGRP reporting requirements and the impacts of these 

requirements on the reported data. The GHGRP covers a subset of national emissions from 

Petroleum and Natural Gas Systems; a facility9in the Petroleum and Natural Gas Systems source 

 

8 The implementing regulations of the Petroleum and Natural Gas Systems source category of the GHGRP are 

located at 40 CFR Part 98 Subpart W.

9

In general, a “facility” for purposes of the GHGRP means all co-located emission sources that are commonly 

owned or operated. However, the GHGRP has developed a specialized facility definition for onshore production. 

For onshore production, the “facility” includes all emissions associated with wells owned or operated by a single 

company in a specific hydrocarbon producing basin (as defined by the geologic provinces published by the 

American Association of Petroleum Geologists). 
22

category is required to submit annual reports if total emissions are 25,000 metric tons carbon 

dioxide equivalent (CO2e) or more. Facilities use uniform methods prescribed by the EPA to 

calculate GHG emissions, such as direct measurement, engineering calculations, or emission 

factors derived from direct measurement. In some cases, facilities have a choice of calculation

methods for an emission source.

Under the GHGRP, facilities report associated gas vented and flared emissions. Vented 

emissions are calculated based on GOR and the volume of oil produced and flared emissions 

using a continuous flow measurement device or engineering calculation. For 2012, 171 facilities 

reported associated gas vented and flared emissions to the GHGRP. Total reported methane 

emissions were 89,535 MT.

4.2 FLARING UP: North Dakota Natural Gas Flaring More Than Doubles in Two 

Years (Flaring Up) (CERES, 2013)

The Flaring Up report discusses the increase in North Dakota’s oil and gas production 

from the Bakken formation between 2007 and mid-2013, the increased flaring of associated gas, 

and the potential value of NGL lost as a result of flaring. The report presents some associated gas 

production and flaring data that the authors derive from the gas production and flaring data 

reported by the North Dakota Industrial Commission (NDIC), Department of Mineral Resources. 

The Commission defines associated gas to be all natural gas and all other fluid hydrocarbons not 

defined as oil. Oil is defined by the Commission to be all crude petroleum oil and other 

hydrocarbons, regardless of gravity which are produced at the wellhead in liquid form and the 

liquid hydrocarbons known as distillate or condensate recovered or extracted from gas, other 

than gas produced in association with oil and commonly known as casinghead gas10.

This Flaring Up report indicates that of the wells that are flaring the associated gas, 

approximately 55% are wells are not connected to a gas gathering system, while 45% are wells 

that are already connected. In addition, the report states that in May of 2013, 266,000 Mcf per 

day was flared, which represents nearly 30% of the gas produced (CERES, 2013). Percent flaring 

is currently reported by the NDIC while the connection data is tracked by the North Dakota 

 

10 North Dakota Century Code, Section I, Chapter 38-08 Control of Gas & Oil Resources, Section 38-08-02.
23

Pipeline Authority. The report concludes that the reason for the flaring of the associated gas is 

lack of pipeline infrastructure, lack of capacity and lack of compression infrastructure. 

The data and information in this report is useful for discussion on the relative percentages 

of gas emissions being flared. The data, however, are specific to the Bakken, a formation that

possesses unique characteristics both with regard to reservoir and formation characteristics, gas 

composition and the lack of infrastructure due to rapid development of the industry in the area. 

5.0 AVAILABLE EMISSION MITIGATION TECHNIQUES

Two mitigation techniques were considered that have been proven in practice and in 

studies to reduce emissions from well completions and recompletions: REC and completion 

combustion. One of these techniques, REC, is an approach that not only reduces emissions but 

delivers natural gas product to the sales meter that would otherwise be vented. The second 

technique, completion combustion, destroys the organic compounds. Both of these techniques 

are discussed in the following sections, along with estimates of the efficacy at reducing 

emissions and costs for their application for a representative well. Combustion control for control 

of associated gas emissions (e.g., flaring) has been demonstrated as effective in the industry. 

However, flaring results in the destruction of a valuable resource and, as such, alternate uses for 

uncaptured/sold associated gas have been the subject of several studies with respect to new 

emerging technologies. 

5.1 Reduced Emission Completions (REC)

5.1.1 Description

Reduced emissions completions are defined for the purposes of this paper as:

A well completion following fracturing or refracturing where gas flowback that is 

otherwise vented is captured, cleaned, and routed to the flow line or collection system, reinjected into the well or another well, used as an onsite fuel source, or used for other 
24

useful purpose that a purchased fuel or raw material would serve, with no direct release to 

the atmosphere.

Reduced emission completions, also referred to as “green” completions, use specially 

designed equipment at the well site to capture and treat gas so it can be directed to the sales line. 

This process prevents some natural gas from venting and results in additional economic benefit 

from the sale of captured gas and, if present, gas condensate. It is the EPA’s understanding that 

the additional equipment required to conduct a REC may include additional tankage, special gasliquid-sand separator traps and a gas dehydrator. In many cases, portable equipment used for 

RECs operates in tandem with the permanent equipment that will remain after well drilling is 

completed (EC/R, 2010b). In other instances, permanent equipment is designed (e.g., oversized) 

to specifically accommodate initial flowback. Some limitations exist for performing RECs 

because technical barriers vary from well to well. Three main limitations include the following:

 Proximity of pipelines. For certain wells, no nearby sales line may exist. The lack of a nearby 

sales line incurs higher capital outlay risk for exploration and production companies and/or 

pipeline companies constructing lines in exploratory fields. 

 Pressure of produced gas. Based on experience using RECs at gas wells, the EPA 

understands that during each stage of the completion process, the pressure of flowback fluids 

may not be sufficient to overcome the sales line backpressure. In this case, combustion of 

flowback gas is one option, either for the duration of the flowback or until a point during 

flowback when the pressure increases to flow to the sales line. 

 Inert gas concentration. Based on experience using RECs at gas wells, if the concentration of 

inert gas, such as nitrogen or carbon dioxide, in the flowback gas exceeds sales line 

concentration limits, venting or combustion of the flowback may be necessary for the 

duration of flowback or until the gas energy content increases to allow flow to the sales line. 

Further, since the energy content of the flowback gas may not be high enough to sustain a 

flame due to the presence of the inert gases, combustion of the flowback stream would 

require a continuous ignition source with its own separate fuel supply. 
25

5.1.2 Effectiveness

Based on data available on RECs use at gas wells, the emission reductions from RECs

can vary according to reservoir characteristics and other parameters including length of 

completion, number of fractured zones, pressure, gas composition, and fracturing 

technology/technique. Based on the results reported by four different Natural Gas STAR Partners 

who performed RECs primarily at natural gas wells, a representative control efficiency of 90%

for RECs was estimated. The companies provided both recovered and total produced gas, 

allowing for the calculation of the percentage of the total gas which was recovered. This estimate 

was based on data for more than 12,000 well completions (ICF, 2011). Any amount of gas that 

cannot be recovered can be directed to a completion combustion device in order to achieve a 

minimum 95% reduction in emissions. Additionally, both wells that co-produced oil and gas and 

were controlled with a REC in the UT Austin study achieved greater than 98% reduction in 

methane emissions.

5.1.3 Cost

The discussion of cost in this section is based on the EPA’s experience with RECs at gas 

wells. It is the EPA’s understanding that the same equipment is used for RECs at gas wells and 

co-producing oil wells. All completions incur some costs to a company. Performing a REC will 

add to these costs. Equipment costs associated with RECs vary from well to well. High 

production rates may require larger equipment to perform the REC and will increase costs. If 

permanent equipment, such as a glycol dehydrator, is already installed or is planned to be in 

place at the well site as normal operations, costs may be reduced as this equipment can be used 

or resized rather than installing a portable dehydrator for temporary use during the completion. 

Some operators normally install equipment used in RECs, such as sand traps and three-phase 

separators, further reducing incremental REC costs. 

The average cost of RECs was obtained from data shown in the Natural Gas STAR 

Lessons Learned document titled “Reduced Emissions Completions for Hydraulically Fractured 

Natural Gas Wells” (U.S. EPA, 2011a). The impacts calculations use the cost per day for gas 
26

capture and the duration of gas capture along with a setup/takedown/transport cost and a flare 

cost to represent the total cost. The cost is then annualized across the time horizon under study. 

Costs of performing a REC are projected to be between $700 and $6,500 per day (U.S. 

EPA, 2011a). This cost range is the incremental cost of performing a REC over a completion

without a REC, where typically the gas is vented or combusted because there is an absence of 

REC equipment. These cost estimates are based on the state of the industry in 2006 (adjusted to 

2008 U.S. dollars). 11 Cost data used in this analysis are qualified below:

 $700 per day (equivalent to $806 per day in 2008 dollars) represents completion and 

recompletion costs where key pieces of equipment, such as a dehydrator or three-phase 

separator, are already found onsite and are of suitable design and capacity for use during 

flowback. 

 $6,500 per day (equivalent to $7,486 in 2008 dollars) represents situations where key 

pieces of equipment, such as a dehydrator or three-phase separator, are temporarily 

brought onsite and then relocated after the completion. 

The average of the above data results in an average incremental cost for a REC of $4,146 

per day (2008 dollars).12 The total cost of the REC depends on the length of the flowback period, 

and thus the length of the completion process. For example, if the completion takes 7 days then 

the total cost would be $29,022, and if the completion takes 3 days then the total cost would be 

$12,438 versus an uncontrolled completion. These costs would be mitigated by the value of the 

captured gas. The extent of this cost mitigation would depend on the price of the gas and the 

quantity that was captured during the REC.

 

11 The Chemical Engineering Cost Index was used to convert dollar years. For REC, the 2008 value equals 575.4 

and the 2006 value equals 499.6.

12 The average incremental cost for a REC was calculated by averaging $806 per day and $7,486 per day (2008 

dollars). While the average estimated cost per day is presented here, it is likely that the cost that is paid by a well 

operator will be the low incremental cost if key pieces of equipment are already present onsite or the high 

incremental cost if this equipment is not present onsite, and not the average of these two estimates.
27

5.1.4 Prevalence of Use at Oil Wells

The UT Austin study found that some co-producing oil wells are conducting RECs. It is 

the EPA’s understanding that in some cases RECs are currently used on co-producing oil wells if 

pipeline infrastructure is available. 

5.2 Completion Combustion Devices

5.2.1 Description

Completion combustion is a high-temperature oxidation process used to burn combustible 

components, mostly hydrocarbons, found in gas streams (U.S. EPA, 1991). Completion 

combustion devices are used to control VOC in many industrial settings, since the completion 

combustion devices can normally handle fluctuations in concentration, flow rate, heating value, 

and inert species content (U.S. EPA, Flares). These devices can be as simple as a pipe with a 

basic ignition mechanism and discharge over a pit near the wellhead. However, the flow directed 

to a completion combustion device may or may not be combustible depending on the inert gas 

composition of flowback gas, which would require a continuous ignition source. Completion 

combustion devices provide a means of minimizing vented gas during a well completion and are 

generally preferable to venting, due to reduced air emissions. 

5.2.2 Effectiveness

Completion combustion devices can be expected to achieve 95% emission reduction 

efficiency, on average, over the duration of the completion or recompletion. If the energy content 

of natural gas is low, then the combustion mechanism can be extinguished by the flowback gas. 

Therefore, it may be more reliable to install an igniter fueled by a consistent and continuous 

ignition source. This scenario would be especially true for energized fractures where the initial 

flowback concentration will be extremely high in inert gases. If a completion combustion device 

has a continuous ignition source with an independent external fuel supply, then it is assumed to 

achieve an average of 95% control over the entire flowback period (U.S. EPA, 2012b). 
28

5.2.3 Cost 

An analysis of costs provided by industry for enclosed combustors was conducted by the 

EPA for the FBIR FIP. In addition, the State of Colorado recently completed an analysis of 

industry provided combustor cost data and updated their cost estimates for enclosed combustors

(CDPE, 2013). Table 5-1 summarizes the data provided from each of the sources with the 

average cost for an enclosed combustor across these sources being $18,092. It is assumed that 

the cost of a continuous ignition source is included in the combustion completion device cost 

estimations. Also noted in the table is the most recent combustor cost used for reconsideration of 

control options for storage vessels under subpart OOOO.

As with RECs, because completion combustion devices are purchased for these one-time 

events, annual costs were assumed to be equal to the capital costs. However, multiple 

completions can be controlled with the same completion combustion device, not only for the 

lifetime of the combustion device but within the same yearly time period. Costs were estimated 

as the total cost of the completion combustion device itself, which corresponds to the assumption 

that only one device will control one completion per year. This approach may overestimate the 

true cost of combustion devices per well completion or recompletion.

5.2.4 Prevalence of Use at Oil Wells

The UT Austin study found that some co-producing oil wells are using completion 

combustion devices to reduce emissions. It is the EPA’s understanding that the most common 

approach to reducing emissions from hydraulically fractured oil well completions is the use of a 

completion combustion device. 
29

Table 5-1. Analysis of Industry Provided Enclosed Combustor Cost

Cost Parameter

Industry Provided Data EPA Estimate in Subpart OOOO

FBIR CDPHE CDHPE

EOG XTO Enerplus QEP Average 

of quotes Original Data Used Adjusted Data Useda

Annualized Capital Cost $5,268 $6,727 $6,116 $6,763 $3,569 $6,281 $3,546 $4,746

Other Annual Costs

Pilot Fuel NR NR NR NR $636 $2,078 $2,144

Operating Labor 

(includes management) NR NR NR NR $10,670 $10,670 $11,012

Maintenance NR NR NR NR $2,206 $2,190 $2,260

Data Management NR NR NR NR $1,000 $1,095 $1,130

Total Other Annual 

Costs (combustor)c $1,500 $23,250 $6,289 $8,500 $14,512 $10,810 $16,033 $16,546

Other Annual Costs 

(continuous pilot)c $1,000 NR NR NR

included 

in 

combustor 

costsb

$1,000 included in 

combustor costsb

included in 

combustor costsc

Total Annual Costs $7,768 $29,977 $12,405 $15,263 $18,081 $18,092 $19,580 $21,292

NR = Not reported, FBIR = Fort Berthold Indian Reservation, CDPHE = Colorado Department of Public Health and Environment, EOG = EOG Resources, XTO =

XTO Energy Inc. , QEP = QEP Energy Co

Cost data in 2012 dollars

a - Cost data for 40 CFR part 60, subpart OOOO updated to reflect more current cost year and equipment life (industry comments indicated a 10-year equipment life 

as opposed to 15 years)

b - Data used for subpart OOOO included a cost for an auto ignition system, surveillance system, VRU system, and freight and installation

c - Quotes received for FBIR FIP did not specify what was included in other annual costs.
30

5.3 Emerging Control Technologies for Control of Associated Gas

Several types of alternative use technologies are being investigated both by industry and 

regulators for use of associated gas. 

The most prominent alternative technologies being investigated to address associated gas 

are liquefaction of natural gas, NGL recovery, gas reinjection, and electricity generation. 

According to the Schlumberger Oilfield Glossary, “liquefied natural gas refers to natural 

gas, mainly methane and ethane, which has been liquefied at cryogenic temperatures. This 

process occurs at an extremely low temperature and a pressure near the atmospheric pressure. 

When a gas pipeline is not available to transport gas to a marketplace, such as in a jungle or 

certain remote regions offshore, the gas may be chilled and converted to liquefied natural gas (a 

liquid) to transport and sell it. The term is commonly abbreviated as LNG.” Research is being 

conducted on the economic and technical feasibility of liquefaction of natural gas as a means to 

realize the full potential of the U.S. natural gas resources, particularly with respect to the 

potential of U.S. exports of LNG. However, available information indicates that this technology 

is typically implemented on a macro scale, requiring installation of large facilities and 

transportation infrastructure. Because the EPA is unaware of existing studies or further 

information on liquefaction of gas at the wellhead, liquefaction of natural gas is not discussed 

further in this paper. 

Cost information is summarized to the extent that this information is readily available. In 

many cases, available literature does not provide cost information as the economics of the 

technology are still being researched. 

5.3.1 Natural Gas Liquids (NGL) Recovery 

Natural gas liquids are defined as “components of natural gas that are liquid at surface in 

field facilities or in gas-processing plants. Natural gas liquids can be classified according to their 

vapor pressures as low (condensate), intermediate (natural gasoline) and high (liquefied 

petroleum gas) vapor pressure. Natural gas liquids include propane, butane, pentane, hexane and 
31

heptane, but not methane and ethane, since these hydrocarbons need refrigeration to be liquefied. 

The term is commonly abbreviated as NGL.”

13

Associated gas from the Bakken formation has been termed “rich” gas, which is defined 

as naturally containing heavier hydrocarbons than a “lean” gas. Its liquid content adds important 

economic value to developments containing this type of fluid. Therefore, the value of the NGLs 

in the associated gas from the Bakken formation has been the subject of several studies, 

particularly with the concerns raised based by the rapid development of Bakken and increased 

flaring of associated gas. As would be expected, most of the recent studies related to NGL 

recovery are based on the Bakken formation. 

One of these studies is the “End-Use Technology Study – An Assessment of Alternative 

Uses for Associated Gas” conducted by the Energy & Environmental Research Center (EERC) 

of the University of North Dakota (EERC, 2013). The study was conducted based on associated 

gas production in December 2011 and was published in 2012. This study provides an evaluation 

of alternative technologies and their associated costs and benefits. In particular, the study looks 

at NGL recovery, as a standalone operation for both recovery of salable NGLs and as a 

pretreatment of the associated gas for use in other local operations such as power generation.

To understand NGL recovery, the typical natural gas processing that occurs at or near the 

wellhead will be reviewed. Liquids and condensates (water and oil) are separated from the “wet” 

gas. The condensates are transported via truck or pipeline for further processing at a refinery or 

gas processing plant. The minimally processed wellhead natural gas is then transported to a gasprocessing plant via pipeline. There, the gas is processed to remove more water, separate out 

NGL, and remove sulfur and carbon dioxide in preparation for release to the sales distribution 

system. Figure 5-1 summarizes generalized natural gas processing.

 

13 From Schlumberger Oilfield Glossary available at 

http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=natural+gas++liquids
32

Figure 5-1. Generalized Natural Gas Processing Schematic

Source: U.S. EIA, 2006.

Because of the relatively high value of NGL products produced, recovery technologies 

have been developed both for large and small scale gas-processing applications. There are 

generally three approaches used in these technologies: 

• Control of temperature and pressure to achieve condensation of NGLs 

• Separation of heavier NGLs from lighter gas with pressurized membrane separation 

systems 

• Physical/chemical adsorption/absorption 

The typical NGL recovery technologies used are turboexpander with demethanizer, 

Joule-Thomson (JT) low pressure separation membranes, absorption (Refrigerated Lean Oil 

Separation, RLOS), adsorption using active carbon or molecular sieve, and Twister Supersonic 

Gas Low Temperature Separation Dew Pointing Process. For the purposes of this paper, the 
33

specifics of these technologies are not discussed; rather, the focus will be on the overall outcome 

and potential costs for small scale implementation at the well head for addressing associated gas. 

The EERC study included a case study for a small scale NGL Recovery process at a well 

head. The case study evaluated the potential for deploying small scale NGL recovery systems as 

an interim practice to flaring associated gas while gathering lines and infrastructure were being 

installed or upgraded. These systems would allow the most valuable hydrocarbon portion of the 

gas to be captured and marketed. The leaner gas resulting could be used onsite for power 

generation or transported as a compressed gas. Alternatively, the leaner gas could continue to be 

flared. Figure 5-2 depicts the NGL Removal system flow diagram. 

Figure 5-2. Natural Gas Liquids (NGL) Removal System Flow Diagram

Source: Figure 22, EERC, 2013

According to the EERC study, 10 to 12 gallons of NGL/Mcf of associated gas is present in 

many producing Bakken wells. At an estimated NGL removal rate of 4 gallons/Mcf (from 1000 

Mcf/day of rich gas), the daily production of NGLs would be approximately 4,000 gallons of 

NGLs per day (EERC, 2013). The study also states that at least at the current natural gas price, 

the NGLs make up a majority of the economic value of the rich gas. An evaluation of a 

simplified model on small-scale NGL recovery was developed based on a JT-based technology. 

The NGL removal system evaluation assumes the parameters shown in Table 5-2.
34

Table 5-2. Assumptions for NGL Recovery Case (Table 9, EERC, 2013)

Parameter Assumed Value

Rich Gas Flow Rate from the Wellhead, average 300 Mcf/day 

Rich Gas Flow Rate Processed, economic cutoff 600 Mcf/day 

Rich Gas Flow Rate, design flow 1000 Mcf/day 

Rich Gas Heat Content 1400 Btu/ft3

Rich Gas Price (cost) at the Wellhead $0.00/Mcf 

Volume of NGLs Existing in Rich Gas 10–12 gallons/Mcf 

NGL Price, value $1.00/gallon 

Lean Gas Flow Rate from NGL Removal System 85% of rich gas flow rate 

Lean Gas Heat Content 1210–1250 Btu/ft3

Lean Gas Price, value $2.00/Mcf 

The EERC study estimated capital and annual costs for the NGL removal system. 

Operating and maintenance (O&M) costs were assumed to be 10% of the total capital cost. 

Revenue calculations were based on NGL sales only at $1/gallon and a recovery rate of 4 

gallons/Mcf. In this scenario, it has been assumed that residue gas is flared (EERC, 2013). Table 

5-3, derived from Table 10 of the study, summaries the cost for the small sale NGL recovery 

system.

Table 5-3. Summary of NGL Removal System Costs (Table 10, EERC)

Description Capital Cost

Annual O&M

Cost

NGL Removal System, 300 Mcfd rich gas $2,500,000 $250,000

NGL Removal System, 600 Mcfd rich gas $2,500,000 $250,000

NGL Removal System, 1000 Mcfd rich gas $2,500,000 $250,000

Mcfd = One thousand standard cubic feet per day. 
35

The EERC study concluded that the technical aspects of NGL recovery are fairly straight 

forward; however, the business aspects are much more complicated, particularly with respect to 

NGL product supply chain and contractual considerations. Further, the study concluded that 

NGL recovery would be most economical at wells flaring larger quantities of gas immediately 

after production begins. Other attributes that would be important for the economic feasibility of 

the NGL recovery system would be that the systems are mobile and easily mobilized, and that 

infrastructure with respect to truing of NGL production is available.

5.3.2 Natural Gas Reinjection

Schlumberger’s Oilfield Glossary defines gas injection as “a reservoir maintenance or 

secondary recovery method that uses injected gas to supplement the pressure in an oil reservoir 

or field. In most cases, a field will incorporate a planned distribution of gas-injection wells to 

maintain reservoir pressure and effect an efficient sweep of recoverable liquids.”14

The industry has employed production methods to increase production, which are termed 

enhanced oil recovery (EOR) or improved oil recovery (IOR) (Rigzone, 2014). These methods 

are generally considered to be tertiary methods employed after waterflooding or pressure 

maintenance. The practice involves injecting gas into the gas cap of the formation and boosting 

the depleted pressure in the formation with systematically placed injection wells throughout the 

field. The pressure maintenance methods maybe employed at the start of production or

introduced after the production has started to lessen. The reinjection of natural gas is the use of 

associated gas at the same oilfield to accomplish the goals of gas injection as defined above. The 

increase in the pressure within the reservoir helps to induce the flow of crude oil. After the crude 

has been pumped out, the natural gas is once again recovered. 

Natural gas injection is also referred to as cycling. Cycling is used to prevent condensate 

from separating from the dry gas in the reservoir due to a drop in reservoir pressure. The 

condensate liquids block the pores within the reservoir, making extraction practically impossible.

The NGL are stripped from the gas on the surface after it has been produced, and the dry gas is 

 

14 Schlumberger Oilfield Glossary, available at 

http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=gas+injection
36

then re-injected into the reservoirs through injection wells. Again, this helps to maintain pressure 

in the reservoir while also preventing the separation within the hydrocarbon (Rigzone, 2014).

Figure 5-3 illustrates the relationship between the gas injection well and the production well.

Figure 5-3. Gas Injection and Production Well

Source: Rigzone, 2014

In the scenarios that were found in available literature, the dry gas is also used as fuel 

onsite for the generators that power the reinjection pumps. Therefore, the costs associated with 

the process are mainly initial capital costs. No published information was obtained on the capital 

and annual costs for these operations. 

Figure 5-4 presents a fully implemented gas injection project scheme. In this scheme, 

associated gas from an oil well (or natural gas from a gas well) is processed through a gas 

cycling facility (GCF) where recoverable NGLs are separated from methane and the resulting 

methane is either used for onsite power generation or re-injected in to the formation.
37

Figure 5-4. Gas Cycling Facility Project Flow

The literature that was reviewed evaluated gas reinjection projects only from the 

perspective of an enhanced oil recovery opportunity and did not specifically discuss the quantity 

or percentage of associated gas emissions that were eliminated through the process. The EPA is 

not aware of literature that discusses the efficacy of mitigating associated gas emissions using the 

natural gas reinjection process. The efficacy would be highly dependent on many factors, which 

include the composition value of the gas and the availability of transmission infrastructure. 

Further, because the use of this process to reduce associated gas emissions in conjunction with 

oil recovery is an emerging technology, the prevalence of use in the industry and estimated cost 

to implement the process is unknown to the EPA.
38

5.5.3 Electricity Generation for Use Onsite

As discussed above, associated gas can be used for generation of electrical power to be 

used onsite. The EERC study stated that power generation technologies would need to be 

designed to match the variable wellhead gas flow rates and gas quality, and would need to be 

constructed for mobility. The EERC study discussed previously also looked at options for use of 

associated gas for power generation. The EERC study included an evaluation of several 

technologies fired by natural gas both for grid support (i.e., power generation for direct delivery 

onto the electric grid) and local power (i.e., power generation for local use with excess 

generation, if any, sent to the electrical grid). This study provides one of the most comprehensive 

and recent evaluations of the economics of use of associated gas for electric generation. 

Therefore, the case study results of this study are used to discuss the cost of this technology for 

this paper.

Although grid support is potentially a viable use for this gas, it is not considered to be an 

emissions reduction technology for the purposes of this paper. Grid support requires an 

infrastructure similar in scope as that needed to bring gas to market. The focus of this section of 

the paper is on the venting or flaring of associated gas due to the lack of infrastructure to bring it 

to market. It is unlikely that a well site that is lacking pipeline infrastructure would have access 

to the necessary infrastructure to provide grid support. Therefore, the focus here is on the use of 

the gas at the local level, either directly at the wellpad or in an immediate oilfield region to 

support local activities. The benefits of using associated gas to provide electricity for these 

activities are both reducing the quantity of gas vented and reducing the quantity of other types of 

fuel used (e.g., diesel).

The EERC study considered a local power project to be wellhead gas (with limited 

cleanup) being piped to an electrical generator that produces electricity which is first used to 

power local consumption (e.g., well pad, group of wells, or an oilfield) with any excess 

electricity put on the electrical grid for distribution by the local utility to its customers. These 

projects can range widely in scale, depending on the goal of the project (i.e., satisfy only local 

load, satisfy local load with minimal excess generation, or satisfy local load with significant 
39

excess generation). The study evaluated two power generation scenarios: reciprocating engine 

and a microturbine. 

The first step in using associated gas for electric generation is removal of NGLs from the 

rich gas. Removal of the NGLs significantly increases the performance of the genset and reduces 

the loss of resource (when flaring is necessary). According to the EERC study, removal of NGLs 

such as butane and some propane could be accomplished using a low temperature separation 

process. The study found that small, modular configurations of these types of systems are not 

widely available. The estimated capital cost for the NGL removal and storage system is 

$2,500,000. This capital cost includes the necessary compression to take the rich gas from the 

heater/treater at 35 psi up to 200 - 1000 psi delivered to the NGL removal system as well as the 

cost for four 400-bbl NGL storage tanks (EERC, 2013). The study authors considered NGL 

recovery a valuable first step; however, they also stated that it was not necessary in all 

circumstances.

The study made certain assumptions about the flow of associated gas from the wellhead 

and fuel consumption of the respective electrical generator for the case study. Table 5-4

summarizes the assumed wellhead gas flow for the case study. Figure 5-5 shows a block flow 

diagram of an example NGL removal system. 

Table 5-4. Summary of Wellhead Gas Flow and Product Volume Assumptions

Scenario

Rich Gas

Flow, Mcf/day

NGLs Produced,

gallons/day

Lean Gas

Produced, Mcf/day

Reciprocating Engine 600 2,400 510

Microturbine 600 2,400 510

Source Table 33, EERC 2013
40

Figure 5-5. NGL Removal System Block Flow Diagram

Source Figure 32, EERC 2013

For the case study, the authors targeted a power production scenario of 1 MW for the 

reciprocating engine and 200 kW for the microturbine. Both scenarios used the same NGL 

removal system prior to introduction of the rich gas to the generator. Figure 5-6 depicts the 

process flow diagram for the local power generation scenario. 

Figure 5-6. Process Flow Diagram, Local Power Generation Scenario

Source: Figure 33, EERC, 2013

For the reciprocating engine scenario, vendor provided costs for a 250-kW natural gas 

fired reciprocating engine genset was $200,000. The study estimated the annual O&M cost was 

assumed to be 10% of the capital cost. The costs for this scenario are summarized in Table 5-5.
41

Table 5-5. Total Cost Summary - Reciprocating Engine Scenario

 Capital Cost Annual Cost

NGL Removal and Storage System $2,500,000 $250,000

Electrical Generator System $200,000 $20,000

All Other Infrastructure $500,000

Total Capital Cost $3,200,000 $270,000

Source Table 38, EERC 2013

For the microturbine scenario, the authors chose to analyze a four, 65 kW microturbine 

package rated to provide approximately 195 kW of power. This scenario also involved the 

removal of NGLs prior to delivery of gas to the microturbine and the use of generated electricity 

to satisfy local electrical demand, with the excess electricity delivered to the grid. The authors 

noted that the volume of gas generated from the wellhead(s) will determine the size of the system 

needed and that a range of generation scales should be considered for optimum performance. The 

process flow for this scenario is the same as shown above in Figure 5-6. 

The NGL removal system is likely to be much larger in processing capacity than the 

electrical generation system. Generally, the NGL removal system will be most economical only 

at the higher-gas-producing wells. The microturbine package evaluated consumed less than 100 

Mcf/day, which meant that excess gas would either need to be flared or the project must be

designed to store the excess gas for sale to the pipeline. In the scenarios described here, the 

authors assumed that the excess lean gas is sold.

For the microturbine system analyzed, the vendors offered a factory protection plan 

(FPP) that covers all scheduled and unscheduled maintenance of the system as well as parts, 

including an overhaul or turbine replacement at 40,000 hours of operation. The FPP “locks in” 

the annual O&M cost of the system and, in both scenarios presented below, it is assumed that the 

FPP is purchased (EERC, 2013). Table 5-6 summarizes the capital and annual O&M costs for 

the microturbine system, as well as the NGL recovery system discussed above.
42

Table 5-6. Total Cost Summary - Microturbine Scenario (Four 65-kW)

 Capital Cost Annual Cost

NGL Removal and Storage System $2,500,000 $250,000

Electrical Generator System $383,200 $33,640

All Other Infrastructure $500,000

Total Capital Cost $3,382,200 $283,640

Source: Table 41, EERC, 2013.

The study authors also evaluated revenue potential for electricity sent to the grid as an 

offset to the costs summarized above. Their analysis indicated that based on cost (discussed 

above) and their revenue assumptions, both scenarios provided a simple payback of 3 years or 

less. However, given the substantial upfront capital costs of these options, these options may not 

be preferable to building the necessary pipeline infrastructure to take the gas to market.

In addition to the electric generation potential for associated gas, the study also discussed 

the use of wellhead gas as a fuel for drilling operations. The authors indicated that the EERC is 

working with Continental Resources, ECO-AFS, Altronics, and Butler Caterpillar to conduct a 

detailed study and field demonstration of the GTI Bi-Fuel System. Within that task, the EERC 

conducted a series of tests at the EERC using a simulated Bakken gas designed to test the 

operational limits of fuel quality and diesel fuel replacement while monitoring engine 

performance and emissions. The authors indicated that the Bi-Fuel System is an aftermarket 

addition to the system allowing natural gas to the air intake, and the engine performance is 

unaltered from the diesel operation. This system, as the name implies, could be used on either 

fuel without requiring any alterations.

According to the study report, total installed capital cost for the Bi-Fuel System ranges 

from $200,000 to $300,000 (EERC, 2013). Other costs that would be incurred would be those for 

piping wellhead gas to the engine building. The study did not include those costs because they 

can be highly variable depending on the distance to the nearest gas source and gas lease terms. 
43

The study reports that ECO-AFS had recently installed several Bi-Fuel Systems on rigs in 

the Williston Basin and that early data suggest that diesel fuel savings of approximately $1 to 

$1.5 million can be achieved annually. Under typical conditions, operators can expect to achieve 

diesel replacement of 40% - 60% at optimal engine loads of 40% - 50% (EERC, 2013).

The EERC study noted that there are a number of other potential natural gas uses related 

to oil production and operations that could take advantage of rich gas on a well site. Those would 

include:

 Heating of drilling fluids during winter months (replacing the diesel or propane fuel used 

currently) 

 Providing power for hydraulic fracturing operations decreasing reliance on diesel fuel

(i.e., by using Bi-fuel systems) 

 Providing fuel for workover rigs (if the rig is equipped with a separate generator) 

6.0 SUMMARY

As discussed in the previous sections, the EPA used the body of knowledge presented in 

this paper to summarize its understanding of emissions characterization and potential emissions 

mitigation techniques for oil well completions and associated gas. From that body of knowledge,

the following statements summarize the EPA’s understanding of the state of the industry with 

respect to these sources of emissions:

 Available estimates of uncontrolled emissions from hydraulically fractured oil well 

completions are presented below:
44

Study

Average Uncontrolled VOC

Emissions

(Tons/Completion)

Average Uncontrolled Methane

Emissions

(Tons/Completion)

Fort Berthold Federal 

Implementation Plan 37 N/A

ERG/ECR Analysis of HPDI® 

Data (7 day flowback period) 20.2 24

ERG/ECR Analysis of HPDI® 

Data (3 day flowback period) 6.4 7.7

EDF/Stratus Analysis of HPDI® 

Data (Eagle Ford)

N/A 27.2

EDF/Stratus Analysis of HPDI® 

Data (Wattenberg) N/A 10.5

EDF/Stratus Analysis of HPDI® 

Data (Bakken) N/A 19.8

Measurements of Methane 

Emissions at Natural Gas 

Production Sites in the United 

States

N/A 213

Methane Leaks from North 

American Natural Gas Systems

(Eagle Ford)

N/A 90.9

Methane Leaks from North 

American Natural Gas Systems

(Bakken)

N/A 31.1

Methane Leaks from North 

American Natural Gas Systems

(Permian)

N/A 31.2

 Limited information is available on uncontrolled emissions from hydraulically fractured 

oil well recompletions, and controlled emission factors for hydraulically fractured oil 

well completions and recompletions.

 National level estimates of uncontrolled methane emissions from hydraulically fractured 

oil well completions range from 44,306 tons per year (ERG/ECR) to 247,000 tons per 

year (EDF/Stratus analysis).

 One study (ERG/ECR) estimated nationwide uncontrolled VOC emissions from 

hydraulically fractured oil well completion to be 116,230 tons per year assuming a 7-day 

flowback period and 36,825 tons per year assuming a 3-day flowback period.

 There is some data that shows (Allen et. al.) that RECs, in certain situations, can be an 

effective emissions control technique for oil well completions when gas is co-produced. 
45

However, there may be a combination of well pressure and gas content below which 

RECs are not technically feasible at co-producing oil wells. 

 Some oil well completions are controlled using RECs; however, national data on the 

number of completions that are controlled using a REC are not available. It is the EPA’s 

understanding that most oil well completion emissions are controlled with combustion;

however, data on an average percentage are not available. Likewise, data are not 

available on the percentage of oil wells nation-wide that vent completion emissions to the 

atmosphere.

 Other gas conserving technologies are being investigated for use in completions and for 

control of associated gas emissions. These include gas reinjection, NGL recovery and use 

of the gas for power generation for local use. Some studies have evaluated the economics 

of some of these technologies and determined, in some cases, they can result in net 

savings to the operator depending on the value of the recovered gas or liquids or the value 

of the power generated. However, some barriers exist with respect to technology 

availability and application of the technology to varying scales of oil well gas production.

In addition, costs vary for implementing some of these technologies.

7.0 CHARGE QUESTIONS FOR REVIEWERS

1. Please comment on the national estimates and per well estimates of methane and VOC 

emissions from hydraulically fractured oil well completions presented in this paper. Are there 

factors that influence emissions from hydraulically fractured oil well completions that were 

not discussed in this paper?

2. Most available information on national and per well estimates of emissions is on 

uncontrolled emissions. What information is available for emissions, or what methods can be 

used to estimate net emissions from uncontrolled emissions data, at a national and/or at a per 

well level? 

3. Are further sources of information available on VOC or methane emissions from 

hydraulically fractured oil well completions beyond those described in this paper?
46

4. Please comment on the various approaches to estimating completion emissions from 

hydraulically fractured oil wells in this paper. 

 Is it appropriate to estimate average uncontrolled oil well completion emissions by using 

the annual average daily gas production during the first year and multiplying that value 

by the duration of the average flowback period?

 Is it appropriate to estimate average uncontrolled oil well completion emissions using 

“Initial Gas Production,” as reported in DI Desktop, and multiplying by the flowback 

period?

 Is it appropriate to estimate average uncontrolled oil well completion emissions by 

increasing emissions linearly over the first nine days until the peak rate is reached

(normally estimated using the production during the first month converted to a daily rate 

of production)?

 Is the use of a 3-day or 7-day flowback period for hydraulically fractured oil wells 

appropriate? 

5. Please discuss other methodologies or data sources that you believe would be appropriate for 

estimating hydraulically fractured oil well completion emissions.

6. Please comment on the methodologies and data sources that you believe would be 

appropriate to estimate the rate of recompletions of hydraulically fractured oil wells. Can 

data on recompletions be used that does not differentiate between conventional oil wells and 

hydraulically fractured oil wells be reasonably used to estimate this rate? For example, in the 

GHG Inventory, a workover rate of 6.5% is applied to all oil wells to estimate the number of 

workovers in a given year, and in the ERG/ECR analysis above a rate of 0.5% is developed 

based on both wells with and without hydraulic fracturing. Would these rates apply to 

hydraulically fractured oil wells? For hydraulically fractured gas wells, the GHG Inventory 

uses a refracture rate of 1%. Would this rate be appropriate for hydraulically fractured oil 

wells?

7. Please comment on the feasibility of the use of RECs or completion combustion devices

during hydraulically fractured oil well completion operations. Please be specific to the types 

of wells where these technologies or processes are feasible. Some characteristics that should 

be considered in your comments are well pressure, gas content of flowback, gas to oil ratio 
47

(GOR) of the well, and access to infrastructure. If there are additional factors, please discuss 

those. For example, the Colorado Oil and Gas Conservation Commission requires RECs only

on “oil and gas wells where reservoir pressure, formation productivity and wellbore 

conditions are likely to enable the well to be capable of naturally flowing hydrocarbon gas in 

flammable or greater concentrations at a stabilized rate in excess of five hundred (500) 

MCFD to the surface against an induced surface backpressure of five hundred (500) psig or 

sales line pressure, whichever is greater.”

15

8. Please comment on the costs for the use of RECs or completion combustion devices to 

control emissions from hydraulically fractured oil well completions.

9. Please comment on the emission reductions that RECs and completion combustion devices 

achieve when used to control emissions from hydraulically fractured oil well completions.

10. Please comment on the prevalence of the use of RECs or completion combustion devices

during hydraulically fractured oil well completion and recompletion operations. Are you 

aware of any data sources that would enable estimating the prevalence of these technologies 

nationally?

11. Did the EPA correctly identify all the available technologies for reducing gas emissions from 

hydraulically fractured oil well completions or are there others?

12. Please comment on estimates of associated gas emissions in this paper, and on other 

available information that would enable estimation of associated gas emissions from 

hydraulically fractured oil wells at the national- and the well-level. 

13. Please comment on availability of pipeline infrastructure in hydraulically fractured oil 

formations. Do all tight oil plays (e.g., the Permian Basin and the Denver-Julesberg Basin) 

have a similar lack of infrastructure that results in the flaring or venting of associated gas? 

14. Did the EPA correctly identify all the available technologies for reducing associated gas 

emissions from hydraulically fractured oil wells or are there others? Please comment on the 

 

15 Colorado Department of Natural Resources: Oil and Gas Conservation Commission Rule 805.b(3)A. 

(http://cogcc.state.co.us/) 
48

costs of these technologies when used for controlling associated gas emissions from 

hydraulically fractured oil wells. Please comment on the emissions reductions achieved when 

these technologies are used for controlling associated gas emissions from hydraulically 

fractured oil wells.

15. Are there ongoing or planned studies that will substantially improve the current 

understanding of VOC and methane emissions from hydraulically fractured oil well 

completions and associated gas and available options for increased product recovery and 

emission reductions?

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U.S. Environmental Protection Agency (U.S. EPA). 2011b. 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. 

EPA-453/R-11002.

U.S. Environmental Protection Agency (U.S. EPA). 2012a. Technical Support Document, 

Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold 

Indian Reservation (Mandan, Hidatsa, and Arikara Nations), North Dakota. Docket Number: 

EPA-R08-OAR-2012-0479.

U.S. Environmental Protection Agency (U.S. EPA). 2012b. Oil and Natural Gas Sector: 

Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and 

Distribution. Background Supplemental Technical Support Document for Proposed Standards.

April 2012.

U.S. Environmental Protection Agency. (U.S. EPA) 2013. Petroleum and Natural Gas Systems: 

2012 Data Summary. Greenhouse Gas Reporting Program. October 2013.

(http://www.epa.gov/ghgreporting/documents/pdf/2013/documents/SubpartW-2012-DataSummary.pdf).

U.S. Environmental Protection Agency (U.S. EPA). 2014. Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-2012. Washington, DC. April 2014. 

(http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2014-

Chapter-3-Energy.pdf).
A - 1

Appendix A

(ERG, 2013)

Memorandum (Draft):

Environmental Research Group, Inc.

Hydraulically Fractured Oil Well Completions.

October 24, 2013
A - 2

TO: David Hendricks, EC/R Incorporated 

FROM: Mike Pring, Eastern Research Group, Inc. (ERG) 

Regi Oommen, ERG 

DATE: October 24, 2013 

SUBJECT: Hydraulically Fractured Oil Well Completions

Eastern Research Group, Inc. (ERG) is currently under contract with EC/R Incorporated to provide 

technical support under EC/R Work Assignment #1-11 with U.S. EPA. This memorandum describes ERG’s 

findings relative to Task 2 of the support effort. Specifically, under this task ERG: 

• Identified wells which were hydraulically fractured in 2011; 

• Determined which of the hydraulically fractured wells completed in 2011 were oil wells; 

• Estimated daily associated gas production from the hydraulically fractured oil wells; and 

• Provided a summary of this information at the national and county level (in Excel spreadsheet 

format). 

Wells Hydraulically Fractured in 2011 

Starting with the most recent analysis and files delivered by ERG to the U.S. EPA Office of Compliance, 

ERG queried DI Desktop, a production database maintained by DrillingInfo, Inc. 

covering U.S. oil and natural gas wells, to identify hydraulically fractured oil and gas well completions 

performed in 2011. This was accomplished using a two-step process: 

• Identification of wells completed in 2011; 

• Identification of wells completed using hydraulic fracturing. 

Wells completed in 2011 were identified as those wells meeting one of the following criteria: 

DRAFT MEMORANDUM
A - 3

• The DI Desktop data for the well indicated it was completed in 2011; or 

• The DI Desktop data for the well indicated the well 1st produced in 2011. 

While the DI Desktop database is fairly comprehensive in its geographic and temporal coverage of 

production data, completion date information can lag behind by a year or more afterwards and is not 

universally available for all areas of the country. Therefore, the list of wells with explicit well completion 

dates of 2011 was supplemented with those wells having a date (month) of 1st production of either gas 

or oil in 2011. This methodology is consistent with the methodology used to estimate well completions 

in the “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2011 (April 12, 2013)”. 

Using this approach, 39,262 conventional and unconventional well completions were identified for 2011. 

Once the population of wells completed in 2011 was identified, hydraulically fractured wells were 

identified as those wells meeting either of the following: 

• Wells completed in a coalbed methane, tight, or shale formation as determined using the DOE 

EIA formation type crosswalk; or 

• Wells identified in the DI Desktop database as horizontal wells. 

The DOE EIA formation type crosswalk used in this analysis may be found in Attachment A. This 

methodology is consistent with the methodology used to identify the number of hydraulically fractured 

well completions in the “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2011 (April 12, 

2013)”. 

Using this approach, 15,979 hydraulically fractured (or unconventional) well completions were identified 

for 2011. 

Oil Wells Hydraulically Fractured in 2011 

Once the population of hydraulically fractured wells completed in 2011 was identified, each well was 

then classified as either an oil well or a gas well. Gas wells were defined as those wells with an average 

gas to liquids ratio greater than or equal to 12,500 standard cubic feet per barrel over the lifetime of the 

well, and oil wells were defined as those wells with an average gas to liquids ratio less than 12,500 

standard cubic feet per barrel over the lifetime of the well. Note that the “liquids” quantity used in this 

analysis does not include produced water. This methodology is consistent with the gas‐oil ratio 

methodology used in the 2012 Oil and Natural Gas Sector NSPS development. 

Using this approach, 6,169 hydraulically fractured (or unconventional) oil well completions were 

identified for 2011. 
A - 4

Daily Gas Production of Oil Wells Hydraulically Fractured in 2011 

Once the population of hydraulically fractured oil wells completed in 2011 was identified, the average 

daily gas production for each well was calculated based on the cumulative gas production from each 

well during its first year of production. This information was then averaged at the county-level, as well 

as at the national level. Nationally, the average daily gas production at an oil well that was hydraulically 

fractured in 2011 was 152 MCF. 

Summary Information 

Table 1 below presents a state-level summary of the derived information on hydraulically fractured oil

wells completed in 2011. Attachment B contains the same information at the county and national level. 

Table 1. Summary of Gas Production at Hydraulically Fractured (or unconventional) Oil Wells 

State Number of 

Counties 

Number of 

Unconventional Oil Well 

Completions 

Average Associated Gas 

Production over the 1st year 

(MCF/Day) a

AR 2 19 110.03 

CO 12 1057 95.46 

FL 1 1 5.81 

KS 3 5 0.80 

LA 17 24 111.87 

MI 4 7 5.58 

MS 1 1 0 

MT 13 95 31.21 

ND 14 1299 138.14 

NM 6 337 114.89 

NY 1 19 0 

OH 32 214 4.43 

OK 14 89 143.62 

PA 5 7 78.38 

SD 1 2 42.79 

TX 88 2855 284.09 

WV 5 11 173.15 

WY 14 127 48.62 

a

Determined by taking the total production from the first 12 months of production and dividing by 365 

days.

Observations 

The analysis conducted under this task was performed in accordance with the procedures described 

above. With respect to qualitative observations made while implementing these procedures, ERG notes 

the following: 
A - 5

• In some instances, the date (month) of 1st production only included oil production, with no 

corresponding gas production recorded for that month; 

• In some instances, there were months within the 1st year of production where there was no 

production (of oil, gas, or both) recorded for the well;

• For 415 oil wells hydraulically fractured and completed in 2011, there was no gas production 

reported for the well during the 1st year of production.

The net effect of these situations is that the average daily gas production values may be skewed low, for 

example, due to a well being shut in for some period of time after initially being brought into 

production. 

In the case of the 415 wells where there was no gas production reported for the well during the 1st year 

of production, summary data is presented in Attachment B excluding these records. This data is 

reflected in the summary sheets indicating “WITHOUT ZERO”. The effect of this differentiation is easily 

seen in the “UNCONV_OIL_NATIONWIDE” sheet, which shows an average daily gas production of 152 

(MCF/day) for all records, and an average daily gas production of 189 (MCF/day) when including only 

those records with some gas production. 
A - 6

Attachment A: DOE EIA Formation Type Crosswalk

(Formation Crosswalk-Memo Counts 2012 08 28_From ECR.xlsx) 

 
A - 7

Attachment B: National and County-level Summary of Average Daily Gas Production from

Hydraulically Fractured Oil Well Completions in 2011

(Task 2 Summary.xlsx)

UNCONVENTIONAL OIL COUNTY WITH ZERO

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

05027 AR Columbia 17

 

220.06 

05139 AR Union 2

 

- 

08001 CO Adams 8

 

75.81 

08005 CO Arapahoe 1

 

100.28 

08013 CO Boulder 4

 

173.39 

08014 CO Broomfield 12

 

194.15 

08043 CO Fremont 4

 

15.34 

08057 CO Jackson 1

 

281.19 

08069 CO Larimer 14

 

24.35 

08077 CO Mesa 1

 

0.43 

08081 CO Moffat 2

 

73.42 

08087 CO Morgan 1

 

14.65 

08103 CO Rio Blanco 3

 

62.57 

08123 CO Weld 1006

 

129.94 

12087 FL Monroe 1

 

5.81 

20073 KS Greenwood 1

 

- 

20097 KS Kiowa 1

 

- 

20125 KS Montgomery 3

 

2.40 

22009 LA Avoyelles 2

 

1.12 
A - 8

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

22011 LA Beauregard 1

 

141.90 

22015 LA Bossier 1

 

- 

22017 LA Caddo 2

 

5.65 

22019 LA Calcasieu 1

 

- 

22023 LA Cameron 1

 

77.58 

22027 LA Claiborne 3

 

1.56 

22037 LA

East 

Feliciana 1

 

23.45 

22047 LA Iberville 1

 

68.21 

22075 LA Plaquemines 1

 

44.28 

22079 LA Rapides 1

 

6.08 

22091 LA St. Helena 1

 

77.15 

22097 LA St. Landry 3

 

44.34 

22101 LA St. Mary 1

 

10.77 

22111 LA Union 1

 

5.58 

22119 LA Webster 1

 

1,382.30 

22127 LA Winn 2

 

11.78 

26075 MI Jackson 3

 

22.32 

26091 MI Lenawee 2

 

- 

26141 MI Presque Isle 1

 

- 

26147 MI St. Clair 1

 

- 

28063 MS Jefferson 1

 

- 

30005 MT Blaine 4

 

- 
A - 9

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

30009 MT Carbon 2

 

9.60 

30021 MT Dawson 1

 

29.33 

30025 MT Fallon 1

 

138.62 

30035 MT Glacier 9

 

29.37 

30065 MT Musselshell 1

 

- 

30069 MT Petroleum 4

 

- 

30073 MT Pondera 1

 

- 

30083 MT Richland 32

 

94.43 

30085 MT Roosevelt 27

 

102.11 

30087 MT Rosebud 2

 

- 

30091 MT Sheridan 10

 

2.30 

30099 MT Teton 1

 

- 

35005 NM Chaves 6

 

90.22 

35015 NM Eddy 206

 

317.14 

35025 NM Lea 121

 

160.97 

35039 NM Rio Arriba 2

 

57.02 

35043 NM Sandoval 1

 

- 

35045 NM San Juan 1

 

64.03 

36009 NY Cattaraugus 19

 

- 

38007 ND Billings 22

 

157.36 

38009 ND Bottineau 10

 

2.69 

38011 ND Bowman 4

 

84.54 
A - 10

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

38013 ND Burke 42

 

83.17 

38023 ND Divide 74

 

144.13 

38025 ND Dunn 208

 

156.73 

38033 ND

Golden 

Valley 3

 

131.73 

38053 ND McKenzie 297

 

355.17 

38055 ND McLean 11

 

102.95 

38061 ND Mountrail 329

 

176.74 

38075 ND Renville 2

 

- 

38087 ND Slope 1

 

140.16 

38089 ND Stark 28

 

184.08 

38105 ND Williams 268

 

214.53 

39005 OH Ashland 23

 

- 

39007 OH Ashtabula 1

 

20.94 

39009 OH Athens 3

 

2.47 

39019 OH Carroll 6

 

4.31 

39029 OH Columbiana 1

 

6.35 

39031 OH Coshocton 8

 

0.75 

39035 OH Cuyahoga 7

 

12.35 

39055 OH Geauga 7

 

4.13 

39067 OH Harrison 3

 

1.57 

39073 OH Hocking 2

 

- 

39075 OH Holmes 14

 

0.23 
A - 11

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

39081 OH Jefferson 6

 

- 

39083 OH Knox 13

 

1.67 

39089 OH Licking 17

 

- 

39093 OH Lorain 1

 

- 

39099 OH Mahoning 3

 

4.72 

39101 OH Marion 1

 

- 

39103 OH Medina 12

 

0.72 

39105 OH Meigs 1

 

2.08 

39111 OH Monroe 13

 

1.05 

39115 OH Morgan 6

 

0.16 

39119 OH Muskingum 9

 

0.79 

39121 OH Noble 1

 

- 

39127 OH Perry 2

 

0.40 

39133 OH Portage 10

 

10.29 

39151 OH Stark 22

 

6.70 

39153 OH Summit 8

 

25.92 

39155 OH Trumbull 4

 

19.92 

39157 OH Tuscarawas 2

 

2.52 

39167 OH Washington 6

 

0.35 

39169 OH Wayne 1

 

0.47 

39175 OH Wyandot 1

 

10.79 

40011 OK Blaine 4

 

138.44 
A - 12

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

40015 OK Caddo 2

 

- 

40017 OK Canadian 24

 

59.77 

40029 OK Coal 14

 

- 

40039 OK Custer 4

 

73.81 

40043 OK Dewey 5

 

25.28 

40045 OK Ellis 13

 

82.28 

40051 OK Grady 4

 

- 

40069 OK Johnston 1

 

273.04 

40095 OK Marshall 1

 

758.99 

40125 OK

Pottawatomi

e 1

 

- 

40129 OK Roger Mills 4

 

60.26 

40149 OK Washita 11

 

25.78 

40151 OK Woods 1

 

513.08 

42019 PA Butler 1

 

3.00 

42083 PA McKean 1

 

2.85 

42123 PA Warren 1

 

1.17 

42125 PA Washington 2

 

322.21 

42129 PA

Westmorela

nd 2

 

62.65 

46063 SD Harding 2

 

42.79 

48003 TX Andrews 18

 

27.20 

48009 TX Archer 4

 

7.96 

48013 TX Atascosa 70

 

119.71 
A - 13

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

48033 TX Borden 1

 

- 

48041 TX Brazos 17

 

88.27 

48051 TX Burleson 15

 

25.89 

48055 TX Caldwell 29

 

- 

48077 TX Clay 3

 

75.75 

48079 TX Cochran 3

 

0.73 

48097 TX Cooke 99

 

297.95 

48103 TX Crane 19

 

110.50 

48105 TX Crockett 20

 

151.12 

48109 TX Culberson 1

 

2,500.75 

48123 TX DeWitt 145

 

1,332.05 

48127 TX Dimmit 322

 

379.76 

48135 TX Ector 15

 

12.91 

48149 TX Fayette 13

 

79.71 

48151 TX Fisher 2

 

1.68 

48163 TX Frio 72

 

105.01 

48165 TX Gaines 1

 

3.92 

48169 TX Garza 1

 

- 

48173 TX Glasscock 19

 

272.15 

48177 TX Gonzales 207

 

98.80 

48181 TX Grayson 4

 

367.12 

48183 TX Gregg 3

 

23.02 
A - 14

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

48185 TX Grimes 7

 

586.87 

48187 TX Guadalupe 2

 

- 

48195 TX Hansford 3

 

93.42 

48197 TX Hardeman 2

 

74.00 

48201 TX Harris 1

 

1.84 

48203 TX Harrison 2

 

13.53 

48211 TX Hemphill 15

 

390.47 

48225 TX Houston 1

 

127.46 

48235 TX Irion 87

 

112.45 

48237 TX Jack 22

 

122.06 

48241 TX Jasper 2

 

1,387.63 

48255 TX Karnes 309

 

388.35 

48263 TX Kent 1

 

- 

48273 TX Kleberg 2

 

33.10 

48283 TX La Salle 216

 

185.29 

48285 TX Lavaca 13

 

83.04 

48287 TX Lee 5

 

25.93 

48289 TX Leon 19

 

61.86 

48295 TX Lipscomb 84

 

403.67 

48297 TX Live Oak 89

 

731.54 

48301 TX Loving 28

 

276.40 

48311 TX McMullen 130

 

276.52 
A - 15

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

48313 TX Madison 21

 

173.35 

48317 TX Martin 1

 

50.01 

48323 TX Maverick 23

 

110.15 

48329 TX Midland 1

 

12.33 

48331 TX Milam 3

 

34.19 

48337 TX Montague 119

 

362.22 

48351 TX Newton 2

 

2,539.85 

48353 TX Nolan 24

 

20.97 

48355 TX Nueces 3

 

1,746.66 

48357 TX Ochiltree 82

 

261.41 

48363 TX Palo Pinto 3

 

244.63 

48365 TX Panola 2

 

220.47 

48367 TX Parker 1

 

20.61 

48371 TX Pecos 8

 

42.56 

48373 TX Polk 4

 

1,394.01 

48383 TX Reagan 15

 

66.05 

48389 TX Reeves 39

 

184.15 

48393 TX Roberts 21

 

445.09 

48395 TX Robertson 15

 

22.76 

48401 TX Rusk 3

 

5.40 

48405 TX

San 

Augustine 1

 

1,052.92 

48413 TX Schleicher 1

 

171.38 
A - 16

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

48415 TX Scurry 5

 

84.33 

48417 TX Shackelford 1

 

- 

48425 TX Somervell 2

 

1.29 

48429 TX Stephens 2

 

27.98 

48433 TX Stonewall 18

 

0.61 

48439 TX Tarrant 1

 

60.16 

48449 TX Titus 1

 

- 

48457 TX Tyler 2

 

1,099.59 

48459 TX Upshur 1

 

49.13 

48461 TX Upton 12

 

3.26 

48475 TX Ward 73

 

375.79 

48477 TX Washington 1

 

276.18 

48479 TX Webb 44

 

874.17 

48483 TX Wheeler 60

 

965.66 

48493 TX Wilson 33

 

36.46 

48495 TX Winkler 7

 

137.90 

48497 TX Wise 3

 

342.57 

48503 TX Young 2

 

- 

48507 TX Zavala 52

 

26.70 

54001 WV Barbour 1

 

1.05 

54051 WV Marshall 1

 

782.02 

54053 WV Mason 1

 

1.40 
A - 17

FIPS_

CODE

STATE_

ABBR

COUNTY_NA

ME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS

_MCF_PER_DAY

54085 WV Ritchie 1

 

- 

54103 WV Wetzel 7

 

81.30 

56003 WY Big Horn 1

 

10.12 

56005 WY Campbell 29

 

282.44 

56007 WY Carbon 2

 

3.52 

56009 WY Converse 45

 

190.09 

56013 WY Fremont 3

 

2.17 

56015 WY Goshen 4

 

11.56 

56017 WY Hot Springs 1

 

0.11 

56019 WY Johnson 2

 

29.93 

56021 WY Laramie 22

 

56.63 

56025 WY Natrona 2

 

0.02 

56027 WY Niobrara 2

 

20.77 

56029 WY Park 3

 

5.60 

56031 WY Platte 2

 

8.15 

56037 WY Sweetwater 9

 

59.59 
A - 18

UNCONVENTONAL OIL COUTTY WITHOUT ZERO

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

05027 AR Columbia 17

 

220.06 

08001 CO Adams 8

 

75.81 

08005 CO Arapahoe 1

 

100.28 

08013 CO Boulder 4

 

173.39 

08014 CO Broomfield 12

 

194.15 

08043 CO Fremont 4

 

15.34 

08057 CO Jackson 1

 

281.19 

08069 CO Larimer 14

 

24.35 

08077 CO Mesa 1

 

0.43 

08081 CO Moffat 2

 

73.42 

08087 CO Morgan 1

 

14.65 

08103 CO Rio Blanco 1

 

187.70 

08123 CO Weld 1000

 

130.72 

12087 FL Monroe 1

 

5.81 

20125 KS Montgomery 3

 

2.40 

22009 LA Avoyelles 1

 

2.24 

22011 LA Beauregard 1

 

141.90 

22017 LA Caddo 1

 

11.31 

22023 LA Cameron 1

 

77.58 

22027 LA Claiborne 1

 

4.67 

22037 LA East Feliciana 1

 

23.45 

22047 LA Iberville 1

 

68.21 
A - 19

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

22075 LA Plaquemines 1

 

44.28 

22079 LA Rapides 1

 

6.08 

22091 LA St. Helena 1

 

77.15 

22097 LA St. Landry 2

 

66.51 

22101 LA St. Mary 1

 

10.77 

22111 LA Union 1

 

5.58 

22119 LA Webster 1

 

1,382.30 

22127 LA Winn 2

 

11.78 

26075 MI Jackson 2

 

33.48 

30009 MT Carbon 1

 

19.19 

30021 MT Dawson 1

 

29.33 

30025 MT Fallon 1

 

138.62 

30035 MT Glacier 7

 

37.76 

30083 MT Richland 30

 

100.73 

30085 MT Roosevelt 27

 

102.11 

30091 MT Sheridan 7

 

3.28 

35005 NM Chaves 5

 

108.26 

35015 NM Eddy 205

 

318.68 

35025 NM Lea 112

 

173.90 

35039 NM Rio Arriba 2

 

57.02 

35045 NM San Juan 1

 

64.03 

38007 ND Billings 22

 

157.36 
A - 20

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

38009 ND Bottineau 5

 

5.38 

38011 ND Bowman 4

 

84.54 

38013 ND Burke 42

 

83.17 

38023 ND Divide 74

 

144.13 

38025 ND Dunn 208

 

156.73 

38033 ND

Golden 

Valley 3

 

131.73 

38053 ND McKenzie 295

 

357.58 

38055 ND McLean 11

 

102.95 

38061 ND Mountrail 329

 

176.74 

38087 ND Slope 1

 

140.16 

38089 ND Stark 28

 

184.08 

38105 ND Williams 268

 

214.53 

39007 OH Ashtabula 1

 

20.94 

39009 OH Athens 2

 

3.70 

39019 OH Carroll 4

 

6.46 

39029 OH Columbiana 1

 

6.35 

39031 OH Coshocton 3

 

2.00 

39035 OH Cuyahoga 7

 

12.35 

39055 OH Geauga 7

 

4.13 

39067 OH Harrison 2

 

2.36 

39075 OH Holmes 4

 

0.82 

39083 OH Knox 8

 

2.71 
A - 21

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

39099 OH Mahoning 2

 

7.08 

39103 OH Medina 2

 

4.31 

39105 OH Meigs 1

 

2.08 

39111 OH Monroe 8

 

1.71 

39115 OH Morgan 3

 

0.32 

39119 OH Muskingum 4

 

1.78 

39127 OH Perry 1

 

0.79 

39133 OH Portage 9

 

11.43 

39151 OH Stark 17

 

8.67 

39153 OH Summit 7

 

29.62 

39155 OH Trumbull 4

 

19.92 

39157 OH Tuscarawas 1

 

5.04 

39167 OH Washington 2

 

1.04 

39169 OH Wayne 1

 

0.47 

39175 OH Wyandot 1

 

10.79 

40011 OK Blaine 4

 

138.44 

40017 OK Canadian 8

 

179.30 

40039 OK Custer 2

 

147.61 

40043 OK Dewey 2

 

63.20 

40045 OK Ellis 9

 

118.85 

40069 OK Johnston 1

 

273.04 

40095 OK Marshall 1

 

758.99 
A - 22

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

40129 OK Roger Mills 3

 

80.35 

40149 OK Washita 1

 

283.55 

40151 OK Woods 1

 

513.08 

42019 PA Butler 1

 

3.00 

42083 PA McKean 1

 

2.85 

42123 PA Warren 1

 

1.17 

42125 PA Washington 2

 

322.21 

42129 PA

Westmorelan

d 2

 

62.65 

46063 SD Harding 1

 

85.59 

48003 TX Andrews 16

 

30.60 

48009 TX Archer 1

 

31.86 

48013 TX Atascosa 69

 

121.44 

48041 TX Brazos 17

 

88.27 

48051 TX Burleson 6

 

64.72 

48077 TX Clay 3

 

75.75 

48079 TX Cochran 3

 

0.73 

48097 TX Cooke 99

 

297.95 

48103 TX Crane 19

 

110.50 

48105 TX Crockett 19

 

159.07 

48109 TX Culberson 1

 

2,500.75 

48123 TX DeWitt 143

 

1,350.68 

48127 TX Dimmit 317

 

385.75 
A - 23

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

48135 TX Ector 15

 

12.91 

48149 TX Fayette 12

 

86.35 

48151 TX Fisher 2

 

1.68 

48163 TX Frio 58

 

130.36 

48165 TX Gaines 1

 

3.92 

48173 TX Glasscock 19

 

272.15 

48177 TX Gonzales 196

 

104.35 

48181 TX Grayson 3

 

489.50 

48183 TX Gregg 3

 

23.02 

48185 TX Grimes 7

 

586.87 

48195 TX Hansford 3

 

93.42 

48197 TX Hardeman 1

 

147.99 

48201 TX Harris 1

 

1.84

48203 TX Harrison 1

 

27.06 

48211 TX Hemphill 15

 

390.47 

48225 TX Houston 1

 

127.46 

48235 TX Irion 87

 

112.45 

48237 TX Jack 22

 

122.06 

48241 TX Jasper 2

 

1,387.63 

48255 TX Karnes 303

 

396.04 

48273 TX Kleberg 2

 

33.10 

48283 TX La Salle 214

 

187.02 
A - 24

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

48285 TX Lavaca 13

 

83.04 

48287 TX Lee 3

 

43.21 

48289 TX Leon 16

 

73.46 

48295 TX Lipscomb 82

 

413.52 

48297 TX Live Oak 89

 

731.54 

48301 TX Loving 26

 

297.66 

48311 TX McMullen 125

 

287.58 

48313 TX Madison 20

 

182.01 

48317 TX Martin 1

 

50.01 

48323 TX Maverick 18

 

140.75 

48329 TX Midland 1

 

12.33 

48331 TX Milam 2

 

51.29 

48337 TX Montague 115

 

374.82 

48351 TX Newton 2

 

2,539.85 

48353 TX Nolan 22

 

22.87 

48355 TX Nueces 3

 

1,746.66 

48357 TX Ochiltree 82

 

261.41 

48363 TX Palo Pinto 3

 

244.63 

48365 TX Panola 2

 

220.47 

48367 TX Parker 1

 

20.61 

48371 TX Pecos 8

 

42.56 

48373 TX Polk 4

 

1,394.01 
A - 25

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

48383 TX Reagan 14

 

70.77 

48389 TX Reeves 37

 

194.11 

48393 TX Roberts 21

 

445.09 

48395 TX Robertson 12

 

28.45 

48401 TX Rusk 1

 

16.21 

48405 TX

San 

Augustine 1

 

1,052.92 

48413 TX Schleicher 1

 

171.38 

48415 TX Scurry 5

 

84.33 

48425 TX Somervell 2

 

1.29 

48429 TX Stephens 2

 

27.98 

48433 TX Stonewall 15

 

0.74 

48439 TX Tarrant 1

 

60.16 

48457 TX Tyler 2

 

1,099.59 

48459 TX Upshur 1

 

49.13 

48461 TX Upton 12

 

3.26 

48475 TX Ward 73

 

375.79 

48477 TX Washington 1

 

276.18 

48479 TX Webb 44

 

874.17 

48483 TX Wheeler 59

 

982.03 

48493 TX Wilson 28

 

42.98 

48495 TX Winkler 7

 

137.90 

48497 TX Wise 3

 

342.57 
A - 26

FIPS_CO

DE

STATE_A

BBR

COUNTY_

NAME

NUMBER_UNCONVENTIONAL_OIL_

WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_

MCF_PER_DAY

48507 TX Zavala 45

 

30.86 

54001 WV Barbour 1

 

1.05 

54051 WV Marshall 1

 

782.02 

54053 WV Mason 1

 

1.40 

54103 WV Wetzel 7

 

81.30 

56003 WY Big Horn 1

 

10.12 

56005 WY Campbell 27

 

303.36 

56007 WY Carbon 1

 

7.03 

56009 WY Converse 45

 

190.09 

56013 WY Fremont 1

 

6.52 

56015 WY Goshen 4

 

11.56 

56017 WY Hot Springs 1

 

0.11 

56019 WY Johnson 2

 

29.93 

56021 WY Laramie 21

 

59.33 

56025 WY Natrona 1

 

0.03 

56027 WY Niobrara 1

 

41.54 

56029 WY Park 3

 

5.60 

56031 WY Platte 2

 

8.15 

56037 WY Sweetwater 8

 

67.04 
A - 27

UNCONVENTIONAL OIL NATIONWIDE

NATIONWIDE UNCONVENTIONAL OIL WELL COMPLETIONS (WITH ZERO)

GEOGRAPHIC

NUMBER_OF_ 

STATES

NUMBER_OF_ 

COUNTIES

NUMBER_UNCONVENTIONAL_OI 

L_WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_ 

MCF_PER_DAY

NATIONWIDE 18 233 6169 152.19

NATIONWIDE UNCONVENTIONAL OIL WELL COMPLETIONS (WITHOUT ZERO)

GEOGRAPHIC

NUMBER_OF_ 

STATES

NUMBER_OF_ 

COUNTIES

NUMBER_UNCONVENTIONAL_OI 

L_WELL_COMPLETIONS

AVG_ASSOCIATED_GAS_ 

MCF_PER_DAY

NATIONWIDE 16 195 5754 189.35