ENERGY-WATER 

NEXUS 

Information on the 

Quantity, Quality, and 

Management of Water 

Produced during Oil 

and Gas Production 

Report to the Ranking Member,

Committee on Science, Space, and 

Technology, House of Representatives 

January 2012 

GAO-12-156 

United States Government Accountability Office

GAO 
United States Government Accountability Office

Highlights of GAO-12-156, a report to the

Ranking Member, Committee on Science, 

Space, and Technology, House of 

Representatives 

January 2012

ENERGY-WATER NEXUS

Information on the Quantity, Quality, and 

Management of Water Produced during Oil and Gas 

Production

Why GAO Did This Study

Water is a significant byproduct 

associated with oil and gas exploration 

and production. This water, known as 

“produced water,” may contain a 

variety of contaminants. If produced 

water is not appropriately managed or 

treated, these contaminants may 

present a human health and 

environmental risk.

GAO was asked to describe (1) what is 

known about the volume and quality of 

produced water from oil and gas 

production; (2) what practices are 

generally used to manage and treat 

produced water, and what factors are 

considered in the selection of each; 

(3) how produced water management

is regulated at the federal level and in 

selected states; and (4) what federal 

research and development efforts have 

been undertaken during the last 10 

years related to produced water. To 

address these objectives, GAO

reviewed studies and other documents 

on produced water and interviewed 

federal and state regulatory officials,

federal scientists, officials from oil and 

gas companies and water treatment 

companies, and other experts. GAO 

focused its review on the nine states

that generate nearly 90 percent of the 

produced water, and conducted site 

visits in three states. 

What GAO Recommends

GAO is not making any 

recommendations. A draft was 

provided to the Departments of Energy 

and the Interior, and EPA for review. 

None of these agencies provided 

written comments. EPA and Interior 

provided technical comments, which 

we incorporated as appropriate.

What GAO Found

A significant amount of water is produced daily as a byproduct from drilling of oil 

and gas. A 2009 Argonne National Laboratory study estimated that 56 million 

barrels of water are produced onshore every day, but this study may 

underestimate the current total volume because it is based on limited, and in 

some cases, incomplete data generated by the states. In general, the volume of 

produced water generated by a given well varies widely according to three key 

factors: the hydrocarbon being produced, the geographic location of the well, and 

the method of production used. For example, some gas wells typically generate 

large volumes of water early in production, whereas oil wells typically generate 

less. Generally, the quality of produced water from oil and gas production is poor, 

and it cannot be readily used for another purpose without prior treatment. The 

specific quality of water produced by a given well, however, can vary widely 

according to the same three factors that impact volume—hydrocarbon, 

geography, and production method. 

Oil and gas producers can choose from a number of practices to manage and 

treat produced water, but underground injection is the predominant practice 

because it requires little or no treatment and is often the least costly option. 

According to federal estimates, more than 90 percent of produced water is 

managed by injecting it into wells that are designated to receive produced water.

A limited amount of produced water is disposed of or reused by producers in 

other ways, including discharging it to surface water, storing it in surface 

impoundments or ponds so that it can evaporate, irrigating crops, and reusing it 

for hydraulic fracturing. Managing produced water in these ways can require 

more advanced treatment methods, such as distillation. How produced water is 

ultimately managed and treated is primarily an economic decision, made within 

the bounds of federal and state regulations. 

The management of produced water through underground injection is subject to 

the Safe Drinking Water Act’s Underground Injection Control program, which is 

designed to prevent contamination of aquifers that supply public water systems 

by ensuring the safe operation of injection wells. Under this program, the 

Environmental Protection Agency (EPA) or the states require producers to obtain 

permits for their injection wells by, among other things, meeting technical 

standards for constructing, operating, and testing and monitoring the wells. EPA 

also regulates the management of produced water through surface discharges 

under the Clean Water Act. Other management practices, such as disposal of the 

water into surface impoundments, irrigation, and the reuse of the water for 

hydraulic fracturing, are regulated by state authorities. 

Several federal agencies, including EPA; the Department of Interior’s Bureau of 

Reclamation and U.S. Geological Survey; and a number of Department of 

Energy national laboratories, have undertaken research and development efforts 

related to produced water. These efforts have included sponsoring and issuing 

studies that describe the volume and quality of produced water, options for 

managing produced water and associated regulatory issues, as well as options 

for improving existing technologies for treating produced water and developing 

new technologies, such as more cost-effective filters. 

View GAO-12-156. For more information, 

contact Anu Mittal or Frank Rusco at 

(202) 512-3841 or mittala@gao.gov or 

ruscof@gao.gov. 
Page i GAO-12-156 Energy-Water Nexus 

Letter 1 

Background 4

Oil and Gas Wells Generate a Significant Amount of Produced 

Water, but the Volume and Quality of the Water Produced at a 

Given Well Varies 9

A Number of Practices Are Available to Manage and Treat 

Produced Water, with Cost Being the Primary Determining 

Factor 14

EPA and the States We Reviewed Regulate the Management of 

Produced Water through a Variety of Means 25

Federal Research Efforts Have Focused on Describing the 

Characteristics of and Uses for Produced Water, Management 

Options, and Treatment Methods 29

Agency Comments 34

Appendix I Scope and Methodology 36

Appendix II Listing of Ongoing and Completed Federal Produced Water Research 

Efforts Undertaken during the Last 10 Years 38

Appendix III GAO Contacts and Staff Acknowledgments 51

Table

Table 1: Number of Injection Wells in Selected States 17

Figures

Figure 1: Geology of Gas Resources 6

Figure 2: Injection Wells for Produced Water 16

Contents
Page ii GAO-12-156 Energy-Water Nexus 

Abbreviations

BLM Bureau of Land Management

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

NETL National Energy Technology Laboratory

USGS U.S. Geological Survey

This is a work of the U.S. government and is not subject to copyright protection in the 

United States. The published product may be reproduced and distributed in its entirety 

without further permission from GAO. However, because this work may contain 

copyrighted images or other material, permission from the copyright holder may be 

necessary if you wish to reproduce this material separately.
Page 1 GAO-12-156 Energy-Water Nexus 

United States Government Accountability Office

Washington, DC 20548 

January 9, 2012 

The Honorable Eddie Bernice Johnson 

Ranking Member 

Committee on Science, Space, 

 and Technology 

House of Representatives 

Dear Ms. Johnson: 

The exploration for and production of oil and gas to meet our nation’s 

energy needs also results in the production of large quantities of water as 

a byproduct.1

 This water, which is produced from wells during exploration 

and production, is known as “produced water.” Because produced water 

may contain a variety of contaminants, such as salts and minerals, it is 

often considered to be a waste stream that oil and gas producers must 

appropriately manage and treat before this water can be disposed of. If it 

is not appropriately managed or treated, the contaminants present in 

produced water discharged from oil and gas operations may threaten 

human health and the environment. 

Oil and gas—known as hydrocarbons—are found in a variety of geologic 

formations. Oil can be found in deep, porous rock or reservoirs that can 

flow under natural pressure to the surface after drilling, as well as other 

geologic formations, including shale and oil sands, in which other 

processes must be used to extract the oil, such as injecting liquid into the 

formation or applying heat or steam. Similarly, gas can be found in porous 

rock or reservoirs, in coal seams (known as coalbed methane), and in 

tighter geologic formations, including tight sands and shale formations. 

Extracting oil and gas from any of these reserves can result in produced 

water as a byproduct because water can exist naturally along with oil and 

gas in geologic formations (known as formation water) or it can be added 

to the well to stimulate oil and gas production (known as injected water). 

Formation water and injected water can return to the surface as produced 

water along with the oil or gas that is being extracted from the well. In 

 

1

Most of the balance of the nation’s energy is supplied by coal, nuclear power, and 

hydropower and renewable resources. 

 
 

Page 2 GAO-12-156 Energy-Water Nexus 

other circumstances, such as when oil and gas are extracted from certain 

shale formations, water, sand, and chemicals are injected at high 

pressure to create fractures in the formation—a process known as 

hydraulic fracturing—thereby allowing the oil or gas to flow easier and be 

brought to the surface.2

Because of the inextricable link between energy production and water, 

you asked us to undertake a series of studies reviewing the energy-water 

nexus.

Some of this mix of water, sand, and chemicals 

returns to the surface when production starts (this type of produced water 

is known as flowback water). Over time, the quantity of produced 

flowback water generally diminishes, but smaller amounts of water will 

continue to be produced from the well.

3

While oil and gas production comes from onshore and offshore 

operations, the focus of this review is onshore because produced water 

from onshore sources has the potential to affect surface and groundwater 

quality, and a greater variety of practices are employed to manage 

produced water. To address these objectives, we conducted a literature 

review of studies and other documents on produced water quality and 

volume, management, and regulations issued by federal agencies and 

laboratories, state agencies, the oil and gas industry, and academic 

institutions. These documents included peer-reviewed scientific and 

This is the fifth and final study in this series and provides 

information on (1) what is known about the volume and quality of 

produced water from oil and gas production; (2) what practices are 

generally used to manage and treat produced water, and what factors are 

considered in the selection of each; (3) how the management of produced 

water is regulated at the federal level and in selected states; and (4) what 

federal research and development efforts have been undertaken during 

the last 10 years related to produced water.

 

2

Ceramic beads are sometimes used in lieu of sand when hydraulically fracturing a well.

Both are used to prevent the fractures from closing when the injection has stopped.

3

GAO, Energy-Water Nexus: Improvements to Federal Water Use Data Would Increase 

Understanding of Trends in Power Plant Water Use, GAO-10-23 (Washington, D.C.: Oct. 

16, 2009); Energy-Water Nexus: Many Uncertainties Remain about National and Regional 

Effects of Increased Biofuel Production on Water Resources, GAO-10-116 (Washington, 

D.C.: Nov. 30, 2009); Energy-Water Nexus: A Better and Coordinated Understanding of 

Water Resources Could Help Mitigate the Impacts of Potential Oil Shale Development, 

GAO-11-35 (Washington, D.C.: Oct. 29, 2010); Energy-Water Nexus: Amount of Energy 

Needed to Supply, Use, and Treat Water Is Location-Specific and Can Be Reduced by 

Certain Technologies and Approaches, GAO-11-225 (Washington, D.C.: Mar. 23, 2011).
 

Page 3 GAO-12-156 Energy-Water Nexus 

industry periodicals, government-sponsored research, and reports from 

nongovernmental research organizations. We believe we have included 

the key studies and have qualified our findings, where appropriate. 

However, it is possible that we may not have identified all of the studies 

with findings relevant to our objectives.

In addition, we interviewed stakeholders such as federal and state 

regulatory officials; federal scientists from the Environmental Protection 

Agency’s (EPA) Office of Research and Development and the 

Department of Energy’s (DOE) Argonne National Laboratory, Los Alamos 

National Laboratory, National Energy Technology Laboratory (NETL), 

Oak Ridge National Laboratory, and Sandia National Laboratories; 

officials from oil and gas exploration and production companies; officials 

from water treatment companies; and other experts with experience 

related to produced water. The federal and state regulatory officials 

included those with responsibility over oil and gas regulation, as well as 

clean water and drinking water regulation. We focused our review of 

management techniques and produced water regulation on nine states—

California, Colorado, Kansas, Louisiana, New Mexico, Oklahoma, 

Pennsylvania, Texas, and Wyoming. These states account for nearly 90 

percent of produced water generated.

We supplemented our literature review and stakeholder discussions with 

site visits to selected locations in Pennsylvania, Texas, and Wyoming, 

where we met with oil and gas producers and officials from produced 

water treatment facilities and discussed issues related to produced water 

management and treatment and the factors that influence these 

decisions. We selected these states because of the current and potential 

volumes of produced water generated, the range of hydrocarbons 

produced, and the different management and treatment practices 

employed. We also visited hydraulic fracturing drilling operations, 

underground injection control well sites, and a number of different 

treatment facilities employing a variety of technologies. To determine 

what federal research and development efforts have been undertaken 

during the last 10 years related to produced water, we analyzed 

information supplied by and conducted interviews with federal officials 

from DOE and select national laboratories, EPA, and the Department of 

the Interior’s U.S. Geological Survey (USGS), Bureau of Land 

Management (BLM), and Bureau of Reclamation.

We conducted this performance audit from October 2010 to January 

2012, in accordance with generally accepted government auditing 

standards. Those standards require that we plan and perform the audit to 
 

Page 4 GAO-12-156 Energy-Water Nexus 

obtain sufficient, appropriate evidence to provide a reasonable basis for 

our findings and conclusions based on our audit objectives. We believe 

that the evidence obtained provides a reasonable basis for our findings 

and conclusions based on our audit objectives.

The domestic production of oil and gas is essential to the nation’s energy 

portfolio. According to DOE’s Energy Information Administration (EIA), the 

United States consumed approximately 6.7 billion barrels of oil and 24 

trillion cubic feet of gas in 2010. Together, oil and gas production supply 

over 60 percent of the nation’s total energy demand, and demand is 

expected to grow in the future. While domestic drilling for oil and gas can 

present risks to the environment, it also results in the creation of jobs and 

economic growth, as well as payments to the government in the form of 

royalties.4

The U.S. oil and gas reserves located onshore are extensive, with proven 

onshore oil reserves of approximately 18 billion barrels and proven 

onshore gas reserves of approximately 271 trillion cubic feet as of 

December 2009, according to the EIA.5

 

4

The federal government issues leases for federal lands and waters to oil and gas 

operators who in turn pay royalties to the government on the oil and gas they produce.

These royalty payments totaled approximately $9 billion in 2009.

These reserves are located 

across the country, primarily in 31 key oil- and gas-producing states, and 

include a range of different types of hydrocarbons. These hydrocarbons 

include both conventional and unconventional oil and gas sources. 

Although there is no clear and consistently agreed upon distinction 

between conventional and unconventional oil and gas, conventional 

sources of oil and gas are generally produced using traditional methods 

of drilling and pumping, whereas unconventional oil and gas sources 

generally require more complex and expensive technologies for 

production. For example, in some instances heavy oils produced using 

steam injection are considered unconventional, while in other situations 

they are considered conventional. For this reason, in this report we 

generally do not distinguish between conventional and unconventional oil 

5

Proven, or proved, reserves are defined as oil and gas that geological and engineering 

data demonstrate with reasonable certainty to be recoverable in future years from known 

reservoirs under existing economic and operating conditions. While the United States also 

has extensive offshore oil and gas reserves, the focus of this report is limited to onshore 

oil and gas production. 

Background
 

Page 5 GAO-12-156 Energy-Water Nexus 

and gas except in instances when supporting documentation or 

information we use from other sources makes this distinction necessary; 

in such cases, we provide the relevant definition in a footnote.6

Oil and gas is found within underground layers of rock referred to as 

formations. The geologic characteristics of the formations in which the 

various hydrocarbons are found vary widely, along with the characteristics 

of the hydrocarbons themselves. For example, shale oil and gas 

formations are generally tighter and much less permeable than other 

formations, causing the oil and gas to be much less free flowing. Coalbed 

methane formations, located at shallow depths of 1,000 to 2,000 feet, are 

more permeable formations through which gas can flow more freely than 

through shale formations. In addition, heavy oil, due to its higher viscosity, 

has much less ability to flow freely through a formation compared to 

lighter oil.7

 

6

This report includes oil and gas currently produced onshore in the United States. It 

excludes some kinds of oil production from shale formations that are not generally being 

produced commercially at the current time, as well as oil sands, which are primarily 

produced in Canada. 

Figure 1 below provides examples of differing geologies for 

various gas hydrocarbons.

7

Viscosity is a measure of the resistance of a fluid to flow.
 

Page 6 GAO-12-156 Energy-Water Nexus 

Figure 1: Geology of Gas Resources

Note: “Associated gas” is gas that accumulates in conjunction with oil in a formation. “Non-associated 

gas” is gas that accumulates separately from oil in a formation. 

As a result of these geologic differences, the methods used to produce 

hydrocarbons vary widely. Some oil and gas can be produced by drilling a 

well and relying on the natural pressure in the formation to push the oil or 

gas to the surface. Heavy oil, on the other hand, may require the injection 

of an additive such as steam into the formation to stimulate the flow of 

oil—a process known as enhanced recovery. Similarly, some 

hydrocarbons are produced through the use of hydraulic fracturing. 

Hydraulic fracturing involves the injection of liquid under pressure to 

fracture the rock formation and to prop open the fractures to allow 

hydrocarbons to flow more freely from the formation into the well for 

collection. The liquids used in this process consist primarily of water, but 

also include chemicals, as well as sand or other propping agents for 

holding open the fractures (proppant). Hydraulic fracturing is commonly 

used to facilitate the production of many hydrocarbons, including oil, 

shale gas, tight gas, and coalbed methane. Recent improvements in 

hydraulic fracturing, combined with horizontal drilling technologies, have 

prompted a boom in shale oil and gas production.

The process of producing oil and gas is complicated and yields several 

byproducts that must be managed as part of the oil and gas operation’s 

waste stream. Key among these byproducts is the produced water that 
 

Page 7 GAO-12-156 Energy-Water Nexus 

comes to the surface along with the oil or gas during production. 

Produced water may include water that occurs naturally in the formation,

water or other liquids that were injected into the formation to enhance 

recovery during the drilling or production process, and flowback water, 

which is the water, proppants, and chemicals used for hydraulic fracturing 

(fracturing fluids).

EPA regulates water primarily through two federal laws: the Safe Drinking 

Water Act and the Clean Water Act. The Safe Drinking Water Act was 

originally passed by Congress in 1974 to protect public health by ensuring 

a safe drinking water supply.8 Under the act, EPA is authorized to set 

standards for both naturally-occurring and man-made contaminants that 

may be found in drinking water. The Safe Drinking Water Act also 

regulates the placement of wastewater and other fluids underground 

through the Underground Injection Control program. This program 

provides safeguards to ensure that wastewater injected underground 

does not endanger drinking water supplies. There are six classes or 

categories of wells regulated through the Underground Injection Control 

program. For example, class II wells are for the management of fluids 

associated with oil and gas production, and they include wells used to 

dispose of wastewater and those used to enhance oil and gas 

production.9

 

8

Pub. L. No. 93-523 (1974), codified as amended at 42 U.S.C. §§ 300f–300j-26. 

EPA may grant, or approve by rule, primary enforcement 

authority for the Underground Injection Control program to a state, which 

means that the state assumes responsibility for executing the program, 

including permitting, monitoring, and enforcement for operations within 

the state. To be approved for this authority, state programs must be at 

least as stringent as the federal program and show that their regulations 

contain effective minimum requirements. To obtain this authority over 

class II wells only, states with existing oil and gas programs may make an 

optional demonstration that their program is effective in protecting 

underground sources of drinking water.

9

The other classes of Underground Injection Control program wells are as follows: class I 

wells are used for the disposal of hazardous and certain nonhazardous waste; class III 

wells are used to inject fluids for mineral extraction; class IV wells are used to dispose of 

hazardous or radioactive wastes, into or above an underground source of drinking water; 

class V wells are used to dispose of other nonhazardous wastes; and class VI wells are 

used for carbon sequestration. Class IV wells are currently banned. 
 

Page 8 GAO-12-156 Energy-Water Nexus 

The Clean Water Act was enacted by Congress in 1972 to protect surface 

waters by regulating discharges of pollutants into those waters.10

Pursuant to the water-quality-based pollution control program mandated 

by the act, states establish and EPA approves water quality standards for 

contaminants in surface waters. The Clean Water Act also regulates the 

discharge of wastewaters, including produced water, through the National 

Pollutant Discharge Elimination System permit program, which requires 

all facilities that discharge pollutants from any point source into surface 

waters to be permitted.11

Oil and gas producers who would like to drill on federal lands managed by 

BLM must also obtain permits from BLM. The Federal Land Policy and 

Management Act of 1976 requires BLM to develop resource management 

plans, which, among other things, identify parcels of federal land that will 

be available for oil and gas development and leasing. Producers who 

have obtained a lease from BLM for oil and gas production on public 

lands must submit an application to BLM for a permit to drill before 

beginning to prepare the land or drilling any new oil or gas wells. The 

complete permit application package must include, among other things, a 

reclamation plan that details the steps operators propose to take to 

reclaim the site, including redistribution of topsoil, configuring the 

reshaped topography, and seeding or other steps to re-establish 

vegetation. In some circumstances, approval from state officials may also 

be required before operators can begin drilling and production.

EPA may delegate primary enforcement 

authority to a state for this program if a state demonstrates that its 

program requirements are as stringent as those set by EPA. Once EPA 

delegates this authority, the state is responsible for permitting, monitoring, 

and enforcing these permits.

 

10The Federal Water Pollution Control Act Amendments of 1972, Pub. L. No. 92-500, § 2, 

86 Stat. 816, codified as amended at 33 U.S.C. § 1251 et seq. (commonly referred to as 

the Clean Water Act).

11Surface waters refer to navigable waters, tributaries to navigable waters, interstate 

waters, the oceans out to 200 miles, and intrastate waters that are used by interstate 

travelers, for recreation or other purposes, as a source of fish or shellfish sold in interstate 

commerce, or for industrial purposes by industries engaged in interstate commerce. Point 

sources are wastes discharged from discrete sources such as pipes. The Clean Water Act 

defines point source as “any discernible, confined and discrete conveyance, including but 

not limited to any pipe, ditch, channel, tunnel, conduit, well, discrete fissure...or vessel or 

other floating craft from which pollutants are or may be discharged.” 
 

Page 9 GAO-12-156 Energy-Water Nexus 

In addition to obtaining permits for underground injection, discharge, and 

drilling, oil and gas producers may also be required to obtain permits from 

state or regional authorities to withdraw water from a river basin or 

underground. For example, producers in the Susquehanna River Basin 

must obtain a permit from the Basin Commission to withdraw surface 

water or groundwater. This water may be blended with recycled or 

produced water and used for hydraulic fracturing. Alternately, producers 

in Colorado and Wyoming must obtain groundwater permits from their 

State Engineer’s Office to drill for coalbed methane. State officials 

consider the drilling to be a beneficial use of water since producers must 

withdraw water from underground to obtain the gas and this classification 

means a permit is required.

A significant amount of water is produced daily as a byproduct from 

onshore drilling of oil and gas, but the volume produced by a given well 

will vary depending on the type of hydrocarbon being produced, the 

geographic location of the well, and the method of production used. 

Overall, most produced water is of poor quality and cannot be used for 

other purposes without prior treatment; however, produced water quality 

can also vary greatly depending on the hydrocarbon, geography, and 

production method.

An estimated 56 million barrels of produced water are generated every 

day as a byproduct of onshore oil and gas production in the United 

States. This estimate is based on an Argonne National Laboratory study 

of produced water volumes generated during 2007—the most recent year 

for which such data were collected—and was derived from data collected 

from state agencies in 31 oil- and gas-producing states.12

 

12Argonne National Laboratory, Produced Water Volumes and Management Practices in 

the United States, ANL/EVS/R-09/1 (Argonne, Ill.: September 2009).

The study is 

considered by agency officials, researchers, and other experts with whom 

we spoke to be the most comprehensive and accurate assessment of 

produced water volumes to date. However, because the Argonne study is 

based on limited and, in some cases, incomplete data, it likely 

underestimates the current total volume of produced water being 

Oil and Gas Wells 

Generate a Significant 

Amount of Produced 

Water, but the Volume 

and Quality of the 

Water Produced at a 

Given Well Varies

Millions of Barrels of 

Produced Water Are 

Generated Daily, but the 

Volume Produced at a 

Given Well Is Dependent 

on Several Factors
 

Page 10 GAO-12-156 Energy-Water Nexus 

generated by oil and gas operations today. Specifically, we noted the 

following limitations in the Argonne estimate:

• The reporting time frame for the study largely occurred prior to the 

recent, dramatic increase in shale gas production in the United States, 

which had an average annual growth rate of 48 percent from 2006 to 

2010, according to the EIA. In 2010, EIA had estimated that shale gas 

accounted for approximately 23 percent of all gas production in the 

United States.

• The study is based on state data that were collected and maintained 

using a variety of methods, making them difficult to compare and 

aggregate at a national level. For example, in some states, producers 

are required to report produced water volumes as measured by flow 

meters, whereas in other states, producers are required to estimate 

produced water volumes using a method of their choosing, which may 

limit the precision of the data. Furthermore, in other states, producers 

are only required to report produced water volumes they dispose of in 

injection wells, which may not reflect the total produced water 

generated. Lastly, some states do not collect data on produced water 

volumes at all. In such cases, Argonne generated estimates of 

produced water volumes based on available information on oil and gas 

production in the state and made certain assumptions about water 

volumes based on produced water data from neighboring states.

Although the Argonne study clearly demonstrates that a large amount of 

produced water is generated daily, the volume generated by a specific oil 

and gas well can vary significantly according to three key factors: the type 

of hydrocarbon being produced, the geographic location of the well, and 

the method of production used. First, according to literature we reviewed 

and stakeholders we spoke with, the type of hydrocarbon influences not 

only how much water a well generates, but also when the water is 

produced over the life of the well. This is because the geological 

formations for different hydrocarbons have different attributes, thus 

influencing the amount of water that is produced from a particular well. 

For example, coalbed methane wells produce large volumes of water in 

the early stages of production, because coal beds are essentially aquifers 

that contain coal rock and gas bound together from the pressure of the 

water present in the aquifer.13

 

13An aquifer is a natural underground layer, often of sand or gravel, that contains water.

By pumping out water, the resulting drop in 
 

Page 11 GAO-12-156 Energy-Water Nexus 

pressure allows the gas to detach from the coal and flow to the surface. In 

contrast, one producer noted that their conventional gas wells produce 

much less water than their coalbed methane wells because the 

formations from which conventional gas is drawn contain much less 

water.14

Second, according to the literature we reviewed and stakeholders we 

spoke with, the geographic location of a well also influences the volume 

of produced water it generates, due to differences in geology. For 

example, stakeholders noted that the Barnett Shale formation in Texas is 

generally known to be a “wetter” formation than the Marcellus Shale 

formation in the Northeast, with shale gas wells in the Barnett typically 

producing three to four times more water than shale gas wells in the 

Marcellus. Similarly, USGS reported that coalbed methane wells in the 

Powder River Basin in Wyoming and Montana produce, on average, 16 

times more water than coalbed methane wells in the San Juan Basin in 

Colorado and New Mexico. In addition, produced water volumes can vary 

among wells in close proximity with one another. For example, at one site 

we visited in Wyoming, some gas wells were producing two to three times 

more water than other gas wells in the same field, for reasons that were, 

in general, not clear to the operator of those wells.

Oil wells, on the other hand, typically generate less water during 

the first years of production, when formation pressure is high enough to 

allow the oil to flow freely to the surface. As these oil wells age, however, 

water volumes increase, as oil taken out is displaced by water flowing in 

from the surrounding formation. One producer that we spoke with noted 

that their older oil fields produce more than five times the volume of water 

produced by their younger oil fields.

Lastly, the method of production used to extract oil and gas also 

influences the volume of water generated, according to the literature we 

reviewed and stakeholders we spoke with. Specifically, stakeholders 

reported that methods of production that rely on the injection of water and 

other fluids into the formation in order to stimulate oil and gas production 

can generate more produced water than in cases in which oil and gas 

comes to the surface under existing pressure. For example, one 

stakeholder reported that the use of enhanced oil recovery methods such 

as steam injection can generate eight to nine barrels of water for every 

 

14In this example, conventional gas well is used to refer to formations typically consisting 

of porous sandstone that can be produced using traditional drilling methods. 
 

Page 12 GAO-12-156 Energy-Water Nexus 

barrel of oil produced. At one enhanced oil recovery field we visited, 

produced water comprised more than 95 percent of the total liquids 

produced, with oil comprising the remainder. Similarly, the use of 

hydraulic fracturing to produce oil or gas can result in larger volumes of 

produced water than production in more porous formations, although the 

larger volumes associated with hydraulic fracturing are limited to the initial 

flowback of water and fracturing fluids. For example, with shale gas 

production, stakeholders reported that flowback volumes can range from 

approximately 10,000 to 60,000 barrels per well for each hydraulic 

fracture.15 However, once the initial flowback ceases, the volume of water 

produced by shale gas production may be relatively small, sometimes

decreasing to just a few barrels per day.

The quality of produced water from oil and gas production is generally 

poor, and in most situations, it cannot be readily used for other purposes 

without prior treatment. According to the literature we reviewed and 

stakeholders we spoke with, produced water may contain a wide range of 

contaminants in varying amounts. Most of the contaminants occur 

naturally in the produced water, but some are added through the process 

of drilling, hydraulic fracturing, and pumping oil and gas. The range of 

contaminants found in produced water can include, but is not limited to

• salts, which include chlorides, bromides, and sulfides of calcium, 

magnesium, and sodium;

• metals, which include barium, manganese, iron, and strontium, among 

others;

• oil, grease, and dissolved organics, which include benzene and 

toluene, among others;

• naturally occurring radioactive materials; and

• production chemicals, which may include friction reducers to help with 

water flow, biocides to prevent growth of microorganisms, and 

additives to prevent corrosion, among others.

 

15An individual shale gas well is typically fractured between 10 and 16 times. 

Produced Water Is 

Generally of Poor Quality, 

with the Levels of 

Contaminants Varying 

Widely
 

Page 13 GAO-12-156 Energy-Water Nexus 

Exposure to these contaminants at high levels may pose risks to human 

health and the environment. For example, according to EPA, a potential 

human health risk from exposure to high levels of barium is increased 

blood pressure, and potential human health risks from exposure to high 

levels of benzene are anemia and increased risk of cancer. From an 

environmental standpoint, research indicated that elevated levels of salts 

can inhibit crop growth by hindering a plant’s ability to absorb water from 

the soil. Additionally, exposure to elevated levels of metals and 

production chemicals, such as biocides, can contribute to increased 

mortality among livestock and wildlife.

The specific quality of water generated by a given well, however, can vary 

widely according to the same three factors that impact the volume of 

water produced from the well: the hydrocarbon being produced, the 

geographic location of the well, and method of production used. First, 

according to stakeholders we spoke with, the type of hydrocarbon is a key 

driver of produced water quality, due to differences in geology across the 

formations in which the hydrocarbons are found. Specifically, the depth at 

which the hydrocarbons are found influences the salt and mineral content 

of produced water, and, in general, the deeper the formation is, the higher 

the salt and mineral content will be. For example, produced water from 

shale gas wells drilled at depths generally ranging from 5,000 to 8,000 

feet have salt and mineral levels 20 times higher than produced water 

from coalbed methane wells drilled at depths of 1,000 to 2,000 feet. 

Additionally, the amount of oil or gas that is mixed in with the produced 

water brought to the surface can also vary. For example, produced water 

typically blends more easily with oil than with gas. As a result, produced 

water from oil wells generally contains levels of oil, grease, and other 

organic compounds that are four to five times higher than water from gas 

wells.

Second, the quality of produced water also varies depending on the well’s 

geographic location, also because of differences in geology. For example, 

producers we spoke with said that produced water from wells in the 

Marcellus Shale formation in the Northeast has higher levels of 

radionuclides than water from shale gas wells in the Barnett Shale 

formation in Texas. Similarly, according to research, produced water from 

coalbed methane wells in the Raton Basin in Colorado and New Mexico 

has a salt content, on average, roughly two and a half times higher than 

produced water from the Powder River Basin in Wyoming and Montana. 

In addition, produced water quality can vary within a given region, 

according to producers we spoke with. For example, some coalbed 

methane wells in the Powder River Basin in Wyoming contain barium 
 

Page 14 GAO-12-156 Energy-Water Nexus 

levels five to six times higher than the barium levels found in wells less 

than 50 miles away. Additionally, produced water from wells in one oil 

field in California contains levels of boron four to five times higher than 

produced water from oil wells in neighboring fields.

Lastly, the method of production can affect the quality of the water 

produced. These differences are largely attributable to the chemicals and 

other substances added during drilling or production processes, according 

to stakeholders we spoke with. Specifically, methods of production that rely 

on hydraulic fracturing or enhanced recovery methods can result in poorer 

quality produced water than other methods. For example, according to 

stakeholders, the range of chemicals, sand, and water that are added to 

facilitate the hydraulic fracturing process can lower the overall quality of the 

produced water from these kinds of operations. Similarly, the use of 

chemicals during enhanced recovery can also affect the quality of water 

produced. Stakeholders noted that enhanced recovery involves the 

addition of production chemicals such as biocides, corrosion inhibitors, and 

friction reducers, along with steam or carbon dioxide. For example, one 

stakeholder estimated that wells produced using these enhanced recovery 

methods can yield produced water with levels of some production 

chemicals three to four times higher than produced water from wells that do 

not use enhanced recovery techniques.

Oil and gas producers have a number of options on how to manage 

produced water, but underground injection is the predominant practice. In 

addition to underground injection, a limited amount of produced water is 

managed by discharging it to surface water, storing it in surface 

impoundments, and reusing it for irrigation or hydraulic fracturing. With 

regard to treatment options, most produced water is minimally treated, 

although more advanced treatment methods are available if the end use 

of the water requires a higher level of treatment. Ultimately, cost is the 

primary driver in producers’ decisions about how to manage and treat 

produced water generated by oil and gas producers.

A Number of 

Practices Are 

Available to Manage 

and Treat Produced 

Water, with Cost 

Being the Primary 

Determining Factor
 

Page 15 GAO-12-156 Energy-Water Nexus 

Over 90 percent of the water produced during oil and gas operations is 

managed through underground injection practices; the remaining water is 

generally discharged to surface water, stored in surface impoundments, 

reused for irrigation, or reused for hydraulic fracturing. In its 2009 report,16

Argonne National Laboratory estimated, and EPA officials that we spoke 

with concurred, that most produced water is managed by injecting it 

underground into wells that are designated to receive this water.17

 

16Argonne National Laboratory, Produced Water Volumes and Management Practices in 

the United States. 

These 

wells, known as injection wells, must be constructed to protect 

underground sources of drinking water, and they are tested and 

monitored periodically to ensure no drinking water is being contaminated 

by well operations (see fig. 2). Injection wells can be used for enhanced 

recovery or permanent disposal of the water. When producers reuse 

produced water for enhanced recovery, they inject it into wells in the 

same producing formation to recover additional oil and, in limited 

applications, gas, thus prolonging the life of the production well. Some of 

this water will come back up as produced water in subsequent well 

operations. When producers inject produced water for permanent 

disposal into an underground formation, they inject it into wells in the 

same formation or a formation that is similar to the one the produced 

water was extracted from.

17Argonne National Laboratory reported that more than 98 percent of produced water 

generated from onshore oil and gas wells in 2007 was injected underground. EPA officials 

we spoke with estimated that over 90 percent of produced water generated from onshore 

wells is still injected underground but could not provide a precise figure for current 

volumes.

Produced Water Can Be 

Managed in a Number of 

Ways, although 

Underground Injection Is 

the Most Common Practice
 

Page 16 GAO-12-156 Energy-Water Nexus 

Figure 2: Injection Wells for Produced Water
 

Page 17 GAO-12-156 Energy-Water Nexus 

According to EPA records, in 2010 there were 150,855 injection wells 

authorized for the injection of fluids brought to the surface during oil and 

gas production, including produced water, although EPA officials told us 

that not all are currently operating.18

Table 1: Number of Injection Wells in Selected States 

About four-fifths of the wells—

124,837—are located in the nine states we reviewed (see table 1).

State Number of injection wells

Texas 52,016

California 29,505

Kansas 16,658

Oklahoma 10,629

Wyoming 4,978

New Mexico 4,585

Louisiana 3,731

Pennsylvania 1,861

Colorado 874

Total in selected states 124,837

Source: GAO analysis of EPA data.

According to state regulators we interviewed in the nine states, underground 

injection is common in most, but not all, of their states. Specifically, 

regulators in five states told us that all or almost all of the produced water is 

managed through underground injection, and in three other states, most of 

the produced water is managed this way. In the ninth state—Pennsylvania—

many producers use underground injection for enhanced recovery, but the 

practice is not widely used for disposal, according to EPA officials.19

 

18Although approximately 80 percent of these injection wells are used for enhanced 

recovery and the remaining 20 percent are used for disposal, only about 59 percent of 

produced water is injected into these wells for enhanced recovery, and about 40 percent is 

injected for disposal.

19According to EPA officials, there are currently only six active injection wells for produced 

water disposal in Pennsylvania. As a result, producers that want to dispose of produced 

water through underground injection would generally have to transport the water to 

authorized injection wells in Ohio or West Virginia, and trucking can be expensive. 

However, EPA officials we interviewed said that in the past 2 years producers have shown 

interest in drilling additional injection wells for disposal in Pennsylvania, and EPA has 

received permit applications for new wells. 
 

Page 18 GAO-12-156 Energy-Water Nexus 

Produced water that is not injected into underground injection wells is 

disposed of or reused by producers in other ways, including the 

following.20

Discharge to surface water. According to Argonne National Laboratory’s 

report, less than 1 percent of produced water generated from onshore oil 

and gas operations in 2007 was managed by discharging it to surface 

water.21 Surface discharges of produced water directly from oil and gas 

production sites are prohibited in much of the United States, but produced 

water may be discharged from an off-site treatment facility.22 According to 

Argonne’s report, discharges of produced water to surface water are 

primarily limited to the western United States and generally occur only 

when the salt content of the water is low. While a current national 

estimate of this practice is not available, EPA officials and regulators in 

seven of the nine states we reviewed told us that surface discharges of 

produced water are limited or are nonexistent in their states. For example, 

officials we spoke with from Colorado said that a very small portion of the 

produced water generated in that state is discharged to surface water and 

only 24 of the approximately 9,900 discharge permits they have issued 

are for oil and gas producers. Among the states we reviewed, Wyoming 

and Pennsylvania were the only two where producers commonly use 

surface discharges to manage produced water.23

 

20Other less commonly used management practices, such as reusing the produced water 

in industrial settings for dust control or cooling water, may also be options for producers. 

For example, an oil 

producer we spoke with in Wyoming told us his company discharges a 

small portion of the produced water from some of its fields directly to a 

nearby creek because the water quality is high enough to meet the state’s 

discharge limits without prior treatment; however, the majority of the water 

generated from these fields has a much higher salt concentration and 

cannot be discharged into surface waters.

21Argonne National Laboratory, Produced Water Volumes and Management Practices in 

the United States. 

22There are limited exceptions to this prohibition. For example, produced water from 

onshore oil and gas production sites located west of the 98th meridian that will be put to 

beneficial use for agriculture or wildlife watering can be discharged directly from the 

production site. 

23Pennsylvania regulatory officials told us that almost all conventional oil and gas 

producers use surface discharges to manage produced water, following treatment; 

however, almost all shale gas producers in Pennsylvania stopped using this practice after 

the state’s surface discharge standards were made more stringent in 2011. 
 

Page 19 GAO-12-156 Energy-Water Nexus 

Surface impoundment. Surface impoundments are lined or unlined ponds 

used primarily to facilitate evaporation of produced water, and in the case 

of unlined ponds, allow it to infiltrate into the ground.24 According to 

DOE’s NETL, drier climates are favorable for evaporation and spray 

nozzles may be used to increase the rate of evaporation. The National 

Research Council reported that, in 2008, surface impoundments were 

used to manage about 64 percent of produced water generated by 

coalbed methane producers in the Wyoming portion of the Powder River 

Basin.25

Irrigation. Some produced water from coalbed methane is reused for 

irrigation in certain parts of Wyoming and Colorado because the water is 

generally of high enough quality that it does not require extensive 

treatment in order to avoid damage to the crops or soil. According to the 

National Research Council,

According to the report, the water was generally untreated, but in 

some cases water was treated to meet requirements for discharging to 

the impoundment. For example, a coalbed methane producer we visited 

in Wyoming treats the produced water at a treatment facility to first 

remove barium to meet state water quality standards, then disposes of 

most of it in a surface impoundment, where it evaporates or infiltrates to 

the subsurface. Officials we spoke with from California, Colorado, and 

New Mexico also said that surface impoundments are used to manage 

produced water in those states, but it is not a significant practice in any of 

them.

26 about 13 percent of the produced water 

generated from coalbed methane producers in Wyoming’s Powder River 

Basin was reused for managed irrigation or subsurface drip irrigation.27

 

24Surface impoundments are also used for the temporary storage of produced water prior 

to managing it in some other way.

For example, a coalbed methane production operation we visited in 

Wyoming disposes of almost all of its produced water from the Powder 

River Basin using a managed irrigation system, following minimal 

25National Research Council, Management and Effects of Coalbed Methane Produced 

Water in the Western United States (Washington, D.C.: 2010).

26National Research Council, Management and Effects of Coalbed Methane Produced 

Water in the Western United States. 

27Managed irrigation combines irrigation using produced water with preventative or 

intervention soil management, such as the addition of gypsum and elemental sulfur to 

improve the soil structure. Managed irrigation is necessary to prevent substantial 

deterioration of the soil structure caused by the salts and sodium present in produced 

water. 
 

Page 20 GAO-12-156 Energy-Water Nexus 

treatment of the water. Because its wells produce more water than can be 

disposed of under its surface discharge permit, it is a fairly economical 

option, and is allowable under state regulations. While there are 

examples of irrigation with produced water occurring elsewhere, it is not a 

widely used management practice. According to NETL, a significant 

challenge to using produced water for irrigation is the salt content of the 

water, which can decrease crop yields and damage the soil. In addition, 

the National Research Council reported that while reusing coalbed 

methane produced water for beneficial purposes such as irrigation would 

seem to be a desirable and relatively easy objective, in reality it is 

potentially economically and environmentally burdensome, complex, and 

challenging. The suitability of water for irrigation depends on a number of 

factors including the type of crops grown, the soil type, irrigation methods, 

and the types and quantity of salts dissolved in the water. In addition, the 

reliability of the produced water supply over time, proximity to the 

irrigation site, and costs also present challenges.

Hydraulic fracturing. In recent years, some shale gas producers have 

begun reusing produced water for hydraulic fracturing of additional wells 

at their operations. The water is typically treated first, either on-site or offsite, and then mixed with freshwater if salt concentrations remain high. 

Although no national estimate of producers’ use of this practice is 

available, a 2009 report on shale gas development reported that interest 

in this type of reuse for produced water was high.28

 

28Ground Water Protection Council and ALL Consulting, Modern Shale Gas Development 

in the United States: A Primer (Oklahoma City, Okla.: April 2009). 

However, the report

also noted that certain water treatment challenges needed to be 

overcome to make this type of reuse more widespread. According to 

NETL, in order for reuse of produced water to become widespread, lowcost treatment technologies must be developed. In the last couple of 

years, reusing produced water for hydraulic fracturing has become more 

common among shale gas producers in Pennsylvania, according to state 

regulators and producers we spoke with in the state. The shift was 

motivated, in part, by a change in the state’s surface discharge standards 

that ultimately made treatment and discharge a comparatively more 

expensive practice. For example, one shale gas production site we visited 

in Pennsylvania currently reuses all of its produced water for hydraulic 

fracturing, although it had used other practices in the past. Other shale 

gas producers in the state are also adopting this approach, according to 
 

Page 21 GAO-12-156 Energy-Water Nexus 

agency officials and an academic expert we spoke with. In addition, 

regulators in five of the other states we reviewed told us that producers in 

these states are reusing produced water for hydraulic fracturing, although 

generally to a lesser extent than in Pennsylvania.

Because most produced water is managed through underground injection 

wells, it is minimally treated; however, if produced water is going to be 

reused or disposed of in some other manner, then more advanced 

treatment methods are available, depending on the level of treatment 

required.

Treatment methods for produced water managed through underground 

injection. Produced water managed through underground injection 

generally does not need to be treated because injection wells are 

designed to confine the produced water to the receiving formation and 

prevent it from migrating to underground sources of drinking water. In 

some cases, however, to meet an injection well’s operating requirements 

or prevent premature “plugging” of the formation, the water may be 

treated to control excessive solids, dissolved oil, corrosion, chemical 

reactions, or the growth of bacteria and other microbes, according to 

NETL. Such treatment is generally minimal and can include storing the 

water in a tank to allow solids to settle out and passing the water through 

a screen or filter to remove additional solids. Chemicals may also be 

added to prevent corrosion of the injection well equipment and filtration or 

biocides may be used to prevent bacteria, algae, or fungi present in the 

water from clogging equipment or encouraging corrosion.

Treatment methods for produced water reused for hydraulic fracturing. 

Producers who reuse produced water for hydraulic fracturing told us they 

treat the water to meet their own operating requirements. While producers

we spoke with said that they had previously treated the water to a very 

high quality before reusing it for hydraulic fracturing, they are currently 

experimenting with lower levels of treatment. For example, one producer 

told us that 2 years ago his company treated the water so that it was 

nearly as clean as freshwater, but based on internal research, the 

company no longer removes salt from the produced water that it reuses 

for hydraulic fracturing. This lower level of treatment has reduced 

operating costs, and the producer is considering eliminating other 

treatment steps as long as doing so will not cause operational problems, 

such as equipment corrosion.

Most Produced Water Is 

Minimally Treated, but 

More Advanced Treatment 

Methods Are Available
 

Page 22 GAO-12-156 Energy-Water Nexus 

Treatment methods for produced water discharged to surface water 

bodies or reused for irrigation. If produced water is going to be discharged 

to surface water or reused for irrigation, then treatment is often necessary 

to reduce hardness, salts, and other contaminants, in addition to settling 

and filtration methods to remove solids. Solids and hardness removal are 

sometimes referred to as “pretreatment” steps. Hard water contains 

dissolved constituents, mainly calcium and magnesium ions, which can 

cause scaling of pipes and equipment. Hardness is typically removed

prior to removing salts by adjusting the pH of the water and adding 

chemicals that cause dissolved calcium and magnesium to form small 

solids, or precipitates, which then settle out or are filtered out of the water 

with the aid of additional processes.29 Alternatively, when produced water 

is going to be reused for irrigation, calcium or magnesium may be added 

to the water to address sodium levels. Treatment technologies, including 

distillation, reverse osmosis, and ion exchange, are then used to remove 

salt and other contaminants from produced water.30 Distillation is a 

treatment process that essentially boils produced water to evaporate and 

then condense the clean water, leaving behind concentrated brine. 

Reverse osmosis is a filtration process that forces water through a semipermeable membrane, allowing water to pass through but trapping salt on 

the other side. Reverse osmosis generally requires a high level of 

pretreatment to prevent fouling of the membranes, and it is only feasible 

when salt concentrations in the produced water are less than 

approximately 25,000 parts per million, according to a study by the 

Colorado School of Mines.31

 

29pH is a measure of how acidic or basic the water is. Excessively high or low pH can be 

detrimental for the use of water.

For example, produced water from a gas 

operation we visited in Wyoming had to first undergo pretreatment to 

remove solids, hardness, and other contaminants before being put 

through three stages of reverse osmosis. A third treatment technology, 

ion exchange, selectively captures sodium ions from produced water and 

30The ratio of sodium to calcium and magnesium ions in produced water is an important 

property affecting the infiltration and permeability of the soil. The sodium adsorption ratio

is an index used to measure the hazard related to sodium abundance in the soil. 

31Colorado School of Mines, An Integrated Framework for Treatment and Management of 

Produced Water (Golden, Colo.: November 2009). The Colorado School of Mines also 

reported that total dissolved solids (i.e., salt concentrations) in produced water from 

conventional oil and gas in the western United States range from 1,000 to 400,000 parts 

per million. Producers we interviewed in other parts of the United States told us total 

dissolved solids in their produced water range from 40,000 to 300,000 parts per million. 
 

Page 23 GAO-12-156 Energy-Water Nexus 

replaces them with others.32 The water is passed through a large bed of 

resin beads and sodium ions are adsorbed to (i.e., concentrate on the 

surface of) the resin. Similar to reverse osmosis, ion exchange faces 

upper limits on salt concentrations of approximately 7,000 parts per 

million, according to the Colorado School of Mines.33 Each of the 

technologies to remove salt typically generates concentrated brine, which 

must then be properly disposed of as well.

While a variety of factors influence how produced water is managed and 

the level to which it is treated, cost is the primary factor that oil and gas 

producers consider when making these decisions. According to producers 

and agency officials we spoke with, how produced water is managed and 

treated is primarily an economic decision, made within the bounds of 

federal and state regulations. In most cases, underground injection is the 

lowest-cost option and producers we spoke with said that their costs for 

underground injection range from $0.07 to $1.60 per barrel of produced 

water.

34

Another significant component of cost is whether treatment will be 

required as part of the management practice being employed. Treatment 

costs depend heavily on the technologies used, which in turn depend on

the quality of the produced water being treated and the level of treatment 

However, if a producer is not operating in close proximity to 

injection wells, transporting the water via truck or pipeline can significantly 

increase these costs. Furthermore, producers told us that trucking is one 

of the most significant cost factors they face, and they seek to minimize 

this cost by managing the water closer to the production site when 

possible. For example, according to one producer, trucking costs in Texas 

range from $0.50 to $1.00 per barrel because injection wells in the area 

are plentiful, whereas costs in Pennsylvania range from $4.00 to $8.00 

per barrel because injection wells are scarce, and the produced water 

often must be transported out of state. As a result, once trucking is 

factored in, underground injection may in fact become more costly than 

other management practices.

 

32Ion exchange can also be used to remove hardness.

33Colorado School of Mines, An Integrated Framework for Treatment and Management of 

Produced Water.

34The costs presented in this report generally do not include construction costs for the 

injection well or treatment facility.

Cost Is the Primary Factor 

That Determines How 

Produced Water Is 

Managed and Treated
 

Page 24 GAO-12-156 Energy-Water Nexus 

needed for the disposal or reuse option being considered. For example, 

there are a number of treatment methods to remove salt from produced 

water, but each option has a different cost and differing level of 

effectiveness. Distillation, while effective at removing salts, has 

significantly higher costs, and representatives from water treatment 

facilities and producers we spoke to said it can cost from $6.35 to $8.50 

per barrel, on average. Reverse osmosis and ion exchange are less 

costly treatment options for removing salt, but their use is limited by the 

level of salt content they can remove from produced water, and reverse 

osmosis can require extensive pretreatment, which can significantly drive 

up costs. Producers we spoke with who use reverse osmosis and ion 

exchange to treat produced water told us that their costs range from 

$0.20 to $0.60 per barrel. In some cases, producers may be able to 

change the management practice they use to minimize their treatment 

costs. For example, state regulators told us that when more stringent 

discharge limits were put into place in Pennsylvania, many shale gas 

producers in the state stopped discharging produced water to the surface 

and started to reuse it for hydraulic fracturing because the latter requires 

a simpler, and less expensive, level of treatment.

In addition to cost, according to our review of the literature and 

stakeholders we spoke with, produced water management decisions are 

also influenced by a number of other factors including the following:

• Poor water quality is a key reason most produced water is managed 

through underground injection, rather than reused or discharged to 

the surface. However, when water quality is relatively good, as some 

of it is in the Powder River Basin of Wyoming, management practices 

such as irrigation and infiltration from surface impoundments may 

become viable options. Nonetheless, adequate quantities of produced 

water are needed for irrigation to be a sustainable practice, and the 

water must be in close proximity to the land it will be used on or 

producers can face high transportation costs.

• Proximity and region-specific factors, such as geology, also influence 

which management practices are feasible in a given area. For 

example, some oil and gas producers are not located in close 

proximity to injection wells, or the number of available wells is limited 

by the underlying geology of the area, and therefore producers must 

manage their produced water some other way. An oil producer we 

spoke to told us his company would prefer to manage all of its 

produced water through underground injection for enhanced recovery 

and disposal. However, opportunities for enhanced recovery at one of 
 

Page 25 GAO-12-156 Energy-Water Nexus 

the producer’s sites are limited by its level of oil production and 

disposal is constrained by the geology in the area. As a result, the 

producer told us he manages about 20 percent of the produced water 

from this site through treatment and discharge, which is significantly 

more costly and technically challenging than underground injection.

• Climate is also a factor in the decision-making process. Arid climates 

are favorable for managing produced water using surface 

impoundments for evaporation, and limited water supplies in certain 

regions can motivate producers to make the water available for other 

purposes, such as irrigation.

• Regulatory requirements at the federal or state level can also 

influence producers’ management decisions. As discussed earlier, the 

changes in discharge limits in Pennsylvania led to a change in 

management practices by shale gas producers in the state.

• Producers’ risk management policies can also influence how they 

manage the water. For example, regulators we spoke with from 

California told us that liabilities associated with surface discharges and 

impoundments are a driving factor in moving away from those practices 

and toward underground injection. According to these regulators, 

surface impoundments were commonly used in California to manage 

produced water in the past, but in the last few years hundreds of them 

have closed down and they are no longer widely used.

The management of produced water is regulated by EPA and the states 

we reviewed through a variety of means, depending on how the water is 

disposed of or reused. EPA regulates the management of produced water 

that is injected underground under the Safe Drinking Water Act, while it 

regulates the management of produced water that is discharged into 

surface waters under the Clean Water Act. Other management practices, 

such as disposal of the water into surface impoundments, irrigation, and 

reuse of the water for hydraulic fracturing, are primarily regulated by the 

state authorities.

The management of produced water through underground injection is 

subject to the Safe Drinking Water Act’s Underground Injection Control 

program. This program is designed to prevent contamination of aquifers 

that supply, or could supply in the future, public water systems by 

EPA and the States 

We Reviewed 

Regulate the 

Management of 

Produced Water 

through a Variety of 

Means

Underground Injection Is 

Regulated under the Safe 

Drinking Water Act
 

Page 26 GAO-12-156 Energy-Water Nexus 

ensuring the safe operation of injection wells. Under this program, EPA or 

authorized states generally require producers to obtain permits for their 

injection wells by, among other things, meeting technical standards for 

constructing, operating, and testing and monitoring wells.35

As part of the Underground Injection Control program, producers 

generally must apply for a permit to drill an injection well and supply 

information, including the location and depth of the proposed well. 

Furthermore, once EPA or the state has issued an Underground Injection 

Control permit, producers must observe and record the injection pressure, 

flow rate, and cumulative volume each month and report this information 

to the permitting agency annually. In addition, the injection well permit 

also requires producers to conduct mechanical integrity tests on the wells 

at least once every 5 years, although EPA and some states require 

testing to be performed more often, according to officials we spoke with. 

Officials at many of the state agencies we spoke with said that they 

observe these tests in person to ensure that the well is mechanically 

sound. According to officials in each of the eight states we contacted, the 

state can levy penalties for noncompliance for violations ranging from a 

failure to submit a report to exceeding the pressure permitted in the well. 

Enforcement response to noncompliance can range from a warning letter 

to a fine. EPA can commence a separate action for penalties if it believes 

that a state’s imposition of penalties is insufficient, although EPA officials 

we spoke with stated that this is rare. 

Of the nine 

states we reviewed, all but Pennsylvania have received approval authority 

from EPA to implement this program for class II wells, including issuing 

permits and conducting oversight. In most of these states, the agency that 

oversees oil and gas activities is responsible for implementing this 

program. Regardless of whether EPA or the state has authority for 

implementing the program, EPA regional offices periodically review each 

state’s program and require states to submit an annual report on program 

activity, according to EPA officials from the regions we spoke with.

 

35Certain existing injection wells were authorized by rule if the well was properly 

inventoried within 1 year after the effective date of the applicable Underground Injection 

Control program. 
 

Page 27 GAO-12-156 Energy-Water Nexus 

The management of produced water through discharge into surface 

waters is regulated under the Clean Water Act’s National Pollutant 

Discharge Elimination System. Under this program, all facilities that 

discharge pollutants to surface waters must obtain a permit from EPA or 

the designated state agency, which is generally the agency responsible 

for environmental protection or quality. Permits can be tailored to 

individual facilities or cover multiple facilities within a specific geographic 

region. To obtain a permit, producers must complete an application that, 

among other things, describes the waste that will be discharged, where 

the discharge will take place, and the method of treatment or 

containment, if applicable. Once the state or EPA has issued a permit, 

producers must report any discharges, including the volume of effluent 

and the amount of each pollutant specified in the permit, to the permitting 

authority at least once per year. EPA has issued regulations establishing 

Effluent Limitations Guidelines for some onshore oil and gas extraction 

including shale gas, but these regulations do not apply to coalbed 

methane extraction.36

Of the nine states we reviewed, all but New Mexico have received 

approval authority from EPA to implement this program for industrial and 

municipal facilities. EPA requires states with approval authority to submit 

annual reports on program activity in their state and conduct program 

reviews every 2 to 5 years. Of these eight states, four—California, 

Colorado, Pennsylvania, and Wyoming—have issued permits for the 

discharge of produced water. This is in part because discharging 

produced water directly from a production site is generally prohibited by 

regulations implementing the Clean Water Act for locations east of the 

98th meridian, which, in the United States, runs from near the eastern 

border of North Dakota through the eastern portion of Texas, passing 

near the Dallas-Ft. Worth area. Discharge of produced water from an offsite treatment plant, however, is allowed under the Clean Water Act 

provided the treated water meets applicable water quality standards, and 

some states have permitted this activity. For example, a commercial 

water treatment facility we visited in Pennsylvania treats produced water 

from shale gas to meet the state’s new, more stringent discharge limits 

 

 

36On October 20, 2011, EPA announced it is developing standards for wastewater 

discharges produced by natural gas extraction from underground coalbed and shale 

formations. No comprehensive set of national standards exists at this time for the disposal 

of wastewater discharged from natural gas extraction activities. The agency plans to 

propose wastewater rules for coalbed methane in 2013 and for shale gas in 2014. 

Discharge of Produced 

Water Is Regulated under 

the Clean Water Act
 

Page 28 GAO-12-156 Energy-Water Nexus 

and then releases it to a municipal sewer system. In addition, one 

producer we spoke with in Wyoming told us his company takes some of 

its produced water to a treatment facility, where it is treated with reverse 

osmosis and then discharged to a ravine that flows into the Powder River. 

The eight states that have approval authority to administer the discharge 

program may levy penalties if they find producers are not complying with 

their permit, or if they are discharging without a permit, according to 

officials we spoke with. As with the Underground Injection Control 

program, EPA may commence a separate action for penalties if it 

believes a state’s penalty determination to be inadequate, but EPA 

officials we spoke with stated that this is rare.

The management of produced water through disposal into a surface 

impoundment or reuse for irrigation is regulated at the state level in the 

four states we reviewed where producers employ these practices. For 

example, the Oil and Gas Conservation Commissions in Colorado and 

Wyoming are among the state regulatory agencies that allow for disposal 

in surface impoundments; however, these states have set different 

standards for the quality of the water that may be placed in the ponds. For 

example, Colorado generally does not require these ponds to be lined, 

while Wyoming requires any pond with a total dissolved solids level of 

10,000 parts per million or more to be lined. In addition, Wyoming also 

allows produced water to be used for irrigation or as water for livestock 

with approval from the Wyoming Department of Environmental Quality.

Some of the states we reviewed also regulate other practices to reuse 

produced water. For example, regulations in Colorado, Pennsylvania, and 

Wyoming allow for the application of produced water to roads in certain 

circumstances. Specifically, Colorado regulations allow produced water to 

be spread on roads as long as it meets certain requirements and is 

authorized by the owner of the road. In addition, reuse of produced water 

for hydraulic fracturing is regulated at the state level for some states.37

 

37In general, the process of hydraulic fracturing is not directly regulated at the federal level 

at this time. Congress exempted most hydraulic fracturing activities from EPA’s jurisdiction 

in the 2005 Energy Policy Act amendments to the Safe Drinking Water Act; however, the 

agency has authority to regulate hydraulic fracturing when diesel fuels are used in 

fracturing fluids or propping agents. EPA is currently studying the impacts of hydraulic 

fracturing and plans to issue an interim report on the potential impacts of hydraulic 

fracturing on drinking water resources in 2012 and a final report in 2014.

Specifically, some states have regulations that apply to the temporary 

Other Management 

Practices Are Regulated by 

State Authorities
 

Page 29 GAO-12-156 Energy-Water Nexus 

storage of hydraulic fracturing fluids, including flowback water, on drilling 

sites. For example, Oklahoma has recently adopted standards for the 

construction, operation, location, and maintenance of noncommercial 

ponds used for temporary storage of flowback water. In addition, some 

states have begun to require producers to disclose the chemical 

composition of their hydraulic fracturing fluids. Of the nine states we 

reviewed, four states—Louisiana, Pennsylvania, Texas, and Wyoming—

currently require this disclosure.

Over 100 federal research studies conducted during the last 10 years 

have addressed various aspects of using, managing, and treating 

produced water. Many federal research projects have focused on 

describing the characteristics of produced water, such as the volume of 

water produced from oil and gas activities and the quality of that water. 

Other research efforts have focused on describing strategies producers 

could use to manage produced water and the regulatory context for doing 

so. Federal research also has focused on developing and describing new 

and existing technologies for treating produced water. Appendix II of this 

report includes a compilation of the studies we identified.

Several federal agencies, including USGS, the Bureau of Reclamation, a 

number of DOE national laboratories, and EPA, have issued or 

sponsored studies describing the characteristics of produced water from 

oil and gas operations––particularly the volume and quality of produced 

water. For example, in 2009, USGS published a fact sheet that, among 

other things, described water disposal issues associated with gas 

production in the Marcellus Shale.38 More recently, in 2010, USGS 

published an article describing the quality of produced water from coalbed 

methane production, and how untreated or partially treated produced 

water from these operations may threaten fish and aquatic resources.39

 

38Daniel J. Soeder and William M. Kappel, Water Resources and Natural Gas Production 

from the Marcellus Shale, USGS Fact Sheet 2009-3032 (May 2009).

USGS also maintains a database that provides the location, geologic 

39Aida M. Farag, David D. Harper, Anna Senecal, and Wayne A. Hubert, “Potential Effects 

of Coalbed Natural Gas Development on Fish and Aquatic Resources,” chap. 11 in 

Coalbed Natural Gas: Energy and Environment (Nova Science Publishers, Inc., 2010).

Federal Research 

Efforts Have Focused 

on Describing the 

Characteristics of and 

Uses for Produced 

Water, Management 

Options, and 

Treatment Methods

Federal Research Efforts 

Have Examined the 

Characteristics of 

Produced Water
 

Page 30 GAO-12-156 Energy-Water Nexus 

setting, and chemical composition of produced water samples from 

locations throughout the United States.

The Department of the Interior’s Bureau of Reclamation participated in a 

study published in 2008 that describes the quantity of produced water 

generated and specific contaminants it contains from oil and gas 

production in the western United States.40

Several DOE national laboratories have also sponsored or published 

research describing the volume and quality of produced water. Argonne 

National Laboratory has published two studies—a 2004 study that 

provided basic information about how much produced water is generated 

and what contaminants are in it,

The study was designed to 

assist producers and others in determining viability of this water for 

beneficial reuse and for selecting appropriate treatment processes.

41 and a 2009 study that describes 

produced water volumes and management practices in every oil- or gasproducing state in the United States.42 Oak Ridge National Laboratory 

has conducted a number of produced water research studies designed to 

characterize and evaluate the soluble organic compounds that 

contaminate the water. In addition, NETL cosponsored several such 

studies, including a 2003 project that provided information about 

radioactive materials from hydrocarbon production in Mississippi.43

Another NETL project, completed in 2005, provided a means by which 

interested stakeholders could access a large quantity of produced water 

chemistry data for New Mexico oil wells.44

 

40Katie L. Benko and Jörg E. Drewes, “Produced Water in the Western United States: 

Geographical Distribution, Occurrence, and Composition,” Environmental Engineering 

Science, vol. 25, no. 2 (2008):.239 – 246.

NETL is currently engaged in 

41John A. Veil, Markus G. Puder, Deborah Elcock, and Robert J. Redweik, Jr., Argonne 

National Laboratory, A White Paper Describing Produced Water from Production of Crude 

Oil, Natural Gas, and Coal Bed Methane (January 2004).

42Argonne National Laboratory, Produced Water Volumes and Management Practices in 

the United States. 

43Evaluations of Radionuclides of Uranium, Thorium, and Radium Associated with 

Produced Fluids, Precipitates, and Sludges from Oil, Gas, and Oilfield Brine Injection 

Wells in Mississippi, a study cosponsored by the National Energy Technology Laboratory, 

2002-2003.

44NM WAIDS: A Produced-Water Quality and Infrastructure GIS Database for New Mexico 

Oil Production, a study sponsored by the National Energy Technology Laboratory, project 

start: 2002, project end: 2005.
 

Page 31 GAO-12-156 Energy-Water Nexus 

two other projects. The first is designed to differentiate produced water 

from surface water or shallow groundwater in the Marcellus shale area. 

The other is a multiagency effort with industry, EPA, and USGS, among 

others, to establish baseline water quality data at a Marcellus drilling site 

that will be monitored 1 year prior to development and compared to data 

acquired for 1 year after production begins.

Finally, EPA’s Office of Research and Development initiated a study in 

January 2010 to examine the potential impacts of hydraulic fracturing on 

drinking water resources and the quality of flowback and produced water. 

The study plan is currently being reviewed by EPA’s Science Advisory 

Board, and the agency anticipates issuing an interim report on the 

potential impacts of hydraulic fracturing on drinking water resources in 

2012 and a final report in 2014.

Federal research has also focused on providing information about options 

producers can use to manage their produced water and the regulations 

they must follow in doing so. For example, the Energy Policy Act of 2005 

mandated that the Department of the Interior, in consultation with EPA, 

engage the National Academy of Sciences to conduct a study on the effect 

of coalbed methane production on surface and groundwater resources in 

selected northern and western states. The study was issued in 2010.45

Several DOE laboratories have also conducted studies or partnered with 

industry, universities, and other labs to provide information about managing 

produced water and associated regulations. For example, in May 2009, 

NETL, in cooperation with the Ground Water Protection Council, published 

a report summarizing produced-water-related regulations enacted by states 

for the purpose of protecting water resources.46

 

45National Research Council, Management and Effects of Coalbed Methane Produced 

Water in the Western United States. 

NETL is also currently 

partnered with Clemson University and Chevron to study the efficacy of 

constructing wetlands to provide a low-cost, effective technology for the 

treatment and potential reuse of produced water. In addition, NETL has 

partnered with other DOE laboratories to conduct research on 

management of produced water. For example, from 2001 through 2004, 

46Ground Water Protection Council, State Oil and Natural Gas Regulations Designed to 

Protect Water Resources, a report funded by the Department of Energy and prepared for 

the National Energy Technology Laboratory, May 2009.

Federal Research Has 

Examined Options for 

Managing Produced Water 

and Associated Regulatory 

Issues
 

Page 32 GAO-12-156 Energy-Water Nexus 

NETL collaborated with Idaho National Laboratory and others to analyze 

coalbed methane production on an Indian reservation and to evaluate 

options for managing the associated produced water in an effort to 

minimize the environmental impacts of the water.

Other DOE national laboratories also have undertaken studies related to 

the management and regulation of produced water. For example, 

Argonne National Laboratory published a study in 2002 that described 

regulatory issues affecting the management of produced water from 

coalbed methane production.47 This was followed by a 2004 study that 

provided information on how produced water is managed and regulated, 

and the cost of various management practices.48 More recently, Argonne 

National Laboratory published a series of studies describing produced 

water management practices in different energy-producing regions, 

including the Marcellus formation in the Appalachians and the Fayetteville 

Shale in Arkansas. In addition, Sandia National Laboratories partnered 

with a producer to study options for managing produced water from 

coalbed methane, and published its analysis in 2008.49

Other federal agencies have also contributed to research on the 

management and regulation of produced water. Specifically, the Bureau 

of Reclamation partially funded a publication containing the proceedings 

from an April 2006 workshop on produced water,

Also, Oak Ridge 

National Laboratory has developed new approaches for produced water 

sampling, analysis, and remediation, and Los Alamos National Laboratory 

is currently conducting research to provide information about how 

produced water can be used to cultivate algae for biofuel production.

50

 

47John A. Veil, Argonne National Laboratory, Regulatory Issues Affecting Management of 

Produced Water from Coal Bed Methane Wells (February 2002).

and the agency 

presented information about the beneficial use of produced water at the 

48John A. Veil et al., Argonne National Laboratory, A White Paper Describing Produced 

Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane. 

49Malynda Cappelle, Randy Everett, William Holub, Richard Kottenstette, and Allan 

Sattler, Sandia National Laboratories, Coal Bed Natural Gas Produced Water Preliminary 

Pilot Plant Operation and Results (August 2008).

50Colorado Waters Resources Research Institute, Colorado State University, Produced 

Water Workshop (April 4-5, 2006).
 

Page 33 GAO-12-156 Energy-Water Nexus 

2007 International Petroleum Environmental Conference.51 In addition, in 

2006, USGS issued a bibliography of studies from across oil- and gasproducing areas that it had compiled from the last 80 years. These 

studies describe the effects of produced water on soils, water quality, and 

ecosystems.52

Federal research efforts, primarily conducted by DOE’s national 

laboratories, have also focused on new technologies and treatment 

methods for produced water. Sandia National Laboratories, for example, 

has partnered with a producer to conduct pilot testing of a new treatment 

system to lower the salt content of produced water from coalbed methane 

sources.53

 

51Steve Dundorf and Katie Benko, Geographical Assessment of Potential for Beneficial 

Use of Produced Water (presented at the International Petroleum Environmental 

Conference, Houston, 2007). 

NETL has partnered with Los Alamos National Laboratory, the 

New Mexico Institute of Mining and Technology, and the University of 

Texas on a long-term project to develop and test a prototype for a new 

treatment system that uses an innovative filtration method to remove 

problem contaminants and that would facilitate on-site treatment of 

produced water. From March 2003 through the end of 2005, NETL also 

partnered with Oak Ridge National Laboratory and industry to develop 

and test novel liquid solvents to remove organic substances from 

produced water. In addition, NETL is currently sponsoring a project to 

develop high-temperature nanofiltration technology to remove 

contaminants from produced water. According to the agency, the goal of 

this project is to minimize environmental impacts from coalbed methane 

and shale gas operations and allow cost-effective reuse of produced 

water that will reduce freshwater consumption and disposal costs. More 

recently, NETL sponsored research that led to the development of a new 

treatment system that, according to the agency, successfully treated 

flowback water from a hydraulic fracturing site in Pennsylvania. According 

to NETL, the treatment system significantly reduced the producer’s 

disposal costs.

52James K. Otton, Department of the Interior, U.S. Geological Survey, Environmental 

Aspects of Produced-water Salt Releases in Onshore and Coastal Petroleum-producing 

Areas of the Conterminous U.S. – A Bibliography, Open-File Report 2006-1154.

53Malynda Cappelle et al., Sandia National Laboratories, Coal Bed Natural Gas Produced 

Water Preliminary Pilot Plant Operation and Results. 

Federal Research Has 

Explored New Ways and 

Existing Alternatives for 

Treating Produced Water
 

Page 34 GAO-12-156 Energy-Water Nexus 

Other federal research efforts have been designed to improve existing 

techniques to treat produced water. For example, NETL partnered with 

Texas A&M, Argonne National Laboratory, and industry to develop 

improved reverse osmosis membrane filtration technology for the removal 

of salt from produced water. The desalination technology developed 

through this project led to the construction of a large-scale mobile unit 

and the development of a commercial oilfield treatment system at a site in 

Texas, according to NETL officials. Similarly, NETL has partnered with 

industry to develop a process that, when combined with existing reverse 

osmosis treatment, will facilitate the reuse of produced water by lowering 

energy requirements needed to treat produced water and by reducing 

membrane fouling.

We provided a draft of this report to the Department of Energy, the 

Department of the Interior, and the Environmental Protection Agency for 

review and comment. None of these agencies provided written 

comments to include in our report; however, the Environmental Protection 

Agency and the Department of the Interior provided technical comments, 

which we incorporated as appropriate.

Agency Comments
 

Page 35 GAO-12-156 Energy-Water Nexus 

As agreed with your office, unless you publicly announce the contents of 

this report earlier, we plan no further distribution until 30 days from the 

report date. At that time, we will send copies of this report to the 

appropriate congressional committees, the Secretary of Energy, the 

Secretary of the Interior, the EPA Administrator, and other interested 

parties. In addition, the report will be available at no charge on the GAO 

website at http://www.gao.gov. 

If you or your staff members have any questions about this report, please 

contact us at (202) 512-3841 or mittala@gao.gov or ruscof@gao.gov. 

Contact points for our Offices of Congressional Relations and Public 

Affairs may be found on the last page of this report. GAO staff who made 

major contributions to this report are listed in appendix III. 

Sincerely yours,

Anu K. Mittal

Director, Natural Resources and Environment

Frank Rusco

Director, Natural Resources and Environment
Appendix I: Scope and Methodology

Page 36 GAO-12-156 Energy-Water Nexus 

Our objectives for this review were to describe (1) what is known about 

the volume and quality of produced water from oil and gas production; (2) 

what practices are generally used to manage and treat produced water, 

and what factors are considered in the selection of each; (3) how the 

management of produced water is regulated at the federal level and in 

selected states; and (4) what federal research and development efforts 

have been undertaken during the last 10 years related to produced water.

To address each of these objectives, we conducted a literature review of 

studies and other documents on produced water quality and volume, 

management, and regulation issued by federal agencies and laboratories, 

state agencies, the oil and gas industry, and academic institutions. These 

documents included peer-reviewed scientific and industry periodicals, 

government-sponsored research, and reports from nongovernmental 

research organizations. We identified this literature through a systematic 

search of databases such as ProQuest, EconLit, and BioDigest, and used 

an iterative process to identify the most relevant studies for our review. 

We believe we have included the key studies and have qualified our 

findings, where appropriate. However, we may not have identified all of 

the studies with findings relevant to our objectives. In addition, we 

reviewed studies that fit the following criteria for selection: (1) the 

research was of sufficient breadth and depth to provide observations or 

conclusions directly related to our objectives; (2) the research was 

targeted specifically toward the volume and quality of produced water, 

available management practices and treatment methods, regulation of 

produced water broadly and in selected states, and undertaken by the 

federal government; and (3) the research was typically published in the 

last 10 years. We examined key assumptions, methods, and relevant 

findings of major scientific articles primarily related to water volumes and 

quality, and treatment methods. Where applicable, we assessed the 

reliability of the data we obtained and found them to be sufficiently 

reliable for our purposes.

In addition, we interviewed federal and state regulatory officials; federal 

scientists from the Environmental Protection Agency’s (EPA) Office of 

Research and Development and the Department of Energy’s (DOE) 

Argonne National Laboratory, Los Alamos National Laboratory, National 

Energy Technology Laboratory, Oak Ridge National Laboratory, and 

Sandia National Laboratories; officials from oil and gas exploration and 

production companies; officials from water treatment facilities; and other 

experts with experience related to produced water. The federal and state 

regulatory officials included those with responsibility over oil and gas 

regulation, as well as clean water and drinking water regulation. We 

Appendix I: Scope and Methodology
Appendix I: Scope and Methodology

Page 37 GAO-12-156 Energy-Water Nexus 

focused our review of management techniques and produced water 

regulation on nine states—California, Colorado, Kansas, Louisiana, New 

Mexico, Oklahoma, Pennsylvania, Texas, and Wyoming. We selected 

eight of these states because the volume of produced water generated 

within their borders accounts for nearly 90 percent of the produced water 

generated in the United States as of 2007, the most recent year for which 

there were available data. In addition, we selected Pennsylvania because 

of the recent growth in shale gas development in the Marcellus shale 

formation and the expected potential for large-scale produced water 

management approaches in this area. While oil shale production has 

expanded and continues to expand in Texas, North Dakota, and other 

states, we did not look specifically at produced water from oil shale as 

part of this review. Furthermore, GAO will be conducting future work on 

the development of shale gas resources and the use of hydraulic 

fracturing for oil and gas development and will address these topics more 

fully in subsequent reports.

We supplemented our literature review and stakeholder discussions with 

site visits to selected locations in Pennsylvania, Texas, and Wyoming, 

where we met with oil and gas producers and officials from produced 

water treatment facilities and discussed issues related to produced water 

management and treatment and the factors that influence these 

decisions. We selected these states because of the current and potential 

volumes of produced water generated, the range of hydrocarbons 

produced, and the different management and treatment practices 

employed. We also visited hydraulic fracturing drilling operations, 

underground injection control sites, and a number of different treatment 

facilities employing a variety of technologies. To determine what federal 

research and development efforts have been undertaken during the last 

10 years related to produced water, we analyzed information supplied by 

and conducted interviews with federal officials from DOE and select 

national laboratories, EPA, and the Department of the Interior’s U.S. 

Geological Survey, Bureau of Land Management, and Bureau of 

Reclamation.

We conducted this performance audit from October 2010 to January 

2012, in accordance with generally accepted government auditing 

standards. Those standards require that we plan and perform the audit to 

obtain sufficient, appropriate evidence to provide a reasonable basis for 

our findings and conclusions based on our audit objectives. We believe 

that the evidence obtained provides a reasonable basis for our findings 

and conclusions based on our audit objectives.
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 38 GAO-12-156 Energy-Water Nexus 

The following is a list of federally sponsored research efforts undertaken 

in the last 10 years that we identified in consultation with officials from the 

Department of Energy and select national laboratories, the Department of 

the Interior, the Environmental Protection Agency, and the National 

Research Council. These research efforts include those related to the 

quantity, quality, management, treatment, and use of produced water. 

The following studies were published by or prepared for Argonne National 

Laboratory.

Analysis of Data from a Downhole Oil/Water Separator Field Trial in East 

Texas. February 2001.

Clark, C.E and J.A. Veil. Produced Water Volumes and Management 

Practices in the United States. September 2009.

Harto, Christopher. Shale Gas – The Energy Water Nexus. April 2011.

Argonne National Laboratory. An Introduction to Slurry Injection 

Technology for Disposal of Drilling Wastes. September 2003.

Puder, Markus G., Bill Bryson, and John A. Veil. Compendium of 

Regulatory Requirements Governing Underground Injection of Drilling 

Wastes. February 2003.

Puder, M.G. and J. A. Veil. Offsite Commercial Disposal of Oil and Gas 

Exploration and Production Waste: Availability, Options, and Costs.

August 2006.

Veil, John A. and John J. Quinn. Downhole Separation Technology 

Performance: Relationship to Geologic Conditions. November 2004.

Veil, John A. and Maurice B. Dusseault. Evaluation of Slurry Injection 

Technology for Management of Drilling Wastes. May 2003.

Veil, J.A. and M.G. Puder. Potential Ground Water and Surface Water 

Impacts from Oil Shale and Tar Sands Energy-Production Operations.

October 2006.

Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years

Department of Energy

Argonne National 

Laboratory
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 39 GAO-12-156 Energy-Water Nexus 

Veil, John A. Regulatory Issues Affecting Management of Produced 

Water from Coal Bed Methane Wells. February 2002.

Veil, J., J. Gasper, M. Puder, and P. Leath. Summary of DOE/PERF 

Water Program Review. January 2006.

Veil, John A. Thermal Distillation Technology for Management of 

Produced Water and Frac Flowback Water. Water Technology Brief 

#2008-1. May 13, 2008.

Veil, J.A. and J.J. Quinn. Water Issues Associated with Heavy Oil 

Production. November 2008.

Veil, John A. “Water Management Practices Used by Fayetteville Shale 

Gas Producers.” Oil & Natural Gas Technology (June 2011).

Veil, John A. “Water Management Technologies Used by Marcellus Shale 

Gas Producers.” Oil & Natural Gas Technology (July 2010).

Veil, John A., Markus G. Puder, Deborah Elcock, and Robert J. Redweik, 

Jr. A White Paper Describing Produced Water from Production of Crude 

Oil, Natural Gas, and Coal Bed Methane. January 2004.

The following studies were published by or prepared for Los Alamos 

National Laboratory.

Altare, Craig R., Robert S. Bowman, Lynn E. Katz, Kerry A. Kinney, and 

Enid J. Sullivan. “Regeneration and Long-term Stability of Surfactant 

Modified Zeolite for Removal of Volatile Organic Compounds from 

Produced Water.” Microporous and Mesosporous Materials, 105 (2007): 

305-316. 

Kwon, Soondong, Enid J. Sullivan, Lynn E. Katz, Robert S. Bowman, and 

Kerry A. Kinney. “Laboratory and Field Evaluation of a Pretreatment 

System for Removing Organics from Produced Water.” Water 

Environment Research, vol. 83 (2011).

Ranck, J. Michael, Robert S. Bowman, Jeffrey L. Weeber, Lynn E. Katz, 

and Enid J. Sullivan. “BTEX Removal from Produced Water Using 

Surfactant-Modified Zeolite.” Journal of Environmental Engineering 

(March 2005).

Los Alamos National 

Laboratory
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 40 GAO-12-156 Energy-Water Nexus 

Sullivan, E.J., C.A. Dean, T.M. Yoshida, B. Cordova, M. Rearick, P. Laur, 

A. Viszolay, L. Brown, and J. Brown. Chemical Quality Impacts of Oil and 

Gas Produced Water as a Growth Medium for Nannochloropsis Grown at 

Pilot Scale for Biofuel Production. LA-UR-11-11017.

The following studies were published by or prepared for the National 

Energy Technology Laboratory.

Billingsley, R.L. Identifying and Remediating High Water Production 

Problems in Basin-Centered Formations. December 2005.

Brown, Terry, Carol D. Frost, Thomas D. Hayes, Leo A. Heath, Drew W. 

Johnson, David A. Lopez, Demian Saffer, Michael A. Urynowicz, John 

Wheaton, and Mark D. Zoback. Final Report: Produced Water 

Management and Beneficial Use. January 2009.

Burnett, David B. and Mustafa Siddiqui. Recovery of Fresh Water 

Resources from Desalination of Brine Produced During Oil and Gas 

Production Operations. September 2003–December 2006.

COAL BED METHANE PRIMER—New Source of Natural Gas – 

Environmental Implications: Background and Development in the Rocky 

Mountain West. February 2004.

DOE Oil and Natural Gas Water Resources Program. December 2009.

Feasibility Study of Expanded Coal Bed Natural Gas Produced Water 

Management Alternatives in the Wyoming Portion of the Powder River 

Basin Phase One. January 2006.

A Guide to Practical Management of Produced Water from Onshore Oil 

and Gas Operations in the United States. October 2006.

Handbook on Best Management Practices and Mitigation Strategies for 

Coal Bed Methane in the Montana Portion of the Powder River Basin.

April 2002.

Handbook on Coal Bed Methane Produced Water: Management and 

Beneficial Use Alternatives. July 2003.

Modern Shale Gas Development in the United States: A Primer. April 

2009.

National Energy 

Technology Laboratory
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 41 GAO-12-156 Energy-Water Nexus 

Policy Analysis of Produced Water Issues Associated With In-Situ 

Thermal Technologies. January 2011.

Remson, Don J. Produced Water in the Rocky Mountain Region—

Quantity and Quality. November 2005.

Review of the U.S. Department of Energy’s Environmental Program. July 

1, 2010.

Siting, Design, Construction and Reclamation Guidebook for Coalbed 

Natural Gas Impoundments. May 2006.

Ground Water Protection Council, State Oil and Natural Gas Regulations 

Designed to Protect Water Resources. May 2009.

Use of Produced Water in Recirculated Cooling Systems at Power 

Generating Facilities. September 2006.

Wang, Xixi, Bethany A. Kurz, and Marc D. Kurz. Subtask 1.18 – A 

Decision Tool for Watershed-Based Effluent Trading. February 2007.

Welch, Robert A. and Dwight F. Rychel. Produced Water from Oil and 

Gas Operations in the Onshore Lower 48 States. December 2004.

The following are past and current projects funded by the National Energy 

Technology Laboratory, but for which no studies have been published.

Advanced Membrane Filtration Technology for Cost-Effective Recovery of 

Fresh Water from Oil and Gas Produced Brine. Project start: 2003. 

Project end: 2006.

Anti-Fouling Reverse Osmosis Desalination System. Project start: 2009. 

Project end: 2010.

Barnett and Appalachian Shale Water Management and Reuse 

Technologies. Project start: 2009. Estimated project end: 2011.

Cleaning Agents for Produced Water Membrane Filters. Project start: 

2004. Project end: 2006.

Coal Bed Methane Best Management Practices Workshop. Project start: 

2003. Project end: 2004.

National Energy 

Technology Laboratory
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 42 GAO-12-156 Energy-Water Nexus 

Coalbed Methane Research. Project start: 2006. Project end: 2008.

Coalbed Natural Gas Produced-Water Treatment Using Gas Hydrate 

Formation at the Wellhead. Project start: 2005. Project end: 2009.

Coalbed Natural Gas Produced-Water Treatment Using Gas Hydrates. 

Project start: 2006. Project end: 2008.

Coalbed Natural Gas Research. Project start: 2003. Project end: 2006.

Comprehensive Lifecycle Planning and Management System for 

Addressing Water Issues Associated with Shale Gas Development in 

New York, Pennsylvania and West Virginia. Project start: 2009. Estimated 

project end: 2012.

Cost Effective Recovery of Low-TDS Frac Flowback Water for Re-use.

Project start: 2009. Project end: 2011.

Cost-Effective Treatment of Produced Water Using Co-Produced Energy 

Sources for Small Producers. Project start: 2008. Original project end: 

2010 (extended).

Effects of Irrigating with Treated Oil and Gas Product Water on Crop 

Biomass and Soil Permeability. Project start: 2008. Project end: 2010.

Energy in the Environment-Initiatives 2004-09. Project start: 2004. Project

end: 2009.

Evaluations of Radionuclides of Uranium, Thorium, and Radium 

Associated with Produced Fluids, Precipitates, and Sludges from Oil, 

Gas, and Oilfield Brine Injection Wells in Mississippi. Project start: 2002. 

Project end: 2003.

Field Validation of Toxicity Tests to Evaluate the Potential for Beneficial 

Use of Produced Water. Project start: 2004. Project end: 2008.

GIS and Web-Based Water Resource Geospatial Infrastructure for Oil 

Shale Development. Project start: 2008. Estimated project end: 2012.

Handbooks for Preparing, Evaluation Development, Environmental Plans 

and Background Development Pertinent to Coal Bed Methane 

Production. Project start: 2002. Project end: 2005.
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 43 GAO-12-156 Energy-Water Nexus 

Hypoxia, Program Review, and Total Petroleum Hydrocarbon Workshop.

Project start: 2006. Project end: 2008.

Identification, Verification, & Compilation of Produced-Water Best 

Management Practices for Conventional Oil & Gas Production 

Operations. Project start: 2004. Project end: 2007.

Improving Science-Based Methods for Assessing Risks Attributable to 

Petroleum Residues in Soil Transferred to Vegetation. Project start: 2002. 

Project end: 2005.

Innovative Water Management Technology to Reduce Environmental 

Impacts of Produced Water. Project start: 2008. Estimated project end: 

2012.

An Integrative Framework for the Treatment and Management of 

Produced Water. Project start: 2008. Estimated project end: 2011.

An Integrated Water Treatment Technology Solution for Sustainable 

Water Resource Management in the Marcellus Shale. Project start: 2009. 

Estimated project end: 2011.

Integration of Water Resource Models with Fayetteville Shale Decision 

and Support Systems. Project start: 2009. Estimated project end: 2012.

Life Cycle Assessment, Produced Water, and Waste Management 

Analyses. Project start: 2004. Project end: 2007.

Long-term field Deployment of a Surfactant Modified Zeolite Vapor Phase 

Bioreactor System. Project start: 2004. Project end: 2007.

Long Term Field Development of a Surfactant-Modified Zeolite/VaporPhase Bioreactor System for Treatment of Produced Waters for Power 

Generation. Project start: 2004. Project end: 2007.

Management of Produced Water. Project start: 2003. Project end: 2006.

Managing Coalbed Natural Gas Produced Water for Beneficial Uses, 

Initially Using the San Juan and Raton Basins as a Model. Project start: 

2003. Project end: 2008.

Membrane Technology for Produced Water at Lea County, NM. Project 

start: 2008. Estimated project end: 2011.
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 44 GAO-12-156 Energy-Water Nexus 

Microbial Ecology of Shale Gas Production Waters. Project start: 2011. 

Estimated project end: not established.

Modified Reverse Osmosis System for Treatment of Produced Water.

Project start: 2000. Project end: 2004.

Modeling of Water-Soluble Organic Content in Produced Water. Project 

start: 2002. Project end: 2005.

NMWAIDS: A Produced-Water Quality and Infrastruture GIS Database for 

New Mexico Oil Production. Project start: 2002. Project end: 2005.

Northeast National Petroleum Reserve-Alaska Reconnaissance-Level 

Airborne Contaminants Study. Project start: 2001. Project end: 2006.

Northern Cheyenne Indian Reservation (NCIR) Coalbed Natural Gas 

Resource Assessment and Analysis of Produced-Water Disposal 

Options. Project start: 2001. Project end: 2004.

Novel Cleanup Agents for Membrane Filters Used to Treat Oilfield 

Produced Water for Beneficial Purposes. Project start: 2004. Project end: 

2007.

Novel Fouling—Reducing Coatings for Ultrafiltration, Nanofiltration and 

Reverse Osmosis Membranes. Project start: 2004. Project end: 2008.

Pilot Testing: Pretreatment Options to Allow Re-Use of Frac Flowback 

and Produced Brine for Gas Shale Resource Development. Project start: 

2009. Estimated project end: 2011.

Pretreatment and Water Management for Frac Water Reuse and Salt 

Production. Project start: 2009. Estimated project end: 2011.

Produced Water Management and Beneficial Use. Project start: 2005. 

Project end: 2007.

Produced Water Management and Beneficial Use/15549 Colorado School 

of Mines. Project start: 2005. Project end: 2007.

Produced Water Management and Beneficial Use/15549 Colorado School 

of Mines. (Different portion of the preceding project with distinct project 

identification.) Project start: 2005. Project end: 2007.
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 45 GAO-12-156 Energy-Water Nexus 

Produced Water Treatment and Decision Tool. Project start: 2008. 

Estimated project end: 2012.

Provide Support to Produced Water: Osage-Skiatook Petroleum 

Environmental Research Project. Project start: 2001. Project end: 2006.

Range Resources Baseline Monitoring Site for Marcellus Shale Gas. 

Project start: 2011. Estimated project end: not established.

Recovery of More Oil-in-Place at lower Production Costs While Creating a 

Beneficial Water Resource. Project start: 2002 Project end: 2006.

Research and Development Concerning Coalbed Natural Gas—

Congressional Mandate. Project start: 2006. Project end: 2008.

Research to Enhance Oil and Gas Development and Environmental 

Protection on Federal Lands: Joint Montana Regional Coalbed Natural 

Gas Ground-Water Monitoring Program. Project start: 2005. Project end: 

2008.

Risk Based Data Management System (RBDMS) and Cost Effective 

Regulatory Approaches (CERA) Related to Hydraulic Fracturing and 

Geologic Sequestration of CO-2. Project start: 2009. Estimated project 

end: 2012.

Subsurface Drip Irrigation. Project start: 2007. Estimated project end: 

2014.

Sustainable Management of Flowback Water during Hydraulic Fracturing 

of Marcellus Shale for Natural Gas Production. Project start: 2009. 

Estimated project end: 2012.

Treating Coalbed Natural Gas Produced Water for Beneficial Use by MFI 

Zeolite Membranes. Project start: 2004. Project end: 2008.

Treatment and Beneficial Reuse of Produced Waters Using a Novel 

Pervaporation-Based Irrigation Technology. (NETL in-house project not 

yet awarded.)

Treatment of Produced Water by FARADAVIC Electrodialysis and 

Reverse Osmosis. Project start: 2009. Project end: 2010.
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 46 GAO-12-156 Energy-Water Nexus 

Treatment of Produced Waters using a Surfactant Modified Zeolite/VaporPhase Bioreactor. Project start: 2002. Project end: 2006.

Treatment of Produced Waters Using a Surfactant-Modified 

Zeolite/Vapor-Phase Bioreactor System. Project start: 2003. Project end: 

2006.

Treatment of Produced Waters Using a Surfactant-Modified 

Zeolite/Vapor-Phase Bioreactor System. (Next phase.) Project start: 

2004. Project end: 2006.

Unconventional High Temperature Nanofiltration for Produced Water 

Treatment. (Phase I.) Project start: 2009. Project end: 2010.

Unconventional High Temperature Nanofiltration for Produced Water 

Treatment. (Next phase.) Project start: 2010. Project end: 2012.

Use of Ionic Liquids in Produced-Water Clean-up. Project start: 2003. 

Project end: 2005.

Use of Stable Isotopes to Discern Marcellus Produced Water When 

Commingled with Surface Water or Shallow Groundwater. Project start: 

2011. Estimated project end: not established.

Use of Wetland Plant Species and Communities for Phytoremediation of 

Coalbed Natural Gas Produced Water and Waters of Quality Similar to 

that Associated with Coalbed Natutral Gas Deposits of the Powder River 

Basin. Project start: 2001. Project end: 2008.

Using Helicopter Electromagnetic Surveys to Determine the Hydrologic 

Fate of Coalbed Methane Produced Water. Project start: 2002. Project 

end: 2004.

Water Management Strategies for Improved Coalbed Methane Production 

in the Black Warrior Basin. Project start: 2009. Estimated project end: 

2012.

Water-Related Issues Affecting Conventional Oil and Gas Recovery and 

Potential Oil Shale Development in the Uinta Basin, Utah. Project start: 

2008. Estimated project end: 2011.

Water & Waste Regulatory Analysis. Project start: 2006. Project end: 

2008.
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 47 GAO-12-156 Energy-Water Nexus 

Zero Discharge Water Management for Horizontal Shale Gas Well 

Development. Project start: 2009. Estimated project end: 2011.

The following studies were published by or prepared for Oak Ridge 

National Laboratory.

Bostick, Debra T., H. Luo and B. Hindmarsh. Characterization of Soluble 

Organics in Produced Water. January 2002.

Klasson, K. Thomas, Costas Tsouris, Sandie A. Jones, Michele D. 

Dinsmore, David W. Depaoli, Angela B. Walker, Sotira Yiacoumi, Viriya 

Vithayaveroj, Robert M. Counce, and Sharon M. Robinson. Ozone 

Treatment of Soluble Organics in Produced Water. Petroleum 

Environmental Research Forum Project 98-04. January 2002.

McFarlane, J. “Application of Chemometrics to Modeling Produced Water 

Contamination.” Separation Science and Technology, 40 (2005): 593-

609.

McFarlane, Joanna. Modeling of Water-Soluble Organic Content in 

Produced Water. May 2006.

McFarlane, Joanna. New Approaches to Produced Water Sampling, 

Analysis and Remediation at ORNL. 2004.

McFarlane, Joanna. Measurement, Characterization and Prediction of 

Organic Solubility in Produced Water. Presentation at Gas Technology 

Institute Natural Gas Technologies II Conference and Exhibition, 

February 8-11, 2004.

McFarlane, Joanna. Offshore Versus Onshore Produced Water 

Characterization and Models. Presentation at Gas Technology Institute 

Natural Gas Technologies II Conference and Exhibition, February 8-11, 

2004.

McFarlane, Joanna, Debra T. Bostick, and Huimin Luo. Characterization 

and Modeling of Produced Water. 2002.

Ren, R.X. Room Temperature Ionic Liquids for Separating Organics from 

Produced Water. Separation Science and Technology, 40 (2005): 1245-

1265.

Oak Ridge National 

Laboratory
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 48 GAO-12-156 Energy-Water Nexus 

The following study was published by or prepared for Sandia National 

Laboratories.

Cappelle, Malynda, Randy Everett, William Holub, Richard Kottenstette, 

and Allan Sattler. Coal Bed Natural Gas Produced Water Preliminary Pilot 

Plant Operation and Results. August 2008.

The following studies were published by or prepared for the Bureau of 

Reclamation.

Benko, Katie L. “Ceramic Membranes for Produced Water Treatment.” 

World Oil (April 2009): 1-3 

Benko, Katie L and Jörg E. Drewes. “Produced Water in the Western 

United States: Geographical Distribution, Occurrence and Composition.” 

Environmental Engineering Science, vol. 25, no. 2 (2008): 239-246.

Benko, Katie and Jörg Drewes, Pei Xu, and Tzahi Cath. “Use of Ceramic 

Membranes for Produced Water Treatment.” World Oil, Gulf Publishing 

Company, vol. 230, no. 4 (April 2009). 

Drewes, Jörg E, Pei Xu, Dean Heil, and Gary Wang. Multibeneficial Use 

of Produced Water Through High-Pressure Membrane Treatment and 

Capacitive Deionization Technology. Desalination and Water Purification 

Research and Development Program Report No. 133. February 2009.

Dundorf, Steve and Katie Benko. “Geographical Assessment of Potential 

for Beneficial Use of Produced Water.” Presentation at International 

Petroleum Environmental Conference. November 2007.

Colorado Waters Resources Research Institute, Colorado State 

University, Produced Water Workshop, (April 4-5, 2006). The publication 

of workshop results was partially funded by the Bureau of Reclamation.

Sandia National 

Laboratories

Department of the 

Interior

Bureau of Reclamation
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 49 GAO-12-156 Energy-Water Nexus 

The following studies were published by or prepared for the U.S. 

Geological Survey.

Engle, Mark A., Carleton R. Bern, Richard W. Healy, James I. Sams, 

John W. Zupancic, and Karl T. Schroeder. “Tracking solutes and water 

from subsurface drip irrigation application of coalbed-methane produced 

waters, Powder River Basin, Wyoming.” Environmental Geosciences, v. 

18, no. 3 (September 2011): 1-19.

Farag, Aida M., David D. Harper, Anna Senecal, and Wayne A. Hubert. 

“Potential Effects of Coalbed Natural Gas Development on Fish and 

Aquatic Resources.” Chapter 11 in Coalbed Natural Gas: Energy and 

Environment. Nova Science Publishers, Inc., 2010.

Healy, Richard W., Cynthia A. Rice, Timothy T. Bartos, and Michael P. 

McKinley. “Infiltration from an impoundment for coal-bed natural gas, 

Powder River Basin, Wyoming: Evolution of water and sediment 

chemistry.” Water Resources Research, Vol. 44, W06424, June 2008.

Healy, Richard W., Timothy T. Bartos, Cynthia A. Rice, Michael P. 

McKinley, and Bruce D. Smith. “Groundwater chemistry near an 

impoundment for produced water, Powder River Basin, Wyoming USA.” 

Journal of Hydrology, 403 (2011): 37-48.

Kharaka, Y.K., and J.K. Otton, 2003, Environmental Impacts of Petroleum 

Production: Initial Results from the Osage-Skiatook Petroleum 

Environmental Research Sites, Osage County, Oklahoma: USGS WaterResources Investigations Report 03-4260.

Orem, William H., Calin A. Tatu, Harry E. Lerch, Cynthia A. Rice, Timothy 

T. Bartos, Anne L. Bates, Susan Tewalt, and Margo D. Corum. “Organic 

compounds in produced waters from coalbed natural gas wells in the 

Powder River Basin, Wyoming, USA.” Applied Geochemistry 22 (May 

2007): 2240-2256.

Otton, James K. Environmental Aspects of Produced-water Salt Releases 

in Onshore and Coastal Petroleum-producing Areas of the Conterminous 

U.S. – A Bibliography. Open-File Report 2006-1154.

Peterman, Zell E., Joanna N. Thamke, Kiyoto Futa, and Thomas A. 

Oliver. Strontium Isotope Detection of Brine Contamination in the East 

Poplar Oil Field, Montana. Open-File Report 2010-1326.

U.S. Geological Survey
Appendix II: List of Ongoing and Completed 

Federal Produced Water Research Efforts 

Undertaken during the Last 10 Years 

Page 50 GAO-12-156 Energy-Water Nexus 

Rice, Cynthia A., Timothy T. Bartos, and Margaret S. Ellis. Chemical and 

Isotopic Composition of Water in the Fort Union and Wasatch Formations 

of the Powder River Basin, Wyoming and Montana: Implications for 

Coalbed Methane Development. Coalbed Methane of North America – II, 

2002: 53-70. 

Rowan, E.L., M.A. Engle, C.S. Kirby, and T.F. Kraemer. Radium Content 

of Oil- and Gas-Field Produced Waters in the Northern Appalachian 

Basin: Summary and Discussion of Data. Scientific Investigations Report 

2011-5135, 2011.

Smith, Bruce D., Joanna N. Thamke, Michael J. Cain, Christa Tyrrell, and 

Patrica L. Hill. Helicopter Electromagnetic and Magnetic Survey Maps 

and Data, East Poplar Oil Field Area, Fort Peck Indian Reservation, 

Northeastern Montana, August 2004. Open-File Report 2006-1216, 

Version 1.0.

Soeder, Daniel J. and William H. Kappel. Water Resources and Natural 

Gas Production from the Marcellus Shale. USGS Fact Sheet 2009-3032. 

May 2009.

Environmental Protection Agency, Draft Hydraulic Fracturing Study Plan

(April 28, 2011).

Committee on Management and Effects of Coalbed Methane 

Development and Produced Water in the Western United States, 

Committee on Earth Resources, Board on Earth Sciences and 

Resources, Water Science and Technology Board, Division on Earth and 

Life Studies, National Research Council of the National Academies. 

Management and Effects of Coalbed Methane Produced Water in the 

Western United States. 2010.

Environmental 

Protection Agency

National Research 

Council
Appendix III: GAO Contacts and Staff 

Acknowledgments

Page 51 GAO-12-156 Energy-Water Nexus 

Anu Mittal, (202) 512-3841 or mittala@gao.gov

Frank Rusco, (202) 512-3841 or ruscof@gao.gov

In addition to the contacts named above, Elizabeth Erdmann, Assistant 

Director; Colleen Candrl; Nancy Crothers; Randy Jones; Annamarie 

Lopata; Alison O’Neill; Stuart Ryba; Rebecca Sandulli; Rebecca Shea; 

Lindsay Taylor; and Barbara Timmerman made significant contributions 

to this report.

Appendix III: GAO Contacts and Staff 

Acknowledgments 

GAO Contacts 

Staff 

Acknowledgments

(361237)
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