Energy-Water Nexus: Information on the Quantity, Quality, and Management of Water Produced during Oil and Gas Production
Published: 2012-01-09T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: 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.
section_title: What GAO Found
paragraphs: 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.
section_title: What GAO Recommends
paragraphs: 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.

section_title: Letter
paragraphs: 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. 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  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. 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.
Because of the inextricable link between energy production and water,  you asked us to undertake a series of studies reviewing the energy-water   This is the fifth and final study in this series and provides nexus. 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.
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  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  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.
subsections: section_title: Background
paragraphs: 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.
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. 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.
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. various gas hydrocarbons.
Viscosity is a measure of the resistance of a fluid to flow.
section_title: 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
paragraphs: 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.
subsections: section_title: Millions of Barrels of Produced Water Are Generated Daily, but the Volume Produced at a Given Well Is Dependent on Several Factors
paragraphs: 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. 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  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. By pumping out water, the resulting drop in  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. 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.
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.
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  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. 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.
section_title: Produced Water Is Generally of Poor Quality, with the Levels of Contaminants Varying Widely
paragraphs: 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 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.
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  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.
section_title: A Number of Practices Are Available to Manage and Treat Produced Water, with Cost Being the Primary Determining Factor
paragraphs: 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.
subsections: section_title: Produced Water Can Be Managed in a Number of Ways, although Underground Injection Is the Most Common Practice
paragraphs: 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,  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. 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.
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. About four-fifths of the wells— 124,837—are located in the nine states we reviewed (see table 1).
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.
Produced water that is not injected into underground injection wells is  disposed of or reused by producers in other ways, including the  following.
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. 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. 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. 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.
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. 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. 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.
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, 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.  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  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 off- site, 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. 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, low- cost 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  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.
section_title: Most Produced Water Is Minimally Treated, but More Advanced Treatment Methods Are Available
paragraphs: 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.
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. 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. 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 semi- permeable 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. 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  replaces them with others. 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.technologies to remove salt typically generates concentrated brine, which  must then be properly disposed of as well.
section_title: Cost Is the Primary Factor That Determines How Produced Water Is Managed and Treated
paragraphs: 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. 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.
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  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  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.
section_title: EPA and the States We Reviewed Regulate the Management of Produced Water through a Variety of Means
paragraphs: 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.
subsections: section_title: Underground Injection Is Regulated under the Safe Drinking Water Act
paragraphs: 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  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. 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.
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.
section_title: Discharge of Produced Water Is Regulated under the Clean Water Act
paragraphs: 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.
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 off- site 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  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.
section_title: Other Management Practices Are Regulated by State Authorities
paragraphs: 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.  Specifically, some states have regulations that apply to the temporary  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.
section_title: Federal Research Efforts Have Focused on Describing the Characteristics of and Uses for Produced Water, Management Options, and Treatment Methods
paragraphs: 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.
subsections: section_title: Federal Research Efforts Have Examined the Characteristics of Produced Water
paragraphs: 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. 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.USGS also maintains a database that provides the location, geologic  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. The study was designed to  assist producers and others in determining viability of this water for  beneficial reuse and for selecting appropriate treatment processes.
John 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). 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.
section_title: Federal Research Has Examined Options for Managing Produced Water and Associated Regulatory Issues
paragraphs: 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.  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.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,   NETL is also currently  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. 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. 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. 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.
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, and the agency presented information about the beneficial use of produced water at the  2007 International Petroleum Environmental Conference. In addition, in  2006, USGS issued a bibliography of studies from across oil- and gas- producing areas that it had compiled from the last 80 years. These  studies describe the effects of produced water on soils, water quality, and  ecosystems.
section_title: Federal Research Has Explored New Ways and Existing Alternatives for Treating Produced Water
paragraphs: 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. 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.
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.
section_title: Agency Comments
paragraphs: 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.
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.
section_title: Appendix I: Scope and Methodology
paragraphs: 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  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.
section_title: Appendix II: List of Ongoing and Completed Federal Produced Water Research Efforts Undertaken during the Last 10 Years
paragraphs: 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.
subsections: section_title: Department of Energy
subsections: section_title: Argonne National Laboratory
paragraphs: 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.
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.
section_title: Los Alamos National Laboratory
paragraphs: 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).
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.
section_title: National Energy Technology Laboratory
paragraphs: 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.
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.
section_title: National Energy Technology Laboratory
paragraphs: 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.
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.
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/Vapor- Phase 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.
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.
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.
Treatment of Produced Waters using a Surfactant Modified Zeolite/Vapor- Phase 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.
Zero Discharge Water Management for Horizontal Shale Gas Well  Development. Project start: 2009. Estimated project end: 2011.
section_title: Oak Ridge National Laboratory
paragraphs: 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.
section_title: Sandia National Laboratories
paragraphs: 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.
section_title: Department of the Interior
subsections: section_title: Bureau of Reclamation
paragraphs: 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.
section_title: U.S. Geological Survey
paragraphs: 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 Water- Resources 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.
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.
section_title: Environmental Protection Agency
paragraphs: Environmental Protection Agency, Draft Hydraulic Fracturing Study Plan  (April 28, 2011).
section_title: National Research Council
paragraphs: 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.
section_title: Appendix III: GAO Contacts and Staff Acknowledgments
subsections: section_title: GAO Contacts
section_title: Staff Acknowledgments
paragraphs: 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.