Energy-Water Nexus: A Better and Coordinated Understanding of Water Resources Could Help Mitigate the Impacts of Potential Oil Shale Development
Published: 2010-10-29T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: Oil shale deposits in Colorado, Utah, and Wyoming are estimated to contain up to 3 trillion barrels of oil--or an amount equal to the world's proven oil reserves. About 72 percent of this oil shale is located beneath federal lands, making the federal government a key player in its potential development. Extracting this oil is expected to require substantial amounts of water and could impact groundwater and surface water. GAO was asked to report on (1) what is known about the potential impacts of oil shale development on surface water and groundwater, (2) what is known about the amount of water that may be needed for commercial oil shale development, (3) the extent to which water will likely be available for commercial oil shale development and its source, and (4) federal research efforts to address impacts to water resources from commercial oil shale development. GAO examined environmental impacts and water needs studies and talked to Department of Energy (DOE), Department of the Interior (Interior), and industry officials.
section_title: What GAO Found
paragraphs: Oil shale development could have significant impacts on the quality and quantity of water resources, but the magnitude of these impacts is unknown because technologies are years from being commercially proven, the size of a future oil shale industry is uncertain, and knowledge of current water conditions and groundwater flow is limited. In the absence of effective mitigation measures, water resources could be impacted from ground disturbances caused by the construction of roads and production facilities; withdrawing water from streams and aquifers for oil shale operations, underground mining and extraction; and discharging waters produced from or used in operations. Estimates vary widely for the amount of water needed to commercially produce oil shale primarily because of the unproven nature of some technologies and because the various ways of generating power for operations use differing quantities of water. GAO's review of available studies indicated that the expected total water needs for the entire life cycle of oil shale production ranges from about 1 barrel (or 42 gallons) to 12 barrels of water per barrel of oil produced from in-situ (underground heating) operations, with an average of about 5 barrels, and from about 2 to 4 barrels of water per barrel of oil produced from mining operations with surface heating. Water is likely to be available for the initial development of an oil shale industry, but the size of an industry in Colorado or Utah may eventually be limited by water availability. Water limitations may arise from increases in water demand from municipal and industrial users, the potential of reduced water supplies from a warming climate, fulfilling obligations under interstate water compacts, and the need to provide additional water to protect threatened and endangered fishes. The federal government sponsors research on the impacts of oil shale on water resources through DOE and Interior. DOE manages 13 projects whose water-related costs total about $4.3 million, and Interior sponsored two water-related projects, totaling about $500,000. Despite this research, nearly all of the officials and experts that GAO contacted said that there are insufficient data to understand baseline conditions of water resources in the oil shale regions of Colorado and Utah and that additional research is needed to understand the movement of groundwater and its interaction with surface water. Federal agency officials also said they seldom coordinate water-related oil shale research among themselves or with state agencies that regulate water. Most officials noted that agencies could benefit from such coordination.
section_title: What GAO Recommends
paragraphs: GAO recommends that Interior establish comprehensive baseline conditions for water resources in oil shale regions of Colorado and Utah, model regional groundwater movement, and coordinate on water-related research with DOE and state agencies involved in water regulation. Interior generally concurred with GAO's recommendations.

section_title: Letter
paragraphs: Being able to tap the vast amounts of oil locked within U.S. oil shale could  go a long way toward satisfying the nation’s future oil demands. Oil shale  is a sedimentary rock containing solid organic material that converts into a  type of crude oil when heated. The Green River Formation—an  assemblage of over 1,000 feet of sedimentary rocks that lie beneath parts  of Colorado, Utah, and Wyoming—contains the world’s largest deposits of  oil shale. The U.S. Geological Survey (USGS) estimates that the Green  River Formation contains about 3 trillion barrels of oil, and about half of  this may be recoverable, depending on available technology and economic  conditions. This is an amount about equal to the entire world’s proven oil  reserves. The thickest and richest oil shale within the Green River  Formation exists in the Piceance Basin of northwest Colorado and the  Uintah Basin of northeast Utah.
The federal government is in a unique position to influence the  development of oil shale because 72 percent of the oil shale within the  Green River Formation is beneath federal lands managed by the  Department of the Interior’s (Interior) Bureau of Land Management  (BLM). The Department of Energy (DOE) has provided technological and  financial support for oil shale development, primarily through its research  and development efforts, but oil shale development has been hampered by  concerns over potential impacts on the environment, technological  challenges, and average oil prices that have been too low to consistently  justify investment. In particular, developing oil shale and providing power  for oil shale operations and other activities will require large amounts of  water—a resource that is already in scarce supply in the arid West where  an expanding population is placing additional demands on water. Some  analysts project that large scale oil shale development within Colorado  could require more water than is currently supplied to over 1 million  residents of the Denver metro area and that water diverted for oil shale  operations would restrict agricultural and urban development. The  potential demand for water is further complicated by the past decade of  drought in the West and projections of a warming climate in the future.  While there are also other concerns over the impacts from oil shale  development, such as impacts to air quality, wildlife, and nearby  communities, this report focuses on water impacts.
In response to your request, and building on our two recent reports  examining the relationship between other forms of energy production and  water use, we examined (1) what is known about the potential impacts of  oil shale development on surface water and groundwater, (2) what is  known about the amount of water that may be needed for the commercial  development of oil shale, (3) the extent to which water will likely be  available for commercial oil shale development and its source, and (4)  federal research efforts to address impacts on water resources from  commercial oil shale development. Our report focuses on oil shale  resources within the Green River Formation in the Piceance Basin of  northwest Colorado and in the Uintah Basin of northeast Utah because  these are the areas in the United States in which the industry is most  interested in pursuing oil shale development due to the great thickness  and richness of the deposits.
To determine what is known about the potential impacts to surface water  and groundwater from commercial oil shale development, we reviewed an  environmental impact statement on oil shale development prepared by  BLM and various studies from private and public groups. We discussed the  completeness and accuracy of these studies in interviews with federal  agency officials, state agency personnel involved in regulating water  quality and quantity, oil shale industry representatives, and representatives  of environmental groups. We also visited oil shale demonstration projects  in Colorado. To determine what is known about the amount of water that  may be needed for commercial oil shale development, we conducted a  comprehensive literature search for studies on water needs, contacted the  authors of these studies, and assessed the reasonableness of their  estimates. Our review of the literature identified several groups of  activities that comprise the life cycle of oil shale production. We then  tabulated the water needs identified in each study for each group of  activities and expressed the total water needs for the life cycle as a range  based on these numbers. To determine the extent to which water is likely  to be available for commercial oil shale development and its source, we  compared the total needs reflected in this estimated range to the amount  of surface water and groundwater that is physically and legally available in  the immediate area and to the future demands of municipalities and other  industries as projected by federal and state agencies. To review federal  research efforts to address the impacts of commercial oil shale  development on water resources, we interviewed officials at DOE, the  USGS, BLM, and organizations performing the research, including  universities and national laboratories, and collected and reviewed relevant  documents describing their research. We also discussed areas for future  water research as it relates to oil shale with 18 organizations—including  the USGS, BLM, the DOE National Energy Technology Laboratory, the  DOE Office of Naval Petroleum and Oil Shale Reserves, the U.S. Bureau of  Reclamation, three DOE national laboratories, four state regulatory  agencies in Colorado and Utah, three water experts, an industry  representative, and two universities performing research—to identify gaps  in current efforts.
We conducted this performance audit from September 2009 through  October 2010 in accordance with generally accepted government auditing  standards. These standards require that we plan and perform the audit to  obtain sufficient and appropriate evidence to provide a reasonable basis  for our findings and conclusions based on our audit objectives. We believe  that the evidence obtained provides such a reasonable basis for our  findings and conclusions based on our audit objectives.
subsections: section_title: Background
paragraphs: Interest in oil shale as a domestic energy source has waxed and waned  since the early 1900s. In 1912, President Taft established an Office of Naval  and Petroleum Oil Shale Reserves, and between 1916 and 1924, executive  orders set aside federal land in three separate naval oil shale reserves to  ensure an emergency domestic supply of oil. The Mineral Leasing Act of  1920 made petroleum and oil shale resources on federal lands available for  development under the terms of a mineral lease, but large domestic oil  discoveries soon after passage of the act dampened interest in oil shale.  Interest resumed at various points during times of generally increasing oil  prices. For example, the U.S. Bureau of Mines developed an oil shale  demonstration project beginning in 1949 in Colorado, where it attempted  to develop a process to extract the oil. The 1970s’ energy crises stimulated  interest once again, and DOE partnered with a number of energy  companies, spawning a host of demonstration projects. Private efforts to  develop oil shale stalled after 1982 when crude oil prices fell significantly,  and the federal government dropped financial support for ongoing  demonstration projects.
More recently, the Energy Policy Act of 2005 directed BLM to lease its  lands for oil shale research and development. In June 2005, BLM initiated a  leasing program for research, development, and demonstration (RD&D) of  oil shale recovery technologies. By early 2007, it granted six small RD&D  leases: five in the Piceance Basin of northwest Colorado and one in Uintah  Basin of northeast Utah. The location of oil shale resources in these two  basins is shown in figure 1. The leases are for a 10-year period, and if the  technologies are proven commercially viable, the lessees can significantly  expand the size of the leases for commercial production into adjacent  areas known as preference right lease areas. The Energy Policy Act of  2005 directed BLM to develop a programmatic environmental impact  statement (PEIS) for a commercial oil shale leasing program. During the  drafting of the PEIS, however, BLM realized that, without proven  commercial technologies, it could not adequately assess the environmental  impacts of oil shale development and dropped from consideration the  decision to offer additional specific parcels for lease. Instead, the PEIS  analyzed making lands available for potential leasing and allowing industry  to express interest in lands to be leased. Environmental groups then filed  lawsuits, challenging various aspects of the PEIS and the RD&D program.  Since then, BLM has initiated another round of oil shale RD&D leasing and  is currently reviewing applications but has not made any awards.
Stakeholders in the future development of oil shale are numerous and  include the federal government, state government agencies, the oil shale  industry, academic institutions, environmental groups, and private  citizens. Among federal agencies, BLM manages the land and the oil shale  beneath it and develops regulations for its development. USGS describes  the nature and extent of oil shale deposits and collects and disseminates  information on the nation’s water resources. DOE, through its various  offices, national laboratories, and arrangements with universities,  advances energy technologies, including oil shale technology. The  Environmental Protection Agency (EPA) sets standards for pollutants that  could be released by oil shale development and reviews environmental  impact statements, such as the PEIS. The Bureau of Reclamation (BOR)  manages federally built water projects that store and distribute water in 17  western states and provides this water to users. BOR monitors the amount  of water in storage and the amount of water flowing in the major streams  and rivers, including the Colorado River, which flows through oil shale  country and feeds these projects. BOR provides its monitoring data to  federal and state agencies that are parties to three major federal, state, and  international agreements, that together with other federal laws, court  decisions, and agreements, govern how water within the Colorado River  and its tributaries is to be shared with Mexico and among the states in  which the river or its tributaries are located. These three major  agreements are the Colorado River Compact of 1922, the Upper Colorado  River Basin Compact of 1948, and the Mexican Water Treaty of 1944.
The states of Colorado and Utah have regulatory responsibilities over  various activities that occur during oil shale development, including  activities that impact water. Through authority delegated by EPA under  the Clean Water Act, Colorado and Utah regulate discharges into surface  waters. Colorado and Utah also have authority over the use of most water  resources within their respective state boundaries. They have established  extensive legal and administrative systems for the orderly use of water  resources, granting water rights to individuals and groups. Water rights in  these states are not automatically attached to the land upon which the  water is located. Instead, companies or individuals must apply to the state  for a water right and specify the amount of water to be used, its intended  use, and the specific point from where the water will be diverted for use,  such as a specific point on a river or stream. Utah approves the application  for a water right through an administrative process, and Colorado  approves the application for a water right through a court proceeding. The  date of the application establishes its priority—earlier applicants have  preferential entitlement to water over later applicants if water availability  decreases during a drought. These earlier applicants are said to have  senior water rights. When an applicant puts a water right to beneficial use,  it is referred to as an absolute water right. Until the water is used,  however, the applicant is said to have a conditional water right. Even if the  applicant has not yet put the water to use, such as when the applicant is  waiting on the construction of a reservoir, the date of the application still  establishes priority. Water rights in both Colorado and Utah can be bought  and sold, and strong demand for water in these western states facilitates  their sale.
subsections: section_title: Challenges to Oil Shale Development
paragraphs: A significant challenge to the development of oil shale lies in the current  technology to economically extract oil from oil shale. To extract the oil,  the rock needs to be heated to very high temperatures—ranging from  about 650 to 1,000 degrees Fahrenheit—in a process known as retorting.  Retorting can be accomplished primarily by two methods. One method  involves mining the oil shale, bringing it to the surface, and heating it in a  vessel known as a retort. Mining oil shale and retorting it has been  demonstrated in the United States and is currently done to a limited extent  in Estonia, China, and Brazil. However, a commercial mining operation  with surface retorts has never been developed in the United States  because the oil it produces competes directly with conventional crude oil,  which historically has been less expensive to produce. The other method,  known as an in-situ process, involves drilling holes into the oil shale,  inserting heaters to heat the rock, and then collecting the oil as it is freed  from the rock. Some in-situ technologies have been demonstrated on very  small scales, but other technologies have yet to be proven, and none has  been shown to be economically or environmentally viable. Nevertheless,  according to some energy experts, the key to developing our country’s oil  shale is the development of an in-situ process because most of the richest  oil shale is buried beneath hundreds to thousands of feet of rock, making  mining difficult or impossible. Additional economic challenges include  transporting the oil produced from oil shale to refineries because pipelines  and major highways are not prolific in the remote areas where the oil shale  is located and the large-scale infrastructure that would be needed to  supply power to heat oil shale is lacking. In addition, average crude oil  prices have been lower than the threshold necessary to make oil shale  development profitable over time.
Large-scale oil shale development also brings socioeconomic impacts.  While there are obvious positive impacts such as the creation of jobs,  increase in wealth, and tax and royalty payments to governments, there  are also negative impacts to local communities. Oil shale development can  bring a sizeable influx of workers, who along with their families, put  additional stress on local infrastructure such as roads, housing, municipal  water systems, and schools. Development from expansion of extractive  industries, such as oil shale or oil and gas, has typically followed a “boom  and bust” cycle in the West, making planning for growth difficult.  Furthermore, traditional rural uses could be replaced by the industrial  development of the landscape, and tourism that relies on natural  resources, such as hunting, fishing, and wildlife viewing, could be  negatively impacted.
In addition to the technological, economic, and social challenges to  developing oil shale resources, there are a number of significant  environmental challenges. For example, construction and mining activities  can temporarily degrade air quality in local areas. There can also be long- term regional increases in air pollutants from oil shale processing,  upgrading, pipelines, and the generation of additional electricity.  Pollutants, such as dust, nitrogen oxides, and sulfur dioxide, can  contribute to the formation of regional haze that can affect adjacent  wilderness areas, national parks, and national monuments, which can have  very strict air quality standards. Because oil shale operations clear large  surface areas of topsoil and vegetation, some wildlife habitat will be lost.  Important species likely to be negatively impacted from loss of wildlife  habitat include mule deer, elk, sage grouse, and raptors. Noise from oil  shale operations, access roads, transmission lines, and pipelines can  further disturb wildlife and fragment their habitat. In addition, visual  resources in the area will be negatively impacted as people generally  consider large-scale industrial sites, pipelines, mines, and areas cleared of  vegetation to be visually unpleasant (see fig. 2 for a typical view within the  Piceance Basin). Environmental impacts from oil shale development could  be compounded by additional impacts in the area resulting from coal  mining, construction, and extensive oil and gas development. Air quality  and wildlife habitat appear to be particularly susceptible to the cumulative  affect of these impacts, and according to some environmental experts, air  quality impacts may be the limiting factor for the development of a large  oil shale industry in the future. Lastly, the withdrawal of large quantities of  surface water for oil shale operations could negatively impact aquatic life  downstream of the oil shale development. Impacts to water resources are  discussed in detail in the next section of this report.
section_title: Oil Shale Development Could Adversely Impact Water Resources, but the Magnitude of These Impacts Is Unknown
paragraphs: Oil shale development could have significant impacts on the quality and  quantity of surface and groundwater resources, but the magnitude of these  impacts is unknown because some technologies have yet to be  commercially proven, the size of a future oil shale industry is uncertain,  and knowledge of current water conditions and groundwater flow is  limited. Despite not being able to quantify the impacts from oil shale  development, hydrologists and engineers have been able to determine the  qualitative nature of impacts because other types of mining, construction,  and oil and gas development cause disturbances similar to impacts  expected from oil shale development. According to these experts, in the  absence of effective mitigation measures, impacts from oil shale  development to water resources could result from disturbing the ground  surface during the construction of roads and production facilities,  withdrawing water from streams and aquifers for oil shale operations,  underground mining and extraction, and discharging waste waters from oil  shale operations.
subsections: section_title: Quantitative Impacts of Oil Shale Development Cannot Be Measured at This Time
paragraphs: The quantitative impacts of future oil shale development cannot be  measured with reasonable certainty at this time primarily because of three  unknowns: (1) the unproven nature of in-situ technologies, (2) the  uncertain size of a future oil shale industry, and (3) insufficient knowledge  of current groundwater conditions. First, geological maps suggest that  most of the prospective oil shale in the Uintah and Piceance Basins is  more amenable to in-situ production methods rather than mining because  the oil shale lies buried beneath hundreds to thousands of feet of rock.  Studies have concluded that much of this rock is generally too thick to be  removed economically by surface mining, and deep subsurface mines are  likely to be costly and may recover no more than 60 percent of the oil  shale. Although several companies have been working on the in-situ  development of oil shale, none of these processes has yet been shown to  be commercially viable. Most importantly, the extent of the impacts of in- situ retorting on aquifers is unknown, and it is uncertain whether methods  for reclamation of the zones that are heated will be effective. Second, it is  not possible to quantify impacts on water resources with reasonable  certainty because it is not yet possible to predict how large an oil shale  industry may develop. The size of the industry would have a direct  relationship to water impacts. Within the PEIS, BLM has stated that the  level and degree of the potential impacts of oil shale development cannot  be quantified because this would require making many speculative  assumptions regarding the potential of the oil shale, unproven  technologies, project size, and production levels. Third, hydrologists at  USGS and BLM state that not enough is known about current surface  water and groundwater conditions in the Piceance and Uintah Basins.  More specifically, comprehensive baseline conditions for surface water  and groundwater do not exist. Therefore, without knowledge of current  conditions, it is not possible to detect changes in groundwater conditions,  much less attribute changes to oil shale development.
section_title: A Number of Impacts to Water Quality and Quantity Could Be Expected from Oil Shale Development
paragraphs: Impacts to water resources from oil shale development would result  primarily from disturbing the ground surface, withdrawing surface water  and groundwater, underground mining, and discharging water from  operations.
subsections: section_title: Ground Disturbances Could Degrade Surface Water Quality
paragraphs: In the absence of effective mitigation measures, ground disturbance  activities associated with oil shale development could degrade surface  water quality, according to the literature we reviewed and water experts to  whom we spoke. Both mining and the in-situ production of oil shale are  expected to involve clearing vegetation and grading the surface for access  roads, pipelines, production facilities, buildings, and power lines. In  addition, the surface that overlies the oil shale would need to be cleared  and graded in preparation for mining or drilling boreholes for in-situ  extraction. The freshly cleared and graded surfaces would then be  exposed to precipitation, and subsequent runoff would drain downhill  toward existing gullies and streams. If not properly contained or diverted  away from these streams, this runoff could contribute sediment, salts, and  possibly chemicals or oil shale products into the nearby streams,  degrading their water quality. Surface mining would expose the entire area  overlying the oil shale that is to be mined while subsurface mining would  expose less surface area and thereby contribute less runoff. One in-situ  operation proposed by Shell for its RD&D leases would require clearing of  the entire surface overlying the oil shale because wells are planned to be  drilled as close as 10 feet apart. Other in-situ operations, like those  proposed by American Shale Oil Company and ExxonMobil, envision  directionally drilling wells in rows that are far enough apart so that strips  of undisturbed ground would remain. The adverse impacts from ground  disturbances would remain until exposed surfaces were properly  revegetated.
If runoff containing excessive sediment, salts, or chemicals finds its way  into streams, aquatic resources could be adversely impacted, according to  the water experts to whom we spoke and the literature we reviewed.  Although aquatic populations can handle short-term increases in sediment,  long-term increases could severely impact plant and animal life. Sediment  could suffocate aquatic plants and decrease the photosynthetic activity of  these plants. Sediment could also suffocate invertebrates, fish, and  incubating fish eggs and adversely affect the feeding efficiency and  spawning success of fish. Sedimentation would be exacerbated if oil shale  activities destroy riparian vegetation because these plants often trap  sediment, preventing it from entering streams. In addition, toxic  substances derived from spills, leaks from pipelines, or leaching of waste  rock piles could increase mortality among invertebrates and fish.
Surface and underground mining of oil shale will produce waste rock that,  according to the literature we reviewed and water experts to whom we  spoke, could contaminate surface waters. Mined rock that is retorted on  site would produce large quantities of spent shale after the oil is extracted.  Such spent shale is generally stored in large piles that would also be  exposed to surface runoff that could possibly transport sediment, salts,  selenium, metals, and residual hydrocarbons into receiving streams unless  properly stabilized and reclaimed. EPA studies have shown that water  percolating through such spent shale piles transports pollutants long after  abandonment of operations if not properly mitigated. In addition to  stabilizing and revegetating these piles, mitigation measures could involve  diverting runoff into retention ponds, where it could be treated, and lining  the surface below waste rock with impervious materials that could prevent  water from percolating downward and transporting pollutants into  shallow groundwater. However, if improperly constructed, retention  ponds would not prevent the degradation of shallow groundwater, and  some experts question whether the impervious materials would hold up  over time.
section_title: Withdrawing Water for Oil Shale Operations Could Adversely Impact Surface Water and Groundwater
paragraphs: Withdrawing water from streams and rivers for oil shale operations could  have temporary adverse impacts on surface water, according to the  experts to whom we spoke and the literature we reviewed. Oil shale  operations need water for a number of activities, including mining,  constructing facilities, drilling wells, generating electricity for operations,  and reclamation of disturbed sites. Water for most of these activities is  likely to come from nearby streams and rivers because it is more easily  accessible and less costly to obtain than groundwater. Withdrawing water  from streams and rivers would decrease flows downstream and could  temporarily degrade downstream water quality by depositing sediment  within the stream channels as flows decrease. The resulting decrease in  water would also make the stream or river more susceptible to  temperature changes—increases in the summer and decreases in the  winter. Elevated temperatures could have adverse impacts on aquatic life,  including fishes and invertebrates, which need specific temperatures for  proper reproduction and development. Elevated water temperatures  would also decrease dissolved oxygen, which is needed by aquatic  animals. Decreased flows could also damage or destroy riparian  vegetation. Removal of riparian vegetation could exacerbate negative  impacts on water temperature and oxygen because such vegetation shades  the water, keeping its temperature cooler.
Similarly, withdrawing water from shallow aquifers—an alternative water  source—would have temporary adverse impacts on groundwater  resources. Withdrawals would lower water levels within these shallow  aquifers and the nearby streams and springs to which they are connected.  Extensive withdrawals could reduce groundwater discharge to connected  streams and springs, which in turn could damage or remove riparian  vegetation and aquatic life. Withdrawing water from deeper aquifers could  have longer-term impacts on groundwater and connected streams and  springs because replenishing these deeper aquifers with precipitation  generally takes longer.
section_title: Underground Mining and In- Situ Extraction Would Permanently Impact Aquifers
paragraphs: Underground mining would permanently alter the properties of the zones  that are mined, thereby affecting groundwater flow through these zones,  according to the literature we reviewed and the water experts to whom we  spoke. The process of removing oil shale from underground mines would  create large tunnels from which water would need to be removed during  mining operations. The removal of this water through pumping would  decrease water levels in shallow aquifers and decrease flows to streams  and springs that are connected. When mining operations cease, the tunnels  would most likely be filled with waste rock, which would have a higher  degree of porosity and permeability than the original oil shale that was  removed. Groundwater flow through this material would increase  permanently, and the direction and pattern of flows could change  permanently. Flows through the abandoned tunnels could decrease  ground water quality by increasing concentrations of salts, metals, and  hydrocarbons within the groundwater.
In-situ extraction would also permanently alter aquifers because it would  heat the rock to temperatures that transform the solid organic compounds  within the rock into liquid hydrocarbons and gas that would fracture the  rock upon escape. Water would be cooked off during the heating  processes. Some in-situ operations envision using a barrier to isolate thick  zones of oil shale with intervening aquifers from any adjacent aquifers and  pumping out all the groundwater from this isolated area before retorting.  Other processes, like those envisioned by ExxonMobil and AMSO, involve  trying to target thinner oil shale zones that do not have intervening  aquifers and, therefore, would theoretically not disturb the aquifers.  However, these processes involve fracturing the oil shale, and it is unclear  whether the fractures could connect the oil shale to adjacent aquifers,  possibly contaminating the aquifer with hydrocarbons. After removal of  hydrocarbons from retorted zones, the porosity and permeability of the  zones are expected to increase, thereby allowing increased groundwater  flow. Some companies propose rinsing retorted zones with water to  remove residual hydrocarbons. However, the effectiveness of rinsing is  unproven, and residual hydrocarbons, metals, salts, and selenium that  were mobilized during retorting could contaminate the groundwater.  Furthermore, the long-term effects of groundwater flowing through  retorted zones are unknown.
section_title: Discharge of Waste Waters from Operations Could Temporarily Impact Downstream Waters
paragraphs: The discharge of waste waters from operations would temporarily  increase water flows in receiving streams. According to BLM’s PEIS, waste  waters from oil shale operations that could be discharged include waters  used in extraction, cooling, the production of electricity, and sewage  treatment, as well as drainage water collected from spent oil shale piles  and waters pumped from underground mines or wells used to dewater the  retorted zones. Discharges could decrease the quality of downstream  water if the discharged water is of lower quality, has a higher temperature,  or contains less oxygen. Lower-quality water containing toxic substances  could increase fish and invertebrate mortality. Also, increased flow into  receiving streams could cause downstream erosion. However, at least one  company is planning to recycle waste water and water produced during  operations so that discharges and their impacts could be substantially  reduced.
section_title: Estimates of Water Needs for Commercial Oil Shale Development Vary Widely
paragraphs: While commercial oil shale development requires water for numerous  activities throughout its life cycle, estimates vary widely for the amount of  water needed to commercially produce oil shale. This variation in  estimates stems primarily from the uncertainty associated with  reclamation technologies for in-situ oil shale development and because of  the various ways to generate power for oil shale operations, which use  different amounts of water. Based on our review of available information  for the life cycle of oil shale production, existing estimates suggest that  from about 1 to 12 barrels of water could be needed for each barrel of oil  produced from in-situ operations, with an average of about 5 barrels.  About 2 to 4 barrels of water could be needed for each barrel of oil  produced from mining operations with a surface retort.
subsections: section_title: Oil Shale Development Requires Water throughout Its Life Cycle
paragraphs: Water is needed for five distinct groups of activities that occur during the  life cycle of oil shale development: (1) extraction and retorting, (2)  upgrading of shale oil, (3) reclamation, (4) power generation, and (5)  population growth associated with oil shale development.
Extraction and retorting. During extraction and retorting, water is used  for building roads, constructing facilities, controlling dust, mining and  handling ore, drilling wells for in-situ extraction, cooling of equipment and  shale oil, producing steam, in-situ fracturing of the retort zones, and  preventing fire. Water is also needed for on-site sanitary and potable uses.
Upgrading of shale oil. Water is needed to upgrade, or improve, the  quality of the produced shale oil so that it can be easily transported to a  refinery. The degree to which the shale oil needs to be upgraded varies  according to the retort process. Shale oil produced by surface retorting  generally requires more upgrading, and therefore, more water than shale  oil produced from in-situ operations that heat the rock at lower  temperatures and for a longer time, producing higher-quality oil.
Reclamation. During reclamation of mine sites, water is needed to cool,  compact, and stabilize the waste piles of retorted shale and to revegetate  disturbed surfaces, including the surfaces of the waste piles. For in-situ  operations, in addition to the typical revegetation of disturbed surfaces, as  shown in figure 3, water also will be needed for reclamation of the  subsurface retorted zones to remove residual hydrocarbons. The volume  of water that would be needed to rinse the zones at present is uncertain  and could be large, depending primarily on how many times the zones  need to be rinsed. In addition, some companies envision reducing water  demands for reclamation, as well as for extracting, retorting, and  upgrading, by recycling water produced during oil shale operations or by  treating and using water produced from nearby oil and gas fields.  Recycling technology, however, has not been shown to be commercially  viable for oil shale operations, and there could be legal restrictions on  using water produced from oil and gas operations.
Power generation. Water is also needed throughout the life cycle of oil  shale production for generating electricity from power plants needed in  operations. The amount of water used to produce this electricity varies  significantly according to generation and cooling technologies employed.  For example, thermoelectric power plants use a heat source to make  steam, which turns a turbine connected to a generator that makes the  electricity. The steam is captured and cooled, often with additional water,  and is condensed back into water that is then recirculated through the  system to generate more steam. Plants that burn coal to produce steam  use more water for cooling than combined cycle natural gas plants, which  combust natural gas to turn a turbine and then capture the waste heat to  produce steam that turns a second turbine, thereby producing more  electricity per gallon of cooling water. Thermoelectric plants can also use  air instead of water to condense the steam. These plants use fans to cool  the steam and consume virtually no water, but are less efficient and more  costly to run.
Population growth. Additional water would be needed to support an  anticipated increase in population due to oil shale workers and their  families who migrate into the area. This increase in population can  increase the demand for water for domestic uses. In isolated rural areas  where oil shale is located, sufficiently skilled workers may not be  available.
section_title: Estimates of Water Needs for In-Situ Development Vary Significantly
paragraphs: Based on studies that we reviewed, the total amount of water needed for  in-situ oil shale operations could vary widely, from about 1 to 12 barrels of  water per barrel of oil produced over the entire life cycle of oil shale  operations. The average amount of water needed for in-situ oil shale  production as estimated by these studies is about 5 barrels. This range is  based on information contained primarily in studies published in 2008 and  2009 by ExxonMobil, Shell, the Center for Oil Shale Technology and  Research at the Colorado School of Mines, the National Oil Shale  Association, and contractors to the state of Colorado. Figure 3 shows  Shell’s in-situ experimental site in Colorado. Because only two studies  examined all five groups of activities that comprise the life cycle of oil  shale production, we reviewed water estimates for each group of activities  that is described within each of the eight studies we reviewed. We  calculated the minimum and the maximum amount of water that could be  needed for in-situ oil shale development by summing the minimum  estimates and the maximum estimates, respectively, for each group of  activities. Differences in estimates are due primarily to the uncertainty in  the amount of water needed for reclamation and to the method of  generating power for operations.
Table 1 shows the minimum, maximum, and average amounts of water  that could be needed for each of the five groups of activities that comprise  the life cycle of in-situ oil shale development. The table shows that  reclamation activities contribute the largest amount of uncertainty to the  range of total water needed for in-situ oil shale operations. Reclamation  activities, which have not yet been developed, contribute from 0 to 5.5  barrels of water for each barrel of oil produced, according to the studies  we analyzed. This large range is due primarily to the uncertainty in how  much rinsing of retorted zones would be necessary to remove residual  hydrocarbons and return groundwater to its original quality. On one end of  the range, scientists at ExxonMobil reported that retorted zones may be  reclaimed by rinsing them several times and using 1 barrel of water or less  per barrel of oil produced. However, another study suggests that many  rinses and many barrels of water may be necessary. For example,  modeling by the Center for Oil Shale Technology and Research suggests  that if the retorted zones require 8 or 10 rinses, 5.5 barrels of water could  be needed for each barrel of oil produced. Additional uncertainty lies in  estimating how much additional porosity in retorted zones will be created  and in need of rinsing. Some scientists believe that the removal of oil will  double the amount of pore space, effectively doubling the amount of water  needed for rinsing. Other scientists question whether the newly created  porosity will have enough permeability so that it can be rinsed. Also, the  efficiency of recycling waste water that could be used for additional rinses  adds to the amount of uncertainty. For example, ExxonMobil scientists  believe that almost no new fresh water would be needed for reclamation if  it can recycle waste water produced from oil shale operations or treat and  use saline water produced from nearby oil and gas wells.
Table 1 also shows that the water needs for generating power contribute  significant uncertainty to the estimates of total water needed for in-situ  extraction. Estimates of water needed to generate electricity range from  near zero for thermoelectric plants that are cooled by air to about 3.4  barrels for coal-fired thermoelectric plants that are cooled by water,  according to the studies that we analyzed. These studies suggested that  from about 0.7 to about 1.2 barrels of water would be needed if electricity  is generated from combined cycle plants fueled by natural gas, depending  on the power requirements of the individual oil shale operation. Overall  power requirements are large for in-situ operations because of the many  electric heaters used to heat the oil shale over long periods of time—up to  several years for one technology proposed by industry. However,  ExxonMobil, Shell, and AMEC—a contractor to the state of Colorado— believe that an oil shale industry of significant size will not use coal-fired  electric power because of its greater water requirements and higher  carbon dioxide emissions. In fact, according to an AMEC study, estimates  for power requirements of a 1.5 million-barrel-per-day oil shale industry  would exceed the current coal-fired generating capacity of the nearest  plant by about 12 times, and therefore would not be feasible. Industry  representatives with whom we spoke said that it is more likely that a large  oil shale industry would rely on natural gas-powered combined cycle  thermoelectric plants, with the gas coming from gas fields within the  Piceance and Uintah Basins or from gas produced during the retort  process. ExxonMobil reports that it envisions cooling such plants with air,  thereby using next to no water for generating electricity. However, cooling  with air can be more costly and will ultimately require more electricity.
In addition, table 1 shows that extracting and retorting activities and  upgrading activities also contribute to the uncertainty in the estimates of  water needed for in-situ operations, but this uncertainty is significantly  less than that of reclamation activities or power generation. The range for  extraction and retorting is from 0 to 1 barrel of water. The range for  upgrading the produced oil is from 0.6 to 1.6 barrels of water, with both  the minimum and maximum of this range cited in a National Oil Shale  Association study. Hence, each of these two groups of activities  contribute about 1 barrel of water to the range of estimates for the total  amount of water needed for the life cycle of in-situ oil shale production.  Last, table 1 shows there is little variation in the likely estimates of water  needed to support the anticipated population increase associated with in- situ oil shale development. Detailed analyses of water needs for  population growth associated with an oil shale industry are present in the  PEIS, a study by the URS Corporation, and a study completed by the  Institute for Clean and Secure Energy at the University of Utah. These  estimates often considered the number of workers expected to move into  the area, the size of the families to which these workers belong, the ratio  of single-family to multifamily housing that would accommodate these  families, and per capita water consumption associated with occupants of  different housing types.
Figure 4 compares the total water needs over the life cycle of in-situ oil  shale development according to the various sources of power generation,  as suggested by the studies we reviewed. This is a convenient way to  visualize the water needs according to power source. The minimum,  average, and maximum values are the sum of the minimum, average, and  maximum water needs, respectively, for all five groups of activities. Most  of the difference between the minimum and the maximum of each power  type is due to water needed for reclamation.
section_title: Estimates of Water Needs for Mining and Surface Retorting Vary but Not as Much as the In-Situ Process
paragraphs: Estimates of water needed for mining oil shale and retorting it at the  surface vary from about 2 to 4 barrels of water per barrel of oil produced  over the entire life cycle of oil shale operations. The average is about 3  barrels of water. This range is based primarily on information obtained  through a survey of active oil shale companies completed by the National  Oil Shale Association in 2009 and information obtained from three  different retorts, as published in a report by the Office of Technology  Assessment (OTA) in 1980. Figure 5 shows a surface retort that is  operating today at a pilot plant. Because only two studies contained  reliable information for all five groups of activities that comprise the life  cycle of oil shale production, we reviewed water estimates for each group  of activities that is described within each of the eight studies we  reviewed. We calculated the minimum and the maximum amount of  water that could be needed for mining oil shale by summing the minimum  estimates and the maximum estimates, respectively, for each group of  activities. The range of water estimates for mining oil shale is far narrower  than that of in-situ oil shale production because, according to the studies  we reviewed, there are no large differences in water estimates for any of  the activities.
Table 2 shows the minimum, maximum, and average amounts of water  that could be needed for each of the groups of activities that comprise the  life cycle of oil shale development that relies upon mining and surface  retorting. Unlike for in-situ production, we could not segregate extraction  and retorting activities from upgrading activities because these activities  were grouped together in some of the studies on mining and surface  retorting. Nonetheless, as shown in table 2, the combination of these  activities contributes 1 barrel of water to the total range of estimated  water needed for the mining and surface retorting of oil shale. This 1  barrel of water results primarily from the degree to which the resulting  shale oil would need upgrading. An oil shale company representative told  us that estimates for upgrading shale oil vary due to the quality of the shale  oil produced during the retort process, with higher grades of shale oil  needing less processing. Studies in the OTA report did not indicate much  variability in water needs for the mining of the oil shale and the handling  of ore. Retorts also produce water—about half a barrel for each barrel of  oil produced—by freeing water that is locked in organic compounds and  minerals within the oil shale. Studies in the OTA report took this produced  water into consideration and reported the net anticipated water use.
Table 2 also shows that differences in water estimates for generating  power contributed about 1 barrel of water to the range of water needed for  mining and surface retorting. We obtained water estimates for power  generation either directly from the studies or from power requirements  cited within the studies. Estimates of water needed range from zero  barrels for electricity coming from thermoelectric plants that are cooled  by air to about 0.9 barrels for coal-fired thermoelectric plants that are  cooled with water. About 0.3 barrels of water are needed to generate  electricity from combined cycle plants fueled by natural gas. Startup oil  shale mining operations, which have low overall power requirements, are  more likely to use electricity from coal-fired power plants, according to  data supplied by oil shale companies, because such generating capacity is  available locally. However, a large-scale industry may generate electricity  from the abundant natural gas in the area or from gas that is produced  during the retorting of oil shale. Water needs for reclamation or for  supporting an anticipated increase in population associated with mining  oil shale show little variability in the studies that we reviewed.
Figure 6 compares the total water needs over the life cycle of mining and  surface retorting of oil shale according to the various sources of power  generation. The minimum, average, and maximum values are the sum of  the minimum, average, and maximum water needs, respectively, for all five  groups of activities.
section_title: Water Is Likely to Be Available Initially from Local Sources, but the Size of an Oil Shale Industry May Eventually Be Limited by Water Availability
paragraphs: Water is likely to be available for the initial development of an oil shale  industry, but the eventual size of the industry may be limited by the  availability of water and demands for water to meet other needs. Oil shale  companies operating in Colorado and Utah will need to have water rights  to develop oil shale, and representatives from all of the companies with  which we spoke are confident that they hold at least enough water rights  for their initial projects and will likely be able to purchase more rights in  the future. Sources of water for oil shale will likely be surface water in the  immediate area, such as the White River, but groundwater could also be  used. Nonetheless, the possibility of competing municipal and industrial  demands for future water, a warming climate, future needs under existing  compacts, and additional water needs for the protection of threatened and  endangered fishes, may eventually limit the size of a future oil shale  industry.
subsections: section_title: Oil Shale Companies Own Considerable Water Rights and Options Exist to Obtain More
paragraphs: Companies with interest in oil shale already hold significant water rights in  the Piceance Basin of Colorado, and representatives from all of the  companies with whom we spoke felt confident that they either had or  could obtain sufficient water rights to supply at least their initial  operations in the Piceance and Uintah Basins. Western Resource  Advocates, a nonprofit environmental law and policy organization,  conducted a study of water rights ownership in the Colorado and White  River Basins of Colorado and concluded that companies have significant  water rights in the area. For example, the study found that Shell owns  three conditional water rights for a combined diversion of about 600  cubic feet per second from the White River and one of its tributaries and  has conditional rights for the combined storage of about 145,000 acre-feet  in two proposed nearby reservoirs. Similarly, the study found that  ExxonMobil owns conditional storage capacities of over 161,000 acre-feet  on 17 proposed reservoirs in the area. In Utah, the Oil Shale Exploration  Company (OSEC), which owns an RD&D lease, has obtained a water right  on the White River that appears sufficient for reopening the White River  Mine and has cited the possibility of renewing an expired agreement with  the state of Utah for obtaining additional water from shallow aquifers  connected to the White River. Similarly, Red Leaf Resources cites the  possibility of drilling a water well on the state-owned lands that it has  leased for oil shale development.
In addition to exercising existing water rights and agreements, there are  other options for companies to obtain more water rights in the future,  according to state officials in Colorado and Utah. In Colorado, companies  can apply for additional water rights in the Piceance Basin on the Yampa  and White Rivers. Shell recently applied—but subsequently withdrew the  application—for conditional rights to divert up to 375 cubic feet per  second from the Yampa River for storage in a proposed reservoir that  would hold up to 45,000 acre-feet for future oil shale development. In  Utah, however, officials with the State Engineer’s office said that  additional water rights are not available, but that if companies want  additional rights, they could purchase them from other owners. Many  people who are knowledgeable on western water rights said that the  owners of these rights in Utah and Colorado would most likely be  agricultural users, based on a history of senior agricultural rights being  sold to developers in Colorado. For example, the Western Resource  Advocates study identified that in the area of the White River, ExxonMobil  Corporation has acquired full or partial ownership in absolute water rights  on 31 irrigation ditches from which the average amount of water diverted  per year has exceeded 9,000 acre-feet. These absolute water rights have  appropriation dates ranging from 1883 through 1918 and are thus senior to  holders of many other water rights, but their use would need to be  changed from irrigation or agricultural to industrial in order to be used for  oil shale. Also, additional rights may be available in Utah from other  sources. According to state water officials in Utah, the settlement of an  ongoing legal dispute between the state and the Ute Indian tribe could  result in the tribe gaining rights to 105,000 acre-feet per year in the Uintah  Basin. These officials said that it is possible that the tribe could lease the  water rights to oil shale companies. There are also two water conservancy  districts that each hold rights to tens of thousands of acre-feet per year of  water in the Uintah Basin that could be developed for any use as  determined by the districts, including for oil shale development.
section_title: Oil Shale Development Is Likely to Use Local Surface Water, but Groundwater Could Also Be Used
paragraphs: Most of the water needed for oil shale development is likely to come first  from surface flows, as groundwater is more costly to extract and generally  of poorer quality in the Piceance and Uintah Basins. However, companies  may use groundwater in the future should they experience difficulties in  obtaining rights to surface water. Furthermore, water is likely to come  initially from surface sources immediately adjacent to development, such  as the White River and its tributaries that flow through the heart of oil  shale country in Colorado and Utah, because the cost of pumping water  over long distances and rugged terrain would be high, according to water  experts. Shell’s attempt to obtain water from the more distant Yampa  River shows the importance of first securing nearby sources. In  relationship to the White River, the Yampa lies about 20 to 30 miles farther  north and at a lower elevation than Shell’s RD&D leases. Hence, additional  costs would be necessary to transport and pump the Yampa’s water to a  reservoir for storage and eventual use. Shell withdrew its application  citing the global economic downturn.
At least one company has considered obtaining surface water from the  even more distant Colorado River, about 30 to 50 miles to the south of the  RD&D leases where oil shale companies already hold considerable water  rights, but again, the costs of transporting and pumping water would be  greater. Although water for initial oil shale development in Utah is also  likely to come from the White River as indicated by OSEC’s interest, water  experts have cited the Green River as a potential water source. However,  the longer distance and rugged terrain is likely to be challenging. Figure 7  shows the locations of the oil shale resource areas and their proximity to  local surface water sources.
In addition to surface water, oil shale companies could use groundwater  for operations should more desirable surface water sources be  unavailable. However, companies would need to acquire the rights to this  groundwater. Shallow groundwater in the Piceance and Uintah Basins  occurs primarily within alluvial aquifers, which are aquifers composed of  unconsolidated sand and gravel associated with nearby streams and rivers.  The states of Utah and Colorado refer to these aquifers legally as tributary  waters, or waters that are connected to surface waters and hence are  considered to be part of the surface water source when appropriating  water rights. Any withdrawal of tributary water is considered to be a  withdrawal from the adjacent or nearby stream or river. Less is known  about deep groundwater in the Piceance and Uintah Basins, but  hydrologists consider it to be of lesser quality, with the water generally  becoming increasingly saline with depth. State officials in Utah said that  they consider this deeper groundwater to be tributary water, and state  officials in Colorado said that they generally consider this deeper water  also to be tributary water but will allow water rights applicants to prove  otherwise. In the Piceance and Uintah Basins, groundwater is not heavily  used, illustrating the reluctance of water users to tap this source.  Nevertheless, Shell is considering the use of groundwater, and  ExxonMobil is considering using water co-produced with natural gas from  nearby but deeper formations in the Piceance Basin. Also, BLM notes that  there is considerable groundwater in the regional Bird’s Nest Aquifer in  the area surrounding OSEC’s RD&D lease in the Uintah Basin. In addition,  representatives of oil shale companies said they plan to use water that is  released from the organic components of oil shale during the retort  process. Since this water is chemically bound within the solid organic  components rather than being in a liquid phase, it is not generally viewed  as being groundwater, but it is unclear as to how it would be regulated.
section_title: Oil Shale Development Will Likely Have to Compete with Increased Demands for Water for Other Needs and a Decreased Water Supply
paragraphs: Developing a sizable oil shale industry may take many years—perhaps 15  or 20 years by some industry and government estimates—and such an  industry may have to contend with increased demands for water to meet  other needs. Substantial population growth and its correlative demand for  water are expected in the oil shale regions of Colorado and Utah. This  region in Colorado is a fast-growing area. State officials expect that the  population within the region surrounding the Yampa, White, and Green  Rivers in Colorado will triple between 2005 and 2050. These officials  expect that this added population and corresponding economic growth by  2030 will increase municipal and industrial demands for water, exclusive  of oil shale development, by about 22,000 acre-feet per year, or a 76  percent increase from 2000. Similarly in Utah, state officials expect the  population of the Uintah Basin to more than double its 1998 size by 2050  and that correlative municipal and industrial water demands will increase  by 7,000 acre-feet per year, or an increase of about 30 percent since the  mid-1990s. Municipal officials in two communities adjacent to proposed  oil shale development in Colorado said that they were confident of  meeting their future municipal and industrial demands from their existing  senior water rights, and as such will probably not be affected by the water  needs of a future oil shale industry. However, large withdrawals could  impact agricultural interests and other downstream water users in both  states, as oil shale companies may purchase existing irrigation and  agricultural rights for their oil shale operations. State water officials in  Colorado told us that some holders of senior agricultural rights have  already sold their rights to oil shale companies.
A future oil shale industry may also need to contend with a decreased  physical supply of water regionwide due to climate change. A contractor  to the state of Colorado ran five projections through a number of climate  models and found that their average result suggested that by 2040, a  warming climate may reduce the amount of water in the White River in  Colorado by about 13 percent, or 42,000 acre-feet. However, there was  much variability among the five results, ranging from a 40 percent  decrease to a 16 percent increase in today’s flow and demonstrating the  uncertainty associated with climate predictions. Nevertheless, any  decrease would mean that less water would be available downstream in  Utah. Because of a warmer climate, the contractor also found that water  needed to irrigate crops could increase significantly in the White River  Basin, but it is uncertain whether the holders of the water rights used to  irrigate the crops would be able to secure this additional water.  Simultaneously, the model shows that summer precipitation is expected to  decrease, thus putting pressure on farmers to withdraw even more water  from local waterways. In addition, the contractor predicted that more  precipitation is likely to fall as rain rather than snow in the early winter  and late spring. Because snow functions as a natural storage reservoir by  releasing water into streams and aquifers as temperatures rise, less snow  means that storage and runoff schedules will be altered and less water  may be available at different times of the year. Although the model shows  that the White River is expected to have reduced flows due to climate  change, the same model shows that the Yampa is more likely to  experience an increased flow because more precipitation is expected to  fall in the mountains, which are its headwaters. Hence, oil shale  companies may look to the Yampa for additional water if restrictions on  the White are too great, regardless of increased costs to transport the  water. While there is not a similar study on climate change impacts for  Utah, it is likely that some of the impacts will be similar, considering the  close proximity and similar climates in the Uintah and Piceance Basins.
Colorado’s and Utah’s obligations under interstate compacts could further  reduce the amount of water available for development. The Colorado  River Compact of 1922, which prescribes how the states through which  the Colorado River and its tributaries flow share the river’s water, is based  on uncharacteristically high flows, as cited in a study contracted by the  state of Colorado. Water regulators have since shown that the flow rates  used to allocate water under the compact may be 21 percent higher than  average historical flow rates, thereby overestimating the amount of water  that may be available to share. As a result, the upstream states of Colorado  and Utah may not have as much water to use as they had originally  planned and may be forced to curtail water consumption so that they can  deliver the amount of water that was agreed on in the compact to the  downstream states of Arizona, Nevada, and California. Another possible  limitation on withdrawals from the Colorado River system is the  requirement to protect certain fish species under the Endangered Species  Act. Federal officials stated that withdrawals from the Colorado River  system, including its tributaries the White and Green Rivers, could be  limited by the amount of flow that is necessary to sustain populations of  threatened or endangered fishes. Although there are currently no federally  mandated minimum flow requirements on the White River in either Utah  or Colorado, the river is home to populations of the federally endangered  Colorado Pikeminnow, and the Upper Colorado Recovery Program is  currently working on a biological opinion which may prescribe minimum  flow requirements. In addition, the Green River in Utah is home to  populations of four threatened or endangered fishes: the Colorado  Pikeminnow, the Razorback Sucker, the Humpback Chub, and the  Bonytail Chub. For this reason, agency officials are recommending  minimum flow requirements on the Green, which could further restrict the  upstream supply of available water.
section_title: The Size of an Oil Shale Industry May Be Limited by Water Availability
paragraphs: Although oil shale companies own rights to a large amount of water in the  oil shale regions of Colorado and Utah, there are physical and legal limits  on how much water they can ultimately withdraw from the region’s  waterways, and thus limits on the eventual size of the overall industry.  Physical limits are set by the amount of water that is present in the river,  and the legal limit is the sum of the water that can be legally withdrawn  from the river as specified in the water rights held by downstream users.  Examining physical limits can demonstrate how much water may be  available to all water users. Subtracting the legal limit can demonstrate  how much water is available for additional development, providing that  current water rights and uses do not change in the future. The state of  Colorado refers to this remaining amount of water in the river as that  which is physically and legally available.
To put the water needs of a potential oil shale industry in Colorado into  perspective, we compared the needs of oil shale industries of various sizes  to what currently is physically available in the White River at Meeker,  Colorado—a small town immediately east of high-quality oil shale deposits  in the Piceance Basin. We also compared the water needs of an oil shale  industry to what may be physically and legally available from the White  River in 2030. Table 3 shows scenarios depicting the amounts of water that  would be needed to develop an oil shale industry of various sizes that  relies on mining and surface retorting, based on the studies we examined.  Table 4 shows similar scenarios for an oil shale industry that uses in-situ  extraction, based on the studies that we examined. The sizes are based on  industry and expert opinion and are not meant to be predictions. Both  tables assume water demands for peak oil shale production rates, but  water use may not follow such a pattern. For example, water use for  reclamation activities may not fully overlap with water use for extraction.  Also, an industry composed of multiple operations is likely to have some  operations at different stages of development. Furthermore, because of  the natural variability of stream flows, both on an annual basis and from  year-to-year, reservoirs would need to be built to provide storage, which  could be used to release a consistent amount of water on a daily basis.
Data maintained by the state of Colorado indicate the amount of water  that is physically available in the Whiter River at Meeker, Colorado,  averages about 472,000 acre-feet per year. Table 3 suggests that this is  much more water than is needed to support the water needs for all the  sizes of an industry relying on mining and surface retorting that we  considered. Table 4, however, shows that an industry that uses in-situ  extraction could be limited just by the amount of water physically  available in the White River at Meeker, Colorado. For example, based on  an oil shale industry that uses about 12 barrels of water for each barrel of  shale oil it produces, such an industry could not reach 1 million barrels per  day if it relied solely on physically available water from the White River.
Comparing an oil shale industry’s needs to what is physically and legally  available considers the needs of current users and the anticipated needs of  future users, rather than assuming all water in the river is available to an  oil shale industry. The amount of water that is physically and legally  available in the White River at Meeker is depicted in table 5. According to  the state of Colorado’s computer models, holders of water rights  downstream use on average about 153,000 acre-feet per year, resulting in  an average of about 319,000 acre-feet per year that is currently physically  and legally available for development near Meeker. By 2030, however, the  amount of water that is physically and legally available is expected to  change because of increased demand and decreased supply. After taking  into account an anticipated future decrease of 22,000 acre-feet per year of  water due to a growing population, about 297,000 acre-feet per year may  be available for future development if current water rights and uses do not  change by 2030. However, there may be additional decreases in the  amount of physically and legally available water in the White River due to  climate change, demands under interstate agreements, and water  requirements for threatened or endangered fishes, but we did not include  these changes in table 5 because of the large uncertainty associated with  estimates.
Comparing the scenarios in table 4 to the amount of water that is  physically and legally available in table 5 shows the sizes that an in-situ oil  shale industry may reach relying solely on obtaining new rights on the  White River. The scenarios in table 4 suggest that if an in-situ oil shale  industry develops to where it produces 500,000 barrels of oil per day—an  amount that some experts believe is reasonable—an industry of this size  could possibly develop in Colorado even if it uses about 12 barrels of  water per barrel of shale oil it produces. Similarly, the scenarios suggest  that an in-situ industry that uses about 5 barrels of water per barrel of oil  produced—almost the average from the studies in which power comes  from combined cycle natural gas plants—could grow to 1 million barrels  of oil per day using only the water that appears to be physically and legally  available in 2030 in the White River. Table 4 also shows that an industry  that uses just 1 barrel of water per barrel of shale oil produced could grow  to over 2.5 million barrels of oil per day.
Regardless of these comparisons, more water or less water could be  available in the future because it is unlikely that water rights will remain  unchanged until 2030. For example, officials with the state of Colorado  reported that conditional water rights—those rights held but not used— are not accounted for in the 297,000 acre-feet per year of water that is  physically and legally available because holders of these rights are not  currently withdrawing water. These officials also said that the amount of  conditional water rights greatly exceeds the flow in the White River near  Meeker, and if any of these conditional rights are converted to absolute  rights and additional water is then withdrawn downstream, even less  water will be available for future development. However, officials with the  state of Colorado said that some of these conditional water rights are  already owned by oil shale companies, making it unnecessary for some  companies to apply for new water rights. In addition, they said, some of  the absolute water rights that are accounted for in the estimated 153,000  acre-feet per year of water currently being withdrawn are already owned  by oil shale companies. These are agricultural rights that were purchased  by oil shale interests who leased them back to the original owners to  continue using them for agricultural purposes. Should water not be  available from the White River, companies would need to look to  groundwater or surface water outside of the immediate area.
There are less data available to predict future water supplies in Utah’s oil  shale resource area. The state of Utah did not provide us summary  information on existing water rights held by oil shale companies.  According to the state of Colorado, the average annual physical flow of the  White River near the Colorado-Utah border is about 510,000 acre-feet per  year. Any amount withdrawn from the White River in Colorado would be  that much less water that would be available for development downstream  in Utah. The state of Utah estimates that the total water supply of the  Uintah Basin, less downstream obligations under interstate compacts, is  688,000 acre-feet per year. Much of the surface water contained in this  amount is currently being withdrawn, and water rights have already been  filed for much of the remaining available surface water.
section_title: Federal Research Efforts on the Impacts of Oil Shale Development on Water Resources Do Not Provide Sufficient Data for Future Monitoring
paragraphs: Although the federal government sponsors research on the nexus between  oil shale development and water, a lack of comprehensive data on the  condition of surface water and groundwater and their interaction limit  efforts to monitor the future impacts of oil shale development. Currently  DOE funds some research related to oil shale and water resources,  including research on water rights, water needs, and the impacts of oil  shale development on water quality. Interior also performs limited  research on characterizing surface and groundwater resources in oil shale  areas and is planning some limited monitoring of water resources.  However, there is general agreement among those we contacted— including state personnel who regulate water resources, federal agency  officials responsible for studying water, water researchers, and water  experts—that this ongoing research is insufficient to monitor and then  subsequently mitigate the potential impacts of oil shale development on  water resources. In addition, DOE and Interior officials noted that they  seldom formally share the information on their water-related research  with each other.
subsections: section_title: DOE Funds Research on Water Rights, Water Needs, and the Impacts of Oil Shale Development on Water Resources
paragraphs: DOE has sponsored most of the oil shale research that involves water- related issues. This research consists of projects managed by the National  Energy Technology Laboratory (NETL), the Office of Naval Petroleum and  Oil Shale Reserves, and the Idaho National Laboratory. As shown in table  6, DOE has sponsored 13 of 15 projects initiated by the federal government  since June 2006. DOE’s projects account for almost 90 percent of the  estimated $5 million that is to be spent by the federal government on  water-related oil shale research through 2013. Appendix II contains a list  and description of these projects.
NETL sponsors the majority of the water-related oil shale research  currently funded by DOE. Through workshops, NETL gathers information  to prioritize research. For example, in October 2007, NETL sponsored the  Oil Shale Environmental Issues and Needs Workshop that was attended by  a cross-section of stakeholders, including officials from BLM and state  water regulatory agencies, as well as representatives from the oil shale  industry. One of the top priorities that emerged from the workshop was to  develop an integrated regional baseline for surface water and groundwater  quality and quantity. As we have previously reported, after the  identification of research priorities, NETL solicits proposals and engages  in a project selection process. We identified seven projects involving oil  shale and water that NETL awarded since June 2006. The University of  Utah, Colorado School of Mines, the Utah Geological Survey, and the  Idaho National Laboratory (INL) are performing the work on these  projects. These projects cover topics such as water rights, water needs for  oil shale development, impacts of retorting on water quality, and some  limited groundwater modeling. One project conducted by the Colorado  School of Mines involves developing a geographic information system for  storing, managing, analyzing, visualizing, and disseminating oil shale data  from the Piceance Basin. Although this project will provide some baseline  data on surface water and groundwater and involves some theoretical  groundwater modeling, the project’s researchers told us that these data  will neither be comprehensive nor complete. In addition, NETL-sponsored  research conducted at the University of Utah involves examining the  effects of oil shale processing on water quality, new approaches to treat  water produced from oil shale operations, and water that can be recycled  and reused in operations.
INL is sponsoring and performing research on four water-related oil shale  projects while conducting research for NETL and the Office of Naval  Petroleum and Oil Shale Reserves. The four projects that INL is sponsoring  were self-initiated and funded internally through DOE’s Laboratory  Directed Research and Development program. Under this program, the  national laboratories have the discretion to self-initiate independent  research and development, but it must focus on the advanced study of  scientific or technical problems, experiments directed toward proving a  scientific principle, or the early analysis of experimental facilities or  devices. Generally, the researchers propose projects that are judged by  peer panels and managers for their scientific merits. An INL official told us  they selected oil shale and water projects because unconventional fossil  fuels, which include oil shale, are a priority in which they have significant  expertise.
According to DOE officials, one of the projects managed by the Office of  Naval Petroleum and Oil Shale Reserves is directed at research on the  environmental impacts of unconventional fuels. The Los Alamos National  Laboratory is conducting the work for DOE, which involves examining  water and carbon-related issues arising from the development of oil shale  and other unconventional fossil fuels in the western United States. Key  water aspects of the study include the use of an integrated modeling  process on a regional basis to assess the amounts and availability of water  needed to produce unconventional fuels, water storage and withdrawal  requirements, possible impacts of climate change on water availability,  and water treatment and recycling options. Although a key aspect of the  study is to assess water availability, researchers on the project told us that  little effort will be directed at assessing groundwater, and the information  developed will not result in a comprehensive understanding of the  baseline conditions for water quality and quantity.
section_title: Interior Funds Limited Oil Shale-Related Research on Groundwater and Surface Water Resources and Monitoring
paragraphs: Within Interior, BLM is sponsoring two oil shale projects related to water  resources with federal funding totaling about $500,000. The USGS is  conducting the research for both projects. For one of the projects, which  is funded jointly by BLM and a number of Colorado cities and counties  plus various oil shale companies, the research involves the development of  a common repository for water data collected from the Piceance Basin.  More specifically, the USGS has developed a Web-based repository of  water quality and quantity data obtained by identifying 80 public and  private databases and by analyzing and standardizing data from about half  of them. According to USGS officials, many data elements are missing, and  the current repository is not comprehensive. The second project, which is  entirely funded by BLM, will monitor groundwater quality and quantity  within the Piceance Basin in 5 existing wells and 10 more to be determined  at a future date. Although USGS scientists said that this is a good start to  understanding groundwater resources, it will not be enough to provide a  regional understanding of groundwater resources.
section_title: Gaps in Groundwater and Surface Water Data Have Been Identified by Federal and State Officials
paragraphs: Federal law and regulations require the monitoring of major federal  actions, such as oil shale development. Regulations developed under the  National Environmental Policy Act (NEPA) for preparing an  environmental impact statement (EIS), such as the EIS that will be needed  to determine the impacts of future oil shale development, require the  preparing agency to adopt a monitoring and enforcement program if  measures are necessary to mitigate anticipated environmental impacts.  Furthermore, the NEPA Task Force Report to the Council on  Environmental Quality noted that monitoring must occur for long enough  to determine if the predicted mitigation effects are achieved. The council  noted that monitoring and consideration of potential adaptive measures to  allow for midcourse corrections, without requiring new or supplemental  NEPA review, will assist in accounting for unanticipated changes in  environmental conditions, inaccurate predictions, or subsequent  information that might affect the original environmental conditions. In  September 2007, the Task Force on Strategic Unconventional Fuels—an  11-member group that included the Secretaries of DOE and Interior and  the Governors of Colorado and Utah—issued a report with  recommendations on promoting the development of fuels from domestic  unconventional fuel resources as mandated by the Energy Policy Act of  2005. This report included recommendations and strategies for developing  baseline conditions for water resources and monitoring the impacts from  oil shale development. It recommended that a monitoring plan be  developed and implemented to fill data gaps at large scales and over long  periods of time and to also develop, model, test, and evaluate short- and  long-term monitoring strategies. The report noted that systems to monitor  water quality would be evaluated; additional needs would be identified;  and relevant research, development, and demonstration needs would be  recommended.
Also in September 2007, the USGS prepared for BLM a report to improve  the efficiency and effectiveness of BLM’s monitoring efforts. The report  noted that regional water-resources monitoring should identify gaps in  data, define baseline conditions, develop regional conceptual models,  identify impacts, assess the linkage of impacts to energy development, and  understand how impacts propagate. The report also noted that in the  Piceance Basin, there is no local, state-level, or national comprehensive  database for surface water and groundwater data. Furthermore, for  purposes of developing a robust and cost-effective monitoring plan, the  report stated that a compilation and analysis of available data are  necessary. One of the report’s authors told us that the two BLM oil shale  projects that the USGS is performing are the initial steps in implementing  such a regional framework for water resource monitoring. However, the  author said that much more work is needed because so much water data  are missing. He noted the current data repository is not comprehensive  and much more data would be needed to determine whether oil shale  development will create adverse effects on water resources.
Nearly all the federal agency officials, state water regulators, oil shale  researchers, and water experts with whom we spoke said that more data  are needed to understand the baseline condition of groundwater and  surface water, so that the potential impacts of oil shale development can  be monitored (see appendix I for a list of the agencies we contacted).  Several officials and experts to whom we spoke stressed the need to  model the movement of groundwater and its interaction with surface  water to understand the possible transport of contaminants from oil shale  development. They suggested that additional research would help to  overcome these shortcomings. Specifically, they identified the following  issues:  Insufficient data for establishing comprehensive baseline conditions for  surface water and groundwater quality and quantity. Of the 18 officials  and experts we contacted, 17 noted that there are insufficient data to  understand the current baseline conditions of water resources in the  Piceance and Uintah Basins. Such baseline conditions include the existing  quantity and quality of both groundwater and surface water. Hydrologists  among those we interviewed explained that more data are needed on the  chemistry of surface water and groundwater, properties of aquifers, age of  groundwater, flow rates and patterns of groundwater, and groundwater  levels in wells. Although some current research projects have and are  collecting some water data, officials from the USGS, Los Alamos National  Laboratory, and the universities doing this research agreed their data are  not comprehensive enough to support future monitoring efforts.  Furthermore, Colorado state officials told us that even though much water  data were generated over time, including during the last oil shale boom,  little of these data have been assimilated, gaps exist, and data need to be  updated in order to support future monitoring.
Insufficient research on groundwater movement and its interaction  with surface water for modeling possible transport of contaminants.  Sixteen of 18 officials and experts to whom we spoke noted that additional  research is needed to develop a better understanding of the interactions  between groundwater and surface water and of groundwater movement.  Officials from NETL explained that this is necessary in order to monitor  the rate and pattern of flow of possible contaminants resulting from the in- situ retorting of oil shale. They noted that none of the groundwater  research currently under way is comprehensive enough to build the  necessary models to understand the interaction and movement. NETL  officials noted more subsurface imaging and visualization are needed to  build geologic and hydrologic models and to study how quickly  groundwater migrates. These tools will aid in monitoring and providing  data that does not currently exist.
section_title: Interior and DOE Officials Generally Have Not Shared Information on Oil Shale Research
paragraphs: Interior and DOE officials generally have not shared current research on  water and oil shale issues. USGS officials who conduct water-related  research at Interior and DOE officials at NETL, which sponsors the  majority of the water and oil shale research at DOE, stated they have not  talked with each other about such research in almost 3 years. USGS staff  noted that although DOE is currently sponsoring most of the water-related  research, USGS researchers were unaware of most of these projects. In  addition, staff at Los Alamos National Laboratory who are conducting  some water-related research for DOE noted that various researchers are  not always aware of studies conducted by others and stated that there  needs to be a better mechanism for sharing this research. Based on our  review, we found there does not appear to be any formal mechanism for  sharing water-related research activities and results among Interior, DOE,  and state regulatory agencies in Colorado and Utah. The last general  meeting to discuss oil shale research among these agencies was in October  2007, although there have been opportunities to informally share research  at the annual Oil Shale Symposium, the last one of which was conducted  at the Colorado School of Mines in October 2010. Of the various officials  with the federal and state agencies, representatives from research  organizations, and water experts we contacted, 15 of 18 noted that federal  and state agencies could benefit from collaboration with each other on  water-related research involving oil shale. Representatives from NETL,  who are sponsoring much of the current research, stated that  collaboration should occur at least every 6 months.
We and others have reported that collaboration among government  agencies can produce more public value than one agency acting alone.  Specifically concerning water resources, we previously reported that  coordination is needed to enable monitoring programs to make better use  of available resources in light of organizations often being unaware of data  collected by other groups. Similarly in 2004, the National Research  Council concluded that coordination of water research is needed to make  deliberative judgments about the allocation of funds, to minimize  duplication, to present to Congress and the public a coherent strategy for  federal investment, and to facilitate large-scale multiagency research  efforts. In 2007, the Subcommittee on Water Availability and Quality  within the Office of Science and Technology Policy, an office that advises  the President and leads interagency efforts related to science and  technology stated, “Given the importance of sound water management to  the Nation’s well-being it is appropriate for the Federal government to play  a significant role in providing information to all on the status of water  resources and to provide the needed research and technology that can be  used by all to make informed water management decisions.” In addition,  H.R. 1145—the National Water Research and Development Initiative Act of  2009—which has passed the House of Representatives and is currently in a  Senate committee, would establish a federal interagency committee to  coordinate all federal water research, which totals about $700 million  annually. This bill focuses on improving coordination among agency  research agendas, increasing the transparency of water research  budgeting, and reporting on progress toward research outcomes.
section_title: Conclusions
paragraphs: The unproven nature of oil shale technologies and choices in how to  generate the power necessary to develop this resource cast a shadow of  uncertainty over how much water is needed to sustain a commercially  viable oil shale industry. Additional uncertainty about the size of such an  industry clouds the degree to which surface and groundwater resources  could be impacted in the future. Furthermore, these uncertainties are  compounded by a lack of knowledge of the current baseline conditions of  groundwater and surface water, including their chemistry and interaction,  properties of aquifers, and the age and rate of movement of groundwater,  in the arid Piceance and Uintah Basins of Colorado and Utah, where water  is considered one of the most precious resources. All of these  uncertainties pose difficulties for oil shale developers, federal land  managers, state water regulators, and current water users in their efforts  to protect water resources.
Attempts to commercially develop oil shale in the United States have  spanned nearly a century. During this time, the industry has focused  primarily on overcoming technological challenges and trying to develop a  commercially viable operation. More recently, the federal government has  begun to focus on studying the potential impacts of oil shale development  on surface water and groundwater resources. However, these efforts are in  their infancy when compared to the length of time that the industry has  spent on attempting to overcome technological challenges. These nascent  efforts do not adequately define current baseline conditions for water  resources in the Piceance and Uintah Basins, nor have they begun to  model the important interaction of groundwater and surface water in the  region. Thus they currently fall short of preparing federal and state  governments for monitoring the impacts of any future oil shale  development. In addition, there is a lack of coordination among federal  agencies on water-related research and a lack of communicating results  among themselves and to the state regulatory agencies. Without such  coordination and communication, federal and state agencies cannot begin  to develop an understanding of the potential impacts of oil shale  development on water resources and monitor progress toward shared  water goals. By taking steps now, the federal government, working in  concert with the states of Colorado and Utah, can position itself to help  monitor western water resources should a viable oil shale industry  develop in the future.
section_title: Recommendations for Executive Action
paragraphs: To prepare for possible impacts from the future development of oil shale,  we are making three recommendations to the Secretary of the Interior.  Specifically, the Secretary should direct the appropriate managers in the  Bureau of Land Management and the U.S. Geological Survey to  1.  establish comprehensive baseline conditions for groundwater and  surface water quality, including their chemistry, and quantity in the  Piceance and Uintah Basins to aid in the future monitoring of impacts  from oil shale development in the Green River Formation; 2.  model regional groundwater movement and the interaction between  groundwater and surface water, in light of aquifer properties and the  age of groundwater, so as to help in understanding the transport of  possible contaminants derived from the development of oil shale; and 3.  coordinate with the Department of Energy and state agencies with  regulatory authority over water resources in implementing these  recommendations, and to provide a mechanism for water-related  research collaboration and sharing of results.
section_title: Agency Comments
paragraphs: We provided a copy of our draft report to Interior and DOE for their  review and comment. Interior provided written comments and generally  concurred with our findings and recommendations. Interior highlighted  several actions it has under way to begin to implement our  recommendations. Specifically, Interior stated that with regard to our first  recommendation to establish comprehensive baseline conditions for  surface water and groundwater in the Piceance and Uintah Basins,  implementation of this recommendation includes ongoing USGS efforts to  analyze existing water quality data in the Piceance Basin and ongoing  USGS efforts to monitor surface water quality and quantity in both basins.  Interior stated that it plans to conduct more comprehensive assessments  in the future. With regard to our second recommendation to model  regional groundwater movement and the interaction between groundwater  and surface water, Interior said BLM and USGS are working on identifying  shared needs for modeling. Interior underscored the importance of  modeling prior to the approval of large-scale oil shale development and  cites the importance of the industry’s testing of various technologies on  federal RD&D leases to determine if production can occur in commercial  quantities and to develop an accurate determination of potential water  uses for each technology. In support of our third recommendation to  coordinate with DOE and state agencies with regulatory authority over  water resources, Interior stated that BLM and USGS are working to  improve such coordination and noted current efforts with state and local  authorities. Interior’s comments are reproduced in appendix III.
DOE also provided written comments, but did not specifically address our  recommendations. Nonetheless, DOE indicated that it recognizes the need  for a more comprehensive and integrated cross-industry/government  approach for addressing impacts from oil shale development. However,  DOE raised four areas where it suggested additional information be added  to the report or took issue with our findings. First, DOE suggested that we  include in our report appropriate aspects of a strategic plan drafted by an  ad hoc group of industry, national laboratory, university, and government  representatives organized by the DOE Office of Naval Petroleum and Oil  Shale Reserves. We believe aspects of this strategic plan are already  incorporated into our report. For example, the strategic plan of this ad hoc  group calls for implementing recommendations of the Task Force on  Strategic Unconventional Fuels, which was convened by the Secretary of  Energy in response to a directive within the Energy Policy Act of 2005. The  Task Force on Strategic and Unconventional fuels recommended  developing baseline conditions for water resources and monitoring the  impacts from oil shale development, which is consistent with our first  recommendation. The ad hoc group’s report recognized the need to share  information and collaborate with state and other federal agencies, which is  consistent with our third recommendation. As such, we made no changes  to this report in response to this comment.
Second, DOE stated that we overestimated the amount of water needed  for in-situ oil shale development and production. We disagree with DOE’s  statement because the estimates presented in our report respond to our  objective, which was to describe what is known about the amount of  water that may be needed for commercial oil shale development, and they  are based on existing publicly available data. We reported the entire range  of reputable studies without bias to illustrate the wide range of uncertainty  in water needed to commercially develop oil shale, given the current  experimental nature of the process. We reported only publicly available  estimates based on original research that were substantiated with a  reasonable degree of documentation so that we could verify that the  estimates covered the entire life cycle of oil shale development and that  these estimates did not pertain solely to field demonstration projects, but  were instead scalable to commercial operations. We reviewed and  considered estimates from all of the companies that DOE identified in its  letter. The range of water needed for commercial in-situ development of  oil shale that we report ranges from 1 to 12 barrels of water per barrel of  oil. These lower and upper bounds represent the sum of the most  optimistic and most pessimistic estimates of water needed for all five  groups of activities that we identified as comprising the life cycle of in-situ  oil shale development. However, the lower estimate is based largely on  estimates by ExxonMobil and incorporates the use of produced water,  water treatment, and recycling, contrary to DOE’s statement that we  dismissed the significance of these activities. The upper range is  influenced heavily by the assumption that electricity used in retorting will  come from coal-fired plants and that a maximum amount of water will be  used for rinsing the retorted zones, based on modeling done at the Center  for Oil Shale Technology and Research. The studies supporting these  estimates were presented at the 29th Annual Oil Shale Symposium at the  Colorado School of Mines. Such a range overcomes the illusion of  precision that is conveyed by a single point estimate, such as the manner  in which DOE cites the 1.59 barrels of water from the AMEC study, or the  bias associated with reporting a narrow range based on the assumption  that certain technologies will prevail before they are proven to be  commercially viable for oil shale development. Consequently, we made no  changes to the report in response to this comment.
Third, DOE stated that using the amount of water in the White River at  Meeker, Colorado, to illustrate the availability of water for commercial oil  shale development understates water availability. We disagree with DOE’s  characterization of our illustration. The illustration we use in the report is  not meant to imply that an entire three-state industry would be limited by  water availability at Meeker. Rather, the illustration explores the  limitations of an in-situ oil shale industry only in the Piceance Basin. More  than enough water appears available for a reasonably sized industry that  depends on mining and surface retorting in the Piceance basin. Our  illustration also suggests that there may be more than enough water to  supply a 2.5 million barrel-per-day in-situ industry at minimum water  needs, even considering the needs of current water users and the  anticipated needs of future water users. In addition, the illustration  suggests that there may be enough water to supply an in-situ industry in  the Piceance Basin of between 1 and 2 million barrels per day at average  water needs, depending upon whether all the water in the White River at  Meeker is used or only water that is expected to be physically and legally  available in the future. However, the illustration does point out limitations.  It suggests that at maximum water needs, an in-situ industry in the  Piceance Basin may not reach 1 million barrels per day if it relied solely on  water in the White River at Meeker. Other sources of water may be  needed, and our report notes that these other sources could include water  in the Yampa or Colorado Rivers, as well as groundwater. Use of produced  water and recycling could also reduce water needs as noted in the draft  report. Consequently, we made no changes to the report in response to  this comment.
Fourth, DOE stated that the report gives the impression that all oil shale  technologies are speculative and proving them to be commercially viable  will be difficult, requiring a long period of time with uncertain outcomes.  We disagree with this characterization of our report. Our report clearly  states that there is uncertainty regarding the commercial viability of in-situ  technologies. Based on our discussions with companies and review of  available studies, Shell is the only active oil shale company to have  successfully produced shale oil from a true in-situ process. Considering  the uncertainty associated with impacts on groundwater resources and  reclamation of the retorted zone, commercialization of an in-situ process  is likely to be a number of years away. To this end, Shell has leased federal  lands from BLM to test its technologies, and more will be known once this  testing is completed. With regard to mining oil shale and retorting it at the  surface, we agree that it is a relatively mature process. Nonetheless,  competition from conventional crude oil has inhibited commercial oil  shale development in the United States for almost 100 years. Should some  of the companies that DOE mentions in its letter prove to be able to  produce oil shale profitably and in an environmentally sensitive manner,  they will be among the first to overcome such long-standing challenges.  We are neither dismissing these companies, as DOE suggests, nor touting  their progress. In addition, it was beyond the scope of our report to  portray the timing of commercial oil shale production or describe a more  exhaustive history of oil shale research, as DOE had recommended,  because much research currently is privately funded and proprietary.  Therefore, we made no changes to the report in response to this comment.  DOE’s comments are reproduced in appendix IV.
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, Secretaries of the Interior and  Energy, Directors of the Bureau of Land Management and U.S. Geological  Survey, and other interested parties. In addition, the report will be  available at no charge on GAO’s Web site at http://www.gao.gov.
If you or your staff have any questions about this report, please contact  one of us at (202) 512-3841 or gaffiganm@gao.gov or mittala@gao.gov.  Contact points for our Offices of Congressional Relations and Public  Affairs may be found on the last page of this report. Key contributors to  this report are listed in appendix V.
section_title: Appendix I: Scope and Methodology
paragraphs: To determine what is known about the potential impacts to groundwater  and surface water from commercial oil shale development, we reviewed  the Proposed Oil Shale and Tar Sands Resource Management Plan  Amendments to Address Land Use Allocations in Colorado, Utah, and  Wyoming and Final Programmatic Environmental Impact Statement  (PEIS) prepared by the Bureau of Land Management in September 2008.  We also reviewed environmental assessments prepared on Shell Oil’s plans  for in-situ development of its research, demonstration, and development  (RD&D) tracts in Colorado and on the Oil Shale Exploration Company’s  (OSEC) plan to mine oil shale on its RD&D tract in Utah because these  two companies have made the most progress toward developing in-situ  and mining technologies, respectively. In addition, we reviewed the Office  of Technology Assessment’s (OTA) 1980 report, An Assessment of Oil  Shale Technologies; the Rand Corporation’s 2005 report, Oil Shale  Development in the United States; and the Argonne National  Laboratory’s 2005 report, Potential Ground Water and Surface Water  Impacts from Oil Shale and Tar Sands Energy-Production Operations.  Because the PEIS was the most comprehensive of these documents, we  summarized impacts to groundwater and surface water quantity and  quality described within this document and noted that these impacts were  entirely qualitative in nature and that the magnitude of impacts was  indeterminate because the in-situ technologies have yet to be developed.  To confirm these observations and the completeness of impacts within the  PEIS, we contacted the Environmental Protection Agency, the Colorado  Division of Water Resources, the Colorado Water Conservation Board, the  Division of Water Quality within the Colorado Department of Public  Health and Environment, the Utah Division of Water Resources, the Utah  Division of Water Quality, and the Utah Division of Water Rights—all of  which have regulatory authority over some aspect of water resources. To  ensure that we identified the range of views on the potential impacts of oil  shale development on groundwater and surface water, we also contacted  the U.S. Geological Survey (USGS), the Colorado Geological Survey, the  Utah Geological Survey, industry representatives, water experts, and  numerous environmental groups for their views on the impacts of oil shale  on water resources. To assess the impacts of oil shale development on  aquatic resources, we reviewed the PEIS and contacted the Colorado  Division of Wildlife and the Utah Division of Wildlife Resources.
To determine what is known about the amount of water that may be  needed for commercial oil shale development, we searched the Internet  and relevant databases of periodicals using the words “oil shale” together  with “water use.” We also searched Web sites maintained by the Bureau of  Land Management (BLM), USGS, and the Department of Energy (DOE) for  information on oil shale and water use and interviewed officials at these  agencies to determine if there were additional studies that we had not  identified. We also checked references cited within the studies for other  studies. We limited the studies to those published in 1980 or after because  experts with whom we consulted either considered the studies published  before then to be adequately summarized in OTA’s 1980 report or to be too  old to be relevant. We included certain data within the OTA report because  some of the surface retort technologies are similar to technologies being  tested today. We did not consider verbal estimates of water needs unless  companies could provide more detailed information. The 17 studies that  we identified appear in table 7.
For further analysis, we divided the studies into two major groups—in-situ  extraction and mining with a surface retort. We dismissed a combination  of mining and in-situ extraction because most of these technologies are  more than 30 years old and generally considered to be infeasible today.  The single company that is pursuing such a combination of technologies  today—Red Leaf Resources— has not published detailed data on water  needs. After reviewing these studies, we found that most of the studies did  not examine water needs for the entire life cycle of oil shale development.  As such, we identified logical groups of activities based on descriptions  within the studies. We identified the following five groups of activities: (1)  extraction and retorting, (2) generating power, (3) upgrading shale oil, (4)  reclamation, and (5) population growth associated with oil shale  development. We did not include refining because we believe it is unlikely  that oil shale production will reach levels in the near- or midterm to justify  building a new refinery.
To characterize the water needs for the entire life cycle of oil shale  development, we identified within each study the water needs for each of  the five groups of activities. Except for OTA’s 1980 report, which is now 30  years old, we contacted the authors of each study and discussed the  estimates with them. If estimates within these studies were given for more  than one group of activities, we asked them to break down this estimate  into the individual groups when possible. We only considered further  analyzing water needs for groups of activities that were based on original  research so as not to count these estimates multiple times. For example,  original research on water needs for extraction and retorting may have  analyzed mine plans, estimated water needs for drilling wells, estimated  water needs for dust control, and discussed recycling of produced water.  Original research on water needs for population growth may have  discussed the number of workers immigrating to a region, their family size,  per capita water consumption, and the nature of housing required by  workers. On the other hand, estimates of water needs that were not based  on original research generally reported water needs for multiple groups of  activities in barrels of water per barrel of oil produced and cited someone  else’s work as the source for this number. We excluded several estimates  that seemed unlikely. For example, we eliminated a water estimate for  power generation that included building a nuclear power plant and water  estimates for population growth where it was assumed that people would  decrease their water consumption by over 50 percent. We also excluded  technologies developed prior to 1980 that are dissimilar to technologies  being considered by oil shale companies today. We checked mathematical  calculations and reviewed power requirements and the reasonableness of  associated water needs. For power estimates that did not include  associated water needs, we converted power needs into water needs using  480 gallons per megawatt hour of electricity produced by coal-fired, wet  recirculating thermoelectric plants and 180 gallons per megawatt hour of  electricity produced by gas-powered, combined cycle, wet recirculating  thermoelectric plants. Air-cooled systems consume almost no water for  cooling. Where appropriate, we also estimated shale oil recoveries based  the company’s estimated oil shale resources and estimated water needs for  rinsing retorted zones based on anticipated changes to the reservoir.
We converted water requirements to barrels of water needed per barrel of  oil produced. For those studies with water needs that met our criteria, we  tabulated water needs for each group of activities for both in-situ  production and mining with a surface retort. The results appear in tables 8  and 9. We estimated the total range of water needs for in-situ development  by summing the minimum estimates for each group of activities and by  summing the maximum estimates for the various groups of activities. We  did the same for mining with a surface retort. We also calculated the  average water needs for each group of activities.
To determine the extent to which water is likely to be available for  commercial oil shale development and its source, we compared the total  needs of an oil shale industry of various sizes to the amount of surface  water and groundwater that the states of Colorado and Utah estimate to be  physically and legally available, in light of future municipal and industrial  demand. We selected the sizes of an oil shale industry based on input from  industry and DOE. These are hypothetical sizes, and we do not imply that  an oil shale industry will grow to these sizes. The smallest size we selected  for an in-situ industry, 500,000 barrels of oil per day, is a likely size  identified by an oil shale company based on experience with the  development of the Canadian tar sands. The largest size of 2,500,000  barrels of oil per day is based on DOE projections. We based our smallest  size of a mining industry, 25,000 barrels of oil per day, on one-half of the  smallest scenario identified by URS in their work on water needs  contracted by the state of Colorado. We based our largest size of a mining  industry, 150,000 barrels of oil per day, on three projects each of 50,000  barrels of oil per day, which is a commonly cited size for a commercial oil  shale mining operation. We reviewed and analyzed two detailed water  studies commissioned by the state of Colorado to determine how much  water is available in Colorado, where it was available, and to what extent  demands will be placed on this water in the future. We also reviewed a  report prepared for the Colorado Water Conservation Board on future  water availability in the Colorado River. These studies were identified by  water experts at various Colorado state water agencies as the most  updated information on Colorado’s water supply and demand. To  determine the available water supply and the potential future demand in  the Uintah Basin, we reviewed and analyzed data in documents prepared  by the Utah Division of Water Resources. We also examined data on water  rights provided by the Utah Division of Water Rights and examined data  collected by Western Resource Advocates on oil shale water rights in  Colorado. In addition to reviewing these documents, we interviewed water  experts at the Bureau of Reclamation, USGS, Utah Division of Water  Rights, Utah Division of Water Resources, Utah Division of Water Quality,  Colorado Division of Natural Resources, Colorado Division of Water  Resources, Colorado River Water Conservation District, the Utah and  Colorado State Demographers, and municipal officials in the oil shale  resource area.
To identify federally funded research efforts to address the impacts of  commercial oil shale development on water resources, we interviewed  officials and reviewed information from offices or agencies within DOE  and the Department of the Interior (Interior). Within DOE, these offices  were the Office of Naval Petroleum and Oil Shale Reserves, the National  Energy Technology Laboratory, and other DOE offices with jurisdiction  over various national laboratories. Officials at these offices identified the  Idaho National Laboratory and the Los Alamos National Laboratory as  sponsoring or performing water-related oil shale research. In addition,  they identified experts at Argonne National Laboratory who worked on the  PEIS for BLM or who wrote reports on water and oil shale issues. Within  Interior, we contacted officials with BLM and the USGS. We asked officials  at all of the federal agencies and offices that were sponsoring federal  research to provide details on research that was water-related and to  provide costs for the water-related portions of these research projects. For  some projects, based on the nature of the research, we counted the entire  award as water-related. We identified 15 water-related oil shale research  projects. A detailed description of these projects is in appendix II. To  obtain additional details on the work performed under these research  projects, we interviewed officials with all the sponsoring organizations  and the performing organizations, including the Colorado School of Mines,  University of Utah, Utah Geological Survey, Idaho National Laboratory,  Los Alamos National Laboratory, Argonne National Laboratory, and the  USGS.
To assess additional needs for research and to evaluate any gaps between  research needs and the current research projects, we interviewed officials  with 14 organizations and four experts that are authors of studies or  reports we used in our analyses and that are recognized as having  extensive knowledge of oil shale and water issues. The names of the 14  organizations appear in table 10. These discussions involved officials with  all the federal offices either sponsoring or performing water-related oil  shale research and state agencies involved in regulating water resources.
section_title: Appendix II: Descriptions of Federally Funded Water-Related Oil Shale Research
paragraphs: Appendix II: Descriptions of Federally  Funded Water-Related Oil Shale Research $4,838,097 The University of Utah received four separate awards, each covering a broad array of oil shale  research over multiple years. The awards included some water-related work. Examples of projects  include (1) Meeting Data Needs to Perform a Water Impact Assessment for Oil Shale Development in  the Uintah and Piceance Basins, (2) Effect of Oil Shale Processing on Water Compositions, and ()  New Approaches to Treat Produced Water and Perform Water Availability Impact Assessments for  Oil Shale Development.
section_title: Appendix III: Comments from the Department of the Interior
section_title: Appendix IV: Comments from the Department of Energy
section_title: Appendix V: GAO Contacts and Staff Acknowledgments
subsections: section_title: GAO Contacts
section_title: Staff Acknowledgments
paragraphs: In addition to the individuals named above, Dan Haas (Assistant Director),  Ron Belak, Laura Hook, and Randy Jones made major contributions to this  report. Other individuals who made significant contributions were Charles  Bausell, Virginia Chanley, Alison O’Neill, Madhav Panwar, and Barbara  Timmerman.