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1,400 | or 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 o |
1,401 | il 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 result |
1,402 | s 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—b |
1,403 | y 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. E |
1,404 | stimates 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 compani |
1,405 | es, 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 t |
1,406 | o 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. 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, an |
1,407 | d 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 ad |
1,408 | ditional water needs for the protection of threatened and endangered fishes, may eventually limit the size of a future oil shale industry. 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 env |
1,409 | ironmental 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. Similar |
1,410 | ly, 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 Reso |
1,411 | urces 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 condition |
1,412 | al 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 |
1,413 | 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 |
1,414 | 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 |
1,415 | 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. 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, |
1,416 | 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 Yamp |
1,417 | a 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 5 |
1,418 | 0 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 resour |
1,419 | ce 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 Colora |
1,420 | do 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 of |
1,421 | ficials 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 natura |
1,422 | l 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 |
1,423 | viewed as being groundwater, but it is unclear as to how it would be regulated. 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 popul |
1,424 | ation 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 correlat |
1,425 | ive 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 in |
1,426 | terests 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 |
1,427 | 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. Becau |
1,428 | se 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 |
1,429 | 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 beca |
1,430 | use 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 int |
1,431 | erstate 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 overestima |
1,432 | ting 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 Spe |
1,433 | cies 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 |
1,434 | 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. Although oil shale companies own rights to a large amount of water in the oil shal |
1,435 | e 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 |
1,436 | 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 |
1,437 | 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 i |
1,438 | ndustry 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. Furthermo |
1,439 | re, 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 al |
1,440 | l 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 Riv |
1,441 | er. 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 |
1,442 | 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 |
1,443 | 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 o |
1,444 | il 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 |
1,445 | 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 beca |
1,446 | use 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 thes |
1,447 | e 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 curren |
1,448 | tly 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 summ |
1,449 | ary 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 |
1,450 | 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. 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 |
1,451 | 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 wat |
1,452 | er 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. 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 Petr |
1,453 | oleum 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 works |
1,454 | hops, 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 |
1,455 | 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, an |
1,456 | d 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 res |
1,457 | earch 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 L |
1,458 | aboratory 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 |
1,459 | 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 |
1,460 | 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 t |
1,461 | hat 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. 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 com |
1,462 | panies, 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 moni |
1,463 | tor 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. 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 envi |
1,464 | ronmental 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 consid |
1,465 | eration 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 r |
1,466 | ecommendations 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 monitori |
1,467 | ng 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, |
1,468 | 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 perform |
1,469 | ing 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 |
1,470 | 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 thes |
1,471 | e 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 |
1,472 | 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 o |
1,473 | fficials 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 in |
1,474 | teractions 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 geolo |
1,475 | gic and hydrologic models and to study how quickly groundwater migrates. These tools will aid in monitoring and providing data that does not currently exist. 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 staf |
1,476 | f 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-r |
1,477 | elated 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 wate |
1,478 | r 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 coo |
1,479 | rdination 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 20 |
1,480 | 07, 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 in |
1,481 | formed 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 res |
1,482 | earch outcomes. 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 g |
1,483 | roundwater 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 |
1,484 | 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 |
1,485 | 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 |
1,486 | 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. To prepare for possible |
1,487 | 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 Forma |
1,488 | tion; 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 |
1,489 | results. 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 recom |
1,490 | mendation 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 undersco |
1,491 | red 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 t |
1,492 | o 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 to |
1,493 | ok 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 Unconventio |
1,494 | nal 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 recommendat |
1,495 | ion. 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 reput |
1,496 | able 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 sc |
1,497 | alable 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. How |
1,498 | ever, 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 |
1,499 | 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 m |
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