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1,300 | cessary concern and confusion. Second, a surfeit of notices, resulting from notification criteria that are too strict, could render all such notices less effective, because consumers could become numb to them and fail to act when risks are truly significant. Finally, the costs to both individuals and business are t too not insignificant and may be worth considering. FTC points out that, in response to a security breach notification, a consumer may ca credit cards, contact credit bureaus to place fraud alert |
1,301 | s on credit files, or obtain a new driver’s license number. These actions cou ld panies be time-consuming for the individual and costly for the com involved. Given these potential negative effects, care is clearly needed in defining appropriate criteria for required breach notifications. Once a determination has been made that a public notice is to be issued, care must be taken to ensure that it does its job effectively. Designing useful, easy-to-understand notices has been cited a in other areas where priv |
1,302 | acy notices are required by law, challenge such as in the financial industry—where businesses are required by the Gramm-Leach-Bliley Act to send notices to consumers ab out their privacy practices—and in the federal government, which is required by the Privacy Act to issue public notices in the Federal Register about its systems of records containing personal information. For example, as noted during a public workshop hosted by the Department of Homeland Security’s Privacy Office, designing easy-to-understa |
1,303 | nd consumer financial privacy notices to meet Gramm-Leach Bliley Act requirements has been challenging Officials from the FTC and Office of the Comptroller of the Currency described widespread criticism of these notices—that t were unexpected, too long, filled with legalese, and not understandable. . If an agency is to notify people of a data breach, it should do so in such a way that they understand the nature of the threat and what steps need to be taken to protect themselves against identity theft. In co |
1,304 | nnection with its state law requiring security breach notifications, the California Office of Privacy Protection has published recommended practices for designing and issuing security breach notices. The office recommends that such notifications include, among other things, a general description of what happened; the type of personal information that was involved; what steps have been taken to prevent further unauthorized acquisition of personal information; the types of assistance to be p free contact tele |
1,305 | phone number for additional information and assistance; rovided to individuals, such as a toll- information on what individuals can do to protect th identity theft, including contact information for the three cred reporting agencies; and it information on where individuals can obtain additional information on protection against identity theft, such as the Federal Trade Commission’s Identity Theft Web site (www.consumer.gov/idtheft). The California Office of Privacy Protection also recommends making notices |
1,306 | clear, conspicuous, and helpful by using clear, simple language and avoiding jargon, and it suggests avoiding using a standardized format to mitigate the risk that the public will become complacent about the process. The Federal Trade Commission has issued guidance to businesses on notifying individuals of data breaches that reiterates several key elements of effective notification—describing clearly what is known about the data compromise, explaining what responses may be appropriate for the type of inform |
1,307 | ation taken, and providing information and contacts regarding identity theft in general. The Commission also suggests providing contact information for the law enforcement officer working on the case, as well as encouraging individuals who discover that their information has been misused to file a complaint with the Commission. Both the state of California and the Federal Trade Commission recommend consulting with cognizant law-enforcement officers about an incident before issuing notices to the public. In |
1,308 | some cases, early notification or disclosure of certain facts about an incident could hamper a law enforcement investigation. For example, an otherwise unknowing thief could learn of the potential value of data stored on a laptop computer that was originally stolen purely for the value of the hardware. Thus it is recommended tha organizations consult with law enforcement regarding the timing and content of notifications. However, law enforcement investigations should not necessarily result in lengthy delays |
1,309 | in notification. California’s guidance states that it should not be necessary for a law enforcement agency to complete an investigation before notification can be given. t When providing notifications to the public, organizations should consider how to ensure that these are easily understood. Various techniques have been suggested to promote comprehension, including the concept of “layering.” Layering involves providing only the most important summary facts up front—often in a graphical format—followed by |
1,310 | one or more lengthier, more narrative versions in order to ensure that all information is communicated that needs to be. Multilayering may be an option to achieving an easy-to-understand notice that is still complete. Similarly, providing context to the notice (explaining to consu why they are receiving the notice and what to do with it) has been found to promote comprehension, as did visual design elem such as a tabular format, large and legible fonts, appropriate space, and simple headings. Although these |
1,311 | techniques were developed for other kinds of notices, they can be applied to those informing the public of data breaches. For example, a multilayered security breach notice could include a brief description of the nature of the security breach, thepotential threat to victims of the incident, and measures to be taken to protect against identity theft. The notice could provide additional details about the incident as an attachment or by providing links to additional information. This would accomplish the pur |
1,312 | pose of communicating the key details in a brief format, while still providi ng complete information to those who require it. Given that people maybe adversely affected by a compromise of their personal information, it is critical that they fully understand the nature of the threat and the options they have to address it. In summary, the recent security breach at VA has highlighted the importance of implementing effective information security practices. Long-standing information security control weaknesses |
1,313 | at VA have placed its information systems and information, including personally identifiable information, at increased risk of misuse and unauthorized disclosure. Although VA has taken steps to mitigate previously reported weaknesses, it has not implemented a comprehensive, integrated information security program, which it needs in order to effectively manage risks on an ongoing basis. Much work remains to be done. Only through strong leadership, sustained management commitment and effort, disciplined proce |
1,314 | sses, and consistent oversight can VA address its persistent, long-standing control weaknesses. To reduce the likelihood of experiencing such breaches, agencies can take a number of actions that can help guard against the possibility that databases of personally identifiable information are inadvertently compromised: strategically, they should ensure that a robust information security program is in place and that PIAs are developed. More specific practical measures aimed at preventing inadvertent data breac |
1,315 | hes include limiting the collection of pe information, limiting data retention, limiting access to personal information and training personnel accordingly, and considering using technological controls such as encryption when data need to be stored on mobile devices. Nevertheless, data breaches can still occur at any time, and whe n they do, notification to the individuals affected and/or the public h clear benefits, allowing people the opportunity to take steps to dangers of identity theft. Care is protect |
1,316 | themselves against the needed in defining appropriate criteria if agencies are to be required to report security breaches to the public. Further, care is also needed to ensure that notices are useful and easy to understand, so that they are effective in alerting individuals to actions they may want to take to minimize the risk of identity theft. We have previously testified that as Congress considers legisla requiring agencies to notify individuals or the public about security tion breaches, it should ensur |
1,317 | e that specific criteria are defined for incidents that merit public notification. It may want to consider creating a two-tier reporting requirement, in which all security breaches are reported to OMB, and affected individuals are notifiedonly of incidents involving significant risk. Further, Congress should consider requiring OMB to provide guidance to agencies on how develop and issue security breach notices to the public. Mr. Chairman, this concludes our testimony today. We would be happy to answer any q |
1,318 | uestions you or other members of the committee may have. If you have any questions concerning this testimony, please contact Linda Koontz, Director, Information Management, at (202) 512-6240, [email protected], or Gregory Wilshusen, Director, Information Security, at (202) 512-6244, [email protected]. Other individuals who made key contributions include Idris Adjerid, Barbara Collier, William Cook, John de Ferrari, Valerie Hopkins, Suzanne Lightman, Barbara Oliver, David Plocher, Jamie Pressman, J. Michael R |
1,319 | esser, and Charles Vrabel. Information Systems: VA Computer Control Weaknesses Increase Risk of Fraud, Misuse, and Improper Disclosure. GAO/AIMD-98- 175. Washington, D.C.: September 23, 1998. VA Information Systems: The Austin Automation Center Has Made Progress in Improving Information System Controls. GAO/AIMD-99-161. Washington, D.C.: June 8, 1999. Information Systems: The Status of Computer Security at the Department of Veterans Affairs. GAO/AIMD-00-5. Washington, D.C.: October 4, 1999. VA Systems Secur |
1,320 | ity: Information System Controls at the North Texas Health Care System. GAO/AIMD-00-52R. Washington, D.C.: February 1, 2000. VA Systems Security: Information System Controls at the New Mexico VA Health Care System. GAO/AIMD-00-88R. Washington, D.C.: March 24, 2000. VA Systems Security: Information System Controls at the VA Maryland Health Care System. GAO/AIMD-00-117R. Washington, D.C.: April 19, 2000. Information Technology: Update on VA Actions to Implement Critical Reforms. GAO/T-AIMD-00-74. Washington, |
1,321 | D.C.: May 11, 2000. VA Information Systems: Computer Security Weaknesses Persist at the Veterans Health Administration. GAO/AIMD-00-232. Washington, D.C.: September 8, 2000. Major Management Challenges and Program Risks: Department of Veterans Affairs. GAO-01-255. Washington, D.C.: January 2001. VA Information Technology: Important Initiatives Begun, Yet Serious Vulnerabilities Persist. GAO-01-550T. Washington, D.C.: April 4, 2001. VA Information Technology: Progress Made, but Continued Management Attention |
1,322 | is Key to Achieving Results. GAO-02-369T. Washington, D.C.: March 13, 2002. Veterans Affairs: Subcommittee Post-Hearing Questions Concerning the Department’s Management of Information Technology. GAO-02-561R. Washington, D.C.: April 5, 2002. Veterans Affairs: Sustained Management Attention is Key to Achieving Information Technology Results. GAO-02-703. Washington, D.C.: June 12, 2002. VA Information Technology: Management Making Important Progress in Addressing Key Challenges. GAO-02-1054T. Washington, D.C |
1,323 | .: September 26, 2002. Information Security: Weaknesses Persist at Federal Agencies Despite Progress Made in Implementing Related Statutory Requirements. GAO-05-552. Washington, D.C.: July 15, 2005. Privacy: Key Challenges Facing Federal Agencies. GAO-06-777T. Washington, D.C.: May 17, 2006. Personal Information: Agencies and Resellers Vary in Providing Privacy Protections. GAO-06-609T. Washington, D.C.: April 4, 2006. Personal Information: Agency and Reseller Adherence to Key Privacy Principles. GAO-06-421 |
1,324 | . Washington, D.C.: April 4, 2006. Data Mining: Agencies Have Taken Key Steps to Protect Privacy in Selected Efforts, but Significant Compliance Issues Remain. GAO- 05-866. Washington, D.C.: August 15, 2005. Aviation Security: Transportation Security Administration Did Not Fully Disclose Uses of Personal Information during Secure Flight Program Testing in Initial Privacy Notices, but Has Recently Taken Steps to More Fully Inform the Public. GAO-05- 864R. Washington, D.C.: July 22, 2005. Identity Theft: Some |
1,325 | Outreach Efforts to Promote Awareness of New Consumer Rights are Under Way. GAO-05-710. Washington, D.C.: June 30, 2005. Electronic Government: Federal Agencies Have Made Progress Implementing the E-Government Act of 2002. GAO-05-12. Washington, D.C.: December 10, 2004. Social Security Numbers: Governments Could Do More to Reduce Display in Public Records and on Identity Cards. GAO-05-59. Washington, D.C.: November 9, 2004. Federal Chief Information Officers: Responsibilities, Reporting Relationships, Tenu |
1,326 | re, and Challenges, GAO-04-823. Washington, D.C.: July 21, 2004. Data Mining: Federal Efforts Cover a Wide Range of Uses, GAO-04- 548. Washington, D.C.: May 4, 2004. Privacy Act: OMB Leadership Needed to Improve Agency Compliance. GAO-03-304. Washington, D.C.: June 30, 2003. Data Mining: Results and Challenges for Government Programs, Audits, and Investigations. GAO-03-591T. Washington, D.C.: March 25, 2003. Technology Assessment: Using Biometrics for Border Security. GAO-03-174. Washington, D.C.: November |
1,327 | 15, 2002. Information Management: Selected Agencies’ Handling of Personal Information. GAO-02-1058. Washington, D.C.: September 30, 2002. Identity Theft: Greater Awareness and Use of Existing Data Are Needed. GAO-02-766. Washington, D.C.: June 28, 2002. Social Security Numbers: Government Benefits from SSN Use but Could Provide Better Safeguards. GAO-02-352. Washington, D.C.: May 31, 2002. Full citations are provided in attachment 1. This is a work of the U.S. government and is not subject to copyright prot |
1,328 | ection in the United States. It may be reproduced and distributed in its entirety without further permission from GAO. However, because this work may contain copyrighted images or other material, permission from the copyright holder may be necessary if you wish to reproduce this material separately. |
1,329 | 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 |
1,330 | 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 |
1,331 | 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 |
1,332 | 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. Durin |
1,333 | g 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. S |
1,334 | ince 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 exten |
1,335 | t 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 |
1,336 | 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 wa |
1,337 | ter 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 un |
1,338 | der 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 |
1,339 | 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 |
1,340 | 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 |
1,341 | and Utah can be bought and sold, and strong demand for water in these western states facilitates their sale. 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 |
1,342 | 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 ho |
1,343 | les 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 thou |
1,344 | sands 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-scal |
1,345 | e 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 o |
1,346 | il 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. Fo |
1,347 | r 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 |
1,348 | 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, pipe |
1,349 | lines, 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 limitin |
1,350 | g 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. 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 technologi |
1,351 | es 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 t |
1,352 | he 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. The quantitative impacts of future oil shale development cannot be measured with reasonable certainty at this time primarily because of three un |
1,353 | knowns: (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 |
1,354 | 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 |
1,355 | 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 producti |
1,356 | on 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. Impacts to water resources from oil shale development would result primar |
1,357 | ily from disturbing the ground surface, withdrawing surface water and groundwater, underground mining, and discharging water from operations. 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, pi |
1,358 | pelines, 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 |
1,359 | 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 |
1,360 | 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 ca |
1,361 | n 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 |
1,362 | 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 pi |
1,363 | les 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 |
1,364 | 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. Withdrawing water from streams and rivers for oil shale operations could have temporary adverse impacts on surface water, according to |
1,365 | 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 tempora |
1,366 | rily 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, wh |
1,367 | ich 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 sprin |
1,368 | gs 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. Underground mining would permanently alter the properties of the zones that are mined, thereby affecting grou |
1,369 | ndwater 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 w |
1,370 | ould 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 |
1,371 | 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 n |
1,372 | ot 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 wa |
1,373 | ter 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. 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 |
1,374 | 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 in |
1,375 | to 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. 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 te |
1,376 | chnologies 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 mini |
1,377 | ng operations with a surface retort. 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, |
1,378 | 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 |
1,379 | , 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 reclamat |
1,380 | ion 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 tec |
1,381 | hnology, 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 us |
1,382 | e 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 produ |
1,383 | cing 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 isolate |
1,384 | d rural areas where oil shale is located, sufficiently skilled workers may not be available. 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 |
1,385 | 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 |
1,386 | 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 co |
1,387 | mprise 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 residu |
1,388 | al 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 n |
1,389 | eeded 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 |
1,390 | 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 |
1,391 | 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 hea |
1,392 | ters 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 curren |
1,393 | t 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 ge |
1,394 | nerating 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 |
1,395 | 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. Det |
1,396 | ailed 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 associ |
1,397 | ated 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 |
1,398 | and the maximum of each power type is due to water needed for reclamation. 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 diffe |
1,399 | rent 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 f |
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