This is the accessible text file for GAO report number GAO-11-35
entitled 'Energy-Water Nexus: A Better and Coordinated Understanding
of Water Resources Could Help Mitigate the Impacts of Potential Oil
Shale Development' which was released on November 29, 2010.
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Report to Congressional Requesters:
United States Government Accountability Office:
GAO:
October 2010:
Energy-Water Nexus:
A Better and Coordinated Understanding of Water Resources Could Help
Mitigate the Impacts of Potential Oil Shale Development:
GAO-11-35:
GAO Highlights:
Highlights of GAO-11-35, a report to congressional requesters.
Why GAO Did This Study:
Oil shale deposits in Colorado, Utah, and Wyoming are estimated to
contain up to 3 trillion barrels of oil—or an amount equal to the
world’s proven oil reserves. About 72 percent of this oil shale is
located beneath federal lands, making the federal government a key
player in its potential development. Extracting this oil is expected
to require substantial amounts of water and could impact groundwater
and surface water. GAO was asked to report on (1) what is known about
the potential impacts of oil shale development on surface water and
groundwater, (2) what is known about the amount of water that may be
needed for commercial oil shale development, (3) the extent to which
water will likely be available for commercial oil shale development
and its source, and (4) federal research efforts to address impacts to
water resources from commercial oil shale development. GAO examined
environmental impacts and water needs studies and talked to Department
of Energy (DOE), Department of the Interior (Interior), and industry
officials.
What GAO Found:
Oil shale development could have significant impacts on the quality
and quantity of water resources, but the magnitude of these impacts is
unknown because technologies are years from being commercially proven,
the size of a future oil shale industry is uncertain, and knowledge of
current water conditions and groundwater flow is limited. In the
absence of effective mitigation measures, water resources could be
impacted from ground disturbances caused by the construction of roads
and production facilities; withdrawing water from streams and aquifers
for oil shale operations, underground mining and extraction; and
discharging waters produced from or used in operations.
Estimates vary widely for the amount of water needed to commercially
produce oil shale primarily because of the unproven nature of some
technologies and because the various ways of generating power for
operations use differing quantities of water. GAO’s review of
available studies indicated that the expected total water needs for
the entire life cycle of oil shale production ranges from about 1
barrel (or 42 gallons) to 12 barrels of water per barrel of oil
produced from in-situ (underground heating) operations, with an
average of about 5 barrels, and from about 2 to 4 barrels of water per
barrel of oil produced from mining operations with surface heating.
Water is likely to be available for the initial development of an oil
shale industry, but the size of an industry in Colorado or Utah may
eventually be limited by water availability. Water limitations may
arise from increases in water demand from municipal and industrial
users, the potential of reduced water supplies from a warming climate,
fulfilling obligations under interstate water compacts, and the need
to provide additional water to protect threatened and endangered
fishes.
The federal government sponsors research on the impacts of oil shale
on water resources through DOE and Interior. DOE manages 13 projects
whose water-related costs total about $4.3 million, and Interior
sponsored two water-related projects, totaling about $500,000. Despite
this research, nearly all of the officials and experts that GAO
contacted said that there are insufficient data to understand baseline
conditions of water resources in the oil shale regions of Colorado and
Utah and that additional research is needed to understand the movement
of groundwater and its interaction with surface water. Federal agency
officials also said they seldom coordinate water-related oil shale
research among themselves or with state agencies that regulate water.
Most officials noted that agencies could benefit from such
coordination.
What GAO Recommends:
GAO recommends that Interior establish comprehensive baseline
conditions for water resources in oil shale regions of Colorado and
Utah, model regional groundwater movement, and coordinate on water-
related research with DOE and state agencies involved in water
regulation. Interior generally concurred with GAO’s recommendations.
View [hyperlink, http://www.gao.gov/products/GAO-11-35] or key
components. For more information, contact Mark Gaffigan or Anu Mittal
at (202) 512-3841 or gaffiganm@gao.gov or mittala@gao.gov.
[End of section]
Contents:
Letter:
Background:
Oil Shale Development Could Adversely Impact Water Resources, but the
Magnitude of These Impacts Is Unknown:
Estimates of Water Needs for Commercial Oil Shale Development Vary
Widely:
Water Is Likely to Be Available Initially from Local Sources, but the
Size of an Oil Shale Industry May Eventually Be Limited by Water
Availability:
Federal Research Efforts on the Impacts of Oil Shale Development on
Water Resources Do Not Provide Sufficient Data for Future Monitoring:
Conclusions:
Recommendations for Executive Action:
Agency Comments:
Appendix I: Scope and Methodology:
Appendix II: Descriptions of Federally Funded Water-Related Oil Shale
Research:
Appendix III: Comments from the Department of the Interior:
Appendix IV: Comments from the Department of Energy:
Appendix V: GAO Contacts and Staff Acknowledgments:
Tables:
Table 1: Estimated Barrels of Water Needed for Various Activities per
Barrel of Shale Oil Produced by In-Situ Operations:
Table 2: Estimated Barrels of Water Needed for Various Activities per
Barrel of Shale Oil Produced by Mining and Surface Retorting:
Table 3: Estimated Water Needs for Mining and Surface Retorting of Oil
Shale by Industries of Various Sizes:
Table 4: Estimated Water Needs for In-Situ Retorting of Oil Shale by
Industries of Various Sizes:
Table 5: Estimated Water That Will Be Physically and Legally Available
in the White River at Meeker, Colorado, in 2030:
Table 6: Federal Funding for Oil Shale Research Initiated Since June
2006:
Table 7: Studies on Water Use for Oil Shale Development Initially
Identified by GAO:
Table 8: Studies GAO Examined That Contained Original Research on
Water Requirements for Groups of Activities Representing the Complete
Life Cycle for the In-Situ Production of Oil Shale:
Table 9: Studies GAO Examined That Contained Original Research on
Water Requirements for Groups of Activities Representing the Complete
Life Cycle for an Oil Shale Mine with a Surface Retort:
Table 10: Agencies Contacted by GAO for Opinions on Research Needs:
Figures:
Figure 1: Location of Oil Shale Resources in Colorado and Utah:
Figure 2: Typical View in the Piceance Basin of Colorado:
Figure 3: Shell's Experimental In-Situ Site in Colorado:
Figure 4: Estimated Total Barrels of Water Needed per Barrel of Shale
Oil Produced by In-Situ Extraction, According to Source of Power
Generation:
Figure 5: Surface Retort near Rifle, Colorado:
Figure 6: Estimated Total Barrels of Water Needed per Barrel of Shale
Oil Produced by Mining and Surface Retorting, According to Source of
Power Generation:
Figure 7: Location of Rivers near Oil Shale Resources:
Figure 8: White River near Meeker, Colorado:
Abbreviations:
BLM: Bureau of Land Management:
BOR: Bureau of Reclamation:
DOE: Department of Energy:
EIS: environmental impact statement:
EPA: Environmental Protection Agency:
INL: Idaho National Laboratory:
Interior: Department of the Interior:
NEPA: National Environmental Policy Act:
NETL: National Energy Technology Laboratory:
OSEC: Oil Shale Exploration Company:
OTA: Office of Technology Assessment:
PEIS: programmatic environmental impact statement:
RD&D: research, development, and demonstration:
USGS: U.S. Geological Survey:
[End of section]
United States Government Accountability Office:
Washington, DC 20548:
October 29, 2010:
The Honorable Bart Gordon:
Chairman:
Committee on Science and Technology:
House of Representatives:
The Honorable Brian N. Baird:
Chairman:
Subcommittee on Energy and Environment:
Committee on Science and Technology:
House of Representatives:
Being able to tap the vast amounts of oil locked within U.S. oil shale
could go a long way toward satisfying the nation's future oil demands.
Oil shale is a sedimentary rock containing solid organic material that
converts into a type of crude oil when heated. The Green River
Formation--an assemblage of over 1,000 feet of sedimentary rocks that
lie beneath parts of Colorado, Utah, and Wyoming--contains the world's
largest deposits of oil shale. The U.S. Geological Survey (USGS)
estimates that the Green River Formation contains about 3 trillion
barrels of oil, and about half of this may be recoverable, depending
on available technology and economic conditions.[Footnote 1] This is
an amount about equal to the entire world's proven oil reserves. The
thickest and richest oil shale within the Green River Formation exists
in the Piceance Basin of northwest Colorado and the Uintah Basin of
northeast Utah.
The federal government is in a unique position to influence the
development of oil shale because 72 percent of the oil shale within
the Green River Formation is beneath federal lands managed by the
Department of the Interior's (Interior) Bureau of Land Management
(BLM). The Department of Energy (DOE) has provided technological and
financial support for oil shale development, primarily through its
research and development efforts, but oil shale development has been
hampered by concerns over potential impacts on the environment,
technological challenges, and average oil prices that have been too
low to consistently justify investment. In particular, developing oil
shale and providing power for oil shale operations and other
activities will require large amounts of water--a resource that is
already in scarce supply in the arid West where an expanding
population is placing additional demands on water. Some analysts
project that large scale oil shale development within Colorado could
require more water than is currently supplied to over 1 million
residents of the Denver metro area and that water diverted for oil
shale operations would restrict agricultural and urban development.
The potential demand for water is further complicated by the past
decade of drought in the West and projections of a warming climate in
the future. While there are also other concerns over the impacts from
oil shale development, such as impacts to air quality, wildlife, and
nearby communities, this report focuses on water impacts.
In response to your request, and building on our two recent reports
examining the relationship between other forms of energy production
and water use,[Footnote 2] we examined (1) what is known about the
potential impacts of oil shale development on surface water and
groundwater, (2) what is known about the amount of water that may be
needed for the commercial development of oil shale, (3) the extent to
which water will likely be available for commercial oil shale
development and its source, and (4) federal research efforts to
address impacts on water resources from commercial oil shale
development. Our report focuses on oil shale resources within the
Green River Formation in the Piceance Basin of northwest Colorado and
in the Uintah Basin of northeast Utah because these are the areas in
the United States in which the industry is most interested in pursuing
oil shale development due to the great thickness and richness of the
deposits.
To determine what is known about the potential impacts to surface
water and groundwater from commercial oil shale development, we
reviewed an environmental impact statement on oil shale development
prepared by BLM and various studies from private and public groups. We
discussed the completeness and accuracy of these studies in interviews
with federal agency officials, state agency personnel involved in
regulating water quality and quantity, oil shale industry
representatives, and representatives of environmental groups. We also
visited oil shale demonstration projects in Colorado. To determine
what is known about the amount of water that may be needed for
commercial oil shale development, we conducted a comprehensive
literature search for studies on water needs, contacted the authors of
these studies, and assessed the reasonableness of their estimates. Our
review of the literature identified several groups of activities that
comprise the life cycle of oil shale production. We then tabulated the
water needs identified in each study for each group of activities and
expressed the total water needs for the life cycle as a range based on
these numbers. To determine the extent to which water is likely to be
available for commercial oil shale development and its source, we
compared the total needs reflected in this estimated range to the
amount of surface water and groundwater that is physically and legally
available in the immediate area and to the future demands of
municipalities and other industries as projected by federal and state
agencies.[Footnote 3] To review federal research efforts to address
the impacts of commercial oil shale development on water resources, we
interviewed officials at DOE, the USGS, BLM, and organizations
performing the research, including universities and national
laboratories, and collected and reviewed relevant documents describing
their research. We also discussed areas for future water research as
it relates to oil shale with 18 organizations--including the USGS,
BLM, the DOE National Energy Technology Laboratory, the DOE Office of
Naval Petroleum and Oil Shale Reserves, the U.S. Bureau of
Reclamation, three DOE national laboratories, four state regulatory
agencies in Colorado and Utah, three water experts, an industry
representative, and two universities performing research--to identify
gaps in current efforts.
We conducted this performance audit from September 2009 through
October 2010 in accordance with generally accepted government auditing
standards. These standards require that we plan and perform the audit
to obtain sufficient and appropriate evidence to provide a reasonable
basis for our findings and conclusions based on our audit objectives.
We believe that the evidence obtained provides such a reasonable basis
for our findings and conclusions based on our audit objectives.
Background:
Interest in oil shale as a domestic energy source has waxed and waned
since the early 1900s. In 1912, President Taft established an Office
of Naval and Petroleum Oil Shale Reserves, and between 1916 and 1924,
executive orders set aside federal land in three separate naval oil
shale reserves to ensure an emergency domestic supply of oil. The
Mineral Leasing Act of 1920 made petroleum and oil shale resources on
federal lands available for development under the terms of a mineral
lease, but large domestic oil discoveries soon after passage of the
act dampened interest in oil shale. Interest resumed at various points
during times of generally increasing oil prices. For example, the U.S.
Bureau of Mines developed an oil shale demonstration project beginning
in 1949 in Colorado, where it attempted to develop a process to
extract the oil. The 1970s' energy crises stimulated interest once
again, and DOE partnered with a number of energy companies, spawning a
host of demonstration projects. Private efforts to develop oil shale
stalled after 1982 when crude oil prices fell significantly, and the
federal government dropped financial support for ongoing demonstration
projects.
More recently, the Energy Policy Act of 2005 directed BLM to lease its
lands for oil shale research and development. In June 2005, BLM
initiated a leasing program for research, development, and
demonstration (RD&D) of oil shale recovery technologies. By early
2007, it granted six small RD&D leases: five in the Piceance Basin of
northwest Colorado and one in Uintah Basin of northeast Utah. The
location of oil shale resources in these two basins is shown in figure
1. The leases are for a 10-year period, and if the technologies are
proven commercially viable, the lessees can significantly expand the
size of the leases for commercial production into adjacent areas known
as preference right lease areas. The Energy Policy Act of 2005
directed BLM to develop a programmatic environmental impact statement
(PEIS) for a commercial oil shale leasing program. During the drafting
of the PEIS, however, BLM realized that, without proven commercial
technologies, it could not adequately assess the environmental impacts
of oil shale development and dropped from consideration the decision
to offer additional specific parcels for lease. Instead, the PEIS
analyzed making lands available for potential leasing and allowing
industry to express interest in lands to be leased. Environmental
groups then filed lawsuits, challenging various aspects of the PEIS
and the RD&D program. Since then, BLM has initiated another round of
oil shale RD&D leasing and is currently reviewing applications but has
not made any awards.
Figure 1: Location of Oil Shale Resources in Colorado and Utah:
[Refer to PDF for image: map]
The following is depicted on the map:
Extent of Green River Formation;
Most geologically prospective oil shale resource.
Source: Adopted from BLM.
[End of figure]
Stakeholders in the future development of oil shale are numerous and
include the federal government, state government agencies, the oil
shale industry, academic institutions, environmental groups, and
private citizens. Among federal agencies, BLM manages the land and the
oil shale beneath it and develops regulations for its development.
USGS describes the nature and extent of oil shale deposits and
collects and disseminates information on the nation's water resources.
DOE, through its various offices, national laboratories, and
arrangements with universities, advances energy technologies,
including oil shale technology. The Environmental Protection Agency
(EPA) sets standards for pollutants that could be released by oil
shale development and reviews environmental impact statements, such as
the PEIS. The Bureau of Reclamation (BOR) manages federally built
water projects that store and distribute water in 17 western states
and provides this water to users. BOR monitors the amount of water in
storage and the amount of water flowing in the major streams and
rivers, including the Colorado River, which flows through oil shale
country and feeds these projects. BOR provides its monitoring data to
federal and state agencies that are parties to three major federal,
state, and international agreements, that together with other federal
laws, court decisions, and agreements, govern how water within the
Colorado River and its tributaries is to be shared with Mexico and
among the states in which the river or its tributaries are located.
These three major agreements are the Colorado River Compact of 1922,
the Upper Colorado River Basin Compact of 1948, and the Mexican Water
Treaty of 1944.
The states of Colorado and Utah have regulatory responsibilities over
various activities that occur during oil shale development, including
activities that impact water. Through authority delegated by EPA under
the Clean Water Act, Colorado and Utah regulate discharges into
surface waters. Colorado and Utah also have authority over the use of
most water resources within their respective state boundaries. They
have established extensive legal and administrative systems for the
orderly use of water resources, granting water rights to individuals
and groups. Water rights in these states are not automatically
attached to the land upon which the water is located. Instead,
companies or individuals must apply to the state for a water right and
specify the amount of water to be used, its intended use, and the
specific point from where the water will be diverted for use, such as
a specific point on a river or stream. Utah approves the application
for a water right through an administrative process, and Colorado
approves the application for a water right through a court proceeding.
The date of the application establishes its priority--earlier
applicants have preferential entitlement to water over later
applicants if water availability decreases during a drought. These
earlier applicants are said to have senior water rights. When an
applicant puts a water right to beneficial use, it is referred to as
an absolute water right. Until the water is used, however, the
applicant is said to have a conditional water right. Even if the
applicant has not yet put the water to use, such as when the applicant
is waiting on the construction of a reservoir, the date of the
application still establishes priority. Water rights in both Colorado
and Utah can be bought and sold, and strong demand for water in these
western states facilitates their sale.
Challenges to Oil Shale Development:
A significant challenge to the development of oil shale lies in the
current technology to economically extract oil from oil shale. To
extract the oil, the rock needs to be heated to very high
temperatures--ranging from about 650 to 1,000 degrees Fahrenheit--in a
process known as retorting. Retorting can be accomplished primarily by
two methods. One method involves mining the oil shale, bringing it to
the surface, and heating it in a vessel known as a retort. Mining oil
shale and retorting it has been demonstrated in the United States and
is currently done to a limited extent in Estonia, China, and Brazil.
However, a commercial mining operation with surface retorts has never
been developed in the United States because the oil it produces
competes directly with conventional crude oil, which historically has
been less expensive to produce. The other method, known as an in-situ
process, involves drilling holes into the oil shale, inserting heaters
to heat the rock, and then collecting the oil as it is freed from the
rock. Some in-situ technologies have been demonstrated on very small
scales, but other technologies have yet to be proven, and none has
been shown to be economically or environmentally viable. Nevertheless,
according to some energy experts, the key to developing our country's
oil shale is the development of an in-situ process because most of the
richest oil shale is buried beneath hundreds to thousands of feet of
rock, making mining difficult or impossible. Additional economic
challenges include transporting the oil produced from oil shale to
refineries because pipelines and major highways are not prolific in
the remote areas where the oil shale is located and the large-scale
infrastructure that would be needed to supply power to heat oil shale
is lacking. In addition, average crude oil prices have been lower than
the threshold necessary to make oil shale development profitable over
time.
Large-scale oil shale development also brings socioeconomic impacts.
While there are obvious positive impacts such as the creation of jobs,
increase in wealth, and tax and royalty payments to governments, there
are also negative impacts to local communities. Oil shale development
can bring a sizeable influx of workers, who along with their families,
put additional stress on local infrastructure such as roads, housing,
municipal water systems, and schools. Development from expansion of
extractive industries, such as oil shale or oil and gas, has typically
followed a "boom and bust" cycle in the West, making planning for
growth difficult. Furthermore, traditional rural uses could be
replaced by the industrial development of the landscape, and tourism
that relies on natural resources, such as hunting, fishing, and
wildlife viewing, could be negatively impacted.
In addition to the technological, economic, and social challenges to
developing oil shale resources, there are a number of significant
environmental challenges. For example, construction and mining
activities can temporarily degrade air quality in local areas. There
can also be long-term regional increases in air pollutants from oil
shale processing, upgrading, pipelines, and the generation of
additional electricity. Pollutants, such as dust, nitrogen oxides, and
sulfur dioxide, can contribute to the formation of regional haze that
can affect adjacent wilderness areas, national parks, and national
monuments, which can have very strict air quality standards. Because
oil shale operations clear large surface areas of topsoil and
vegetation, some wildlife habitat will be lost. Important species
likely to be negatively impacted from loss of wildlife habitat include
mule deer, elk, sage grouse, and raptors. Noise from oil shale
operations, access roads, transmission lines, and pipelines can
further disturb wildlife and fragment their habitat. In addition,
visual resources in the area will be negatively impacted as people
generally consider large-scale industrial sites, pipelines, mines, and
areas cleared of vegetation to be visually unpleasant (see figure 2
for a typical view within the Piceance Basin). Environmental impacts
from oil shale development could be compounded by additional impacts
in the area resulting from coal mining, construction, and extensive
oil and gas development. Air quality and wildlife habitat appear to be
particularly susceptible to the cumulative affect of these impacts,
and according to some environmental experts, air quality impacts may
be the limiting factor for the development of a large oil shale
industry in the future. Lastly, the withdrawal of large quantities of
surface water for oil shale operations could negatively impact aquatic
life downstream of the oil shale development. Impacts to water
resources are discussed in detail in the next section of this report.
Figure 2: Typical View in the Piceance Basin of Colorado:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
Oil Shale Development Could Adversely Impact Water Resources, but the
Magnitude of These Impacts Is Unknown:
Oil shale development could have significant impacts on the quality
and quantity of surface and groundwater resources, but the magnitude
of these impacts is unknown because some technologies have yet to be
commercially proven, the size of a future oil shale industry is
uncertain, and knowledge of current water conditions and groundwater
flow is limited. Despite not being able to quantify the impacts from
oil shale development, hydrologists and engineers have been able to
determine the qualitative nature of impacts because other types of
mining, construction, and oil and gas development cause disturbances
similar to impacts expected from oil shale development. According to
these experts, in the absence of effective mitigation measures,
impacts from oil shale development to water resources could result
from disturbing the ground surface during the construction of roads
and production facilities, withdrawing water from streams and aquifers
[Footnote 4] for oil shale operations, underground mining and
extraction, and discharging waste waters from oil shale operations.
Quantitative Impacts of Oil Shale Development Cannot Be Measured at
This Time:
The quantitative impacts of future oil shale development cannot be
measured with reasonable certainty at this time primarily because of
three unknowns: (1) the unproven nature of in-situ technologies, (2)
the uncertain size of a future oil shale industry, and (3)
insufficient knowledge of current groundwater conditions. First,
geological maps suggest that most of the prospective oil shale in the
Uintah and Piceance Basins is more amenable to in-situ production
methods rather than mining because the oil shale lies buried beneath
hundreds to thousands of feet of rock. Studies have concluded that
much of this rock is generally too thick to be removed economically by
surface mining, and deep subsurface mines are likely to be costly and
may recover no more than 60 percent of the oil shale. Although several
companies have been working on the in-situ development of oil shale,
none of these processes has yet been shown to be commercially viable.
Most importantly, the extent of the impacts of in-situ retorting on
aquifers is unknown, and it is uncertain whether methods for
reclamation of the zones that are heated will be effective.[Footnote
5] Second, it is not possible to quantify impacts on water resources
with reasonable certainty because it is not yet possible to predict
how large an oil shale industry may develop. The size of the industry
would have a direct relationship to water impacts. Within the PEIS,
BLM has stated that the level and degree of the potential impacts of
oil shale development cannot be quantified because this would require
making many speculative assumptions regarding the potential of the oil
shale, unproven technologies, project size, and production levels.
Third, hydrologists at USGS and BLM state that not enough is known
about current surface water and groundwater conditions in the Piceance
and Uintah Basins. More specifically, comprehensive baseline
conditions for surface water and groundwater do not exist. Therefore,
without knowledge of current conditions, it is not possible to detect
changes in groundwater conditions, much less attribute changes to oil
shale development.
A Number of Impacts to Water Quality and Quantity Could Be Expected
from Oil Shale Development:
Impacts to water resources from oil shale development would result
primarily from disturbing the ground surface, withdrawing surface
water and groundwater, underground mining, and discharging water from
operations.
Ground Disturbances Could Degrade Surface Water Quality:
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.[Footnote 6] Both mining and the in-situ
production of oil shale are expected to involve clearing vegetation
and grading the surface for access roads, pipelines, production
facilities, buildings, and power lines. In addition, the surface that
overlies the oil shale would need to be cleared and graded in
preparation for mining or drilling boreholes for in-situ extraction.
The freshly cleared and graded surfaces would then be exposed to
precipitation, and subsequent runoff would drain downhill toward
existing gullies and streams. If not properly contained or diverted
away from these streams, this runoff could contribute sediment, salts,
and possibly chemicals or oil shale products into the nearby streams,
degrading their water quality. Surface mining would expose the entire
area overlying the oil shale that is to be mined while subsurface
mining would expose less surface area and thereby contribute less
runoff. One in-situ operation proposed by Shell for its RD&D leases
would require clearing of the entire surface overlying the oil shale
because wells are planned to be drilled as close as 10 feet apart.
Other in-situ operations, like those proposed by American Shale Oil
Company and ExxonMobil, envision directionally drilling wells in rows
that are far enough apart so that strips of undisturbed ground would
remain.[Footnote 7] The adverse impacts from ground disturbances would
remain until exposed surfaces were properly revegetated.
If runoff containing excessive sediment, salts, or chemicals finds its
way into streams, aquatic resources could be adversely impacted,
according to the water experts to whom we spoke and the literature we
reviewed. Although aquatic populations can handle short-term increases
in sediment, long-term increases could severely impact plant and
animal life. Sediment could suffocate aquatic plants and decrease the
photosynthetic activity of these plants. Sediment could also suffocate
invertebrates, fish, and incubating fish eggs and adversely affect the
feeding efficiency and spawning success of fish. Sedimentation would
be exacerbated if oil shale activities destroy riparian vegetation
because these plants often trap sediment, preventing it from entering
streams. In addition, toxic substances derived from spills, leaks from
pipelines, or leaching of waste rock piles could increase mortality
among invertebrates and fish.
Surface and underground mining of oil shale will produce waste rock
that, according to the literature we reviewed and water experts to
whom we spoke, could contaminate surface waters. Mined rock that is
retorted on site would produce large quantities of spent shale after
the oil is extracted. Such spent shale is generally stored in large
piles that would also be exposed to surface runoff that could possibly
transport sediment, salts, selenium, metals, and residual hydrocarbons
into receiving streams unless properly stabilized and reclaimed. EPA
studies have shown that water percolating through such spent shale
piles transports pollutants long after abandonment of operations if
not properly mitigated. In addition to stabilizing and revegetating
these piles, mitigation measures could involve diverting runoff into
retention ponds, where it could be treated, and lining the surface
below waste rock with impervious materials that could prevent water
from percolating downward and transporting pollutants into shallow
groundwater. However, if improperly constructed, retention ponds would
not prevent the degradation of shallow groundwater, and some experts
question whether the impervious materials would hold up over time.
Withdrawing Water for Oil Shale Operations Could Adversely Impact
Surface Water and Groundwater:
Withdrawing water from streams and rivers for oil shale operations
could have temporary adverse impacts on surface water, according to
the experts to whom we spoke and the literature we reviewed. Oil shale
operations need water for a number of activities, including mining,
constructing facilities, drilling wells, generating electricity for
operations, and reclamation of disturbed sites. Water for most of
these activities is likely to come from nearby streams and rivers
because it is more easily accessible and less costly to obtain than
groundwater. Withdrawing water from streams and rivers would decrease
flows downstream and could temporarily degrade downstream water
quality by depositing sediment within the stream channels as flows
decrease. The resulting decrease in water would also make the stream
or river more susceptible to temperature changes--increases in the
summer and decreases in the winter. Elevated temperatures could have
adverse impacts on aquatic life, including fishes and invertebrates,
which need specific temperatures for proper reproduction and
development. Elevated water temperatures would also decrease dissolved
oxygen, which is needed by aquatic animals. Decreased flows could also
damage or destroy riparian vegetation. Removal of riparian vegetation
could exacerbate negative impacts on water temperature and oxygen
because such vegetation shades the water, keeping its temperature
cooler.
Similarly, withdrawing water from shallow aquifers--an alternative
water source--would have temporary adverse impacts on groundwater
resources. Withdrawals would lower water levels within these shallow
aquifers and the nearby streams and springs to which they are
connected. Extensive withdrawals could reduce groundwater discharge to
connected streams and springs, which in turn could damage or remove
riparian vegetation and aquatic life. Withdrawing water from deeper
aquifers could have longer-term impacts on groundwater and connected
streams and springs because replenishing these deeper aquifers with
precipitation generally takes longer.
Underground Mining and In-Situ Extraction Would Permanently Impact
Aquifers:
Underground mining would permanently alter the properties of the zones
that are mined, thereby affecting groundwater flow through these
zones, according to the literature we reviewed and the water experts
to whom we spoke. The process of removing oil shale from underground
mines would create large tunnels from which water would need to be
removed during mining operations. The removal of this water through
pumping would decrease water levels in shallow aquifers and decrease
flows to streams and springs that are connected. When mining
operations cease, the tunnels would most likely be filled with waste
rock, which would have a higher degree of porosity and permeability
than the original oil shale that was removed.[Footnote 8] Groundwater
flow through this material would increase permanently, and the
direction and pattern of flows could change permanently. Flows through
the abandoned tunnels could decrease ground water quality by
increasing concentrations of salts, metals, and hydrocarbons within
the groundwater.
In-situ extraction would also permanently alter aquifers because it
would heat the rock to temperatures that transform the solid organic
compounds within the rock into liquid hydrocarbons and gas that would
fracture the rock upon escape. Water would be cooked off during the
heating processes. Some in-situ operations envision using a barrier to
isolate thick zones of oil shale with intervening aquifers from any
adjacent aquifers and pumping out all the groundwater from this
isolated area before retorting.[Footnote 9] Other processes, like
those envisioned by ExxonMobil and AMSO, involve trying to target
thinner oil shale zones that do not have intervening aquifers and,
therefore, would theoretically not disturb the aquifers. However,
these processes involve fracturing the oil shale, and it is unclear
whether the fractures could connect the oil shale to adjacent
aquifers, possibly contaminating the aquifer with hydrocarbons. After
removal of hydrocarbons from retorted zones, the porosity and
permeability of the zones are expected to increase, thereby allowing
increased groundwater flow. Some companies propose rinsing retorted
zones with water to remove residual hydrocarbons. However, the
effectiveness of rinsing is unproven, and residual hydrocarbons,
metals, salts, and selenium that were mobilized during retorting could
contaminate the groundwater. Furthermore, the long-term effects of
groundwater flowing through retorted zones are unknown.
Discharge of Waste Waters from Operations Could Temporarily Impact
Downstream Waters:
The discharge of waste waters from operations would temporarily
increase water flows in receiving streams. According to BLM's PEIS,
waste waters from oil shale operations that could be discharged
include waters used in extraction, cooling, the production of
electricity, and sewage treatment, as well as drainage water collected
from spent oil shale piles and waters pumped from underground mines or
wells used to dewater the retorted zones. Discharges could decrease
the quality of downstream water if the discharged water is of lower
quality, has a higher temperature, or contains less oxygen. Lower-
quality water containing toxic substances could increase fish and
invertebrate mortality. Also, increased flow into receiving streams
could cause downstream erosion. However, at least one company is
planning to recycle waste water and water produced during operations
so that discharges and their impacts could be substantially reduced.
Estimates of Water Needs for Commercial Oil Shale Development Vary
Widely:
While commercial oil shale development requires water for numerous
activities throughout its life cycle, estimates vary widely for the
amount of water needed to commercially produce oil shale. This
variation in estimates stems primarily from the uncertainty associated
with reclamation technologies for in-situ oil shale development and
because of the various ways to generate power for oil shale
operations, which use different amounts of water. Based on our review
of available information for the life cycle of oil shale production,
existing estimates suggest that from about 1 to 12 barrels of water
could be needed for each barrel of oil produced from in-situ
operations, with an average of about 5 barrels. About 2 to 4 barrels
of water could be needed for each barrel of oil produced from mining
operations with a surface retort.[Footnote 10]
Oil Shale Development Requires Water throughout Its Life Cycle:
Water is needed for five distinct groups of activities that occur
during the life cycle of oil shale development: (1) extraction and
retorting, (2) upgrading of shale oil, (3) reclamation, (4) power
generation, and (5) population growth associated with oil shale
development.
* Extraction and retorting. During extraction and retorting, water is
used for building roads, constructing facilities, controlling dust,
mining and handling ore, drilling wells for in-situ extraction,
cooling of equipment and shale oil, producing steam, in-situ
fracturing of the retort zones, and preventing fire. Water is also
needed for on-site sanitary and potable uses.
* Upgrading of shale oil. Water is needed to upgrade, or improve, the
quality of the produced shale oil so that it can be easily transported
to a refinery. The degree to which the shale oil needs to be upgraded
varies according to the retort process. Shale oil produced by surface
retorting generally requires more upgrading, and therefore, more water
than shale oil produced from in-situ operations that heat the rock at
lower temperatures and for a longer time, producing higher-quality oil.
* Reclamation. During reclamation of mine sites, water is needed to
cool, compact, and stabilize the waste piles of retorted shale and to
revegetate disturbed surfaces, including the surfaces of the waste
piles. For in-situ operations, in addition to the typical revegetation
of disturbed surfaces, as shown in figure 3, water also will be needed
for reclamation of the subsurface retorted zones to remove residual
hydrocarbons. The volume of water that would be needed to rinse the
zones at present is uncertain and could be large, depending primarily
on how many times the zones need to be rinsed. In addition, some
companies envision reducing water demands for reclamation, as well as
for extracting, retorting, and upgrading, by recycling water produced
during oil shale operations or by treating and using water produced
from nearby oil and gas fields. Recycling technology, however, has not
been shown to be commercially viable for oil shale operations, and
there could be legal restrictions on using water produced from oil and
gas operations.[Footnote 11]
* Power generation. Water is also needed throughout the life cycle of
oil shale production for generating electricity from power plants
needed in operations. The amount of water used to produce this
electricity varies significantly according to generation and cooling
technologies employed. For example, thermoelectric power plants use a
heat source to make steam, which turns a turbine connected to a
generator that makes the electricity. The steam is captured and
cooled, often with additional water, and is condensed back into water
that is then recirculated through the system to generate more steam.
Plants that burn coal to produce steam use more water for cooling than
combined cycle natural gas plants, which combust natural gas to turn a
turbine and then capture the waste heat to produce steam that turns a
second turbine, thereby producing more electricity per gallon of
cooling water. Thermoelectric plants can also use air instead of water
to condense the steam. These plants use fans to cool the steam and
consume virtually no water, but are less efficient and more costly to
run.
* Population growth. Additional water would be needed to support an
anticipated increase in population due to oil shale workers and their
families who migrate into the area. This increase in population can
increase the demand for water for domestic uses. In isolated rural
areas where oil shale is located, sufficiently skilled workers may not
be available.
Figure 3: Shell's Experimental In-Situ Site in Colorado:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
Estimates of Water Needs for In-Situ Development Vary Significantly:
Based on studies that we reviewed, the total amount of water needed
for in-situ oil shale operations could vary widely, from about 1 to 12
barrels of water per barrel of oil produced over the entire life cycle
of oil shale operations. The average amount of water needed for in-
situ oil shale production as estimated by these studies is about 5
barrels. This range is based on information contained primarily in
studies published in 2008 and 2009 by ExxonMobil, Shell, the Center
for Oil Shale Technology and Research at the Colorado School of Mines,
the National Oil Shale Association, and contractors to the state of
Colorado.[Footnote 12] 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.[Footnote 13]
We calculated the minimum and the maximum amount of water that could
be needed for in-situ oil shale development by summing the minimum
estimates and the maximum estimates, respectively, for each group of
activities. Differences in estimates are due primarily to the
uncertainty in the amount of water needed for reclamation and to the
method of generating power for operations.
Table 1 shows the minimum, maximum, and average amounts of water that
could be needed for each of the five groups of activities that
comprise the life cycle of in-situ oil shale development. The table
shows that reclamation activities contribute the largest amount of
uncertainty to the range of total water needed for in-situ oil shale
operations. Reclamation activities, which have not yet been developed,
contribute from 0 to 5.5 barrels of water for each barrel of oil
produced, according to the studies we analyzed. This large range is
due primarily to the uncertainty in how much rinsing of retorted zones
would be necessary to remove residual hydrocarbons and return
groundwater to its original quality. On one end of the range,
scientists at ExxonMobil reported that retorted zones may be reclaimed
by rinsing them several times and using 1 barrel of water or less per
barrel of oil produced. However, another study suggests that many
rinses and many barrels of water may be necessary. For example,
modeling by the Center for Oil Shale Technology and Research suggests
that if the retorted zones require 8 or 10 rinses, 5.5 barrels of
water could be needed for each barrel of oil produced. Additional
uncertainty lies in estimating how much additional porosity in
retorted zones will be created and in need of rinsing. Some scientists
believe that the removal of oil will double the amount of pore space,
effectively doubling the amount of water needed for rinsing. Other
scientists question whether the newly created porosity will have
enough permeability so that it can be rinsed. Also, the efficiency of
recycling waste water that could be used for additional rinses adds to
the amount of uncertainty. For example, ExxonMobil scientists believe
that almost no new fresh water would be needed for reclamation if it
can recycle waste water produced from oil shale operations or treat
and use saline water produced from nearby oil and gas wells.
Table 1: Estimated Barrels of Water Needed for Various Activities per
Barrel of Shale Oil Produced by In-Situ Operations:
Activity: Extraction/retorting;
Minimum estimate: 0;
Average estimate: 0.7;
Maximum estimate: 1.0.
Activity: Upgrading liquids;
Minimum estimate: 0.6;
Average estimate: 0.9;
Maximum estimate: 1.6.
Activity: Power generation;
Minimum estimate: 0.1;
Average estimate: 1.5;
Maximum estimate: 3.4.
Activity: Reclamation;
Minimum estimate: 0;
Average estimate: 1.4;
Maximum estimate: 5.5.
Activity: Population growth;
Minimum estimate: 0.1;
Average estimate: 0.3;
Maximum estimate: 0.3.
Activity: Total;
Minimum estimate: 0.8;
Average estimate: 4.8;
Maximum estimate: 11.8.
Source: GAO analysis of selected studies.
Notes: GAO used from four to six studies to obtain the numbers for
each group of activities. See table 8 in appendix I to identify the
specific studies. The average for reclamation may be less useful
because estimates are either at the bottom or the top of this range.
[End of table]
Table 1 also shows that the water needs for generating power
contribute significant uncertainty to the estimates of total water
needed for in-situ extraction. Estimates of water needed to generate
electricity range from near zero for thermoelectric plants that are
cooled by air to about 3.4 barrels for coal-fired thermoelectric
plants that are cooled by water, according to the studies that we
analyzed. These studies suggested that from about 0.7 to about 1.2
barrels of water would be needed if electricity is generated from
combined cycle plants fueled by natural gas, depending on the power
requirements of the individual oil shale operation. Overall power
requirements are large for in-situ operations because of the many
electric heaters used to heat the oil shale over long periods of time--
up to several years for one technology proposed by industry. However,
ExxonMobil, Shell, and AMEC--a contractor to the state of Colorado--
believe that an oil shale industry of significant size will not use
coal-fired electric power because of its greater water requirements
and higher carbon dioxide emissions. In fact, according to an AMEC
study, estimates for power requirements of a 1.5 million-barrel-per-
day oil shale industry would exceed the current coal-fired generating
capacity of the nearest plant by about 12 times, and therefore would
not be feasible.[Footnote 14] Industry representatives with whom we
spoke said that it is more likely that a large oil shale industry
would rely on natural gas-powered combined cycle thermoelectric
plants, with the gas coming from gas fields within the Piceance and
Uintah Basins or from gas produced during the retort process.
ExxonMobil reports that it envisions cooling such plants with air,
thereby using next to no water for generating electricity. However,
cooling with air can be more costly and will ultimately require more
electricity.
In addition, table 1 shows that extracting and retorting activities
and upgrading activities also contribute to the uncertainty in the
estimates of water needed for in-situ operations, but this uncertainty
is significantly less than that of reclamation activities or power
generation. The range for extraction and retorting is from 0 to 1
barrel of water. The range for upgrading the produced oil is from 0.6
to 1.6 barrels of water, with both the minimum and maximum of this
range cited in a National Oil Shale Association study.[Footnote 15]
Hence, each of these two groups of activities contribute about 1
barrel of water to the range of estimates for the total amount of
water needed for the life cycle of in-situ oil shale production. Last,
table 1 shows there is little variation in the likely estimates of
water needed to support the anticipated population increase associated
with in-situ oil shale development. Detailed analyses of water needs
for population growth associated with an oil shale industry are
present in the PEIS, a study by the URS Corporation, and a study
completed by the Institute for Clean and Secure Energy at the
University of Utah. These estimates often considered the number of
workers expected to move into the area, the size of the families to
which these workers belong, the ratio of single-family to multifamily
housing that would accommodate these families, and per capita water
consumption associated with occupants of different housing types.
Figure 4 compares the total water needs over the life cycle of in-situ
oil shale development according to the various sources of power
generation, as suggested by the studies we reviewed. This is a
convenient way to visualize the water needs according to power source.
The minimum, average, and maximum values are the sum of the minimum,
average, and maximum water needs, respectively, for all five groups of
activities. Most of the difference between the minimum and the maximum
of each power type is due to water needed for reclamation.
Figure 4: Estimated Total Barrels of Water Needed per Barrel of Shale
Oil Produced by In-Situ Extraction, According to Source of Power
Generation:
[Refer to PDF for image: vertical bar graph]
Mining: Air cooled;
Minimum: 0.9;
Average: 3.3;
Maximum: 8.5.
Mining: Combined cycle, natural gas;
Minimum: 1.5;
Average: 4.2;
Maximum: 9.6.
Mining: Coal-fired;
Minimum: 3.9;
Average: 6.4;
Maximum: 11.8.
Source: GAO analysis of selected studies.
[End of figure]
Estimates of Water Needs for Mining and Surface Retorting Vary but Not
as Much as the In-Situ Process:
Estimates of water needed for mining oil shale and retorting it at the
surface vary from about 2 to 4 barrels of water per barrel of oil
produced over the entire life cycle of oil shale operations. The
average is about 3 barrels of water. This range is based primarily on
information obtained through a survey of active oil shale companies
completed by the National Oil Shale Association in 2009 and
information obtained from three different retorts, as published in a
report by the Office of Technology Assessment (OTA) in 1980.[Footnote
16] 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.
[Footnote 17] We calculated the minimum and the maximum amount of
water that could be needed for mining oil shale by summing the minimum
estimates and the maximum estimates, respectively, for each group of
activities. The range of water estimates for mining oil shale is far
narrower than that of in-situ oil shale production because, according
to the studies we reviewed, there are no large differences in water
estimates for any of the activities.
Figure 5: Surface Retort near Rifle, Colorado:
[Refer to PDF for image: photograph]
Source: Shale Technologies, LLC.
[End of figure]
Table 2 shows the minimum, maximum, and average amounts of water that
could be needed for each of the groups of activities that comprise the
life cycle of oil shale development that relies upon mining and
surface retorting. Unlike for in-situ production, we could not
segregate extraction and retorting activities from upgrading
activities because these activities were grouped together in some of
the studies on mining and surface retorting. Nonetheless, as shown in
table 2, the combination of these activities contributes 1 barrel of
water to the total range of estimated water needed for the mining and
surface retorting of oil shale. This 1 barrel of water results
primarily from the degree to which the resulting shale oil would need
upgrading. An oil shale company representative told us that estimates
for upgrading shale oil vary due to the quality of the shale oil
produced during the retort process, with higher grades of shale oil
needing less processing. Studies in the OTA report did not indicate
much variability in water needs for the mining of the oil shale and
the handling of ore. Retorts also produce water--about half a barrel
for each barrel of oil produced--by freeing water that is locked in
organic compounds and minerals within the oil shale. Studies in the
OTA report took this produced water into consideration and reported
the net anticipated water use.
Table 2: Estimated Barrels of Water Needed for Various Activities per
Barrel of Shale Oil Produced by Mining and Surface Retorting:
Activity: Extraction/retorting and upgrading liquids;
Minimum estimate: 0.9;
Average estimate: 1.5;
Maximum estimate: 1.9.
Activity: Power generation;
Minimum estimate: 0;
Average estimate: 0.3;
Maximum estimate: 0.9.
Activity: Reclamation;
Minimum estimate: 0.6;
Average estimate: 0.7;
Maximum estimate: 0.8.
Activity: Population growth;
Minimum estimate: 0.3;
Average estimate: 0.3;
Maximum estimate: 0.4.
Activity: Total;
Minimum estimate: 1.8;
Average estimate: 2.8;
Maximum estimate: 4.0.
Source: GAO analysis of selected studies.
Note: GAO used from three to six studies to obtain the numbers for
each group of activities. See table 9 in appendix I to identify the
specific studies.
[End of table]
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.[Footnote 18] Estimates of water
needed range from zero barrels for electricity coming from
thermoelectric plants that are cooled by air to about 0.9 barrels for
coal-fired thermoelectric plants that are cooled with water. About 0.3
barrels of water are needed to generate electricity from combined
cycle plants fueled by natural gas. Startup oil shale mining
operations, which have low overall power requirements, are more likely
to use electricity from coal-fired power plants, according to data
supplied by oil shale companies, because such generating capacity is
available locally. However, a large-scale industry may generate
electricity from the abundant natural gas in the area or from gas that
is produced during the retorting of oil shale. Water needs for
reclamation or for supporting an anticipated increase in population
associated with mining oil shale show little variability in the
studies that we reviewed.
Figure 6 compares the total water needs over the life cycle of mining
and surface retorting of oil shale according to the various sources of
power generation. The minimum, average, and maximum values are the sum
of the minimum, average, and maximum water needs, respectively, for
all five groups of activities.
Figure 6: Estimated Total Barrels of Water Needed per Barrel of Shale
Oil Produced by Mining and Surface Retorting, According to Source of
Power Generation:
[Refer to PDF for image: vertical bar graph]
Mining: Air cooled;
Minimum: 1.8;
Average: 2.6;
Maximum: 3.1.
Mining: Combined cycle, natural gas;
Minimum: 2.0;
Average: 2.8;
Maximum: 3.4.
Mining: Coal-fired;
Minimum: 2.3;
Average: 3.3;
Maximum: 4.0.
Source: GAO analysis of selected studies.
[End of figure]
Water Is Likely to Be Available Initially from Local Sources, but the
Size of an Oil Shale Industry May Eventually Be Limited by Water
Availability:
Water is likely to be available for the initial development of an oil
shale industry, but the eventual size of the industry may be limited
by the availability of water and demands for water to meet other
needs. Oil shale companies operating in Colorado and Utah will need to
have water rights to develop oil shale, and representatives from all
of the companies with which we spoke are confident that they hold at
least enough water rights for their initial projects and will likely
be able to purchase more rights in the future. Sources of water for
oil shale will likely be surface water in the immediate area, such as
the White River, but groundwater could also be used. Nonetheless, the
possibility of competing municipal and industrial demands for future
water, a warming climate, future needs under existing compacts, and
additional water needs for the protection of threatened and endangered
fishes, may eventually limit the size of a future oil shale industry.
Oil Shale Companies Own Considerable Water Rights and Options Exist to
Obtain More:
Companies with interest in oil shale already hold significant water
rights in the Piceance Basin of Colorado, and representatives from all
of the companies with whom we spoke felt confident that they either
had or could obtain sufficient water rights to supply at least their
initial operations in the Piceance and Uintah Basins. Western Resource
Advocates, a nonprofit environmental law and policy organization,
conducted a study of water rights ownership in the Colorado and White
River Basins of Colorado and concluded that companies have significant
water rights in the area.[Footnote 19] For example, the study found
that Shell owns three conditional water rights[Footnote 20] 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.[Footnote 21] Similarly, the study found that ExxonMobil
owns conditional storage capacities of over 161,000 acre-feet on 17
proposed reservoirs in the area. In Utah, the Oil Shale Exploration
Company (OSEC), which owns an RD&D lease, has obtained a water right
on the White River that appears sufficient for reopening the White
River Mine and has cited the possibility of renewing an expired
agreement with the state of Utah for obtaining additional water from
shallow aquifers connected to the White River. Similarly, Red Leaf
Resources cites the possibility of drilling a water well on the state-
owned lands that it has leased for oil shale development.
In addition to exercising existing water rights and agreements, there
are other options for companies to obtain more water rights in the
future, according to state officials in Colorado and Utah. In
Colorado, companies can apply for additional water rights in the
Piceance Basin on the Yampa and White Rivers. Shell recently applied--
but subsequently withdrew the application--for conditional rights to
divert up to 375 cubic feet per second from the Yampa River for
storage in a proposed reservoir that would hold up to 45,000 acre-feet
for future oil shale development. In Utah, however, officials with the
State Engineer's office said that additional water rights are not
available, but that if companies want additional rights, they could
purchase them from other owners. Many people who are knowledgeable on
western water rights said that the owners of these rights in Utah and
Colorado would most likely be agricultural users, based on a history
of senior agricultural rights being sold to developers in Colorado.
For example, the Western Resource Advocates study identified that in
the area of the White River, ExxonMobil Corporation has acquired full
or partial ownership in absolute water rights on 31 irrigation ditches
from which the average amount of water diverted per year has exceeded
9,000 acre-feet.[Footnote 22] These absolute water rights have
appropriation dates ranging from 1883 through 1918 and are thus senior
to holders of many other water rights, but their use would need to be
changed from irrigation or agricultural to industrial in order to be
used for oil shale. Also, additional rights may be available in Utah
from other sources. According to state water officials in Utah, the
settlement of an ongoing legal dispute between the state and the Ute
Indian tribe could result in the tribe gaining rights to 105,000 acre-
feet per year in the Uintah Basin. These officials said that it is
possible that the tribe could lease the water rights to oil shale
companies. There are also two water conservancy districts that each
hold rights to tens of thousands of acre-feet per year of water in the
Uintah Basin that could be developed for any use as determined by the
districts, including for oil shale development.
Oil Shale Development Is Likely to Use Local Surface Water, but
Groundwater Could Also Be Used:
Most of the water needed for oil shale development is likely to come
first from surface flows, as groundwater is more costly to extract and
generally of poorer quality in the Piceance and Uintah Basins.
However, companies may use groundwater in the future should they
experience difficulties in obtaining rights to surface water.
Furthermore, water is likely to come initially from surface sources
immediately adjacent to development, such as the White River and its
tributaries that flow through the heart of oil shale country in
Colorado and Utah, because the cost of pumping water over long
distances and rugged terrain would be high, according to water
experts. Shell's attempt to obtain water from the more distant Yampa
River shows the importance of first securing nearby sources. In
relationship to the White River, the Yampa lies about 20 to 30 miles
farther north and at a lower elevation than Shell's RD&D leases.
Hence, additional costs would be necessary to transport and pump the
Yampa's water to a reservoir for storage and eventual use. Shell
withdrew its application citing the global economic downturn.[Footnote
23]
At least one company has considered obtaining surface water from the
even more distant Colorado River, about 30 to 50 miles to the south of
the RD&D leases where oil shale companies already hold considerable
water rights, but again, the costs of transporting and pumping water
would be greater. Although water for initial oil shale development in
Utah is also likely to come from the White River as indicated by
OSEC's interest, water experts have cited the Green River as a
potential water source. However, the longer distance and rugged
terrain is likely to be challenging. Figure 7 shows the locations of
the oil shale resource areas and their proximity to local surface
water sources.
Figure 7: Location of Rivers near Oil Shale Resources:
[Refer to PDF for image: map]
The following is depicted on the map:
Rivers near Oil Shale Resources:
Green River;
Yampa River:
White River;
Colorado River:
Extent of Green River Formation;
Most geologically prospective oil shale resource;
BLM preference right lease area;
BLM RD&D leases.
Source: Adopted from BLM.
[End of figure]
In addition to surface water, oil shale companies could use
groundwater for operations should more desirable surface water sources
be unavailable. However, companies would need to acquire the rights to
this groundwater. Shallow groundwater in the Piceance and Uintah
Basins occurs primarily within alluvial aquifers, which are aquifers
composed of unconsolidated sand and gravel associated with nearby
streams and rivers. The states of Utah and Colorado refer to these
aquifers legally as tributary waters, or waters that are connected to
surface waters and hence are considered to be part of the surface
water source when appropriating water rights. Any withdrawal of
tributary water is considered to be a withdrawal from the adjacent or
nearby stream or river. Less is known about deep groundwater in the
Piceance and Uintah Basins, but hydrologists consider it to be of
lesser quality, with the water generally becoming increasingly saline
with depth. State officials in Utah said that they consider this
deeper groundwater to be tributary water, and state officials in
Colorado said that they generally consider this deeper water also to
be tributary water but will allow water rights applicants to prove
otherwise. In the Piceance and Uintah Basins, groundwater is not
heavily used, illustrating the reluctance of water users to tap this
source. Nevertheless, Shell is considering the use of groundwater, and
ExxonMobil is considering using water co-produced with natural gas
from nearby but deeper formations in the Piceance Basin. Also, BLM
notes that there is considerable groundwater in the regional Bird's
Nest Aquifer in the area surrounding OSEC's RD&D lease in the Uintah
Basin. In addition, representatives of oil shale companies said they
plan to use water that is released from the organic components of oil
shale during the retort process. Since this water is chemically bound
within the solid organic components rather than being in a liquid
phase, it is not generally viewed as being groundwater, but it is
unclear as to how it would be regulated.
Oil Shale Development Will Likely Have to Compete with Increased
Demands for Water for Other Needs and a Decreased Water Supply:
Developing a sizable oil shale industry may take many years--perhaps
15 or 20 years by some industry and government estimates--and such an
industry may have to contend with increased demands for water to meet
other needs. Substantial population growth and its correlative demand
for water are expected in the oil shale regions of Colorado and Utah.
This region in Colorado is a fast-growing area. State officials expect
that the population within the region surrounding the Yampa, White,
and Green Rivers in Colorado will triple between 2005 and 2050. These
officials expect that this added population and corresponding economic
growth by 2030 will increase municipal and industrial demands for
water, exclusive of oil shale development, by about 22,000 acre-feet
per year, or a 76 percent increase from 2000. Similarly in Utah, state
officials expect the population of the Uintah Basin to more than
double its 1998 size by 2050 and that correlative municipal and
industrial water demands will increase by 7,000 acre-feet per year, or
an increase of about 30 percent since the mid-1990s. Municipal
officials in two communities adjacent to proposed oil shale
development in Colorado said that they were confident of meeting their
future municipal and industrial demands from their existing senior
water rights, and as such will probably not be affected by the water
needs of a future oil shale industry. However, large withdrawals could
impact agricultural interests and other downstream water users in both
states, as oil shale companies may purchase existing irrigation and
agricultural rights for their oil shale operations. State water
officials in Colorado told us that some holders of senior agricultural
rights have already sold their rights to oil shale companies.
Figure 8: White River near Meeker, Colorado:
[Refer to PDF for image: photograph]
Source: GAO.
[End of figure]
A future oil shale industry may also need to contend with a decreased
physical supply of water regionwide due to climate change. A
contractor to the state of Colorado ran five projections through a
number of climate models and found that their average result suggested
that by 2040, a warming climate may reduce the amount of water in the
White River in Colorado by about 13 percent, or 42,000 acre-feet.
However, there was much variability among the five results, ranging
from a 40 percent decrease to a 16 percent increase in today's flow
and demonstrating the uncertainty associated with climate predictions.
Nevertheless, any decrease would mean that less water would be
available downstream in Utah. Because of a warmer climate, the
contractor also found that water needed to irrigate crops could
increase significantly in the White River Basin, but it is uncertain
whether the holders of the water rights used to irrigate the crops
would be able to secure this additional water. Simultaneously, the
model shows that summer precipitation is expected to decrease, thus
putting pressure on farmers to withdraw even more water from local
waterways. In addition, the contractor predicted that more
precipitation is likely to fall as rain rather than snow in the early
winter and late spring. Because snow functions as a natural storage
reservoir by releasing water into streams and aquifers as temperatures
rise, less snow means that storage and runoff schedules will be
altered and less water may be available at different times of the
year. Although the model shows that the White River is expected to
have reduced flows due to climate change, the same model shows that
the Yampa is more likely to experience an increased flow because more
precipitation is expected to fall in the mountains, which are its
headwaters. Hence, oil shale companies may look to the Yampa for
additional water if restrictions on the White are too great,
regardless of increased costs to transport the water. While there is
not a similar study on climate change impacts for Utah, it is likely
that some of the impacts will be similar, considering the close
proximity and similar climates in the Uintah and Piceance Basins.
Colorado's and Utah's obligations under interstate compacts could
further reduce the amount of water available for development. The
Colorado River Compact of 1922, which prescribes how the states
through which the Colorado River and its tributaries flow share the
river's water, is based on uncharacteristically high flows, as cited
in a study contracted by the state of Colorado. Water regulators have
since shown that the flow rates used to allocate water under the
compact may be 21 percent higher than average historical flow rates,
thereby overestimating the amount of water that may be available to
share. As a result, the upstream states of Colorado and Utah may not
have as much water to use as they had originally planned and may be
forced to curtail water consumption so that they can deliver the
amount of water that was agreed on in the compact to the downstream
states of Arizona, Nevada, and California. Another possible limitation
on withdrawals from the Colorado River system is the requirement to
protect certain fish species under the Endangered Species Act. Federal
officials stated that withdrawals from the Colorado River system,
including its tributaries the White and Green Rivers, could be limited
by the amount of flow that is necessary to sustain populations of
threatened or endangered fishes. Although there are currently no
federally mandated minimum flow requirements on the White River in
either Utah or Colorado, the river is home to populations of the
federally endangered Colorado Pikeminnow, and the Upper Colorado
Recovery Program is currently working on a biological opinion which
may prescribe minimum flow requirements. In addition, the Green River
in Utah is home to populations of four threatened or endangered
fishes: the Colorado Pikeminnow, the Razorback Sucker, the Humpback
Chub, and the Bonytail Chub. For this reason, agency officials are
recommending minimum flow requirements on the Green, which could
further restrict the upstream supply of available water.
The Size of an Oil Shale Industry May Be Limited by Water Availability:
Although oil shale companies own rights to a large amount of water in
the oil shale regions of Colorado and Utah, there are physical and
legal limits on how much water they can ultimately withdraw from the
region's waterways, and thus limits on the eventual size of the
overall industry. Physical limits are set by the amount of water that
is present in the river, and the legal limit is the sum of the water
that can be legally withdrawn from the river as specified in the water
rights held by downstream users. Examining physical limits can
demonstrate how much water may be available to all water users.
Subtracting the legal limit can demonstrate how much water is
available for additional development, providing that current water
rights and uses do not change in the future. The state of Colorado
refers to this remaining amount of water in the river as that which is
physically and legally available.
To put the water needs of a potential oil shale industry in Colorado
into perspective, we compared the needs of oil shale industries of
various sizes to what currently is physically available in the White
River at Meeker, Colorado--a small town immediately east of high-
quality oil shale deposits in the Piceance Basin. We also compared the
water needs of an oil shale industry to what may be physically and
legally available from the White River in 2030. Table 3 shows
scenarios depicting the amounts of water that would be needed to
develop an oil shale industry of various sizes that relies on mining
and surface retorting, based on the studies we examined. Table 4 shows
similar scenarios for an oil shale industry that uses in-situ
extraction, based on the studies that we examined. The sizes are based
on industry and expert opinion and are not meant to be predictions.
Both tables assume water demands for peak oil shale production rates,
but water use may not follow such a pattern. For example, water use
for reclamation activities may not fully overlap with water use for
extraction. Also, an industry composed of multiple operations is
likely to have some operations at different stages of development.
Furthermore, because of the natural variability of stream flows, both
on an annual basis and from year-to-year, reservoirs would need to be
built to provide storage, which could be used to release a consistent
amount of water on a daily basis.
Table 3: Estimated Water Needs for Mining and Surface Retorting of Oil
Shale by Industries of Various Sizes:
Size of industry (barrels of oil per day): 25,000[D];
Minimum water needs (acre-feet per year)[A]: 2,400;
Average water needs (acre-feet per year)[B]: 3,500;
Maximum water needs (acre-feet per year)[C]: 4,700.
Size of industry (barrels of oil per day): 50,000[E];
Minimum water needs (acre-feet per year)[A]: 4,700;
Average water needs (acre-feet per year)[B]: 7,100;
Maximum water needs (acre-feet per year)[C]: 9,400.
Size of industry (barrels of oil per day): 75,000;
Minimum water needs (acre-feet per year)[A]: 7,100;
Average water needs (acre-feet per year)[B]: 10,600;
Maximum water needs (acre-feet per year)[C]: 14,100.
Size of industry (barrels of oil per day): 100,000;
Minimum water needs (acre-feet per year)[A]: 9,400;
Average water needs (acre-feet per year)[B]: 14,100;
Maximum water needs (acre-feet per year)[C]: 18,800.
Size of industry (barrels of oil per day): 150,000[F];
Minimum water needs (acre-feet per year)[A]: 14,100;
Average water needs (acre-feet per year)[B]: 21,200;
Maximum water needs (acre-feet per year)[C]: 28,200.
Source: GAO analysis of selected studies on water needs.
[A] This scenario assumes 2 barrels of water are needed to produce 1
barrel of shale oil. All figures are rounded to the nearest 100 acre-
feet.
[B] This scenario assumes 3 barrels of water are needed to produce 1
barrel of shale oil.
[C] This scenario assumes 4 barrels of water are needed to produce 1
barrel of shale oil.
[D] URS, the contractor to the state of Colorado, used this level as
the minimum size for a mining operation with a surface retort.
[E] Several literature sources and oil shale companies cite this level
as a reasonable commercial operation.
[F] GAO estimated industry size based on three operations of 50,000
barrels per day each.
[End of table]
Table 4: Estimated Water Needs for In-Situ Retorting of Oil Shale by
Industries of Various Sizes:
Size of industry (barrels of oil per day): 500,000[D];
Minimum water needs (acre-feet per year)[A]: 24,000;
Average water needs (acre-feet per year)[B]: 118,000;
Maximum water needs (acre-feet per year)[C]: 282,000.
Size of industry (barrels of oil per day): 1,000,000;
Minimum water needs (acre-feet per year)[A]: 47,000;
Average water needs (acre-feet per year)[B]: 235,000;
Maximum water needs (acre-feet per year)[C]: 565,000.
Size of industry (barrels of oil per day): 1,500,000;
Minimum water needs (acre-feet per year)[A]: 71,000;
Average water needs (acre-feet per year)[B]: 353,000;
Maximum water needs (acre-feet per year)[C]: 847,000.
Size of industry (barrels of oil per day): 2,000,000;
Minimum water needs (acre-feet per year)[A]: 94,000;
Average water needs (acre-feet per year)[B]: 470,000;
Maximum water needs (acre-feet per year)[C]: 1,129,000.
Size of industry (barrels of oil per day): 2,500,000[E];
Minimum water needs (acre-feet per year)[A]: 118,000;
Average water needs (acre-feet per year)[B]: 588,000;
Maximum water needs (acre-feet per year)[C]: 1,411,000.
Source: GAO analysis of selected studies on water needs.
[A] This scenario assumes 1 barrel of water is needed to produce 1
barrel of shale oil. All figures are rounded to the nearest 100 acre-
feet.
[B] This scenario assumes 5 barrels of water are needed to produce 1
barrel of shale oil.
[C] This scenario assumes 12 barrels of water are needed to produce 1
barrel of shale oil.
[D] One oil shale company with whom we spoke estimated that an oil
shale industry could grow to this level, based on analogy to oil sands
being developed in Alberta, Canada.
[E] DOE uses this level as the high end for its size estimates of an
oil shale industry.
[End of table]
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.[Footnote 24] Table 3
suggests that this is much more water than is needed to support the
water needs for all the sizes of an industry relying on mining and
surface retorting that we considered. Table 4, however, shows that an
industry that uses in-situ extraction could be limited just by the
amount of water physically available in the White River at Meeker,
Colorado. For example, based on an oil shale industry that uses about
12 barrels of water for each barrel of shale oil it produces, such an
industry could not reach 1 million barrels per day if it relied solely
on physically available water from the White River.
Comparing an oil shale industry's needs to what is physically and
legally available considers the needs of current users and the
anticipated needs of future users, rather than assuming all water in
the river is available to an oil shale industry. The amount of water
that is physically and legally available in the White River at Meeker
is depicted in table 5. According to the state of Colorado's computer
models, holders of water rights downstream use on average about
153,000 acre-feet per year, resulting in an average of about 319,000
acre-feet per year that is currently physically and legally available
for development near Meeker. By 2030, however, the amount of water
that is physically and legally available is expected to change because
of increased demand and decreased supply. After taking into account an
anticipated future decrease of 22,000 acre-feet per year of water due
to a growing population, about 297,000 acre-feet per year may be
available for future development if current water rights and uses do
not change by 2030. However, there may be additional decreases in the
amount of physically and legally available water in the White River
due to climate change, demands under interstate agreements, and water
requirements for threatened or endangered fishes, but we did not
include these changes in table 5 because of the large uncertainty
associated with estimates.
Table 5: Estimated Water That Will Be Physically and Legally Available
in the White River at Meeker, Colorado, in 2030:
Average historic flow, or water that is physically available today:
Acre-feet per year: 472,000.
Average water use by holders of downstream water rights:
Acre-feet per year: -153,000.
Average physically and legally available water today:
Acre-feet per year: 319,000.
Estimated increase in municipal and industrial use by 2030:
Acre-feet per year: -22,000.
Estimated physically and legally available supply in 2030:
Acre-feet per year: 297,000.
Source: GAO analysis of state of Colorado data.
[End of table]
Comparing the scenarios in table 4 to the amount of water that is
physically and legally available in table 5 shows the sizes that an in-
situ oil shale industry may reach relying solely on obtaining new
rights on the White River. The scenarios in table 4 suggest that if an
in-situ oil shale industry develops to where it produces 500,000
barrels of oil per day--an amount that some experts believe is
reasonable--an industry of this size could possibly develop in
Colorado even if it uses about 12 barrels of water per barrel of shale
oil it produces. Similarly, the scenarios suggest that an in-situ
industry that uses about 5 barrels of water per barrel of oil
produced--almost the average from the studies in which power comes
from combined cycle natural gas plants--could grow to 1 million
barrels of oil per day using only the water that appears to be
physically and legally available in 2030 in the White River. Table 4
also shows that an industry that uses just 1 barrel of water per
barrel of shale oil produced could grow to over 2.5 million barrels of
oil per day.
Regardless of these comparisons, more water or less water could be
available in the future because it is unlikely that water rights will
remain unchanged until 2030. For example, officials with the state of
Colorado reported that conditional water rights--those rights held but
not used--are not accounted for in the 297,000 acre-feet per year of
water that is physically and legally available because holders of
these rights are not currently withdrawing water. These officials also
said that the amount of conditional water rights greatly exceeds the
flow in the White River near Meeker, and if any of these conditional
rights are converted to absolute rights and additional water is then
withdrawn downstream, even less water will be available for future
development. However, officials with the state of Colorado said that
some of these conditional water rights are already owned by oil shale
companies, making it unnecessary for some companies to apply for new
water rights. In addition, they said, some of the absolute water
rights that are accounted for in the estimated 153,000 acre-feet per
year of water currently being withdrawn are already owned by oil shale
companies. These are agricultural rights that were purchased by oil
shale interests who leased them back to the original owners to
continue using them for agricultural purposes. Should water not be
available from the White River, companies would need to look to
groundwater or surface water outside of the immediate area.
There are less data available to predict future water supplies in
Utah's oil shale resource area. The state of Utah did not provide us
summary information on existing water rights held by oil shale
companies. According to the state of Colorado, the average annual
physical flow of the White River near the Colorado-Utah border is
about 510,000 acre-feet per year. Any amount withdrawn from the White
River in Colorado would be that much less water that would be
available for development downstream in Utah. The state of Utah
estimates that the total water supply of the Uintah Basin, less
downstream obligations under interstate compacts, is 688,000 acre-feet
per year.[Footnote 25] 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.
Federal Research Efforts on the Impacts of Oil Shale Development on
Water Resources Do Not Provide Sufficient Data for Future Monitoring:
Although the federal government sponsors research on the nexus between
oil shale development and water, a lack of comprehensive data on the
condition of surface water and groundwater and their interaction limit
efforts to monitor the future impacts of oil shale development.
Currently DOE funds some research related to oil shale and water
resources, including research on water rights, water needs, and the
impacts of oil shale development on water quality. Interior also
performs limited research on characterizing surface and groundwater
resources in oil shale areas and is planning some limited monitoring
of water resources. However, there is general agreement among those we
contacted--including state personnel who regulate water resources,
federal agency officials responsible for studying water, water
researchers, and water experts--that this ongoing research is
insufficient to monitor and then subsequently mitigate the potential
impacts of oil shale development on water resources. In addition, DOE
and Interior officials noted that they seldom formally share the
information on their water-related research with each other.
DOE Funds Research on Water Rights, Water Needs, and the Impacts of
Oil Shale Development on Water Resources:
DOE has sponsored most of the oil shale research that involves water-
related issues. This research consists of projects managed by the
National Energy Technology Laboratory (NETL), the Office of Naval
Petroleum and Oil Shale Reserves, and the Idaho National Laboratory.
As shown in table 6, DOE has sponsored 13 of 15 projects initiated by
the federal government since June 2006. DOE's projects account for
almost 90 percent of the estimated $5 million[Footnote 26] that is to
be spent by the federal government on water-related oil shale research
through 2013.[Footnote 27] Appendix II contains a list and description
of these projects.
Table 6: Federal Funding for Oil Shale Research Initiated Since June
2006:
Sponsoring office: DOE National Energy Technology Lab;
Number of oil shale research projects: 13;
Federal share of funding for all oil shale research projects:
$15,424,702;
Number of water-related projects: 7;
Federal share of funding for water-related projects: $2,433,097.
Sponsoring office: DOE Office of Naval Petroleum and Oil Shale
Reserves;
Number of oil shale research projects: 2;
Federal share of funding for all oil shale research projects:
$2,468,000;
Number of water-related projects: 2;
Federal share of funding for water-related projects: $920,000.
Sponsoring office: DOE Idaho National Lab;
Number of oil shale research projects: 5;
Federal share of funding for all oil shale research projects:
$3,012,500[A];
Number of water-related projects: 4;
Federal share of funding for water-related projects: $965,000[A].
Sponsoring office: BLM;
Number of oil shale research projects: 3;
Federal share of funding for all oil shale research projects: $535,000;
Number of water-related projects: 2;
Federal share of funding for water-related projects: $520,000.
Sponsoring office: USGS;
Number of oil shale research projects: 1;
Federal share of funding for all oil shale research projects:
$1,100,000;
Number of water-related projects: 0;
Federal share of funding for water-related projects: 0.
Sponsoring office: Total;
Number of oil shale research projects: 24;
Federal share of funding for all oil shale research projects:
$22,540,202;
Number of water-related projects: 15;
Federal share of funding for water-related projects: $4,838,097.
Source: GAO analysis of DOE and Interior data.
[A] Numbers may contain some nonfederal funds.
[End of table]
NETL sponsors the majority of the water-related oil shale research
currently funded by DOE. Through workshops, NETL gathers information
to prioritize research. For example, in October 2007, NETL sponsored
the Oil Shale Environmental Issues and Needs Workshop that was
attended by a cross-section of stakeholders, including officials from
BLM and state water regulatory agencies, as well as representatives
from the oil shale industry. One of the top priorities that emerged
from the workshop was to develop an integrated regional baseline for
surface water and groundwater quality and quantity. As we have
previously reported, after the identification of research priorities,
NETL solicits proposals and engages in a project selection process.
[Footnote 28] We identified seven projects involving oil shale and
water that NETL awarded since June 2006. The University of Utah,
Colorado School of Mines, the Utah Geological Survey, and the Idaho
National Laboratory (INL) are performing the work on these projects.
These projects cover topics such as water rights, water needs for oil
shale development, impacts of retorting on water quality, and some
limited groundwater modeling. One project conducted by the Colorado
School of Mines involves developing a geographic information system
for storing, managing, analyzing, visualizing, and disseminating oil
shale data from the Piceance Basin. Although this project will provide
some baseline data on surface water and groundwater and involves some
theoretical groundwater modeling, the project's researchers told us
that these data will neither be comprehensive nor complete. In
addition, NETL-sponsored research conducted at the University of Utah
involves examining the effects of oil shale processing on water
quality, new approaches to treat water produced from oil shale
operations, and water that can be recycled and reused in operations.
INL is sponsoring and performing research on four water-related oil
shale projects while conducting research for NETL and the Office of
Naval Petroleum and Oil Shale Reserves. The four projects that INL is
sponsoring were self-initiated and funded internally through DOE's
Laboratory Directed Research and Development program. Under this
program, the national laboratories have the discretion to self-
initiate independent research and development, but it must focus on
the advanced study of scientific or technical problems, experiments
directed toward proving a scientific principle, or the early analysis
of experimental facilities or devices. Generally, the researchers
propose projects that are judged by peer panels and managers for their
scientific merits. An INL official told us they selected oil shale and
water projects because unconventional fossil fuels, which include oil
shale, are a priority in which they have significant expertise.
According to DOE officials, one of the projects managed by the Office
of Naval Petroleum and Oil Shale Reserves is directed at research on
the environmental impacts of unconventional fuels. The Los Alamos
National Laboratory is conducting the work for DOE, which involves
examining water and carbon-related issues arising from the development
of oil shale and other unconventional fossil fuels in the western
United States. Key water aspects of the study include the use of an
integrated modeling process on a regional basis to assess the amounts
and availability of water needed to produce unconventional fuels,
water storage and withdrawal requirements, possible impacts of climate
change on water availability, and water treatment and recycling
options. Although a key aspect of the study is to assess water
availability, researchers on the project told us that little effort
will be directed at assessing groundwater, and the information
developed will not result in a comprehensive understanding of the
baseline conditions for water quality and quantity.
Interior Funds Limited Oil Shale-Related Research on Groundwater and
Surface Water Resources and Monitoring:
Within Interior, BLM is sponsoring two oil shale projects related to
water resources with federal funding totaling about $500,000.[Footnote
29] The USGS is conducting the research for both projects. For one of
the projects, which is funded jointly by BLM and a number of Colorado
cities and counties plus various oil shale companies, the research
involves the development of a common repository for water data
collected from the Piceance Basin. More specifically, the USGS has
developed a Web-based repository of water quality and quantity data
obtained by identifying 80 public and private databases and by
analyzing and standardizing data from about half of them. According to
USGS officials, many data elements are missing, and the current
repository is not comprehensive. The second project, which is entirely
funded by BLM, will monitor groundwater quality and quantity within
the Piceance Basin in 5 existing wells and 10 more to be determined at
a future date. Although USGS scientists said that this is a good start
to understanding groundwater resources, it will not be enough to
provide a regional understanding of groundwater resources.
Gaps in Groundwater and Surface Water Data Have Been Identified by
Federal and State Officials:
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)[Footnote 30] for
preparing an environmental impact statement (EIS), such as the EIS
that will be needed to determine the impacts of future oil shale
development, require the preparing agency to adopt a monitoring and
enforcement program if measures are necessary to mitigate anticipated
environmental impacts.[Footnote 31] 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.[Footnote 32] The council noted that monitoring
and consideration of potential adaptive measures to allow for
midcourse corrections, without requiring new or supplemental NEPA
review, will assist in accounting for unanticipated changes in
environmental conditions, inaccurate predictions, or subsequent
information that might affect the original environmental conditions.
In September 2007, the Task Force on Strategic Unconventional Fuels--
an 11-member group that included the Secretaries of DOE and Interior
and the Governors of Colorado and Utah--issued a report with
recommendations on promoting the development of fuels from domestic
unconventional fuel resources as mandated by the Energy Policy Act of
2005. This report included recommendations and strategies for
developing baseline conditions for water resources and monitoring the
impacts from oil shale development. It recommended that a monitoring
plan be developed and implemented to fill data gaps at large scales
and over long periods of time and to also develop, model, test, and
evaluate short-and long-term monitoring strategies. The report noted
that systems to monitor water quality would be evaluated; additional
needs would be identified; and relevant research, development, and
demonstration needs would be recommended.
Also in September 2007, the USGS prepared for BLM a report to improve
the efficiency and effectiveness of BLM's monitoring efforts.[Footnote
33] The report noted that regional water-resources monitoring should
identify gaps in data, define baseline conditions, develop regional
conceptual models, identify impacts, assess the linkage of impacts to
energy development, and understand how impacts propagate. The report
also noted that in the Piceance Basin, there is no local, state-level,
or national comprehensive database for surface water and groundwater
data. Furthermore, for purposes of developing a robust and cost-
effective monitoring plan, the report stated that a compilation and
analysis of available data are necessary. One of the report's authors
told us that the two BLM oil shale projects that the USGS is
performing are the initial steps in implementing such a regional
framework for water resource monitoring. However, the author said that
much more work is needed because so much water data are missing. He
noted the current data repository is not comprehensive and much more
data would be needed to determine whether oil shale development will
create adverse effects on water resources.
Nearly all the federal agency officials, state water regulators, oil
shale researchers, and water experts with whom we spoke said that more
data are needed to understand the baseline condition of groundwater
and surface water, so that the potential impacts of oil shale
development can be monitored (see appendix I for a list of the
agencies we contacted). Several officials and experts to whom we spoke
stressed the need to model the movement of groundwater and its
interaction with surface water to understand the possible transport of
contaminants from oil shale development. They suggested that
additional research would help to overcome these shortcomings.
Specifically, they identified the following issues:
* Insufficient data for establishing comprehensive baseline conditions
for surface water and groundwater quality and quantity. Of the 18
officials and experts we contacted, 17 noted that there are
insufficient data to understand the current baseline conditions of
water resources in the Piceance and Uintah Basins. Such baseline
conditions include the existing quantity and quality of both
groundwater and surface water. Hydrologists among those we interviewed
explained that more data are needed on the chemistry of surface water
and groundwater, properties of aquifers, age of groundwater, flow
rates and patterns of groundwater, and groundwater levels in wells.
Although some current research projects have and are collecting some
water data, officials from the USGS, Los Alamos National Laboratory,
and the universities doing this research agreed their data are not
comprehensive enough to support future monitoring efforts.
Furthermore, Colorado state officials told us that even though much
water data were generated over time, including during the last oil
shale boom, little of these data have been assimilated, gaps exist,
and data need to be updated in order to support future monitoring.
* Insufficient research on groundwater movement and its interaction
with surface water for modeling possible transport of contaminants.
Sixteen of 18 officials and experts to whom we spoke noted that
additional research is needed to develop a better understanding of the
interactions between groundwater and surface water and of groundwater
movement. Officials from NETL explained that this is necessary in
order to monitor the rate and pattern of flow of possible contaminants
resulting from the in-situ retorting of oil shale. They noted that
none of the groundwater research currently under way is comprehensive
enough to build the necessary models to understand the interaction and
movement. NETL officials noted more subsurface imaging and
visualization are needed to build geologic and hydrologic models and
to study how quickly groundwater migrates. These tools will aid in
monitoring and providing data that does not currently exist.
Interior and DOE Officials Generally Have Not Shared Information on
Oil Shale Research:
Interior and DOE officials generally have not shared current research
on water and oil shale issues. USGS officials who conduct water-
related research at Interior and DOE officials at NETL, which sponsors
the majority of the water and oil shale research at DOE, stated they
have not talked with each other about such research in almost 3 years.
USGS staff noted that although DOE is currently sponsoring most of the
water-related research, USGS researchers were unaware of most of these
projects. In addition, staff at Los Alamos National Laboratory who are
conducting some water-related research for DOE noted that various
researchers are not always aware of studies conducted by others and
stated that there needs to be a better mechanism for sharing this
research. Based on our review, we found there does not appear to be
any formal mechanism for sharing water-related research activities and
results among Interior, DOE, and state regulatory agencies in Colorado
and Utah. The last general meeting to discuss oil shale research among
these agencies was in October 2007, although there have been
opportunities to informally share research at the annual Oil Shale
Symposium, the last one of which was conducted at the Colorado School
of Mines in October 2010. Of the various officials with the federal
and state agencies, representatives from research organizations, and
water experts we contacted, 15 of 18 noted that federal and state
agencies could benefit from collaboration with each other on water-
related research involving oil shale. Representatives from NETL, who
are sponsoring much of the current research, stated that collaboration
should occur at least every 6 months.
We and others have reported that collaboration among government
agencies can produce more public value than one agency acting alone.
[Footnote 34] Specifically concerning water resources, we previously
reported that coordination is needed to enable monitoring programs to
make better use of available resources in light of organizations often
being unaware of data collected by other groups.[Footnote 35]
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.[Footnote 36] In 2007, the Subcommittee on Water Availability
and Quality within the Office of Science and Technology Policy, an
office that advises the President and leads interagency efforts
related to science and technology stated, "Given the importance of
sound water management to the Nation's well-being it is appropriate
for the Federal government to play a significant role in providing
information to all on the status of water resources and to provide the
needed research and technology that can be used by all to make
informed water management decisions."[Footnote 37] In addition, H.R.
1145--the National Water Research and Development Initiative Act of
2009--which has passed the House of Representatives and is currently
in a Senate committee, would establish a federal interagency committee
to coordinate all federal water research, which totals about $700
million annually. This bill focuses on improving coordination among
agency research agendas, increasing the transparency of water research
budgeting, and reporting on progress toward research outcomes.
Conclusions:
The unproven nature of oil shale technologies and choices in how to
generate the power necessary to develop this resource cast a shadow of
uncertainty over how much water is needed to sustain a commercially
viable oil shale industry. Additional uncertainty about the size of
such an industry clouds the degree to which surface and groundwater
resources could be impacted in the future. Furthermore, these
uncertainties are compounded by a lack of knowledge of the current
baseline conditions of groundwater and surface water, including their
chemistry and interaction, properties of aquifers, and the age and
rate of movement of groundwater, in the arid Piceance and Uintah
Basins of Colorado and Utah, where water is considered one of the most
precious resources. All of these uncertainties pose difficulties for
oil shale developers, federal land managers, state water regulators,
and current water users in their efforts to protect water resources.
Attempts to commercially develop oil shale in the United States have
spanned nearly a century. During this time, the industry has focused
primarily on overcoming technological challenges and trying to develop
a commercially viable operation. More recently, the federal government
has begun to focus on studying the potential impacts of oil shale
development on surface water and groundwater resources. However, these
efforts are in their infancy when compared to the length of time that
the industry has spent on attempting to overcome technological
challenges. These nascent efforts do not adequately define current
baseline conditions for water resources in the Piceance and Uintah
Basins, nor have they begun to model the important interaction of
groundwater and surface water in the region. Thus they currently fall
short of preparing federal and state governments for monitoring the
impacts of any future oil shale development. In addition, there is a
lack of coordination among federal agencies on water-related research
and a lack of communicating results among themselves and to the state
regulatory agencies. Without such coordination and communication,
federal and state agencies cannot begin to develop an understanding of
the potential impacts of oil shale development on water resources and
monitor progress toward shared water goals. By taking steps now, the
federal government, working in concert with the states of Colorado and
Utah, can position itself to help monitor western water resources
should a viable oil shale industry develop in the future.
Recommendations for Executive Action:
To prepare for possible impacts from the future development of oil
shale, we are making three recommendations to the Secretary of the
Interior. Specifically, the Secretary should direct the appropriate
managers in the Bureau of Land Management and the U.S. Geological
Survey to:
1. establish comprehensive baseline conditions for groundwater and
surface water quality, including their chemistry, and quantity in the
Piceance and Uintah Basins to aid in the future monitoring of impacts
from oil shale development in the Green River Formation;
2. model regional groundwater movement and the interaction between
groundwater and surface water, in light of aquifer properties and the
age of groundwater, so as to help in understanding the transport of
possible contaminants derived from the development of oil shale; and:
3. coordinate with the Department of Energy and state agencies with
regulatory authority over water resources in implementing these
recommendations, and to provide a mechanism for water-related research
collaboration and sharing of results.
Agency Comments:
We provided a copy of our draft report to Interior and DOE for their
review and comment. Interior provided written comments and generally
concurred with our findings and recommendations. Interior highlighted
several actions it has under way to begin to implement our
recommendations. Specifically, Interior stated that with regard to our
first recommendation to establish comprehensive baseline conditions
for surface water and groundwater in the Piceance and Uintah Basins,
implementation of this recommendation includes ongoing USGS efforts to
analyze existing water quality data in the Piceance Basin and ongoing
USGS efforts to monitor surface water quality and quantity in both
basins. Interior stated that it plans to conduct more comprehensive
assessments in the future. With regard to our second recommendation to
model regional groundwater movement and the interaction between
groundwater and surface water, Interior said BLM and USGS are working
on identifying shared needs for modeling. Interior underscored the
importance of modeling prior to the approval of large-scale oil shale
development and cites the importance of the industry's testing of
various technologies on federal RD&D leases to determine if production
can occur in commercial quantities and to develop an accurate
determination of potential water uses for each technology. In support
of our third recommendation to coordinate with DOE and state agencies
with regulatory authority over water resources, Interior stated that
BLM and USGS are working to improve such coordination and noted
current efforts with state and local authorities. Interior's comments
are reproduced in appendix III.
DOE also provided written comments, but did not specifically address
our recommendations. Nonetheless, DOE indicated that it recognizes the
need for a more comprehensive and integrated cross-industry/government
approach for addressing impacts from oil shale development. However,
DOE raised four areas where it suggested additional information be
added to the report or took issue with our findings. First, DOE
suggested that we include in our report appropriate aspects of a
strategic plan drafted by an ad hoc group of industry, national
laboratory, university, and government representatives organized by
the DOE Office of Naval Petroleum and Oil Shale Reserves. We believe
aspects of this strategic plan are already incorporated into our
report. For example, the strategic plan of this ad hoc group calls for
implementing recommendations of the Task Force on Strategic
Unconventional Fuels, which was convened by the Secretary of Energy in
response to a directive within the Energy Policy Act of 2005. The Task
Force on Strategic and Unconventional fuels recommended developing
baseline conditions for water resources and monitoring the impacts
from oil shale development, which is consistent with our first
recommendation. The ad hoc group's report recognized the need to share
information and collaborate with state and other federal agencies,
which is consistent with our third recommendation. As such, we made no
changes to this report in response to this comment.
Second, DOE stated that we overestimated the amount of water needed
for in-situ oil shale development and production. We disagree with
DOE's statement because the estimates presented in our report respond
to our objective, which was to describe what is known about the amount
of water that may be needed for commercial oil shale development, and
they are based on existing publicly available data. We reported the
entire range of reputable studies without bias to illustrate the wide
range of uncertainty in water needed to commercially develop oil
shale, given the current experimental nature of the process. We
reported only publicly available estimates based on original research
that were substantiated with a reasonable degree of documentation so
that we could verify that the estimates covered the entire life cycle
of oil shale development and that these estimates did not pertain
solely to field demonstration projects, but were instead scalable to
commercial operations. We reviewed and considered estimates from all
of the companies that DOE identified in its letter. The range of water
needed for commercial in-situ development of oil shale that we report
ranges from 1 to 12 barrels of water per barrel of oil. These lower
and upper bounds represent the sum of the most optimistic and most
pessimistic estimates of water needed for all five groups of
activities that we identified as comprising the life cycle of in-situ
oil shale development. However, the lower estimate is based largely on
estimates by ExxonMobil and incorporates the use of produced water,
water treatment, and recycling, contrary to DOE's statement that we
dismissed the significance of these activities. The upper range is
influenced heavily by the assumption that electricity used in
retorting will come from coal-fired plants and that a maximum amount
of water will be used for rinsing the retorted zones, based on
modeling done at the Center for Oil Shale Technology and Research.
[Footnote 38] The studies supporting these estimates were presented at
the 29th Annual Oil Shale Symposium at the Colorado School of Mines.
Such a range overcomes the illusion of precision that is conveyed by a
single point estimate, such as the manner in which DOE cites the 1.59
barrels of water from the AMEC study, or the bias associated with
reporting a narrow range based on the assumption that certain
technologies will prevail before they are proven to be commercially
viable for oil shale development. Consequently, we made no changes to
the report in response to this comment.
Third, DOE stated that using the amount of water in the White River at
Meeker, Colorado, to illustrate the availability of water for
commercial oil shale development understates water availability. We
disagree with DOE's characterization of our illustration. The
illustration we use in the report is not meant to imply that an entire
three-state industry would be limited by water availability at Meeker.
Rather, the illustration explores the limitations of an in-situ oil
shale industry only in the Piceance Basin. More than enough water
appears available for a reasonably sized industry that depends on
mining and surface retorting in the Piceance basin. Our illustration
also suggests that there may be more than enough water to supply a 2.5
million barrel-per-day in-situ industry at minimum water needs, even
considering the needs of current water users and the anticipated needs
of future water users. In addition, the illustration suggests that
there may be enough water to supply an in-situ industry in the
Piceance Basin of between 1 and 2 million barrels per day at average
water needs, depending upon whether all the water in the White River
at Meeker is used or only water that is expected to be physically and
legally available in the future. However, the illustration does point
out limitations. It suggests that at maximum water needs, an in-situ
industry in the Piceance Basin may not reach 1 million barrels per day
if it relied solely on water in the White River at Meeker. Other
sources of water may be needed, and our report notes that these other
sources could include water in the Yampa or Colorado Rivers, as well
as groundwater. Use of produced water and recycling could also reduce
water needs as noted in the draft report. Consequently, we made no
changes to the report in response to this comment.
Fourth, DOE stated that the report gives the impression that all oil
shale technologies are speculative and proving them to be commercially
viable will be difficult, requiring a long period of time with
uncertain outcomes. We disagree with this characterization of our
report. Our report clearly states that there is uncertainty regarding
the commercial viability of in-situ technologies. Based on our
discussions with companies and review of available studies, Shell is
the only active oil shale company to have successfully produced shale
oil from a true in-situ process. Considering the uncertainty
associated with impacts on groundwater resources and reclamation of
the retorted zone, commercialization of an in-situ process is likely
to be a number of years away. To this end, Shell has leased federal
lands from BLM to test its technologies, and more will be known once
this testing is completed. With regard to mining oil shale and
retorting it at the surface, we agree that it is a relatively mature
process. Nonetheless, competition from conventional crude oil has
inhibited commercial oil shale development in the United States for
almost 100 years. Should some of the companies that DOE mentions in
its letter prove to be able to produce oil shale profitably and in an
environmentally sensitive manner, they will be among the first to
overcome such long-standing challenges. We are neither dismissing
these companies, as DOE suggests, nor touting their progress. In
addition, it was beyond the scope of our report to portray the timing
of commercial oil shale production or describe a more exhaustive
history of oil shale research, as DOE had recommended, because much
research currently is privately funded and proprietary. Therefore, we
made no changes to the report in response to this comment. DOE's
comments are reproduced in appendix IV.
As agreed with your office, unless you publicly announce the contents
of this report earlier, we plan no further distribution until 30 days
from the report date. At that time, we will send copies of this report
to the appropriate congressional committees, Secretaries of the
Interior and Energy, Directors of the Bureau of Land Management and
U.S. Geological Survey, and other interested parties. In addition, the
report will be available at no charge on GAO's Web site at [hyperlink,
http://www.gao.gov].
If you or your staff have any questions about this report, please
contact one of us at (202) 512-3841 or gaffiganm@gao.gov or
mittala@gao.gov. Contact points for our Offices of Congressional
Relations and Public Affairs may be found on the last page of this
report. Key contributors to this report are listed in appendix V.
Signed by:
Mark Gaffigan:
Director, Natural Resources and Environment:
Signed by:
Anu Mittal:
Director, Natural Resources and Environment:
[End of section]
Appendix I: Scope and Methodology:
To determine what is known about the potential impacts to groundwater
and surface water from commercial oil shale development, we reviewed
the Proposed Oil Shale and Tar Sands Resource Management Plan
Amendments to Address Land Use Allocations in Colorado, Utah, and
Wyoming and Final Programmatic Environmental Impact Statement (PEIS)
prepared by the Bureau of Land Management in September 2008. We also
reviewed environmental assessments prepared on Shell Oil's plans for
in-situ development of its research, demonstration, and development
(RD&D) tracts in Colorado and on the Oil Shale Exploration Company's
(OSEC) plan to mine oil shale on its RD&D tract in Utah because these
two companies have made the most progress toward developing in-situ
and mining technologies, respectively. In addition, we reviewed the
Office of Technology Assessment's (OTA) 1980 report, An Assessment of
Oil Shale Technologies; the Rand Corporation's 2005 report, Oil Shale
Development in the United States; and the Argonne National
Laboratory's 2005 report, Potential Ground Water and Surface Water
Impacts from Oil Shale and Tar Sands Energy-Production Operations.
Because the PEIS was the most comprehensive of these documents, we
summarized impacts to groundwater and surface water quantity and
quality described within this document and noted that these impacts
were entirely qualitative in nature and that the magnitude of impacts
was indeterminate because the in-situ technologies have yet to be
developed. To confirm these observations and the completeness of
impacts within the PEIS, we contacted the Environmental Protection
Agency, the Colorado Division of Water Resources, the Colorado Water
Conservation Board, the Division of Water Quality within the Colorado
Department of Public Health and Environment, the Utah Division of
Water Resources, the Utah Division of Water Quality, and the Utah
Division of Water Rights--all of which have regulatory authority over
some aspect of water resources. To ensure that we identified the range
of views on the potential impacts of oil shale development on
groundwater and surface water, we also contacted the U.S. Geological
Survey (USGS), the Colorado Geological Survey, the Utah Geological
Survey, industry representatives, water experts, and numerous
environmental groups for their views on the impacts of oil shale on
water resources. To assess the impacts of oil shale development on
aquatic resources, we reviewed the PEIS and contacted the Colorado
Division of Wildlife and the Utah Division of Wildlife Resources.
To determine what is known about the amount of water that may be
needed for commercial oil shale development, we searched the Internet
and relevant databases of periodicals using the words "oil shale"
together with "water use." We also searched Web sites maintained by
the Bureau of Land Management (BLM), USGS, and the Department of
Energy (DOE) for information on oil shale and water use and
interviewed officials at these agencies to determine if there were
additional studies that we had not identified. We also checked
references cited within the studies for other studies. We limited the
studies to those published in 1980 or after because experts with whom
we consulted either considered the studies published before then to be
adequately summarized in OTA's 1980 report or to be too old to be
relevant. We included certain data within the OTA report because some
of the surface retort technologies are similar to technologies being
tested today. We did not consider verbal estimates of water needs
unless companies could provide more detailed information. The 17
studies that we identified appear in table 7.
Table 7: Studies on Water Use for Oil Shale Development Initially
Identified by GAO:
Bartis, et al. Oil Shale Development in the United States: Prospects
and Policy Issues. Rand Corporation, 2005.
Boak, Jeremy and Earl Mattson. Water Use for In-Situ Production of
Shale Oil from the Green River Formation. Presented at the 29th Oil
Shale Symposium, Colorado School of Mines, October 20, 2009.
Bureau of Land Management. Oil Shale Research, Development, and
Demonstration Project. Environmental Assessment CO-110-2006-117-EA.
Prepared to analyze a proposal by Shell Frontier Oil and Gas, Inc.,
2006.
Bureau of Land Management. Oil Shale Research, Development and
Demonstration Project, White River Mine, Uintah County, Utah.
Environmental Assessment UT-080-06-280. Prepared to analyze a proposal
by the Oil Shale Exploration Company, April 2007.
Bureau of Land Management. Proposed Oil Shale and Tar Sands Resource
Management Plan Amendments to Address Land Use Allocations in
Colorado, Utah, and Wyoming and Final Programmatic Environmental
Impact Statement (PEIS). September 2008.
Dudley-Murphy, Beth, et al. Meeting Data Needs to Perform a Water
Impact Assessment for Oil Shale Development in the Uinta and Piceance
Basins, Appendix D in Utah Heavy Oil Program: Final
Scientific/Technical Report. Institute for Clean and Secure Energy,
October 2009.
Harding, Benjamin. AMEC Earth and Environmental. Energy Development
Water Needs Assessment and Water Supply Alternatives Analysis.
Presented at the Promise and Perils of Oil Shale Symposium sponsored
by the Natural Resources Law Center at the University of Colorado at
Boulder, February 5, 2010.
Mangmeechai, Aweewan. Life Cycle Greenhouse Gas Emissions, Consumptive
Water Use and Levelized Costs of Unconventional Oil in North America.
Ph.D. dissertation, Carnegie Mellon University, August 2009.
Mangmeechai, Aweewan et al. Life Cycle Consumptive Water Use of U.S.
Oil Shale. Presented at the International Society for Industrial
Ecology, Boston, Massachusetts, September 29-October 2, 2009.
National Oil Shale Association. "NOSA Evaluates Oil Shale Water
Usage." Oil Shale Update, vol. II, issue I (September 2009).
Office of Technology Assessment. An Assessment of Oil Shale
Technologies. June 1980.
Shell Frontier Oil and Gas, Inc. Plan of Operations, Oil Shale Test
Project. February 15, 2006.
Thomas, Michele Mosio, et al. ExxonMobil Upstream Research.
Responsible Development of Oil Shale. Presented at the 29th Oil Shale
Symposium, Colorado School of Mines, October 2009.
URS Corporation. Energy Development Water Needs Assessment (Phase I
Report). Glenwood Springs, Colorado, September 2008.
Veil, J. A. and M.G. Puder. Potential Ground Water and Surface Water
Impacts from Oil Shale and Tar Sands Energy-Production Operations,
Argonne National Lab. October 2006.
Western Resource Advocates. Water on the Rocks: Oil Shale Water Rights
in Colorado. Boulder, Colorado, 2009.
Wilson, C, et al. Los Alamos National Laboratory. Assessment of
Climate Variability on Water Resource Availability for Oil Shale
Development. Presented at the First Western Forum on Energy and Water
Sustainability, School of Environmental Science and Management,
University of California, Santa Barbara, March 22-23, 2007.
Source: GAO.
Note: While this table includes all the studies we initially
identified, we describe further in this section of the report how we
identified data within these studies that sufficiently met our quality
criteria to be included in the range of water estimates.
[End of table]
For further analysis, we divided the studies into two major groups--in-
situ extraction and mining with a surface retort. We dismissed a
combination of mining and in-situ extraction because most of these
technologies are more than 30 years old and generally considered to be
infeasible today. The single company that is pursuing such a
combination of technologies today--Red Leaf Resources--has not
published detailed data on water needs. After reviewing these studies,
we found that most of the studies did not examine water needs for the
entire life cycle of oil shale development. As such, we identified
logical groups of activities based on descriptions within the studies.
We identified the following five groups of activities: (1) extraction
and retorting, (2) generating power, (3) upgrading shale oil, (4)
reclamation, and (5) population growth associated with oil shale
development. We did not include refining because we believe it is
unlikely that oil shale production will reach levels in the near-or
midterm to justify building a new refinery.
To characterize the water needs for the entire life cycle of oil shale
development, we identified within each study the water needs for each
of the five groups of activities. Except for OTA's 1980 report, which
is now 30 years old, we contacted the authors of each study and
discussed the estimates with them. If estimates within these studies
were given for more than one group of activities, we asked them to
break down this estimate into the individual groups when possible. We
only considered further analyzing water needs for groups of activities
that were based on original research so as not to count these
estimates multiple times. For example, original research on water
needs for extraction and retorting may have analyzed mine plans,
estimated water needs for drilling wells, estimated water needs for
dust control, and discussed recycling of produced water. Original
research on water needs for population growth may have discussed the
number of workers immigrating to a region, their family size, per
capita water consumption, and the nature of housing required by
workers. On the other hand, estimates of water needs that were not
based on original research generally reported water needs for multiple
groups of activities in barrels of water per barrel of oil produced
and cited someone else's work as the source for this number. We
excluded several estimates that seemed unlikely. For example, we
eliminated a water estimate for power generation that included
building a nuclear power plant and water estimates for population
growth where it was assumed that people would decrease their water
consumption by over 50 percent. We also excluded technologies
developed prior to 1980 that are dissimilar to technologies being
considered by oil shale companies today. We checked mathematical
calculations and reviewed power requirements and the reasonableness of
associated water needs. For power estimates that did not include
associated water needs, we converted power needs into water needs
using 480 gallons per megawatt hour of electricity produced by coal-
fired, wet recirculating thermoelectric plants and 180 gallons per
megawatt hour of electricity produced by gas-powered, combined cycle,
wet recirculating thermoelectric plants. Air-cooled systems consume
almost no water for cooling. Where appropriate, we also estimated
shale oil recoveries based the company's estimated oil shale resources
and estimated water needs for rinsing retorted zones based on
anticipated changes to the reservoir.
We converted water requirements to barrels of water needed per barrel
of oil produced. For those studies with water needs that met our
criteria, we tabulated water needs for each group of activities for
both in-situ production and mining with a surface retort. The results
appear in tables 8 and 9. We estimated the total range of water needs
for in-situ development by summing the minimum estimates for each
group of activities and by summing the maximum estimates for the
various groups of activities. We did the same for mining with a
surface retort. We also calculated the average water needs for each
group of activities.
Table 8: Studies GAO Examined That Contained Original Research on
Water Requirements for Groups of Activities Representing the Complete
Life Cycle for the In-Situ Production of Oil Shale[A]:
Study: BLM, PEIS;
Extraction and retorting: [Empty];
Power: [Empty];
Reclamation: [Empty];
Upgrading liquids: [Empty];
Population growth: [Check].
Study: Dudley-Murphy et al., table 6, scenarios 2 and 6[B];
Extraction and retorting: [Empty];
Power: [Empty];
Reclamation: [Empty];
Upgrading liquids: [Empty];
Population growth: [Check].
Study: NOSA, report and personal communication[C];
Extraction and retorting: [Check];
Power: [Check];
Reclamation: [Check];
Upgrading liquids: [Check];
Population growth: [Empty].
Study: Boak and Mattson, report and personal communication[D];
Extraction and retorting: [Check];
Power: [Check];
Reclamation: [Check];
Upgrading liquids: [Empty];
Population growth: [Empty].
Study: ExxonMobil;
Extraction and retorting: [Check];
Power: [Check];
Reclamation: [Check];
Upgrading liquids: [Check];
Population growth: [Empty].
Study: URS[E];
Extraction and retorting: [Check];
Power: [Check];
Reclamation: [Check];
Upgrading liquids: [Check];
Population growth: [Check].
Study: AMEC[F];
Extraction and retorting: [Empty];
Power: [Check];
Reclamation: [Empty];
Upgrading liquids: [Empty];
Population growth: [Empty].
Study: Shell EA, plan of operation and personal communication[G];
Extraction and retorting: [Check];
Power: [Check];
Reclamation: [Check];
Upgrading liquids: [Check];
Population growth: [Check].
Source: GAO analysis of selected studies.
[A] A [Check] in the column indicates that we analyzed the water
estimate in this study for this group of activities. We do not list
quantitative water estimates for these groups of activities because
some of these data are confidential.
[B] This study did not differentiate estimates for in-situ extraction
from estimates for mining with a surface retort.
[C] This study was a confidential survey of multiple companies. Since
we did not have access to the identities of the respondents or their
individual answers, we could not exclude their estimates if they
appear elsewhere in this table. The National Oil Shale Association
published the survey results as total water needs being 1.7 barrels of
water plus 0.6 to 1.6 barrels of water for upgrading liquids per
barrel of oil produced. The upgrading estimate is for both in-situ and
mining with a surface retort. Water for power generation and
population growth is not included. We estimated water needs for power
based on the average of the survey responses to power requirements. We
estimated water needs for extraction and retorting and for reclamation
based on the average of the survey responses. "Personal communication"
indicates that we supplemented information in the study by contacting
the author for more information.
[D] We included estimates for site water (water for extraction and
retorting and reclamation) between the 25 percent and 75 percent
cumulative probability levels. According to the author, about 90
percent of the site water is needed for reclamation. "Personal
communication" indicates that we supplemented information in the study
by contacting the author for more information.
[E] We could not separate water needs for upgrading liquids from
extraction and retorting. The water needs for power are based on coal-
fired plants.
[F] The purpose of this study is to update water requirements in the
URS report. Preliminary data were presented by Benjamin Harding at the
Promise and Perils of Oil Shale Symposium on February 5, 2010. Water
needs for power are based on combined-cycle natural gas plants. The
final study, which is expected to examine water needs for all groups
of activities, will not be publicly available until October 2010.
[G] Shell cites a total of 3 barrels of water for each barrel of oil
produced as appropriate for planning purposes. We estimated individual
water needs for each of the five groups of activities by examining
parameters discussed in Shell's EA and Plan of Operations in light of
revised data provided verbally by Shell. Our estimates for individual
groups of activities, based on Shell's revised data, add up to about 3
barrels of water. "Personal communication" indicates that we
supplemented information in the study by contacting the author for
more information.
[End of table]
Table 9: Studies GAO Examined That Contained Original Research on
Water Requirements for Groups of Activities Representing the Complete
Life Cycle for an Oil Shale Mine with a Surface Retort[A]:
Study: BLM, PEIS;
Extraction and retorting and upgrading liquids[B]: [Empty];
Power: [Empty];
Reclamation: [Empty];
Population growth: [Check].
Study: Dudley-Murphy, table 6, scenarios 2 and 6[C];
Extraction and retorting and upgrading liquids[B]: [Empty];
Power: [Empty];
Reclamation: [Empty];
Population growth: [Check].
Study: NOSA, report and personal communication[D];
Extraction and retorting and upgrading liquids[B]: [Check];
Power: [Check];
Reclamation: [Check];
Population growth: [Empty].
Study: URS;
Extraction and retorting and upgrading liquids[B]: [Empty];
Power: [Check];
Reclamation: [Empty];
Population growth: [Check].
Study: OTA, Paraho-Direct process developed by WPA/DRI;
Extraction and retorting and upgrading liquids[B]: [Check];
Power: [Check];
Reclamation: [Check];
Population growth: [Check].
Study: OTA, Paraho-Direct process developed by McGee-Kunchal;
Extraction and retorting and upgrading liquids[B]: [Check];
Power: [Check];
Reclamation: [Check];
Population growth: [Check].
Study: OTA, Paraho-Indirect process developed by McGee-Kunchal;
Extraction and retorting and upgrading liquids[B]: [Check];
Power: [Check];
Reclamation: [Empty];
Population growth: [Check].
Study: Oil Shale Exploration Company;
Extraction and retorting and upgrading liquids[B]: [Check][E];
Power: [Check][E];
Reclamation: [Empty];
Population growth: [Empty].
Source: GAO analysis of selected studies.
[A] A [Check] in the column indicates that we analyzed the water
estimate in this study for this group of activities. We do not list
quantitative water estimates for these groups of activities because
some of these data are confidential.
[B] We could not differentiate extraction and retorting from upgrading
liquids in many of these studies.
[C] This study did not differentiate estimates for in-situ extraction
from estimates for mining with a surface retort.
[D] This study was a confidential survey of multiple companies. Since
we did not have access to the identities of the respondents or their
individual answers, we could not exclude their estimates if they
appear elsewhere in this table. The National Oil Shale Association
published survey results as total water needs being 2 barrels of water
plus 0.6 to 1.6 barrels of water for upgrading liquids per barrel of
oil produced. The upgrading estimate is for both in-situ and mining
with a surface retort. Water for population growth is not included. We
estimated water needs for extraction and retorting and for reclamation
based on the average of the survey responses. We estimated water needs
for power based on the average of the survey responses to power needs.
"Personal communication" indicates that we supplemented information in
the study by contacting the author for more information.
[E] Although we reviewed these estimates, we excluded them from our
analysis because we do not believe they are scalable to a commercial
operation. They were moderately higher than the other estimates but
not unreasonable, and they serve as a check on the upper limit for
these two groups of activities.
[End of table]
To determine the extent to which water is likely to be available for
commercial oil shale development and its source, we compared the total
needs of an oil shale industry of various sizes to the amount of
surface water and groundwater that the states of Colorado and Utah
estimate to be physically and legally available, in light of future
municipal and industrial demand. We selected the sizes of an oil shale
industry based on input from industry and DOE. These are hypothetical
sizes, and we do not imply that an oil shale industry will grow to
these sizes. The smallest size we selected for an in-situ industry,
500,000 barrels of oil per day, is a likely size identified by an oil
shale company based on experience with the development of the Canadian
tar sands. The largest size of 2,500,000 barrels of oil per day is
based on DOE projections. We based our smallest size of a mining
industry, 25,000 barrels of oil per day, on one-half of the smallest
scenario identified by URS in their work on water needs contracted by
the state of Colorado. We based our largest size of a mining industry,
150,000 barrels of oil per day, on three projects each of 50,000
barrels of oil per day, which is a commonly cited size for a
commercial oil shale mining operation. We reviewed and analyzed two
detailed water studies commissioned by the state of Colorado to
determine how much water is available in Colorado, where it was
available, and to what extent demands will be placed on this water in
the future.[Footnote 39] We also reviewed a report prepared for the
Colorado Water Conservation Board on future water availability in the
Colorado River.[Footnote 40] These studies were identified by water
experts at various Colorado state water agencies as the most updated
information on Colorado's water supply and demand. To determine the
available water supply and the potential future demand in the Uintah
Basin, we reviewed and analyzed data in documents prepared by the Utah
Division of Water Resources.[Footnote 41] We also examined data on
water rights provided by the Utah Division of Water Rights and
examined data collected by Western Resource Advocates on oil shale
water rights in Colorado. In addition to reviewing these documents, we
interviewed water experts at the Bureau of Reclamation, USGS, Utah
Division of Water Rights, Utah Division of Water Resources, Utah
Division of Water Quality, Colorado Division of Natural Resources,
Colorado Division of Water Resources, Colorado River Water
Conservation District, the Utah and Colorado State Demographers, and
municipal officials in the oil shale resource area.
To identify federally funded research efforts to address the impacts
of commercial oil shale development on water resources, we interviewed
officials and reviewed information from offices or agencies within DOE
and the Department of the Interior (Interior). Within DOE, these
offices were the Office of Naval Petroleum and Oil Shale Reserves, the
National Energy Technology Laboratory, and other DOE offices with
jurisdiction over various national laboratories. Officials at these
offices identified the Idaho National Laboratory and the Los Alamos
National Laboratory as sponsoring or performing water-related oil
shale research. In addition, they identified experts at Argonne
National Laboratory who worked on the PEIS for BLM or who wrote
reports on water and oil shale issues. Within Interior, we contacted
officials with BLM and the USGS. We asked officials at all of the
federal agencies and offices that were sponsoring federal research to
provide details on research that was water-related and to provide
costs for the water-related portions of these research projects. For
some projects, based on the nature of the research, we counted the
entire award as water-related. We identified 15 water-related oil
shale research projects. A detailed description of these projects is
in appendix II. To obtain additional details on the work performed
under these research projects, we interviewed officials with all the
sponsoring organizations and the performing organizations, including
the Colorado School of Mines, University of Utah, Utah Geological
Survey, Idaho National Laboratory, Los Alamos National Laboratory,
Argonne National Laboratory, and the USGS.
To assess additional needs for research and to evaluate any gaps
between research needs and the current research projects, we
interviewed officials with 14 organizations and four experts that are
authors of studies or reports we used in our analyses and that are
recognized as having extensive knowledge of oil shale and water
issues. The names of the 14 organizations appear in table 10. These
discussions involved officials with all the federal offices either
sponsoring or performing water-related oil shale research and state
agencies involved in regulating water resources.
Table 10: Agencies Contacted by GAO for Opinions on Research Needs:
BLM;
DOE Office of Naval Petroleum and Oil Shale Reserves (DOE NPOSR);
DOE National Energy Technology Laboratory (DOE NETL);
Bureau of Reclamation;
USGS;
Idaho National Laboratory;
Los Alamos National Laboratory;
Argonne National Laboratory;
University of Utah;
Colorado School of Mines;
Colorado River Water Conservation District;
Colorado Division of Water Resources;
Utah Division of Water Quality;
Colorado Geological Survey.
Source: GAO.
[End of table]
[End of section]
Appendix II: Descriptions of Federally Funded Water-Related Oil Shale
Research:
Research title: Water Related Issues Affecting Conventional Oil & Gas
Recovery and Oil Shale Development;
Sponsoring organization: DOE NETL;
Performing organization: Utah Geological Survey;
Total federal cost: $688,223;
Federal cost related to water: $688,223[A].
Research title: GIS Water Resource Infrastructure for Oil Shale;
Sponsoring organization: DOE NETL;
Performing organization: Colorado School of Mines;
Total federal cost: $883,972;
Federal cost related to water: $883,972[A].
Research title: Support for GIS Water Resource Infrastructure for Oil
Shale;
Sponsoring organization: DOE NETL;
Performing organization: Idaho National Laboratory;
Total federal cost: $261,769;
Federal cost related to water: $261,769[A].
Research title: Utah Center for Heavy Oil Research FY06[B];
Sponsoring organization: DOE NETL;
Performing organization: University of Utah;
Total federal cost: $1,442,376;
Federal cost related to water: $122,809[C].
Research title: Institute for Clean and Secure Energy FY08[B];
Sponsoring organization: DOE NETL;
Performing organization: University of Utah;
Total federal cost: $873,340;
Federal cost related to water: $154,937[C].
Research title: Institute for Clean and Secure Energy FY09[B];
Sponsoring organization: DOE NETL;
Performing organization: University of Utah;
Total federal cost: $2,585,715;
Federal cost related to water: $161,227[C].
Research title: Institute for Clean and Secure Energy FY10[B];
Sponsoring organization: DOE NETL;
Performing organization: University of Utah;
Total federal cost: $3,044,800;
Federal cost related to water: $160,160[C].
Research title: Carbon and Water Resources Impacts from Unconventional
Fuel Development in the Western Energy Corridor;
Sponsoring organization: DOE NPOSR;
Performing organization: Los Alamos National Lab;
Total federal cost: $1,968,000;
Federal cost related to water: $820,000[D].
Research title: Western Energy Corridor Initiative (support for Los
Alamos);
Sponsoring organization: DOE NPOSR;
Performing organization: Idaho National Laboratory;
Total federal cost: $500,000;
Federal cost related to water: $100,000[E].
Research title: Dynamic Impact Model and Information System to Support
Unconventional Fuels Development;
Sponsoring organization: Idaho National Laboratory;
Performing organization: Idaho National Laboratory;
Total federal cost: $600,000[F];
Federal cost related to water: $250,000[E,F].
Research title: Generation and Expulsion of Hydrocarbons from Oil
Shale;
Sponsoring organization: Idaho National Laboratory;
Performing organization: Idaho National Laboratory;
Total federal cost: $1,050,000[F];
Federal cost related to water: $90,000[E,F].
Research title: Near Field Impacts of In-Situ Oil Shale Development on
Water Quality;
Sponsoring organization: Idaho National Laboratory;
Performing organization: Idaho National Laboratory;
Total federal cost: $612,500[F];
Federal cost related to water: $612,500[E,F].
Research title: Nuclear Pathways to Energy Security;
Sponsoring organization: Idaho National Laboratory;
Performing organization: Idaho National Laboratory;
Total federal cost: $75,000[F];
Federal cost related to water: $12,500[E,F].
Research title: Common Data Repository and Water Resource Assessment
for the Piceance Basin, Western Colorado;
Sponsoring organization: BLM;
Performing organization: USGS;
Total federal cost: $110,000;
Federal cost related to water: $110,000[A].
Research title: Water: Groundwater Monitoring in Piceance Basin and
Yellow Creek Basin;
Sponsoring organization: BLM;
Performing organization: USGS;
Total federal cost: $410,000;
Federal cost related to water: $410,000[A].
Research title: Total;
Sponsoring organization: 15 projects;
Performing organization: [Empty];
Total federal cost: $15,105,695;
Federal cost related to water: $4,838,097.
Source: DOE and Interior agencies and offices.
[A] Entire award is considered water-related due to the nature of the
project.
[B] The University of Utah received four separate awards, each
covering a broad array of oil shale research over multiple years. The
awards included some water-related work. Examples of projects include
(1) Meeting Data Needs to Perform a Water Impact Assessment for Oil
Shale Development in the Uintah and Piceance Basins, (2) Effect of Oil
Shale Processing on Water Compositions, and (3) New Approaches to
Treat Produced Water and Perform Water Availability Impact Assessments
for Oil Shale Development.
[C] DOE NETL provided this estimate of the water-related portion of
the award.
[D] Los Alamos National Laboratory provided this estimate of the water-
related portion of the award.
[E] Idaho National Laboratory provided this estimate of the water-
related portion of the award.
[F] According to Idaho National Laboratory, some funding may be
nonfederal, but it provided no details.
[End of table]
[End of section]
Appendix III: Comments from the Department of the Interior:
United States Department of the Interior:
Office Of The Secretary:
Washington, DC 20240:
October 15, 2010:
Mr. Mark Gaffigan:
Director, Natural Resources and Environment:
Government Accountability Office:
441 G Street, N.W.
Washington, D.C. 20548:
Dear Mr. Gaffigan:
Thank you for the opportunity to review and comment on the Government
Accountability Office (GAO) draft report entitled, ENERGY-WATER NEXUS:
A Better and Coordinated Understanding of Water Resources Could Help
Mitigate the Impacts of Potential Oil Shale Development (GAO-11-35).
The Department of the Interior (DOI) generally concurs with GAO's
findings and recommendations. The report focused on the research and
coordination efforts of the Bureau of Land Management (BLM) and the
United States Geological Survey (USGS) related to oil shale
development.
The BLM and USGS continue to collaborate and collect baseline data in
the Piceance Basin and to design and implement a groundwater and
surface water monitoring network. Within the Piceance Basin, natural
gas and oil development is occurring along with oil shale research and
development activities. The USGS has compiled water quality data and
continues to analyze groundwater and surface water to provide a
baseline water quality assessment and identify data gaps and
redundancies. This information can be used to understand current
conditions, inform future monitoring in the basin, and as part of the
evaluation performed under regulatory processes involved in the
approval of large-scale commercial oil shale development.
The report recommends that the USGS and BLM "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 impacts from oil shale
development in the Green River Formation." Implementation of this
recommendation is underway. The USGS efforts for surface-water
monitoring provide surface water quantity and quality monitoring at
sites within these basins. A more comprehensive effort would include a
work plan for gathering additional surface-water quantity data,
groundwater monitoring, aquifer testing, and water-quality monitoring.
In addition, the USGS Data Repository project, referred to in the
report, will be used to better define data gaps in the baseline
groundwater and surface water quality and quantity data currently
existing for the Piceance and Uintah Basins.
The GAO next recommends that the BLM and USGS "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." The BUM and
USGS are working on shared needs for regional groundwater modeling.
The Department agrees that data compilation and regional modeling
should be performed prior to the approval of large-scale oil shale
development. Modeling of the impact to regional groundwater and
groundwater/surface water interaction requires accurate estimation of
potential water use from the various oil shale development
technologies as well as accurate baseline hydrologic information. The
six new Research, Development and Demonstration (R, D&D) leases on
Federal land in Colorado and Utah will allow industry to test various
technologies to determine if production can occur in commercial
quantities, and to develop an accurate determination of potential
water use for each technology. Interior will then assess the economic
and technological challenges involved with the R. D&D projects.
The third recommendation is for the BLM and USGS to "coordinate with
the Department of Energy and state agencies with regulatory authority
over water resources in implementing these recommendations, and to
provide a mechanism for water-related research collaboration and
sharing of results." Both bureaus are also working to improve such
coordination. Currently, the bureaus are coordinating with state and
local regulatory authorities in the many arenas of oil shale
development and will build greater collaboration. As the results or
the R, D&D leases become known, non-proprietary information will be
shared within the Department and with Department of Energy.
If you have any questions, please contact LaVanna Stevenson-Harris,
KAI Audit Liaison Officer, at 202-912-7088, or Rebecca Bageant, USGS
Audit Liaison Officer, at 703-648-4328.
Sincerely,
Signed by:
Rhea S. Suh:
Assistant Secretary:
Policy, Management and Budget:
[End of section]
Appendix IV: Comments from the Department of Energy:
Department of Energy:
Washington, DC 20585:
October 19, 2010:
Mr. Mark E. Gaffigan:
Director:
Natural Resources and Environment Team:
U.S. Government Accountability Office:
441 G Street, NW, Mail 2T23A:
Washington, DC 20548:
Dear Mr. Gaffigan:
Thank you for the opportunity to review the Government Accountability
Office (GAO) draft report entitled, "Energy-water Nexus: A Better and
Coordinated Understanding of Water Resources Could Help Mitigate the
Impacts of Potential Oil Shale Development." Enclosed pleased find the
U.S. Department of Energy's comments on the draft report.
If you have any questions or comments please contact Mr. David F.
Johnson, Deputy Assistant Director. Office of Petroleum Reserves, of
my staff at (202) 586-4733.
Sincerely,
Signed by:
James J. Markowsky:
Assistant Secretary:
Office of Fossil Energy:
Enclosure: DOE Comments on Draft GAO Report:
[End of letter]
Department of Energy Comments On GAO Draft Report:
"Energy-Water Nexus: A Better and Coordinated Understanding of Water
Resources Could Help Mitigate the Impacts of Oil Shale Development
(GAO-11-35)"
The following comments are based on comments received from Idaho
National Laboratory (INL), Los Alamos National Laboratory (LANL), and
the Office of Petroleum Reserves (OPR):
1. The Department of Energy (DOE) recognizes the need discussed in the
Report for a more comprehensive and integrated cross-
industry/government approach for determining water requirements,
availability, and impacts associated with oil shale development (see
for example Report Highlights). Recognition of this need, as well as a
potential solution, are discussed in the Strategic Plan described by
Citation 25, a document that was prepared by representatives from
industry, national laboratories, universities, and Federal, state, and
local governments. Consideration should be given to including
appropriate aspects of the Strategic Plan in the Report.
2. Water requirements for oil shale in-situ technologies are
overstated, and water available for an oil shale industry and all
other uses is understated (see pages 17-21 and 25-36, and Tables 1, 3,
4, and 5, and Figure 4).
Water Requirements: The two primary in-situ processes are by Exxon
Mobil Exploration Company (Exxon) and Shell Exploration and Production
Company (Shell).
* Exxon -- Exxon reports that life cycle water requirements are 1-2
barrels of water per barrel of oil produced, taking into account
aggressive water conservation technologies (like utilizing produced
water/process waste water, via water treating and recycling; using air
cooled power generation; using natural gas instead of water for
upgrading; and using natural gas instead of coal for power
generation.)[Footnotes 1, 4, 7, 9]
* Shell -- Shell representatives have stated publicly that life cycle
water requirements have been studied, and that for planning purposes
they are using 3 barrels per barrel, based on using aggressive water
conservation technologies. They have also stated that ultimately they
should be able to improve on this number.[Footnotes 2, 4, 20]
* The Report dismisses water treating and recycling because the
technologies have not been shown to be commercially viable (see page
16 of the Report). Challenges for oil shale are well within the bounds
of commercially viable water treating/recycling technologies currently
in operation in other industries in the U.S.; and, as such, the
private sector is clearly planning to use them.[Footnotes 1, 3, 4, 7,
20]
* The Report dismisses the use of produced water due to State-imposed
legal limitations (see page 16 of the Report). Utilizing produced
water for oil shale production is well within the bounds of how
produced water is currently being used under these same limitations in
the oil and gas and other industries in the U.S.; as such, the private
sector is clearly planning to utilize produced water (within imposed
legal limitations).[Footnotes 1, 3, 4, 6, 7, 20]
* Thus, the water requirements range should be 1-3 barrels per barrel,
not 0.8-12, as shown. The 12 barrel per barrel figure is based on a
controversial report that was completed without sufficient industry
input. 6 The primary complaint was that the URS report did not
properly take into account aggressive utilization of water
conservation technologies. The report has been reworked by AMEC Earth
& Environmental Corporation (AMEC) with private industry input, and a
draft of the AMEC report has been publicly released showing a life
cycle high number of 1.59 barrels per barrel. The AMEC report
addressed comments received from National Oil Shale Association
(NOSA), which incorporated comments from Exxon and Shell.[Footnotes 4,
5, 6, 7, 9, 20]
* On the basis of the foregoing, the Report should be revised to more
fully describe water conservation technologies, with associated
adjustments for in-situ water requirements.
Water Availability — The Report provides an analysis showing how using
just the water available on the White River at Meeker would limit the
size of an oil shale industry (see pages 32-36, and Tables 3, 4, and
5). This implies that the size of an industry for the entire
3-State Green River Formation is limited by water available at Meeker.
In actuality, water to support the entire industry would be drawn from
many locations within the Upper Colorado River Basin. The Report
should be revised to show how water available from the entire basin
might limit a 3-State oil shale industry. Numerous data sources on
Upper Colorado water flows are publicly available. See Citations 8, 9,
10, and 21.
3. The Report gives the impression that all oil shale technologies are
speculative, and that proving them to be commercially viable will be
difficult, requiring a very long period of time, with uncertain
outcomes (see pages 7 and 10). This is not an accurate represent-
action of the state of the technologies, or of the expected timing of
first commercial production. The Report should be revised to address
these issues.
* Advanced oil shale technologies have been under research for many
years at a cost of billions of dollars. Much has been accomplished --
for some technologies; all, or almost all, technical questions
impeding commercialization have been answered.[Footnotes 11, 12, 13,
14]
* The great majority of the components of the various oil shale
technologies are not new; most have been in use in the oil and gas and
other industries in the U.S. and elsewhere for many years -- e.g.,
mining, heating formations, fracturing formations, oil and gas
production, environmental mitigation, upgrading, transporting,
refining, etc. Much of the oil shale challenge is to integrate these
components for oil shale in a manner that is economically and
environmentally sustainable. This has been the primary focus of all of
the research undertaken to date. Although this endeavor is very
capital intensive, it is not technically difficult, and expectations
have been generally optimistic, evidence of which is the billions of
private research and development (R&D) dollars committed to date. The
biggest obstacles to investment in the development of a viable oil
shale industry in the U.S. have not been the state of the technology,
but rather the regulatory uncertainty, and lack of access to resources
on Federal lands in the western U.S.[Footnotes 11, 12, 13, 14, 22, 23,
25]
* Red Leaf Resources Inc (Red Leaf): The Report dismisses Red Leaf
because it has not formally published detailed data on water needs
(see page 50).
- Red Leaf is a small start-up company that is funded with private
capital. As such, it is not focused on publishing. In 2009, Red Leaf
successfully completed a large field pilot/semi-works demonstration
project. Based on this success Red Leaf has been funded to design and
construct a 30,000 barrels per day commercial project that is
due to begin operation within 2-3 years. Engineering is in progress.
In order to permit its demonstration and commercial projects, detailed
water studies were completed. Results have been presented at
conferences and symposia.[Footnotes 15, 16, 18]
- Red Leaf's extraction process requires almost no water, and it is
potentially applicable to any near-surface deposits, an enormous
resource target.[Footnotes 15, 16, 18]
* Oil Shale Exploration Company's (OSEC) surface retort technology has
been in commercial operation in Brazil since 1992, and is proven
there. Production capacity is about 4,600 barrels per day.[Footnotes
10, 17]
- All that remains for OSEC to do is adapt the technology as needed to
make it economic to operate in the U.S. regulatory environment.
- OSEC completed a feasibility study in 2009 which found no need for a
demonstration project and estimated operating costs to be $29-35 per
barrel.[Footnotes 10, 17]
- OSEC is designing a 12,500 barrel per day commercial plant that is
funded and expects to begin operation in 2016, expanding to 50,000
barrels/day by 2027.[Footnotes 10, 17]
- The OSEC technology is potentially applicable to any near-surface or
mineable deposits, an enormous resource target.[Footnotes 10, 17]
* There are several other technologies that are also promising,
especially the technology by Enshale Inc.{Footnote 19]
* The Report should be revised to more fully address Red Leaf, OSEC,
and other technologies.
* The Report should also more fully reflect the extensive history of
oil shale research in the U.S., including ongoing public and private
efforts. [Footnotes 11, 24, 25]
Footnotes/citations:
1. Thomas, Michele M., et al. (Exxon Mobil Exploration Company):
"Responsible Development of Oil Shale" Presented to 29" Oil Shale
Symposium, October 19-21, 2009.
2. US General Accountability Office: "Energy-Water Nexus: A Better and
Coordinated Understanding of Water Resources Could Help Mitigate the
Impacts of Oil Shale Development (GAO-11-35) pg. 52, footnote "g".
3. Shell Exploration and Production Company "Plan of Operations - Oil
Shale Test Project" Prepared for US Bureau of Land Management,
February 15, 2006.
4. Harding, Ben (AMEC Earth & Environmental Corporation) "Energy
Development Water Needs Assessment and Water Supply Alternative
Analysis" presentation to Yampa River Basin Roundtable Meeting, July
21, 2010.
5. National Oil Shale Association "Position Paper: Studies
Misrepresent Future Oil Shale Impacts" April 2009.
www.Oilshaleassoc.org.
6. United Research Services (DRS) Corp. "Energy Development Water
Needs Assessment (Phase I Report)", prepared for Colorado, Yampa, and
White River Basin Roundtables Energy Subcommittee. September 2008.
7. Harding, Benjamin (AMEC): "Oil Shale Direct Water Use Estimates -
Draft" Memorandum to Joint Energy Water Needs Subcommittee, April 13,
2010.
http://www.crwcd.org/media/upload/Water_and_Energy_Oil_Share_Direct_Wate
r_use_final_Draft_20100411.pdf.
8. Wood, Thomas, et al. "Environmental Aspects of CO2 and Water
Management" Presentation to 27' Oil Shale Symposium, Colorado School
of Mines. October 15-17, 2007. Slides 7-9.
9. Harding, Benjamin (AMEC) "Energy Development Water Needs Assessment
and Water Supply Alternative Analysis: The Promise and Peril of Oil
Shale" February 5, 2010. Slides 9-13.
10. Aho, Gary (Oil Shale Exploration Company) "White River Oil Shale
Project 2009 Update" Presentation to 29" Oil Shale Symposium, October
19-21, 2009.
11. "Secure Fuels from Domestic Resources: The Continuing Evolution of
America's Oil Shale and Tar Sands Industries" prepared by INTEK, Inc.
for US Department of Energy, September 2010.
12. Strategic Significance of America's Oil Shale Resource; Volume I
Assessment of Strategic Issues and Volume II Oil Shale Resources,
Technology and Economics. Prepared for the U.S. Department of Energy
Office of Naval Petroleum and Oil Shale Reserves, March 2004.
13. US Department of Energy "Joint USA -Estonia Oil Shale Research and
Utilization program: Phase I, Phase II, and Phase III Reports and
Executive Summary" Compilation of Reports, 2009.
14. US Congress, Office of Technology Assessment "An Assessment of Oil
Shale Technology" June 1980.
15. Patten, James, et al (Red Leaf Resources Inc) "The EcoShale
Process: Field Pilot Construction, Operation, and Results"
Presentation to 29" Oil Shale Symposium, October 19-21, 2009.
16. "Secure Fuels from Domestic Resources: The Continuing Evolution of
America's Oil Shale and Tar Sands Industries" prepared by INTEK, Inc
for US Department of Energy September 2010. - Red Leaf company profile.
17. "Secure Fuels from Domestic Resources: The Continuing Evolution of
America's Oil Shale and Tar Sands Industries" prepared by INTEK, Inc
for US Department of Energy September 2010. - OSEC company profile.
18. Demmer, Anton (Red Leaf Resources Inc) "The EcoShale In-Capsule
Retorting Technology" Presentation to International Oil Shale
Symposium, Tallinn, Estonia June 2009.
19. "Secure Fuels from Domestic Resources: The Continuing Evolution of
America's Oil Shale and Tar Sands Industries" prepared by INTEK, Inc.
for US Department of Energy, September 2010. - Enshale Inc profile.
20. "Energy Water Use Scenarios" Memorandum to Joint Energy Water
Needs Subcommittee, June 29, 2010.
21. US Bureau of Land Management: "Final Programmatic Environmental
Impact Statement (PETS)", September 2008.
http://www.ostseis.anl.gov/els/guide/index.cfm.
22. Task Force on Strategic Unconventional Fuels, Initial Report of
Findings and Recommendations: Development of America's Strategic
Unconventional Fuels Resources, September 2006.
23. Task Force on Strategic Unconventional Fuels, Development of
America's Strategic Unconventional Fuels; Volumes I-III, September
2007.
24. "Oil Shale Research In the United States: Profiles of Oil Shale
Research and Development Activates in Universities, National
Laboratories, and Public Agencies" prepared by INTEK, Inc. for US
Department of Energy, September 2010.
25. Ad Hoc Unconventional Fuels Working Group: "Strategic Plan:
Unconventional Fuels Development in the Western Energy Corridor"
November 2008.
[End of section]
Appendix V: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Mark Gaffigan, (202) 512-3841 or gaffiganm@gao.gov Anu Mittal, (202)
512-3841 or mittala@gao.gov:
Staff Acknowledgments:
In addition to the individuals named above, Dan Haas (Assistant
Director), Ron Belak, Laura Hook, and Randy Jones made major
contributions to this report. Other individuals who made significant
contributions were Charles Bausell, Virginia Chanley, Alison O'Neill,
Madhav Panwar, and Barbara Timmerman.
[End of section]
Footnotes:
[1] The Rand Corporation, a nonprofit research organization, estimates
that between 30 and 60 percent of the oil shale in the Green River
Formation can be recovered. At the midpoint of this estimate, almost
half of the 3 trillion barrels of oil would be recoverable.
[2] GAO, Energy-Water Nexus: Improvements to Federal Water Use Data
Would Increase Understanding of Trends in Power Plant Water Use,
[hyperlink, http://www.gao.gov/products/GAO-10-23] (Washington, D.C.:
Oct. 16, 2009) and Energy-Water Nexus: Many Uncertainties Remain about
National and Regional Effects of Increased Biofuel Production on Water
Resources, [hyperlink, http://www.gao.gov/products/GAO-10-116]
(Washington, D.C.: Nov. 30, 2009).
[3] Physically available, according to the state of Colorado, is the
actual or observed amount of water flowing in a stream. This amount
can vary from year to year, based on the amount of precipitation and
snow pack. Legally available, according to the state of Colorado, is
the portion of physically available flow that could be developed
without injury to other water rights or compacts.
[4] An aquifer is an underground layer of rock or unconsolidated sand,
gravel, or silt that will yield groundwater to a well or spring.
[5] Reclamation is an attempt to mitigate the adverse impacts of
heating the subsurface zone, such as repeated rinsing with water to
remove any residual hydrocarbons that were not economically extracted.
[6] For a detailed discussion of the literature we reviewed and the
experts to whom we spoke, see appendix I.
[7] In directional drilling, the company starts drilling a borehole on
the disturbed ground surface and angles the well so that the bottom of
the hole occurs below the undisturbed surface.
[8] Porosity is the amount of space within an aquifer that can be
filled with groundwater. Permeability is the ability of a material,
such as an aquifer or rock formation, to transmit liquids like water.
[9] In Shell's original process, a ring of bore holes is drilled
around the zone to be isolated. Liquid ammonia is circulated down the
boreholes, which freezes the groundwater in the immediate vicinity,
creating a ring of ice around the isolated zone.
[10] One barrel contains 42 gallons.
[11] The state of Colorado has promulgated extensive regulations
regarding the nature of water produced from oil and gas operations.
According to Colorado state officials, the transport and use of this
water offsite to oil shale operations may be restricted.
[12] For a complete list of the studies we reviewed and a detailed
description of our methodology, see appendix I.
[13] Shell and the URS Corporation--a contractor to the state of
Colorado--conducted the two studies that examine water needs for all
five groups of activities comprising the life cycle of in-situ oil
shale development. For planning purposes, Shell cites 3 barrels of
water needed per barrel of oil. URS estimates that 5.2 barrels of
water would be needed per barrel of oil.
[14] We calculated that AMEC's estimated power requirements exceeded
by over seven times the coal-fired generating capacity of northwest
Colorado, which consists of this nearest plant and one other smaller
plant.
[15] The National Oil Shale Association provided this estimate for
upgrading shale oil. This range also contains data for upgrading oil
from surface retorts, which we could not segregate. Conversations with
an oil shale industry representative suggest that water estimates for
upgrading oil derived from in-situ operations may lie toward the
bottom of this range.
[16] More information on studies we examined appears in appendix I.
Experts consider some of the data within the OTA study to still be
relevant because certain surface retort technologies are similar to
those being tested today.
[17] The two studies that examined water needs for all five groups of
activities that comprise the life cycle of oil shale development by
mining and surface retorting are included in the OTA report. Both
studies involve the Paraho-Direct Process. These estimates are 2.3 and
2.8 barrels of water per barrel of oil.
[18] We multiplied these power requirements by the amounts of water
needed to generate power as the amounts appear in GAO, Energy-Water
Nexus: Improvements to Federal Water Use Data Would Increase
Understanding of Trends in Power Plant Water Use, [hyperlink,
http://www.gao.gov/products/GAO-10-23] (Washington, D.C.: Oct. 16,
2009), p. 20.
[19] Western Resource Advocates, Water on the Rocks: Oil Shale Water
Rights in Colorado (Boulder, Colo., 2009).
[20] A conditional water right is a water right that has not yet been
put to beneficial use. Its date of application establishes its
priority among other water rights.
[21] An acre-foot is the amount of water that would fill an area of
one acre to a depth of one foot. An acre-foot contains 325,851
gallons, or 7,758 barrels, and is roughly equal to the amount of water
that a family of four will use in a year.
[22] An absolute water right is a water right that has been put to
beneficial use.
[23] Shell also experienced considerable formal opposition to its
proposal from 25 groups, some of which was for environmental reasons.
[24] Year-to-year flows on rivers can vary significantly with annual
precipitation. However, officials with the state of Colorado said that
they are comfortable using average annual flows.
[25] This estimate represents all of the groundwater and surface water
that can be used in the Uintah Basin, but does not take into account
any current withdrawals from streams and rivers.
[26] Many research projects involve water and nonwater issues. For
projects that include nonwater-related segments, we obtained estimates
of the amount of the project spent on water related tasks.
[27] Most projects run for 2 to 3 years. Some have been completed,
while others are still ongoing.
[28] A general description of the process DOE uses to select research
proposals can be found in GAO, Research and Development: DOE Could
Enhance the Project Selection Process for Government Oil and Natural
Gas Research, [hyperlink, http://www.gao.gov/products/GAO-09-186]
(Washington, D.C.: Dec. 29, 2008).
[29] In January 2010, BOR initiated the Colorado River Basin Water
Supply and Demand Study at a federal cost of $1 million. Although not
directed at oil shale, this 2-year study's objective is to define and
resolve current and future imbalances between the supply and demand
for water within the Colorado River Basin over the next 50 years.
[30] NEPA requires all federal agencies to consider the environmental
impacts of their actions and decisions. It requires an analysis and a
detailed statement of the environmental impact of any proposed major
federal action which significantly affects the environment.
[31] 40 C.F.R. §1505.2 (c).
[32] The NEPA Task Force Report to the Council on Environmental
Quality: Modernizing NEPA Implementation (September 2003).
[33] USGS, Colorado Water Science Center, Regional Framework for Water-
Resources Monitoring Related to Energy Exploration and Development
(Sept. 30, 2007).
[34] GAO, Results-Oriented Government: Practices that Can Help Enhance
and Sustain Collaboration among Federal Agencies, [hyperlink,
http://www.gao.gov/products/GAO-06-15] (Washington, D.C.: Oct 21,
2005).
[35] GAO, Watershed Management: Better Coordination of Data Collection
Efforts Needed to Support Key Decisions, [hyperlink,
http://www.gao.gov/products/GAO-04-382] (Washington, D.C.: June 7,
2004).
[36] National Research Council of the National Academies, Confronting
the Nation's Water Problems: The Role of Research (2004).
[37] Subcommittee on Water Availability and Quality, National Science
and Technology Council, A Strategy for Federal Science and Technology
to Support Water Availability and Quality in the United States
(Washington, D.C., September 2007).
[38] This research was funded by ExxonMobil, Shell, and Total
Exploration and Production.
[39] CDM, Statewide Water Supply Initiative, a report contracted by
the Colorado Water Conservation Board, November 2004; and CDM
Colorado's Water Supply Future: State of Colorado 2050 Municipal and
Industrial Water Use Projections, a report contracted by the Colorado
Water Conservation Board, June 2009.
[40] AECOM Colorado River Water Availability Study (Draft Report), a
report contracted by the Colorado Water Conservation Board, March 2010.
[41] Utah Division of Water Resources, Utah's Water Resources:
Planning for the Future (May 2001); Municipal and Industrial Water
Supply and Uses in the Uintah Basin (Data Collected for Calendar-Year
2005) (December 2007); and Utah State Water Plan, Uintah Basin
(December 1999).
[End of section]
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