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Carbon capture and sequestration (or storage)—known as CCS—has attracted interest as a
measure for mitigating global climate change because potentially large amounts of carbon dioxide
(CO2) emitted from fossil fuel use in the United States could be captured and stored underground.
Large, industrial sources of CO2, such as electricity-generating plants, are the most likely initial
candidates for CCS because they are predominantly large, single-point sources. Electricity-
generating plants contribute approximately one-third of U.S. CO2 emissions from fossil fuels.
Congressional interest has grown markedly in CCS as part of a legislative strategy to address
climate change. On February 13, 2009, Congress passed the American Recovery and
Reinvestment Act (ARRA, P.L. 111-5) of 2009, which included $3.4 billion for projects and
programs related to CCS. Of that amount, $1.52 billion would be made available for a
competitive solicitation for industrial carbon capture and energy efficiency improvement projects,
$1 billion for fossil energy research and development, and $800 million for U.S. Department of
Energy Clean Coal Power Initiative Round III solicitations, which specifically target coal-based
systems that capture and sequester, or reuse, CO2 emissions. The $3.4 billion contained in ARRA
greatly exceeds the federal government’s cumulative outlays for CCS research and development
since 1997.
The large and rapid influx of funding for industrial-scale CCS projects may accelerate
development and deployment of CO2 capture technologies. Currently, large U.S. power plants do
not capture large volumes of CO2 for CCS, even though technology is available that can
potentially remove 80%-95% of CO2 from a point source. This is due to the absence of either an
economic incentive (i.e., a price for captured CO2) or a regulatory requirement to curtail CO2
emissions. In addition, DOE estimates that CCS costs between $100 and $300 per metric ton
(2,200 pounds) of carbon emissions avoided using current technologies. Those additional costs
mean that power plants with CCS would require more fuel, and costs per kilowatt-hour would be
higher than for plants without CCS.
After CO2 is captured from the source and compressed into a liquid, pipelines or ships would
likely convey the captured CO2 to storage sites to be injected underground. Three main types of
geological formations are being considered for storing large amounts of CO2 as a liquid: oil and
gas reservoirs, deep saline reservoirs, and unmineable coal seams. The deep ocean also has a huge
potential to store carbon; however, direct injection of CO2 into the deep ocean is still
experimental, and environmental concerns have forestalled planned experiments in the open
ocean. Mineral carbonation—reacting minerals with a stream of concentrated CO2 to form a solid
carbonate—is well understood, but it is still an experimental process for storing large quantities
of CO2.
The increase in funding for CCS provided for in ARRA may lead to less expensive and better
technologies for capturing large quantities of CO2. Without a carbon price or a regulatory
requirement to cap CO2 emissions, however, it will be difficult to predict or evaluate how the
technology would be deployed throughout the U.S. energy sector. By comparison, transporting,
injecting, and storing CO2 underground may be less daunting. A large pipeline infrastructure for
transporting CO2 could be very costly, however, and considerable uncertainty remains over how
large quantities of injected CO2 would be permanently stored underground. To help resolve these
uncertainties, DOE has initiated seven large-scale CO2 injection tests in a variety of geologic
reservoirs that are to take place over the next several years.
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Introduction ..................................................................................................................................... 6
The American Recovery and Reinvestment Act (ARRA) of 2009.................................................. 7
Capturing CO2 ................................................................................................................................. 8
Post-Combustion Capture ......................................................................................................... 8
Pre-Combustion Capture........................................................................................................... 9
Oxy-Fuel Combustion Capture ................................................................................................. 9
Transportation................................................................................................................................ 10
Sequestration in Geological Formations ........................................................................................11
Oil and Gas Reservoirs.............................................................................................................11
The In Salah and Weyburn Projects .................................................................................. 12
Advantages and Disadvantages......................................................................................... 12
Deep Saline Reservoirs ........................................................................................................... 12
The Sleipner Project.......................................................................................................... 13
Advantages and Disadvantages......................................................................................... 13
Unmineable Coal Seams ......................................................................................................... 14
Advantages and Disadvantages......................................................................................... 14
Geological Storage Capacity for CO2 in the United States ........................................................... 15
Deep Ocean Sequestration............................................................................................................. 16
Advantages and Disadvantages......................................................................................... 17
Mineral Carbonation...................................................................................................................... 18
Advantages and Disadvantages......................................................................................... 18
Costs for CCS................................................................................................................................ 19
The DOE Carbon Capture and Sequestration Program ................................................................. 21
DOE CCS Research and Development Funding Through FY2008 ........................................ 22
Loan Guarantees and Tax Credits ..................................................................................... 22
Regional Carbon Sequestration Partnerships .......................................................................... 23
FutureGen................................................................................................................................ 23
Issues for Congress........................................................................................................................ 24
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Figure 1. Simplified Illustration of Post-Combustion CO2 Capture................................................ 8
Figure 2. Simplified Illustration of Pre-Combustion CO2 Capture ................................................. 9
Figure 3. Simplified Illustration of Oxy-Fuel CO2 Capture .......................................................... 10
Figure B-1. Avoided Versus Captured CO2 ................................................................................... 29
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Table 1. Sources for CO2 Emissions in the United States from Combustion of Fossil
Fuels ............................................................................................................................................. 6
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Table 2. Geological Sequestration Potential for the United States and Parts of Canada .............. 16
Table 3. Estimates of Additional Costs of Selected Carbon Capture Technology......................... 20
Table 4. Estimates of CCS Costs at Different Stages of Development ......................................... 20
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Appendix A. Carbon Sequestration Legislation in the 110th Congress.......................................... 27
Appendix B. Avoided CO2............................................................................................................. 29
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Author Contact Information .......................................................................................................... 29
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Carbon capture and sequestration (or storage)—known as CCS—is capturing carbon at its source
and storing it before its release to the atmosphere. CCS would reduce the amount of carbon
dioxide (CO2) emitted to the atmosphere despite the continued use of fossil fuels. An integrated
CCS system would include three main steps: (1) capturing and separating CO2; (2) compressing
and transporting the captured CO2 to the sequestration site; and (3) sequestering CO2 in
geological reservoirs or in the oceans. As a measure for mitigating global climate change, CCS
has attracted congressional interest because several projects in the United States and abroad—
typically associated with oil and gas production—are successfully capturing, injecting, and
storing CO2 underground, albeit at relatively small scales. The oil and gas industry in the United
States injects approximately 48 million metric tons of CO2 underground each year to help recover
oil and gas resources (enhanced oil recovery, or EOR).1 Also, potentially large amounts of CO2
generated from fossil fuels—as much as one-third of the total CO2 emitted in the United States,
over 2 billion metric tons per year—could be eligible for large-scale CCS.2
Fuel combustion accounts for 94% of all U.S. CO2 emissions.3 Electricity generation contributes
the largest proportion of CO2 emissions compared to other types of fossil fuel use in the United
States. (See Table 1.) Electricity-generating plants are among the most likely initial candidates
for capture, separation, and storage, or reuse of CO2 because they are predominantly large, single-
point sources for emissions. Large industrial facilities, such as cement-manufacturing, ethanol, or
hydrogen production plants, that produce large quantities of CO2 as part of the industrial process
are also good candidates for CO2 capture and storage.4
Table 1. Sources for CO2 Emissions in the United States
from Combustion of Fossil Fuels
Sources CO2 Emissionsa
Percent of Totalb
Electricity generation
2,273.3
41%
Transportation 1,856.0
33%
Industrial 862.2
15%
Residential 326.5
6%
Commercial 210.1
4%
Total 5,583.0
100%
Source: U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Emissions and Sinks: 1990-
2006, Table ES-3; see http://epa.gov/climatechange/emissions/usinventoryreport.html.
a. CO2 emissions in millions of metric tons for 2006; excludes emissions from U.S. territories.
1 U.S. DOE, Carbon Sequestration Through Enhanced Oil Recovery, National Energy Technology Laboratory (March,
2008), at http://www.netl.doe.gov/publications/factsheets/program/Prog053.pdf.
2 DOE estimates that large, fossil-fuel power plants account for one-third of all U.S. CO2 emissions; see
http://www.fossil.energy.gov/programs/sequestration/overview.html.
3 U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Emissions and Sinks: 1990-2006, p. ES-
7. The percentage refers to U.S. emissions in 2006; see http://epa.gov/climatechange/emissions/usinventoryreport.html.
4 Intergovernmental Panel on Climate Change (IPCC) Special Report: Carbon Dioxide Capture and Storage, 2005.
(Hereafter referred to as IPCC Special Report.)
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b. Total does not sum to 100% because of rounding.
Congressional interest in CCS, as part of legislation addressing climate change, is growing. In its
first month, the 111th Congress passed the American Recovery and Reinvestment Act (ARRA) of
2009, which included $3.4 billion for CCS-related activities. In the 110th Congress, several bills
that would have established comprehensive cap-and-trade programs for limiting greenhouse gas
emissions also included provisions for geologic sequestration. (See Appendix A for a discussion
of legislation in the 110th Congress.) Comprehensive cap-and-trade legislation in the 111th
Congress will likely also include provisions for CCS. At issue for Congress is whether the
“technology-push” approach of investing in research and development, such as the large influx of
funding provided in ARRA, will spur commercial deployment of CCS even without a market
demand—created through a price mechanism or regulatory requirement. Even if CCS technology
becomes more efficient and cheaper as a result of federal investment in R&D, few companies
may have the incentive to install such technology unless they are required to do so.
This report covers only CCS and not other types of carbon sequestration activities whereby CO2
is removed from the atmosphere and stored in vegetation, soils, or oceans. Forests and
agricultural lands store carbon, and the world’s oceans exchange huge amounts of CO2 from the
atmosphere through natural processes.5
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Funding for carbon capture and sequestration technology may increase substantially as a result of
enactment of ARRA (P.L. 111-5). In the compromise legislation considered in conference on
February 11, 2009, the conferees agreed to provide $3.4 billion through FY2010 for fossil energy
research and development. Of that amount, $1.52 billion would be made available for a
competitive solicitation for industrial carbon capture and energy efficiency improvement projects,
according to the explanatory statement accompanying the legislation. This provision likely refers
to a program for large scale demonstration projects that capture CO2 from a range of industrial
sources. A small portion of the $1.52 billion would be allocated for developing innovative
concepts for reusing CO2, according to the explanatory statement. Of the remaining $1.88 billion,
$1 billion would be available for fossil energy research and development programs. The
explanatory statement does not specify which program or programs would receive funding,
however, or how the $1 billion would be allocated. Of the remaining $880 million, the conferees
agreed to allocate $800 million to the DOE Clean Coal Power Initiative Round III solicitations,
which specifically target coal-based systems that capture and sequester, or reuse, CO2 emissions.
Lastly, $50 million would be allocated for site characterization activities in geologic formations
(for the storage component of CCS activities), $20 million for geologic sequestration training and
research, and $10 million for unspecified program activities.
5 For more information about carbon sequestration in forests and agricultural lands, see CRS Report RL31432, Carbon
Sequestration in Forests, by Ross W. Gorte; CRS Report RL33898, Climate Change: The Role of the U.S. Agriculture
Sector, by Renée Johnson, and CRS Report R40186, Biochar: Examination of an Emerging Concept to Mitigate
Climate Change, by Kelsi S. Bracmort. For more information about carbon exchanges between the oceans, atmosphere,
and land surface, see CRS Report RL34059, The Carbon Cycle: Implications for Climate Change and Congress, by
Peter Folger.
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If the bulk of the $3.4 billion agreed to by conferees for fossil energy research and development is
used for CCS activities, it would represent a substantial infusion of funding compared to current
spending levels. It would also be a large and rapid increase in funding over what DOE spent on
CCS cumulatively over the 11 years between FY1997 through FY2007 (slightly less than $500
million). Moreover, the bulk of DOE’s CCS program would shift to the capture component of
CCS, unless funding for the storage component increases commensurately in annual
appropriations. The large and rapid increase in funding, compared to the magnitude and pace of
previous CCS spending, may raise questions about how efficiently the new funding could be used
to spur innovation for carbon capture technology.
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The first step in CCS is to capture CO2 at the source and produce a concentrated stream for
transport and storage. Currently, three main approaches are available to capture CO2 from large-
scale industrial facilities or power plants: (1) post-combustion capture, (2) pre-combustion
capture, and (3) oxy-fuel combustion capture. For power plants, current commercial CO2 capture
systems could operate at 85%-95% capture efficiency.6 Techniques for capturing CO2 have not
yet been applied to large power plants (e.g., 500 megawatts or more).7
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This process involves extracting CO2 from the flue gas following combustion of fossil fuels or
biomass. Several commercially available technologies, some involving absorption using chemical
solvents, can in principle be used to capture large quantities of CO2 from flue gases. U.S.
commercial electricity-generating plants currently do not capture large volumes of CO2 because
they are not required to and there are no economic incentives to do so. Nevertheless, the post-
combustion capture process includes proven technologies that are commercially available today.
Figure 1 shows a simplified illustration of this process.
Figure 1. Simplified Illustration of Post-Combustion CO2 Capture
Source: Scottish Centre for Carbon Storage. Figure available at http://www.geos.ed.ac.uk/sccs/capture/
precombustion.html
6 IPCC Special Report, p. 107.
7 Ibid., p. 25.
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This process separates CO2 from the fuel by combining it with air and/or steam to produce
hydrogen for combustion and a separate CO2 stream that could be stored. The most common
technologies today use steam reforming, in which steam is employed to extract hydrogen from
natural gas.8 In the absence of a requirement or economic incentives, pre-combustion
technologies have not been used for power systems, such as natural gas combined-cycle power
plants. Figure 2 shows a simplified illustration of this process.
Pre-combustion capture of CO2 is viewed by some as a necessary requirement for coal-to-liquid
fuel processes, whereby coal can be converted through a catalyzed chemical reaction to a variety
of liquid hydrocarbons. Concerns have been raised because the coal-to-liquid process releases
CO2, and the end product—the liquid fuel itself—further releases CO2 when combusted. Pre-
combustion capture during the coal-to-liquid process would reduce the total amount of CO2
emitted, although CO2 would still be released during combustion of the liquid fuel used for
transportation or electricity generation.9
Figure 2. Simplified Illustration of Pre-Combustion CO2 Capture
Source: Scottish Centre for Carbon Storage. Figure available at http://www.geos.ed.ac.uk/sccs/capture/
precombustion.html.
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This process uses oxygen instead of air for combustion and produces a flue gas that is mostly CO2
and water, which are easily separable, after which the CO2 can be compressed, transported, and
stored. This technique is still considered developmental, in part because temperatures of pure
oxygen combustion (about 3,500o Celsius) are far too high for typical power plant materials.10
Figure 3 shows a simplified illustration of this process.
8 IPCC Special Report, p. 130.
9 For more information on the coal-to-liquid process and issues for Congress, see CRS Report RL34133, Fischer-
Tropsch Fuels from Coal, Natural Gas, and Biomass: Background and Policy, by Anthony Andrews and Jeffrey
Logan.
10 IPCC Special Report, p. 122.
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Figure 3. Simplified Illustration of Oxy-Fuel CO2 Capture
Source: Scottish Centre for Carbon Storage. Figure available at http://www.geos.ed.ac.uk/sccs/capture/
oxyfuel.html.
Application of these technologies to power plants generating several hundred megawatts of
electricity has not yet been demonstrated.11 Also, up to 80% of the total costs for CCS may be
associated with the capture phase of the CCS process.12
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Pipelines are the most common method for transporting CO2 in the United States. Currently, over
5,800 kilometers (about 3,600 miles) of pipeline transport CO2 in the United States,
predominately to oil and gas fields, where it is used for enhanced oil recovery (EOR).13
Transporting CO2 in pipelines is similar to transporting petroleum products like natural gas and
oil; it requires attention to design, monitoring for leaks, and protection against overpressure,
especially in populated areas.14
Using ships may be feasible when CO2 needs to be transported over large distances or overseas.
Ships transport CO2 today, but at a small scale because of limited demand. Liquefied natural gas,
propane, and butane are routinely shipped by marine tankers on a large scale worldwide. Rail cars
and trucks can also transport CO2, but this mode would probably be uneconomical for large-scale
CCS operations.
Costs for pipeline transport vary, depending on construction, operation and maintenance, and
other factors, including right-of-way costs, regulatory fees, and more. The quantity and distance
transported will mostly determine costs, which will also depend on whether the pipeline is
onshore or offshore, the level of congestion along the route, and whether mountains, large rivers,
11 The Schwarze-Pumpe 30 MW oxy-fuel pilot plant in Germany has been operating since mid-2008. The captured CO2
will be used for enhanced gas recovery at a nearby natural gas field. See http://www.vattenfall.com/www/co2_en/
co2_en/Gemeinsame_Inhalte/DOCUMENT/388963co2x/401837co2x/P0277108.pdf.
12 Steve Furnival, reservoir engineer at Senergy, Ltd., “Burying Climate Change for Good,” Physics World; see
http://physicsweb.org/articles/world/19/9/3/1.
13 U.S. Department of Transportation, National Pipeline Mapping System database (June 2005), at
https://www.npms.phmsa.dot.gov/. By comparison, nearly 800,000 kilometers (500,000 miles) of pipeline operates to
convey natural gas and hazardous liquids in the United States.
14 IPCC Special Report, p. 181.
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or frozen ground are encountered. Shipping costs are unknown in any detail, however, because no
large-scale CO2 transport system (in millions of metric tons of CO2 per year, for example) is
operating. Ship costs might be lower than pipeline transport for distances greater than 1,000
kilometers and for less than a few million metric tons of CO2 (MtCO2) 15 transported per year.16
Even though regional CO2 pipeline networks currently operate in the United States for enhanced
oil recovery (EOR), developing a more expansive network for CCS could pose numerous
regulatory and economic challenges. Some of these include questions about pipeline network
requirements, economic regulation, utility cost recovery, regulatory classification of CO2 itself,
and pipeline safety.17
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Three main types of geological formations are being considered for carbon sequestration:
(1) depleted oil and gas reservoirs, (2) deep saline reservoirs, and (3) unmineable coal seams. In
each case, CO2 would be injected, in a dense form, below ground into a porous rock formation
that holds or previously held fluids. By injecting CO2 below 800 meters in a typical reservoir, the
pressure induces CO2 to become supercritical—a relatively dense liquid—and thus less likely to
migrate out of the geological formation. Injecting CO2 into deep geological formations uses
existing technologies that have been primarily developed by and used for the oil and gas industry,
and that could potentially be adapted for long-term storage and monitoring of CO2. Other
underground injection applications in practice today, such as natural gas storage, deep injection of
liquid wastes, and subsurface disposal of oil-field brines, can also provide information for
sequestering CO2 in geological formations.18
The storage capacity for CO2 storage in geological formations is potentially huge if all the
sedimentary basins in the world are considered.19 The suitability of any particular site, however,
depends on many factors including proximity to CO2 sources and other reservoir-specific
qualities like porosity, permeability, and potential for leakage.
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Pumping CO2 into oil and gas reservoirs to boost production (enhanced oil recovery, or EOR) is
practiced in the petroleum industry today. The United States is a world leader in this technology
and injects approximately 48 MtCO2 underground each year to help recover oil and gas
resources.20 Carbon dioxide can be stored onshore or offshore; to date, most CO2 projects
15 One metric ton of CO2 equivalent is written as 1 tCO2; one million metric tons is written as 1 MtCO2; one billion
metric tons is written as 1 GtCO2.
16 IPCC Special Report, p. 31.
17 These issues are discussed in more detail in CRS Report RL33971, Carbon Dioxide (CO2) Pipelines for Carbon
Sequestration: Emerging Policy Issues, by Paul W. Parfomak and Peter Folger, and CRS Report RL34316, Pipelines
for Carbon Dioxide (CO2) Control: Network Needs and Cost Uncertainties, by Paul W. Parfomak and Peter Folger.
18 IPCC Special Report, p. 31.
19 Sedimentary basins refer to natural large-scale depressions in the Earth’s surface that are filled with sediments and
fluids and are therefore potential reservoirs for CO2 storage.
20 U.S. DOE, Carbon Sequestration Through Enhanced Oil Recovery, National Energy Technology Laboratory (March
2008), at http://www.netl.doe.gov/publications/factsheets/program/Prog053.pdf.
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associated with EOR are onshore, with the bulk of U.S. activities in west Texas. The advantage of
using this technique for long-term CO2 storage is that sequestration costs can be partially offset
by revenues from oil and gas production. Carbon dioxide can also be injected into oil and gas
reservoirs that are completely depleted, which would serve the purpose of long-term
sequestration, but without any offsetting benefit from oil and gas production.
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The In Salah Project in Algeria is the world’s first large-scale effort to store CO2 in a natural gas
reservoir.21 At In Salah, CO2 is separated from the produced natural gas and then reinjected into
the same formation. Approximately 17 MtCO2 are planned to be captured and stored over the
lifetime of the project.
The Weyburn Project in south-central Canada uses CO2 produced from a coal gasification plant in
North Dakota for EOR, injecting up to 5,000 tCO2 per day into the formation and recovering oil.22
Approximately 20 MtCO2 are expected to remain in the formation over the lifetime of the project.
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Depleted or abandoned oil and gas fields, especially in the United States, are considered prime
candidates for CO2 storage for several reasons:
• oil and gas originally trapped did not escape for millions of years, demonstrating
the structural integrity of the reservoir;
• extensive studies have typically characterized the geology of the reservoir;
• computer models have often been developed to understand how hydrocarbons
move in the reservoir, and the models could be applied to predicting how CO2
could move; and
• infrastructure and wells from oil and gas extraction may be in place and might be
used for handling CO2 storage.
Some of these features could also be disadvantages to CO2 sequestration. Wells that penetrate
from the surface to the reservoir could be conduits for CO2 release if they are not plugged
properly. Care must be taken not to overpressure the reservoir during CO2 injection, which could
fracture the caprock—the part of the formation that formed a seal to trap oil and gas—and
subsequently allow CO2 to escape. Also, shallow oil and gas fields (those less than 800 meters
deep, for example) may be unsuitable because CO2 may form a gas instead of a denser liquid and
could escape to the surface more easily.
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Some rocks in sedimentary basins are saturated with brines or brackish water unsuitable for
agriculture or drinking. As with oil and gas, deep saline reservoirs can be found onshore and
21 IPCC Special Report, p. 203.
22 Ibid., p. 204.
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offshore; in fact, they are often part of oil and gas reservoirs and share many characteristics. The
oil industry routinely injects brines recovered during oil production into saline reservoirs for
disposal.23 Using saline reservoirs for CO2 sequestration has several advantages: (1) they are
more widespread in the United States than oil and gas reservoirs and thus have greater probability
of being close to large point sources of CO2; and (2) saline reservoirs have potentially the largest
reservoir capacity of the three types of geologic formations.
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The Sleipner Project in the North Sea is the first commercial-scale operation for sequestering CO2
in a deep saline reservoir. The Sleipner project has been operating since 1996, and it injects and
stores approximately 2,800 tCO2 per day, or about 1 MtCO2 per year.24 Carbon dioxide is
separated from natural gas production at the nearby Sleipner West Gas Field, compressed, and
then injected 800 meters below the seabed of the North Sea into the Utsira formation, a sandstone
reservoir 200-250 meters (650-820 feet) thick containing saline fluids. Monitoring has indicated
the CO2 has not leaked from the saline reservoir, and computer simulations suggest that the CO2
will eventually dissolve into the saline water, reducing the potential for leakage in the future.
Large CO2 sequestration projects, similar to Sleipner, are being planned in western Australia (the
Gorgon Project)25 and in the Barents Sea (the Snohvit Project),26 that would inject 10,000 and
2,000 tCO2 per day respectively, when at full capacity. Similar to the Sleipner operation, both
projects plan to strip CO2 from produced natural gas and inject it into deep saline formations for
permanent storage.
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Although deep saline reservoirs have huge potential capacity to store CO2, estimates of lower and
upper capacities vary greatly, reflecting a high degree of uncertainty in how to measure storage
capacity.27 Actual storage capacity may have to be determined on a case-by-case basis.
In addition, some studies have pointed out potential problems with maintaining the integrity of
the reservoir because of chemical reactions following CO2 injection. Injecting CO2 can acidify
(lower the pH of) the fluids in the reservoir, dissolving minerals such as calcium carbonate, and
possibly increasing permeability. Increased permeability could allow CO2-rich fluids to escape
the reservoir along new pathways and contaminate aquifers used for drinking water.
In an October 2004 experiment, researchers injected 1,600 tCO2 1,500 meters deep into the Frio
Formation—a saline reservoir containing oil and gas—along the Gulf Coast near Dayton, TX, to
test its performance for CO2 sequestration and storage.28 Test results indicated that calcium
23 DOE Office of Fossil Energy; see http://www.fossil.energy.gov/programs/sequestration/geologic/index.html.
24 IEA Greenhouse Gas R&D Programme, RD&D Projects Database, at
http://www.co2captureandstorage.info/project_specific.php?project_id=26.
25 Ibid, at http://www.co2captureandstorage.info/project_specific.php?project_id=122.
26 Ibid, at http://www.co2captureandstorage.info/project_specific.php?project_id=35.
27 IPCC Special Report, p. 223.
28 Y. K. Kharaka, et al., “Gas-water interactions in the Frio Formation following CO2 injection: implications for the
storage of greenhouse gases in sedimentary basins,” Geology, v. 34, no. 7 (July, 2006), pp. 577-580.
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carbonate and other minerals rapidly dissolved following injection of the CO2. The researchers
also measured increased concentrations of iron and manganese in the reservoir fluids, suggesting
that the dissolved minerals had high concentrations of those metals. The results raised the
possibility that toxic metals and other compounds might be liberated if CO2 injection dissolved
minerals that held high concentrations of those substances.
Another concern is whether the injected fluids, with pH lowered by CO2, would dissolve cement
used to seal the injection wells that pierce the formation from the ground surface. Leaky injection
wells could then also become pathways for CO2-rich fluids to migrate out of the saline formation
and contaminate fresher groundwater above. Approximately six months after the injection
experiment at the Dayton site, however, researchers did not detect any leakage upwards into the
overlying formation, suggesting that the integrity of the saline reservoir formation remained intact
at that time.
Preliminary results from a second injection test in the Frio Formation appear to replicate results
from the first experiment, indicating that the integrity of the saline reservoir formation remained
intact, and that the researchers could detect migration of the CO2-rich plume from the injection
point to the observation well in the target zone. These results suggest to the researchers that they
have the data and experimental tools to move to the next, larger-scale, phase of CO2 injection
experiments.29
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According to DOE, nearly 90% of U.S. coal resources are not mineable with current technology,
because the coal beds are not thick enough, the beds are too deep, or the structural integrity of the
coal bed30 is inadequate for mining. Even if they cannot be mined, coal beds are commonly
permeable and can trap gases, such as methane, which can be extracted (a resource known as coal
bed methane, or CBM). Methane and other gases are physically bound (adsorbed) to the coal.
Studies indicate that CO2 binds even more tightly to coal than methane.31 Carbon dioxide injected
into permeable coal seams could displace methane, which could be recovered by wells and
brought to the surface, providing a source of revenue to offset the costs of CO2 injection.
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Unmineable coal seam injection projects would need to assess several factors in addition to the
potential for CBM extraction. These include depth, permeability, coal bed geometry (a few thick
seams, not several thin seams), lateral continuity and vertical isolation (less potential for upward
leakage), and other considerations. Once CO2 is injected into a coal seam, it would likely remain
there unless the seam is depressurized or the coal is mined. Also, many unmineable coal seams in
the United States are located near electricity-generating facilities, which could reduce the distance
and cost of transporting CO2 from large point sources to storage sites.
29 Personal communication with Susan D. Hovorka, principal investigator for the Frio Project, Bureau of Economic
Geology, Jackson School of Geosciences, University of Texas at Austin, Aug. 22, 2007.
30 Coal bed and coal seam are interchangeable terms.
31 IPCC Special Report, p. 217.
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Not all types of coal beds are suitable for CBM extraction. Without the coal bed methane
resource, the sequestration process would be less economically attractive. No commercial CO2
injection and sequestration project in coal beds is currently underway.
Without ongoing commercial experience, storing CO2 in coal seams has significant uncertainties
compared to the other two types of geological storage discussed. According to IPCC, unmineable
coal seams have the smallest potential capacity for storing CO2 globally compared to oil and gas
fields or deep saline formations. DOE indicates that unmineable coal seams in the United States,
however, have more potential capacity than oil and gas fields for storing CO2. The discrepancy
could represent the relatively abundant U.S. coal reserves compared to other regions in the world,
or it might also indicate the level of uncertainty in estimating the CO2 storage capacity in
unmineable coal seams.
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According to the DOE 2008 Carbon Sequestration Atlas,32 at least one of each of these three types
of potential CO2 reservoirs occurs across most of the United States in relative proximity to many
large point sources of CO2, such as fossil fuel power plants or cement plants. The 2008 Carbon
Sequestration Atlas replaces the 2007 version, and contains a substantial expansion of the
estimated storage capacity for oil and gas reservoirs and for deep saline formations compared to
2007 estimates. Table 2 shows the 2008 estimates and compares them to estimates from the 2007
version.
The Carbon Sequestration Atlas was compiled from estimates of geological storage capacity
made by seven separate regional partnerships, government-industry collaborations fostered by
DOE, that each produced estimates for different regions of the United States and parts of Canada.
According to DOE, geographical differences in fossil fuel use and sequestration potential across
the country led to a regional approach to assessing CO2 sequestration potential.33 The Carbon
Sequestration Atlas reflects some of the regional differences; for example, not all of the regional
partnerships identified unmineable coal seams as potential CO2 reservoirs. Other partnerships
identified geological formations unique to their regions—such as organic-rich shales in the
Illinois Basin, or flood basalts in the Columbia River Plateau—as other types of possible
reservoirs for CO2 storage.
Table 2 indicates a lower and upper range for sequestration potential in deep saline formations
and for unmineable coal seams, but only a single estimate for oil and gas fields. The 2007 Carbon
Sequestration Atlas explained that a range of sequestration capacity for oil and gas reservoirs is
not provided—in contrast to deep saline formations and coal seams—because of the relatively
good understanding of oil and gas field volumetrics.34 Although it is widely accepted that oil and
gas reservoirs are better understood, primarily because of the long history of oil and gas
32 U.S. Dept. of Energy, National Energy Technology Laboratory, 2008 Carbon Sequestration Atlas of the United
States and Canada, 2nd ed. (November 2008), 140 pages. Hereafter referred to as the 2008 Carbon Sequestration Atlas.
See http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasII/.
33 2008 Carbon Sequestration Atlas, p. 8.
34 2007 Carbon Sequestration Atlas, p. 12.
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exploration and development, it seems unlikely that the capacity for CO2 storage in oil and gas
formations is known to the level of precision stated in the 2008 Carbon Sequestration Atlas. It is
likely that the estimate of 138 GtCO2 shown in Table 2 may change, for example, pending the
results of large-scale CO2 injection tests in oil and gas fields.
Table 2. Geological Sequestration Potential for the
United States and Parts of Canada
(comparing 2008 and 2007 estimates, GtCO )
2
Lower
Lower
Upper
Upper
Reservoir
estimate
estimate
estimate
estimate
type
(2008)
(2007)
% change
(2008)
(2007)
% change
Oil and gas
138 82.4 +67% — — —
fields
Deep saline
3,297 919.0 +259% 12,618 3,378.0 +274%
formations
Unmineable
157 156.1 +0.6% 178 183.5 -3.0%
coal seams
Source: 2008 and 2007 Carbon Sequestration Atlases.
Each partnership produced its own estimates of reservoir capacity, and some observers have
raised the issue of consistency among estimates across the regions. The Energy Independence and
Security Act of 2007, enacted as P.L. 110-140 on December 19, 2007, directed the Department of
the Interior (DOI) to develop a single methodology for an assessment of the national potential for
geologic storage of carbon dioxide. Under P.L. 110-140, the U.S. Geological Survey (USGS)
within DOI is directed to complete an assessment of the national capacity for CO2 storage in
accordance with the methodology. The law gives the USGS two years following publication of
the methodology to complete the national assessment. According to DOE, the USGS effort will
allow refinement of the estimates provided in the 2008 Carbon Sequestration Atlas, and will
incorporate uncertainty in the capacity estimates.35 The DOE Sequestration Atlas should probably
be considered an evolving assessment of U.S. reservoir capacity for CO2 storage.
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The world’s oceans contain approximately 50 times the amount of carbon stored in the
atmosphere and nearly 10 times the amount stored in plants and soils.36 The oceans today take
up—act as a net sink for—approximately 1.7 GtCO2 per year. About 45% of the CO2 released
from fossil fuel combustion and land use activities during the 1990s has remained in the
atmosphere, while the remainder has been taken up by the oceans, vegetation, or soils on the land
surface.37 Without the ocean sink, atmospheric CO2 concentration would be increasing more
rapidly. Ultimately, the oceans could store more than 90% of all the carbon released to the
35 2008 Carbon Sequestration Atlas, p. 23.
36 Christopher L. Sabine et al., “Current Status and Past Trends of the Global Carbon Cycle,” in C. B. Field and M. R.
Raupach, eds., The Global Carbon Cycle: Integrating Humans, Climate, and the Natural World (Washington, DC:
Island Press, 2004), pp. 17-44.
372007 IPCC Working Group I Report, pp. 514-515.
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atmosphere by human activities, but the process takes thousands of years.38 The ocean’s capacity
to absorb atmospheric CO2 may change, however, and possibly even decrease in the future.39
Also, studies indicate that as more CO2 enters the ocean from the atmosphere, the surface waters
are becoming more acidic.40
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Although the surface of the ocean is becoming more concentrated with CO2, the surface waters
and the deep ocean waters generally mix very slowly, on the order of decades to centuries.
Injecting CO2 directly into the deep ocean would take advantage of the slow rate of mixing,
allowing the injected CO2 to remain sequestered until the surface and deep waters mix and CO2
concentrations equilibrate with the atmosphere. What happens to the CO2 would depend on how it
is released into the ocean, the depth of injection, and the temperature of the seawater.
Carbon dioxide injected at depths shallower than 500 meters typically would be released as a gas,
and would rise towards the surface. Most of it would dissolve into seawater if the injected CO2
gas bubbles were small enough.41 At depths below 500 meters, CO2 can exist as a liquid in the
ocean, although it is less dense than seawater. After injection below 500 meters, CO2 would also
rise, but an estimated 90% would dissolve in the first 200 meters. Below 3,000 meters in depth,
CO2 is a liquid and is denser than seawater; the injected CO2 would sink and dissolve in the water
column or possibly form a CO2 pool or lake on the sea bottom. Some researchers have proposed
injecting CO2 into the ocean bottom sediments below depths of 3,000 meters, and immobilizing
the CO2 as a dense liquid or solid CO2 hydrate.42 Deep storage in ocean bottom sediments, below
3,000 meters in depth, might potentially sequester CO2 for thousands of years.43
The potential for ocean storage of captured CO2 is huge, but environmental impacts on marine
ecosystems and other issues may determine whether large quantities of captured CO2 will
ultimately be stored in the oceans. Also, deep ocean storage is in a research stage, and the effects
of scaling up from small research experiments, using less than 100 liters of CO2,44 to injecting
several GtCO2 into the deep ocean are unknown.
Injecting CO2 into the deep ocean would change ocean chemistry, locally at first, and assuming
that hundreds of GtCO2 were injected, would eventually produce measurable changes over the
38 CO2 forms carbonic acid when dissolved in water. Over time, the solid calcium carbonate (CaCO3) on the seafloor
will react with, or neutralize, much of the carbonic acid that entered the oceans as CO2 from the atmosphere. See David
Archer et al., “Dynamics of fossil fuel CO2 neutralization by marine CaCO3,” Global Biogeochemical Cycles, vol. 12,
no. 2 (June 1998): pp. 259-276.
39 One study, for example, suggests that the efficiency of the ocean sink has been declining at least since 2000; see
Josep G. Canadell et al., “Contributions to accelerating atmospheric CO2 growth from economic activity, carbon
intensity, and efficiency of natural sinks,” PNAS, vol. 47, no. 104 (November 20, 2007), pp. 18866-18870.
40 For more information on ocean acidification, see CRS Report R40143, Ocean Acidification, by Eugene H. Buck and
Peter Folger.
41 IPCC Special Report, p. 285.
42 A CO2 hydrate is a crystalline compound formed at high pressures and low temperatures by trapping CO2 molecules
in a cage of water molecules.
43 K. Z. House, et al., “Permanent carbon dioxide storage in deep-sea sediments,” Proceedings of the National Academy
of Sciences, vol. 103, no. 33 (Aug. 15, 2006): pp. 12291-12295.
44 P. G. Brewer, et al., “Deep ocean experiments with fossil fuel carbon dioxide: creation and sensing of a controlled
plume at 4 km depth,” Journal of Marine Research, vol. 63, no. 1 (2005): p. 9-33.
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entire ocean.45 The most significant and immediate effect would be the lowering of pH, increasing
the acidity of the water. A lower pH may harm some ocean organisms, depending on the
magnitude of the pH change and the type of organism. Actual impacts of deep sea CO2
sequestration are largely unknown, however, because scientists know very little about deep ocean
ecosystems.46
Environmental concerns led to the cancellation of the largest planned experiment to test the
feasibility of ocean sequestration in 2002. A scientific consortium had planned to inject 60 tCO2
into water over 800 meters deep near the Kona coast on the island of Hawaii. Environmental
organizations opposed the experiment on the grounds that it would acidify Hawaii’s fishing
grounds, and that it would divert attention from reducing greenhouse gas emissions.47 A similar
but smaller project with plans to release more than 5 tCO2 into the deep ocean off the coast of
Norway, also in 2002, was cancelled by the Norway Ministry of the Environment after opposition
from environmental groups.48
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Another option for sequestering CO2 produced by fossil fuel combustion involves converting CO2
to solid inorganic carbonates, such as CaCO3 (limestone), using chemical reactions. When this
process occurs naturally it is known as “weathering” and takes place over thousands or millions
of years. The process can be accelerated by reacting a high concentration of CO2 with minerals
found in large quantities on the Earth’s surface, such as olivine or serpentine.49 Mineral
carbonation has the advantage of sequestering carbon in solid, stable minerals that can be stored
without risk of releasing carbon to the atmosphere over geologic time scales.
Mineral carbonation involves three major activities: (1) preparing the reactant minerals—mining,
crushing, and milling—and transporting them to a processing plant, (2) reacting the concentrated
CO2 stream with the prepared minerals, and (3) separating the carbonate products and storing
them in a suitable repository.
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Mineral carbonation is well understood and can be applied at small scales, but is at an early phase
of development as a technique for sequestering large amounts of captured CO2. Large volumes of
silicate oxide minerals are needed, from 1.6 to 3.7 metric tons of silicates per tCO2 sequestered.
Thus, a large-scale mineral carbonation process needs a large mining operation to provide the
reactant minerals in sufficient quantity.50 Large volumes of solid material would also be produced,
between 2.6 and 4.7 metric tons of materials per tCO2 sequestered, or 50%-100% more material
45 IPCC Special Report, p. 279.
46 Ibid., p. 298.
47 Virginia Gewin, “Ocean carbon study to quit Hawaii,” Nature, vol. 417 (June 27, 2002): p. 888.
48 Jim Giles, “Norway sinks ocean carbon study,” Nature, vol. 419 (Sept. 5, 2002): p. 6.
49 Serpentine and olivine are silicate oxide minerals—combinations of the silica, oxygen, and magnesium—that react
with CO2 to form magnesium carbonates. Wollastonite, a silica oxide mineral containing calcium, reacts with CO2 to
form calcium carbonate (limestone). Magnesium and calcium carbonates are stable minerals over long time scales.
50 IPCC Special Report, p. 40.
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to be disposed of by volume than originally mined. Because mineral carbonation is in the research
and experimental stage, estimating the amount of CO2 that could be sequestered by this technique
is difficult.
One possible geological reservoir for CO2 storage—major flood basalts51 such as those on the
Columbia River Plateau—is being explored for its potential to react with CO2 and form solid
carbonates in situ (in place). Instead of mining, crushing, and milling the reactant minerals, as
discussed above, CO2 would be injected directly into the basalt formations and would react with
the rock over time and at depth to form solid carbonate minerals. Large and thick formations of
flood basalts occur globally, and many have characteristics—such as high porosity and
permeability—that are favorable to storing CO2. Those characteristics, combined with tendency
of basalt to react with CO2, could result in a large-scale conversion of the gas into stable, solid
minerals that would remain underground for geologic time. One of the DOE regional carbon
sequestration partnerships is exploring the possibility for using Columbia River Plateau flood
basalts for storing CO2; however, investigations are in a preliminary stage.52
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Cost estimates for CCS typically present a range of values and depend on many variables, such as
the type of capture technology (post-combustion, pre-combustion, oxy-fuel), whether the plant
represents new construction or is a retrofit to an existing plant, whether the CCS project is in a
demonstration or a commercial stage, and a variety of other factors. Part of the difficulty in
estimating costs is the lack of any operating, commercial-scale electricity-generating power plants
that capture and sequester their CO2 emissions. Thus, there are no real-world examples to draw
from. In addition, there is neither a market price for CO2 emitted nor a regulatory requirement to
capture CO2—a market demand—which would likely shape cost estimates. All observers,
however, agree that installing CO2 capture technology will increase the cost of generating
electricity from fossil fuel power plants. As a result, few companies are likely to commit to the
extra expense of installing technology to capture CO2, or installing the infrastructure to transport
and store it, until they are required to do so.
Despite these challenges, several studies have estimated costs for CCS, in the likelihood that
desire for lower CO2 emissions and continued demand for electricity from fossil fuel power plants
converge and foster development and deployment of CCS. According to one DOE estimate,
sequestration costs for capture, transport, and storage range from $27 to $82 per metric ton of
CO2 emissions avoided using present technology.53 In a 2007 study, MIT estimated how much the
cost of generating electricity would increase if CO2 capture technology were installed, both for
new plants and for retrofits of existing plants. Table 3 shows the MIT estimates.
51 Flood basalts are vast expanses of solidified lava, commonly containing olivine, that erupted over large regions in
several locations around the globe. In addition to the Columbia River Plateau flood basalts, other well-known flood
basalts include the Deccan Traps in India and the Siberian Traps in Russia.
52 2008 Carbon Sequestration Atlas, p. 35.
53 Equivalent to $100 to $300 per metric ton of carbon emissions avoided; see http://www.fossil.energy.gov/programs/
sequestration/overview.html.
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Table 3. Estimates of Additional Costs of Selected Carbon Capture Technology
(percent increase in electric generating costs on levelized basis)
New
Construction
Retrofita
Post-combustion
60%-70%
220%-250%
Pre-combustion
22%-25%
not applicable
Oxy-fuel 46%
170%-206%
Source: Massachusetts Institute of Technology, The Future of Coal: An Interdisciplinary MIT Study (2007), pp. 27,
30, 36, 149.
a. Assumes capital costs have been fully amortized.
In most carbon sequestration systems, the cost of capturing CO2 is the largest component,
possibly accounting for as much as 80% of the total.54 In a 2008 study by McKinsey & Company,
capture costs accounted for the majority of CCS costs estimated for demonstration plants and
early commercial plants.55 Table 4 shows the McKinsey & Company estimates for three different
stages of CCS development for new, coal-fired power plants.
Table 4. Estimates of CCS Costs at Different Stages of Development
(dollars per metric ton of CO , for new coal-fired powerplants)
2
Capture Transport Storage Total
Initial
$73-$94 $7-$22 $6-$17 $86-$133
demonstration
Early commercial
$36-$46
$6-$9
$6-$17
$48-$73
Past early
— — — $44-$65
commerciala
Source: McKinsey & Company, Carbon Capture and Storage: Assessing the Economics, Sept. 22, 2008.
Notes: Source provided cost estimates in Euros. Euros converted to dollars at 1 Euro = $1.45, rounded to
nearest dollar.
a. Cost ranges for capture, transport, and storage components for past early commercial-stage plants are not
available from this study.
The MIT and McKinsey & Company studies both suggest that retrofitting power plants would
lead to more expensive CCS costs, in general, compared to new plants on a levelized basis. Four
reasons for higher costs include (1) the added expense of adapting the existing plant configuration
for the capture unit; (2) a shorter lifespan for the capture unit compared to new plants; (3) a
higher efficiency penalty compared to new plants that incorporate CO2 capture from the design
stage; and (4) the generating time lost when an existing plant is taken off-line for the retrofit.56
Retrofitted plants could be less expensive if capture technology is installed on new plants that
were designed “capture-ready,” or if an older plant was already due for extensive revamping.57
54 Furnival, “Burying Climate Change for Good.”
55 McKinsey & Company, Carbon Capture and Storage: Assessing the Economics, Sept. 22, 2008, at
http://www.mckinsey.com/clientservice/ccsi/pdf/CCS_Assessing_the_Economics.pdf.
56 McKinsey & Company, p. 29.
57 Ibid., p. 30.
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As these cost estimates indicate, capturing CO2 at electricity-generating power plants would
likely require more energy, per unit of power output, than is required by plants without CCS,
reducing the plant efficiency. The additional energy required also means that more CO2 would be
produced, per unit of power output. (See Appendix B.) Improving the efficiency of the CO2
capture phase would likely produce the largest cost savings and reduce CO2 emissions. Costs for
each CCS project would probably not be uniform, however, even for those employing the same
type of capture technology. Other site-specific factors, such as types and costs of fuels used by
power plants, distance of transport to a storage site, and the type of CO2 storage, would likely
vary from project to project.
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The DOE CCS program has had three main elements: (1) core research and development,
consisting of laboratory and pilot-scale research for developing new technologies and systems for
greenhouse gas mitigation; (2) demonstration and deployment, consisting of demonstration
projects to test the viability of large-scale CCS technologies using regional partnerships; and (3)
support for the DOE FutureGen project.58 FutureGen was a 10-year initiative to build a near-zero
emissions integrated carbon sequestration and hydrogen production power plant. DOE announced
on January 30, 2008, that the focus for FutureGen would shift away from its original concept, a
decision that sparked some controversy and led to efforts to restore funding for a near zero-
emission plant or plants (see below).
According to DOE, the overall goal of the CCS program is to develop, by 2012, systems that will
achieve 90% capture of CO2 at less than a 10% increase in the cost of energy services and retain
99% storage permanence.59 The research aspect of the DOE program includes a combination of
cost-shared projects, industry-led development projects, research grants, and research at the
National Energy Technology Laboratory. The program investigates five focus areas: (1) CO2
capture; (2) carbon storage; (3) monitoring, mitigation, and verification; (4) work on non-CO2
greenhouse gases; and (5) advancing breakthrough technologies.
After the 2007 DOE roadmap and program plan was made available, Congress passed the Energy
Independence and Security Act of 2007 (P.L. 110-140), which authorized an expansion of the
DOE carbon sequestration research and development program and increased its emphasis on
large-scale underground injection and storage experiments in geologic reservoirs. The American
Recovery and Reinvestment Act (ARRA) of 2009 provides up to $3.4 billion for CCS-related
activities at DOE through FY2010, which will likely alter DOE’s CCS program priorities over
that time frame, although which specific projects and programs will receive funding is not clear
(see discussion of ARRA above).
58 DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, p. 8. See
http://www.netl.doe.gov/technologies/carbon_seq/refshelf/project%20portfolio/2007/2007Roadmap.pdf.
59 Ibid., p. 5.
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The federal government has recognized the potential need for CCS technology—as part of
broader efforts to address greenhouse-gas induced climate change—since at least 1997, when
DOE spent approximately $1 million for the entire CCS program.60 DOE spending on the CCS
program has increased over the 11-year period to its highest amount in FY2008 of $118.9
million.61 If DOE spending for FutureGen is included, together with carbon-capture technology
investments through the Innovations for Existing Plants (IEP) and the Advanced Integrated
Gasification Combined Cycle (AIGCC) programs (also within the DOE Office of Fossil Energy),
then CCS spending at DOE would equal nearly $283 million for FY2008.62 If the Bush
Administration’s budget request for FY2009 were fully funded, then overall spending for CCS
R&D could equal $414 million, a 46% increase over FY2008 spending levels. As noted above,
funding provided under ARRA will likely increase funding for CCS-related programs
dramatically above FY2008 levels.
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Appropriations represent one mechanism for funding carbon capture technology R&D; others
include loan guarantees and tax credits, both of which are available under current law. Loan
guarantee incentives that could be applied to CCS are authorized under Title XVII of the Energy
Policy Act of 2005 (EPAct2005, P.L. 109-58). Title XVII of EPAct2005 (42 U.S.C. 16511-16514)
authorizes the Secretary of Energy to make loan guarantees for projects that, among other
purposes, avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse
gases. The Consolidated Appropriations Act for FY2008 (P.L. 110-161) provided loan guarantees
authorized by EPAct2005 for coal-based power generation and industrial gasification activities
that incorporate CCS, as well as for advanced coal gasification. The explanatory statement
accompanying P.L. 110-161 directed allocation of $6 billion in loan guarantees for retrofitted and
new facilities that incorporate CCS or other beneficial uses of carbon.63
Title XIII of EPAct2005 provides for tax credits that can be used for Integrated Gasification
Combined Cycle (IGCC) projects and for projects that use other advanced coal-based generation
technologies (ACBGT). For these types of projects, the aggregate credits available total up to
$1.3 billion: $800 million for IGCC projects, and $500 million for ACBGT projects. Qualifying
projects under Title XIII of EPAct2005 are not limited to technologies that employ carbon capture
technologies, but the Secretary of the Treasury is directed to give high priority to projects that
include greenhouse gas capture capability. Under the same title of EPAct2005, certain projects
employing gasification technology64 would be eligible to receive up to $650 million in tax credits,
60 Personal communication, Timothy E. Fout, General Engineer, DOE National Energy Technology Laboratory,
Morgantown, WV (July 16, 2008).
61 CCS research and development program line item in the DOE budget (part of the Office of Fossil Energy), U.S.
Department of Energy, FY2009 Congressional Budget Request, Volume 7, DOE/CF-030 (Washington, DC, February
2008).
62Ibid.
63 The explanatory statement was published with the committee print of the House Committee on Appropriations,
Consolidated Appropriations Act, 2008, H.R. 2764/P.L. 110-161. The committee print, which was published in January
2008, is available at http://www.gpoaccess.gov/congress/house/appropriations/08conappro.html.
64 Under Title XIII of EPAct2005, gasification technology means any process that converts a solid or liquid product
from coal, petroleum residue, biomass, or other materials, which are recovered for their energy or feedstock value, into
a synthesis gas (composed primarily of carbon monoxide and hydrogen) for direct use in the production of energy or
(continued...)
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and these projects would also receive high priority from the Secretary of the Treasury if they
include greenhouse gas capture technology.
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Beginning in 2003, DOE created seven regional carbon sequestration partnerships to identify
opportunities for carbon sequestration field tests in the United States and Canada.65 The regional
partnerships program is being implemented in a three-phase overlapping approach: (1)
characterization phase (from FY2003 to FY2005); (2) validation phase (from FY2005 to
FY2009); and (3) deployment phase (from FY2008 to FY2017).66
The third phase, deployment, is intended to demonstrate large-volume, prolonged injection and
CO2 storage in a wide variety of geologic formations. According to DOE, this phase is to address
the practical aspects of large-scale operations, with an aim toward producing the results necessary
for commercial CCS activities to move forward. On November 17, 2008, DOE announced it was
awarding the seventh, and last, award for the large-scale carbon sequestration projects under
phase three.67 DOE has now awarded funds totaling $457.6 million (an average of $65 million per
project) to conduct a variety of large-scale injection tests over several years. In addition to DOE
funding, each partnership also contributes funds ranging from 21% to over 50% of the total
project costs.68
ȱ
On February 27, 2003, President Bush proposed a 10-year, $1 billion project to build a coal-fired
power plant that integrates carbon sequestration and hydrogen production while producing 275
megawatts of electricity, enough to power about 150,000 average U.S. homes. As originally
conceived, the plant would have been a coal-gasification facility and would have produced and
sequestered between 1 and 2 MtCO2 annually. On January 30, 2008, DOE announced that it was
“restructuring” the FutureGen program away from a single, state-of-the-art “living laboratory” of
integrated R&D technologies—a single plant—to instead pursue a new strategy of multiple
commercial demonstration projects.69 In the restructured program, DOE would support up to two
or three demonstration projects of at least 300 megawatts and that would sequester at least 1
MtCO2 per year.
(...continued)
for subsequent conversion to another product.
65 The seven partnerships are Midwest Regional Carbon Sequestration Partnership; Midwest (Illinois Basin) Geologic
Sequestration Consortium; Southeast Regional Carbon Sequestration Partnership; Southwest Regional Carbon
Sequestration Partnership; West Coast Regional Carbon Sequestration Partnership; Big Sky Regional Carbon
Sequestration Partnership; and Plains CO2 Reduction Partnership; see http://www.fossil.energy.gov/programs/
sequestration/partnerships/index.html.
66 DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, p. 36.
67 DOE awarded $66.9 million to the Big Sky Carbon Sequestration Partnership. See
http://www.fossil.energy.gov/news/techlines/2008/08059-DOE_Makes_Sequestration_Award.html.
68 For more information about specific sequestration projects, see the DOE Carbon Sequestration Regional Partnerships
website, at http://www.fossil.energy.gov/programs/sequestration/partnerships/index.html.
69 See http://www.fossil.energy.gov/news/techlines/2008/08003-DOE_Announces_Restructured_FutureG.html.
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In its budget justification for FY2009, DOE cited “new market realities” for its decision, namely
rising material and labor costs for new power plants, and the need to demonstrate commercial
viability of Integrated Gasification Combined Cycle (IGCC) power plants with CCS.70 The
budget justification also noted that a number of states are making approval of new power plants
contingent on provisions to control CO2 emissions, further underscoring the need to demonstrate
commercial viability of a new generation of coal-based power systems, according to DOE. For
FY2009, DOE requested $156 million for the restructured program, and specified that the federal
cost-share would only cover the CCS portions of the demonstration projects, not the entire power
system.
Prior to DOE’s announced restructuring of the program, the FutureGen Alliance—an industry
consortium of 13 companies—announced on December 18, 2007, that it had selected Mattoon,
IL, as the host site from a set of four finalists.71 In its January 30, 2008, announcement, DOE
stated that the four finalist locations may be eligible to host an IGCC plant with CCS under the
new program.
In the debate leading up to enactment of ARRA, the Senate amendment to H.R. 1 (known as the
Collins-Nelson amendment) contained language under Fossil Energy Research and Development
that made $2 billion “available for one or more near zero emissions powerplant(s).”72 Some
observers noted that the language may refer to a plant or plants similar to the original conception
for FutureGen, although the Senate amendment did not refer either to FutureGen or to a specific
location where the plant would be built. The language referring to zero-emissions power plant(s)
was removed in conference and is not included in the conference report to accompany P.L. 111-5
(ARRA).
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A primary goal of developing and deploying CCS is to allow large industrial facilities, such as
fossil fuel power plants and cement plants, to operate while reducing their CO2 emissions by
80%-90%. Such reductions would presumably reduce the likelihood of continued climate
warming from greenhouse gases by slowing the rise in atmospheric concentrations of CO2
(atmospheric CO2 concentrations grew at an annual rate of 3.2% for the first five years of this
decade, faster than the annual rate during the 1990s). To achieve the overarching goal of reducing
the likelihood of continued climate warming would depend, in part, on how fast and how
widespread CCS could be deployed throughout the economy.
Congress has supported CCS R&D for over 10 years and DOE spending increased substantially
in FY2007 and FY2008 compared to previous years. The American Recovery and Reinvestment
Act of 2009 (P.L. 111-5) increases that trend markedly, adding an additional $3.4 billion in CCS-
related federal obligations through FY2010. It is likely that the large increase in funding will
accelerate technological development of CCS systems.
70 DOE FY2009 Budget Request, p. 16.
71 The four were Mattoon, IL; Tuscola, IL; Heart of Brazos (near Jewett, TX); and Odessa, TX.
72 See http://appropriations.senate.gov/News/2009_02_09_Substitute_Amendment_to_HR1_%7BCollins_Nelson_
Amendment%7D.pdf?CFID=23617867&CFTOKEN=75628290.
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The timeline for developing systems to capture and sequester CO2, however, differs from when
CCS technologies may become available for large-scale deployment and are actually deployed. In
testimony before the Senate Energy and Natural Resources Committee on April 16, 2007, Thomas
D. Shope, Acting Assistant Secretary for Fossil Energy at DOE, stated that under current (2007)
budget constraints and outlooks CCS technologies would be available and deployable in the 2020
to 2025 timeframe. However, Mr. Shope added that “we’re not going to see common, everyday
deployment [of those technologies] until approximately 2045.”73 With enactment of ARRA, the
budget constraints now are likely very different compared to when Mr. Shope testified in 2007;
nevertheless, Congress faces several challenges to the rapid and widespread deployment of CCS.
The dramatic increase in CCS R&D funding provided for in ARRA will likely invite scrutiny of
the relative roles of research, development, and deployment (technology-push mechanisms)
versus the requirement for a successful technology to be fully commercialized. To achieve
commercialization, the technology must also meet a market demand—a demand created either
through a price mechanism or a regulatory requirement (demand-pull mechanisms). Even if
technologies for capturing large amounts of CO2 become more efficient and cheaper, few
companies are likely to install such technologies until they are required to do so.
Major increases in capture technology efficiency will likely produce the greatest relative cost
savings for CCS systems, but challenges also face the transportation and storage components of
CCS. Ideally, storage reservoirs for CO2 would be located close to sources, obviating the need to
build a large pipeline infrastructure to deliver captured CO2 for underground sequestration. If
CCS moves to widespread implementation, however, some areas of the country may not have
adequate reservoir capacity nearby, and may need to construct pipelines from sources to
reservoirs. Identifying and validating sequestration sites would need to account for CO2 pipeline
costs, for example, if the economics of the sites are to be fully understood. If this is the case, there
would be questions to be resolved regarding pipeline network requirements, economic regulation,
utility cost recovery, regulatory classification of CO2 itself, and pipeline safety.
Although DOE has identified substantial potential storage capacity for CO2, particularly in deep
saline formations, large-scale injection experiments are only beginning in the United States to test
how different types of reservoirs perform during CO2 injection. Data from the upcoming
experiments will undoubtedly be crucial to future permitting and site approval regulations;
however, no existing federal regulations govern the injection and storage of CO2 for the purposes
of carbon sequestration. In July 2008, the U.S. Environmental Protection Agency (EPA) released
a draft rule that would regulate CO2 injection for the purposes of geological sequestration under
the authority of the Safe Drinking Water Act, Underground Injection Control (UIC) program.74
Some observers have noted that regulating CO2 injection solely to protect groundwater, which is
the focus of the UIC rulemaking process, may not fully address the primary purpose of storing
CO2 underground, which is to reduce atmospheric concentrations.75
73 Testimony of Thomas D. Shope, Acting Assistant Secretary for Fossil Energy, DOE, before the Senate Energy and
Natural Resources Committee, Apr. 16, 2007; at http://frwebgate.access.gpo.gov/cgi-bin/
getdoc.cgi?dbname=110_senate_hearings&docid=f:36492.pdf.
74 Federal Register, pages 43,491-43,541 (July 25, 2008).
75 See, for example, Carbon Capture and Sequestration: Framing the Issues for Regulation, an Interim Report from the
CCSReg Project (December 2008), pp. 73-90; at http://www.ccsreg.org/interimreport/feedback.php.
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In addition, liability, ownership, and long-term stewardship for CO2 sequestered underground are
issues that would need to be resolved before CCS is deployed commercially. Some states are
moving ahead with state-level geological sequestration regulations for CO2, so federal efforts to
resolve these issues at a national level would likely involve negotiations with the states. In
addition, acceptance by the general public of large-scale deployment of CCS may be a significant
challenge if the majority of CCS projects involve private land.76 Some of the large-scale injection
tests could garner information about public acceptance, as local communities become familiar
with the concept, process, and results of CO2 injection tests. Apart from the question of how the
public would accept the likely higher cost for electricity generated from plants with CCS, how a
growing CCS infrastructure of pipelines, injection wells, underground reservoirs, and other
facilities would be accepted by the public is as yet unknown.
76 For more information on public acceptance of CCS, see CRS Report RL34601, Community Acceptance of Carbon
Capture and Sequestration Infrastructure: Siting Challenges, by Paul W. Parfomak.
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P.L. 110-140, the Energy Independence and Security Act of 2007, authorized an expansion of the
current federal carbon sequestration research and development program at DOE and placed an
increased emphasis on large-scale underground injection and storage experiments. Title VII,
Subtitle A, § 702, required that DOE conduct at least seven large-volume sequestration tests of
1 million metric tons of carbon (MtCO2) or more, in addition to conducting fundamental science
and engineering research that would apply to developing CCS technologies. Appropriations to
carry out activities under § 702 were authorized at $240 million per year for FY2008-FY2012, a
total of $1.2 billion over five years.
Section 703 of Title VII authorized a program for projects that would demonstrate technologies
for large-scale capture of CO2, from a range of industrial sources, as well as for transporting and
injecting CO2, and provided for integrating the demonstration program with activities authorized
under § 702. Appropriations for the demonstration program under § 703 were authorized at $200
million per year for FY2009-FY2013, a total of $1 billion over five years. Together, §§ 702 and
703 authorized a total of $2.2 billion through FY2013.
Under Title VII, § 704, the National Academy of Science (NAS) is to review the expanded R&D
program beginning in 2011. Under § 705, DOE is to arrange with NAS to undertake a study to
develop interdisciplinary graduate degree programs with an emphasis in geologic sequestration
science. Section 708 establishes a university-based R&D program to study CCS using various
types of coal.
Under the act, injection and sequestration activities under Subtitle A are subject to requirements
of the Safe Drinking Water Act. Further, the U.S. Environmental Protection Agency is directed to
assess potential impacts of carbon sequestration on public health, safety, and the environment.
Under Subtitle B of Title VII, § 711 directed the Department of the Interior (DOI) to develop a
methodology for an assessment of the national potential for geologic storage of carbon dioxide.
Not later than two years following publication of the methodology, DOI was directed to complete
an assessment of national capacity for CO2 storage in accordance with the methodology. Section
711 authorized a total of $30 million for FY2008-FY2012 for DOI to complete the assessment
and submit its findings to Congress. In addition to completing a national assessment of CO2
storage capacity, DOI under § 714 is to submit a report on a recommended regulatory framework
for managing geologic carbon sequestration on public lands. The report is to include
• an assessment of options to ensure the United States receives fair market value
for the use of public land;
• proposed procedures for public review and comment;
• procedures for protecting natural and cultural resources of the public land
overlying the geologic sequestration sites;
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• a description of the status of liability issues related to the storage of carbon
dioxide in public land;
• identification of legal and regulatory issues for cases where the United States
owns title to the mineral resources but not the overlying land;
• identification of issues related to carbon dioxide pipeline rights-of-way; and
• recommendations for additional legislation that may be required for adequate
public land management and leasing to accommodate geologic sequestration of
carbon dioxide and pipeline rights-of-way.
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Bills introduced in the 110th Congress that proposed cap-and-trade programs to reduce emissions
of greenhouse gases also contained provisions addressing geologic sequestration. Of these, S.
2191, sponsored by Senators Lieberman and Warner, was reported by the Senate Environment
and Public Works Committee on May 20, 2008. A new version of the bill, S. 3036—identical to
S. 2191 but containing a deficit reduction amendment aimed at making the bill revenue-neutral—
was introduced on May 20 and a cloture motion was filed on May 22, 2008. On June 2, 2008, the
Senate invoked cloture on the motion to proceed, allowing discussion of the bill, but not allowing
amendments. A vote on June 6 failed to invoke cloture to end debate on the bill.
S. 3036 would have capped emissions of greenhouse gases 19% below 2005 levels by 2020, and
63% below 2005 levels by 2050. The bill would have allocated a portion of bonus emission
allowances77 on the basis of carbon sequestration. Under Title III, Subtitle F, of the bill, each
qualifying project would have initially received allowances equal to the number of metric tons of
CO2 sequestered multiplied by 4.5. The multiplier would have decreased steadily from 2017 to
2031, and remained at 0.5 until 2039. For example, qualifying projects that geologically sequester
1 MtCO2 in 2012 would have been eligible to receive 4,500,000 emission allowances. After 2031
and until 2039, qualifying projects that sequester 1 MtCO2 could have received 500,000 emission
allowances.
Provisions such as Title III, Subtitle F, in S. 3036 are intended to provide an incentive to develop
and deploy CCS to help mitigate CO2 emissions. In the 111th Congress, comprehensive cap-and-
trade bills are likely to contain similar types of incentives for CCS.
77 An emission allowance, as defined in S. 2191, means authorization to emit 1 CO2 equivalent of greenhouse gas. One
CO2 equivalent is defined as the quantity of greenhouse gas that makes the same contribution to global warming as 1
MtCO2.
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Figure B-1 compares captured CO2 and avoided CO2 emissions. Additional energy required for
capture, transport, and storage of CO2 results in additional CO2 production from a plant with
CCS. The lower bar in Figure B-1 shows the larger amount of CO2 produced per unit of power
(kWh) relative to the reference plant (upper bar) without CCS. Unless no additional energy is
required to capture, transport, and store CO2, the amount of CO2 avoided is always less than the
amount of CO2 captured. Thus the cost per tCO2 avoided is always more than the cost per tCO2
captured.78
Figure B-1. Avoided Versus Captured CO2
Source: IPCC Special Report, Figure 8.2.
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Peter Folger
Specialist in Energy and Natural Resources Policy
pfolger@crs.loc.gov, 7-1517
78 IPCC Special Report, pp. 346-347.
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