Carbon Capture and Sequestration (CCS)
Peter Folger
Specialist in Energy and Natural Resources Policy
June 19, 2009
Congressional Research Service
7-5700
www.crs.gov
RL33801
CRS Report for Congress
P
repared for Members and Committees of Congress
Carbon Capture and Sequestration (CCS)
Summary
Carbon capture and sequestration (or storage)—known as CCS—has attracted interest as a
measure for mitigating global climate change because large amounts of carbon dioxide (CO2)
emitted from fossil fuel use in the United States are potentially available to be captured and stored
underground or prevented from reaching the atmosphere. Large, industrial sources of CO2, such
as electricity-generating plants, are likely initial candidates for CCS because they are
predominantly stationary, single-point sources. Electricity generation contributes over 40% of
U.S. CO2 emissions from fossil fuels.
Congressional interest has grown in CCS as part of legislative strategies to address climate
change. On February 13, 2009, Congress passed the American Recovery and Reinvestment Act of
2009 (ARRA, P.L. 111-5), 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 the renewal of
FutureGen, 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, 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, in part, 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 also is still an experimental process for storing large
quantities of CO2.
The increase in funding for CCS provided for in ARRA and by other economic incentives may
lead to less expensive and more effective 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 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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Contents
Introduction ................................................................................................................................ 1
Selected Legislation in the 111th Congress ............................................................................. 2
Capturing CO2 ............................................................................................................................ 5
Post-Combustion Capture...................................................................................................... 5
Pre-Combustion Capture ....................................................................................................... 6
Oxy-Fuel Combustion Capture.............................................................................................. 7
Transportation............................................................................................................................. 8
Sequestration in Geological Formations ...................................................................................... 8
Oil and Gas Reservoirs.......................................................................................................... 9
The In Salah and Weyburn Projects ................................................................................. 9
Advantages and Disadvantages ..................................................................................... 10
Deep Saline Reservoirs ....................................................................................................... 10
The Sleipner Project...................................................................................................... 11
Advantages and Disadvantages ..................................................................................... 11
Unmineable Coal Seams ..................................................................................................... 12
Advantages and Disadvantages ..................................................................................... 12
Geological Storage Capacity for CO2 in the United States.................................................... 13
Deep Ocean Sequestration......................................................................................................... 14
Advantages and Disadvantages ..................................................................................... 15
Mineral Carbonation ................................................................................................................. 16
Advantages and Disadvantages ..................................................................................... 16
Costs for CCS ........................................................................................................................... 17
The DOE Carbon Capture and Sequestration Program............................................................... 19
DOE CCS Research and Development Funding .................................................................. 20
Loan Guarantees and Tax Credits .................................................................................. 21
Regional Carbon Sequestration Partnerships........................................................................ 22
FutureGen........................................................................................................................... 23
Current Issues and Future Challenges ........................................................................................ 25
Figures
Figure 1. Simplified Illustration of Post-Combustion CO2 Capture .............................................. 6
Figure 2. Simplified Illustration of Pre-Combustion CO2 Capture................................................ 7
Figure 3. Simplified Illustration of Oxy-Fuel CO2 Capture .......................................................... 7
Figure A-1. Avoided Versus Captured CO2 ................................................................................ 27
Tables
Table 1. Sources for CO2 Emissions in the United States from Combustion of Fossil
Fuels ........................................................................................................................................ 1
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Table 2. Geological Sequestration Potential for the United States and Parts of Canada .............. 14
Table 3. Estimates of Additional Costs of Selected Carbon Capture Technology ........................ 18
Table 4. Estimates of CCS Costs at Different Stages of Development ........................................ 18
Table 5. Funding for CCS-Related Activities at DOE................................................................. 20
Appendixes
Appendix. Avoided CO2 ............................................................................................................ 27
Contacts
Author Contact Information ...................................................................................................... 27
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Introduction
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 electricity generation—over 40% of the total CO2 emitted in the United States
from fossil fuels, nearly 2.4 billion metric tons per year—could be targeted for large-scale CCS.
(See Table 1.)
Fuel combustion accounts for 94% of all U.S. CO2 emissions.2 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,
stationary, single-point sources of 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.3
Table 1. Sources for CO2 Emissions in the United States
from Combustion of Fossil Fuels
Sources CO2 Emissionsa Percent
of
Total
Electricity generation
2,397.3
42%
Transportation 1,887.4
33%
Industrial 845.4
15%
Residential 340.6
6%
Commercial 214.4
4%
Total 5,685.1
100%
Source: U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Emissions and Sinks: 1990-
2007, Table ES-3; see http://epa.gov/climatechange/emissions/usinventoryreport.html.
a. CO2 emissions in millions of metric tons for 2007; excludes emissions from U.S. territories.
1 U.S. Department of Energy, National Energy Technology Laboratory, Carbon Sequestration Through Enhanced Oil
Recovery, (March, 2008), at http://www.netl.doe.gov/publications/factsheets/program/Prog053.pdf.
2 U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Emissions and Sinks: 1990-2007, p. ES-
6. The percentage refers to U.S. emissions in 2007; see http://epa.gov/climatechange/emissions/usinventoryreport.html.
3 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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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 of 2009
(ARRA), which included $3.4 billion for CCS-related activities. The Omnibus Appropriations Act
for 2009 (P.L. 111-8) extended authorization indefinitely for $8 billion in loan guarantees for
coal-based power generation and gasification with carbon capture. In the 110th Congress, Division
B of P.L. 110-343 (part of the Emergency Economic Stabilization Act of 2008) nearly doubled the
aggregate amount of tax credits available for CCS-related projects from $1.65 billion to $3.15
billion. Comprehensive cap-and-trade legislation introduced in the 111th Congress, such as H.R.
2454, also includes 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.4
Selected Legislation in the 111th Congress
P.L. 111-5, The American Recovery and Reinvestment Act of 2009
Funding for carbon capture and sequestration technology has increased 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 within the Department of Energy (DOE). 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 did not specify which program or
programs would receive funding, however, or how the $1 billion would be allocated. However, on
June 12, 2009, Energy Secretary Chu announced that the $1 billion would be used to support a
renewed FutureGen facility in Mattoon, IL. 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
4 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 and Congressional Action, 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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storage component of CCS activities), $20 million for geologic sequestration training and
research, and $10 million for unspecified program activities.
With the announcement that $1 billion of the ARRA funds would be used to restart FutureGen,
nearly all of the $3.4 billion agreed to by conferees will be used for CCS activities, and 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 since FY1997.5
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.
P.L. 111-8, The Omnibus Appropriations Act, 2009
The Omnibus Appropriations Act for FY2009 restated and made indefinite the existing loan
guarantee authority that could be applied to CCS-related activities, originally authorized under
Title XVII of the Energy Policy Act of 2005 (EPAct2005, P.L. 109-58, 42 U.S.C. §§16511-
16514). Under P.L. 111-8, $6 billion in loan guarantees is provided for coal-based power
generation and industrial gasification activities at retrofitted and new facilities that incorporate
CCS or other beneficial uses of carbon. The act provides an additional $2 billion in loan
guarantees for advanced coal gasification.6
H.R. 2454, the American Clean Energy and Security Act of 2009
H.R. 2454 (introduced on May 15, 2009, by Representatives Waxman and Markey) has been the
primary energy and climate change legislative proposal thus far in the 111th Congress. Subtitle B
of H.R. 2454 contains several provisions addressing CCS:7
• Section 111 requires the U.S. Environmental Protection Agency (EPA)
Administrator to submit a report to Congress, within 120 days of enactment,
detailing a unified national strategy for addressing the key legal and regulatory
barriers to deployment of commercial-scale carbon capture and sequestration.
• Section 113 amends the Safe Drinking Water Act (SDWA) by directing the EPA
Administrator to promulgate regulations for the development, operation, and
closure of CO2 geologic sequestration wells within one year of enactment, and to
consider the ongoing SDWA rulemaking regarding these wells. Section 113
would also amend Title VIII of the Clean Air Act and establish a coordinated
certification and permitting process for geologic sequestration sites.
5 Approximately $900 million through FY2008 (CRS estimate).
6 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
for subsequent conversion to another product.
7 For a more detailed description and analysis of Subtitle B and all other provisions of H.R. 2454, see CRS Report
R40643, Greenhouse Gas Legislation: Summary and Analysis of H.R. 2454 as Reported by the House Committee on
Energy and Commerce, coordinated by Mark Holt and Gene Whitney.
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• Section 114 authorizes a Carbon Storage Research Corporation to establish and
administer a program to accelerate the commercial availability of CO2 capture
and storage technologies and methods by awarding grants, contracts, and
financial assistance to electric utilities, academic institutions, and other eligible
entities. If established, the corporation would levy an assessment on distribution
utilities for all fossil fuel-based electricity delivered to retail customers, and
would adjust the assessment rates to generate between $1.0 and $1.1 billion per
year.
• Section 115 amends Title VII of the Clean Air Act (CAA) to require that the EPA
Administrator promulgate regulations to distribute emission allowances to
support the commercial deployment of carbon capture and sequestration
technologies in both electric power generation and industrial operations.
• Section 116 amends Title VIII of the CAA by adding performance standards for
new coal-fired power plants and, in some instances, for existing plants retrofitted
with carbon capture and sequestration technology.
S. 1013, the Department of Energy Carbon Capture and Sequestration Program
Amendments Act of 2009
S. 1013 (introduced May 7, 2009, by Senator Bingaman and others) authorizes DOE to carry out
a program of up to 10 “large-scale” projects that demonstrate all aspects of CCS: capture,
transportation, injection, monitoring, and long-term storage of CO2 from industrial facilities. The
legislation defines “large-scale” as the injection of at least 1 million tons of CO2 per year into a
geologic formation. The Secretary of Energy is authorized to enter into cooperative agreements,
under a competitive selection process, with applicants who provide sufficient information about
the long-term geologic storage capacity of the site, possess or have interests in the land, and have
or can reasonably be expected to obtain the necessary permits for the project.
The legislation requires a successful applicant to maintain financial protection in a form and
amount acceptable to the DOE Secretary, EPA Administrator, or Secretary with jurisdiction over
the land. In addition, the operator of the site must meet post-closure criteria established in the
legislation, and continual compliance with criteria for at least 10 consecutive years after the
plume of injected CO2 has come into “equilibrium” with the geologic formation. The legislation
does not define “equilibrium” specifically, but includes the following as necessary conditions:
• no change in the project footprint—the extent of the plume and area of elevated
subsurface;
• no leakage of CO2 or displaced fluids;
• no expectation of future migration of CO2 or displaced fluids that could lead to
leakage;
• injection wells plugged and abandoned in compliance with federal and state
requirements.
If the operator meets all the requirements, and is not guilty of gross negligence and intentional
misconduct, the Secretary of Energy may indemnify the operator from any liability that exceeds
the amount of liability covered through financial protection maintained by the operator as
required by the legislation.
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Under S. 1013, some of the projects may be sited on federal lands in a manner consistent with
applicable laws and land management plans under the relevant land management agency. The
Secretary with jurisdiction over the land would also take into account the framework for
geological sequestration on public land prepared in accordance with §714 of P.L. 110-140.8
The legislation also allows the Secretary of Energy to accept title to, or accept transfer of,
administrative jurisdiction from another federal agency for land necessary for the monitoring,
remediation, or long-term stewardship of the project site.
Capturing CO2
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,9 but such techniques for capturing CO2
have not yet been applied to large power plants (e.g., 500 megawatts or more).10
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
Post-Combustion Capture
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.
8 The framework was released in a report on June 3, 2009 and is available at http://www.doi.gov/news/
09_News_Releases/EISA_Sec._714_Report_to_Congress_V12_Final.pdf.
9 IPCC Special Report, p. 107.
10 Ibid., p. 25.
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://physicsworld.com/cws/article/print/25727.
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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
Pre-Combustion Capture
This process separates CO2 from the fuel by combining the fuel with air and/or steam to produce
hydrogen for combustion and a separate CO2 stream that could be stored. Figure 2 shows a
simplified illustration of this process. The most common technologies today use steam reforming,
in which steam is employed to extract hydrogen from natural gas.13 In the absence of a
requirement or economic incentives, pre-combustion technologies have not been used for some
power systems, such as natural gas combined-cycle power plants.
Currently, a requirement for the pre-combustion capture of CO2 is the use of Integrated
Gasification Combined-Cycle (IGCC) technology to generate electricity.14 There are currently
four commercial IGCC plants worldwide (two in the United States) each with a capacity of about
250 MW. The technology has yet to make a major breakthrough in the U.S. market because its
potential superior environmental performance is currently not required under the Clean Air Act,
and, thus, its higher costs can not be justified.
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.15
13 IPCC Special Report, p. 130.
14 IGCC is an electric generating technology in which pulverized coal is not burned directly but mixed with oxygen and
water in a high-pressure gasifier to make “syngas,” a combustible fluid that is then burned in a conventional combined-
cycle arrangement to generate power.
15 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.
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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.
Oxy-Fuel Combustion Capture
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 C) are far too high for typical power plant materials.16 The
details of this “oxy-fuel” process are still being refined, but generally, from the boiler the exhaust
gas is cleaned of conventional pollutants (SO2, NOx, and particulates) and some of the gases can
be recycled to the boiler to control the higher temperature resulting from coal combustion with
pure oxygen. The rest of the gas stream is sent for further purification and compression in
preparation for transport and/or storage.17 Depending on site-specific conditions, oxy-fuel could
be retrofitted onto existing boilers. Figure 3 shows a simplified illustration of this process.
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.
16 IPCC Special Report, p. 122.
17 Massachusetts Institute of Technology, The Future of Coal: Options for a Carbon-Constrained World, 2007, pp. 30-
31. Hereafter referred to as .MIT, The Future of Coal.
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Transportation
Pipelines are the most common method for transporting CO2 in the United States. Currently, more
than 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).18
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.19
Using ships may be feasible when CO2 must 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,
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) 20 transported per year.21
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.22
Sequestration in Geological Formations
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 supercritical state—a relatively dense liquid—below
ground into a porous rock formation that holds or previously held fluids. By injecting CO2 at
depths greater than 800 meters in a typical reservoir, the pressure keeps the injected CO2 in a
18 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.
19 IPCC Special Report, p. 181.
20 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.
21 IPCC Special Report, p. 31.
22 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.
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supercritical state 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
and used by 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 valuable experience and information for sequestering CO2 in geological
formations.23
The storage capacity for CO2 storage in geological formations is potentially huge if all the
sedimentary basins in the world are considered.24 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.
Oil and Gas Reservoirs
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 oil and gas operators inject approximately 48 MtCO2 underground each year to help recover
oil and gas resources.25 Most of the CO2 used for EOR in the United States comes from naturally
occurring geologic formations, however, not from industrial sources.
Carbon dioxide can be stored onshore or offshore; to date, most CO2 projects 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.
The In Salah and Weyburn Projects
The In Salah Project in Algeria is the world’s first large-scale effort to store CO2 in a natural gas
reservoir.26 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.27
Approximately 20 MtCO2 are expected to remain in the formation over the lifetime of the project.
23 IPCC Special Report, p. 31.
24 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.
25 Data from 2006. See DOE, National Energy Technology Laboratory, Carbon Sequestration Through Enhanced Oil
Recovery, (March 2008), at http://www.netl.doe.gov/publications/factsheets/program/Prog053.pdf..
26 IPCC Special Report, p. 203.
27 Ibid., p. 204.
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Advantages and Disadvantages
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 for oil and gas typically have 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. In addition, oil and gas fields that are suitable for EOR
may not necessarily be located near industrial sources of CO2. Costs to construct pipelines to
connect sources of CO2 with oil and gas fields may, in part, determine whether an EOR operation
using industrial sources of CO2 is feasible.
Although the United States injects nearly 50 MtCO2 underground each year for the purposes of
EOR, that amount represents approximately 2% of the CO2 emitted from fossil fuel electricity
generation alone. The sheer volume of CO2 envisioned for CCS as a climate mitigation option is
overwhelming compared to the amount of CO2 used for EOR. It may be that EOR will increase in
the future, depending on economic, regulatory, and technical factors, and more CO2 will be
sequestered as a consequence. It is also likely that EOR would only account for a small fraction
of the total amount of CO2 injected underground in the future if CCS becomes a significant
component in an overall scheme to substantially reduce CO2 emissions to the atmosphere.
Deep Saline Reservoirs
Some rocks in sedimentary basins contain saline fluids—brines or brackish water unsuitable for
agriculture or drinking. As with oil and gas, deep saline reservoirs can be found onshore and
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.28 Using suitably deep 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.
28 DOE Office of Fossil Energy; see http://www.fossil.energy.gov/programs/sequestration/geologic/index.html.
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The Sleipner Project
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.29 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)30 and in the Barents Sea (the Snohvit Project),31 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. According to company sources, the Snohvit Project began capturing and
sequestering CO2 in April 2008.32
Advantages and Disadvantages
Although deep saline reservoirs potentially have huge capacity to store CO2, estimates of lower
and upper capacities vary greatly, reflecting a higher degree of uncertainty in how to measure
storage capacity.33 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.34 Test results indicated that calcium
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.
29 International Energy Agency (IEA) Greenhouse Gas R&D Programme, RD&D Projects Database, at
http://www.co2captureandstorage.info/project_specific.php?project_id=26.
30 Ibid, at http://www.co2captureandstorage.info/project_specific.php?project_id=122.
31 Ibid, at http://www.co2captureandstorage.info/project_specific.php?project_id=35.
32 See http://www.statoilhydro.com/AnnualReport2008/en/Sustainability/Climate/Pages/5-3-2-
4_Sn%C3%B8hvitCCS.aspx.
33 IPCC Special Report, p. 223.
34 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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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.35
Unmineable Coal Seams
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 bed36 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.37 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.
Advantages and Disadvantages
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 relatively near electricity-generating facilities, which could reduce
the distance and cost of transporting CO2 from large point sources to storage sites.
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. Also, the displaced
methane would need to be combusted or captured because methane itself is a more potent
greenhouse gas than CO2. No commercial CO2 injection and sequestration projects in coal beds
are currently underway.
35 Personal communication with Dr. 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.
36 Coal bed and coal seam are interchangeable terms.
37 IPCC Special Report, p. 217.
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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.
Geological Storage Capacity for CO2 in the United States
According to the DOE 2008 Carbon Sequestration Atlas,38 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 updates the 2007 version, and contains a substantial expansion of the
estimated storage capacity for oil and gas reservoirs and especially 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.39 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.40 Although it is widely accepted that oil and
gas reservoirs are better understood, primarily because of the long history of oil and gas
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.
38 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/.
39 2008 Carbon Sequestration Atlas, p. 8.
40 2007 Carbon Sequestration Atlas, p. 12.
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Table 2. Geological Sequestration Potential for the
United States and Parts of Canada
(comparing 2008 and 2007 estimates, GtCO2)
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 (EISA, P.L. 110-140) 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. EISA directed the U.S. Geological Survey (USGS) within DOI 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.41 The DOE Sequestration Atlas should probably be considered an evolving assessment
of U.S. reservoir capacity for CO2 storage.
Deep Ocean Sequestration
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.42 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.43 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
atmosphere by human activities, but the process takes thousands of years.44 The ocean’s capacity
41 2008 Carbon Sequestration Atlas, p. 23.
42 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.
432007 IPCC Working Group I Report, pp. 514-515.
44 CO2 forms carbonic acid when dissolved in water. Over time, the solid calcium carbonate (CaCO3) on the seafloor
will react with (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.
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to absorb atmospheric CO2 may change, however, and possibly even decrease in the future.45
Also, studies indicate that, as more CO2 enters the ocean from the atmosphere, the surface waters
are becoming more acidic.46
Advantages and Disadvantages
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.47 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.48 Deep storage in ocean bottom sediments, below
3,000 meters in depth, might potentially sequester CO2 for thousands of years.49
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 CO2,50 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
entire ocean.51 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
45 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,” Proceedings of the National Academy of Sciences, vol. 104, no. 47 (Nov. 20,
2007), pp. 18866-18870.
46 For more information on ocean acidification, see CRS Report R40143, Ocean Acidification, by Eugene H. Buck and
Peter Folger.
47 IPCC Special Report, p. 285.
48 A CO2 hydrate is a crystalline compound formed at high pressures and low temperatures by trapping CO2 molecules
in a cage of water molecules.
49 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.
50 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.
51 IPCC Special Report, p. 279.
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sequestration are largely unknown, however, because scientists know very little about deep ocean
ecosystems.52
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.53 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.54
Mineral Carbonation
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.55 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.
Advantages and Disadvantages
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.56 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
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.
52 Ibid., p. 298.
53 Virginia Gewin, “Ocean carbon study to quit Hawaii,” Nature, vol. 417 (June 27, 2002): p. 888.
54 Jim Giles, “Norway sinks ocean carbon study,” Nature, vol. 419 (Sept. 5, 2002): p. 6.
55 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.
56 IPCC Special Report, p. 40.
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One possible geological reservoir for CO2 storage—major flood basalts57 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.58
Costs for CCS
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 tCO2 emissions
avoided using present technology.59 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.
57 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.
58 2008 Carbon Sequestration Atlas, p. 35.
59 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 ful y 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.60 In a 2008 study by McKinsey & Company,
capture costs accounted for the majority of CCS costs estimated for demonstration plants and
early commercial plants.61 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 CO2, for new coal-fired powerplants)
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 dol ars 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.62
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.63
60 Furnival, “Burying Climate Change for Good.”
61 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.
62 McKinsey & Company, p. 29.
63 McKinsey & Company, 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.) 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.
The DOE Carbon Capture and Sequestration
Program
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.64
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.65 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 of 2009 (ARRA, P.L. 111-5) provided 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. On May 15, 2009, Energy Secretary Chu announced that Notices
of Intent to issue $2.4 billion of ARRA funding would be posted: $1.52 billion for industrial
carbon capture and storage, $800 million for the Clean Coal Power Initiative, and $80 million for
geologic site characterization, training, research, and program administration.66 The remaining $1
billion provided in ARRA will be used to support the revival of FutureGen (see below).
64 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.
65 Ibid., p. 5.
66 For a summary of Secretary Chu’s remarks, see http://www.energy.gov/news2009/7405.htm. For the funding
opportunity announcements, see http://www.fossil.energy.gov/aboutus/budget/stimulus.html.
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DOE CCS Research and Development Funding
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.67 Table 5 shows that DOE
programs that provide funding for CCS-related activities total nearly $600 million for FY2009, a
significant increase since 1997.68 Funding for CCS R&D increased by nearly 58% from FY2008
to FY2009, excluding funding from ARRA.
Table 5. Funding for CCS-Related Activities at DOE
($ thousands)
FY2008 FY2009 FY2010
ARRA
Clean Coal Power Initiative (CCPI)a
67,444
288,174
0
800,000
FutureGenb 72,262
0
0
1,000,000
Innovation for Existing Plants (IEP)c 35,083
50,000
41,000
—
Advanced Integrated Gasification Combined Cycled 52,029 65,236 55,000
—
Advanced Turbinese 23,125
28,000
31,000
—
Industrial Carbon Capture Projects
—
—
— 1,520,000
Site Characterization, Training, Program Direction
—
—
—
80,000
Subtotal
252,943 431,410 127,000
3,400,000
Carbon Sequestration Greenhouse Gas Controlf 105,985
136,000
130,865
—
Carbon Sequestration Energy Innovation Hubg 0
0
35,000
—
Carbon Sequestration Focus Area for
9,635 14,000 14,000
—
Carbon Sequestration Scienceh
Subtotal for Carbon Sequestration
115,620 150,000 179,865
—
Total
368,563 581,410 306,865
3,400,000
Source: CRS, from the U.S. Department of Energy, FY2010 Congressional Budget Request, Volume 7, Fossil
Energy Research and Development, at http://www.cfo.doe.gov/budget/10budget/Content/Volumes/Volume7.pdf;
and U.S. Congress, House Committee on Appropriations, Conference Report to Accompany H.R. 1, 111th
Cong., 1st sess., February 11, 2009, 111-16 (Washington: GPO, 2009).
Notes: FY2010 represents the requested amounts; FY2008 and FY2009 are amounts reported in the DOE
FY2010 Congressional Budget Request. Overall Fossil Energy Research appropriations are included in CRS
Report RL34417, Energy and Water Development: FY2009 Appropriations.
a. The FY2010 budget request does not include any funds for CCPI demonstration projects because $800
million is already provided by ARRA (P.L. 111-5) for Phase III of the CCPI program.
b. Language in ARRA indicated that $1 billion would be allocated for Fossil Energy R&D. On June 12, 2009,
Secretary Chu announced that the funds would be used to support FutureGen.
67 Personal communication, Timothy E. Fout, General Engineer, DOE National Energy Technology Laboratory,
Morgantown, WV (July 16, 2008).
68 Funding for FY2009 is according to U.S. Department of Energy, FY2010 Congressional Budget Request, Volume 7,
Fossil Energy Research and Development, at http://www.cfo.doe.gov/budget/10budget/Content/Volumes/Volume7.pdf.
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c. In its FY2010 budget request, DOE indicates that al the IEP activity in FY2010 is focused on the
development of post-combustion CO2 capture technology for new and existing plants. In FY2009, $33
million was focused on carbon capture. However, of the $50 million in total funding for IEP in FY2009, $12
million was allocated to developing and testing advanced water conservation technologies applicable to new
and existing thermoelectric plants, and $5 million for mercury control research. No funding is requested for
either activity in FY2010.
d. According to DOE, the IGCC activity is focused on developing advanced gasification-based technologies to
reduce the costs of near-zero emissions (including CO2) coal-based IGCC plants. The program is also
intended to improve the thermal efficiency of the plants, and to achieve near-zero atmospheric emissions
for all pollutants, including CO2, SO2, NOx, and mercury.
e. The Advanced Turbines program is focused on creating the technology base for turbines that will permit
the design of near-zero atmospheric emission IGCC plants (including CO2). Specifically, the program will
focus in FY2010 on enabling hydrogen-fueled turbines in integrated gasification combined cycle systems that
capture CO2.
f.
Carbon Sequestration includes research and development on al aspects of CCS, but most of the funding is
allocated to the seven Regional Partnerships for large scale CO2 capture, transportation, injection, and
storage projects.
g. The Energy Innovation Hub is requested for the Carbon Sequestration program in FY2010, and would focus
on enabling fundamental advances and discovery of novel and revolutionary capture/separation approaches
to reduce the energy penalty and costs associated with CO2 capture, according to DOE.
h. The Focus Area for Carbon Sequestration Science is part of the Carbon Sequestration program and will
continue applied research in support of CO2 injection and storage field efforts conducted by the seven
Regional Partnerships.
DOE indicates in its FY2010 budget request that programs listed in Table 5 support the mission
to “ensure the availability of near-zero atmospheric emissions” and that “carbon dioxide (CO2)
capture and geologic storage (CCS) is a promising option for addressing this challenge.”69 In
addition to the Carbon Sequestration program itself, for which DOE requested almost $180
million in FY2010 (Table 5), DOE requested a total of $127 million for the Innovation for
Existing Plant (IEP) program, the Advanced Integrated Gasification Combined Cycle program,
and the Advanced Turbine program. The Carbon Sequestration program is focused on all aspects
of CCS: capture technology, transportation, and especially the injection and safe storage of CO2.
The other programs support the broader goal “to significantly reduce coal power plant emissions
(including CO2) and substantially improve efficiency to reduce carbon emissions, leading to a
viable near-zero atmospheric emissions coal energy system and supporting carbon capture and
storage.”70
As noted above, funding provided under ARRA will likely increase funding for CCS-related
programs dramatically above levels in previous years, and exceed the cumulative spending on
CCS by DOE since 1997.
Loan Guarantees and Tax Credits
Appropriations represent one mechanism for funding carbon capture technology R&D and
deployment; others include loan guarantees and tax credits, both of which are available under
current law.
69 Ibid, p. 23.
70 DOE FY2010 Congressional Budget Request, p. 40.
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Loan Guarantees
Loan guarantee incentives that could be applied to CCS were authorized under Title XVII of the
Energy Policy Act of 2005 (EPAct2005, P.L. 109-58, 42 U.S.C. §§16511-16514), and were given
indefinite authorization under the Omnibus Appropriations Act, 2009 (P.L. 111-8). Title XVII of
EPAct2005 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 Omnibus Appropriations Act for FY2009 restates the loan guarantee
authority and provides $6 billion in loan guarantees for coal-based power generation and
industrial gasification activities at retrofitted and new facilities that incorporate CCS or other
beneficial uses of carbon. The act provides an additional $2 billion in loan guarantees for
advanced coal gasification.71
Tax Credits
Title XIII of EPAct2005 provided for tax credits that could 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 under
EPAct2005 totaled up to $1.3 billion: $800 million for IGCC projects, and $500 million for
ACBGT projects. Qualifying projects under Title XIII of EPAct2005 were not limited to
technologies that employ carbon capture technologies, but the Secretary of the Treasury was
directed to give high priority to projects that include greenhouse gas capture capability. An
additional $350 million of tax credits were made available for coal gasification projects.
Sections 111 and 112 of P.L. 110-343, Division B, the Energy Improvement and Extension Act of
2008 (part of the Emergency Economic Stabilization Act of 2008), increased the aggregate tax
credits available from $1.65 billion to $3.15 billion. Section 111 added an additional $1.25 billion
to the existing tax credit authority for ACBGT projects. Section 112 added an additional $250
million to $350 million in existing authority for the coal gasification investment credit, for
gasification projects that separate and sequester at least 75% of the project’s total CO2 emissions.
Section 115 of the act added a new tax credit for sequestering CO2 and storing it underground.
The section provides for a credit of $20 per metric ton of CO2 captured at a qualified facility and
disposed of in secure geological storage, and $10 per metric ton if the CO2 is used as a tertiary
injectant for the purposes of enhanced oil or natural gas recovery. To qualify for the tax credit, the
facility must capture at least 500,000 metric tons of CO2 per year. If CO2 is used for enhanced oil
or gas recovery, a tax credit would be available only for an initial injection; CO2 subsequently
recaptured, recycled, and re-injected would not be eligible for a tax credit.
Regional Carbon Sequestration Partnerships
Beginning in 2003, DOE created seven regional carbon sequestration partnerships to identify
opportunities for carbon sequestration field tests in the United States and Canada.72 The regional
71 U.S. Congress, House Committee on Appropriations, Omnibus Appropriations Act, 2009, Division C—Energy and
Water Development and Related Agencies Appropriations Act, 2009, committee print, 111th Cong., 1st sess., March 11,
2009, p. 672.
72 The seven partnerships are Midwest Regional Carbon Sequestration Partnership; Midwest (Illinois Basin) Geologic
Sequestration Consortium; Southeast Regional Carbon Sequestration Partnership; Southwest Regional Carbon
(continued...)
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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).73
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 made the seventh,
and last, award for the large-scale carbon sequestration projects under phase three.74 DOE has
now awarded funds totaling $457.6 million (an average of approximately $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.75
FutureGen
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.76 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.
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 IGCC power plants with CCS.77 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. 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,
(...continued)
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.
73 DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, p. 36.
74 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.
75 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.
76 See http://www.fossil.energy.gov/news/techlines/2008/08003-DOE_Announces_Restructured_FutureG.html.
77 DOE FY2009 Budget Request, p. 16.
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IL, as the host site from a set of four finalists.78 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).”79 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 mention either
FutureGen or a specific location where the plant would be built. The language referring to zero-
emissions power plant(s) was removed in conference and was not included in the conference
report to accompany ARRA; instead, $1 billion would be allocated for fossil energy research and
development programs.
On June 12, 2009, Secretary Chu announced that the $1 billion of funding from ARRA will be
used to support FutureGen, and that the plant will be built in Mattoon, IL, the site selected by the
FutureGen Alliance in 2007.80 According to DOE, its total anticipated contribution to FutureGen
will be $1.073 billion, and the FutureGen Alliance will contribute between $400 and $600 million
to the project. Under the terms of a provisional agreement with the FutureGen Alliance, DOE has
stated that it will issue a Record of Decision on the project by the middle of July 2009, after
which DOE would pursue the following:
• rapid restart of preliminary design activities;
• completion of a site-specific preliminary design and updated cost estimate;
• expansion of the Alliance sponsorship group;
• development of a complete funding plan; and
• potential additional subsurface characterization.
Some reports indicate that the newly revived plans for FutureGen call for an initial carbon capture
goal of 60% for the facility, with the ultimate goal of achieving a 90% capture rate, the target set
in the project’s original conception.81 Some environmental groups have expressed views that the
lower capture rate may put FutureGen in the same category as other CCS commercialization
projects, calling into question the status of FutureGen as a “flagship facility to demonstrate
carbon capture and storage at commercial scale.”82
78 The four were Mattoon, IL; Tuscola, IL; Heart of Brazos (near Jewett, TX); and Odessa, TX.
79 See http://appropriations.senate.gov/News/
2009_02_09_Substitute_Amendment_to_HR1_%7BCollins_Nelson_Amendment%7D.pdf?CFID=23617867&
CFTOKEN=75628290.
80 See DOE announcement at http://www.fossil.energy.gov/news/techlines/2009/09037-
DOE_Announces_FutureGen_Agreement.html.
81 Ben Geman, “Enviros fault scaled-back FutureGen carbon goal,” Greenwire, June 16, 2009.
82 See Secretary Chu’s announcement on FutureGen at http://www.energy.gov/news2009/7454.htm.
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Current Issues and Future Challenges
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. To
achieve the overarching goal of reducing the likelihood of continued climate warming would
depend, in part, on how fast and how widely CCS could be deployed throughout the economy.
Congress has supported CCS R&D for more than 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.
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, then Acting Assistant DOE Secretary for Fossil Energy, 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.”83 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. H.R. 2454, for
example, contains components of both demand-pull and technology-push, via the cap-and-trade
provisions (demand-pull) and the distribution of emission allowances and other funding to
promote CCS commercialization (technology-push). How the demand-pull and technology-push
provisions in legislation such as H.R. 2454 would affect the rate of CCS commercialization and
its deployment is unclear.
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
83 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.
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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. In addition,
Congress may be called upon to address federal jurisdictional authority over CO2 pipelines under
existing law, and whether additional legislation may be necessary if a CO2 pipeline network
grows and crosses state lines.
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.84
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.85 Cap-and-trade legislation
introduced in the 111th Congress (H.R. 2454) contains provisions that would amend the Clean Air
Act to broaden the regulatory scope and protect human health and the environment by minimizing
the risk of CO2 escape to the atmosphere.
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.86 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.
84 73 Federal Register, 43491-43541 (July 25, 2008).
85 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.
86 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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Appendix. Avoided CO2
Figure A-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 A-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.87
Figure A-1. Avoided Versus Captured CO2
Source: IPCC Special Report, Figure 8.2.
Author Contact Information
Peter Folger
Specialist in Energy and Natural Resources Policy
pfolger@crs.loc.gov, 7-1517
87 IPCC Special Report, pp. 346-347.
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