Order Code RL33801
Direct Carbon Sequestration:
Capturing and Storing CO2
Updated September 13, 2007
Peter Folger
Specialist in Energy and Natural Resources Policy
Resources, Science, and Industry Division

Direct Carbon Sequestration:
Capturing and Storing CO2
Summary
Direct sequestration is capturing carbon at its source and storing it before its
release to the atmosphere. Carbon capture and storage — also known as CCS — is
attracting interest as a measure for mitigating global climate change, because
potentially large amounts of carbon dioxide (CO ) emitted from fossil fuel use in the
2
United States could be eligible for sequestration. Electricity-generating plants may
be the most likely initial candidates for direct sequestration because they are
predominantly large, single-point sources, and they contribute approximately one-
third of U.S. CO emissions from fossil fuels.
2
Congressional interest is growing in direct sequestration as part of legislative
strategies addressing climate change. In the 110th Congress, the House and Senate
have each passed bills that contain provisions expanding the current Department of
Energy (DOE) carbon capture research and development program and creating new
programs to accelerate R&D for CO storage. The bills would require at least seven
2
large-volume underground sequestration tests. DOE is planning to spend almost
$100 million on carbon sequestration R&D in FY2007. The House- and Senate-
passed bills would sharply increase that amount, doubling or tripling R&D spending
on carbon sequestration within two years compared to FY2007 levels.
Approaches for capturing CO are available that can potentially remove 80%-
2
95% of CO emitted from a power plant or large industrial source. Large U.S. power
2
plants currently do not capture large volumes of CO for CCS, owing to the absence
2
of either an economic incentive or a requirement to curtail CO emissions. In a CCS
2
system, pipelines or ships will likely transport captured CO from capture to storage.
2
Three main types of geological formations are likely candidates for storing large
amounts of CO : oil and gas reservoirs, deep saline reservoirs, and unmineable coal
2
seams. The deep ocean also has a huge potential to store carbon; however, direct
injection of CO into the deep ocean is still experimental, and environmental
2
concerns have forestalled planned experiments in the open ocean. Mineral
carbonation — reacting minerals with a stream of concentrated CO to form a solid
2
carbonate — is a well understood process, but is still experimental as a viable process
for storing large quantities of CO .
2
DOE’s carbon sequestration research program will be facilitating field tests for
carbon sequestration, with seven regional partners, across the United States. DOE
is also undertaking a 10-year, $1.5 billion project — known as FutureGen — to build
a 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. DOE estimates direct sequestration costs of between $100 and $300 per
metric ton (2,200 pounds) of carbon emissions avoided using current technologies.
Power plants with CCS would require more fuel, and costs per kilowatt-hour would
likely rise compared to plants without CCS.

Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Carbon Sequestration Legislation in the 110th Congress . . . . . . . . . . . . . . . . 2
Capturing and Separating CO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
2
Post-Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Pre-Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Oxy-Fuel Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Sequestration in Geological Formations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Oil and Gas Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Deep Saline Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Unmineable Coal Seams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Geological Storage Capacity for CO in the United States . . . . . . . . . . . . . 13
2
Deep Ocean Sequestration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Direct Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Limitations to Deep Ocean Sequestration . . . . . . . . . . . . . . . . . . . . . . 16
Mineral Carbonation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Costs for Direct Sequestration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Research Programs and Demonstration Projects . . . . . . . . . . . . . . . . . . . . . 21
DOE Carbon Sequestration Program . . . . . . . . . . . . . . . . . . . . . . . . . . 21
FutureGen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Issues for Congress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Appendix A. Avoided CO
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
2
List of Figures
Figure 1. Sites Where Activities Involving CO Storage Are Planned or
2
Underway . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 2. DOE Carbon Sequestration Program Field Tests . . . . . . . . . . . . . . . . . 25
Figure 3. Avoided Versus Captured CO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
2
List of Tables
Table 1. Sources for CO Emissions in the United States from Combustion of
2
Fossil Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Table 2. Current and Planned CO Storage Projects . . . . . . . . . . . . . . . . . . . . . . . 8
2
Table 3. Estimated Global Capacity for CO Storage in Three Different
2
Geological Formations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Table 4. Geological Sequestration Potential for the United States and
Parts of Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Table 5. Fraction of CO Retained for Ocean Storage . . . . . . . . . . . . . . . . . . . . 15
2
Table 6. Estimated Cost Ranges for Components of a Carbon Capture and
Storage System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Table 7. Comparison of CO Captured Versus CO Avoided for New
2
2
Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Table 8. Comparison of Electricity Costs for New Power Plants With and
Without Carbon Capture and Geological Storage . . . . . . . . . . . . . . . . . . . . 20

Direct Carbon Sequestration:
Capturing and Storing CO2
Introduction
Direct sequestration is capturing carbon at its source and storing it before its
release to the atmosphere. Carbon capture and storage — also known as CCS —
would reduce the amount of carbon dioxide (CO ) emitted to the atmosphere while
2
allowing the use of fossil fuels at some electricity-generating plants and industrial
facilities. An integrated CCS system would include three main steps: (1) capturing
and separating CO at the plant; (2) transporting the captured CO to the storage site;
2
2
and (3) storing CO in geological reservoirs or in the oceans. As a measure for
2
mitigating global climate change, direct sequestration is attracting interest because
several projects in the United States and abroad — typically associated with oil and
gas production — are successfully injecting and storing CO underground, albeit at
2
relatively small scales. Also, potentially large amounts of CO generated from fossil
2
fuels — as much as one-third of the total CO emitted in the United States — could
2
be eligible for large-scale direct sequestration.1
Fuel combustion accounts for 94% of all U.S. CO emissions.2 Electricity
2
generation contributes the largest proportion of CO emissions compared to other
2
types of fossil fuel use in the United States. (See Table 1.) Electricity-generating
plants, thus, may be the most likely initial candidates for capture, separation, and
storage, or reuse of CO because they are predominantly large, single-point sources
2
for emissions. Large industrial facilities, such as cement-manufacturing plants or
hydrogen production plants, that already produce concentrated CO streams as part
2
of the industrial process are also good candidates for CO capture and storage.3
2
Congressional interest in direct sequestration, as part of legislation addressing
climate change, is growing. The House and Senate have each passed bills that
contain provisions expanding the current DOE carbon capture research and
development program and creating new programs to accelerate R&D for CO storage.
2
(See below.)
1 DOE estimates that large, fossil-fuel power plants account for one-third of all U.S. CO2
emissions; see [http://www.fossil.energy.gov/programs/sequestration/overview.html].
2 U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Emissions
and Sinks: 1990-2005,
p. ES-6. The percentage refers to U.S. emissions in 2005; 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.)

CRS-2
This report covers only direct sequestration, and not indirect sequestration,
whereby CO is removed from the atmosphere and stored in vegetation, soils, or
2
oceans. Forests and agricultural lands store carbon, and the world’s oceans exchange
huge amounts of CO from the atmosphere through natural processes.4
2
Table 1. Sources for CO Emissions in the United States from
2
Combustion of Fossil Fuels
Sources
CO
Percent
2
Emissionsa
of Total
Electricity generation
2,328.7
41%
Transportation
1,892.8
34%
Industrial
840.1
15%
Residential
358.7
6%
Commercial
225.8
4%
Total
5,646.1
100%
Source: U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Emissions and
Sinks: 1990-2005
, Table ES-3; see [http://epa.gov/climatechange/emissions/usinventoryreport.html].
a. CO emissions in millions of metric tons for 2005; excludes emissions from U.S. territories.
2
Carbon Sequestration Legislation in the 110th Congress
Several measures have been introduced in the 110th Congress that seek to
expand the current federal carbon sequestration research and development program
or to create new programs that accelerate research and development on capturing and
storing CO . The House and Senate each have passed omnibus energy bills that
2
contain carbon sequestration provisions with many similarities and some important
differences. In H.R. 6, the proposed Renewable Fuels, Consumer Protection, and
Energy Efficiency Act of 2007 passed by the Senate on June 21, 2007, Title III, §302,
would expand the DOE program for carbon capture technology and place new
emphasis on R&D for carbon storage, including at least seven large-volume
sequestration tests of 1 million metric tons of carbon (MtCO )or more.5 Section 304
2
in the same title would create a new program for large-scale demonstration projects
that would capture CO from industrial sources and sequester it in one of the seven
2
4 For more information about carbon sequestration in forests and agricultural lands, see CRS
Report RL31432, Carbon Sequestration in Forests, by Ross Gorte; and CRS Report
RL33898, Climate Change: the Role of the U.S. Agriculture Sector, by Renée Johnson. 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.
5 One metric ton of CO equivalent is written as 1 tCO ; one million metric tons is written
2
2
as 1 MtCO ; one billion metric tons is written as 1 GtCO .
2
2

CRS-3
sequestration tests under §302, or in another storage project approved by the
Secretary of Energy.
On August 4, 2007, the House passed H.R. 3221, which includes provisions
under Title IV, Subtitle F, that are similar to carbon sequestration provisions in H.R.
6. Like H.R. 6, Subtitle F of H.R. 3221 would expand the DOE carbon sequestration
program, put new emphasis on the storage component of R&D, include large-volume
sequestration tests, and institute large-scale CO capture demonstration projects from
2
industrial facilities. In contrast to H.R. 6, the House-passed bill includes a provision
for EPA to conduct a research program to assess potential impacts of CO storage on
2
the environment, and public health and safety associated with CO capture and
2
sequestration. Under H.R. 3221, the National Academy of Sciences (NAS) would
review the large-scale sequestration and capture programs, beginning in 2011. Also,
H.R. 3221 establishes a grant program for graduate degrees in geological
sequestration science.
DOE is planning to spend approximately $100 million on the carbon
sequestration program in FY2007, and these bills would authorize substantial
increases over the next five years. H.R. 6, the Senate-passed bill, would authorize
nearly double the $86 million DOE requested for FY2008, and H.R. 3221, the House-
passed bill, nearly triples that amount, authorizing $240 million for DOE carbon
sequestration R&D in FY2008. H.R. 3221 authorizes a higher level of appropriations
for activities under Title IV, Subtitle F, than H.R. 6 — $1.7 billion over five years in
the House-passed bill compared to $1.4 billion over six years in the Senate-passed
bill. The Senate-passed bill would authorize roughly 80% of the funding levels that
are authorized in the House-passed bill, and spread the authorization over six instead
of five years.
Both bills contain nearly identical provisions for a new program to assess the
nation’s potential capacity for geological storage of CO
Title VII, Subtitle D, of
2.
H.R. 3221 would establish a program in the Department of the Interior (DOI), to be
carried out by the U.S. Geological Survey, that would develop a methodology for and
conduct an assessment of the CO storage capacity of the United States. Title III,
2
§303, of H.R. 6 establishes a nearly identical program, and both bills authorize $30
million over five years to carry out the assessment.
The omnibus energy bills passed by both chambers incorporate carbon
sequestration provisions from other legislation introduced earlier in the 110th
Congress. For example, Title III of H.R. 6 derives from S. 1321, the Energy Savings
Act of 2007, which in turn drew from S. 962, the Department of Energy Carbon
Capture and Storage Research, Development, and Demonstration Act of 2007, and
S. 731, the National Carbon Dioxide Storage Capacity Assessment Act of 2007.
Similarly, H.R. 3221 includes provisions from H.R. 1933, the companion bill to S.
962, and from H.R. 1267, the companion bill to S. 731.
Capturing and Separating CO2
The first step in direct sequestration is to produce a concentrated stream of CO2
for transport and storage. Currently, three main approaches are available to capture
CO from large-scale industrial facilities or power plants: (1) post-combustion
2

CRS-4
capture, (2) pre-combustion capture, and (3) oxy-fuel combustion capture. For power
plants, current commercial CO capture systems could operate at 85%-95% capture
2
efficiency.6 Techniques for capturing CO have not yet been applied to large power
2
plants (e.g., 500 megawatts or more).7
Post-Combustion Capture. This process involves extracting CO from the
2
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 CO from flue gases. U.S.
2
commercial electricity-generating plants currently do not capture large volumes of
CO because they are not required to and there are no economic incentives to do so.
2
Nevertheless, the post-combustion capture process includes proven technologies that
are commercially available today, and costs can be reasonably estimated for scaling
up for a large-scale application.
Pre-Combustion Capture. This process separates CO from the fuel by
2
combining it with air and/or steam to produce hydrogen for combustion and a
separate CO stream that could be stored. The most common technologies today use
2
steam reforming, in which steam is employed to extract hydrogen from natural gas.8
In the absence of a requirement or economic incentives, pre-combustion technologies
have not been used for power systems, such as natural gas combined-cycle power
plants.
Pre-combustion capture of CO is viewed by some as a necessary requirement
2
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 CO , and the end product — the liquid
2
fuel itself — further releases CO when combusted. Several bills have been
2
introduced in the 110th Congress that would spur coal-to-liquid fuels that proponents
argue would help reduce U.S. reliance on oil imports and alleviate strained refinery
capacity (and as an alternative use for coal). Pre-combustion capture during the
coal-to-liquid process would reduce the total amount of CO emitted, although CO
2
2
would still be released during combustion of the liquid fuel used for transportation
or electricity generation. For more information on the coal-to-liquid process and
issues for Congress, see CRS Report RL34133, Liquid Fuels from Coal, Natural
Gas, and Biomass: Background and Policy,
by Anthony Andrews.
Oxy-Fuel Combustion Capture. This process uses oxygen instead of air
for combustion and produces a flue gas that is mostly CO and water, which are
2
easily separable, after which the CO can be compressed, transported, and stored.
2
This technique is still considered developmental, in part because temperatures of pure
6 IPCC Special Report, p. 107.
7 IPCC Special Report, p. 25.
8 IPCC Special Report, p. 130.

CRS-5
oxygen combustion (about 3,500o Celsius) are far too high for typical power plant
materials.9
Application of these technologies to power plants generating several hundred
megawatts of electricity has not yet been demonstrated. Also, up to 80% of the total
costs may be associated with the capture phase of the CCS process.10 Costs are
discussed below in more detail.
Transportation
Pipelines are currently the most common method for transporting CO in the
2
United States. Over 2,500 kilometers (about 1,500 miles) of pipeline transports more
than 40 MtCO each year, predominantly to Texas, where CO is used in enhanced
2
2
oil recovery (EOR).11 Transporting CO in pipelines is similar to transporting
2
petroleum products like natural gas and oil; it requires attention to design, monitoring
for leaks, and protection against overpressure, especially in populated areas.12
Using ships may be feasible when CO needs to be transported over large
2
distances or overseas. Ships transport CO today, but at a small scale because of
2
limited demand. Liquified natural gas, propane, and butane are routinely shipped by
marine tankers on a large scale worldwide. Rail cars and trucks can also transport
CO , but this mode would probably be uneconomical for large-scale CCS operations.
2
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 CO transport system (in MtCO per year, for example) is operating. Ship costs
2
2
might be lower than pipeline transport for distances greater than 1,000 kilometers and
for less than a few MtCO transported per year.13
2
Even though regional CO pipeline networks currently operate in the United
2
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 CO itself, and pipeline safety. These
2
issues are discussed in more detail in CRS Report RL33971, Carbon Dioxide (CO )
2
9 IPCC Special Report, p. 122.
10 Steve Furnival, reservoir engineer at Senergy, Ltd., “Burying Climate Change for Good,”
Physics World; see [http://physicsweb.org/articles/world/19/9/3/1].
11 IPCC Special Report, p. 29.
12 IPCC Special Report, p. 181.
13 IPCC Special Report, p. 31.

CRS-6
Pipelines for Carbon Sequestration: Emerging Policy Issues, by Paul W. Parfomak
and Peter Folger.
Sequestration in Geological Formations
Three main types of geological formations are being considered for carbon
sequestration: (1) oil and gas reservoirs, (2) deep saline reservoirs, and (3)
unmineable coal seams. In each case, CO would be injected, in a dense form, below
2
ground into a porous rock formation that holds or previously held fluids. By
injecting CO below 800 meters in a typical reservoir, the pressure induces CO to
2
2
become supercritical — a relatively dense liquid — and thus less likely to migrate
out of the geological formation. Injecting CO into deep geological formations uses
2
existing technologies that have been primarily developed by and used for the oil and
gas industry, and that could potentially be adapted for long-term storage and
monitoring of CO . Other underground injection applications in practice today, such
2
as natural gas storage, deep injection of liquid wastes, and subsurface disposal of oil-
field brines, can also provide information for sequestering CO in geological
2
formations.14
The storage capacity for CO storage in geological formations is potentially huge
2
if all the sedimentary basins in the world are considered.15 The suitability of any
particular site, however, depends on many factors including proximity to CO sources
2
and other reservoir-specific qualities like porosity, permeability, and potential for
leakage. Figure 1 is a snapshot of current or planned projects (most are associated
with natural gas production) as of 2005 that involve CO storage in geological
2
formations. Table 2 lists their characteristics. The subsections below briefly
describe general characteristics of each of the three types of geological formations.
Oil and Gas Reservoirs. Pumping CO into oil and gas reservoirs to boost
2
production (enhanced oil recovery, or EOR) is practiced in the petroleum industry
today. The United States is a world leader in this technology and uses approximately
32 MtCO annually for EOR, according to DOE.16 The advantage of using this
2
technique for long-term CO storage is that sequestration costs can be partially offset
2
by revenues from oil and gas production. CO can also be injected into oil and gas
2
reservoirs that are completely depleted, which would serve the purpose of long-term
sequestration, but without any offsetting benefit from oil and gas production. CO2
can be stored onshore or offshore; to date, most CO projects associated with EOR
2
are onshore, with the bulk of U.S. activities in west Texas. (See Figure 1.)
14 IPCC Special Report, p. 31.
15 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 CO storage.
2
16 See [http://www.fossil.energy.gov/programs/sequestration/geologic/index.html].


CRS-7
Figure 1. Sites Where Activities Involving CO Storage Are Planned or Underway
2
Source: IPCC Special Report, Figure 5.1, p. 198.
Note: EOR is enhanced oil recovery; EGR is enhanced gas recovery; ECBM is enhanced coal bed methane recovery.
Depleted or abandoned oil and gas fields, especially in the United States, are
considered prime candidates for CO storage for several reasons:
2
! oil and gas originally trapped did not escape for millions of years,
demonstrating the structural integrity of the reservoir;
! extensive studies have typically characterized the geology of the
reservoir;
! computer models have often been developed to understand how
hydrocarbons move in the reservoir, and the models could be applied
to predicting how CO could move; and
2
! infrastructure and wells from oil and gas extraction may be in place
and might be used for handling CO storage.
2


CRS-8
Table 2. Current and Planned CO Storage Projects
2
Project
Country
Scale of
Lead
Injection
Approximate
Total
Storage type
Geological
Age of
Lithology
Monitoring
Project
organizations
start date
average daily
storage
storage
formation
injection rate
formation
Sleipner
Norway
Commercial
Statoil, IEA
1996
3000 t per day
20 Mt
Saline formation Utsira
Tertiary
Sandstone
4D seismic plus
planned
Formation
gravity
Weyburn
Canada
Commercial
EnCana, IEA
May 2000
3-5000 t per day
20 Mt
CO -EOR Midale
Mississippian Carbonate Comprehensive
2
planned
Formation
Minami-
Japan Demo Research
Institute
2002
Max 40 t per day
10,000 t
Saline formation Haizume
Pleistocene Sandstone
Crosswell
Nagoaka
of Innovative
planned
(Sth. Nagoaka
Formation
seismic + well
Technology for the
Gas Field)
monitoring
Earth
Yubari
Japan
Demo
Japanese Ministry
2004
10 t per day
200 t
CO -ECBM
Yubari
Tertiary
Coal
Comprehensive
2
of Economy, Trade
Planned
Formation
and Industry
(Ishikari Coal

Basin)
In Salah
Algeria
Commercial
Sonatrach, BP,
2004
3-4000 t per day
17 Mt
Depleted
Krechba
Carboniferous
Sandstone
Planned
Statoil
planned
hydrocarbon
Formation
comprehensive
reservoirs
Frio
USA
Pilot
Bureau of
Oct. 4-13,
Approx. 177 t per 1600t
Saline formation Frio Formation
Tertiary
Brine-
Comprehensive
Economic Geology 2004
day for 9 days
bearing
of the University
sandstone-
of Texas
shale
K12B
Netherlands
Demo
Gaz de France
2004
100-1000 t per
Approx
EGR
Rotleigendes
Permian
Sandstone
Comprehensive
day (2006+)
8 Mt
Fenn Big
Canada
Pilot
Alberta Research
1998
50 t per day
200 t
CO -ECBM
Mannville
Cretaceous
Coal
P, T, flow
2
Valley
Council
Group
Recopol
Poland
Pilot
TNO-NITG
2003
1 t per day
10 t
CO -ECBM
Silesian Basin
Carboniferous
Coal
2
(Netherlands)

CRS-9
Project
Country
Scale of
Lead
Injection
Approximate
Total
Storage type
Geological
Age of
Lithology
Monitoring
Project
organizations
start date
average daily
storage
storage
formation
injection rate
formation
Qinshui
China
Pilot
Alberta Research
2003
30 t per day
150 t
CO -ECBM
Shanxi
Carboniferous-
Coal
P, T, flow
2
Basin
Council
Formation
Permian
Salt Creek
USA
Commercial
Anadarko
2004
5-6000 t per day
27 Mt
CO -EOR
Frontier
Cretaceous
Sandstone
Under
2
development
Planned Projects (2005 onwards)
Snøhvit Norway
Decided
Statoil
2006
2000 t per day
Saline formation Tubaen
Lower Jurassic
Sandstone
Under
Commercial
Formation
development
Gorgon
Australia
Planned
Chevron
Planned
Approx. 10,000 t
Saline formation Dupuy
Late Jurassic
Massive
Under
Commercial
2009
per day
Formation
sandstone
development
Ketzin
Germany
Demo
GFZ Potsdam
2006
100 t per day
60 kt
Saline formation Stuttgart
Triassic
Sandstone Comprehensive
Formation
Otway
Australia
Pilot
CO2CRC
Planned late 160 t per day for
0.1 Mt
Saline fm and
Waarre
Cretaceous
Sandstone
Comprehensive
2005
2 years
depleted gas
Formation
field
Teapot
USA
Proposed
RMOTC
Proposed
170 t per day for 10 kt
Saline fm and
Tensleep and
Permian
Sandstone
Comprehensive
Dome
Demo
2006
3 months
CO -EOR
Red Peak Fm
2
CSEMP
Canada
Pilot
Suncor Energy
2005
50 t per day
10 kt
CO -ECBM
Ardley Fm
Tertiary
Coal
Comprehensive
2
Pembina
Canada
Pilot
Penn West
2005
50 t per day
50 kt
CO -EOR
Cardium Fm
Cretaceous
Sandstone
Comprehensive
2
Source: IPCC Special Report, Table 5.1, p. 201.
Note: EOR is enhanced oil recovery; EGR is enhanced gas recovery; ECBM is enhanced coal bed methane recovery.

CRS-10
Some of these features could also be disadvantages to CO sequestration. Wells
2
that penetrate from the surface to the reservoir could be conduits for CO release if
2
they are not plugged properly. Care must be taken not to overpressure the reservoir
during CO injection, which could fracture the caprock — the part of the formation
2
that formed a seal to trap oil and gas — and subsequently allow CO to escape. Also,
2
shallow oil and gas fields (those less than 800 meters deep, for example) may be
unsuitable because CO may form a gas instead of a denser liquid and could escape
2
to the surface more easily.
The In Salah Project in Algeria is the world’s first large-scale effort to store CO2
in a gas reservoir.17 (See Table 2.) At In Salah, CO is separated from the produced
2
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 CO produced from a coal
2
gasification plant in North Dakota for EOR, injecting up to 5,000 tCO per day into
2
the formation and recovering oil.18 (See Table 2.) Approximately 20 MtCO are
2
expected to remain in the formation over the lifetime of the project.
Table 3 shows that the global potential for CO storage in oil and gas fields may
2
be 900 GtCO . According to DOE, potential storage capacity in the United States is
2
approximately 80 Gt CO , roughly 10% of world potential. (See Table 4.)
2
Table 3. Estimated Global Capacity for CO Storage in
2
Three Different Geological Formations
(annual CO emissions for the U.S. and globally are shown for comparison)
2
Lower estimate
Upper estimate
CO from
2
of storage
of storage
combustion of
capacity
capacity
fossil fuels
Reservoir type
(GtCO )
(GtCO )
(GtCO )
2
2
2
Oil and gas
675
900

fields
Deep saline
1000
10,000a

formations
Unmineable
3
200

coal seams
United Statesb


5.65
Globalc


27.0
Sources: IPCC Special Report, Table 5.2, p. 221; U.S. Energy Information Agency; see
[http://www.eia.doe.gov/pub/international/iealf/tableh1co2.xls]; U.S. Environmental Protection
Agency (EPA), Inventory of U.S. Greenhouse Emissions and Sinks: 1990-2005.
a. The IPCC Special Report indicates that this number (10,000 GtCO ) is highly uncertain.
2
b. U.S. CO emissions in 2005.
2
c. Global CO emissions in 2004 (including the United States).
2
17 IPCC Special Report, p. 203.
18 IPCC Special Report, p. 204.

CRS-11
Deep Saline Reservoirs. Some rocks in sedimentary basins are saturated
with brines or brackish water unsuitable for agriculture or drinking. As with oil and
gas, deep saline reservoirs can be found onshore and 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.19 Using saline reservoirs for CO sequestration has several advantages:
2
! 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 CO .
2
! Saline reservoirs have potentially the largest reservoir capacity of the
three types of geologic formations (at least 1,000 GtCO , and
2
possibly ten times that globally; see Table 3).20 DOE estimates that
the U.S. storage capacity in saline reservoirs could range from 900
to 1,000 GtCO . (See Table 4.)
2
The Sleipner Project in the North Sea is the first commercial-scale operation for
sequestering CO in a deep saline reservoir (see Table 2.) As of 2005, Sleipner has
2
stored more than 7 MtCO . Carbon dioxide is separated from natural gas production
2
at the nearby Sleipner West Gas Field, then injected 800 meters below the seabed of
the North Sea into a saline formation at 2,700 tCO per day. Monitoring has
2
indicated the CO has not leaked from the saline reservoir, and computer simulations
2
suggest that the CO will eventually dissolve into the saline water, further reducing
2
the potential for leakage.
Large CO sequestration projects, similar to Sleipner, are being planned in
2
western Australia (the Gorgon Project) and in the Barents Sea (the Snohvits Project),
that will inject 10,000 and 2,000 tCO per day, respectively, when at capacity. (See
2
Figure 1 and Table 2.) Both projects plan to strip CO from produced natural gas
2
and inject it into deep saline formations for permanent storage.
Although deep saline reservoirs have huge potential capacity to store CO2
(Table 3), estimates of lower and upper capacities vary greatly, reflecting a high
degree of uncertainty in how to measure storage capacity.21 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 CO injection.
2
Injecting CO can acidify (lower the pH of) the fluids in the reservoir, dissolving
2
minerals such as calcium carbonate, and possibly increasing permeability. Increased
permeability could allow CO -rich fluids to escape the reservoir along new pathways
2
and contaminate aquifers used for drinking water.
19 DOE Office of Fossil Energy; see [http://www.fossil.energy.gov/programs/sequestration/
geologic/index.html].
20 IPCC Special Report, p. 223.
21 IPCC Special Report, p. 223.

CRS-12
In an October 2004 experiment, researchers injected 1,600 tCO 1,500 meters
2
deep into the Frio Formation — a saline reservoir containing oil and gas — along the
Gulf Coast near Dayton, TX, to test its performance for CO sequestration and
2
storage.22 Test results indicated that calcium carbonate and other minerals rapidly
dissolved following injection of the CO . The researchers also measured increased
2
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 CO injection
2
dissolved minerals that held high concentrations of those substances.
Another concern is whether the injected fluids, with pH lowered by CO , would
2
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 CO -rich
2
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 CO -rich plume from the injection point to the observation well in the target
2
zone. These results suggest to the researchers that they have the data and
experimental tools to move to the next, larger-scale, phase of CO injection
2
experiments.23
Unmineable Coal Seams. Table 3 shows that up to 200 GtCO could be
2
stored in unmineable coal seams around the globe. 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
bed24 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 CO binds even more
2
tightly to coal than methane.25 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 CO injection.
2
22 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.
23 Personal communication with Susan D. Hovorka, principal investigator for the Frio
Project, Bureau of Economic Geology, Jackson School of Geosciences, University of Texas
at Austin, August 22, 2007.
24 Coal bed and coal seam are interchangeable terms.
25 IPCC Special Report, p. 217.

CRS-13
According to DOE, between 150 and 170 Gt CO could be stored in unmineable
2
coal seams in the United States and parts of Canada. (See Table 4.) That estimate
represents a significant increase from estimates for North America provided in the
IPCC Special Report, and is a significant fraction of the global potential for coal-
seam storage estimated by IPCC. Not all types of coal beds are suitable for CBM
extraction, however. Without the coal bed methane resource, the sequestration
process would be less economically attractive. Given economic considerations, total
CO storage capacity in North America may be less than the DOE projections.
2
Unmineable coal seam injection projects will 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
CO is injected into a coal seam, it will likely remain there unless the seam is
2
depressurized or the coal is mined. Also, many unmineable coal seams in the United
States are located near electricity-generating facilities, which could reduce the
distance and cost of transporting CO from large point sources to storage sites.
2
Carbon dioxide injection into coal beds has been successful in the Alberta
Basin, Canada, and in a pilot project in the San Juan Basin of northern New Mexico.
(See Figure 1.) However, no commercial CO injection and sequestration project in
2
coal beds is currently underway. Without ongoing commercial experience, storing
CO in coal seams has significant uncertainties compared to the other two types of
2
geological storage discussed. According to IPCC, unmineable coal seams have the
smallest potential capacity for storing CO globally compared to oil and gas fields or
2
deep saline formations. However, DOE indicates that unmineable coal seams in the
United States have nearly double the capacity of oil and gas fields for storing CO .
2
The discrepancy could represent the relatively abundant U.S. coal reserves compared
to other regions in the world, or might also indicate the uncertainty in estimating the
CO storage capacity in unmineable coal seams.
2
Geological Storage Capacity for CO in the United States
2
In March 2007, DOE’s National Energy Technology Laboratory (NETL)
released an assessment of geological sequestration potential across the United States
and parts of Canada.26 According to DOE, the Carbon Sequestration Atlas represents
the first coordinated assessment of carbon sequestration potential, and includes the
most current and best available estimates of CO sequestration potential determined
2
by a consistent methodology. However, DOE also notes that some areas of the
United States yielded more and better-quality data than others, and acknowledges that
the data sets are not comprehensive. Table 4 shows the estimates broken down by
the three types discussed above: oil and gas reservoirs, deep saline formations, and
unmineable coal seams.
26 U.S. Dept. of Energy, National Energy Technology Laboratory, Carbon Sequestration
Atlas of the United States and Canada
, March, 2007, 86 pages; see [http://www.netl.doe.
gov/publications/carbon_seq/atlas/index.html]. Hereafter referred to as the Carbon
Sequestration Atlas. For an interactive version of the Carbon Sequestration Atlas and its
underlying data, see the National Carbon Sequestration Database and Geographical
Information System (NATCARB) at [http://www.natcarb.org].

CRS-14
Table 4 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 Carbon Sequestration Atlas explains 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.27 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 CO storage in oil and gas
2
formations is known to the level of precision stated in the Carbon Sequestration
Atlas. It is likely that the estimate of 82.4 GtCO shown in Table 4 may change, for
2
example, pending the results of large-scale CO injection tests in oil and gas fields.
2
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 CO sequestration potential.28 The Carbon
2
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 CO storage.
2
Table 4. Geological Sequestration Potential for the United
States and Parts of Canada
Lower estimate
Upper estimate of
of storage
storage capacity
Reservoir type
capacity (GtCO )
(GtCO )
2
2
Oil and gas fieldsa
82.4

Deep saline
919.0
3,378.0
formations
Unmineable coal
156.1
183.5
seams
Source: Carbon Sequestration Atlas.
a. According to DOE, oil and gas fields are sufficiently well-understood that no range of
values for storage capacity is given.
The Carbon Sequestration Atlas contains a discussion of the methodology used
to construct the estimates; however, because each partnership produced its own
estimates of reservoir capacity, some observers have raised the issue of consistency
among estimates across the regions. Partly because of those concerns, some interests
support legislation, contained in Senate-passed H.R. 6 and House-passed H.R. 1321
(discussed above), that shifts the responsibility for developing a single methodology
27 Carbon Sequestration Atlas, p. 12.
28 Carbon Sequestration Atlas, p. 6.

CRS-15
and for conducting a national geological carbon sequestration assessment to the U.S.
Geological Survey within the Department of the Interior. The DOE regional
partnerships are discussed in more detail later in this report.
Deep Ocean Sequestration
The world’s oceans contain approximately 50 times the amount of carbon stored
in the atmosphere and nearly 20 times the amount stored in plants and soils.29 The
oceans today take up — act as a net sink for — approximately 1.7 Gt CO per year,
2
and have stored approximately one-third, or more than 500 GtCO , of the total CO
2
2
released by humans to the atmosphere over the past 200 years.30 Over time, experts
predict that most CO released to the atmosphere from fossil fuel combustion will
2
eventually be absorbed in the ocean, but the rate of uptake depends on how fast the
ocean mixes the surface waters with the deep ocean, a process that takes decades to
centuries.
Injecting CO directly into the deep ocean is considered a potentially viable
2
process for long-term sequestration of large amounts of captured CO . The potential
2
for ocean storage of captured CO is huge, on the order of thousands of GtCO , but
2
2
environmental impacts on marine ecosystems and other issues may determine
whether large quantities of captured CO will ultimately be stored in the oceans.
2
Direct Injection. Injecting CO directly into the ocean would take advantage
2
of the slow rate of mixing, allowing the injected CO to remain sequestered until the
2
surface and deep waters mix and CO concentrations equilibrate with the atmosphere.
2
What happens to the CO would depend on how it is released into the ocean, the
2
depth of injection, and the temperature of the seawater. The fraction of CO stored
2
and retained in the ocean tends to be higher with deeper injection. Table 4 shows
estimates of the percent of CO retained in the ocean, over time, for different
2
injection depths according to one set of ocean models.
Table 5. Fraction of CO Retained for Ocean Storage
2
Injection depth
Year
800 ma
1500 mb
3000 mc
2100
78%
91%
99%
2200
50%
74%
94%
2300
36%
60%
87%
2400
28%
49%
79%
2500
23%
42%
71%
Source: IPCC Special Report, Table TS.7, p. 38.
Note: Models assume 100 years of continuous injection at three different depths beginning in 2000.
a. For 800 meter depths, model results vary by 6-7%.
b. For 1,500 meter depths, model results vary by 5-9%.
c. For 3,000 meter depths, model results vary by 1-14%.
29 IPCC Special Report, p. 281.
30 IPCC Special Report, p. 37.

CRS-16
Carbon dioxide injected above 500 meters in depth typically would be released
as a gas, and would rise towards the surface. Most of it would dissolve into seawater
if the injected CO gas bubbles were small enough.31 Below 500 meters in depth,
2
CO can exist as a liquid in the ocean, although it is less dense than seawater. After
2
injection at 500 meters, CO would also rise, but an estimated 90% would dissolve
2
in the first 200 meters. Below 3,000 meters in depth, CO is a liquid and is denser
2
than seawater; the injected CO would sink and dissolve in the water column or
2
possibly form a CO pool or lake on the sea bottom. Some researchers have proposed
2
injecting CO into the ocean bottom sediments below depths of 3,000 meters, and
2
immobilizing the CO as a dense liquid or solid CO hydrate.32 Deep storage in
2
2
ocean bottom sediments, below 3,000 meters in depth, might potentially sequester
CO for thousands of years.33
2
Limitations to Deep Ocean Sequestration. In addition to uncertainties
about cost, other concerns about storing CO in the oceans include the length of time
2
that injected CO remains in the ocean, the quantity retained, and environmental
2
impacts from elevated CO concentrations in the seawater. Also, deep ocean storage
2
is in a research stage. The types of problems associated with scaling up from small
research experiments, using less than 100 liters of CO ,34 to injecting several GtCO
2
2
into the deep ocean are unknown.
Injecting CO into the deep ocean would change ocean chemistry, locally at first,
2
and assuming hundreds of GtCO were injected, would eventually produce
2
measurable changes over the entire ocean. 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 CO sequestration are largely
2
unknown, however, because scientists know very little about deep ocean
ecosystems.35
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 tCO into water over 800 meters deep near the
2
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
31 IPCC Special Report, p. 285.
32 A CO hydrate is a crystalline compound formed at high pressures and low temperatures
2
by trapping CO molecules in a cage of water molecules.
2
33 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.
34 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.
35 IPCC Special Report, p. 298.

CRS-17
it would divert attention from reducing greenhouse gas emissions.36 A similar but
smaller project with plans to release more than 5 tCO into the deep ocean off the
2
coast of Norway, also in 2002, was cancelled by the Norway Ministry of the
Environment after opposition from environmental groups.37
Mineral Carbonation
Another option for sequestering CO produced by fossil fuel combustion
2
involves converting CO to solid inorganic carbonates, such as CaCO (limestone),
2
3
using chemical reactions. This process, known as “weathering,” also occurs naturally
but takes place over thousands or millions of years. The process can be accelerated
by reacting a high concentration of CO with minerals found in large quantities on
2
the Earth’s surface, such as olivine or serpentine.38 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 CO stream with the prepared minerals, and (3)
2
separating the carbonate products and storing them in a suitable repository.
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 CO . Large volumes of silicate oxide minerals are needed, from 1.6 to 3.7
2
tonnes (metric tons) of silicates per tCO sequestered. Thus, a large-scale mineral
2
carbonation process needs a large mining operation to provide the reactant minerals
in sufficient quantity.39 Large volumes of solid material would also be produced,
between 2.6 and 4.7 tonnes of materials per tCO sequestered, or 50%-100% more
2
material to be disposed of by volume than originally mined. Because mineral
carbonation is in the research and experimental stage, reasonably estimating the
amount of CO that could be sequestered by this technique is difficult.
2
One possible geological reservoir for CO storage — major flood basalts40 such
2
as those on the Columbia River Plateau — is being explored for its potential to react
with CO and form solid carbonates in situ (in place). Instead of mining, crushing,
2
36 Virginia Gewin, “Ocean carbon study to quit Hawaii,” Nature, vol. 417 (June 27, 2002):
p. 888.
37 Jim Giles, “Norway sinks ocean carbon study,” Nature, vol. 419 (Sep. 5, 2002): p. 6.
38 Serpentine and olivine are silicate oxide minerals — combinations of the silica, oxygen,
and magnesium — that react with CO to form magnesium carbonates. Wollastonite, a silica
2
oxide mineral containing calcium, reacts with CO to form calcium carbonate (limestone).
2
Magnesium and calcium carbonates are stable minerals over long time scales.
39 IPCC Special Report, p. 40.
40 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.

CRS-18
and milling the reactant minerals, as discussed above, CO would be injected directly
2
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 may have characteristics — such as high porosity and permeability —
that are favorable to storing CO . Those characteristics, combined with tendency of
2
basalt to react with CO could result in a large-scale conversion of the gas into stable,
2,
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 CO ; however, investigations are
2
in a preliminary stage.41
Costs for Direct Sequestration
According to one DOE estimate, sequestration costs for capture, transport, and
storage range from $100 to $300 per tonne of carbon emissions avoided using
present technology.42 In most carbon sequestration systems, the cost of capturing
CO is the largest component, possibly accounting for as much as 80% of the total.43
2
Cost information is sparse for large, integrated, commercial CCS systems because
few are currently operating, but estimates are available for the components of
hypothetical systems. Table 6 shows a range of estimated costs of each component
of a CCS system, using data from 2002, and assuming that prices for geological
storage are not offset by revenues from enhanced oil recovery or coal bed methane
extraction.
The wide range of costs for each component reflects the wide variability of site-
specific factors. With the exception of certain industrial applications, such as
capturing CO from natural gas production facilities (see Sleipner example, above),
2
CCS has not been used at a large scale. To date, no large electricity-generating
plants, the likely candidates for large-scale carbon sequestration, have incorporated
CCS. Retrofitting existing plants with CO capture systems would probably lead to
2
higher costs than newly built power plants that incorporate CCS systems, and
industrial sources of CO may be more easily retrofitted. Cost disadvantages of
2
retrofitting may be reduced for relative new and highly efficient existing plants.44
Capturing CO at electricity-generating power plants will likely require more
2
energy, per unit of power output, than required by plants without CCS. The
additional energy required also means that more CO would be produced, per unit of
2
power output. As a result, plants with CCS would be less efficient than plants
without CCS. Comparisons of costs between power plants with and without CCS
often include “avoided CO emissions” as well as captured CO emissions. Avoided
2
2
CO emissions takes into account the additional fuel needed to generate the
2
additional energy required to capture CO . Appendix A provides more information
2
about avoided versus captured CO emissions.
2
41 Carbon Sequestration Atlas, p. 23.
42 Equivalent to $27 to $82 per tCO emissions avoided; see [http://www.fossil.energy.gov/
2
programs/sequestration/overview.html].
43 Furnival, “Burying Climate Change for Good.”
44 IPCC Special Report, p. 10.

CRS-19
Table 6. Estimated Cost Ranges for Components of a Carbon Capture and
Storage System
(data from 2002)
CCS system components
Cost range
Remarks
Capture from a coal- or gas-fired
15-75 US$/tCO net captured
Net costs of captured CO , compared to the
2
2
power plant
same plant without capture.
Capture from hydrogen and
5-55 US$/tCO net captured
Applies to high-purity sources requiring
2
ammonia production or gas
simple drying and compression.
processing
Capture from other industrial
25-115 US$/tCO net captured
Range reflects use of a number of different
2
sources
technologies and fuels.
Transportation
1-8 US$/tCO transported
Per 250 km pipeline or shipping for mass
2
flow rates of 5 (high end) to 40 (low end)
MtCO per year.
2
Geological storage
0.5-8 US$/tCO net injected
Excluding potential revenues from EOR or
2
ECBM.
Geological storage: monitoring and 0.1-0.3 US$/tCO injected
This covers pre-injection, injection, and
2
verification
post-injection monitoring, and depends on
the regulatory requirements.
Ocean storage
5-30 US$/tCO net injected
Including offshore transportation of 100-500
2
km, excluding monitoring and verification.
Mineral carbonation
50-100 US$/tCO net
Range for the best case studied. Includes
2
mineralized
additional energy use for carbonation.
Source: IPCC Special Report, Table TS.9, p. 42.
Note: Costs are as applied to a type of power plant or industrial source, and represent costs for large-scale, new
installations, with assumed gas prices of $3-4.75 per MCF (thousand cubic feet), and assumed coal prices of $21.80-
32.70 per short ton (2,000 pounds).
Table 7 compares CO avoided versus CO captured for three different types of
2
2
power plants, and the increased fuel required for capturing CO at the plant. Table
2
8 compares the cost of electricity for plants without CCS against plants with CCS.
A 2007 DOE study of the cost and performance baseline for fossil energy plants
estimated that the total costs of CO avoided for three different types of plants were
2
as follows: $74.8 per tonne for pulverized coal (PC) plants; $42.9 per tonne for
integrated coal gasification combined cycle plants (IGCC); and $91.3 per tonne for
natural gas combined cycle plants (NGCC).45 The report noted that costs for CO2
avoided in IGCC plants are substantially less than for the other two types of plants
because CO removal takes place prior to combustion and at high pressures using
2
physical absorption. Costs of CO avoided are higher for NGCC plants because
2
baseline emissions for NGCC plants are 46% lower than IGCC plants; thus costs for
removing additional CO in NGCC plants are proportionately higher.
2
45 DOE/National Energy Technology Laboratory, Cost and Performance Baseline for Fossil
Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Final Repor
t,
DOE/NETL 2007/1281 (May, 2007), p. 15.

CRS-20
Table 7. Comparison of CO Captured Versus CO Avoided
2
2
for New Power Plants
Integrated coal
Natural gas
gasification
Power plants
Pulverized coal
combined cycle
combined cycle
CO captured
0.82-0.97 kg/kWh
0.36-0.41 kg/kWh
0.67-0.94 kg/kWh
2
CO avoided
0.62-0.70 kg/kWh
0.30-0.32 kg/kWh
0.59-0.73 kg/kWh
2
Increased fuel
24-40%
11-22%
14-25%
requirement
for capture
Source: From IPCC Special Report, Table 8.3a, p. 347.
Note: kWh is kilowatt hour; kg is kilogram.
Table 8. Comparison of Electricity Costs for New Power Plants
With and Without Carbon Capture and Geological Storage
Integrated coal
Natural gas
gasification
Power plants
Pulverized coal
combined cycle
combined cycle
Cost of
0.043-0.052 $/kWh
0.031-0.050 $/kWh
0.041-0.061 $/kWh
electricity (plant
without CCS)
Cost of
0.063-0.099 $/kWh
0.043-0.077 $/kWh
0.055-0.091 $/kWh
electricity (plant
with CCS)
Cost increase
47%-90%
39%-54%
34%-49%
Source: From IPCC Special Report, Table 8.3a, p. 347.
DOE states that the goal of its carbon sequestration program is to reduce costs
to $10 or less per tonne of carbon emissions avoided by 2015.46 That goal is
approximately 6% of the cost per tonne CO avoided by IGCC plants according to
2
the 2007 DOE study discussed above. Other sources suggest that costs of building
and operating CO capture systems will decline over time with sustained research and
2
development, and with technological improvements.47 Nevertheless, DOE’s goal
would require reducing costs for CCS by over 90% from today’s lower-end cost
estimates in less than 10 years.
Costs of capturing CO at a large electricity-generating plant would probably
2
dominate the overall cost of comprehensive CCS system. Thus, improving the
efficiency of the CO capture phase may produce the largest cost savings. However,
2
the variability of 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 CO storage, also
2
suggests that costs will vary widely from project to project.
46 Equivalent to $2.70 per tCO avoided; see [http://www.fossil.energy.gov/programs/
2
sequestration/overview.html].
47 IPCC Special Report, p. 41.

CRS-21
Research Programs and Demonstration Projects
Figure 1 and Table 2 list a number of geologic sequestration projects that are
planned or underway around the globe. Many are commercial projects that include
aspects of enhanced oil recovery and some are related to coal bed methane extraction.
The U.S. petroleum industry, for example, injects 32 MtCO per year of CO
2
2
underground for EOR, particularly in west Texas.48 The Sleipner Project in Norway,
using CO stripped from natural gas production, sequesters approximately 3,000 tCO
2
2
per day in a deep saline formation. Norway’s carbon tax of nearly 40 euro per tCO 49
2
was a strong economic incentive for the project; sequestration avoids nearly $50
million per year in carbon taxes.50 The Gorgon Project in western Australia, also
planning to use a deep saline formation, would inject 10,000 tCO per day recovered
2
from natural gas operations. Gorgon, expected to begin operations between 2008 and
2010, would be the world’s largest CO sequestration project.
2
In addition to the Sleipner Project, the Weyburn and In Salah Projects (discussed
above) are the other two ongoing, large-scale CCS projects underway worldwide.
Costs for large-scale projects and the role of national governments in supporting CCS
are influencing commercial decisions about whether to pursue capturing and storing
CO for EOR or other purposes. For example, BP announced in May 2007 that it was
2
cancelling a carbon capture project in Peterhead, Scotland, in which CO removed
2
from natural gas would have been injected in a North Sea oilfield for EOR.
According to news reports, one factor in the company’s decision was delay on the
part of the British government in supporting the project.51 BP is still pursuing its
plans in the United States to build a 500 MW plant near its Carson, CA, refinery that
would capture 4 MtCO per year and reinject it for EOR. The Carson plant would
2
convert petroleum coke, the byproduct of oil refining, to hydrogen for electricity
generation and capture the CO as a byproduct.
2
In March 2007, American Electric Power announced that it would move forward
on plans for a commercial-scale CCS system at its Mountaineer Plant in West
Virginia that would capture 100,000 tCO per year in a post-combustion process
2
using chilled ammonia, and inject it in a deep saline aquifer beneath the plant. The
decision follows a 10-year DOE-sponsored project on the site to help develop the
technology to move to a larger-scale system, and is touted as one of the success
stories within the DOE Carbon Sequestration Program.52
DOE Carbon Sequestration Program. DOE’s carbon sequestration
program marks its tenth year in 2007. Spending on carbon sequestration R&D has
48 See [http://www.fossil.energy.gov/programs/sequestration/geologic/index.html].
49 See CRS Report RL33581, Climate Change: The European Union’s Emissions Trading
System (EU-ETS), Appendix: Norway’s Trading System,
by Larry Parker.
50 Furnival, “Burying Climate Change for Good.”
51 BBC news, May 23, 2007, at [http://news.bbc.co.uk/1/hi/scotland/north_east/6685345.
stm].
52 Energy Washington Week, “DOE Touts Success of AEP Carbon Storage Efforts,” March
21, 2007.

CRS-22
grown to nearly $100 million53 in FY2007 from less than $5 million in FY1997. The
Administration budget proposal for FY2008 includes $86 million for the carbon
sequestration R&D program (excluding funding for the FutureGen program,
discussed below). The program has three main elements: (1) laboratory and pilot-
scale research for developing new technologies and systems; (2) infrastructure
development for future deployment of carbon sequestration using regional
partnerships; and (3) support for the DOE FutureGen project, a 10-year initiative to
build the world’s first integrated carbon sequestration and hydrogen production
power plant.
According to DOE, the overall goal of the program is to develop, by 2012,
systems that will achieve 90% capture of CO at less than a 10% increase in the cost
2
of energy services and retain 99% storage permanence.54 Developing systems to
capture and sequester CO , however, differs from when CCS technologies are
2
available for large-scale deployment and are actually deployed. In testimony before
the Senate Energy and Natural Resources Committee on April 16, 2007, Thomas D.
Shope, Acting Assistant Secretary for Fossil Energy at DOE, stated that under current
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.”55
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 Engineering Technology Laboratory. The program investigates five focus
areas: (1) CO capture; (2) carbon storage; (3) monitoring, mitigation, and
2
verification; (4) work on non-CO greenhouse gases; and (5) advancing breakthrough
2
technologies.
Beginning in 2003, DOE created seven regional carbon sequestration
partnerships to identify opportunities for carbon sequestration field tests in the United
States and Canada.56 The regional partnerships program is being implemented in a
53 DOE had originally included $74 million for the Carbon Sequestration Program in
FY2007, and has made available an additional $24 million from within the DOE Fossil
Energy Office, bringing the total to approximately $100 million for FY2007. Personal
communication, John Litynski, DOE National Energy Technology Laboratory, August 23,
2007.
54 DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, p. 5; see
[http://www.netl.doe.gov/publications/carbon_seq/project%20portfolio/2007/2007Road
map.pdf].
55 Testimony of Thomas D. Shope, Acting Assistant Secretary for Fossil Energy, DOE,
before the Senate Energy and Natural Resources Committee, April 16, 2007; at
[http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=110_senate_hearings&doci
d=f:36492.pdf].
56 The seven partnerships are Midwest Regional Carbon Sequestration Partnership; Midwest
(Illinois Basin) Geologic Sequestration Consortium; Southeast Regional Carbon
Sequestration Partnership; Southwest Regional Carbon Sequestration Partnership; West
(continued...)

CRS-23
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).57 According to the Carbon Sequestration Atlas, the first
phase of the partnership program identified the potential for sequestering over 1,000
GtCO across the United States and parts of Canada. On October 31, 2006, DOE
2
announced it will provide $450 million over the next 10 years for field tests in the
seven regions to validate results from smaller tests in the first phase, with an
additional cost share of 20% to be provided by each partnership. Figure 2 shows the
validation phase field tests by region.
The third phase, deployment, is intended to demonstrate large-volume,
prolonged injection and CO storage in a wide variety of geologic formations.
2
According to DOE, this phase is supposed to address the practical aspects of large-
scale operations, presumably producing the results necessary for commercial CCS
activities to move forward. One possible limitation to the deployment phase is,
paradoxically, access by each partnership region to large volumes of CO that can be
2
used for the large-scale injection projects. For regions nearby to currently available
sources of CO in large volume, such as those associated with EOR, availability of
2
CO may not be an issue. But availability could be a serious issue for other regions
2
where CO is not extracted or separated in large volumes for commercial use. That
2
possible limitation raises the issue of timing, whether CO capture technology and
2
transportation infrastructure will be ready to supply the needed million tonnes of CO2
per year over several years for the deployment stage tests.
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. The plant will be a coal-gasification
facility and will produce between 1 and 2 MtCO annually. DOE will provide most
2
of the funding. An industry consortium, the FutureGen Industrial Alliance, Inc.,58 is
expected to contribute up to $250 million, and international partners may contribute
up to 8% of the project’s cost.59 Since the original announcement, DOE has revised
56 (...continued)
Coast Regional Carbon Sequestration Partnership; Big Sky Regional Carbon Sequestration
Partnership; and Plains CO Reduction Partnership; see [http://www.fossil.energy.gov/
2
programs/sequestration/partnerships/index.html].
57 DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, p. 36.
58 As of Dec. 2006, 12 companies form the FutureGen Industrial Alliance: American Electric
Power; Southern Company; CONSOL Energy, Inc.; Rio Into Energy America (RHEA);
Peabody Energy; EON US; PAL Corporation; BHP Billiton; Foundation Coal Corp.; China
Hennaing Group; Anglo American; and Xstrata Coal. See [http://www.futuregenalliance.
org/].
59 DOE report to Congress, March 2004. See [http://www.fossil.energy.gov/programs/
powersystems/futuregen/futuregen_report_march_04.pdf].

CRS-24
its cost estimate to $1.5 billion net cost, calculated when anticipated revenue offsets
are included.60
Congress directed $9 million to initiate FutureGen in the conference report
(H.Rept. 108-330) for the 2004 Interior Appropriations Act. DOE spent
approximately $17 million for the project in FY2006, has allocated $54 million for
FutureGen in FY2007, and has requested $108 million for FY2008.
The FutureGen Industrial Alliance will conduct the first phase of the project. In
July 2006, from a list of 12 sites in seven states, they announced four finalists who
will compete to host the FutureGen plant.61 In May, 2007, DOE released a draft
Environmental Impact Statement (EIS) for the FutureGen project, announced it was
accepting public comments through July 16, 2007, and scheduled public hearings in
the four finalist sites. Following the National Environmental Policy Act review, the
FutureGen Alliance will select the final site, possibly in the latter half of 2007, and
issue a final EIS for the plant following site selection.
60 See [http://www.fossil.energy.gov/programs/powersystems/futuregen/index.html].
61 The four finalists are Mattoon, IL; Tuscola, IL; Heart of Brazos (near Jewett, TX); and
Odessa, TX.


CRS-25
Figure 2. DOE Carbon Sequestration Program Field Tests

CRS-26
Source: DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, Figure 22, p. 39.
Note: MRCSP is Midwest Regional Carbon Sequestration Partnership; MGSC is Midwest (Illinois
Basin) Geologic Sequestration Consortium; SECARB is Southeast Regional Carbon Sequestration
Partnership; SRCSP is Southwest Regional Carbon Sequestration Partnership; WESTCARB is West
Coast Regional Carbon Sequestration Partnership; Big Sky is Big Sky Regional Carbon Sequestration
Partnership; PCOR is Plains CO Reduction Partnership.
2
Issues for Congress
In March 2007, the Massachusetts Institute of Technology (MIT) released a
report called The Future of Coal, which concluded that CCS “is the critical enabling
technology that would reduce CO emissions significantly while also allowing coal
2
to meet the world’s pressing energy needs.”62 The report’s conclusion assumes that
a future, “carbon-constrained” world includes some level of a carbon charge, or a
price on CO emissions. The United States is not yet in a carbon-constrained world
2
and, in the absence of a price on CO and an economic incentive to invest in CCS,
2
technological advancement and commercial deployment of CCS may depend, at least
initially, on federal support. At issue for Congress is whether the current DOE
carbon sequestration R&D program is appropriate in its emphasis and funding, and
whether other agencies should be involved in carbon sequestration research as well.
A number of bills introduced in the 110th Congress would alter the DOE
program and would engage at least one other agency, the U.S. Geological Survey
within the Department of the Interior, in assessing the national capacity to
geologically store CO Both the House and Senate have passed bills — H.R. 3221
2.
and H.R. 6, respectively — that would authorize levels of funding for CCS R&D that
double or triple the current DOE spending over the next five to six years. Each bill
also gives the USGS prime responsibility for producing a methodology for and
conducting a national survey of the U.S. carbon sequestration potential. DOE
officials have acknowledged that more funding would help accelerate their timeline
for conducting large-volume CO injection tests across the United States. Whether
2
Congress will pass carbon sequestration legislation and appropriate the funds to
match spending levels in H.R. 6 or H.R. 3221 remain open questions.
It is widely recognized that costs for CO capture and compression, either pre-
2
or post-combustion, will dominate the overall costs of CCS, and that reducing those
costs will be imperative to widespread deployment of CCS technologies. The
premise of a carbon-constrained world, and the projected costs of carbon
sequestration, is influencing decisions made today about future fossil-fueled power
plants. For example, in 2007 a judge in a Minnesota public utility hearing
recommended against purchasing power from a proposed power plant, citing the high
cost estimates of CCS, which could double the cost of energy compared to an older
non-CCS plant, as a reason to reject the proposal.63 Thus, even without a price for
CO emissions, or a mandatory cap, the private sector is faced with a regulatory and
2
62 John Deutch, Ernest J. Moniz, et al., The Future of Coal, Cambridge, MA: Massachusetts
Institute of Technology (2007).
63 Rebecca Smith, “Coal’s Doubters Block New Wave of Power Plants,” Wall Street Journal
(July 25, 2007).

CRS-27
permitting environment that anticipates such requirements and is beginning to
include the potential cost of CCS into its decision-making process.
Paradoxically, and despite U.S. emissions of over 2 GtCO per year from
2
electricity generation alone, large-volume geologic sequestration tests of 1 MtCO2
per year may have difficulty finding sufficient and inexpensive quantities of CO to
2
inject underground. The difficulty ties back to the costs, and technological barriers,
of separating large volumes of CO from the flue streams of the hundreds of currently
2
operating coal-fired plants that hypothetically could furnish CO for the tests.
2
Congress may consider whether the U.S. carbon sequestration program is on track to
develop the technology that efficiently captures CO so that the costs of supplying
2
sufficient CO for large-volume sequestration tests across the country are not
2
prohibitive.
Other issues that Congress may consider for large-scale CCS deployment are not
discussed in this report. Liability and long-term ownership for CO sequestered
2
underground are two examples, especially as the treatment of CO transitions from
2
a commodity — as it is considered in EOR — to a pollutant, as the Supreme Court
has ruled in one case.64 Congress may also wish to consider the economic impacts
of a broad CCS infrastructure that could require large quantities of CO pipeline and
2
could raise issues of rights-of-way and safety. Infrastructure may be especially
important for areas of the country that lack geologic sequestration potential, such as
New England and the Carolinas. In those cases, other types of sequestration
strategies, such as deep-ocean disposal of CO , may become more attractive where
2
otherwise long and expensive pipeline networks would be required to transport CO2
from source to geologic reservoirs.
64 Massachusetts vs. EPA; at [http://www.supremecourtus.gov/opinions/06pdf/05-1120.pdf].


CRS-28
Appendix A. Avoided CO2

Figure 3 compares captured CO and avoided CO emissions. Additional
2
2
energy required for capture, transport, and storage of CO results in additional CO
2
2
production from a plant with CCS. The lower bar in Figure 3 shows the larger
amount of CO produced per unit of power (kWh) relative to the reference plant
2
(upper bar) without CCS. Unless no additional energy is required to capture,
transport, and store CO , the amount of CO avoided is always less than the amount
2
2
of CO captured. Thus the cost per tCO avoided is always more than the cost per
2
2
tCO captured.65
2
Figure 3. Avoided Versus Captured CO2
Source: IPCC Special Report, Figure 8.2.
65 IPCC Special Report, p. 346-347.