Order Code RL33801
Direct Carbon Sequestration:
Capturing and Storing CO2
January 17, 2007
Peter Folger
Specialist in Energy Policy
Resources, Science, and Industry Division

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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 CO emitted from fossil fuel use in the United States
2
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. CO2
emissions from fossil fuels.
Congressional interest is growing in direct sequestration as part of legislative
strategies addressing climate change. Several bills introduced in the 109th Congress
promoted carbon sequestration technologies for coal-fired power plants or coal
gasification facilities. Other bills included provisions for establishing carbon
sequestration programs, and one bill set goals for sequestering 60% of U.S.
greenhouse gas emissions from stationary sources by 2020. Congress appropriated
$67 million in FY2006 for the Department of Energy’s (DOE’s) carbon sequestration
program.
Approaches for capturing CO are available that can potentially remove 80%-
2
95% of CO emitted from a power plant or large industrial source. Pipelines or ships
2
will likely transport captured CO from capture to storage. Three main types of
2
geological formations are likely candidates for storing large amounts of CO : oil and
2
gas reservoirs, deep saline reservoirs, and unmineable coal seams. The deep ocean
also has a huge potential to store carbon. Direct injection of CO into the deep ocean,
2
however, is in an experimental stage. Mineral carbonation — reacting minerals with
a stream of concentrated CO to form a solid carbonate — is a well understood
2
process, but is in an experimental stage 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. The
department is also undertaking a 10-year, $1 billion project — known as FutureGen
— 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. DOE estimates that direct sequestration costs
between $100 and $300 per tonne of carbon emissions avoided using current
technologies. (A tonne refers to a metric ton, or 1,000 kilograms, which is
approximately 2,200 pounds.) Power plants with CCS would require more fuel, and
costs per kilowatt-hour would likely rise compared to plants without CCS.

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

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Direct Carbon Sequestration:
Capturing and Storing CO2
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 CO emitted to the atmosphere while allowing the use
2
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; and (3) storing
2
2
CO in geological reservoirs or in the oceans. As a measure for mitigating global
2
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 relatively small
2
scales. Also, potentially large amounts of CO generated from fossil fuels — as
2
much as one-third of the total CO emitted in the United States — could be eligible
2
for large-scale direct sequestration.1
Fossil fuel use 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 hydrogen production plants, that
already produce concentrated CO streams as part of the industrial process are also
2
good candidates for CO capture and storage.3
2
Congressional interest in direct sequestration, as part of legislation addressing
climate change, is growing. Several bills introduced in the 109th Congress would
have provided tax or financial incentives, or otherwise promoted carbon
sequestration technologies for coal-fired power plants or coal gasification facilities.
Other bills included provisions for establishing carbon sequestration programs and
one bill would have set goals for sequestering 60% of U.S. greenhouse gas emissions
from stationary sources by 2020. The Energy Policy Act of 2005 (P.L. 109-58)
directed DOE to undertake a 10-year research and development program to enhance
technological development of systems that capture or produce concentrated streams
of CO which can be stored. In FY2006, Congress appropriated $67 million for
2
DOE’s carbon sequestration program.
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: 1990-2004; 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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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 (see CRS Report RL31432, Carbon Sequestration in Forests, by
Ross Gorte) and agricultural lands store carbon, and the world’s oceans exchange
huge amounts of CO from the atmosphere through natural processes.
2
Table 1. Sources for CO Emissions in the United States from
2
Combustion of Fossil Fuels
Sources
CO Emissionsa
Percent of Total
2
Electricity generation
2,290.6
41%
Transportation
1,855.5
33%
Industrial
863.5
15%
Residential
369.6
7%
Commercial
226.0
4%
Total
5,605.2
100%
Source: U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Emissions and
Sinks: 1990-2004, Table ES-3; see [http://epa.gov/climatechange/emissions/usinventoryreport.html].
a. CO emissions in millions of metric tons (MtCO ) for 2004; totals exclude emissions from U.S.
2
2
territories.
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
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.4 Techniques for capturing CO have not yet been applied to large power
2
plants (e.g., 500 megawatts).5
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.
4 IPCC Special Report, p. 107.
5 Ibid., p. 25.

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CRS-3
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 CO2
storage. The most common technologies today use steam reforming, in which steam
is employed to extract hydrogen from natural gas.6 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.
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
oxygen combustion (about 3,500o Celsius) are far too high for typical power plant
materials.
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.7 Costs are
discussed below in more detail.
Transportation
Pipelines are the most common method for transporting CO in the United
2
States. Over 2,500 kilometers (about 1,500 miles) of pipeline transports more than
40 MtCO each year,8 predominantly to Texas, where CO is used in enhanced oil
2
2
recovery (EOR).9 Transporting CO in pipelines is similar to transporting petroleum
2
products like natural gas and oil; it requires attention to design, monitoring for leaks,
and protection against overpressure, especially in populated areas.10
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
6 IPCC Special Report, p. 130.
7 Steve Furnival, reservoir engineer at Senergy, Ltd., “Burying Climate Change for Good,”
Physics World; see [http://physicsweb.org/articles/world/19/9/3/1].
8 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
9 IPCC Special Report, p. 29.
10 Ibid., p. 181.

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CRS-4
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.11
2
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.12
The storage capacity for CO storage in geological formations is potentially huge
2
if all the sedimentary basins in the world are considered.13 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.14 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.)
11 IPCC Special Report, p. 31.
12 Ibid.
13 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
14 See [http://www.fossil.energy.gov/programs/sequestration/geologic/index.html].

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CRS-5
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
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
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.

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CRS-6
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
Aquifer
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
Aquifer (Sth.
Haizume
Pleistocene Sandstone
Crosswell
Nagoaka
of Innovative
planned
Nagoaka Gas
Formation
seismic + well
Technology for the
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)

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CRS-7
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.

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CRS-8
The In Salah Project in Algeria is the world’s first large-scale effort to store CO2
in a gas reservoir.15 (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.16 (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 . Potential storage capacity in the United States could be
2
approximately 11% of world potential, or about 100 GtCO .17
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 of
2004 CO emitted
2
of storage
storage capacity
from combustion of
Reservoir type
capacity (GtCO )
(GtCO )
fossil fuels (GtCO )
2
2
2
Oil and gas fields
675
900
—
Deep saline
1,000
Uncertain, possibly
—
formations
10,000
Unmineable coal
3
200
—
seams
United States
—
—
5.6
Global
—
—
27.0
(including U.S.)
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].
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.18 Using saline reservoirs for CO sequestration has several advantages:
2
15 IPCC Special Report, p. 203.
16 IPCC Special Report, p. 204.
17 Ibid., p. 222.
18 DOE Office of Fossil Energy; see [http://www.fossil.energy.gov/programs/sequestration/
geologic/index.html].

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CRS-9
! 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).19 DOE estimates that
the U.S. storage capacity in saline reservoirs could be half of the
minimum global estimate, or 500 GtCO , although some studies
2
point to higher estimates, approaching 1,000 GtCO in the United
2
States.20
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 aquifer at 2,700 tCO per day. Monitoring has indicated
2
the CO has not leaked from the saline reservoir, and computer simulations suggest
2
that the CO will eventually dissolve into the saline water, further reducing the
2
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.
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, Texas, to test its performance for CO sequestration and
2
storage.22 Test results indicated that calcium carbonate and other minerals rapidly
19 IPCC Special Report, p. 223.
20 Ibid.
21 Ibid.
22 Y. K. Kharaka et al., “Gas-water interactions in the Frio Formation following CO2
(continued...)

---

CRS-10
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. Researchers are conducting further injection tests and monitoring
whether the fluids are leaking.
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
bed23 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.24 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
An estimated 60-90 GtCO could be stored, potentially, in North American coal
2
seams.25 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
2
in North America may be only 3-15 GtCO .
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
22 (...continued)
injection: implications for the storage of greenhouse gases in sedimentary basins,” Geology,
v. 34, no. 7 (July, 2006), pp. 577-580.
23 Coal bed and coal seam are interchangeable terms.
24 IPCC Special Report, p. 217.
25 Ibid., p. 224.

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CRS-11
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. Also, of the three methods, unmineable coal seams
have the smallest potential capacity for storing CO .
2
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.26 The
oceans took up an average of 7 GtCO per year from 1980 to 2000, and have stored
2
approximately one-third, or more than 500 GtCO , of the total CO released by
2
2
humans to the atmosphere over the past 200 years.27 Over time, experts predict that
most CO released to the atmosphere from fossil fuel combustion will eventually be
2
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 fraction of CO retained in the ocean (0.99 is 99% retained), over
2
time, for different injection depths according to one set of ocean models.
Table 4. Fraction of CO Retained for Ocean Storage
2
Injection depth
Year
800 m
1500 m
3000 m
2100
0.78 ± 0.06
0.91 ± 0.05
0.99 ± 0.01
2200
0.50 ± 0.06
0.74 ± 0.07
0.94 ± 0.06
2300
0.36 ± 0.06
0.60 ± 0.08
0.87 ± 0.10
2400
0.28 ± 0.07
0.49 ± 0.09
0.79 ± 0.12
2500
0.23 ± 0.07
0.42 ± 0.09
0.71 ± 0.14
Source: IPCC Special Report, Table TS.7, p. 38.
Note: Models assume 100 years of continuous injection at three different depths beginning in 2000.
26 Ibid., p. 281.
27 IPCC Special Report, p. 37.

---

CRS-12
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.28 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 both a liquid and is
2
denser than seawater; the injected CO would sink and dissolve in the water column
2
or possibly form a CO pool or lake on the sea bottom. Some researchers have
2
proposed injecting CO into the ocean bottom sediments below depths of 3,000
2
meters, and immobilizing the CO as a dense liquid or solid CO hydrate.29 Deep
2
2
storage in ocean bottom sediments, below 3,000 meters in depth, might potentially
sequester CO for thousands of years.30
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 ,31 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.32
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
it would divert attention from reducing greenhouse gas emissions.33 A similar but
28 Ibid., p. 285.
29 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
30 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): p.
12291-12295.
31 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.
32 IPCC Special Report, p. 298.
33 Virginia Gewin, “Ocean carbon study to quit Hawaii,” Nature, vol. 417 (June 27, 2002):
(continued...)

---

CRS-13
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.34
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 could take place over thousands or millions of years. The process can be
accelerated by reacting a high concentration of CO with minerals found in large
2
quantities on the Earth’s surface, such as olivine or serpentine.35 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.36 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
Costs for Direct Sequestration
DOE estimates that sequestration costs — for capture, transport, and storage —
range from $100 to $300 per tonne of carbon emissions avoided using present
technology.37 In most carbon sequestration systems, the cost of capturing CO is the
2
33 (...continued)
p. 888.
34 Jim Giles, “Norway sinks ocean carbon study,” Nature, vol. 419 (Sep. 5, 2002): p. 6.
35 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.
36 IPCC Special Report, p. 40.
37 Equivalent to $27 to $82 per tCO emissions avoided.
2

---

CRS-14
largest component, possibly accounting for as much as 80% of the total.38 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 5 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.
Table 5. 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 yr-1.
2
Geological storagea
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).
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. 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 higher
2
costs than newly built power plants that incorporate CCS systems, and industrial
sources of CO may be more easily retrofitted. Cost disadvantages of retrofitting may
2
be reduced for relative new and highly efficient existing plants.39
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
38 Furnival, “Burying Climate Change for Good.”
39 IPCC Special Report, p. 10.

---

CRS-15
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
Table 6 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
7 compares the cost of electricity for plants without CCS — capture, transport, and
storage — against plants with CCS.
Table 6. 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 7. 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)
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 2015.40 That goal is 10% of
DOE’s lower estimate of today’s carbon sequestration costs. Other sources suggest
that costs of building and operating CO capture systems will decline over time with
2
sustained research and development, and with technological improvements.41
40 Equivalent to $2.70 per tCO avoided; see [http://www.fossil.energy.gov/programs/
2
sequestration/overview.html].
41 IPCC Special Report, p. 41.

---

CRS-16
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.
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.42 The Sleipner Project in Norway,
using CO stripped from natural gas production, sequesters approximately 3,000 tCO
2
2
per day of in a deep saline aquifer. Norway’s carbon tax of nearly 40 euro per tCO 43
2
was a strong economic incentive for the project; sequestration avoids nearly $50
million per year in carbon taxes.44 The Gorgon Project in western Australia, also
planning to use a deep saline aquifer, 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
DOE Carbon Sequestration Program. DOE’s carbon sequestration
program has grown to over $60 million per year since 1997, when it was less than $5
million. 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 (discussed below). The program seeks results from its program by 2012
that will lead to three goals: (1) ensure 90% capture of CO from power plants; (2)
2
store 99% of the sequestered CO over 100 years; and (3) add no more than 10% to
2
costs.45
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 CO2
capture, storage, monitoring, mitigation, and verification, and includes work on non-
CO greenhouse gases and on advancing breakthrough technologies.
2
42 See [http://www.fossil.energy.gov/programs/sequestration/geologic/index.html].
43 See CRS Report RL33581, Climate Change: The European Union’s Emissions Trading
System (EU-ETS), Appendix: Norway’s Trading System, by Larry Parker.
44 Furnival, “Burying Climate Change for Good.”
45 DOE Carbon Sequestration Technology Roadmap and Program Plan 2006, p. 9; see
[http://www.fossil.energy.gov/programs/sequestration/publications/programplans/2006/2
006_sequestration_roadmap.pdf].

---

CRS-17
Beginning in 2003, DOE created seven regional partnerships to identify
opportunities for carbon sequestration field tests in the United States and Canada.46
According to DOE, the first phase of the partnership program identified the potential
for sequestering 600 GtCO across the United States. 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. Figure 2 shows
the validation phase field tests by region.
Following the field test phase and starting in 2009, DOE plans to conduct large-
volume sequestration tests (up to 1 MtCO ) to demonstrate that the identified sites
2
can store large quantities of CO .
2
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.,47 is
expected to contribute up to $250 million, and international partners may contribute
up to 8% of the project’s cost.48 Congress directed $9 million to initiate FutureGen
in the conference report (H.Rept. 108-330) for the 2004 Interior Appropriations Act,
and most recently appropriated $18 million for the project in FY2006. The FY2007
budget request included $54 million for FutureGen.
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.49 DOE will conduct a National
Environmental Policy Act (NEPA) environmental analysis, will specify further site
characterization, and will provide public scoping meetings at the four sites in
anticipation of producing an Environmental Impact Statement for the plant after final
site selection. Following the NEPA review, the FutureGen Alliance will select the
final site, possibly in the latter half of 2007.
46 The seven partnerships are Midwest Regional Carbon Sequestration Partnership; Midwest
(Illinois Basin) Geologic Sequestration Consortium; Southeast Regional Carbon
Sequestration Partnership; Southwest Regional Carbon Sequestration Partnership; West
Coast Regional Carbon Sequestration Partnership; Big Sky Regional Carbon Sequestration
Partnership; and Plains CO Reduction Partnership; see [http://www.fossil.energy.gov/
2
programs/sequestration/partnerships/index.html].
47 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/].
48 DOE report to Congress, March 2004. See [http://www.fossil.energy.gov/programs/
powersystems/futuregen/futuregen_report_march_04.pdf].
49 The four finalists are Mattoon, IL; Tuscola, IL; Heart of Brazos (near Jewett, TX); and
Odessa, TX.

---

CRS-18
Figure 2. DOE Carbon Sequestration Program Field Tests

---

CRS-19
Source: DOE Carbon Sequestration Technology Roadmap and Program Plan 2006, Figure 14, p. 33.
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
Conclusion
In 2004, the United States emitted over 5.6 GtCO from fossil fuel combustion,
2
and electricity generation constituted nearly 40% of the total, or almost 2.3 GtCO .
2
By far the largest sources of CO amenable to direct carbon sequestration are fossil
2
fuel power plants.50 In addition to efforts that reduce CO emissions by increasing the
2
share of energy production from renewable sources, improving efficiency, and
fostering conservation, U.S. strategies to mitigate climate change in the near future
may include direct carbon sequestration. The federal government is already
committing resources towards that goal through the 10-year, $1 billion FutureGen
project, and with DOE’s carbon sequestration program, funded at $67 million in
FY2006. The only projects that directly inject large quantities of CO into the
2
subsurface in the United States today, however, are associated with enhancing oil and
gas recovery.
An integrated direct sequestration system would include three main steps: (1)
capturing and separating CO at the plant; (2) transporting the captured CO to the
2
2
storage site; and (3) storing CO in geological reservoirs or in the oceans.
2
Technologies to separate and compress CO are commercially available, but they
2
have not been applied to large scale CO capture from power plants for the purpose
2
of long term storage.51 Commercial operations that inject CO to enhance oil recovery
2
have the economic incentive of increasing revenues from oil production. Injecting
CO to enhance coal bed methane recovery has a similar incentive, although large
2
scale commercial CO injection projects to recover coal bed methane have not yet
2
been implemented. In contrast, the current economic incentives for direct carbon
sequestration to mitigate climate change are not clear. Norway’s carbon tax has
provided an incentive to sequester CO from one of its natural gas operations: the
2
Sleipner Project in Norway avoids nearly $50 million per year in carbon taxes by
stripping CO and storing it offshore in a deep saline aquifer.
2
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. Estimates of the total reservoir capacity vary widely and are
subject to large uncertainties — possibly up to several orders of magnitude —
reflecting an incomplete understanding of how to measure storage capacity. The
world’s oceans have the largest potential capacity to store CO , especially the deep
2
ocean below 3,000 meters. However, deep ocean sequestration of large amounts of
CO is in a research stage, and environmental concerns about acidification and
2
50 H. J. Herzog and D. Golumb, “Carbon Capture and Storage from Fossil Fuel Use,” in C.J.
Cleveland (ed.), Encyclopedia of Energy, New York, NY: Elsevier Science, Inc. (2004), p.
277-287.
51 Ibid.

---

CRS-20
impacts to marine ecosystems stymied ocean sequestration experiments off the coast
of Hawaii and Norway in 2002.
DOE plans to conduct direct carbon sequestration field tests over the next
several years in seven regional partnerships across the country. DOE also plans to
identify a final site for the FutureGen project, with the FutureGen Industrial Alliance,
which would be the world’s first large scale emission-free fossil fuel power plant.
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.52
2
Figure 3. Avoided Versus Captured CO2
Source: IPCC Special Report, Figure 8.2.
52 IPCC Special Report, p. 346-347.

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