Order Code RL33801
Carbon Capture and Sequestration (CCS)
Updated June 10, 2008
Peter Folger
Specialist in Energy and Natural Resources Policy
Resources, Science, and Industry Division

---

Carbon Capture and Sequestration (CCS)
Summary
Carbon capture and sequestration (or storage) — 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 United States
2
could be captured and stored underground. Electricity-generating plants are the most
likely initial candidates for CCS because they are predominantly large, single-point
sources, and they contribute approximately one-third of U.S. CO emissions from
2
fossil fuels.
Congressional interest is growing in CCS as a legislative strategy to address
climate change. The 110th Congress passed H.R. 6, the Energy Independence and
Security Act of 2007 (P.L. 110-140), which expands the Department of Energy
(DOE) carbon sequestration program and authorizes more than $2.2 billion for
research and development through FY2013. Congress appropriated $120 million for
CCS R&D at DOE in FY2008, a 50% increase above the request, although half the
amount authorized under P.L. 110-140. DOE is requesting $149.1 million for its
CCS R&D program in FY2009, a 25% increase over the FY2008 appropriated level.
At issue for Congress is whether the CCS program at DOE will conform to P.L. 110-
140, and whether funding provided by Congress will enable the program to meet its
goals and objectives. Other bills addressing climate change, notably S. 2191 (now
S. 3036), contain provisions that would provide other incentives for deploying CCS.
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 to storage sites. Three
2
main types of geological formations are likely candidates for storing large amounts
of CO : oil and gas reservoirs, deep saline reservoirs, and unmineable coal seams.
2
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 concerns have
2
forestalled planned experiments in the open ocean. Mineral carbonation — reacting
minerals with a stream of concentrated CO to form a solid carbonate — is a well
2
understood process, but is still experimental as a viable process for storing large
quantities of CO .
2
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. In January 2008, DOE announced that it was
restructuring the FutureGen program — originally conceived in 2003 as a 10-year,
$1 billion project to build a single power plant integrated with CCS — to instead
pursue a new strategy of multiple commercial demonstration projects. DOE based
its decision, in part, on rising costs for the original FutureGen concept. For FY2009,
DOE requests $156 million for the restructured program, and specifies that the
federal cost-share would only cover the CCS portions of the demonstration projects,
not the entire power system.

---

Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Carbon Sequestration Legislation in the 110th Congress . . . . . . . . . . . . . . . . 2
The Energy Independence and Security Act of 2007 . . . . . . . . . . . . . . . 2

Other Selected CCS-Related Legislation in the 110th Congress . . 4
The Consolidated Appropriations Act for 2008 (P.L. 110-161) . . . . . . 5
Capturing and Separating CO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
2
Post-Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Pre-Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Oxy-Fuel Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Sequestration in Geological Formations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Oil and Gas Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Deep Saline Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Unmineable Coal Seams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Geological Storage Capacity for CO in the United States . . . . . . . . . . . . . 15
2
Deep Ocean Sequestration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Direct Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Limitations to Deep Ocean Sequestration . . . . . . . . . . . . . . . . . . . . . . 18
Mineral Carbonation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Costs for Direct Sequestration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Research Programs and Demonstration Projects . . . . . . . . . . . . . . . . . . . . . 23
DOE Carbon Sequestration Program . . . . . . . . . . . . . . . . . . . . . . . . . . 24
FutureGen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Issues for Congress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Appendix A. Avoided CO
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
2
List of Figures
Figure 1. Sites Where Activities Involving CO Storage Are Planned
2
or Underway . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Figure 2. DOE Carbon Sequestration Program Field Tests . . . . . . . . . . . . . . . . . 27
Figure 3. Avoided Versus Captured CO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
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 . . . . . . . . . . . . . . . . . . . . . . 10
2
Table 3. Estimated Global Capacity for CO Storage in Three Different
2
Geological Formations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Table 4. Geological Sequestration Potential for the United States and
Parts of Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Table 5. Fraction of CO Retained for Ocean Storage . . . . . . . . . . . . . . . . . . . . 18
2
Table 6. Estimated Cost Ranges for Components of a Carbon Capture and
Storage System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Table 7. Comparison of CO Captured Versus CO Avoided for New
2
2
Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

---

Table 8. Comparison of Electricity Costs for New Power Plants With and Without
Carbon Capture and Geological Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

---

Carbon Capture and Sequestration (CCS)
Introduction
Carbon capture and sequestration (or storage) — known as CCS — is capturing
carbon at its source and storing it before its release to the atmosphere. CCS would
reduce the amount of carbon dioxide (CO ) emitted to the atmosphere despite the
2
continued use of fossil fuels. An integrated CCS system would include three main
steps: (1) capturing and separating CO ; (2) transporting the captured CO to the
2
2
sequestration site; and (3) sequestering CO in geological reservoirs or in the oceans.
2
As a measure for 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 CO2
underground, albeit at relatively small scales. Also, potentially large amounts of CO2
generated from fossil fuels — as much as one-third of the total CO emitted in the
2
United States — could 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, are the most likely initial candidates for capture, separation, and storage,
or reuse of CO because they are predominantly large, single-point sources for
2
emissions. Large industrial facilities, such as cement-manufacturing, ethanol, or
hydrogen production plants, that produce large quantities of CO as part of the
2
industrial process are also good candidates for CO capture and storage.3
2
Congressional interest in CCS, as part of legislation addressing climate change,
is growing. Congress passed legislation — H.R. 6, the Energy Independence and
Security Act of 2007 (P.L. 110-140, enacted on December 19, 2007) — that would
expand the current Department of Energy (DOE) carbon sequestration program and
authorize a four-fold increase in funding compared to DOE’s current program
spending levels. Several bills to establish cap-and-trade programs for limiting
greenhouse gas emissions include provisions for geologic sequestration. One bill,
S. 2191 — reported by the Senate Environment and Public Works Committee on
May 20, 2008 — would establish a cap that would reduce total greenhouse gas
emissions by an estimated 63% from 2005 levels by 2050, and award allowances for
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
geologic sequestration. (See below.) Whether the increase in R&D spending
authorized in P.L. 110-140, and incentives for carbon sequestration proposed in
various cap-and-trade bills introduced in the 110th Congress, are adequate to spur
carbon sequestration on a scale sufficient to slow or stop the buildup of greenhouse
gases in the atmosphere remains an open question.
This report covers only CCS and not other types of carbon sequestration
activities whereby CO is removed from the atmosphere and stored in vegetation,
2
soils, or 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
The Energy Independence and Security Act of 2007. P.L. 110-140, the
Energy Independence and Security Act of 2007, authorizes an expansion of the
current federal carbon sequestration research and development program at DOE and
places an increased emphasis on large-scale underground injection and storage
experiments. Title VII, Subtitle A, § 702, requires that DOE conduct at least seven
large-volume sequestration tests of 1 million metric tons of carbon (MtCO )5 or
2
more, in addition to conducting fundamental science and engineering research that
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
would apply to developing CCS technologies. Appropriations to carry out activities
under § 702 are authorized at $240 million per year for FY2008-FY2012, a total of
$1.2 billion over five years.
Section 703 of Title VII would authorize a program for projects that would
demonstrate technologies for large-scale capture of CO from a range of industrial
2
sources, as well as for transporting and injecting CO , and provide for integrating the
2
demonstration program with activities authorized under § 702. Appropriations for
the demonstration program under § 703 are authorized at $200 million per year for
FY2009-FY2013, a total of $1 billion over five years. Together, §§ 702 and 703
authorize a total of $2.2 billion through FY2013.
Under Title VII, § 704, the National Academy of Science (NAS) would review
the expanded R&D program beginning in 2011. Under § 705, DOE would arrange
with NAS to undertake a study to develop interdisciplinary graduate degree programs
with an emphasis in geologic sequestration science. Section 708 would establish a
university-based R&D program to study CCS using various types of coal.
Under the act, injection and sequestration activities under Subtitle A are subject
to requirements of the Safe Drinking Water Act. Further, the U.S. Environmental
Protection Agency is directed to assess potential impacts of carbon sequestration on
public health, safety, and the environment.
Under Subtitle B of Title VII, § 711 would direct the Department of the Interior
(DOI) to develop a methodology for an assessment of the national potential for
geologic storage of carbon dioxide. Not later than two years following publication
of the methodology, DOI would be directed to complete an assessment of national
capacity for CO storage in accordance with the methodology. Section 711 would
2
authorize a total of $30 million for FY2008-FY2012 for DOI to complete the
assessment and submit its findings to Congress. In addition to completing a national
assessment of CO storage capacity, DOI under § 714 would submit a report on a
2
recommended regulatory framework for managing geologic carbon sequestration on
public lands. The report is to include:
! an assessment of options to ensure the United States receives fair
market value for the use of public land;
! proposed procedures for public review and comment;
! procedures for protecting natural and cultural resources of the public
land overlying the geologic sequestration sites;
! a description of the status of liability issues related to the storage of
carbon dioxide in public land;
! identification of legal and regulatory issues for cases where the
United States owns title to the mineral resources but not the
overlying land;
! identification of issues related to carbon dioxide pipeline rights-of-
way; and
! recommendations for additional legislation that may be required for
adequate public land management and leasing to accommodate
geologic sequestration of carbon dioxide and pipeline rights-of-way.

---

CRS-4
Other Selected CCS-Related Legislation in the 110th Congress.
Several bills introduced in the 110th Congress contained elements that were
incorporated, in amended form, into P.L. 110-140. Other bills introduced in the first
session that propose cap-and-trade programs to reduce emissions of greenhouse gases
also contain provisions addressing geologic sequestration. Of these, S. 2191,
sponsored by Senators Lieberman and Warner, was reported by the Senate
Environment and Public Works Committee on May 20, 2008. A new version of the
bill, S. 3036 — identical to S. 2191 but containing a deficit reduction amendment
aimed at making the bill revenue-neutral — was introduced on May 20 and a cloture
motion was filed on May 22. On June 2, the Senate invoked cloture on the motion
to proceed, allowing discussion of the bill, but not allowing amendments. A vote on
June 6 failed to invoke cloture to end debate on the bill.
Other comprehensive cap-and-trade bills like S. 3036 may be introduced and
debated in the 110th Congress, but some observers indicate that chances of passage
in 2008 are slim. It is likely that, similar to S. 3036, other cap-and-trade legislation
will contain provisions addressing CCS. (A complete discussion of all cap-and-trade
bills is beyond the scope of this report; for more information, see CRS Report
RL33846, Greenhouse Gas Reduction: Cap-and-Trade Bills in the 110th Congress,
by Larry Parker and Brent D. Yacobucci.)
S. 3036 would cap emissions of greenhouse gases 19% below 2005 levels by
2020, and 63% below 2005 levels by 2050. The bill would allocate a portion of
bonus emission allowances6 on the basis of carbon sequestration. Under Title III,
Subtitle F of the bill, each qualifying project would initially receive allowances equal
to the number of metric tons of CO sequestered multiplied by 4.5. The multiplier
2
would decrease steadily from 2017 to 2031, and remain at 0.5 until 2039. For
example, qualifying projects that geologically sequester 1 MtCO in 2012 would be
2
eligible to receive 4,500,000 emission allowances. After 2031 and until 2039,
qualifying projects that sequester 1 MtCO could receive 500,000 emission
2
allowances.
Provisions such as Title III, Subtitle F in S. 3036 are intended to provide an
incentive to develop and deploy CCS to help mitigate CO emissions. Another cap-
2
and-trade bill, S. 1766, includes a similar provision whereby qualifying projects
would receive bonus emission allowances for CCS at a rate of 3.5 per metric ton in
2012, declining to 0.5 after 2031. As with S. 3036, geologic sequestration projects
encouraged by the availability of bonus emission allowances would be eligible for
the allowances only for the first ten years of operation. Two cap-and-trade bills
introduced in the House, H.R. 620 and H.R. 4226, would provide incentives for CCS
by establishing direct grant programs for the repowering of existing facilities or
construction of new coal gasification combined-cycle plants that capture and store
90% of their CO emissions.
2
6 An emission allowance, as defined in S. 2191, means authorization to emit 1 CO2
equivalent of greenhouse gas. One carbon dioxide equivalent is defined as the quantity of
greenhouse gas that makes the same contribution to global warming as 1 MtCO .
2

---

CRS-5
Other bills address different aspects of CCS. For example, S. 2144 would
require DOE to conduct a feasibility study of the construction and operation of
pipelines that would be used to carry CO from the point of capture to the storage
2
site. Another bill, S. 2323, contains a section that would establish an interagency
task force to develop regulations for CCS. The requirements under S. 2323 would
take into account current regulations governing underground injection, certification
and closure of capture and storage sites, potential transfer of liability, CO2
transportation issues, cost, and outcomes of planned demonstration projects.
The Consolidated Appropriations Act for 2008 (P.L. 110-161). The
Consolidated Appropriations Act for 2008 provides $120 million for DOE carbon
sequestration programs in FY2008.7 That amount is $40.923 million above the
FY2008 request (more than a 50% increase), and approximately $20 million above
what DOE spent on CCS R&D in FY2007.8 Congressionally directed spending listed
in the act would add an additional $6 million of CCS-related funding in FY2008.
The amount provided for carbon sequestration programs at DOE does not include
funding for FutureGen, which is funded separately in P.L. 110-161 at $75 million,
$33 million below the Administration request. (See below for further discussion of
FutureGen.)
The increase in the carbon sequestration program reflects, in part, new emphasis
on CCS in Congress as a strategy for reducing the buildup of greenhouse gases in the
atmosphere. The funding provided for FY2008, however, is half the amount
authorized for DOE carbon sequestration programs in P.L. 110-140, the Energy
Independence and Security Act of 2007. For FY2009, DOE requests $149.1 million,
a 25% increase over the levels appropriated for FY2008.
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.9 Techniques for capturing CO have not yet been applied to large power
2
plants (e.g., 500 megawatts or more).10
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
7 The amount does not reflect any rescissions required by the act.
8 The FY2007 CCS R&D program at DOE spent $97.2 million. U.S. Department of Energy,
FY2009 Congressional Budget Request, Volume 7, DOE/CF-030 (Washington, D.C.,
February 2008), p. 45. Hereafter referred to as DOE FY2009 Budget Request.
9 IPCC Special Report, p. 107.
10 IPCC Special Report, p. 25.

---

CRS-6
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.11
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.12
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.13
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.14 Costs are
discussed below in more detail.
11 IPCC Special Report, p. 130.
12 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.
13 IPCC Special Report, p. 122.
14 Steve Furnival, reservoir engineer at Senergy, Ltd., “Burying Climate Change for Good,”
Physics World; see [http://physicsweb.org/articles/world/19/9/3/1].

---

CRS-7
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).15 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.16
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.17
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.18
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
15 IPCC Special Report, p. 29.
16 IPCC Special Report, p. 181.
17 IPCC Special Report, p. 31.
18 These issues are discussed in more detail in CRS Report RL33971, Carbon Dioxide (CO )
2
Pipelines for Carbon Sequestration: Emerging Policy Issues, and CRS Report RL34316,
Pipelines for Carbon Dioxide (CO ) Control: Network Needs and Cost Uncertainties, by
2
Paul W. Parfomak and Peter Folger.

---

CRS-8
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.19
The storage capacity for CO storage in geological formations is potentially huge
2
if all the sedimentary basins in the world are considered.20 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.21 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.)
19 IPCC Special Report, p. 31.
20 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
21 See [http://www.fossil.energy.gov/programs/sequestration/geologic/index.html].

---

CRS-9
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.

---

CRS-10
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-11
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-12
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
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.22 (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.23 (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 U.S. oil and gas
2
fields is approximately 80 GtCO , roughly 10% of world potential. (See Table 4.)
2
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.24 Using saline reservoirs for CO sequestration has several advantages:
2
22 IPCC Special Report, p. 203.
23 IPCC Special Report, p. 204.
24 DOE Office of Fossil Energy; see [http://www.fossil.energy.gov/programs/sequestration/
geologic/index.html].

---

CRS-13
! 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).25 DOE estimates that
the U.S. storage capacity in saline reservoirs could range from 900
to over 3,000 GtCO . (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
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.
25 IPCC Special Report, p. 223.

---

CRS-14
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.26 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, TX, to test its performance for CO sequestration and
2
storage.27 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.28
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%
26 IPCC Special Report, p. 223.
27 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.
28 Personal communication with Susan D. Hovorka, principal investigator for the Frio
Project, Bureau of Economic Geology, Jackson School of Geosciences, University of Texas
at Austin, Aug. 22, 2007.

---

CRS-15
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
bed29 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.30 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
According to DOE, between 150 and 180 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
29 Coal bed and coal seam are interchangeable terms.
30 IPCC Special Report, p. 217.

---

CRS-16
and parts of Canada.31 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.
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.32 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.33 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
31 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/technologies/carbon_seq/refshelf/atlas/]. 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].
32 Carbon Sequestration Atlas, p. 12.
33 Carbon Sequestration Atlas, p. 6.

---

CRS-17
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. The Energy Independence and Security Act of
2007, enacted as P.L. 110-140 on December 19, 2007, directs the Department of the
Interior (DOI) to develop a single methodology for an assessment of the national
potential for geologic storage of carbon dioxide. Under P.L. 110-140, the U.S.
Geological Survey (USGS) within DOI would be directed to complete an assessment
of the national capacity for CO storage in accordance with the methodology. The
2
law gives the USGS two years following publication of the methodology to complete
the national assessment.
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.34 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.35 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
34 IPCC Special Report, p. 281.
35 IPCC Special Report, p. 37.

---

CRS-18
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 5 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%.
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.36 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.37 Deep storage in
2
2
ocean bottom sediments, below 3,000 meters in depth, might potentially sequester
CO for thousands of years.38
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
36 IPCC Special Report, p. 285.
37 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
38 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.

---

CRS-19
is in a research stage. The types of problems associated with scaling up from small
research experiments, using less than 100 liters of CO ,39 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.40
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.41 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.42
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.43 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
39 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.
40 IPCC Special Report, p. 298.
41 Virginia Gewin, “Ocean carbon study to quit Hawaii,” Nature, vol. 417 (June 27, 2002):
p. 888.
42 Jim Giles, “Norway sinks ocean carbon study,” Nature, vol. 419 (Sep. 5, 2002): p. 6.
43 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.

---

CRS-20
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.44 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 basalts45 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
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.46
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.47 In most carbon sequestration systems, the cost of capturing CO is the
2
largest component, possibly accounting for as much as 80% of the total.48 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.
44 IPCC Special Report, p. 40.
45 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.
46 Carbon Sequestration Atlas, p. 23.
47 Equivalent to $27 to $82 per tCO emissions avoided; see [http://www.fossil.energy.gov/
2
programs/sequestration/overview.html].
48 Furnival, “Burying Climate Change for Good.”

---

CRS-21
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.49
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
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).
49 IPCC Special Report, p. 10.

---

CRS-22
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).50 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
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.
50 DOE/National Energy Technology Laboratory, Cost and Performance Baseline for Fossil
Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity, Final Report,
DOE/NETL 2007/1281 (May, 2007), p. 15.

---

CRS-23
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 2015.51 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.52 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.
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.53 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 54
2
was a strong economic incentive for the project.55 The Gorgon Project in western
Australia, also planning to use a deep saline formation, would inject 10,000 tCO per
2
day recovered 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
51 Equivalent to $2.70 per tCO avoided; see [http://www.fossil.energy.gov/programs/
2
sequestration/overview.html].
52 IPCC Special Report, p. 41.
53 See [http://www.fossil.energy.gov/programs/sequestration/geologic/index.html].
54 See CRS Report RL33581, Climate Change: The European Union’s Emissions Trading
System (EU-ETS), Appendix: Norway’s Trading System, by Larry Parker.
55 Furnival, “Burying Climate Change for Good.”

---

CRS-24
part of the British government in supporting the project.56 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.57
DOE Carbon Sequestration Program. Spending on carbon sequestration
R&D at DOE grew from less than $5 million in FY1997 to nearly $100 million in
FY2007. The Administration budget request for FY2008 was $79 million for the
carbon sequestration R&D program; however, Congress provided $120 million58 for
the program in P.L. 110-161, the Consolidated Appropriations Act for 2008
(excluding funding for FutureGen, discussed below). The Administration request for
DOE’s carbon sequestration program in FY2009 is $149.1 million, a 25% increase
over the FY2008 appropriated level.59 In its budget justification for FY2009, DOE
states that the Innovations for Existing Plants (IEP) program will be refocused to
develop advanced technology for post-combustion capture of CO ; the IEP program
2
would provide $40 million for the new focus.60 DOE also states that its Advanced
Integrated Gasification Cycle program, funded at $69 million in the FY2009 budget
justification, would develop technologies deemed integral to CCS demonstration
projects.61
The DOE CCS 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 (FutureGen is funded separately in P.L. 110-161). DOE announced on
56 BBC news, May 23, 2007, at [http://news.bbc.co.uk/1/hi/scotland/north_east/6685345.
stm].
57 Energy Washington Week, “DOE Touts Success of AEP Carbon Storage Efforts,” March
21, 2007.
58 The actual appropriation for FY2008 is $118.9 million because of the 0.91% reduction
applied to certain DOE funding in P.L. 110-161.
59 U.S. Department of Energy, FY2009 Congressional Budget Request, Volume 7, DOE/CF-
030 (Washington, D.C., February 2008), p. 45. Hereafter referred to as DOE FY2009
Budget Request.
60 DOE FY2009 Budget Request, p. 46.
61 DOE FY2009 Budget Request, p. 47.

---

CRS-25
January 30, 2008, that the focus for FutureGen would change in FY2008 and beyond
(see below).
According to DOE, the overall goal of the CCS 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.62 The timeline for developing
systems to capture and sequester CO , however, differs from when CCS technologies
2
may become available for large-scale deployment and are actually deployed. In
testimony before the Senate Energy and Natural Resources Committee on April 16,
2007, Thomas D. Shope, Acting Assistant Secretary for Fossil Energy at DOE, stated
that under current 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.”63
The research aspect of the DOE program includes a combination of cost-shared
projects, industry-led development projects, research grants, and research at the
National Energy Technology Laboratory. The program investigates five focus areas:
(1) CO capture; (2) carbon storage; (3) monitoring, mitigation, and verification; (4)
2
work on non-CO greenhouse gases; and (5) advancing breakthrough technologies.
2
Beginning in 2003, DOE created seven regional carbon sequestration
partnerships to identify opportunities for carbon sequestration field tests in the United
States and Canada.64 The regional partnerships program is being implemented in a
three-phase overlapping approach: (1) characterization phase (from FY2003 to
FY2005); (2) validation phase (from FY2005 to FY2009); and (3) deployment phase
(from FY2008 to FY2017).65 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.
62 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].
63 Testimony of Thomas D. Shope, Acting Assistant Secretary for Fossil Energy, DOE,
before the Senate Energy and Natural Resources Committee, Apr. 16, 2007; at
[http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=110_senate_hearings&doci
d=f:36492.pdf].
64 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].
65 DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, p. 36.

---

CRS-26
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 to address the practical aspects of large-scale
operations, presumably producing the results necessary for commercial CCS
activities to move forward. On October 9, 2007, DOE announced that it awarded the
first three large-scale carbon sequestration projects in the United States.66 According
to DOE, each of the three projects plans to inject a million tons of CO or more into
2
deep saline reservoirs. The sequestration projects will be located in the Williston
Basin of North Dakota and Alberta Basin of Alberta, Canada; the Lower Tuscaloosa
Formation in the southeast United States; and the Entrada Formation in the
southwestern United States. On December 18, 2007, DOE announced its fourth
award for a large-scale CO injection and sequestration project in the Mount Simon
2
Formation of the Illinois Basin. The Mount Simon Formation project will inject
approximately 1,000 tons per day of CO underground for nearly three years,
2
followed by monitoring and modeling of the behavior of the injected CO in the
2
reservoir.67
One possible limitation to the deployment phase is, paradoxically, access by
each partnership region to large volumes of CO that can be used for the large-scale
2
injection projects. For regions nearby to currently available sources of CO in large
2
volume, such as those associated with EOR, availability of CO may not be an issue.
2
But availability could be a serious issue for other regions where CO is not extracted
2
or separated in large volumes for commercial use. That possible limitation raises the
issue of timing, whether CO capture technology and transportation infrastructure
2
will be ready to supply the needed million tonnes of CO per year over several years
2
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. As originally conceived, the plant would
have been a coal-gasification facility and produced between 1 and 2 MtCO annually.
2
On January 30, 2008, DOE announced that it was “restructuring” the FutureGen
program away from a single, state-of-the-art “living laboratory” of integrated R&D
technologies — a single plant — to instead pursue a new strategy of multiple
commercial demonstration projects.68 In the restructured program, DOE would
support up to two or three demonstration projects of at least 300 megawatts and that
would sequester at least 1 MtCO per year.
2
66 See [http://www.netl.doe.gov/publications/press/2007/07072-DOE_Awards_
Sequestration_Projects.html].
67 See [http://www.fossil.energy.gov/news/techlines/2007/07084-Illinois_Basin_
Sequestration_Proje.html].
68 See [http://www.fossil.energy.gov/news/techlines/2008/08003-DOE_Announces_
Restructured_FutureG.html].

---

CRS-27
Figure 2. DOE Carbon Sequestration Program Field Tests
Source: DOE Carbon Sequestration Technology Roadmap and Program Plan 2007, Figure 22, p. 39.

---

CRS-28
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 CO2
Reduction Partnership.
In its budget justification for FY2009, DOE cited “new market realities” for its
decision, namely rising material and labor costs for new power plants, and the need
to demonstrate commercial viability of Integrated Gasification Combined Cycle
(IGCC) power plants with CCS.69 The budget justification also noted that a number
of states are making approval of new power plants contingent on provisions to
control CO emissions, further underscoring the need to demonstrate commercial
2
viability of a new generation of coal-based power systems, according to DOE.
DOE requested $108 million for FutureGen in FY2008, but Congress
appropriated only $75 million, $33 million less than the request, due to unused prior
year funds. In remarks included in the explanatory statement accompanying P.L.
110-161, the Consolidated Appropriations Act for 2008, the appropriations
committees also cited concerns about maintaining core funding for fossil energy
R&D and demonstration programs. In its budget justification for FY2009, DOE
requests $156 million for the restructured program, and specifies that the federal cost-
share would only cover the CCS portions of the demonstration projects, not the entire
power system.
Prior to DOE’s announced restructuring of the program, the FutureGen Alliance
— an industry consortium of 13 companies — announced on December 18, 2007,
that it had selected Mattoon, IL, as the host site from a set of four finalists.70 In its
January 30, 2008, announcement, DOE stated that the four finalist locations may be
eligible to host an IGCC plant with CCS under the new program. It is unclear
whether these four sites would have an advantage over other possible sites under the
new FutureGen structure.
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.”71 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. The Energy Independence and Security Act of 2007
(P.L. 110-140) placed new emphasis on R&D and demonstration projects for CCS.
At issue for Congress is whether the DOE carbon sequestration R&D program will
69 DOE FY2009 Budget Request, p. 16.
70 The four were Mattoon, IL; Tuscola, IL; Heart of Brazos (near Jewett, TX); and Odessa,
TX.
71 John Deutch, Ernest J. Moniz, et al., The Future of Coal (Cambridge, MA: MIT, 2007).

---

CRS-29
conform to P.L. 110-140, and whether funding appropriated by Congress will enable
the program to meet its goals and objectives.
Other bills introduced in the 110th Congress, including those such as S. 3036
that would authorize cap-and-trade programs to curtail the growth of greenhouse gas
emissions,72 contain provisions that could provide incentives for CCS. Whether
Congress acts on those bills may, in part, determine how and how fast CCS is
implemented on a large scale.
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.73 Thus, even without a price for
CO emissions, or a mandatory cap, the private sector is faced with a regulatory and
2
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 evolves from a
2
commodity — as it is considered in EOR — to a pollutant, as the Supreme Court has
ruled in one case.74 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 southeastern Atlantic coast states. In those cases, other types
72 For more information on cap-and-trade bills in the 110th Congress, see CRS Report
RL33846, Greenhouse Gas Reduction: Cap-and-Trade Bills in the 110th Congress, by Larry
Parker and Brent D. Yacobucci.
73 Rebecca Smith, “Coal’s Doubters Block New Wave of Power Plants,” Wall Street Journal
(July 25, 2007).
74 Massachusetts vs. EPA; at [http://www.supremecourtus.gov/opinions/06pdf/05-1120.pdf].

---

CRS-30
of sequestration strategies, such as deep-ocean disposal of CO , may become more
2
attractive where otherwise long and expensive pipeline networks would be required
to transport CO from source to geologic reservoirs.
2

---

CRS-31
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.75
2
Figure 3. Avoided Versus Captured CO2
Source: IPCC Special Report, Figure 8.2.
75 IPCC Special Report, p. 346-347.

---