<DOC>
[110th Congress House Hearings]
[From the U.S. Government Printing Office via GPO Access]
[DOCID: f:35234.wais]
PROSPECTS FOR ADVANCED COAL
TECHNOLOGIES: EFFICIENT ENERGY PRODUCTION,
CARBON CAPTURE AND SEQUESTRATION
=======================================================================
HEARING
BEFORE THE
SUBCOMMITTEE ON ENERGY AND
ENVIRONMENT
COMMITTEE ON SCIENCE AND TECHNOLOGY
HOUSE OF REPRESENTATIVES
ONE HUNDRED TENTH CONGRESS
FIRST SESSION
__________
MAY 15, 2007
__________
Serial No. 110-29
__________
Printed for the use of the Committee on Science and Technology
Available via the World Wide Web: http://www.science.house.gov
______
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COMMITTEE ON SCIENCE AND TECHNOLOGY
HON. BART GORDON, Tennessee, Chairman
JERRY F. COSTELLO, Illinois RALPH M. HALL, Texas
EDDIE BERNICE JOHNSON, Texas F. JAMES SENSENBRENNER JR.,
LYNN C. WOOLSEY, California Wisconsin
MARK UDALL, Colorado LAMAR S. SMITH, Texas
DAVID WU, Oregon DANA ROHRABACHER, California
BRIAN BAIRD, Washington ROSCOE G. BARTLETT, Maryland
BRAD MILLER, North Carolina VERNON J. EHLERS, Michigan
DANIEL LIPINSKI, Illinois FRANK D. LUCAS, Oklahoma
NICK LAMPSON, Texas JUDY BIGGERT, Illinois
GABRIELLE GIFFORDS, Arizona W. TODD AKIN, Missouri
JERRY MCNERNEY, California JO BONNER, Alabama
PAUL KANJORSKI, Pennsylvania TOM FEENEY, Florida
DARLENE HOOLEY, Oregon RANDY NEUGEBAUER, Texas
STEVEN R. ROTHMAN, New Jersey BOB INGLIS, South Carolina
MICHAEL M. HONDA, California DAVID G. REICHERT, Washington
JIM MATHESON, Utah MICHAEL T. MCCAUL, Texas
MIKE ROSS, Arkansas MARIO DIAZ-BALART, Florida
BEN CHANDLER, Kentucky PHIL GINGREY, Georgia
RUSS CARNAHAN, Missouri BRIAN P. BILBRAY, California
CHARLIE MELANCON, Louisiana ADRIAN SMITH, Nebraska
BARON P. HILL, Indiana VACANCY
HARRY E. MITCHELL, Arizona
CHARLES A. WILSON, Ohio
------
Subcommittee on Energy and Environment
HON. NICK LAMPSON, Texas, Chairman
JERRY F. COSTELLO, Illinois BOB INGLIS, South Carolina
LYNN C. WOOLSEY, California ROSCOE G. BARTLETT, Maryland
DANIEL LIPINSKI, Illinois JUDY BIGGERT, Illinois
GABRIELLE GIFFORDS, Arizona W. TODD AKIN, Missouri
JERRY MCNERNEY, California RANDY NEUGEBAUER, Texas
MARK UDALL, Colorado MICHAEL T. MCCAUL, Texas
BRIAN BAIRD, Washington MARIO DIAZ-BALART, Florida
PAUL KANJORSKI, Pennsylvania
BART GORDON, Tennessee RALPH M. HALL, Texas
JEAN FRUCI Democratic Staff Director
CHRIS KING Democratic Professional Staff Member
MICHELLE DALLAFIOR Democratic Professional Staff Member
SHIMERE WILLIAMS Democratic Professional Staff Member
ELAINE PAULIONIS Democratic Professional Staff Member
ADAM ROSENBERG Democratic Professional Staff Member
ELIZABETH STACK Republican Professional Staff Member
STACEY STEEP Research Assistant
C O N T E N T S
May 15, 2007
Page
Witness List..................................................... 2
Hearing Charter.................................................. 3
Opening Statements
Statement by Representative Nick Lampson, Chairman, Subcommittee
on Energy and Environment, Committee on Science and Technology,
U.S. House of Representatives.................................. 6
Written Statement............................................ 6
Statement by Representative Bob Inglis, Ranking Minority Member,
Subcommittee on Energy and Environment, Committee on Science
and Technology, U.S. House of Representatives.................. 7
Written Statement............................................ 8
Prepared Statement by Representative Jerry F. Costello, Member,
Subcommittee on Energy and Environment, Committee on Science
and Technology, U.S. House of Representatives.................. 8
Witnesses:
Mr. Carl O. Bauer, Director, National Energy Technology
Laboratory, U.S. Department of Energy
Oral Statement............................................... 9
Written Statement............................................ 11
Biography.................................................... 14
Dr. Robert J. Finley, Director, Energy and Earth Resources
Center, Illinois State Geological Survey
Oral Statement............................................... 15
Written Statement............................................ 17
Biography.................................................... 18
Mr. Michael W. Rencheck, Senior Vice President, Engineering,
Projects and Field Services, American Electric Power
Oral Statement............................................... 19
Written Statement............................................ 20
Biography.................................................... 33
Mr. Stuart M. Dalton, Director, Generation, Electric Power
Research Institute
Oral Statement............................................... 34
Written Statement............................................ 34
Biography.................................................... 43
Mr. Gardiner Hill, Director, CCS Technology, Alternative Energy,
BP
Oral Statement............................................... 44
Written Statement............................................ 46
Discussion
Carbon Sequestration Risks..................................... 48
Regulatory Requirements........................................ 49
Carbon Sequestration Sites..................................... 50
Carbon Dioxide Transportation.................................. 50
Carbon Sequestration Atlas..................................... 51
CCS Technology Readiness....................................... 52
Other Uses for CO<INF>2.....................................</INF> 55
Western Regional Partnerships.................................. 55
Funding Concerns............................................... 57
Carbon Capture for Coal to Liquids............................. 58
Efficiency..................................................... 60
Basic Organic Chemistry........................................ 63
Carbon Capture................................................. 63
H.R. 1933, the Department of Energy Carbon Capture and Storage
Research, Development, and Demonstration Act................. 65
More on Carbon Sequestration Risks............................. 67
Appendix 1: Answers to Post-Hearing Questions
Mr. Carl O. Bauer, Director, National Energy Technology
Laboratory, U.S. Department of Energy.......................... 70
Appendix 2: Additional Material for the Record
H.R. 1933, Department of Energy Carbon Capture and Storage
Research, Development, and Demonstration Act of 2007........... 74
PROSPECTS FOR ADVANCED COAL TECHNOLOGIES: EFFICIENT ENERGY PRODUCTION,
CARBON CAPTURE AND SEQUESTRATION
----------
TUESDAY, MAY 15, 2007
House of Representatives,
Subcommittee on Energy and Environment,
Committee on Science and Technology,
Washington, DC.
The Subcommittee met, pursuant to call, at 1:05 p.m., in
Room 2318 of the Rayburn House Office Building, Hon. Nick
Lampson [Chairman of the Subcommittee] presiding.
[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]
hearing charter
SUBCOMMITTEE ON ENERGY AND ENVIRONMENT
COMMITTEE ON SCIENCE AND TECHNOLOGY
U.S. HOUSE OF REPRESENTATIVES
Prospects for Advanced Coal
Technologies: Efficient Energy Production,
Carbon Capture and Sequestration
tuesday, may 15, 2007
1:00 p.m.-3:00 p.m.
2318 rayburn house office building
Purpose
On Tuesday, May 15, 2007 the Subcommittee on Energy and Environment
of the Committee on Science and Technology will hold a hearing to
receive testimony on the advancement of coal technologies and carbon
capture and sequestration strategies which will help to reduce the
emissions of greenhouse gases, in particular, carbon dioxide.
The Department of Energy has a number of ongoing research and
development programs designed to demonstrate advanced technologies that
reduce coal power's carbon emissions. In addition, some industry
leaders also have begun to invest in advanced coal technologies. The
Committee will hear testimony from five witnesses who will speak to the
current research, development, demonstration and ultimate commercial
application of technologies that enable our power plants to operate
more efficiently, reduce emissions, and capture carbon for long-term
storage. They will discuss the technological and economic challenges we
face in limiting carbon emissions and safely managing the captured
carbon on a large scale.
Witnesses
1. Mr. Carl O. Bauer, Director of the National Energy
Technology Laboratory (NETL), a national laboratory owned and
operated by the Department of Energy. In his current position
as Director of NETL, he oversees the implementation of major
science and technology development programs to resolve the
environmental, supply and reliability constraints of producing
and using fossil resources, including advanced coal-fueled
power generation, carbon sequestration, and environmental
control for the existing fleet of fossil steam plants.
2. Dr. Robert J. Finley, Director Energy and Earth Resources
Center for Illinois State Geological Survey with specialization
in fossil energy resources. He is currently heading a regional
carbon sequestration partnership in the Illinois Basin aimed at
addressing concerns with geological carbon management.
3. Mr. Michael Rencheck, Senior Vice President for Engineering
Projects and Field Services at American Electric Power
headquartered in Columbus, Ohio. He is responsible for
engineering, regional maintenance and shop service
organizations, projects and construction, and new generation
development. He will discuss ongoing projects at AEP and can
talk to plant efficiencies and retrofitting facilities to
capture carbon.
4. Mr. Stu Dalton, Director, Generation at the Electric Power
Research Institute. His current research activities cover a
wide variety of generation options with special focus on
emerging generation, coal-based generation, emission controls
and CO<INF>2</INF> capture and storage. He also helped to
create the EPRI Coal Fleet for Tomorrow program.
5. Mr. Gardiner Hill, Director of Technology in Alternative
Energy Technology, is responsible for BP group-wide aspects of
CO<INF>2</INF> Capture and Storage technology development,
demonstration and deployment. He also is the BP manager
responsible for the BP/Ford/Princeton Carbon Mitigation
Initiative at Princeton University as well as the BP manager
responsible for the BP/Harvard partnership on the Energy
Technology Innovation Project. He posses 20 years of technical
and managerial experience which is directly relevant to
technology, business and project management.
Background
Approximately 50 percent of the electricity generated in the United
States is from coal. According to DOE's Energy Information
Administration (EIA) carbon dioxide emissions in the United States and
its territories were 6,008.6 million metric tons (MMT) in 2005. In the
United States, most CO<INF>2</INF> is emitted as a result of the
combustion of fossil fuels. In particular, the electric power sector
accounts for 40 percent of the CO<INF>2</INF> emissions in the U.S.,
according to EIA.
If we are going to implement policies to reduce greenhouse gas
emissions associated with the use of coal, what technologies are
currently available, what technologies need to be developed or
improved, and what technical challenges must we overcome to meet that
goal? There are two primary approaches to reducing emissions associated
with coal-fired power production: increasing the efficiency of coal-
fired plants (through replacement with new plants or retrofitting
existing plants) and through installation of carbon capture technology
and transporting CO<INF>2</INF> to a permanent storage facility.
CO<INF>2</INF> Capture
Retrofitting existing coal-fired power plants to capture carbon is
a critical component of any strategy to reduce our emissions of
greenhouse gases. Carbon capture applications may be installed in new
energy plants or retrofitted to existing plants. Some outstanding
issues with retrofitting existing plants include site constraints such
as availability of land for the capture equipment and the need for a
long remaining plant life to justify the large expense of installing
the capture equipment. Another potential barrier to retrofitting is the
loss in efficiency that can occur due to the energy required to operate
the carbon-capture equipment.
The first step in carbon capture and sequestration is to produce a
concentrated stream of CO<INF>2</INF> for capture. Currently, there are
three main approaches to capture CO<INF>2</INF> from large-scale
industrial facilities or power plants: 1) post-combustion capture, 2)
pre-combustion capture, and 3) oxy-fuel combustion capture.
Post-combustion capture process, although not required, involves
extracting CO<INF>2</INF> from the flue gas following combustion of
fossil fuels. There are commercially available technologies that use
chemical solvents to absorb the carbon.
Pre-combustion capture separates CO<INF>2</INF> from the fuel by
combining it with air and/or steam to produce hydrogen for combustion
and CO<INF>2</INF> for storage. The most commonly discussed type of
pre-combustion capture technology is the gasification method.
Gasification is a method of taking low-value feedstocks such as coal,
biomass or petroleum coke and transforming them through a chemical
process to make high value products such as chemicals or electricity.
Integrated Gasification Combined Cycle (IGCC)--often discussed as a
major breakthrough to improve the environmental performance of coal-
based electric power generation--is a form of gasification, which uses
syngas created from the gasification process as the feedstock, to power
a combined-cycle turbine used to produce electricity. IGCC has the
ability to produce a relatively pure stream of CO<INF>2</INF> arguably
making it better suited for carbon capture than a pulverized coal
plant.
Oxy-fuel combustion capture uses oxygen instead of air for
combustion and produces a flue gas that is mostly CO<INF>2</INF> and
water which are easily separated. This technique is considered
developmental and has not been widely applied for power production,
mainly because the temperatures that result from the combustion of pure
oxygen are far too high for typical power plant materials.
CO<INF>2</INF> Sequestration
Geologic sequestration of CO<INF>2</INF> is considered the most
feasible and widely studied method of storage. There are three main
types of geologic formations: 1) oil and gas reservoirs, 2) deep saline
reservoirs, and 3) unmineable coal seams.
When CO<INF>2</INF> is injected below 800 meters in a typical
reservoir, the pressure induces CO<INF>2</INF> to behave like a
relatively dense liquid. This state is known as ``super-critical.''
With each of the three methods listed above, CO<INF>2</INF> would be
injected into reservoirs that hold, or previously held liquids or
gases. In addition, injecting CO<INF>2</INF> into deep geological
formations uses existing technologies that have been primarily
developed by and used for the oil and gas industry. For these reasons,
geologic sequestration appears to be a promising carbon storage
strategy.
Pumping CO<INF>2</INF> into oil and gas reservoirs to boost
production, a process known as enhanced oil recovery (EOR) is practiced
by the petroleum industry today. Using EOR for long-term CO<INF>2</INF>
storage is beneficial because sequestration costs can be partially
offset by revenues from oil and gas production. However, the primary
purpose of CO<INF>2</INF> for EOR was not intended to serve the need
for long-term sequestration of CO<INF>2</INF> and the degree to which
injected CO<INF>2</INF> remains in the reservoir in many areas
utilizing EOR is unknown.
Depleted or abandoned oil and gas fields are potential candidates
for CO<INF>2</INF> storage because the oil and gas originally trapped
did not escape for millions of years demonstrating the structural
integrity of these reservoirs. Because of their value as sources of oil
and gas, these reservoirs have been mapped and studied and computer
models have often been developed to understand how hydrocarbons move in
the reservoir. These models could be applied to predict the potential
movement of CO<INF>2</INF> within these reservoirs.
Still, there are concerns with using oil and gas reservoirs for
CO<INF>2</INF> storage that stem from the stability of the reservoir
post-production and the degree of certainty that leakage could be
prevented.
A noteworthy project is the Weyburn Project in south-central Canada
which uses CO<INF>2</INF> produced from a coal gasification plant in
North Dakota for EOR. According to CRS, comprehensive monitoring is
being conducted at Weyburn.
Deep saline formations are sedimentary basins saturated with saline
or briny water that is unfit for human consumption or agricultural use.
As with oil and gas, deep saline reservoirs can be found onshore and
offshore. There are advantages of using saline reservoirs for CO<INF>2</INF>
sequestration: they are more widespread in the U.S. than oil and gas
reservoirs and potentially have the largest reservoir capacity of the
three types of geologic formations being considered for carbon
sequestration.
The first commercial-scale operation for sequestering CO<INF>2</INF>
in a deep saline reservoir is the Sleipner Project in the North Sea.
While deep saline reservoirs have huge potential capacity to store
CO<INF>2</INF>, there is concern about maintaining the integrity of the
reservoir because of chemical reactions following CO<INF>2</INF>
injection. CO<INF>2</INF> can acidify the fluids in the reservoir,
dissolving minerals such as calcium carbonate, and possibly weakening
the reliability of the storage site. Increased permeability could allow
the CO<INF>2</INF> to create new pathways that lead to contamination of
aquifers used for drinking water.
Many coal seams are unmineable with current technology because the
coal beds are not thick enough, the beds are too deep, or the
structural integrity of the coal bed is inadequate for mining. Because
coal beds are highly permeable they tend to trap gases, such as
methane, that bind themselves to the coal. CO<INF>2</INF> binds even
more tightly to coal than methane, thus making it possible to store the
unwanted CO<INF>2</INF> and increase the recovery of the valuable
coalbed methane.
Efficient Energy Production and Retrofitting Existing Coal-fired Power
Plants
EIA projections show that a two percent increase in coal efficiency
would exceed all additional renewable power generation through the EIA
forecast period (2030).
Raising the efficiency of power plants is part of the debate on how
best to reduce carbon dioxide emissions. Adopting advanced power
generating systems could help plant efficiency for coal-fired power
plants. For example, the Department of Energy's National Energy
Technology Laboratory (NETL) is developing technologies to ensure
existing and future coal power systems are more efficient and burn more
cleanly. Their work includes gasification, advanced combustion, and
turbine and heat engine technologies. Coal power plants operate at
approximately a 33 percent efficiency level and NETL is striving to
develop technologies for a central power plant that is capable of 60
percent efficiency with near zero emissions by 2020.
In addition to designing new plants to be more efficient, NETL and
others are working on technologies that can be utilized to improve the
efficiency of existing coal-fired power plants. In the short-term,
options such as converting from sub-critical to super-critical steam
cycle and combining coal with biomass to fuel plants both offer
opportunities to lower CO<INF>2</INF> emissions from existing coal
plants.
Chairman Lampson. This hearing will come to order, and I am
pleased to welcome our witnesses here today to talk about a
critical issue: the advancing technologies designed to reduce
coal power's carbon dioxide emissions.
I think our panelists will bring a wealth of knowledge to
share about cleaner production of electricity at both new and
existing coal-fired power plants, and we have several witnesses
who will discuss the technical issues regarding long-term
geological storage of CO<INF>2</INF>. Again, I welcome our
witnesses and thank you very much for testifying before the
Subcommittee this afternoon.
As many of us know in this room this afternoon,
approximately 50 percent of the electricity generated in the
United States is from coal. According to DOE's Energy
Information Administration, EIA, carbon dioxide emissions in
the United States and its territories were just over six
billion metric tons in 2005, and the electric power sector
generates approximately 40 percent of the Nation's CO<INF>2</INF>
emissions.
Because we will continue to rely on coal for a large
percentage of our energy consumption for the foreseeable
future, there is growing national and global interest in
developing strategies to significantly reduce the billions of
tons of carbon dioxide released into our atmosphere from this
source.
If we are going to implement policies to reduce greenhouse
gas emissions associated with the use of coal, today's hearing
will help us better understand how far along we have come in
meeting this challenge and how much further we may need to go.
I understand that promising technologies are being
developed to improve the efficient production of electricity
from coal-fired power plants which could help to reduce
CO<INF>2</INF> emissions. I look forward to learning more about
the deployment of technologies that can capture CO<INF>2</INF>
from new and existing power plants and keep it out of the
atmosphere.
We must advance our technical ability to capture CO<INF>2</INF>
and prepare the heat-trapping gas for safe and effective
storage in geologic formations. Without commercialization of
carbon capture technologies and effective strategies to
transport the CO<INF>2</INF> from capture to long-term storage,
we run the risk of profound damages to our climate system.
I believe that coal will continue to remain a major energy
source in the United States. I also believe the government, in
partnership with private industry and universities, can take
great strides in reducing coal's contribution to global
warming.
I look forward to hearing from our panelists about the
challenges we face to design a carbon capture and sequestration
strategy that is sensible and meaningful.
And now, I would like to recognize our distinguished
Ranking Member, Mr. Inglis of South Carolina, for his opening
statement.
[The prepared statement of Chairman Lampson follows:]
Prepared Statement of Chairman Nick Lampson
I am pleased to welcome our witnesses here today to talk about a
critical issue--advancing technologies designed to reduce coal power's
carbon dioxide emissions.
I think our panelists bring a wealth of knowledge to share about
cleaner production of electricity at both new and existing coal-fired
power plants. And, we have several witnesses who will discuss the
technical issues regarding long-term geological storage of
CO<INF>2</INF>. Again, I welcome our witnesses and thank you for
testifying before the Subcommittee this afternoon.
As many of us in this room know, approximately 50 percent of the
electricity generated in the United States is from coal. According to
DOE's Energy Information Administration (EIA) carbon dioxide emissions
in the United States and its territories were just over six billion
metric tons in 2005, and the electric power sector generates
approximately 40 percent of the Nation's CO<INF>2</INF> emissions.
Because we will continue to rely on coal for a large percent of our
energy consumption for the foreseeable future, there is a growing
national and global interest in developing strategies to reduce
significantly the billions of tons of carbon dioxide released into our
atmosphere from this source.
If we are going to implement policies to reduce greenhouse gas
emissions associated with the use of coal, today's hearing will help us
better understand how far along we have come in meeting this challenge
and how much further we may need to go.
I understand that promising technologies are being developed to
improve the efficient production of electricity from coal-fired power
plants which could help to reduce CO<INF>2</INF> emissions. I look
forward to learning more about the deployment of technologies that can
capture CO<INF>2</INF> from new and existing power plants and keep it
out of the atmosphere.
We must advance our technical ability to capture CO<INF>2</INF> and
prepare the heat-trapping gas for safe and effective storage in
geologic formations. Without commercialization of carbon capture
technologies and effective strategies to transport the CO<INF>2</INF>
from capture to long-term storage, we run the risk of profound damages
to our climate system.
I believe that coal will continue to remain a major energy source
in the United States. I also believe the government, in partnership
with private industry and universities, can take great strides in
reducing coal's contribution to global warming.
I look forward to hearing from our panelists about the challenges
we face to design a carbon capture and sequestration strategy that is
sensible and meaningful.
Mr. Inglis. And I thank the Chairman. Thank you for holding
this hearing on an important topic.
As the Chairman just pointed out, we get a lot of our
electricity from coal, and we have a lot of coal available to
us, so sequestration seems to be one of the key breakthroughs
that we need to achieve in order to make efficient or effective
use of this resource.
And you know, we have got a case study in South Carolina
right now. Duke Energy faces a decision of whether to build a
coal-fired plant or a nuclear power plant, the question of the
nuclear plant, I think that it would be preferable, frankly, in
that situation, even though it is very expensive, $6 billion.
But their probable choice, sounds to me, since I am not
connected with the company, I guess we don't have to make any
SEC disclosures based on this, but it seems to me that they are
probably headed toward the coal-fired plant, which will, 24/7,
365 days a year, have a CO<INF>2</INF> issue associated with
it. And somehow, we have got to deal with that, and so, this
panel today, I hope, will help us figure out where the science
stands with respect to sequestration, and help us know how the
government might be a partner in funding some research, or in
being the early adopters or the regulators that would cause
this technology to advance, and make it so that that plant, if
it is built as a coal plant, doesn't create the harmful side
effects that we are all concerned about.
So, it is good to be here. It is good to have the
opportunity to have some experts that will help us understand
the possibilities that are available to us, and Mr. Chairman, I
look forward to hearing from our witnesses.
[The prepared statement of Mr. Inglis follows:]
Prepared Statement of Representative Bob Inglis
Thank you for holding this hearing, Mr. Chairman.
Duke Energy faces a dilemma in South Carolina. They would like to
be producing energy free of CO<INF>2</INF> emissions, but because of
the extensive licensing hurdles of nuclear, and the high costs of wind
and solar power, Duke has been forced to meet increased energy demand
by building coal-powered plants. Perhaps if we had clean coal and
carbon capture technologies readily available and affordable, companies
like Duke would be able to meet growing energy demand with coal and
without emissions.
We are currently consuming coal energy at a rapid pace. We need to
focus on ways to make that consumption cleaner and more efficient.
Clean coal and carbon capture and sequestration technologies offer such
solutions. I hope that we can find ways to encourage the implementation
of these technologies.
More importantly, I hope that these technologies will be affordable
and attractive to U.S. and global industry alike. America can lead the
way with technological innovation that can be easily integrated into
existing coal plants worldwide. In addition, the research that will
soon begin at the FutureGen site, and the construction of IGCC power
plants, will be vital for pioneering and demonstrating the many
benefits of clean coal and carbon capture and sequestration
technologies for other countries.
The future of renewable energy promises an end to our dependence on
fossil fuels like oil and coal. But for today, we must work to make
sure that our coal consumption is as emission-free and energy efficient
as possible, bringing benefits to both industry and the environment.
Thank you again for holding this hearing, Mr. Chairman, and I look
forward to hearing from our witnesses.
Chairman Lampson. Thank you very much. I ask unanimous
consent that all additional opening statements submitted by
Subcommittee Members be included in the record. Without
objection, so ordered.
[The prepared statement of Mr. Costello follows:]
Prepared Statement of Representative Jerry F. Costello
Mr. Chairman, thank you for calling today's hearing to receive
testimony on the advancement of coal technologies and carbon capture
and sequestration strategies.
I am privileged to represent the 12th Congressional District of
Illinois, a region rich in coal reserves and mining. Coal plays a vital
role as an energy source, and the industries involved in the mining,
transportation and utilization of coal provide thousands of jobs for
people in Illinois and other parts of the country, in addition to
economic benefits to many communities across Illinois and the Nation.
Further, the Clean Coal Research Center at Southern Illinois University
(SIUC), the State of Illinois and its energy industries are committed
to the development and application of technologies for the
environmentally sound use of Illinois coal.
I believe clean coal technology is part of the solution to
achieving U.S. energy independence, continued economic prosperity and
improved environmental stewardship. In February, a group of twenty-
seven Democrats sent a letter to Speaker Pelosi and Majority Leader
Hoyer stating our strong commitment to advance the deployment of clean
coal technologies, including carbon capture and sequestration (CCS). In
order for carbon capture and sequestration technology to become
commercially viable, the Federal Government must show it is committed
to the necessary research, development, and demonstration (RD&D). Mr.
Chairman, as you know, I have been a strong advocate for federal coal
initiatives and programs. I am focused on increasing the funding levels
for clean coal research and development (R&D) programs for FY08 because
coal is going to be the mainstay for electricity generation well into
the future. I intend to continue to work with my colleagues on both
sides of the aisle to ensure we continue to advance clean coal
technology to overcome the technical and economical challenges for
coal-based power plants.
There have been several Committee hearings in the House and Senate
to discuss CCS technology. I am glad we are having today's Subcommittee
hearing because it is important to clarify that while CCS technology
will enable our power plants to operate more efficiently and reduce
emissions, there are challenges to overcome before the utilities or the
coal industry can deploy CCS technology. The reality is that until CCS
technology is ready to be deployed at a commercial scale, a mandate
from Congress requiring industry to cap all carbon dioxide underground
will shut down coal plants across the country, drive up consumer's
electricity bills, and convert power generation plants to burn natural
gas. Given the volatility of the oil and gas market, the instability in
the Middle East and rising oil and gas prices, we should be moving away
from policies that place a greater dependence on foreign resources and
instead, focus on improving clean coal R&D and demonstration projects
to utilize the natural resources we have here in the U.S. I am
interested in hearing from our witnesses further on this point.
With that, again, thank you Chairman Lampson--I look forward to
hearing from our witnesses.
Chairman Lampson. It is my pleasure to introduce the
excellent panel of witnesses that we have here with us this
afternoon. Mr. Carl Bauer is the Director of the National
Energy Technology Laboratory at the Department of Energy. He is
accompanied by Dr. Joseph Strakey, who leads the Strategic
Center for Coal at the Laboratory.
Mr. Michael Rencheck is the Senior Vice President of
Engineering Projects and Field Services for American Electric
Power. Mr. Stuart Dalton is the Director of Generation at the
Electric Power Research Institute, and Mr. Gardiner Hill is the
Director of the CCS Technology and Alternative Energy for
British Petroleum.
And at this time, I would yield to my colleague from
Illinois, Mr. Costello, to introduce our fifth witness, Dr.
Robert Finley.
Mr. Costello. Mr. Chairman, I thank you, and I thank you
for calling this hearing today on this important topic.
Dr. Robert Finley is the Director of Energy and Earth
Resources Center for the Illinois State Geological Survey. Dr.
Finley is the head of a Regional Carbon Sequestration
Partnership in the Illinois Basin aimed at addressing concerns
with geological carbon management. We look forward to hearing
from him today, as well as the other witnesses, and I might add
that we have had the opportunity to discuss this important
issue with Dr. Finley in the past, and we look forward to
hearing his testimony and the testimony of the other witnesses.
I thank you, Mr. Chairman.
Chairman Lampson. Thank you, Mr. Costello.
You will each have five minutes for your spoken testimony.
Your full written testimony will be included in the record for
the hearing, and when each of you has completed your testimony,
we will begin with questions, and each Member will have five
minutes to question the panel.
Mr. Bauer, would you begin, please.
STATEMENT OF MR. CARL O. BAUER, DIRECTOR, NATIONAL ENERGY
TECHNOLOGY LABORATORY, U.S. DEPARTMENT OF ENERGY
Mr. Bauer. Thank you, Mr. Chairman and Members of the
Committee. I appreciate this opportunity to provide testimony
on DOE's advanced clean coal technologies and the program for
carbon capture and storage.
Our economic prosperity was built upon abundance of fossil
fuels, and we have approximately a 250 year supply of coal in
the United States. The continued use of this secure domestic
resource is critically dependent on developing cost-effective
technology options to meet our environmental goals, including
the reduction of carbon dioxide.
Carbon capture and storage, or CCS, offers a great
opportunity to reduce these potential emissions, and the U.S.
and Canada are blessed with an abundance of potential geologic
storage capacity for CO<INF>2</INF>. The current facts store
annual CO<INF>2</INF> emissions associated with all current
energy production and use in North America for a period of
about 500 years.
Our coal technology program includes development of
advanced technologies for pre-combustion or gasification, post-
combustion, and oxy-combustion, multiple pathways to produce
power and capture CO<INF>2</INF>, as well as a robust program
for carbon sequestration. The 2012 program goal is to show that
we can develop advanced technology to capture and store at
least 90 percent of the potential CO<INF>2</INF> emissions from
coal-fired power plants, with less than a 10 percent increase
in the cost of electricity. Commercially available technology
to do this today would add from 30 to 70 percent to the present
price of electricity.
Gasification is a pre-combustion pathway to convert coal
biomass or carbon containing feedstocks into clean synthesis
gas for use in producing power, fuel, chemicals, and hydrogen.
The gasification technologies being developed meet the most
stringent environmental regulations in any state and provide
the opportunity for potential efficient capture of
CO<INF>2</INF>.
The Power System Development Facility in Wilsonville,
Alabama provides a pilot-scale test platform for evaluating
critical process components. The transport gasifier at the PSDF
is showing great promise for cost-effective gasification of
low-rank, high-moisture western coals. Recent successful
testing of the Stamet dry-feed coal pump indicates a
breakthrough, allowing coal to be pumped directly into a high-
pressure gasifier, and thus avoiding the need for coal drying
and complex feeding systems.
Another major development is the ion transport membrane
technology. This is a more efficient and lower cost method for
producing oxygen which is needed for these processes. This
year, we are testing the robustness of the technology at Air
Products' Sparrows Point facility.
Finally, we are successfully testing at Research Triangle
Institute's warm gas sulfur cleanup system at Eastman
Chemical's facility in Kingsport, Tennessee. They have a
gasifier there that uses coal. Since last fall, the test unit
has performed exceptionally well and achieved extremely low
sulfur levels.
The Advanced Turbine Program is developing and testing
advanced turbine technologies for use of hydrogen as a fuel. A
key need for zero-emission coal gasification plants. We plan to
increase the efficiency of these turbines by two to three
percentage points, while reducing the nitrous oxide emissions
to ultra-low t parts per million. High temperature solid oxide
fuel cells are being developed for a variety of applications
under the SECA program. These fuel cells offer several
significant advantages to coal-based near-zero-emissions power
systems, and are focused on operating on coal-derived syngas.
DOE's carbon sequestration program leverages basic and
applied research with field verification to assess the
technical and economic viability of CCS. The key challenges for
this program are to demonstrate the ability to capture and
store CO<INF>2</INF> in underground geologic formations with
long-term stability, develop the ability to monitor and verify
the fate of the CO<INF>2</INF>, and to gain public and
regulatory acceptance. DOE's seven Regional Carbon
Sequestration Partnerships are engaged in a major effort to
develop and validate the CCS technology in different geologies
across the U.S.
DOE also recognizes the importance of the existing fleet of
coal-fired power plants in meeting energy demand and possible
future carbon constraints. Research is being pursued to
dramatically lower the cost of capturing CO<INF>2</INF> from
these plants.
The FutureGen project is an industry/government partnership
designed to build and operate a gasification-based, nearly
emission-free, coal-fired electricity production plant. The
275-megawatt plant will serve as a large-scale laboratory for
the validating of the commercial readiness of the technologies
that are emerging from the base coal R&D pipeline. The
important data and experience from FutureGen will lead to
design of the next generation of near-zero-emission coal
plants, and provide information for industry, financial
investors, and regulatory partners to understand how better to
regulate and operate these plants.
Mr. Chairman and Members of the Committee, this completes
my statement, and I would be happy to take any questions you
may have at this time or later. Thank you.
[The prepared statement of Mr. Bauer follows:]
Prepared Statement of Carl O. Bauer
Thank you Mr. Chairman and Members of the Committee. I appreciate
this opportunity to provide testimony on the Department of Energy's
advanced clean coal technologies and the program for carbon capture and
storage.
The economic prosperity of the United States over the past century
has been built upon an abundance of fossil fuels in North America. We
have approximately a 250-year supply of coal available in the United
States, at our current consumption rates. Coal-fired power plants
supply over half of our electricity today; the continued use of this
secure domestic resource is critically dependent on the development of
cost-effective technology options to meet our environmental goals,
including the reduction of carbon dioxide (CO<INF>2</INF>) emissions.
Carbon capture and storage (CCS) technologies offer a great
opportunity to reduce these potential emissions. Fortunately, the
United States and Canada are blessed with an abundance of potential
geologic storage capacity. At the current rate of energy production and
use, we could potentially store all of the associated CO<INF>2</INF>
emissions in North America that are produced over the next 175 to 500
years, according to the geologic storage capacity estimates recently
made by DOE's Regional Carbon Sequestration Partnerships. These results
were recently published in the ``Carbon Sequestration Atlas of the
United States and Canada'' that is available on our website at http://
www.netl.doe.gov/publications/carbon<INF>-</INF>seq/refshelf.html.
The two greatest challenges facing technology development for clean
power production integrated with CCS are reducing the cost of carbon
capture and proving the safety and efficiency of long-term geologic
storage of CO<INF>2</INF>. DOE supports a robust RD&D program
specifically designed to address these challenges. The Office of Fossil
Energy's core Coal Technology Program includes the development of
advanced technologies for pre-combustion (or gasification), post-
combustion, and oxy-combustion--multiple pathways to produce power and
capture CO<INF>2</INF>--as well as a robust program for carbon
sequestration to prove the viability of long-term geologic and
terrestrial storage. DOE's Office of Science also supports basic
research in areas such as combustion chemistry, fundamentally new
materials, and modeling of combustion reactions that underpin the
development of potential future clean coal technologies, and basic
research towards improving our scientific understanding of the behavior
of CO<INF>2</INF> at potential geological sites.
The 2012 goal of the Coal Technology Program is to show that we can
develop advanced technology to capture and store at least 90 percent of
the potential CO<INF>2</INF> emissions from coal-fired power plants,
with less than a 10 percent increase in the cost of electricity. This
is an ambitious and significant goal, considering that commercially
available technology to do this today will add from 30 to 70 percent to
the cost of electricity.
Based on the Energy Information Administration's 2007 new capacity
forecast, 145 gigawatts of new coal-based capacity will be required in
the United States by 2030, while still maintaining most of the 300
gigawatts of generating capacity in the existing coal fleet. We have a
fast-approaching opportunity to introduce a ``new breed'' of power
plant--one that is highly efficient, capable of producing multiple
products, and is virtually pollution-free (``near-zero'' emissions,
including carbon). In addition to technology for new plants, we are
also likely to need technology that will permit efficient, cost-
effective capture of CO<INF>2</INF> emissions from the existing fleet.
DOE's R&D program is aimed at providing the scientific and
technological foundation for carbon capture and storage for both new
and existing coal-fueled power plants.
Gasification is a pre-combustion pathway to convert coal or other
carbon-containing feedstocks into synthesis gas, a mixture composed
primarily of carbon monoxide and hydrogen, which can be used as a fuel
to generate electricity or steam, or as a basic raw material to produce
hydrogen, high-value chemicals, and liquid transportation fuels. We are
developing advanced gasification technology to meet the most stringent
environmental regulations in any state and facilitate the efficient
capture of CO<INF>2</INF> for subsequent sequestration--a pathway to
``near-zero-emission'' coal-based energy.
The portfolio of gasification projects that we are developing in
partnership with industry covers a broad range of approaches. I'd like
to highlight some of the important recent developments.
The Power Systems Development Facility (PSDF) in Wilsonville,
Alabama, operated by the Southern Company for DOE, provides a pilot-
scale test platform for evaluating components critical to the evolution
of gasification technology. The ``transport gasifier'' under
development at the PSDF is proving to be very promising in terms of
efficiency and cost, especially for gasifying low-rank, high-moisture
western coals. Data from this facility is providing the design basis
for scaling technology components to full-size in support of near-zero-
emission coal systems.
The Stamet dry-feed coal pump is another promising gasification
sub-system that we have been sponsoring. It allows coal to be
``pumped'' directly into a high-pressure gasifier, thus avoiding the
need for coal drying and a complex and costly lock hopper feeding
system--or, alternatively, a slurry feeding system that is inefficient
when used to feed high-moisture western coals. We have tested the
system successfully at the PSDF, and in recent tests at Stamet's
facilities in California where operation was successfully demonstrated
at conditions typical of high-pressure gasifiers.
Another major program objective is the development of ion transport
membrane (ITM) technology, an alternative to conventional cryogenic
methods for oxygen production that promises capital cost reductions of
$130 per kilowatt, and efficiency improvements of about one percent
when integrated into oxygen-based gasification systems. This year we
will test the robustness of the membranes under various process
conditions and upsets in a five-ton-per-day unit that is operating at
Air Products and Chemicals, Inc.'s, Sparrows Point industrial gas
facility located near Baltimore, Maryland. The information generated
from this small unit will be used to design and test a 150-ton-per-day
facility that will pave the way for a full-scale commercial unit in the
Department's FutureGen Project, discussed further below.
Finally, we have been successfully testing the Research Triangle
Institute's (RTI's) warm gas sulfur cleanup system at Eastman
Chemical's Kingsport, Tennessee, chemical complex where a small syngas
slipstream is taken from commercial coal gasifiers and processed in a
transport desulfurization unit. Since last fall--in over 2,000 hours of
operation--the unit has performed exceptionally well, achieving
extremely low sulfur levels compared to existing commercial
technologies. This new technology offers potential for capital cost
reductions of $250 per kilowatt and efficiency improvements of three to
four percent. We are currently in negotiations with RTI to scale up
this technology for testing at a commercial Integrated Gasification
Combined Cycle (IGCC) facility.
The Advanced Turbine Program is leveraging the knowledge gained
from previous turbine R&D activities to make unprecedented gains in
state-of-the-art turbine designs. Potential pathways to advanced
turbine designs for high-hydrogen fuels include increasing turbine
inlet temperatures, developing advanced combustor designs, increasing
compression ratios, and integrating air separation and CO<INF>2</INF>
compression.
For near-zero-emission power plants, a new generation of turbine
technology is needed that is capable of operating on hydrogen fuels,
without compromising operational performance, while achieving ultra-low
NOX emissions.
A primary goal of the Advanced Turbines Program is to show by 2012
that we can operate on hydrogen fuel, increase efficiency by two to
three percentage points over baseline, and reduce NOX emissions to two
parts per million (ppm). At the same time, we hope to reduce capital
cost when compared to today's turbines in existing IGCC plants. We are
working with two of the turbine original equipment manufacturers,
General Electric and Siemens Westinghouse, to meet these goals.
To facilitate the development of near-zero-emission coal-based
power systems, the Advanced Turbines Program is also funding R&D on
oxygen-fired (oxy-fuel) turbines and combustors that provide high
efficiency through the use of ultra-high-temperature power cycles.
Bringing such oxy-fuel combustors and turbines to commercial viability
will require development and integrated testing of the combustor,
turbine components, advanced cooling technology, and materials.
To reduce the costs associated with sequestering CO<INF>2</INF>,
the Advanced Turbines Program is investigating novel approaches for
CO<INF>2</INF> compression, including development of the Ramgen shock-
wave compression technology. Successful development will reduce the
substantial power requirements and costs associated with compression
for any zero-emission approach.
The Office of Fossil Energy has been developing high-temperature
Solid Oxide Fuel Cells for a variety of applications under the Solid
State Energy Conversion Alliance (SECA) program. These high-temperature
fuel cells offer several significant advantages to coal-based near-
zero-emission power systems. Recognizing the strategic importance of
being able to operate on domestic fuel resources, namely, coal, we are
refocusing the program to coal-based power generation applications.
First, electrochemical power generation is highly efficient and can
result in large savings by reducing the size and cost of the up-front
gasification and clean-up parts of the plant, as well as by reducing
the amount of CO<INF>2</INF> that has to be sequestered.
Second, solid oxide technology can directly utilize carbon monoxide
and methane produced in gasification without the need to shift the
composition of the syngas to pure hydrogen, which incurs cost and
efficiency penalties.
Third, solid oxide fuel cells have built-in carbon separation
capability if the anode (fuel side) and cathode (oxidant side) streams
are not mixed. We expect that fuel cells will provide over a 10
percentage point increase in efficiency in near-zero-emission systems,
with capital costs comparable to or lower than current gas turbine/
steam turbine systems.
DOE's Carbon Sequestration Program leverages basic and applied
research with field verification to assess the technical and economic
viability of CCS as a greenhouse gas mitigation option. The Program
encompasses two main elements: Core R&D and Validation and Deployment.
The Core R&D element focuses on technology solutions, including low-
cost, low-energy intensive capture technologies, that can be validated
and deployed in the field. Lessons learned from field tests are fed
back to the Core R&D element to guide future R&D.
The key challenges the program is addressing are to demonstrate the
ability to store CO<INF>2</INF> in underground geologic formations with
long-term stability (permanence), to develop the ability to monitor and
verify the fate of CO<INF>2</INF>, and to gain public and regulatory
acceptance. DOE's seven Regional Carbon Sequestration Partnerships are
engaged in an effort to develop and validate CCS technology in
different geologies across the Nation.
Collectively, the seven Partnerships represent regions encompassing
97 percent of coal-fired CO<INF>2</INF> emissions, 97 percent of
industrial CO<INF>2</INF> emissions, 97 percent of the total land mass,
and essentially all of the geologic storage sites in the United States
potentially available for sequestration. The Partnerships are
evaluating numerous CCS approaches to assess which approaches are best
suited for specific geologies, and are developing the framework needed
to validate and potentially deploy the most promising technologies.
The Regional Partnership initiative is using a three-phased
approach.
Characterization, the first phase, was initiated in 2003 and
focused on characterizing regional opportunities for CCS, and
identifying regional CO<INF>2</INF> sources and storage formations. The
Characterization Phase was completed in 2005 and led to the current
Validation Phase.
Validation, the second phase, focuses on field tests to validate
the efficacy of CCS technologies in a variety of geologic storage sites
throughout the United States. Using the extensive data and information
gathered during the Characterization Phase, the seven Partnerships
identified the most promising opportunities for storage in their
regions and are performing widespread, multiple geologic field tests.
In addition, the Partnerships are verifying regional CO<INF>2</INF>
storage capacities, satisfying project permitting requirements, and
conducting public outreach and education activities.
Deployment, the third phase, involves large-volume injection tests.
This phase was initiated this fiscal year and will demonstrate CO<INF>2</INF>
injection and storage at a scale necessary to demonstrate potential
future commercial deployment. The geologic structures to be tested
during these large-volume storage tests will serve as potential
candidate sites for the future deployment of technologies demonstrated
in the FutureGen Project as well as the Clean Coal Power Initiative
(CCPI). The Department expects to issue a CCPI solicitation for carbon
capture technologies at commercial scale in 2007.
DOE also recognizes the importance of the existing fleet of coal-
fired power plants in meeting energy demand and possible future carbon
constraints. Research is being pursued to develop technologies that
dramatically lower the cost of capturing CO<INF>2</INF> from power
plant stack emissions. This research, supported by the Office of Fossil
Energy, is exploring a wide range of approaches that includes
membranes, ionic liquids, metal organic frameworks, improved CO<INF>2</INF>
sorbents, advanced combustor concepts, advanced scrubbing, and oxy-
combustion. Additionally, advanced research is being pursued on high-
temperature materials, advanced sensors & controls, and advanced
visualization software. These developments could provide significant
efficiency improvements and cost reductions for both existing and
future power plants, based on pulverized coal combustion.
The FutureGen Project is an industry/government partnership to
design, build, and operate a gasification-based, nearly emission-free,
coal-fired electricity production plant. The 275-megawatt plant will be
the cleanest fossil-fuel-fired power plant in the world. With respect
to sequestration technologies, FutureGen will test, and ideally
demonstrate the large-scale, permanent sequestration of the captured
CO<INF>2</INF> in a deep saline formation. FutureGen is scheduled to
operate from 2012 to 2016, followed by a CO<INF>2</INF> monitoring
phase. The data and experience derived from this important endeavor
will then be available to facilitate the design of the next generation
of near-zero-emission plants.
By working in partnership with other federal agencies, utilities,
coal companies, research organizations, academia, and non-government
organizations, we hope to make near-zero-emission coal technology a
cost-effective and safe option to help meet our future power needs.
Mr. Chairman, and Members of the Committee, this completes my
statement. I would be happy to take any questions you may have at this
time.
Biography for Carl O. Bauer
Carl Bauer is Director of the National Energy Technology Laboratory
(NETL), a national laboratory owned and operated by the U.S. Department
of Energy (DOE). In this position, he oversees the implementation of
major science and technology development programs to resolve the
environmental, supply, and reliability constraints of producing and
using fossil resources. This includes technologies for--
<bullet> Advanced coal-fueled power generation and hydrogen
production.
<bullet> Carbon sequestration.
<bullet> Environmental control for the existing fleet of
fossil steam plants.
<bullet> Improving the efficiency and environmental quality of
domestic oil and natural gas exploration, production, and
processing.
Mr. Bauer served as NETL's Deputy Director from October 2003 until
his current appointment in February 2005. In his previous position, Mr.
Bauer was responsible for NETL's energy assurance and infrastructure
protection activities, and he provided oversight for the Office of
Institutional and Business Operations; the Office of Science,
Technology, and Analysis; and the Office of Technology Impacts and
International Coordination.
Prior to serving as Deputy Director, Mr. Bauer was the Director of
NETL's Office of Coal and Environmental Systems, with responsibility
for all of NETL's activities related to coal and environmental
research. Prior to that, he was Director of NETL's Office of Product
Management for Environmental Management, with responsibility for
development and demonstration of hazardous- and radioactive-waste
cleanup technologies.
Mr. Bauer has more than 30 years of experience in technical and
business management in both the public and private sectors. His
positions at the Department of Energy Headquarters have included
Director of the Division of Work for Other Agencies, Director of the
Idaho and Chicago Environmental Restoration Operations Division, Acting
Director for the Environmental Management Office of Acquisition
Management, and Director of the Office of Technology Systems. He has
also served as Director of Engineering Support and Logistics, Naval Sea
Systems Command for the U.S. Department of Defense; Vice President and
General Manager of Technology Application, Inc.; and Vice President,
Ship Systems and Logistics Group, Atlantic Research Corporation.
Mr. Bauer received an M.S. in nuclear power engineering from the
Naval Nuclear Power Postgraduate Program in 1972 and a B.S. in marine
engineering/oceanography from the U.S. Naval Academy in 1971. He has
taken additional postgraduate courses at the Wharton School of Business
and George Washington University in business administration, finance,
and management, and has received additional executive management
training at Harvard University's John F. Kennedy School of Government.
Chairman Lampson. Thank you, Mr. Bauer. We will postpone
those questions for just a few minutes. Dr. Finley.
STATEMENT OF DR. ROBERT J. FINLEY, DIRECTOR, ENERGY AND EARTH
RESOURCES CENTER, ILLINOIS STATE GEOLOGICAL SURVEY
Dr. Finley. Thank you, Mr. Chairman and Members of the
Committee.
Understanding the capacity to geologically sequester carbon
dioxide as a byproduct of fossil fuel use, including the use of
advanced coal technologies, is an essential strategy to
mitigate the growing potential for climate change related to
CO<INF>2</INF> buildup in the atmosphere.
At the Illinois State Geological Survey, we have been
investigating this capacity for more than five years, and since
October of 2003, have been doing so as part of a competitively
awarded U.S. Department of Energy Regional Carbon Sequestration
Partnership. This partnership covers the Illinois Basin, a
geological feature that covers most of Illinois, Southwestern
Indiana, and Western Kentucky.
Our Phase I effort focused on compiling and evaluating
existing data, and resulted in a 496-page report, indicating
that one, suitable CO<INF>2</INF> sequestration reservoirs are
present in the Illinois Basin, and that sufficient
sequestration capacity existed to warrant further
investigation. We then entered a Phase II validation effort, in
which we are currently engaged, in which six small-scale field
pilot projects will be carried out through September 2009.
In July 2006, DOE managers of the Regional Carbon
Sequestration Partnership began the process of developing a
Carbon Sequestration Atlas of the United States and Canada.
This Atlas was released in digital form in March of this year,
and the first edition of the printed version was released last
week at the DOE Annual Carbon Capture and Sequestration
Conference. I have a copy of it here that Members may peruse at
their leisure. I would be pleased to leave it with you.
The Atlas suggests that there are some 3,500 billion tons
of storage capacity in the regions covered by the partnerships.
In my judgment, there is sufficient geological carbon
sequestration capacity in the United States for geological
sequestration to be one of multiple tools used on a large scale
to reduce CO<INF>2</INF> emissions from fixed sources, such as
coal gasification facilities.
While compiling our Phase I report, and while setting up
environmental monitoring programs are integral to each of the
six field pilots, we have been aware of the need to understand
the risks, both short-term and long-term, of geological carbon
sequestration. We have been paying as much attention to the
overlying rock that will hold the carbon dioxide in place, the
caprock or the seals, as we have to the rock into which the
CO<INF>2</INF> itself will be injected.
To be an effective climate change mitigation strategy, the
CO<INF>2</INF> must remain in place and not leak back to the
atmosphere, not contaminate potable groundwater, not affect
surface biota, and not present a risk to human health and
safety. We know that rock formations can perform this in an
effective manner, as both reservoirs and seals, because they
have trapped and held oil and natural gas that we drill for and
produce every day. These hydrocarbons have been trapped in
place for millions to hundreds of millions of years before
being brought to the surface through wells. To minimize the
risk of CO<INF>2</INF> injection, the reverse of the process of
oil and natural gas production, we need to apply many of these
same advanced methods that we use to find oil and natural gas.
We need to evaluate subsurface rock formations to find thick
and competent reservoir seals, to avoid areas where faults and
fractures could become leakage pathways, and to understand the
chemical changes in the pore space of the rock where the
CO<INF>2</INF> will be injected.
With respect to the safety of established projects, we have
been injecting CO<INF>2</INF> for enhanced oil recovery in
reservoirs in West Texas for more than two decades. Since 1983,
more than 600 million tons of pressurized CO<INF>2</INF> have
been injected into the surface, and 30 million tons are being
injected currently on an annual basis. The safety record of
this process has been excellent, with not a single loss of life
incident during the period of injection. The injection of one
million tons per year of CO<INF>2</INF> for sequestration
beneath the seabed of the North Sea has been taking place since
1996, and based on published reports, this process has been
both safe and effective.
I would conclude from this experience with CO<INF>2</INF>,
and from industry experience with geological storage of natural
gas, that we could readily proceed with large-scale, by which I
mean one million tons per year tests of geological
sequestration for further evaluation of reservoirs and caprocks
as they vary geologically around the country.
To establish public confidence, all the regional
partnerships have been carrying out outreach and education
activities, and have been integrating environmental monitoring
into our small-scale CO<INF>2</INF> pilot tests. As we move to
the upcoming larger scale tests, we need to invest even more
into education, outreach, and especially environmental
monitoring to ensure public confidence. Our experience to date,
very much informed by the public meetings that we have held in
regard to the two FutureGen finalist sites, which we are
fortunate to have in the State of Illinois, has been the
process of ensuring openness and transparency to help gain the
public trust. Yes, we are putting something new into the
subsurface. Yes, there are small and difficult to quantify
risks, such as slow leakage, involved in carrying out any such
effort, but yes, we are working diligently and in the most open
way possible to investigate the geology of sequestration, and I
believe that the geologic framework has the capacity and the
security that we require to make sequestration a viable carbon
management strategy.
Thank you.
[The prepared statement of Dr. Finley follows:]
Prepared Statement of Robert J. Finley
Understanding the capacity to geologically sequester carbon dioxide
(CO<INF>2</INF>) as a byproduct of fossil fuel use, including the use
of advanced coal technologies, is an essential strategy to mitigate the
growing potential for climate change related to carbon dioxide buildup
in the atmosphere. At the Illinois State Geological Survey, we have
been investigating this capacity for more than five years, and, since
October of 2003, have been doing so as part of a U.S. Department of
Energy (DOE) Regional Carbon Sequestration Partnership. This
Partnership covers the Illinois Basin, a geological feature that
extends across most of Illinois, southwestern Indiana, and western
Kentucky. Our sister geological surveys in Indiana and Kentucky are our
partners in this research. Our Phase I effort focused on compiling and
evaluating existing data and resulted in a 496-page report in December
2005 indicating 1) that suitable CO<INF>2</INF> sequestration
reservoirs were present in the Illinois Basin, and that 2) sufficient
sequestration capacity existed warranting further investigation. We
then entered a Phase II validation effort, in which we are currently
engaged, in which six small-scale, field pilot injection projects will
be carried out through September 2009. The injection phase of one field
pilot has been completed and two more will see either injection or
drilling of new wells for injection within the next 90 days. While
planning and executing these field pilot projects, we have also been
making further detailed assessments of geological storage capacity, as
have the other six partnerships.
In July 2006, DOE managers for the Regional Carbon Sequestration
Partnerships convened a meeting at the Kansas Geological Survey to
begin the process of developing a Carbon Sequestration Atlas of the
United States and Canada. This Atlas was released in digital form in
March 2007 and the first edition of the printed version was released
last week in Pittsburgh at DOE's annual carbon capture and
sequestration conference. The Atlas was developed on the basis of
regional partnership work that began in 2003, and earlier, to
understand the major geological reservoirs that may be utilized for
carbon sequestration. This Atlas also builds on the work supported by
DOE in the form of the original MIDCARB, and now NATCARB, digital
databases that are accessible on the Internet. The Atlas documented
some 3,500 billion tons of storage capacity in the regions covered by
the Partnerships. In my judgment there is sufficient geological carbon
sequestration capacity in the United States for geological
sequestration to be one of multiple tools useful on a large scale to
reduce CO<INF>2</INF> emissions from fixed sources such as coal
gasification facilities. In the Illinois Basin region, if we could
capture 80 percent of all current fixed-source emissions, a volume of
237 million tons of CO<INF>2</INF> per year, we would have storage
capacity for 122 to 485 years of emissions just in the deep saline
reservoirs.
While compiling our Phase I report, and while setting up
environmental monitoring programs integral to each of our six field
pilot projects, we have been aware of the need to understand the risks,
both short- and long-term, of geological carbon sequestration. We have
been paying as much attention to the overlying rock that will hold the
carbon dioxide in place, the reservoir seal or caprock, as we have to
the qualities of the reservoir rock that the CO<INF>2</INF> will be
injected into. To be an effective climate change mitigation strategy,
the CO<INF>2</INF> must remain in place and not leak back to the
atmosphere, not contaminate potable ground water, not affect surface
biota, and not present a risk to human health and safety. That implies
that we must do an excellent job of investigating the properties of
these rocks and the fluids now within them and predicting their
performance in the future. We know that rock formations can perform as
effective reservoirs and seals because they have trapped and held the
oil and natural gas that we drill for and produce every day. These
hydrocarbons have been trapped in place for millions to hundreds of
millions of years before being brought to the surface through wells. To
minimize the risk in CO<INF>2</INF> injection, the reverse of the oil
or natural gas production process, we need to apply many of the same
advanced methods as we use to find oil and natural gas. We need to
evaluate subsurface rock formations to find thick and competent
reservoir seals, to avoid areas where faults and fractures could become
leakage pathways, and to understand the chemical changes in the pore
space of the rock that the CO<INF>2</INF> will be injected into. All of
this can be done to mitigate risk and if done well, and in sufficient
detail, will allow appropriate sites with minimum risk to be selected
for geological sequestration. After all, we also have decades of
experience with underground natural gas storage projects at sites where
tens of billions of cubic feet of flammable natural gas are stored
safely and effectively.
With respect to the safety of established projects, we have been
injecting CO<INF>2</INF> for enhanced oil recovery in West Texas for
more than two decades. Since 1983, more than 600 million tons of
pressurized CO<INF>2</INF> have been injected and 30 million tons are
currently being injected annually in West Texas oil reservoirs. The
safety record of this process has been excellent with not a single
incident of loss of life. The injection of CO<INF>2</INF> for
sequestration beneath the seabed of the North Sea has been taking place
since 1996, and based on published reports, the CO<INF>2</INF> has been
readily tracked in the subsurface using geophysical techniques and the
process has been safe and effective. About one million metric tonnes
per year are being injected at a sub-seabed depth of 3,300 feet under a
caprock about 260 feet thick, comparable to shale caprocks in the
Illinois Basin. I would conclude from this experience with
CO<INF>2</INF>, and from industry experience with geological storage of
natural gas, that we should proceed with large-scale (one million tons/
year to one million tons over three to four years) tests of geological
carbon sequestration for further evaluation of reservoirs and caprocks
as they vary in different regions of the country. These projects need
to be well funded and designed to build on the technical experience I
have just described.
To establish public confidence, all the regional partnerships have
been carrying out public outreach activities and have been integrating
environmental monitoring into their small-scale field testing of
CO<INF>2</INF> injection during Phase II. For our Illinois Basin
region, this monitoring has been the largest single budget item in our
Phase II project, and appropriately so. As we move to the upcoming
larger-scale tests, we need to invest even more into education,
outreach, and, especially, environmental monitoring to ensure public
confidence. Our experience to date, very much informed by the public
meetings we have held with regard to the two FutureGen finalist sites
in Illinois, has been that openness and transparency are essential to
the process of gaining public trust. Yes, we are putting something new
into the subsurface. Yes, there are small and difficult-to-quantify
risks, such as slow leakage, involved in carrying out any such effort.
But, yes, we are working diligently and in the most open way possible
to investigate the geology of sequestration, and I believe that the
geologic framework has the capacity and the security that we require to
make sequestration a viable carbon management strategy. I also believe,
however, that some budget figures that I have seen for FY08 and FY09
are inadequate to fully execute and monitor these critical large-scale
tests in diverse geological settings around the U.S. I trust that this
subcommittee and the Full Committee on Science and Technology will have
the opportunity to review those allocations and give priority to the
Phase III Regional Partnership Program's large-scale testing, among
other important sequestration programs that benefit from the
investments made to date in technology and expertise by the Department
of Energy.
In summary, I would suggest to the Subcommittee that we are
beginning to have a substantive understanding of the geological
capacity for carbon sequestration, especially based on research over
the last two to five years in the U.S. and internationally. Advanced
coal technologies including coal gasification for electricity
production, coal to synthetic natural gas, and coal to liquid fuels
will depend on geological sequestration capacity to directly manage
their CO<INF>2</INF> emissions. The need for such management has been
made all the more evident by the growing concern over climate change as
embodied in the assessments released by the Intergovernmental Panel on
Climate Change (IPCC) and other groups since February of this year.
While we are advancing sequestration technology, we must also address
issues of long-term liability for sequestration projects, legal access
to subsurface pore space, and issues of who will bear the costs of
sequestration and how those costs will be distributed. Some of these
issues are beginning to be articulated, but it is unlikely that these
issues, or the testing of advanced coal technologies combined with
carbon sequestration, can be addressed without unprecedented public-
private collaboration. I urge this subcommittee to facilitate that
process as we look forward to implementing advanced coal technologies
incorporating geological carbon sequestration as a preferred and
routine approach to coal utilization.
Biography for Robert J. Finley
Robert J. Finley is the Director of the Energy and Earth Resources
Center at the Illinois State Geological Survey, Champaign, Illinois. He
joined the Illinois Survey in February 2000 after serving as Associate
Director at the Bureau of Economic Geology, The University of Texas at
Austin. Rob's area of specialization is fossil energy resources. His
work has ranged from large-scale resource assessment, addressing
hydrocarbon resources at national and State scales, to evaluation of
specific fields and reservoirs for coal, oil, and natural gas. He is
currently heading a regional carbon sequestration partnership in the
Illinois Basin aimed at addressing concerns with geological carbon
management. Rob has served on committees of the National Petroleum
Council, the American Association of Petroleum Geologists, the National
Research Council, the Stanford Energy Modeling Forum, and the U.S.
Potential Gas Committee. He has taught aspects of energy resource
development since 1986 to numerous clients domestically and overseas in
Venezuela, Brazil, South Africa, and Australia, among other countries.
Rob holds a Ph.D. in geology from the University of South Carolina; he
is currently also an Adjunct Professor in the Department of Geology,
University of Illinois at Urbana-Champaign.
Chairman Lampson. Thank you, Dr. Finley. Mr. Rencheck.
STATEMENT OF MR. MICHAEL W. RENCHECK, SENIOR VICE PRESIDENT,
ENGINEERING, PROJECTS AND FIELD SERVICES, AMERICAN ELECTRIC
POWER
Mr. Rencheck. Good afternoon, Mr. Chairman and Members of
the Committee. Thank you for inviting me to participate in this
meeting.
American Electric Power is one of the Nation's largest
electricity utilities, with more than five million retail
customers in 11 States. We are also one of the Nation's largest
power generators, with more than 38,000 megawatts of generating
capacity from a diverse fleet. In a particular note for today,
AEP is one of the largest coal-fired electric generators in the
U.S., and we have implemented a portfolio of voluntary actions
to reduce, avoid, and offset greenhouse gases during the past
decade.
Coal generates over 50 percent of the electricity used in
the United States, and is used extensively worldwide. As demand
for electricity increases significantly, coal use will increase
as well. In the future, coal-fired electric generation must be
zero-emission or close to it. This will be achieved through new
technologies that are being developed today, but are not yet
proven or commercially available.
Like most companies in our sector, AEP needs new
generation. We are investing in new clean coal technology that
will enable AEP and our industry to meet the challenge of
reducing greenhouse gases for the long-term. This includes
plans to build two new integrated gasification combined cycle
units, IGCC, and two state-of-the-art ultrasupercritical units.
These will be the first new generation of ultrasupercritical
and IGCC units deployed in the United States. AEP is also
taking a lead role of commercializing carbon capture technology
for use on new generation, and more importantly, for use on
existing generation as a retrofit.
We signed a memorandum of understanding also for post-
combustion capture technology using Alstom's chilled ammonia
system. Starting with a commercial performance verification
project in mid to late 2008 in West Virginia, a project that
will also include storage of the carbon dioxide in a saline
aquifer, we will move to the first commercial sized project at
one of our 450-megawatt plants at our Northeastern Unit in
Oklahoma in 2011. This would capture about 1.5 million metric
tons of CO<INF>2</INF> per year, which will be used for
enhanced oil recovery.
We are also working with Babcock and Wilcox to develop its
oxy-coal combustion technology, through development of a 30-
megawatt thermal pilot plant at its Barberton, Ohio facility in
2007. Oxy-coal combustion forms a concentrated CO<INF>2</INF>
post-combustion gas that can be stored without additional post-
combustion gas processing equipment. We are hoping to bring
this technology from the drawing board to commercial scale
early in the next decade.
Retrofitting our existing fleet to ensure carbon capture
will be neither easy nor inexpensive, and AEP is very
comfortable leading the way. We have a long and impressive list
of technological firsts that we achieved during our first
hundred years of existence, but we have identified one very
important caveat during our century of technological
achievement and engineering excellence. Proving technology to
be commercially viable and having that technology ready for
widespread commercial use are two very different things. It
takes time to develop off-the-shelf commercial offerings for
new technology.
AEP is not calling for an indefinite delay in the enactment
of mandatory climate change legislation until the advanced
technology, such as carbon capture and storage, is developed.
However, as the requirements become more stringent during the
next ten to twenty years, and we move beyond the availability
of current technology to deliver those reductions, it is
essential that requirements for deeper reductions allow
sufficient time for the demonstration and commercialization of
these advanced technologies.
How can you help? It is also important to establish public
funding, as well as incentives for private funding, for the
development of commercially viable technology solutions, as
well as providing the legal and the regulatory framework to
facilitate this development. AEP believes that the IGCC and
carbon capture and storage technologies need to be advanced,
but the building of an IGCC and the timely development of
commercially viable carbon capture and sequestration
technologies will require additional public funding.
AEP and others in our sectors have already invested heavily
into research and early development of technologies that may
eventually be commercially viable solutions to capture and
store greenhouse gas emissions. For this reason, separate
investment tax credits are needed to facilitate both the
construction of IGCC plants now, and the development of CCS
technologies for future use.
American industry has long been staffed by excellent
problem solvers. I am confident we will be able to develop the
technologies to efficiently address emissions of greenhouse
gases in an increasingly cost-effective manner. We have the
brainpower. We need time, funding assistance, and the legal or
regulatory support.
Thank you.
[The prepared statement of Mr. Rencheck follows:]
Prepared Statement of Michael W. Rencheck
Summary of Testimony
American Electric Power (AEP) is one of the Nation's largest
electricity generators with over five million retail consumers in 11
states. AEP has a diverse generating fleet--coal, nuclear,
hydroelectric, gas, oil and wind. But of particular note, AEP is one of
the largest coal-fired electricity generators in the U.S.
Over the last 100 years, AEP has led the Industry in developing and
deploying new technologies beginning with the first high voltage
transmission lines at 345 kilovolt (kV) and 765 kV to new and more
efficient coal power plants starting with the large central station
power plant progressing to super-critical and ultra-super-critical
power plants. During the past decade, American Electric Power has
implemented a portfolio of voluntary actions to reduce, avoid or offset
greenhouse gases (GHG). During 2003-05, AEP reduced its GHG emissions
by 31 million metric tons of CO<INF>2</INF> by planting trees, adding
wind power, increasing power plant generating efficiency, and retiring
less-efficient units among other measures.
We also continue to invest in new clean coal technology that will
enable AEP and our industry to meet the challenge of reducing GHG
emissions for the long-term. This includes plans to build two new
integrated gasification combined cycle (IGCC) plants and two state-of-
the-art, ultra-super-critical plants. These will be the first of the
new generation of ultra-super-critical plants in the U.S. AEP plans to
take a lead role in commercializing carbon capture technology. We
signed a memorandum of understanding (MOU) with Alstom for post-
combustion carbon capture technology using its chilled ammonia system.
Starting with a ``commercial performance verification'' project in mid
to late 2008 in West Virginia, we would move to the first commercial-
sized project at one of our 450-megawatt coal-fired units at
Northeastern Plant in Oklahoma by late 2011. This would capture about
1.5 million metric tons of CO<INF>2</INF> a year, which will be used
for enhanced oil recovery. Additionally, we signed a memorandum of
understanding with Babcock and Wilcox to participate in a oxy-coal
pilot project. This project will be used to refine the process and
eventually determine if the combustion technology can be retrofit into
existing plants.
Over all, AEP supports the adoption of an economy-wide cap-and-
trade type GHG reduction program that is well thought-out, achievable,
and reasonable. We believe legislation can be crafted that does not
impede AEP's ability to provide reliable, reasonably priced electricity
to support the economic well-being of our customers, and includes
mechanisms that foster international participation and avoids harming
the U.S. economy. A pragmatic approach for phasing in GHG reductions
through a cap-and-trade program coincident with developing technologies
to support these reductions will be critical to crafting achievable and
reasonable legislation.
The development of these technologies will be facilitated by and
are dependent on public funding through tax credits and similar
incentives. AEP is doing its part as we aggressively explore the
viability of this technology in several first-of-a-kind commercial
projects. We are advancing the development of IGCC and other necessary
technologies as we seek to build two IGCC plants and two state-of-the-
art ultra-super-critical power plants. 1n addition, we are a founding
member of FutureGen, a ground-breaking public-private collaboration
that aims squarely at making near-zero-emissions coal-based energy a
reality. Simply put, however, commercially engineered and available
technology to capture and store CO<INF>2</INF> does not economically
exist today and we strongly recommend that any legislation you adopt
reflect this fact.
Testimony
Good morning Mr. Chairman and distinguished Members of the House
Committee on Science and Technology, Subcommittee on Energy and
Environment.
Thank you for inviting me here today. Thank you for this
opportunity to offer the views of American Electric Power (AEP) and for
soliciting the views of our industry and others on climate change
technologies.
My name is Mike Rencheck, Senior Vice President--Engineering,
Projects & Field Services of American Electric Power (AEP).
Headquartered in Columbus, Ohio, we are one of the Nation's largest
electricity generators--with over 36,000 megawatts of generating
capacity--and serve more than five million retail consumers in 11
states in the Midwest and south central regions of our nation. AEP's
generating fleet employs diverse sources of fuel--including coal,
nuclear, hydroelectric, natural gas, and oil and wind power. But of
particular importance for the Committee Members here today, AEP uses
more coal than any other electricity generator in the Western
hemisphere.
AEP's Technology Development
Over the last 100 years, AEP has been an industry leader in
developing and deploying new technologies beginning with the first high
voltage transmission lines at 345 kilovolt (kV) and 765kV, to new and
more efficient coal power plants starting with the large central
station power plant, progressing to super-critical and ultra-super-
critical powers plants. We are continuing that today. We have
implemented 14 selective catalytic reactors (SCRs), and 10 Flue Gas
Desulphurization units, with others currently under construction, and
we are a leader in developing and deploying mercury capture and
monitoring technology. In addition, we continue to invest in new clean
coal technology plants and R&D that will enable AEP and our industry to
meet the challenge of significantly reducing GHG emissions in future
years. For example, AEP is working to build two new generating plants
using Integrated Gasification Combined Cycle (IGCC) technology in Ohio
and West Virginia, as well as two highly efficient new generating
plants using the most advanced (e.g., ultra-super-critical) pulverized
coal combustion technology in Arkansas and Oklahoma. We are also
providing a leading role in the FutureGen project, which once
completed, will be the world's first near-zero CO<INF>2</INF> emitting
commercial scale coal-fueled power plant. We are also working to
progress specific carbon capture and storage technology.
AEP's Major New Initiative to Reduce GHG Emissions
In March, AEP announced several major new initiatives to reduce
AEP's GHG emissions and to advance the commercial application of carbon
capture and storage technology and Oxy-coal combustion. Our company has
been advancing technology for the electric utility industry for more
than 100 years. AEP's recent announcement continues to build upon this
heritage. Technology development needs are often cited as an excuse for
inaction. We see these needs as opportunities for action.
AEP has signed a memorandum of understanding (MOU) with Alstom, a
worldwide leader in equipment and services for power generation, for
post-combustion carbon capture technology using Alstom's chilled
ammonia system. It will be installed at our 1,300-megawatt Mountaineer
Plant in New Haven, West Virginia as a ``30-megawatt (thermal)
commercial performance verification'' project in mid to late 2008 and
it will capture up to 100,000 metric tons of carbon dioxide
(CO<INF>2</INF>) per year. Once the CO<INF>2</INF> is captured, we will
store it. The Mountaineer site has an existing deep saline aquifer
injection well previously developed in conjunction with the Department
of Energy (DOE) and Battelle. Working with Battelle and with continued
DOE support, we will use this well (and develop others) to store and
further study CO<INF>2</INF> injection into deep geological formations.
Following the completion of commercial verification at Mountaineer,
AEP plans to install Alstom's system on one of the 450-megawatt coal-
fired units at its Northeastern Plant in Oologah, Oklahoma, as a first-
of-a-kind commercial demonstration. The system is expected to capture
approximately 1.5 million metric tons of CO<INF>2</INF> per year and be
operational in late 2011. The CO<INF>2</INF> captured at Northeastern
Plant will be used for enhanced oil recovery.
AEP has also signed an MOU with Babcock and Wilcox to pursue the
development of Oxy-coal combustion that uses oxygen in lieu of air for
combustion. The Oxy-coal combustion forms a concentrated CO<INF>2</INF>
post combustion gas that can be stored without additional post
combustion capture processes. AEP is working with B&W on a ``30-
megawatt (thermal) pilot project.'' The results are due in mid-2007 and
then these results will be used to study the feasibility of a scaled up
100-200MW (electric) demonstration. The CO<INF>2</INF> from the
demonstration project would be captured and stored in a deep saline
geologic formation or used for enhanced oil recovery application.
In March, AEP also voluntarily committed to achieve an additional
five million tons of GHG reductions annually beginning in 2011. We will
accomplish these reductions through a new AEP initiative that will add
another 1,000MW of purchased wind power into our system, substantially
increase our forestry investments (in addition to the 62 million trees
we have planted to date), as well as invest in domestic offsets, such
as methane capture from agriculture, mines, and landfills.
AEP has also implemented efficiency improvements at several plants
in its existing generation fleet. These improvements include new
turbine blading, valve replacements, combustion tuning, and
installation of variable speed drives on rotating equipment. Such
improvements are currently reported through the Department of Energy's
1605 (b) program to the extent they produce creditable reductions in
greenhouse gas emissions. However, we are limited in the efficiency
improvements we can make due to the ambiguities in the existing New
Source Review program, and support further clarification and reform of
this program to encourage efficiency improvements.
AEP Perspectives on a Federal GHG Reduction Program
While AEP has done much, and will do much more, to mitigate GHG
emissions from its existing sources, we also support the adoption of an
economy-wide cap-and-trade type GHG reduction program that is well
thought-out, achievable, and reasonable. Although today I intend to
focus on the need for the development and deployment of commercially
viable technologies to address climate change and not on the specific
policy issues that must be addressed, AEP believes that legislation can
be crafted that does not impede AEP's ability to provide reliable,
reasonably priced electricity to support the economic well-being of our
customers, and includes mechanisms that foster international
participation and avoid creating inequities and competitive issues that
would harm the U.S. economy. AEP supports reasonable legislation, and
is not calling for an indefinite delay until advanced technology to
support carbon capture and storage (CCS), among others, is developed.
However, as the requirements become more stringent during the next ten
to twenty years, and we move beyond the ability of current technology
to deliver those reductions, it is essential that requirements for
deeper reductions coincide with the commercialization of advanced
technologies.
Phased-in Timing and Gradually Increasing Level of Reductions
Consistent With Technology Development That Is
Facilitated by Public Funding
As a practical matter, implementing climate legislation is a
complex undertaking that will require procedures for measuring,
verifying, and accounting for GHG emissions, as well as for designing
efficient administration and enforcement procedures applicable to all
sectors of our economy. Only a pragmatic approach with achievable
targets, supported by commercial technology, and reasonable
timetables--that does not require too many reductions within too short
a time period--will succeed.
AEP also believes that the level of emissions reductions and timing
of those reductions under a federal mandate must keep pace with
developing technologies for reducing GHG emissions from new and
existing sources. The technologies for effective carbon capture and
storage from coal-fired facilities are developing, but are not
commercially engineered to meet production needs, and cannot be
artificially accelerated through unrealistic reduction mandates.
While AEP and other companies have successfully lowered their
average emissions and emission rates during this decade, further
substantial reductions will require the wide-scale commercial
availability of new clean coal technologies. AEP believes that the
electric power industry can potentially manage much of the expected
economic (and CO<INF>2</INF> emissions) growth over the course of the
next decade (2010-2020) through aggressively deploying renewable
energy, achieving further gains in supply and demand-side energy
efficiency, and implementing new emission offset projects. As stated
above, AEP supports reasonable legislation, and is not calling for an
indefinite delay of GHG reduction obligations until advanced clean coal
technology is developed. However, as the reduction requirements become
more stringent, and move beyond the ability of current technologies to
deliver those reductions, it is important that those stringent
requirements coincide with the commercialization of advanced
technology. This includes the next generation of low- and zero-emitting
technologies.
Significantly, today's costs of new clean coal technologies with
carbon capture and storage are much more expensive than current coal-
fired technologies. For example, carbon capture and storage using
current inhibited monoethanolamine (MEA) technology is expected to
increase the cost of electricity from a new coal fired power plant by
about 60-70 percent. Even the newer chilled ammonia carbon capture
technology we plan to deploy on a commercial sized scale by 2012 at one
of our existing coal-fired units will result in significantly higher
costs.
Additionally the MEA technology has limitations under existing
plant retrofit conditions. CO<INF>2</INF> capture requires a large
volume of steam to regenerate the amine used to capture the
CO<INF>2</INF>. Review of several of our existing PC units indicates
they can only supply enough steam from the power generation cycle to
regenerate the amine necessary to capture about 50 percent of the
CO<INF>2</INF>, without jeopardizing the steam cycle.
It is only through the steady and judicious advancement of these
applications during the course of the next decade that we can start to
bring these costs down, in order to avoid substantial electricity rate
shocks and undue harm to the U.S. economy.
IGCC technology, for example, integrates two proven processes--coal
gasification and combined cycle power generation--to convert coal into
electricity more efficiently and cleanly than any existing uncontrolled
power plant can. Not only is it cleaner and more efficient than today's
installed power plants, but IGCC has the potential to be retrofitted in
the future for carbon capture at a lower capital cost and with less of
an energy penalty than traditional power plant technologies, but only
after the technology has been developed and proven. Our IGCC plants
will incorporate the space and layout for the addition of components to
capture CO<INF>2</INF> for sequestration.
Our IGCC plants will be among the earliest, if not the first,
deployments of large-scale IGCC technology. The cost of constructing
these plants will be high, resulting in a cost of generated electricity
that would be twenty to thirty percent greater than that from
pulverized coal (PC) combustion technology. As more plants are built,
the costs of construction are expected to come into line with the cost
of PC plants.
To help bridge the cost gap and move IGCC technology down the cost
curve, there is a need for continuation and expansion of the advanced
coal project tax credits that were introduced by the Energy Policy Act
of 2005. All of the available tax credits for IGCC projects using
bituminous coal were allocated to only two projects during the initial
allocation round in 2006. More IGCC plants are needed to facilitate
this technology. AEP believes an additional one billion dollars of
section 48A (of the Internal Revenue Code) tax credits are needed, with
the bulk of that dedicated to IGCC projects without regard to coal
type.
Along with an increase in the amount of the credits, changes are
needed in the manner in which the credits are allocated. Advanced coal
project credits should be allocated based on net generating capacity
and not based upon the estimated gross nameplate generating capacity of
projects. Allocation based upon gross, rather than net, generating
capacity potentially rewards less efficient projects, which is
antithetical to the purpose of advanced coal project tax incentives.
AEP also believes that the Secretary of Energy should be delegated a
significant role in the selection of IGCC projects that will receive
tax credits.
On a critical note, the inclusion of carbon capture and
sequestration equipment must not be a prerequisite for the allocation
of these additional tax credits due to the urgent need for new electric
generating capacity in the U.S. AEP also believes that this requirement
is premature and self-defeating to advancing IGCC technology. The
addition would require yet-to-be developed technology and/or would
cause the projected cost of a project to increase significantly, making
it that much more difficult for a public utility commission to approve.
AEP also believes that additional tax incentives are needed to spur
the development and deployment of greenhouse gas capture and
sequestration equipment for all types of coal fired generation. We
suggest that additional tax credits be established to offset a
significant portion of the incremental cost of capturing and
sequestering CO<INF>2</INF>. These incentives could be structured
partly as an investment tax credit, similar to that in section 48A (of
the Internal Revenue Code), to cover the up-front capital cost, and
partly as a production tax credit to cover the associated operating
costs.
In summary, AEP recommends a pragmatic approach for phasing in GHG
reductions through a cap-and-trade program coincident with developing
technologies to support these reductions.
Technology Is the Answer to Climate Change
The primary human-induced cause of global warming is the emission
of CO<INF>2</INF> arising from the burring of fossil fuels. Put simply,
our primary contribution to climate change is also what drives the
global economic engine.
Changing consumer behavior by buying efficient appliances and cars,
by driving less, and other similar steps, is helping to reduce the
growth of GHG emissions. However, these steps will never be enough to
significantly reduce CO<INF>2</INF> emissions from the burning of coal,
oil and natural gas. Such incremental steps, while important, will
never be sufficient to stabilize greenhouse gases concentrations in the
atmosphere at a level that is believed to be capable of preventing
dangerous human-induced interference with the climate system, as called
for in the U.S.-approved U.N. Framework Convention on Climate Change
(Rio agreement). For that, we need major technological advances to
effectively capture and store CO<INF>2</INF>. The Congress and indeed
all Americans must come to recognize the gigantic undertaking and
significant sacrifices that this enterprise is likely to require.
CCS should not be mandated until and unless it has been
demonstrated to be effective and the costs have significantly dropped
so that it becomes commercially engineered and available on a
widespread basis. Until that threshold is met, it would be
technologically unrealistic and economically unacceptable to require
the widespread installation of carbon capture equipment. The use of
deep saline geologic formations as primary long-term CO<INF>2</INF>
storage locations has not yet been sufficiently demonstrated. There are
no national standards for permitting such storage reservoirs; there are
no widely accepted monitoring protocols; and the standards for
liability are unknown (as well as whether federal or State laws would
apply). In addition, who owns the rights to these deep geologic
reservoirs remains a question.
Outstanding technical questions for CO<INF>2</INF> storage include:
What is the number of injector wells needed? What is the injector well
lifespan? What is the injector well proximity to other wells? What
measurement, monitoring, and verification of storage in the geologic
reservoirs is needed? What is the time span of post-injection
monitoring? Much work needs to be done to ensure that the potential
large and rapid scale-up in CCS deployment will be successful.
Underscoring these realities, industrial insurance companies point
to this lack of scientific data on CO<INF>2</INF> storage as one reason
they are disinclined to insure early projects. In a nutshell, the
institutional infrastructure to support CO<INF>2</INF> storage does not
yet exist and will require time to develop. In addition, application of
today's CO<INF>2</INF> capture technology would significantly increase
the cost of an IGCC or a new efficient pulverized coal plant, calling
into serious question regulatory approval for the costs of such a plant
by State regulators. Further, recent studies sponsored by the Electric
Power Research Institute (EPRI) suggest that application of today's
CO<INF>2</INF> capture technology would increase the cost of
electricity from an IGCC plant by 40 to 50 percent, and boost the cost
of electricity from a conventional pulverized coal plant by 60 to 70
percent, which would again jeopardize State regulatory approval for the
costs of such plants.
Despite these uncertainties, I believe that we must aggressively
explore the viability of CCS technology in several first-of-a-kind
commercial projects. AEP is committed to help lead the way, and to show
how this can be done.
As described earlier in this testimony, AEP will install carbon
capture controls on two existing coal-fired power plants, the first
commercial use of this technology, as part of our comprehensive
strategy to reduce, avoid or offset GHG emissions.
AEP is also building two state-of-the-art advanced ultra-super-
critical power plants in Oklahoma and Arkansas. These will be the first
of the new generation of ultra-super-critical plants in the U.S. The
more efficient turbine cycle on these ultra-super-critical units
results from increased steam temperatures (greater than 1100
<SUP>+</SUP>F). This improved efficiency reduces fuel (coal)
consumption and thereby reduces emissions. The long-term goal for
ultra-super-critical technology is to develop ``super alloys'' which
can withstand operating temperatures of 1400 <SUP>+</SUP>F. This
increased steam temperature will improve efficiency by about 20 percent
relative to today's super-critical units that are operating in the 1000
<SUP>+</SUP>F to 1050 <SUP>+</SUP>F range.
AEP is also advancing the development of IGCC technology. IGCC
represents a major breakthrough in our work to improve the
environmental performance of coal-based electric power generation. AEP
is in the process of permitting and designing two of the earliest
commercial scale IGCC plants in the Nation. Construction of the IGCC
plants will start once traditional rate recovery is approved.
AEP is also a founding member of FutureGen, a ground-breaking
public-private collaboration that aims squarely at making near-zero-
emissions coal-based energy a reality.
FutureGen is a $1.5 billion, 10-year research and demonstration
project. It is on track to create the world's first coal-fueled, near-
zero emission electricity and hydrogen plant with the capability to
capture and sequester at least 90 percent of its carbon dioxide
emissions.
As an R&D plant, FutureGen will stretch--and indeed create--the
technology envelope. Within the context of our fight to combat global
climate change, FutureGen has a truly profound mission--to validate the
cost and performance baselines of a fully integrated, near zero-
emission coal-fueled power plant.
The design of the FutureGen plant is already underway, and we are
making great progress. The plant will be on-line early in the next
decade. By the latter part of that decade, following on the
advancements demonstrated by AEP, FutureGen, and other projects, CCS
technology should become a commercial reality.
It is when these technologies are commercially demonstrated, and
only then, that commercial orders will be placed on a widespread basis
to implement CCS at coal-fueled power plants. That is, roughly around
2020. Widespread deployment assumes that a host of other important
issues have been resolved, and there is governmental and public
acceptance of CCS as the proven and safe technology that we now believe
it to be. AEP supports rapid action on climate change including the
enactment of well thought-out and achievable legislation so that our
nation can get started on dealing with climate change. However, the
development of technology must coincide with any increase in the
stringency of the program.
A huge challenge that our society faces over the remainder of this
century is how we will reduce the release of GHG emissions from fossil
fuels. This will require nothing less than the complete re-engineering
of the entire global energy system over the next century. The magnitude
of this task is comparable to the industrial revolution, but for this
revolution to be successful, it must stimulate new technologies and new
behaviors in all major sectors of the world economy. The benefits of
projects like FutureGen and the ones AEP is pursuing will apply to all
countries blessed with an abundance of coal, not only the United
States, but also nations like China and India.
In the end, the only sure path to stabilizing GHG concentrations
over the long-term is through the development and utilization of
advanced technologies. And we must do more than simply call for it. Our
nation must prepare, inspire, guide, and support our citizens and the
very best and the brightest of our engineers and scientists; private
industry must step up and start to construct the first commercial
plants; and our country must devote adequate financial and
technological resources to this enormous challenge. AEP is committed to
being a part of this important process, and to helping you achieve the
best outcome at the most reasonable cost and timelines possible. Thank
you again for this opportunity to share these views with you.
[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]
Biography for Michael W. Rencheck
Michael W. Rencheck is Senior Vice President--Engineering, Projects
and Field Services and is responsible for engineering, regional
maintenance and shop service organizations, projects and construction,
and new generation development.
From June 2003 to December 2005, he was Senior Vice President--
Engineering, Technical and Environmental Services. He was also
President of AEP Pro Serv from November 2002 to May 2003.
He served as Senior Vice President--Engineering and Region
Operations for Pro Serv from April to November 2002. Prior to that, he
was Vice President--Strategic Business Improvement at AEP's D.C. Cook
Nuclear Plant from October 2001 to March 2002 and Vice President--
Nuclear Engineering at Cook from 1998 to 2001.
Previously, he served as Director--Nuclear Engineering and Projects
at Florida Power Corp.'s Crystal River Nuclear Station in 1997-98. He
was Director--System Engineering in 1997 and Manager--System
Engineering from 1995 to 1997 at Public Service Electric & Gas Co. He
held various technical and management positions at Duquesne light
Company from 1983 to 1995.
Rencheck has a Master's degree in management and computer
information systems from Robert Morris College in Coraopolis, Pa., and
a Bachelor's degree in electrical engineering from Ohio Northern
University in Ada, Ohio. He is a professional engineer (Arkansas,
Indiana, Kentucky, Michigan, Ohio, Pennsylvania, Virginia and West
Virginia) and a certified senior reactor operator.
Chairman Lampson. Thank you, Mr. Rencheck. Mr. Dalton.
STATEMENT OF MR. STUART M. DALTON, DIRECTOR, GENERATION,
ELECTRIC POWER RESEARCH INSTITUTE
Mr. Dalton. Thank you, Mr. Chairman, thank you to the
Committee, and thank you for having EPRI here for the
testimony. For those of you that don't know, EPRI is a
nonprofit R&D organization, with operational headquarters in
California, but with principal operations also in Tennessee and
in North Carolina.
I would like to summarize just a couple of brief points,
and then elaborate briefly. Recent EPRI work shows that
reduction of CO<INF>2</INF> from the electricity sector will
require a portfolio of technologies of all sorts, not just
capture and storage. Efficiency improvements, which we haven't
talked about much yet today, includes post-generation and can
be implemented in both new and existing plants. CO<INF>2</INF>
capture and storage, which we have talked about, will be an
important CO<INF>2</INF> reduction method, but there is no
silver bullet technology, and it will not be easy or cheap.
Accelerated R&D is needed in all types of coals and
technologies, as well as for large-scale storage of CO<INF>2</INF>
to prove effectiveness. And finally, policy and research needs
to match this accelerated approach to efficiency enhancements,
CO<INF>2</INF> capture and storage.
To expand on these briefly, recent analytical work by EPRI
estimates that in order to significantly reduce CO<INF>2</INF>
from the electricity sector, the U.S. will need to improve
efficiency of electric transmission, and use efficiency,
renewables, nuclear, as well as improvements in coal and
capture and storage, a lot of it is to the subject of today's
hearing.
There is no single silver bullet, but there is a veritable
arsenal of technology being developed worldwide that needs to
be demonstrated and deployed. Multiple coal technologies with
carbon capture and storage will need to be demonstrated across
the range of U.S. applications. Our projects, and those of
others, are that coal will continue to be used, and that we
will need to optimize efficiency and CO<INF>2</INF> capture and
storage as a major part of the overall CO<INF>2</INF> reduction
program.
Existing and new plants can improve efficiency, and reduce
CO<INF>2</INF> per megawatt-hour, per unit of power produced,
by a variety of equipment and operational changes. Some of
these can be accomplished through operational minor equipment
changes. Some will require significant modifications in their
equipment. All types of coal-based generation are capable of
improving efficiency for new units. Significant programs are
underway in the U.S. with regard to that. Over the next 20
years, we believe the improvements can achieve CO<INF>2</INF>
reductions of up to 20 percent per megawatt-hour without
additional CO<INF>2</INF> capture. The MIT Future of Coal
report, the National Coal Council upcoming report, both lead to
this same sort of measure.
It will require a sustained R&D effort and substantial
investment in demonstration facilities. One example, the DOE
Energy Industries of Ohio, Oakridge National Lab, EPRI, as well
as the equipment suppliers, have been working on next
generation superalloys for some years, but there is no
demonstration path going forward at this point toward an
ultrasupercritical coal technology of the advanced type in the
U.S., as there is in Europe.
Technical barriers to reduce CO<INF>2</INF> include cost
and energy, use of capture, and the assurance of safe storage,
as we have talked about. We believe CCS costs and barriers can
be overcome through a joint public and private research
development demonstration effort.
We believe that they can be integrated into all types of
new coal power plants, combined cycles, IGCCs, pulverized coal,
fluidized bed combustion, oxyfuel, and that demonstrations are
vital. In our opinion, no advanced coal technology is
economically preferred for adopting CCS. When you add capture,
it becomes a horse race, in our opinion.
If you use today's technology to capture, compress,
transport, and store, you may see a cost increase of pulverized
coal plants of 60 to 80 percent, 40 to 50 percent for an IGCC
plant, in our estimation. With an aggressive research and
development demonstration program, these costs can be brought
down. Sites for long-term storage are regionally available
throughout the U.S., yet there are major challenges to
overcome, as you have heard. Specifically, we believe large-
scale, greater than one million tons a year demonstrations,
need to commence as soon as possible, and the legal and
regulatory framework needs to be established for long-term
ownership and liability.
We believe there are gaps in the policy toward, to quickly
pursue this research, but primarily, policy toward establishing
long-term liability for CO<INF>2</INF> storage when proper
safeguards are in place. We believe there are pathways for
this, and that industry and government need to act now to move
this forward to improve efficiency, capture, and guiding
principles for storage.
Thank you very much.
[The prepared statement of Mr. Dalton follows:]
Prepared Statement of Stuart M. Dalton
Thank you, Mr. Chairman, Ranking Member Inglis, and Members of the
Committee. I am Stuart Dalton, Director of Generation for the Electric
Power Research Institute (EPRI), a non-profit, collaborative R&D
organization. EPRI has principal locations in Palo Alto, California,
Charlotte, North Carolina, and Knoxville, Tennessee. EPRI appreciates
the opportunity to provide testimony to the Committee on the topic of
``Prospects for Advanced Coal Technologies: Efficient Energy
Production, Carbon Capture and Sequestration''
I want to focus my comments today on three subjects: (I) the
technological challenges our country faces in limiting carbon dioxide
(CO<INF>2</INF>) emissions from power plants that use coal as an energy
source through both efficiency gains and CO<INF>2</INF> capture and
sequestration (2) policy and research gaps where we believe the federal
government can do more to facilitate the reduction of CO<INF>2</INF>
emissions from coal, and (3) highlights from recent EPRI analytical
work that emphasizes the importance of advanced coal technologies as
part of an overall low-cost, low-carbon portfolio of options to reduce
greenhouse gas emissions associated with climate change.
Background
Coal is the energy source for over half of the electricity
generated in the United States, and numerous forecasts of future energy
use show that coal will continue to have a dominant share in our
electric power generation for the foreseeable future. Coal is a stably
priced, affordable, domestic fuel that can be used in an
environmentally responsible manner. Over the past three decades,
development and application of advanced pollution control technologies
and sensible regulatory programs have reduced emissions of criteria air
pollutants from new coal-fired power plants by more than 90 percent.
And by displacing otherwise needed imports of natural gas or fuel oil,
coal helps address America's energy security and reduces our trade
deficit with respect to energy.
By 2030, according to the Energy Information Administration, the
consumption of electricity in the United States is expected to be
approximately 40 percent higher than current levels. At the same time,
to responsibly address the risks posed by potential climate change, we
must substantially reduce the greenhouse gas emissions intensity of our
economy in a way which allows for continued economic growth and
maintains the benefits that energy provides. This is not a trivial
matter--it implies a substantial change in the way we produce and
consume electricity. Because coal contains a higher percentage of
carbon than other fossil fuels such as natural gas, and because this
carbon is emitted as CO<INF>2</INF>, coal presents a greater challenge
to achieving reduced greenhouse gas emissions.
Technologies to reduce CO<INF>2</INF> emissions from coal will
necessarily be one part of an economy-wide solution that includes
greater end-use efficiency, increased renewable energy, more efficient
use of natural gas, expanded nuclear power, and similar transformations
in the transportation, commercial, industrial, and residential sectors
of our economy. In fact, our work at EPRI on the impacts of climate
policy on technology development and deployment has consistently shown
that non-emitting technologies for electricity generation will likely
be less expensive than technologies for limiting emissions of direct
fossil fuel end uses in other sectors.
EPRI stresses that no single advanced coal generating technology
(or any generating technology) has clear-cut economic advantages across
the range of U.S. applications. The best strategy for meeting future
electricity needs while addressing climate change concerns and economic
impact lies in developing multiple technologies from which power
producers (and their regulators) can choose the option best suited to
local conditions and preferences. Assuring timely, cost-effective coal
power technology with CO<INF>2</INF> capture entails simultaneous and
substantial progress in research, development and demonstration (RD&D)
efforts to improve capture processes and fundamental plant systems.
EPRI sees the need for government and industry to pursue these and
other pertinent RD&D efforts aggressively through significant public
policy and funding support. Early commercial viability will likely come
only through firm commitments to the necessary R&D and demonstrations
and through collaborative arrangements that share risks and disseminate
results.
Improvements and new development in several technology areas are
required to achieve large scale reduction of CO<INF>2</INF> emissions
from coal power plants. These needs can be described in three major
aspects:
<bullet> Substantially increased thermodynamic efficiency of
coal plants
<bullet> Cost-effective, efficient, commercially available
technologies for capture of CO<INF>2</INF> from coal plants
<bullet> Cost-effective, commercially available technologies
for storage of captured CO<INF>2
</INF>Each of these areas presents substantial technology
challenges requiring a sustained investment in RD&D.
Increasing Coal Plant Efficiency
Although the United States was an early leader in developing high-
efficiency coal plant designs, we have built very few new coal power
plants in the last two decades and are now playing catchup in the world
race to achieve high-efficiency designs. In the 1950s and `60s, the
United States was the world's pioneer in power plants using
thermodynamically efficient ``super-critical'' and ``ultra-super-
critical'' steam conditions. Exelon's coal-fired Eddystone Unit 1, in
service since 1960, still boasts the world's highest steam temperatures
and pressures. Because of reliability problems with some of these early
units, U.S. designers retreated from the highest super-critical steam
conditions until recently when international efforts involving EPRI and
U.S., European and Japanese researchers concentrated on new, reliable
materials for high-efficiency pulverized coal plants. Given the
prospect of potential CO<INF>2</INF> regulations (and efforts by power
producers to demonstrate voluntary CO<INF>2</INF> reductions), the
impetus for higher efficiency in future coal-based generation units has
gained economic traction worldwide. In fact, the majority of new
pulverized coal (PC) plants announced over the last two years will
employ high-efficiency super-critical steam cycles, and several will
use the ultra-super-critical steam (USC) conditions with very high
temperature, high efficiency designs heretofore used only overseas
(aside from Eddystone).
EPRI is working with the Department of Energy, the Ohio Coal
Development Office and major equipment suppliers on an important
initiative to qualify a whole new class of nickel-based ``super-
alloys,'' which will enable maximum steam temperatures to rise from an
ultra-super-critical steam temperature of 1100<SUP>+</SUP>F to an
``advanced'' ultra-super-critical steam temperature of
1400<SUP>+</SUP>F.
Combined with a modest increase in steam pressure, this provides an
efficiency gain that reduces a new plant's carbon intensity (expressed
in terms of tons of CO<INF>2</INF> emitted per megawatt-hour [Tons/
MWh]) by about 20 percent relative to today's state-of-the-art plants.
Even modest increases in steam conditions can raise efficiency by
several percent in the near-term (a two percent increase in efficiency,
for example, represents a roughly five percent reduction of CO<INF>2</INF>
production and coal use). If capture of the remaining CO<INF>2</INF> is
desired, improved efficiency will also reduce the required size of the
capture equipment and the amount of coal mined and transported.
However, realization of this opportunity will not be automatic. In
fact, it will require a renewed, sustained R&D commitment and
substantial investment in demonstration facilities to bring new
technologies to market. The European Union has embraced such a strategy
and is midway through its program to demonstrate a pulverized coal
plant with 1300<SUP>+</SUP>F steam conditions, which was realistically
planned as a 20-year activity. Efficiency improvements will also be
important for other coal power technologies. The world's first super-
critical circulating fluidized-bed (CFB) plant is currently under
construction in Poland. Many new units in China are being built with
temperatures and efficiencies higher than recent U.S. units, as the
cost of fuel and environmental pressures rise.
The greatest increase in efficiency for integrated gasification
combined cycle (IGCC) units will come from increases in the size and
efficiency of the gas turbines and improvements in their ability to
handle hydrogen rich ``syngas'' that would be produced in IGCC plants
designed for CO<INF>2</INF> capture.
A number of technologies are being developed that promise to
decrease the amount of CO<INF>2</INF> per unit of power produced (e.g.,
pounds CO<INF>2</INF>/kWh or Tons/MWh). With today's technology, a
modern pulverized coal plant and a modern coal-based IGCC plant would
produce roughly the same amount of CO<INF>2</INF>/kWh. Neither achieves
CO<INF>2</INF> capture without significant operational and hardware
modifications and some loss of efficiency. Both are expected to achieve
efficiency advances and cost reductions based on research and
development occurring worldwide. EPRI believes that both industry and
the government should support the development, demonstration, and
deployment of multiple high-efficiency technologies for the future,
rather than picking technology winners.
CO<INF>2</INF> Capture Technology
Carbon dioxide capture and storage (CCS) technologies can be
feasibly integrated into virtually all types of new coal-fired power
plants, including IGCC, PC, CFB and variants such as oxy-fuel
combustion. For those constructing new plants, it is unclear which type
of plant would be economically preferred if it were built to include
carbon capture. All can have relative competitive advantages under
various scenarios.
A utility's choice between these technologies will depend on
available coals and their physical-chemical properties, desired plant
size, the CO<INF>2</INF> capture process and its degree of integration
with other plant processes, plant elevation, the value of plant co-
products, and other factors. For example, IGCC with CO<INF>2</INF>
capture generally shows an economic advantage with low-moisture
bituminous coals. For coals with high moisture and low heating value,
such as sub-bituminous and lignite coals, a recent EPRI study (report
1014510 available publicly) shows PC with CO<INF>2</INF> capture as
competitive with IGCC with CO<INF>2</INF> capture. However, no single
set of costs can represent all conditions. In addition to such
variables as coal type and plant design, the cost of electricity will
also vary due to plant location and the type of financing of the
facility receives.
Post-combustion CO<INF>2</INF> Capture
Although carbon dioxide capture appears technically feasible for
all coal power technologies, it poses substantial engineering
challenges (requiring major investments in R&D and demonstrations) and
comes at considerable cost. However, analyses by EPRI and the Coal
Utilization Research Council suggest that once these substantial
investments are made, the cost of CCS becomes manageable and,
ultimately, coal-based electricity with CCS can be cost competitive
with other low-carbon generation technologies.
Post-combustion CO<INF>2</INF> separation processes (placed after
the boiler in the power plant) are currently used commercially in the
food and beverage and chemical industries, but these applications are
at a scale much smaller than that needed for power producing PC or CFB
power plants. These processes themselves are also huge energy
consumers, and without investment in their improvement, they would
reduce plant electrical output by as much as 30 percent creating the
need for more new plants.
EPRI's most recent cost estimates suggest that for PC plants, the
addition of CO<INF>2</INF> capture using amine solvents (the most
highly developed technical option currently available), along with
drying and compression, pipeline transportation to a nearby storage
site, and underground injection, would add 60-80 percent to the net
present value of life cycle costs of electricity (expressed as
levelized cost-of-electricity, or COE, and excluding storage site
monitoring, liability insurance, etc.). With coal providing 50 percent
of U.S. electricity generation, this translates into a potentially
significant increase in consumers' electric bills.
Oxy-firing
For PC plants, the introduction of oxy-fuel or oxy-coal combustion
may allow further reductions in CO<INF>2</INF> capture costs by
allowing the flue gas to be compressed directly, without any CO<INF>2</INF>
separation process while also allowing the size of the super-critical
steam generator to be reduced. Boiler suppliers and major European and
Canadian power generators are actively working on pilot-scale testing
and scale-up of this technology. AEP has recently announced plans to
study use of this ``oxy-coal'' technology for retrofitting an existing
plant, and SaskPower (Saskatchewan Power) has announced that, Babcock &
Wilcox Canada (B&W) and Air Liquide will jointly develop the SaskPower
Clean Coal Project.
Pre-combustion CO<INF>2</INF> Capture
CO<INF>2</INF> separation processes suitable for IGCC plants are
used commercially in the oil and gas and chemical industries at a scale
closer to that ultimately needed, but their application necessitates
deployment of modified IGCC plant equipment, including additional
chemical process steps and gas turbines that can burn nearly pure
hydrogen.
The COE cost premium for including CO<INF>2</INF> capture in IGCC
plants, along with drying, compression, transportation and storage, is
about 40-50 percent. Although this is a lower cost increase in
percentage terms than that for PC plants, IGCC plants initially cost
more than PC plants. Thus, the bottom-line cost to consumers for power
from IGCC plants with capture may be comparable to that for PC plants
with capture, depending on the types of coal used, elevation of the
plant and other site-specific factors.
It should be noted that IGCC plants (like PC plants) do not capture
CO<INF>2</INF> without substantial plant modifications, energy losses,
and investments in additional process equipment. As noted above,
however, the magnitude of these impacts could likely be reduced
substantially through aggressive investments in R&D. Historical
experience with the development of environmental control technologies
for today's power plants suggests that technological advances from
``learning-by-doing'' will likely lead to significant cost reductions
in CO<INF>2</INF> capture technologies as the installed base of plants
with CO<INF>2</INF> capture grows. An International Energy Agency study
led by Carnegie Mellon University suggested that overall electricity
costs from plants with CO<INF>2</INF> capture could come down by 15
percent relative to the currently predicted costs after about 200
systems were installed.
Furthermore, despite the substantial cost increases for adding
CO<INF>2</INF> capture to coal-based IGCC and PC power plants, their
resulting cost-of-electricity is still usually less than that for
natural gas-based plants at current and forecast natural gas prices.
Engineering analyses by EPRI, DOE and the Coal Utilization Research
Council suggest that costs could come down faster through CO<INF>2</INF>
capture process innovations or, in the case of IGCC plants, fundamental
plant improvements--provided sufficient RD&D investments are made. EPRI
pathways for reduction in capital costs and improvements in efficiency
are embodied in two companion RD&D Augmentation Plans developed under
the collaborative CoalFleet for Tomorrow program. The IGCC plan (Report
No. 1013219) is publicly available, and the PC plan will be available
later this year. Efforts toward reducing the cost of IGCC plants with
CO<INF>2</INF> capture will focus on adapting more advanced and larger
gas turbines for use with hydrogen-rich fuels, lower-cost oxygen
supplies, improved gas clean-up, advanced steam cycle conditions and
other activities.
CO<INF>2</INF> Transportation and Geologic Storage
Geologic sequestration of CO<INF>2</INF> has been proven effective
by nature, as evidenced by the numerous natural underground CO<INF>2</INF>
reservoirs in Colorado, Utah and other western states. CO<INF>2</INF>
is also found in natural gas reservoirs, where it has resided for
millions of years. Thus, evidence suggests that depleting or depleted
oil and gas reservoirs, and similar ``capped'' sandstone formations
containing saltwater that cannot be made potable, are capable of
storing CO<INF>2</INF> for millennia or longer. Geologic sequestration
as a strategy for reducing CO<INF>2</INF> emissions is being
demonstrated in numerous projects around the world.
Three relatively large projects--the Sleipner Saline Aquifer
CO<INF>2</INF> Storage (SACS) project in the North Sea off of Norway;
the Weyburn-Midale Project in Saskatchewan, Canada and the In Salah
Project in Algeria--together sequester about three to four million
metric tons of CO<INF>2</INF> per year, which approaches the output of
just one typical 500 megawatt coal-fired power plant. With 17
collective years of operating experience, these projects suggest that
CO<INF>2</INF> storage in deep geologic formations can be carried out
safely and reliably. Furthermore, CO<INF>2</INF> injection technology
and subsurface behavior modeling have been proven in the oil industry,
where CO<INF>2</INF> has been injected for 35 years for enhanced oil
recovery (EOR) in the Permian Basin fields of west Texas and Oklahoma
and in other U.S. fields. Regulatory oversight and community acceptance
of injection operations are well established in those contexts.
Within the United States, DOE manages an active R&D program, the
Regional Carbon Sequestration Partnerships, that is mapping geologic
formations suitable for CO<INF>2</INF> storage and conducting pilot-
scale CO<INF>2</INF> injection validation tests across the country.
These tests, as well as most commercial applications for long-term
storage, will compress CO<INF>2</INF> to a liquid-like ``super-
critical'' state to maximize the amount that can be stored. Virtually
all CO<INF>2</INF> storage will be at least a half-mile underground,
where the CO<INF>2</INF> will be injected into a porous sandstone-like
material saturated with salty water. CO<INF>2</INF> will be stored in
locations with geologic seals to minimize the likelihood of any leakage
to the atmosphere (which would defeat the purpose of sequestering the
CO<INF>2</INF> in the first place).
DOE's Regional Carbon Sequestration Partnerships represent a broad
collaboration of public agencies, private companies and non-profits;
they would be an excellent vehicle for conducting larger ``near-
deployment scale'' CO<INF>2</INF> injection tests to prove specific
U.S. geologic formations, which EPRI believes to be one of the keys to
commercializing CCS for coal-based power plants. Evaluations by these
Regional Partnerships and others suggest that enough geologic storage
capacity exists in the United States to hold several centuries' worth
of CO<INF>2</INF> emissions from coal-based power plants and other
stationary sources. However, the distribution of suitable storage
formations across the country is not uniform: some areas have ample
storage capacity whereas others appear to have little or none.
Thus, CO<INF>2</INF> captured at some power plants would require
pipeline transportation for several hundred miles to reach suitable
injection locations, which may be in other states. While this adds
cost, it does not represent a technical hurdle because CO<INF>2</INF>
pipeline technology has been proven in oil field FOR applications. As
CCS is applied commercially, EPRI expects that early projects would
take place at coal-based power plants near to sequestration sites or to
existing CO<INF>2</INF> pipelines. As the number of projects increases,
regional CO<INF>2</INF> pipeline networks connecting multiple sources
and storage sites would be needed.
There is still much work to be done before CCS can implemented on a
scale large enough to significantly reduce CO<INF>2</INF> emissions
into the atmosphere. In addition to large-scale demonstrations at U.S.
geologic formations, many legal and institutional uncertainties need to
be resolved. Uncertainty about long-term monitoring requirements,
liability and insurance is an example. State-by-state variation in
regulatory approaches is another. Some geologic formations suitable for
CO<INF>2</INF> storage underlie multiple states. For private companies
considering CCS, these various uncertainties translate into increased
risk.
The Promise of CCS
Recent EPRI work has illustrated the urgent necessity to develop
CCS technologies as part of the solution to satisfying our energy needs
in an environmentally responsible manner. Our recently released
``Electricity Technology in a Carbon-Constrained Future'' study
suggests that with aggressive R&D, demonstration and deployment of
advanced electricity technologies, it is technically feasible to slow
down and stop the increase in U.S. electric sector CO<INF>2</INF>
emissions, and to then eventually reduce them over the next 25 years
while simultaneously meeting the increased demand for electricity. Of
the technologies that can eventually lead to reductions in CO<INF>2</INF>
emissions, the study indicates that the largest single contribution
would come from applying CCS technologies to new coal-based power
plants coming on-line after 2020.
Many other U.S. and international climate models and reports have
stressed that CCS is a vital part of the needed technology mix in any
carbon-constrained future. We believe action is needed now to assure we
can meet these technological and cost challenges.
R&D Gaps
A gap in the policy and RD&D area that EPRI believes needs to be
addressed by the U.S. industry and government is the funding of
multiple capture, transport, and storage demonstrations at large scale
(>1 million metric tons per year of CO<INF>2</INF>). These
demonstrations should encompass a variety of coal technologies and
capture processes, and should be conducted in multiple regions, using
varying geologic formations. Monitoring will need to be conducted to
assure long-term storage effectiveness.
Engineering analyses by EPRI, DOE and the Coal Utilization Research
Council suggest that costs could come down faster through CO<INF>2</INF>
capture process innovations or, in the case of IGCC plants, fundamental
plant improvements--provided sufficient RD&D investments are made.
Combined with EPRI's past experience in transforming science into
deployed technologies, these analyses clearly indicate that a sustained
and substantial RD&D investment will be necessary to assure the
availability of CCS and levels of coal plant performance compatible
with potential CO<INF>2</INF> policies.
EPRI pathways for reduction in capital cost and improvement in
efficiency for IGCC plants are embodied in an RD&D Augmentation Plan
developed under the CoalFleet for Tomorrow program. This figure shows
how efficiency can be increased over the next two decades as costs are
decreased in constant dollar terms. The detailed plans for this have
been developed in our collaborative efforts with firms form five
continents and over 60 participants. A similar figure appears for
combustion processes and shows equally impressive efficiency and cost
gains. Neither of these can be realized without a strong commitment to
research development and demonstration.
[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]
Efforts toward reducing the cost of IGCC plants with CO<INF>2</INF>
capture will focus on adapting more advanced and larger gas turbines
for use with hydrogen-rich fuels, lower-cost oxygen supplies, improved
gas clean-up, advanced steam cycle conditions, and more.
[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]
For PC plants, the progression to advanced ultra-super-critical
steam conditions will steadily increase plant efficiency and reduce
CO<INF>2</INF> production. Improved solvents are expected to greatly
reduce post-combustion CO<INF>2</INF> capture process. EPRI is working
to accelerate the introduction of novel, alternative CO<INF>2</INF>
separation solvents with much lower energy requirements for
regeneration. Such solvents--for example, chilled ammonium carbonate--
could reduce the loss in power output imposed by the CO<INF>2</INF>
capture process from about 30 percent to about 10 percent. At present,
a small pilot plant (five MW-thermal) for chilled ammonia is being
designed for installation at a power plant in Wisconsin later this
year; success there would warrant a scale-up to a larger pilot or pre-
commercial plant. An EPRI timeline (compatible with DOE's timeframe)
for the possible commercial introduction of post-combustion CO<INF>2</INF>
capture follows.
[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]
The introduction of oxy-fuel combustion may allow further
reductions in CO<INF>2</INF> capture costs by allowing the flue gas to
be compressed directly, without any CO<INF>2</INF> separation process
and reducing the size of the super-critical steam generator. Boiler
suppliers and major European and Canadian power generators are actively
working on pilot-scale testing and scale-up of this technology.
Assuring timely, cost-effective coal power technology with CO<INF>2</INF>
capture entails simultaneous and substantial progress in RD&D efforts
on improving capture processes and fundamental plant systems. EPRI sees
the need for government and industry to pursue these and other
pertinent RD&D efforts aggressively through significant public policy
and funding support. Early commercial viability will likely come only
through firm commitments to the necessary R&D and demonstrations and
through collaborative arrangements that share initial risks and
disseminate results.
The urgent need to establish an enhanced RD&D program for
developing advanced coal and carbon capture and storage technologies is
further increased by the likelihood that, as is typical for research,
unexpected technical challenges will surface and require additional
time, effort and funding to resolve.
[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]
Policy Gaps
Without incentives or regulatory requirements, or a market for
CO<INF>2</INF>, CCS will not be chosen based on economics. In addition
to incentives to encourage use of CCS, the State and Federal
governments will need to deal with the issues of land use, ownership,
and liability for CO<INF>2</INF>. This is perhaps the biggest unknown.
No company can take on unlimited liability--options will be needed to
allow firms to make long-term commitments to the technology. Such
options may include special insurance provisions, State or federal
liability provisions, and must include clarity in regulatory
requirements for long-term storage of CO<INF>2</INF>. Models and
current analogies lead us, and many in the industry, to believe that
the risk should be manageable, but the unknowns of long-term liability
makes this risk difficult to manage.
Conclusions
Our country does face significant technology challenges in limiting
CO<INF>2</INF> emissions from coal and it will require multiple
technological approaches for capture and multiple storage
demonstrations to prove the cost, efficiency, and effectiveness of
CO<INF>2</INF> capture and storage. These must be pursued in the near
future to provide options for CO<INF>2</INF> capture and storage on
timeframes compatible with potential policies.
Our research indicates that with proper support and an RD&D program
sustained over the coming decades, the technology for CCS can play a
significant role in reducing CO<INF>2</INF> emissions from the power
industry to meet future national requirements.
Summary of Testimony
Coal is a stably priced, affordable, domestic fuel that can be used
in an environmentally responsible manner. It is the workhorse of the
U.S. electricity grid, accounting for more than half of all the power
generated. Forecasts of future U.S. energy needs envision the continued
predominance of coal in the electric power sector. Thus, technologies
to reduce CO<INF>2</INF> emissions from coal-based power plants must be
part of the set of solutions to climate change concerns. For the
electric sector, that portfolio will also include improved efficiency
in transmission and end use, increased renewable energy, more efficient
use of natural gas, and expanded nuclear power. Analogous low-carbon
transformations must occur in the economy's transportation, commercial,
industrial, and residential sectors. Even within the sub-sector of
coal-based electricity, EPRI stresses that a portfolio of advanced coal
technologies is needed. No single technology has clear-cut economic
advantages across the range of U.S. applications. The best strategy for
reducing CO<INF>2</INF> emissions lies in developing multiple
technologies from which power producers (and their regulators) can
choose the option best suited to local conditions and preferences.
An often-cited step is improving the efficiency of new coal power
plants. This can achieve CO<INF>2</INF> reductions of up to 20 percent
per megawatt hour of electricity before the addition of any dedicated
CO<INF>2</INF> controls. The MIT ``Future of Coal'' report and a
forthcoming report by the National Coal Council endorse this
fundamental measure. Realization of this opportunity will require a
sustained R&D commitment and substantial investment in demonstration
facilities. EPRI, DOE, Ohio Coal Development Office, and equipment
suppliers have a program in place.
EPRI and others believe that CO<INF>2</INF> capture and
sequestration (CCS) technologies for coal-based power plants will be an
indispensable technology for achieving the deep cuts in man-made
CO<INF>2</INF> emissions needed to stop, and ultimately reverse,
atmospheric build-up. CCS technologies can be feasibly integrated into
all types of new coal power plants, including integrated gasification
combined cycle (IGCC), pulverized coal (PC), circulating fluidized-bed
(CFB), and variants such as oxy-fuel combustion. No advanced coal
technology is economically preferred for adopting CCS, and the field of
CO<INF>2</INF> capture technology options is evolving quickly at small-
scale, but large demonstrations are vital. Sites for long-term geologic
storage of CO<INF>2</INF> are regionally available throughout much of
the United States. Yet, there are major challenges to be overcome--both
technically and in terms of public policy--before geologic storage of
CO<INF>2</INF> can be applied at the broad scale needed. Specifically,
multiple large-scale (>1 million tons) demonstrations need to commence
as soon as possible. Legal and regulatory frameworks need to be
established, particularly with respect to long-term ownership and
liability.
RD&D pathways to success have been established collaboratively by
EPRI, DOE, and industry groups. The RD&D funding needs are a
significant step up from current levels, but within historical
percentages for government agencies and private industry. Given the
long technology development and deployment lead times inherent in
capital intensive industries like energy, investment and policy
decisions must be made now or we risk foreclosing windows of
opportunity for technology options that we expect will prove
tremendously valuable in a carbon-constrained future.
Biography for Stuart M. Dalton
Stuart M. Dalton is a Director in the Generation Sector. His
current research activities cover a wide variety of generation options
with special focus on emerging generation, renewables, and coal-based
generation, emission controls, and CO<INF>2</INF> capture and storage.
Mr. Dalton joined EPRI in 1976 as a Project Manager focused on
SO<INF>2</INF> control and later led this area for 20 years,
additionally working on integrated emission controls for NOX, mercury,
and particulates. He helped lead industry efforts to reduce costs,
improve reliability, and apply these technologies.
Before joining EPRI, Mr. Dalton worked at Pacific Gas & Electric
evaluating new generation options (coal gasification and conventional
coal), refuse firing, and NOX control retrofits. Prior to that he
worked at Babcock and Wilcox focusing on power plants and emission
controls.
Mr. Dalton holds a BS in chemical engineering from University of
California, Berkeley.
Mr. Dalton helped create the EPRI CoaIFleet for Tomorrow program
and, more recently, helped develop CO<INF>2</INF> capture and storage
work as well as EPRI's ocean energy program.
The U.S. State Department has designated Mr. Dalton as one of two
official U.S. Asia Pacific Partnership (APP) industry delegates to the
Cleaner Fossil Task Force. In addition, he is leading EPRI's
contribution to the National Coal Council report on CO<INF>2</INF>
Capture and Storage and the Coal Utilization Research Council's CURC/
EPRI Roadmap.
Chairman Lampson. Thank you. Mr. Hill.
STATEMENT OF MR. GARDINER HILL, DIRECTOR, CCS TECHNOLOGY,
ALTERNATIVE ENERGY, BP
Mr. Hill. Mr. Chairman, ladies and gentlemen, I feel
honored to be invited here today to talk about CO<INF>2</INF>
capture and storage. I am indeed heartened that the Science and
Technology Committee is holding a hearing on this technology,
given the potential it has to play a critical role in helping
address the climate change problem.
A number of the elements of CO<INF>2</INF> geological
storage have been practiced for over 30 years in activities
such as: Enhanced Oil Recovery (EOR), where we typically use
CO<INF>2</INF> to inject into oil reservoirs and flush more oil
recovery; in the gas storage operations, where gas is stored
underground, so we have availability and operability of the gas
system; and in acid gas injection operations. Something on the
order of 20 million tons of CO<INF>2</INF> per year is
currently injected into geological formations for EOR, so we
already have a lot of experience.
So, what have we learned about CO<INF>2</INF> geological
storage over this time and through subsequent technology R&D?
Well, we know the best rocks for CO<INF>2</INF> storage are
depleted oil and gas fields and deep saline formations. Now,
these are layers of porous rock, typically very deep, below a
kilometer, and they are located under an impermeable rock known
as a caprock, which acts as a seal to the main reservoir. The
Intergovernmental Panel on Climate Change, the IPCC, has
estimated the technical potential for CO<INF>2</INF> storage is
likely to exceed 2,000 gigatons or 2,000 billion tons of
CO<INF>2</INF>, with the largest capacity likely to exist in
saline formations.
So, given that today's CO<INF>2</INF> emissions are
approximately 24 gigatons of CO<INF>2</INF> from fossil fuels,
geological storage has the capacity to store about 70 to 100
years of all emissions from fossil fuels. On the other hand,
others have estimated that CCS has the potential to contribute
a quarter of the emission reductions required to address
climate change, and in that scenario, you can envision 400
years of CCS storage.
In addition, a critical thing to remember about CCS is its
flexibility and adaptability. And when CO<INF>2</INF> is stored
through the use of an EOR operation, as I discussed earlier,
there is a genuine win/win for the environment and energy
security.
But what are the outstanding risks in the matter of
CO<INF>2</INF> storage? Well, it turns out this is not
dissimilar to today's oil and gas industry. Local health,
safety, and environmental risks associated with geological
storage can be comparable to the risks of current activities,
such as natural gas storage, EOR, and deep underground disposal
of acid gas, provided best practice is applied in four keys
area.
The first one is site selection. The second one is the
design of the storage and the operation of the storage
facility. The third one is putting in place a robust monitoring
program to validate your understanding of the storage system,
and the fourth one is site abandonment, so you have integrity
and seal of that storage site.
Now, over and above these four areas, there are two
critical frameworks I think are necessary to have managed these
risks, and ensure we have consistency in the way CO<INF>2</INF>
is stored. And one is the important regulatory framework for
CCS, and the second one is a CO<INF>2</INF> storage site
certification framework, so we have a consistent standard
applied.
So, what are the things we should consider when selecting a
storage site? Well, I think there are three primary things to
bear in mind. The first one is capacity. Does the site have
enough space to store a large amount of CO<INF>2</INF>? The
second one is injectivity. Can you actually get the CO<INF>2</INF>
in the rock and actually fill it up? And the third one,
importantly, is integrity. Will the site store the CO<INF>2</INF>
for the timeframe required?
So, that means we need to understand the competence of the
structure, the stratigraphic trap, you need to understanding
the faulting within geological structure, because that could
contribute to a leak or, indeed, compartmentalization of the
rocks, you don't get access to all the pore space. You need to
understand the geochemistry, the number of wells you need to
store the CO<INF>2</INF> and the design of the wells, so you
have integrity for the life of the installation. But as I said
before, a key element is the performance prediction, and we
have to have a monitoring and verification program to validate
the understanding of the storage site.
Now storage, secure storage, actually increases over time,
and that occurs through the interaction of four different
trapping mechanisms. Some can be engineered to enhance the
trapping, and hence, is important to understand the role that
each of these mechanisms play when selecting a storage site.
So, the first one, as I have mentioned, is structural trapping,
where you have an impermeable rock above the formation, which
actually physically traps the CO<INF>2</INF> moving up.
The second mechanism is called residual phase trapping.
That is simply CO<INF>2</INF> going into like a sponge. You
have a sponge you have in your bath that you fill with water,
sinking the CO<INF>2</INF> in a rock, the CO<INF>2</INF> goes
into the pores in that sponge in that rock and gets trapped
between the pore, and becomes totally immobile, just like you
can't get the water out of the sponge unless you squeeze it.
The third one is solubility, and that is where your
CO<INF>2</INF> dissolves in water, in your fizzy water, and
what happens is the density of that water increases, so that
water, then, sinks to the bottom of the reservoir, and can't
possibly come out, because of the density difference.
And the fourth one is mineral trapping, and that is where
the CO<INF>2</INF> reacts with some of the minerals in the
formation, and you get physical hard scales forming, so it is
physically trapped in a solid form, and hence the security of
storage increases with time.
So, what steps remain to be taken so we can design long-
term carbon sequestration projects? Well, clearly, technology
development must continue, and has an important role to play,
but my sense is the time is now right to embark upon large-
scale demonstration projects, and I would say that is a million
tons or more per year projects. And it is important we
demonstrate and we look and we try to demonstrate in a number
of different types of reservoirs in different locations. And we
need to truly learn by doing at scale.
This needs to be done in a managed way by something like a
deployment strategy, which is a framework or plan that is
consistent with a clear objective that will be achieved by a
certain point in time. We need to set a goal and put in place a
plan to achieve the goal, being clear and transparent on the
conditions of satisfaction required one way, so we can secure
the public's confidence in this technology.
It is clear we need to put in place regulations and policy
measures that will allow geological studies to happen. Industry
needs a regulatory framework, so that the operating conditions
are clear, and industry needs a policy framework so we can
define the necessary business and commercial conditions for
CO<INF>2</INF> storage. We need to also identify and remove
roadblocks to technology, and I will give you two examples.
One roadblock, potentially, is what happens to any
liability associated with CO<INF>2</INF> storage after a
storage site is full and safely abandoned. Another example
could be who owns the pore space? The number of laws in the
U.S. are unclear in some cases about ownership of the very pore
space in the rocks that will be used for storing
CO<INF>2</INF>. So, removing these barriers, and a deployment
strategy that is open and transparent, with the appropriate
regulations, I think are really important to convincing public,
regulators, and governments alike that CCS is a safe and
important technology to help solve climate change.
Ladies and gentlemen, it is time to get into action. It is
time to get on with the job. This technology is available now,
and with some help, we can make it happen at scale. And this is
actually being demonstrated today by BP, who have announced two
hydrogen power projects which will utilize CO<INF>2</INF>
capture and geological storage to use carbon power from fossil
fuels.
Thank you very much.
[The prepared statement of Mr. Hill follows:]
Prepared Statement of Gardiner Hill
Chairman Lampson, Ranking Member Inglis, thank you for inviting me
to testify here today on carbon capture and sequestration. I am
Gardiner Hill, Director of CCS Technology at BP, and a petroleum and
civil engineer by training.
For those of you who don't know, BP has made a commitment to
investing $8 billion over the next 10 years in alternative energy--
including wind, solar, and fossil-fuel powered power plants with carbon
capture and sequestration (CCS). We have announced two projects using
CCS--one in Scotland, the other at our Carson refinery in California.
BP, and the oil and gas industry generally, has more than thirty
years of experience injecting carbon dioxide in oil and gas reservoirs.
We do so every day for enhanced oil recovery-injecting CO<INF>2</INF>
into depleted oil reservoirs, recovering the remaining oil, and
inevitably leaving CO<INF>2</INF> behind. In other words, CO<INF>2</INF>
storage is a technology that is available today and we know that it has
the potential to play a significant role in helping to reduce CO<INF>2</INF>
emissions into the atmosphere, helping to combat climate change.
My role today is to explain how CO<INF>2</INF> stays underground.
It is important to understand that many natural geological stores of
CO<INF>2</INF> have been discovered underground--often by people
looking for oil and gas. In many cases, the CO<INF>2</INF> has been
trapped underground for millions of years in geological traps, plus
CO<INF>2</INF> is also found indigenous in many oil and gas fields,
where is has been stored underground naturally for millions of years.
It is true that under certain circumstances, CO<INF>2</INF> does leak
naturally from underground. Indeed the world's natural carbonated
mineral waters, long prized and bottled for drinking, come from natural
CO<INF>2</INF> sources. The reasons why some rock formations trap the
CO<INF>2</INF> permanently and some do not are well understood and this
understanding will be used to select and manage storage sites to
minimize the change of leakage.
The best rocks for CO<INF>2</INF> storage are depleted oil and gas
fields and deep saline formations. These are layers of porous rock,
such as sandstone, more than half a mile underground, located
underneath a layer of impermeable rock, or cap-rock, which acts as a
seal. In the case of oil and gas fields, it was this cap-rock that
trapped the oil and gas underground for millions of years.
Depleted oil and gas fields are the best places to start storing
CO<INF>2</INF> because their geology is well known, and they are proven
traps.
Deep saline formations are rocks with pore spaces that are filled
with very salty water--much saltier than seawater. They exist in most
regions of the world and appear to have a very large capacity for
CO<INF>2</INF> storage. However, the geology of saline formations is
currently less well understood than that of oil and gas fields and so
more work needs to be done to understand which formations will be best
suited to CO<INF>2</INF> storage, but the potential appears to be huge!
So why does CO<INF>2</INF> stay underground? As CO<INF>2</INF> is
pumped deep underground it is compressed by the higher pressures and
becomes essentially a liquid, which then becomes trapped in the pore
spaces between the grains of rock. The longer the CO<INF>2</INF>
remains underground, the more securely it is stored. There are four
different ways that CO<INF>2</INF> gets trapped underground.
The first mechanism is called structural storage. This can be best
demonstrated by BP's joint venture with Sonatrach called In Salah,
which is a natural gas development in Central Algeria. At In Salah, the
natural gas produced from the deep rock formations is a mixture of
methane (CH4) and CO<INF>2</INF>. Once it reaches the surface, the
natural gas is separated into methane and CO<INF>2</INF>. The Methane
gas is pumped North to Europe, while the CO<INF>2</INF> is pumped deep
underground--back into the rock formations from which the natural gas
was originally extracted. One million tons per year of captured
CO<INF>2</INF> is injected and stored in this way. When it is pumped
deep underground, it is initially more buoyant than water and will rise
up through the porous rocks until it reaches the top of the formation
where it is trapped by an impermeable layer of cap-rock, such as shale
at the In Salah field. The cap-rock that kept the natural gas in the
rock formation for millions of years keeps the liquid CO<INF>2</INF>
stored in the underground reservoir. The wells that were drilled to
place the CO<INF>2</INF> in storage can be sealed with plugs made of
steel and cement.
The second mechanism is where CO<INF>2</INF> gets trapped in the
rock pore space through what is known as residual trapping. In this
instance, the reservoir rock acts like a tight, rigid sponge. When
liquid CO<INF>2</INF> is pumped into a rock formation, much of it
becomes stuck within the pore spaces of the rock and does not move.
The third mechanism is called dissolution storage. In this
instance, CO<INF>2</INF> dissolves in salty water, just like sugar
dissolves in tea. The water with CO<INF>2</INF> dissolved in it is then
heavier than the water around it and so it sinks to the bottom of the
rock, trapping the CO<INF>2</INF> indefinitely.
And finally, the fourth mechanism is when CO<INF>2</INF> dissolves
in salt water, becoming weakly acidic and reacting with the minerals in
the surrounding rocks, forming new minerals as a coating on the rock--
much like shellfish use calcium and carbon from seawater to form their
shells. This process effectively binds the CO<INF>2</INF> to the rocks,
trapping it there.
We have the technology and the knowledge to get started on storing
carbon underground. BP, in partnership with Edison Mission, has
announced a CCS project at our Carson refinery in Southern California.
We will be taking petcoke, a refinery byproduct, and gasifying it. The
resulting hydrogen will be used to power a 500 megawatt power plant,
and the CO<INF>2</INF> will be stored underground, probably via an
Enhanced Oil Recovery process (EOR), which is the mechanism I outlined
at the start of the testimony in which industry has over 30 years
experience. We know that CCS is part of the solution to the climate
change problem, i.e., ref. IPCC special report and Princeton Wedges
analysis, etc.--estimates are that CCS technology has the capability to
contribute around a quarter of the emission reductions needed to get to
environmental stabilization. We have the technological know-how to do
this, we need the policy and regulatory framework to enable its
deployment.
Thank you and I welcome any questions you may have.
Discussion
Carbon Sequestration Risks
Chairman Lampson. Thank you very much. We will now begin
with our first round of questions, and I will recognize myself
for five minutes. And I would start with a whole bunch of
questions at one time, if you will forgive me for doing this,
and do them as best you can, and I would like to ask Mr. Bauer,
Dr. Finley, and Mr. Hill to respond to these.
I understand that CO<INF>2</INF> storage is a technology
that is available today, as we have heard, and could play a
significant role in reducing CO<INF>2</INF> emissions into the
atmosphere. Do we know what the probability is of a carbon
release from a geological site? What research and data are
available to understand the environmental and human health and
safety risks? Are there well established risk assessment
methodologies for geological storage of CO<INF>2</INF>? Let me
start with those, and then I am going to ask two more.
Dr. Finley. Well, I think with regard to the probabilities
of release, I think yes, there is a probability of release. It
is very difficult to quantify at this point in time. The
natural gas storage industry has had many very safe and
operational natural gas storage facilities. For example, we
have one in Champaign County, Illinois that stores 150 billion
cubic feet of flammable natural gas over an area of 25 square
miles, and that facility has been in place since the early
1970s, and to the best of our knowledge, never has had a leak
to surface or a problem.
So, we have some analogies out there. We need to take
advantage of those analogies, and I think with the advent of
the large-scale testing that is being proposed here, and that
we are moving toward on the regional partnerships, it is really
going to give us an opportunity to put in place a series of
sensors, observation wells, and the like, that I think will
really begin to try and take this largely qualitative
understanding, and move it over into the quantitative arena, as
you suggest.
Mr. Bauer. I would agree with that, and I think Gardiner
Hill did a great job of describing basically what a reservoir
would be, which is really not a void. It is a rock, it is a
permeable rock, and many people get concerned about a rapid
release, but from a permeable rock, it doesn't just spring out
in tremendous force. To be a volcanic void, and there has been
a couple incidents in history recorded, where a volcanic void
erupted, with CO<INF>2</INF> being released in a low-lying
area, and there was a concern, but that is not the kind of
capture area, plus the capstone rock being very important.
We do have data, the regional partnerships have done some
great things in the first two phases, at both analysis and
collecting data, but the third phase, which we are entering
this year, is to do projects towards the million ton per year
level, and to catch, gather greater data for that. On the area
of risk assessment, there are abilities to do risk assessment.
The application to this particular arena is not really done,
except from the standpoint, I think, and Gardiner, maybe you
could speak to the EOR and the risk assessments about there,
that might be of enlightenment to you.
Mr. Hill. Thank you very much. I think this is all about
risk management, actually. And the way we approach this is by
taking fundamental review of the risks, and making sure these
are managed adequately. But let me start by saying there is a
lot of experience. I mean, there is many examples of gas
storage, which is clearly more dangerous than CO<INF>2</INF>,
because of the increased buoyancy and the flammability of gas,
many years of EOR, and indeed, we actually have a number of
CO<INF>2</INF> natural gas fields that exist, or CO<INF>2</INF>
natural reservoirs that exist in the U.S., that primarily are
used today for supplying CO<INF>2</INF> for EOR.
So, we can actually go and look and study these CO<INF>2</INF>
natural reservoirs that have occurred for millions of years,
and why CO<INF>2</INF> has stayed there for millions of years.
And indeed, we have done studies to undertake the performance
of the natural gas storage system, and there is examples in
Europe where there is a very large natural gas storage system,
actually under the City of Berlin itself. So, there is real
examples of where gases, like CO<INF>2</INF> and perhaps even
more volatile, are actually stored in fairly public places very
safely and with a great track record.
Regulatory Requirements
Chairman Lampson. Okay. Let me interrupt you, because I
have got 50 seconds left, and I want to try to be a little bit
better on my timing this time.
Let me ask the last two questions of you for this
particular section for me, and then, I will catch something
else a little bit later, but who should manage and monitor the
sequestration sites, and secondly, does the EPA have good
regulatory structure in place to adequately address the review
and oversight necessary for large-scale carbon sequestration?
Mr. Bauer. On the matter of who should regulate, I won't
take that one on directly, because of my position, but we are
working with the EPA to put in information and to prepare
regulatory requirements. They do not presently have one of
sequestration, they do have it for injection wells. There was a
letter of guidance released March 7 of this year from EPA,
giving direction of large-scale injection, but the long-term
storage is not framed properly yet.
Chairman Lampson. Dr. Finley or Mr. Hill, would you
comment?
Dr. Finley. Yeah, I think, as Carl mentioned, yes, the U.S.
EPA has issued these guidelines looking at, classified as
experimental under the underground injection control
regulations, as a place to start. I think the Interstate Oil
and Gas Compact Commission has been working now for several
years, looking at the State regulatory framework, because after
all, under UIC, states that have primacy, for example, do
regulate as Class 2 the wells that deal with oil and gas and
EOR, which Gardiner has referred to.
So, I think basically, I think the States need to have an
important role in it, but the exact framework of that role has
yet to be defined.
Mr. Hill. Yes. I would validate that. I think it is an
important thing to tackle regulations, I think, when you take
groups together, to make sure we have the right people who can
write the right regulations.
We are involved in helping, we would like to be involved in
helping develop these, given the experience we have through EOR
and through CO<INF>2</INF> storage, like in Sowerfield, where
we are injecting a million tons per year of CO<INF>2</INF>
which is stored annually.
Chairman Lampson. Thank you very much. Ranking Member
Inglis, recognized for five minutes.
Carbon Sequestration Sites
Mr. Inglis. Thank you, Mr. Chairman. Now, I am a commercial
real estate lawyer, not a scientist, which will become obvious
in the midst of these questions that I am about to ask.
But one of the things you say in real estate, you know, is
three things determine the value of real estate, location,
location, location. And so, the question that I have about the
geological formations is how common are they, and are they
located in places that are usable? I mentioned in my opening
statement the Duke power plant in South Carolina that may be a
coal-fired plant. How readily available are these locations for
the kind of storage that we are talking? Anybody want to,
whoever wants to take a shot at that?
Dr. Finley. Well, I think, I mean it depends on the type of
rocks. I was in Madison, Wisconsin two weeks ago, and listened
to the Wisconsin State geologist proclaim very clearly that the
State of Wisconsin has very limited opportunity to store carbon
dioxide in the rock framework. I am afraid that is also the
case for much of the Atlantic coastal plain, which you
represent with regard to South Carolina. I got my Ph.D. at
Columbia, and so, I have some knowledge of the geology of the
State of South Carolina.
But basically, it is the rock framework, but that is not to
say that we are restricted locally within that rock framework,
because after all, we have more than a million miles of natural
gas pipelines in this country that deliver natural gas from our
shore of the Gulf of Mexico to the State of Maine, for that
matter. So, basically, I think what can be adapted is find the
places where the geology is suitable, where it is safe and
where it can be effective, and if you have places where the
coal resources or the water resources are available, such that
power generation is appropriate there, then we can build an
infrastructure to move the CO<INF>2</INF> to where it can be
safely stored.
Carbon Dioxide Transportation
Mr. Inglis. So, then, we would likely be talking about
moving CO<INF>2</INF>, pipeline system. I guess a truck would
not be effective, right, because there is a lot of it, so you
got to move it, which the next question is, is the other thing
about commercial real estate, as we say, you know, they are not
making any more of it, which makes it valuable, real estate
that is. And so, the question is how quickly before these
formations are used up? What kind of capacity do we have?
Mr. Bauer. Well, I think as Dr. Finley gave in his
testimony, there are multiple hundreds of years of geologic
storage capacity available. It goes back to location. They may
not be always available where you are. I think as Gardiner also
mentioned, making sure you have a sufficient reservoir when you
start to meet your stand for longevity there, is also something
to determine.
So, the bottom line is there is plenty of storage
available. The geographic location may not always be in the
right place. You may have to pipeline to it. But for the
Nation, about 97 percent of the areas that use coal power today
have geologic storage within a reasonable distance, 50 to 100
miles, at maximum, to be pipelined, many times, even right
below a facility presently.
Mr. Hill. Can I just add to that? I think this is actually
a volume issue, and that if CCS is to make a contribution to
climate change, then we are actually talking about huge
volumes, and in my statement, I said it could contribute up to
a quarter of the reductions required to help stabilize
emissions. Now, even a quarter contribution is something like
equivalent to 125 million barrels equivalent of oil, so that is
an industry big as the oil industry. Currently the oil industry
is about 18 million barrels per day, so if CCS is doing only a
quarter of the reductions required emissions, you are talking a
business, an infrastructure, at least equivalent at least
equivalent to these oil industry, so it will be a big
infrastructure requirement. At times, there are a number of oil
and gas fields that are very suitable to store CO<INF>2</INF>,
but there is actually a lot larger capacity in these deep
saline formations, which turn out to be quite extensive across
the U.S., and in fact, most of the world.
Mr. Rencheck. I would like to add on that, regional
partnerships, the importance of continuing the drilling into
the saline aquifers. While we understand a lot about the oil
formations and gas formations, these rock structures in some
cases are 9,000 feet below the surface. At our Mountaineer
Plant, we participated in the drilling of that, understanding
the geology, and we think we need to do more of that, so we
understand the geology at those deep levels.
Carbon Sequestration Atlas
Mr. Inglis. I have more questions, but my time is almost
up. Mr. Bauer, just to make sure, how much, you said within 50
miles, we have what percent of the capacity?
Mr. Bauer. When we did the Atlas, which Dr. Finley held up,
and I have a couple digital versions I would be glad to leave
with the Committee, it identified that there were plenty of
reservoirs, and the regional partnerships cover about 97
percent of the land mass of the United States, which also
happens to coincide to about 97 percent of the power plant
areas, and well within that realm, there is pretty much
sequestration availability for most of those plants within a
reasonable transmission framework, and going with what Gardiner
said, we are talking mainly with saline aquifers, as well as
oil and gas fields that would be expended or used for EOR
before expending.
Chairman Lampson. Mr. Costello, you are recognized.
CCS Technology Readiness
Mr. Costello. Mr. Chairman, thank you, and I thank all of
the witnesses for their thoughtful testimony.
I would like to try and clarify a few points, and then, ask
a few questions as well. One is that I think it is important to
clarify that while CCS technology will enable our power plants
to operate more efficiently, and enable them to not only
operate more efficiently, but reduce emissions, that there are
legitimate reasons why utility companies and the coal industry
are not using the technology today, and until the technology is
ready to be deployed on a commercial scale basis, I believe
that a mandate from Congress to capture and store all carbon
dioxide underground will, in fact, shut down coal plants across
the country, which will, of course, drive up consumer
electricity bills, and convert existing power plants to burn
natural gas.
Given the volatility of the oil and gas market, and the
instability in the Middle East and the rising cost of oil and
natural gas, I believe we should reject policies which move us
toward greater dependence on foreign sources of energy, and
instead, embrace policies and encourage the use of our domestic
resources, such as advanced clean coal technology demonstration
projects.
The figures that I have from the Energy Information
Administration in May of 2007, the cost per million Btu of oil
is $7.66 per million Btus. Natural gas is $7.53, and coal is
$1.73, so I think it is very evident, the cost differences in
oil versus natural gas and coal. Today's hearing, of course,
has shed some light on some of these issues, and also, brings
out the fact that there are significant challenges to overcome,
such as the readiness of the technology, the capital costs and
long-term liability issues, which was touched on, and I think
that we in the Congress must first address these issues before
we can implement a CCS technology mandate.
With that, I would like to pose a few questions, and to try
and clarify a few points. And Mr. Hill, in particular, I read
your written testimony, and you state that carbon dioxide
storage, also known as sequestration, is a technology that is
available today, and I wanted to clarify a point, and to make
certain that I understand, that you are referring to carbon
sequestration technology for enhanced oil recovery. Is that
correct?
Mr. Hill. No, I am not only referring to oil recovery. I
think the technology for storing CO<INF>2</INF> in oil and gas
reservoirs independent of enhanced oil recovery is available
today, and I could point, I can point to the two well examples
of where that occurs. Under the North Sea, the Sax Formation
has been storing a million tons per year of CO<INF>2</INF> for
ten years, and the Dust Development in Salah. It is also
storing a million tons of CO<INF>2</INF> per year in the bottom
of a gas reservoir.
Mr. Costello. Now, is anyone currently capturing CO<INF>2</INF>
underground, on a full, large-scale basis in the United States?
Mr. Hill. I am not aware of a full-scale application in the
United States.
Mr. Costello. Any of the other witnesses like to comment?
Dr. Finley. There is a plant in North Dakota that captures,
from gasification, not from power production, but from
gasification of coal, about 2.7 million tons a year, and it is
shipped north to an enhanced oil recovery, and there is some
testing as to how much will stay in that oil recovery field.
So, that is one application.
Mr. Costello. Let me, there is a bit of, we have a briefing
for Members on the issue of coal and some of the challenges
that we have, and in sum, people believe that the technology on
a large-scale commercial basis is available today. Others say
that it won't be available until the year 2020, and I wonder
if, in particular, if any of the witnesses would like to
comment, beginning with Dr. Finley.
Dr. Finley. Well, I think that would be a little
pessimistic, in my view. I think, in view of the experience at,
in Sleipner, which is the North Sea project, and Salah in
Algeria, and the Weyburn Project, and the gas, natural gas
storage, I think saying that we cannot do this until 2020 would
be, in my view, a bit conservative.
Mr. Costello. But would you agree that the technology is
not on a commercial, full-scale basis, available?
Dr. Finley. Well, let me ask, are you speaking of the
capture at the power plant, versus the ability to put it in the
ground? Capture at the power plant is not available.
Mr. Costello. Right.
Dr. Finley. That is correct. Ability to put it in the
ground from a source, such as the Dakota Plains Gasification
Plant, where we have a relatively pure stream available, that
technology is there.
Mr. Costello. And in your judgment, Dr. Finley, how long
will it be--of course, it is your--you have got to give your
best guess, before the technology is available to capture it at
the power plant on-site?
Dr. Finley. I think we need probably, certainly, perhaps,
six to ten years of intensive development to focus on that
capture, basically to scale up some of the processes that we
have seen today, and make them widely available.
Mr. Costello. Two more quick questions, before I run out of
time here. Would you agree that if, in fact, the Congress
enacted a mandate to capture all, and to sequester underground,
all CO<INF>2</INF> emissions, in the short-term, that that, in
fact, would shut down most of the coal-fired plants in the
United States today, and force them to convert to natural gas?
Dr. Finley. I think that would be a fair statement, yes.
Mr. Costello. The last question, and I would love to hear
from the other witnesses, but I am about out of time. Maybe we
will have a second round, but Dr. Finley, some have suggested
to Members of this subcommittee and to the Congress that, I
have heard that we have a 250 year supply of coal. Others say
that if we continue to use coal, and in fact, can sequester the
CO<INF>2</INF> and move forward in using additional coal, that
we are going to run out of coal in the short-term, and I wonder
if you might give your estimate as to the coal supply of the
United States.
Dr. Finley. Well, I think your number is correct,
approximately 247 billion tons of defined reserves. We use
about 1.1 billion tons a year, so that number is, indeed, very
close. I think some of the Sasol process, Sasol experience in
South Africa suggests we can get about two barrels of
hydrocarbon liquids for each ton of coal. I think we could
easily move to perhaps produce as much as two million barrels
per day of liquids from coal, and I still think we would easily
have 100 years of coal to do that, in addition to having the
coal available for electric generation that we would need over
the next 100 years.
Mr. Costello. I thank the Chair for being generous with my
time, and thank the witnesses.
Chairman Lampson. Very welcome. We will get you back
somehow. Mr. Neugebauer, you are recognized.
Mr. Neugebauer. Well, I thank the Chairman, and like the
distinguished Ranking Member, he is a real estate lawyer, and I
am a real estate developer, so I don't know if I am going to be
able to contribute much more than he did to this discussion.
I think I am going to start with a fundamental question and
just for my own edification, if I had two electric power plants
sitting side by side, one of them using natural gas, and one of
them using coal, what is the ratio of CO<INF>2</INF> being
emitted by those two plants? Mr. Dalton.
Mr. Dalton. You would roughly get about 2,000 pounds per
megawatt-hour from a coal plant, conventional design or
gasification design, without capture. And you would roughly get
about 800 pounds per megawatt-hour from a natural gas plant,
combined cycle.
Mr. Neugebauer. So, it is a substantial difference.
Mr. Dalton. Correct.
Mr. Neugebauer. And so, while we have got you in the queue,
from your testimony, my impression is that post-combustion
CO<INF>2</INF> capture not only reduces the output of
pulverized coal, therefore, adding to the cost, but also, adds
to the cost, due to the additional technology, transportation,
and storage requirements. Is that accurate?
Mr. Dalton. That is accurate. We estimate that both the
energy use and capture, and the compression energy, primarily,
that is used to get the CO<INF>2</INF> up to the point where it
becomes almost like a liquid, about half the density of water,
it is transported through a pipeline, that energy can roughly
run from, if you used today's technology, 20 to 30 percent of
the overall energy of the plant. Again, we are looking at a lot
of new technologies, both for compression and for capture, that
will reduce that, but that is the kind of range that we are
looking at.
Mr. Neugebauer. So, I have got to have 120 percent more
capacity with that process, to produce about the same amount of
energy, without it, and so, and at the same time, I guess I am
creating more CO<INF>2</INF> to be dealt with.
Mr. Dalton. And you are using more coal, correct.
Mr. Neugebauer. So, what--for that to be a viable option
for the future, what kind of research needs to begin to, or is
research going on to try to make that a more efficient process?
Mr. Dalton. There is research going on. Carl Bauer referred
to several pieces of that work that is going on. There is
research going on on both the, if you will, the chemical plant
that is in front of the power generation, which is
gasification, and the chemical plant that is in the back of a
more conventional plant, to capture the CO<INF>2</INF>.
Unfortunately, we haven't found anything yet that is the
perfect absorbent material, that grabs it very easily, captures
it very easily, and then, when you want it to, wants to let it
go very easily. If it is easy on the capture side, it doesn't
tend to want to let it go, and this is what takes all the
energy, is to try and make it let go of the CO<INF>2</INF>.
Mr. Neugebauer. Yes, Mr. Rencheck.
Mr. Rencheck. I would tell you that we are working on
demonstration projects that would take those types of
technologies that Stu was talking about from a pilot phase to
an advanced phase, and we are hoping to get the energy
penalties down to the 10 to 15 percent range. And the purpose
of the demonstration is to do it at scale, and understand how
it will behave on the back of the plant.
We are also looking at building IGCC plants which, in order
to advance that technology, we are going to have to build four
or five, six of these plants at a commercial scale, before we
understand how they can more efficiently and more effectively
be utilized.
Other Uses for CO<INF>2
</INF>Mr. Neugebauer. Mr. Finley, you indicated in, that in
my part of the world, West Texas, we have been using CO<INF>2</INF>
for tertiary and secondary recovery of oil very, very
successfully, and I assume without much hazard to the
environment and to the region. I guess the other question is,
what kind of research is going on where we could, rather than
just putting this CO<INF>2</INF> in the ground and disposing of
it, use CO<INF>2</INF> for other kinds of activities? Is any of
that kind of activity going on?
Mr. Bauer. Yes, sir. There is some other work looking at
using CO<INF>2</INF> for more rapid plant growth, algae growth,
taking the algae as a quick uptake of CO<INF>2</INF>, and then
converting it to a biodiesel. There is a couple of different
experiments around the country. Arizona Power Service is doing
on a fairly large scale off of a plant, and they are moving it
up to Four Corners area right now. There are a couple others I
am aware of, where they use a pond rather than a bio-reactor,
and those seems to hold promise, although the magnitude of the
CO<INF>2</INF> generated across the Nation, that would only be
one of the tools, it would not solve the problem totally. But
they are looking at using CO<INF>2</INF> as a working fluid, to
capture energy and move it elsewhere, and in fact, even oxy-
combustion plants previously mentioned, looked at recycling
CO<INF>2</INF> as part of the working fluid in operating the
plant and keeping it cooler.
Mr. Neugebauer. I thank you and thank the Chairman.
Chairman Lampson. Thank you, Mr. Neugebauer. Ms. Giffords,
you are recognized.
Western Regional Partnerships
Ms. Giffords. Thank you, Mr. Chairman. I realize I wasn't
here for the earlier questions and some of the testimony, but I
hail from the great State of Arizona, where 90 percent of our
electricity in the City of Tucson is generated from coal.
Over 50 percent of our state's energy is generated from
coal, but we are the fastest growing state in the Nation, and
new coal plants are being proposed for Southern Arizona and
across the State as well.
I would like to see Arizona transition from coal to clean,
renewable energy. However, I recognize that for the foreseeable
future, that carbon capture and sequestration could help us
reduce emissions in the meantime. So, I am curious to the
barriers that we have in front of us in Arizona. I am curious
about the environmental benefits and the costs, and also, some
of the political obstacles that we have to overcome to make
this a reality. And for anyone on the panel to answer, please.
Mr. Bauer. Well, if you are talking Arizona specifically,
there are, as I am sure you are aware of the geological
resources to put CO<INF>2</INF> in and store it, so those
possibilities are there, but I think you made a very important
point in your question, which is the political, and I might say
the public receptivity to this. And this is one of the reasons
the regional partnerships were formulated, to both understand
the challenges in the geographic locations as well as the
geologies, but also to work across the States that are part of
it, to work with the communities and the academia to
communicate what they find and what the challenges and what the
opportunities are, so that the public acceptance and political
acceptance would be there, should this process turn out, as it
seems to be, to be a very viable solution.
So, I think part of it is education, and then part of that
education, as you again wisely observed, is to go where we
would like to go, as far as renewables, will take many decades
to raise the quantity capability. How do we keep the economy
viable while we do that? We are going to have to use what we
have, which is basically coal, natural gas, and others, which
are more carbon intensive.
Mr. Dalton. I would like to add that we have been working
with the WESTCARB Regional Partnership in the West. There is
some small-scale work being planned with Salt River Project as
one of the organizations, working with, again this is the
small-scale type of work that the regional partnerships has
been excellent at setting out. It helps in understanding the
mechanics, the monitoring, the verification. It helps in
understanding the public perception issues as well, but there
are geologies that run throughout certain parts of the West
that are somewhat similar, and so, there should be quite a bit
learned from any large-scale work that follows on wherever that
is in the West, that the geologies are somewhat similar, to my
understanding, as a chemical engineer, not as a geologist.
Mr. Rencheck. And I would offer that the initial approach
to improved efficiency as a coal generating plants are very
important, and that is the reason for advancing technology such
as the ultra-super critical plant, as well as the IGCC plants.
And also, the existing fleet can also be improved from an
efficiency perspective, but at times, it runs headlong into NSR
regulations about improving border functionalities, so you
could advance the existing fleet efficiency if we could get
better clarity around new source review requirements.
Funding Concerns
Ms. Giffords. And Mr. Chairman, if we could just follow up
there. I am curious in terms of the actual costs, and where
those costs would be shouldered. Is this--would--privately
shouldered, publicly shouldered? Can the government step in and
be helpful here?
Mr. Rencheck. On the projects we are proposing, we are
looking for a partnership between public and private funding.
We are working also with technology providers who are also
putting some of their money upfront in the development of
technologies.
But it is quite expensive, and any one entity trying to
push this forward by itself isn't going to be able to do it, so
it does need to be a partnership. We do need to have incentives
and funding to be able to progress technology, especially if we
are looking for it to progress in an expedient manner.
Mr. Dalton. One other point, I am not sure if you were here
for the testimony that I gave, but I mentioned that for a
current technology on the pulverized coal plant, adding capture
and storage might be an increase of 60 to 80 percent in the
whole cost of generation, and for an IGCC, possibly 40 to 50
percent.
Now, a lot of research, federal and private efforts, are
going toward reducing that cost, but right now, it is a very
significant cost. Now, that isn't all of the retail cost of
energy, obviously, but it could very significantly add, if it
is today's technology.
Mr. Hill. I would just like to reinforce a couple of
points. I think the government has a very important role to
play here to enable this technology to happen, and to happen
quickly, because time is of the essence, and the key ones, I
think, are regulations and policy, and the need for public/
private partnerships to co-invest and build these large,
integrated projects.
They are very large capital outlays, but for that, you get
very large reductions in emissions, and that is one of the
unique things about this. You get very large reductions in
emissions for one very large power plant. The downside is there
are large capital outlays, and that is why you need to have
this public/private partnership sharing the risk and sharing
the development of this technology.
Ms. Giffords. Chairman, if I can just follow up really
quickly, Mr. Hill, can you give us very specific examples where
public/private partnerships of this magnitude have been created
around other industries, and areas that we can possibly learn
from?
Mr. Hill. Well, I can give you a couple of examples where
we were doing that on technology R&D. We have, we formed a
public/private partnership, in fact, with the Department of
Energy, probably about six or seven years ago now, where we
really embarked upon a large program to develop new
breakthrough technologies to reduce the cost of capture, and to
prove that CO<INF>2</INF> could be stored safely. And that
involved eight different companies, the Department of Energy,
the European Commission, and the Norwegian government, who have
been working together over the last six years at developing
these technology, and it has now got us to the stage where we
are ready to deploy and really demonstrate that at scale.
And I think that is a great example of where these public/
private partnerships have got into action and produced some
really tangible results.
Mr. Rencheck. I would also offer that FutureGen is off to a
good start with public/private partnerships, and it also has an
international flavor, with participation from both the utility
companies, coal companies, as well as governments.
Ms. Giffords. Thank you, Mr. Chairman.
Chairman Lampson. You are welcome. Thanks, Ms. Giffords,
and now, I will recognize Mr. Wilson.
Carbon Capture for Coal to Liquids
Mr. Wilson. Thank you, Mr. Chairman. Gentleman, thank you
for being here today. I represent the State of Ohio, or Ohio's
Sixth Congressional District, which is coal country all along
the Ohio River.
We have some interesting things going on there, and I would
sort of like to present them to you, and be interested in your
comments. And the panel in general, not just a specific person.
But we have a coal to liquid plant being proposed by the
Baard Corporation, and it is going to be in Southern Columbiana
and Northern Jefferson County along the Ohio River, but again,
trying to tie together the Armed Services Contract, who will
take the fuel for jet fuel, and be able to marry the two
together, so that the fuel that is produced will have an
automatic market for it. And again, trying to protect the
investors, because we are looking at this thing long-term, not
just something that if oil happens to hit $35 a barrel, we
would have to be able to secure that investment.
That is one thing we are hearing. Another one of the
concerns--and we are very excited about that, I might add--we
also have a new coal-fired electric plant, a couple of them in
play right now, and we have a couple of retrofits that AEP are
doing along this Ohio River corridor.
The question or, to me, at least, the focus should be
politically, or from the government, I should say, that if oil
is the numbers that Congressman Costello said, which are just
hugely different in what the coal can produce, it would seem to
me that it would be wise to focus on the research and
development of this at this point. It would be a much less
expensive process than to continue sort of bantering around,
for lack of a better term, but I am not sure, as a new
Congressman, how we do that.
So, I am not sure that you have all the answers to those
questions, but the other thing I am hearing is sort of a mixed
message on how we do the sequestration. One of them is, in one
of my areas, we have a new process called Powerspan, that has
been put in, and they have drilled a 9,000 foot hole in
Shadyside, Ohio there at the Burger Plant, to do sequestration,
and my understanding is that the hole gets smaller as it gets
deeper. I missed the first part, as far as pipeline, and I
believe, Mr. Chairman, what we were saying is that this could
be piped off into other areas. It doesn't have to be
sequestered right onsite. Is that what I am hearing there?
The second thing, in ways of doing, or capturing the
CO<INF>2</INF>, was that of the algae process, and my
understanding in dealing there with the people at the Voinovich
Center at Ohio University, we are talking about the algae being
applied to, at least this is my understanding of it, large
sheets of it, if you will, and then, the carbon would be
captured, and could somehow be reused, then, as a coke in
producing steel. So, just some of those thoughts, if perhaps
you could help me get some clarity on those. Mr. Rencheck.
Mr. Rencheck. We are trying to develop an IGCC plant in
Meigs County, Ohio, and had applied for, instead of tax
credits, the incentive tax credits were only enough to cover
two facilities. Two facilities won't be enough to keep the IGCC
technology advancing. We need to have more funding in that area
to be able to advance those plants.
As far as the Powerspan technology, it is very similar in
the type of technology that is being produced by Alstom, who we
have teamed with. It uses a chilled ammonia process for
capturing CO<INF>2</INF>. With the hope of the chilled ammonia
process, it would reduce the overall power requirements of the
plant, where Stu had said, upwards of 30 percent. Again, we are
hoping to get it to a power penalty of around 10 to 15 percent,
so it would advance that. And funding is needed to move these
projects forward as well, if we are expecting to do this in a
timely manner.
Mr. Dalton. Just to add, EPRI has also been working with
the First Energy and Powerspan organization on their past work
at the plant, and are involved in the planning for the next
phase. This, again, is part of the regional partnership's work
for injection of CO<INF>2</INF> at the Burger station. We think
that there are a number of promising technologies. When we did
a recent screening, we came up with about three dozen different
promising technologies, and I am sure we didn't cover them all.
There are some that are still at different stages of
development.
This is an area where we think in parallel, not in the
normal sequential arrangement of first you do the very small-
scale work, then you do the pilot, then you do the large-scale
up, we are going to have to work on multiple technologies at
the same time, with an aggressive R&D effort, and we have been
putting together some of these different plans for different
technologies. I have in my hand one that is called CoalFleet,
we have a program called that, RD&D, Augmentation Plan for
Integrated Gasification Combined Cycle Power Plants. This has
been put in the public domain. We have others that we have been
working on for combustion. We believe that there are lots of
things that need to be pressed right now, and pressed rapidly,
as a public/private partnership.
Mr. Rencheck. As part of a regional partnership, we have
also drilled a 9,000 foot hole, just further down the Ohio
River on the West Virginia side, being able to inject in both
of those locations will give us a very good understanding of
the rock formations and the capability in the area, in the
regional area, of being able to sequester and store
CO<INF>2</INF>. So, we are looking to progress both of these
projects as part of the regional partnership.
Mr. Hill. One of the things, I think your other question
was focusing on R&D, and how you get actually things done at
this scale. One of the things I can share with this hearing is
what is being done in Europe, and the European Commission have
set up a technology platform for zero-emissions power.
And I think two key things have come out of that, well,
probably three key things have come out of that. One is a
strategic research agenda, identifying all the research that is
required. The second one, I think, is probably the most key,
and that is a deployment strategy. What needs to get done to
enable this to be in place and actually happening at commercial
scale by a certain date? And the third one is setting a time
when this will happen. And President Barroso, in the recent
energy announcement, in fact, earlier this year, announced that
by 2020, their plan is to have all fossil fuel power plants to
require carbon capture and storage. Otherwise, they won't be
permitted.
So, I think that was, and I mentioned this in my statement,
I think it is really important to have a plan and a target, and
a research and deployment strategy to enable you to achieve
that objective. And one of the things the platform in Europe
has done is brought together government, industry, utilities,
all sectors of the industry, as well as equipment suppliers,
academics and engineers, to work with us together, given that
context and the goals that have been set.
Mr. Rencheck. Not deploying further coal generation would
inhibit and retard the ability to make that generation more
efficient over time. As Mr. Dalton said, working the
technologies in parallel will help us to get to the end
solution faster. And as an example, in IGCC technology, its
first commercial plants will occur with AEP and with,
potentially, Duke Energy in Florida at a 600-megawatt level.
They have not been built yet in the States. Not to continue
developing that will slow the development of the gasification
process technology, as it integrates with the combustion
turbine process.
Mr. Bauer. If I may, Mr. Chairman. I know your red light is
on, but----
Chairman Lampson. Go ahead.
Mr. Bauer. The DOE has had a plan, a roadmap, to go forward
on these various challenges, and that is part of what the
budget is based on. Of course, within the limited confines of
funding availability, we have to make decisions, but the
program both develops technologies for efficiency, as well as
carbon capture, many of the things that were talked about, and
have all been funded through the DOE. And the Powerspan
technologies is in action, an NETL patent that was licensed to
Powerspan.
On the algae issue, there are multiple ways to capture, and
I think part of the things you are hearing, Congressman, are
that there are multiple pathways forward, and our funding level
constraint for parallel production is part of what is slowing
the process down. So, going back to what my friends here are
saying, trying to do things in parallel costs more
instantaneously than doing things in series.
Chairman Lampson. Will you help us push for that additional
funding?
Mr. Bauer. I will do what I can do.
Mr. Wilson. Thank you, gentlemen. Thank you, Mr. Chairman.
Efficiency
Chairman Lampson. You are welcome. Thank you.
I have a number of questions, and if you all will keep your
answers as short as you possibly can, I might be able to make
it through all of them.
Mr. Bauer, how high do you believe the alternative
combustion technologies DOE is researching, like oxy-
combustion, can push the efficiency of coal, energy efficiency
of coal?
Mr. Bauer. I think the issue on the oxy-combustion is we
can get to several percentage points more efficiency. So,
presently, the advanced power pulverized coal plants and IGCCs
are equivalent in efficiency. I think with oxy-combustion, with
some improvements in IGCC, they will both be in the 40 percent
plus range over the next several decades. The thing that oxy-
combustion provides is to the savings on the capture side,
because now, then you have a higher concentration of CO<INF>2</INF>
to capture from a pulverized coal unit, which is one of the
advantages the IGCC has. They have a higher concentration of
CO<INF>2</INF> in their stream. So, that begins to level those
issues, as far as the price of operation.
Chairman Lampson. What progress has your Advanced Turbine
Program demonstrated over the last ten years, and how close are
these technologies to commercial scale application?
Mr. Bauer. I am going to ask Dr. Strakey to speak up,
because that is his domain.
Mr. Strakey. I think the Advanced Turbine Program has made
some remarkable progress. Originally, it was directed towards
natural gas, and resulted in the H-class turbines, which are
the most efficient, largest machines that are now being
demonstrated at multiple sites around the world.
What we are trying to do in the coal program is take that
same kind of technology, and adapt it for burning hydrogen,
which is what you would have in a zero-emission plant. We are
at some of the early stages of this work, and we hope to test
some of that technology in FutureGen and other sites as well.
Chairman Lampson. How close to commercial scale
application?
Mr. Strakey. Well, you can do it commercially now, but you
will take a hit in terms of efficiency and emissions. So, the
problem is how do you get back the couple points of efficiency
that you would lose, and keep NOX emissions very low, in the
parts per million, couple parts per million range, so these
plants can be sited anywhere in the U.S.
Chairman Lampson. Thank you. Mr. Rencheck, pulverized coal
plants can achieve very high efficiencies with supercritical or
ultrasupercritical steam pressures and temperatures that can
reach 1,400 degrees Fahrenheit. You mention AEP's lead on
development and deployment of more efficient coal power plants.
I understand these extreme conditions can cause problems for
the materials used in the power plants.
Who is conducting the primary research in these areas?
Could you explain some of those material issues? Is there
sufficient investment in these advanced technologies, either
from the federal or private?
Mr. Rencheck. The easiest way to explain it, an existing
subcritical plant metallurgy, if you take it to the
ultrasupercritical level that we are building right now, at a
little over 1,100 degrees, the piping system that would
normally last 75 years, in a supercritical plant would probably
last about two. So, the metallurgy advancements to get the
1,400 degrees take quite a bit more research and development.
It is primarily being pursued in Europe and Asia at this point
in time, with a little funding in the U.S. It does need
additional funding to be able to advance the metallurgies and
technologies forward. There is some work going on with U.S.
companies at this point, but it is not at a level that would
advance it in the near-term.
Chairman Lampson. Mr. Dalton.
Mr. Dalton. I might add, under the sponsorship over the
last about six years from the U.S. Department of Energy, the
Ohio Coal Development Office and, with a team that includes the
major U.S. boiler and now, turbine manufacturers, as well as
specialists in EPRI as part of that team, and actually leads
some of the technical work, we have been looking at some of
those, at more advanced materials. There are very few
materials, they also tend to be extremely high alloy, meaning
high nickel, and for the same reason that we have taken the
nickel out of the nickel in the U.S., it has gotten very
expensive, it is very expensive for some of the alloy materials
that are being used worldwide.
And this could significantly increase the cost, limit the
number of alloys that could be used, so what we are looking at
is the design methodologies, the tests in the field, and right
now, there is not enough to bring that to the full-scale
demonstration and deployment stage. We are really limited to
the materials work in the work that we are conducting right now
with DOE.
Mr. Rencheck. And I would just like to add, the vintage,
where we are looking to build here over the next several years,
are already operating in Germany and Japan. We are behind.
Chairman Lampson. Mr. Dalton, in your testimony, you state
that the significant energy consumption required by CO<INF>2</INF>
separation processes and other emissions technologies can
reduce a plant's electrical output by as much as 30 percent.
Are there technologies that bring about enough production
efficiencies so that the output losses from CO<INF>2</INF>
separation are offset?
Mr. Dalton. The technologies for capture will almost always
use a significant amount of energy. However, with the
advancements of efficiency, through things like we were just
talking about in the ultrasupercritical designs, the H turbine
design, as one example, the ion transport membrane for oxygen
separation, put these things together, and you get a more
efficient front end, if you will, and a less parasitic load, or
a less consumptive load on the back end. The overall, we
believe, can mean that in 15, 20 years, you are back up to
higher efficiencies again. But there is some consumptive use.
Mr. Rencheck. I would like to make one point, as a retrofit
on an existing plant, there are steam requirements for the
existing technology that can get to the point where the plant
physically won't work, and looking at some of our existing
fleet, we believe we can only get enough steam off the steam
cycle to capture a maximum of 50 percent carbon.
Chairman Lampson. Thank you. Would the work that Rick
Smalley was doing at Rice University on carbon nanotechnology
be--are you familiar at all?
Mr. Dalton. There again, there are at least three dozen new
processes. Some of them propose very low energy use or using
other forms of energy, such as the algal growth, which uses
solar energy as part of the overall energy balance.
Chairman Lampson. Thank you all. You did good. Ranking
Member Inglis, it is your turn.
Basic Organic Chemistry
Mr. Inglis. Thank you, Mr. Chairman. You know, necessity is
the mother of invention, but it is also true that invention is
propelled by a can-do spirit, and the neat thing about being
here and hearing you testify is it is obvious that you are out
there trying to solve these things, and so, we are very
fortunate to have people like you doing what you are doing.
And maybe now you can explain to me the chemistry of carbon
as said earlier I need to understand the science a little bit
better. And maybe it would help me to have somebody tell me why
it is that apparently, carbon wants to hook up with oxygen,
right, and to get it to unhook, it takes some energy. But it
must be possible to hook it with something else, to make it so
that it isn't necessary to sequester it, or is it? I mean, is
anybody working on something that would cause it to hook with
something else, or is there nothing else that it likes to dance
with?
Mr. Bauer. Well, as you said, Congressman, carbon and
oxygen seem to like each other. H<INF>2</INF>O, of course, is
hydrogen and oxygen, but given the choice, more energy is
released going to carbon dioxide than water, so in fact,
shifting the gasification reaction to make more hydrogen, we
pass steam through the system, and it hooks up with carbon
monoxide, CO, to form water, I mean, to release hydrogen and
have more oxygen and carbon combining, so the problem is that
it is a lower state of energy required to have that bond of
CO<INF>2</INF>, so therefore, it is very hard to break it apart
once it is joined.
It is possible, and in fact, some people are looking at
taking CO<INF>2</INF>, and using it to reverse the process,
which will take energy, but if the economics are right, because
of the pain of CO<INF>2</INF> in the world, you could possibly
make a Fischer-Tropsch fuel out of that. That doesn't make
sense in our present economy, because of the energy burden, but
in the future, it may make sense, because the problem of
CO<INF>2</INF> could be so great that the economics drive it
the other way.
Mr. Inglis. In which case, the carbon itself has some
value, if you could isolate it.
Mr. Bauer. Yes, most of our fuel, and many other things
that we use, carbon is an essential component of it.
Mr. Inglis. Right.
Mr. Bauer. Even biomass is basically because of its carbon
value that we use it.
Carbon Capture
Mr. Inglis. So now, maybe somebody can explain to me the
thing that, I heard a presentation, and I didn't get it. So,
maybe you can help me understand it, about how it is that, how
pre-combustion CO<INF>2</INF> capture works.
Mr. Rencheck. The bottom line is the, in the gasification
process, you are taking coal, and you are not oxidizing it or
burning it. It is more like it is smoldering, and with that, it
produces a gas. The gas is primarily carbon monoxide and water,
and it is under pressure, so it is a pressurized gas stream.
The way you would do that, then, is as syngas goes forward, you
shift it, and when you shift it through a Fischer-Tropsch
process, it creates basically hydrogen and CO<INF>2</INF> in a
pure stream. That CO<INF>2</INF> stream is pressurized already,
so now, to pump it in the ground takes a lot less energy to
store it. And then, the hydrogen is used in the combustion
turbine to generate electricity.
Mr. Dalton. Let me try one other analogy. If I had a pretty
good sized power plant, and I made this gas, I take a little
bit of oxygen, not enough to burn it, but a little bit, I react
it, I make something that looks like obsidian, volcanic glass,
and it is inert. In the process, I make some hydrogen. The gas
is under pressure, and it is high in concentration. I can
literally put my arms around it, the size of a duct. However,
at the back end of a power plant, the duct is more like the
size of this room. It is very, very large, and you can just
think it takes more equipment to literally get your arms around
it. It is a much smaller, more compact, cheaper process to
capture it in this pre-combustion, at pressure, with a higher
concentration of CO<INF>2</INF>, than it is to capture it
afterwards. But do you want your chemical plant in front or in
back, because they are both really chemical plants.
Mr. Rencheck. And in the back process, it is basically at
atmosphere conditions, and in the combined cycle process, it is
compressed down at over 200 pounds, well over 200 pounds.
Mr. Inglis. Mr. Hill, did you want to add something to
that?
Mr. Hill. Yeah, I was just going to say the same thing from
a different perspective. I mean, so pulse combustion is
basically you burn the fossil fuels, and you have the exhaust
gas, and you have to strip out the CO<INF>2</INF> from the
exhaust gas, and the challenge is the CO<INF>2</INF> might only
be a small part of that exhaust gas. It might 10 to 13 percent,
if it is coal, or maybe three or five percent if it is gas, so
you have got a huge volume, and you are trying to just pick out
this 13 or three percent of CO<INF>2</INF>. That is why that is
quite tricky and quite expensive.
Pre-combustion is quite interesting, because pre-combustion
is basically you are taking, you are developing a conversion
process. You are converting gas, or you are converting a fossil
fuel, putting it through a chemical conversion process to get
some other state for that fossil you. And if you shift it the
whole way by using steam, you get, eventually, CO<INF>2</INF>
and hydrogen. But at other stages, there are other chemicals
you can get before you get to the CO<INF>2</INF> and hydrogen,
so it is quite a flexible technology. You could produce syngas,
which you could actually put in the gas distribution system.
You could produce other chemicals for chemical processing, as
well as also making hydrogen for power.
So, pre-combustion is like a conversion process of fossil
fuels to some other chemical state you would like that fossil
fuel in. That does take a lot of energy, and the challenge is
how you do that in the most cost-effective and efficient way.
Mr. Inglis. And I assume the economics of that aren't quite
there at this point. Is that right, or is that--how far away
are we from the economics working on that sort of thing?
Mr. Bauer. Well, I think as both Stu and I have suggested,
that with gasification, we are looking at 30 percent increase
in the cost of electricity, so that gives you a sense of the
economics. With an existing power plant, or even a brand new
pulverized coal plant, not oxy-combustion, because the
advantage of the oxy is you have a higher concentration of
CO<INF>2</INF> again, because you don't put all the nitrogen in
the rest of the air, and nitrogen is 70 percent of air.
So, that is like 50 to 70 percent, depending on the design
of the plant, the substantial increase in the cost of
electricity. And I think what is important to realize is that
electricity is a low value product, and that is dispatches,
whoever has the lowest price sells it, so for someone like AEP
to make an investment on a plant that they couldn't dispatch
early and recover costs, is a prohibitive hurdle to get over on
their part, and that is part of the real issue on trying to
move forward on this.
Mr. Rencheck. I would just like to add as well, in the
combustion process for oxy, coal, and IGCC, one of the biggest
cost drivers or inefficiencies of that plant is actually making
the oxygen for partial combustion. If you have to take air and
separate the nitrogen and the oxygen, you run it through these
gigantic compressors, some of which have 45,000 horsepower
motors, bigger than probably the size of this room, you
actually have to make sure your grid is reinforced, just so you
can start these things. They are massive pieces of equipment,
where some of the R&D work that Carl was talking about, with
membrane technology, that could separate the air into nitrogen
and oxygen, would make that process much more efficient, and
much more economical over time.
Mr. Inglis. Thank you.
Chairman Lampson. The Chair recognizes Mr. Udall.
H.R. 1933, the Department of Energy Carbon Capture and Storage
Research, Development, and Demonstration Act
Mr. Udall. Thank you, Mr. Chairman. I want to thank all you
witnesses for being here. This is a really important and very
interesting, it goes without saying, and just having been here
a few minutes, it is clear that carbon capture and storage
technology has real promise, particularly when it comes to
utilizing these vast coal reserves that we have.
The DOE, as you know, has been researching this
opportunity, I like to think of it in that regard, through its
R&D program, but I think that Congress could do more to move
the technology forward, and to that, I have recently introduced
a piece of legislation, H.R. 1933, entitled the Department of
Energy Carbon Capture and Storage Research Development Act, and
what I would like to do is ask you, Mr. Bauer, starting with
you, if you think this approach would help validate the
technology, and move it towards commercialization.
I would, as you begin to speak, that Senator Bingaman has
introduced a companion bill in the Senate, and there was a
recent hearing that I am referencing with my question.
Mr. Bauer. Thank you, Congressman. I am familiar with 1933,
and Senate 962, which are companion bills, and I think both
bills provide a great deal of opportunity and are very positive
towards dealing with these issues. I appreciate the recognition
in the bill of the cost severity of trying to pursue this,
which in the Energy Policy Act of 2005, has lower numbers, but
this is a substantial problem, and so, the increase that you
have recognized in the numbers are very good, the recognition
of the regional partnership and the contribution they are able
to make, I think is essential for us moving forward.
We have done a competitive process with both academia and
environmental agencies, State agencies, and other agencies of
the government, National Labs, and these regional partnerships
have formed around that, and they have moved forward, and we
are about to go into the phase of a million ton per year seven
projects. I think you referenced that in the bill, and that is
very exciting. So, overall, I think both bills provide the
opportunity to move more rapidly and aggressively to overcome
this challenge, and truly make it an opportunity.
Mr. Udall. If anybody else on the panel would like to
respond, I would welcome your thoughts.
Dr. Finley. I think 1933 also addresses that issue, and I
would like to echo the sentiments that Mr. Bauer indicated. I
think it is really important now that we move forward with the
large-scale aspect of this, and that takes additional funding.
The equipment, for example, even for a modest so-called large-
scale test, 1,000 ton a day test, we need alone perhaps $12 to
$14 million to install the equipment, large compressors that
are very difficult to obtain. In fact, there is almost a year
lead time just to order that equipment.
So, I think funding of this effort is extremely important.
I think where there is a much greater recognition, as a result
of the three IPCC reports that have come out since February,
and I commend the effort to move this forward, particularly at
the large scale, and to fund those efforts at that larger
scale.
Mr. Udall. Anyone else on the panel, or Mr. Bauer, do you
want another----
Mr. Bauer. Yeah, I just wanted to add one other thing. I am
trying to recall the many things in looking at the bill.
Mr. Udall. Sure.
Mr. Bauer. And I am hoping I am not going to be out of turn
in saying this, sir, but to do these projects is going to take
more than three years, and I am sure you realize that and
understand the process, but I didn't want to be remiss in
suggesting that this would be the end of the story. I wish it
would be, but it is probably seven to ten years, depending on
how successful we are, to get to the end.
Mr. Udall. Well, we are here to improve the legislation
that has been proposed, and that makes complete sense that
three years is not the only length of time we should be
considering. Anybody else on the panel? Mr. Dalton.
Mr. Dalton. While I am not commenting on the bill itself, I
would point out that capture is one of the big costs. It is
almost as if you can look at two big issues, the cost in energy
use of capture, and the effectiveness and assurance that you
have storage well in hand. Those are the two big issues, and
putting them together is one of the things that we think is
very important as well. It is well enough to say that yes, I
can, the car will perform this way, and the tires will perform
that way, but you really do want to test them together. And in
this case, I think that we want to make sure that large-scale
capture and transport and storage are operated together, to
make sure that there is good ability to do that, and operate
the system that includes point-to-point transport, storage, as
well as capture.
Mr. Udall. Excellent point. Mr. Hill, and then we will come
back to Mr. Rencheck.
Mr. Hill. Yes, I just want to reinforce that point. One of
the things that BP has been very active over the last three or
four years, is actually studying in a great deal of depth the
integration of capture and storage systems. Through the two
projects we have proposed, one in Peterhead in Scotland, and
the other one at Carson in Long Beach, California.
And one of the key things we are learning is once we do
this detailed work, is the integration of the various
components of the overall process, in a way that will have a
high degree of efficiency and a high degree of operability. So,
I think there is only so much you can do by looking at
individual components, and there really is a need now to build
these very large-scale, integrated, commercial scale project to
prove the integration of the various components, the
operability, and the overall cost, and we will only discover it
when we actually build them, and get really experienced, and I
think that is the next step for us to take.
Mr. Udall. Mr. Chairman, I see my time has expired. Is
there time for Mr. Rencheck, or will we have another round,
whatever works?
Mr. Rencheck. We have provided projects that we are
undertaking, and it will take it to scale, but as we talk about
that, we need to also advance the combustion process and the
pre-combustion process through ultrasupercritical technology or
IGCC technology in addition to post-capture or capture and
storage as well. Doing one without the other only thwarts the
technology advancement going into the future.
More on Carbon Sequestration Risks
Mr. Udall. These are very important points. Mr. Chairman, I
had a couple other questions. I could submit them for the
record, or I can direct them to the witnesses, depending on
your timeframe.
If I could, and if you all discussed this before I arrived,
what is the probability of the carbon release from geological
storage sites, and what research and data are available to
understand the environmental and human health and safety risks,
and are there well established risk assessment methodologies
for geological storage of CO<INF>2</INF>? Easy questions, I am
sure, given the smiles I see on people's faces, and I think Mr.
Hill, Dr. Finley, and finely, and Mr. Bauer, you all have some
qualifications to speak to. Dr. Finley, I am sorry, I have got,
I see it is finely here and Finley here, so you correct me.
Dr. Finley. That is correct. Well, that is an extremely
important issue, and it is, in fact, one that DOE has funded
work. The National Labs, Lawrence Livermore and Lawrence
Berkeley, have both been working on this for some time,
independent of the Regional Carbon Sequestration Partnerships.
We are in the process of uptaking some of that knowledge into
our partnership.
I think you have to make the distinction between the so-
called catastrophic release that is often cited in the press,
the Lake Nyos example, I mean, I don't think we would decide to
put CO<INF>2</INF>, inject CO<INF>2</INF> beneath a volcanic
lake, which is a high risk situation, obviously, and in this
case, it was natural CO<INF>2</INF>, in any event.
The risks are just beginning to be quantified. There is a
lot of detail work now beginning to look at this, especially as
we move forward with the large-scale injections per se.
CO<INF>2</INF> is not flammable, it is not poisonous, but yet,
you don't want to fill a room up with it, and walk into the
room, and not move out. So, basically, you don't want it coming
up, obviously, in people's basements and so forth.
My feeling as a geologist is that the risk, there is the
natural risk posed by the geology itself, and then, there is a
risk posed by the facilities, such as wells. I think the risk,
if we carefully site these projects, and we assess the geology
extremely carefully, with geophysics and seismic, look to make
sure there are no faults or fracture zones, I think that risk
is relatively low.
I think the larger risk, as we get many, many of these
projects, is to make sure that the manmade infrastructure, the
wells, pipelines, compressors, and so forth are done with the
utmost care.
Mr. Udall. Mr. Chairman, perhaps given the votes that have
been called, we could submit the rest of the, others could
have, on the panel, a chance to submit their answers for the
record. And I have some additional questions I would like to
submit for the record as well.
Chairman Lampson. Without objection, you may do so.
We want to thank all of you for appearing before the
Subcommittee this afternoon. And under the rules of our
committee, the record will be held open for two weeks for
Members to submit additional statements and any additional
questions that they might have for the witnesses.
And this hearing is now adjourned. Thank you.
[Whereupon, at 2:50 p.m., the Subcommittee was adjourned.]
Appendix 1:
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Answers to Post-Hearing Questions
<SKIP PAGES = 000>
Answers to Post-Hearing Questions
Responses by Carl O. Bauer, Director, National Energy Technology
Laboratory, U.S. Department of Energy
Questions submitted by Chairman Nick Lampson
Q1. Because the existing fleet of coal-fired power plants generate
over 50 percent of the Nation's electricity and are one of the major
emitters of greenhouse gases and other pollutants like mercury, how
much funding will be dedicated to retrofitting the existing fleet to
operate more cleanly and more efficiently in Fiscal Year 2008? How does
this amount compare to the funds allocated to develop more efficient
technologies for coal generating power plants in Fiscal Year 2007?
Could you please elaborate on the specific efficiency retrofitting
projects prioritized by the Department of Energy?
A1. The Innovations for Existing Plants (IEP) program supported
technology development for criteria pollutant control technologies
retrofits to existing conventional power plants, in anticipation of
regulatory limits that are now being implemented through the Clean Air
Interstate Rule and the Clean Air Mercury Rule. Because the industry
now has strong regulatory drivers to complete the development on their
own and commercially deploy such technologies, the IEP program is
terminated. However, several programs are funded in the FY 2008 that
target retrofit technologies for carbon capture, or that target
technologies for new plants, but are also applicable to retrofit
applications. In FY 2008, the Department plans to issue a Clean Coal
Power Initiative (CCPI) Round 3 solicitation that would provide the
opportunity for proposing projects to retrofit carbon capture
technology, with ultra low emissions, such as mercury capture, to
existing plants. However, since the selections require a competitive
process it is not yet known how much will be awarded for retrofits. In
FY 2007, the focus of the $414M coal R&D program is on the development
of cleaner, more efficient technologies for coal generating power
plants, and carbon sequestration. In each of the years FY 2007 and FY
2008 approximately $7M is being allocated to Advanced Research
Materials to improve the efficiency of new and existing plants. The
carbon sequestration program also funds development of post-combustion
carbon capture technologies that could be applied as retrofits.
Q2. A 2007 interdisciplinary MIT Study ``The Future of Coal'' states
that ``It is critical that the government RD&D program not fall in the
trap of picking a technology ``winner'' especially at a time when there
is great coal combustion and conversion development activity underway
in the private sector in both the United States and abroad.'' IGCC has
received extensive DOE support through grants and FutureGen funding.
What is the Department doing to advance oxyfuel technology, given that
it can be used on all coal types on both existing and new plants and
could be deployed soon?
A2. DOE does not pick technology winners. Rather, in response to
environmental drivers such as climate change, the Department's research
programs provide a portfolio of technology options that could be
applicable under a variety of future regulatory and/or policy
scenarios. This allows the marketplace, once regulations have been
promulgated, to determine the most appropriate technologies for
commercial deployment, based on performance and cost. Integrated
gasification combined cycle (IGCC) technology is an important option
being developed by DOE, applicable to a wide range of coal types. For
example, the Department's Clean Coal Power Initiative includes a 285
MWe IGCC project to demonstrate technologies capable of major
efficiency gains for low-rank, high-moisture, high-ash coals. Oxyfuel
or oxy-combustion technology also is being investigated and DOE has
several projects underway in this area.
Q3. The DOE National Energy Technology Laboratory in Albany, Oregon
has developed the Integrated Pollutant Removal (IPR) technology. It is
my understanding that tests show that when coupled with Oxyfuel, the
hybrid Oxyfuel/IPR system can remove 90 percent of the mercury, 99
percent of the sulfur, 99 percent of the particulate including 80
percent of the PM2.5, and NOX measured at the exit of the combustion
process was 0.088 lbs/MMBtu. I further understand that the Oxyfuel/IPR
system is also fully capture ready. Please explain any discrepancies
the Department may have with the information I provided on the IPR
system.
When does the Administration anticipate the IPR technology will
move forward from development to commercial deployment? Will the
Department need to dedicate additional funding to the IPR technology
before it is ready for commercial applications? To date, what level of
funding has been used for the Department's development of the IPR
technology?
A3. Results from bench-scale development and testing and preliminary
engineering analyses suggest that the IPR is a promising concept for
reducing emissions from coal-fired power plants. Based on bench testing
to date, Albany has achieved NOX combustion levels at the exit of the
combustion process of 0.088 lb/MMBtu; >99 percent of sulfur were
removal; and >99 percent removal of particulate matter. However, it
needs to be stressed that ``bench-scale'' results are not necessarily
an accurate prediction of commercial results. Coupled with oxyfuel
combustion to generate a more concentrated CO<INF>2</INF> flue gas, the
IPR concept is one of a number of advanced carbon capture technologies
being investigated under DOE's research program. As noted in your
question, NETL's Albany research laboratory has been supporting the
development of the IPR. Currently, through a Congressionally Directed
Project, Jupiter Oxygen Corporation has teamed with NETL to integrate
oxy-combustion with IPR at the Jupiter's test facilities in Hammond,
Indiana. The timing for commercial deployment of oxyfuel/IPR technology
is highly uncertain. It will be depend on the results from the Jupiter
effort, any follow-on pilot and larger field testing over which the DOE
program has some control; and on other factors outside the control of
DOE. Finally as with many of the advanced carbon capture technologies
the private sector also needs to resolve numerous issues before the
oxyfuel/IPR concept is considered a viable, cost-effective CO<INF>2</INF>
mitigation strategy. Because of all these uncertainties it is difficult
to predict whether the Department will need to dedicate additional
funding to the IPR technology before it is ready for commercial
applications. To date, $3 million has been spent for the Department's
development of the IPR technology.
Q4. Older natural gas fueled power plants built since 1950 surround
many cities and contribute to NOX and CO<INF>2</INF> pollution. Is it
possible to retrofit these older gas plants with oxyfuel technology and
if so, what would be the emissions reductions benefits? If the older
gas plants were retrofitted with oxyfuel technology what steps would be
necessary to provide for capture of the CO<INF>2</INF>? What are the
cost estimates for adding carbon capture technology to these
facilities? Is the Department exploring other technologies to reduce
emissions from gas fueled electric power plants?
A4. It might be possible to retrofit some older natural gas plants with
oxyfuel technology, and there might be emissions reductions benefits to
this approach. If gas plants were retrofitted with oxyfuel technology
the necessary steps would begin with a feasibility study and comparison
with alternative feasible alternatives. DOE has not performed cost
estimates for retrofitting older natural gas plants with oxyfuel
technology. The focus of DOE's carbon capture R&D effort is on
technology applicable to coal-based power systems. This is because
coal-fired power plants provide over half of the electricity generated
in the United States, and their significant contribution to the United
States' electricity grid is expected to continue through the better
part of this century. It is recognized, however, that CO<INF>2</INF> is
also emitted from other stationary fossil-fuel-combustion facilities,
including natural-gas-fired boilers. As such, it is expected that the
advanced post-combustion carbon capture technologies under development
as part of DOE's Carbon Sequestration Program will have application to
natural-gas-fueled power plants. Oxy-combustion is one such technology.
The technical and operations issues associated with oxyfuel combustion,
which DOE's R&D program is addressing, would be similar for a gas-fired
boiler as for a coal-fired boiler. An important technical challenge is
developing materials to withstand increased temperature in the furnace
resulting from burning the fuel (coal or natural gas) in an oxygen-rich
environment.
Flue gas recirculation is one approach being investigated to reduce
the temperature, another approach is the development of new materials
more resistant to high temperatures. Another critical issue associated
with oxy-combustion is obtaining a large supply of low-cost oxygen.
Current oxygen production systems, such as cryogenic, are prohibitively
expensive. This is another area of research under DOE's Carbon
Sequestration Program.
Appendix 2:
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Additional Material for the Record
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