U.S. GOVERNMENT PRINTING OFFICE

WASHINGTON : 

For sale by the Superintendent of Documents, U.S. Government Printing Office

Internet: bookstore.gpo.gov Phone: toll free (866) 512–1800; DC area (202) 512–1800

Fax: (202) 512–2104 Mail: Stop IDCC, Washington, DC 20402–0001

35–234PS 2008

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

(II)

COMMITTEE ON SCIENCE AND TECHNOLOGY

HON. BART GORDON, Tennessee, Chairman

JERRY F. COSTELLO, Illinois

EDDIE BERNICE JOHNSON, Texas

LYNN C. WOOLSEY, California

MARK UDALL, Colorado

DAVID WU, Oregon

BRIAN BAIRD, Washington

BRAD MILLER, North Carolina

DANIEL LIPINSKI, Illinois

NICK LAMPSON, Texas

GABRIELLE GIFFORDS, Arizona

JERRY MCNERNEY, California

PAUL KANJORSKI, Pennsylvania

DARLENE HOOLEY, Oregon

STEVEN R. ROTHMAN, New Jersey

MICHAEL M. HONDA, California

JIM MATHESON, Utah

MIKE ROSS, Arkansas

BEN CHANDLER, Kentucky

RUSS CARNAHAN, Missouri

CHARLIE MELANCON, Louisiana

BARON P. HILL, Indiana

HARRY E. MITCHELL, Arizona

CHARLES A. WILSON, Ohio

RALPH M. HALL, Texas

F. JAMES SENSENBRENNER JR.,

Wisconsin

LAMAR S. SMITH, Texas

DANA ROHRABACHER, California

ROSCOE G. BARTLETT, Maryland

VERNON J. EHLERS, Michigan

FRANK D. LUCAS, Oklahoma

JUDY BIGGERT, Illinois

W. TODD AKIN, Missouri

JO BONNER, Alabama

TOM FEENEY, Florida

RANDY NEUGEBAUER, Texas

BOB INGLIS, South Carolina

DAVID G. REICHERT, Washington

MICHAEL T. MCCAUL, Texas

MARIO DIAZ-BALART, Florida

PHIL GINGREY, Georgia

BRIAN P. BILBRAY, California

ADRIAN SMITH, Nebraska

VACANCY

SUBCOMMITTEE ON ENERGY AND ENVIRONMENT

HON. NICK LAMPSON, Texas, Chairman

JERRY F. COSTELLO, Illinois

LYNN C. WOOLSEY, California

DANIEL LIPINSKI, Illinois

GABRIELLE GIFFORDS, Arizona

JERRY MCNERNEY, California

MARK UDALL, Colorado

BRIAN BAIRD, Washington

PAUL KANJORSKI, Pennsylvania

BART GORDON, Tennessee

BOB INGLIS, South Carolina

ROSCOE G. BARTLETT, Maryland

JUDY BIGGERT, Illinois

W. TODD AKIN, Missouri

RANDY NEUGEBAUER, Texas

MICHAEL T. MCCAUL, Texas

MARIO DIAZ-BALART, Florida

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

(III)

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 CO2 .............................................................................................. 55

Western Regional Partnerships .......................................................................... 55

Funding Concerns ................................................................................................ 57

Page

IV

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

(1)

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.

2

3

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 CO2 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 CO2 Capture and Storage

technology development, demonstration and deployment. He also is the BP

manager responsible for the BP/Ford/Princeton Carbon Mitigation Initiative

4

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 CO2 is emitted as a result of the combustion of fossil fuels. In particular, the electric power sector accounts for 40 percent

of the CO2 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 coalfired plants (through replacement with new plants or retrofitting existing plants)

and through installation of carbon capture technology and transporting CO2 to a

permanent storage facility.

CO2 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 CO2 for capture. Currently, there are three main approaches to capture

CO2 from large-scale industrial facilities or power plants: 1) post-combustion capture, 2) pre-combustion capture, and 3) oxy-fuel combustion capture.

Post-combustion capture process, although not required, involves extracting CO2

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 CO2 from the fuel by combining it with air and/

or steam to produce hydrogen for combustion and CO2 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 CO2 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 CO2 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.

CO2 Sequestration

Geologic sequestration of CO2 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 CO2 is injected below 800 meters in a typical reservoir, the pressure induces CO2 to behave like a relatively dense liquid. This state is known as ‘‘supercritical.’’ With each of the three methods listed above, CO2 would be injected into

reservoirs that hold, or previously held liquids or gases. In addition, injecting CO2

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 CO2 into oil and gas reservoirs to boost production, a process known as

enhanced oil recovery (EOR) is practiced by the petroleum industry today. Using

5

EOR for long-term CO2 storage is beneficial because sequestration costs can be partially offset by revenues from oil and gas production. However, the primary purpose

of CO2 for EOR was not intended to serve the need for long-term sequestration of

CO2 and the degree to which injected CO2 remains in the reservoir in many areas

utilizing EOR is unknown.

Depleted or abandoned oil and gas fields are potential candidates for CO2 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 CO2

within these reservoirs.

Still, there are concerns with using oil and gas reservoirs for CO2 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

CO2 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 CO2 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 CO2 in a deep saline reservoir is the Sleipner Project in the North Sea. While deep saline reservoirs have

huge potential capacity to store CO2, there is concern about maintaining the integrity of the reservoir because of chemical reactions following CO2 injection. CO2 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 CO2 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. CO2 binds even more

tightly to coal than methane, thus making it possible to store the unwanted CO2

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 CO2 emissions from existing coal plants.

6

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 CO2. 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

CO2 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 CO2 emissions. I look forward to

learning more about the deployment of technologies that can capture CO2 from new and existing power plants and keep it out of

the atmosphere.

We must advance our technical ability to capture CO2 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 CO2 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 geologiVerDate 11-MAY-2000 19:17 Feb 09, 2008 Jkt 035234 PO 00000 Frm 00010 Fmt 6633 Sfmt 6621 C:\WORKD\E&E07\051507\35234 SCIENCE1 PsN: SCIENCE1
7

cal storage of CO2. 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 CO2 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 CO2 emissions. I look forward to learning more about the deployment of technologies that can capture CO2 from new and existing power plants and keep it out

of the atmosphere.

We must advance our technical ability to capture CO2 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

CO2 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 CO2 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:]

8

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 CO2 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

9

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.

10

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

CO2. The current facts store annual CO2 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 CO2, 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

CO2 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 CO2. 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-zeroemissions 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 CO2 in underground geoVerDate 11-MAY-2000 19:17 Feb 09, 2008 Jkt 035234 PO 00000 Frm 00014 Fmt 6633 Sfmt 6601 C:\WORKD\E&E07\051507\35234 SCIENCE1 PsN: SCIENCE1
11

logic formations with long-term stability, develop the ability to

monitor and verify the fate of the CO2, 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 coalfired power plants in meeting energy demand and possible future

carbon constraints. Research is being pursued to dramatically

lower the cost of capturing CO2 from these plants.

The FutureGen project is an industry/government partnership

designed to build and operate a gasification-based, nearly emissionfree, 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-zeroemission 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 costeffective technology options to meet our environmental goals, including the reduction of carbon dioxide (CO2) 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 CO2 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¥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 CO2. 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 CO2—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 CO2 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 CO2

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 comVerDate 11-MAY-2000 19:17 Feb 09, 2008 Jkt 035234 PO 00000 Frm 00015 Fmt 6633 Sfmt 6621 C:\WORKD\E&E07\051507\35234 SCIENCE1 PsN: SCIENCE1
12

mercially 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 CO2 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 CO2 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 CO2 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 NOΧ emissions.

13

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 NOΧ 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 CO2, the Advanced Turbines Program is investigating novel approaches for CO2 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 CO2 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 CO2 in underground geologic formations with long-term stability (permanence), to develop the ability to monitor and verify the fate of CO2, 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 CO2 emissions, 97 percent of industrial CO2 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 CO2 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 CO2 storage capacities, satisfying

project permitting requirements, and conducting public outreach and education activities.

14

Deployment, the third phase, involves large-volume injection tests. This phase

was initiated this fiscal year and will demonstrate CO2 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 CO2

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 CO2 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 CO2

in a deep saline formation. FutureGen is scheduled to operate from 2012 to 2016,

followed by a CO2 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—

• Advanced coal-fueled power generation and hydrogen production.

• Carbon sequestration.

• Environmental control for the existing fleet of fossil steam plants.

• 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

15

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 CO2 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 CO2 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 CO2 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

16

will hold the carbon dioxide in place, the caprock or the seals, as

we have to the rock into which the CO2 itself will be injected.

To be an effective climate change mitigation strategy, the CO2

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 CO2 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 CO2 will be injected.

With respect to the safety of established projects, we have been

injecting CO2 for enhanced oil recovery in reservoirs in West Texas

for more than two decades. Since 1983, more than 600 million tons

of pressurized CO2 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 CO2 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 CO2, 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 CO2

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:]

17

PREPARED STATEMENT OF ROBERT J. FINLEY

Understanding the capacity to geologically sequester carbon dioxide (CO2) 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 CO2 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 CO2 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 CO2 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 CO2 will be injected into. To be an effective climate change mitigation strategy, the CO2 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 CO2 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 CO2 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 CO2 for

enhanced oil recovery in West Texas for more than two decades. Since 1983, more

than 600 million tons of pressurized CO2 have been injected and 30 million tons are

currently being injected annually in West Texas oil reservoirs. The safety record of

18

this process has been excellent with not a single incident of loss of life. The injection

of CO2 for sequestration beneath the seabed of the North Sea has been taking place

since 1996, and based on published reports, the CO2 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 CO2, 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 CO2 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 CO2 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 nuVerDate 11-MAY-2000 19:17 Feb 09, 2008 Jkt 035234 PO 00000 Frm 00022 Fmt 6633 Sfmt 6621 C:\WORKD\E&E07\051507\35234 SCIENCE1 PsN: SCIENCE1
19

merous 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 coalfired 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-ofthe-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 CO2 per year, which will be used

for enhanced oil recovery.

We are also working with Babcock and Wilcox to develop its oxycoal combustion technology, through development of a 30-megawatt

thermal pilot plant at its Barberton, Ohio facility in 2007. Oxy-coal

combustion forms a concentrated CO2 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.

20

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-supercritical 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 CO2 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.

21

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 CO2 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 capand-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 ultrasuper-critical power plants. 1n addition, we are a founding member of FutureGen,

a ground-breaking public-private collaboration that aims squarely at making nearzero-emissions coal-based energy a reality. Simply put, however, commercially engineered and available technology to capture and store CO2 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 ultrasuper-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., ultrasuper-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 CO2 emitting commercial scale coal-fueled

power plant. We are also working to progress specific carbon capture and storage

technology.

22

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 (CO2) per

year. Once the CO2 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 CO2 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 CO2 per

year and be operational in late 2011. The CO2 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 CO2 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 CO2 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-andtrade 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.

23

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 CO2 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. CO2 capture requires a large volume of steam to regenerate the amine used

to capture the CO2. 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 CO2, 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 CO2 for

sequestration.

Our IGCC plants will be among the earliest, if not the first, deployments of largescale 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.

24

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 CO2. 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 CO2 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 CO2 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 humaninduced 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 CO2. 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 CO2 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 CO2 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 CO2 storage as one reason they are disinclined to insure early

projects. In a nutshell, the institutional infrastructure to support CO2 storage does

not yet exist and will require time to develop. In addition, application of today’s CO2

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 CO2

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

25

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 °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 °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 °F to 1050 °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 coalbased 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 coalfueled 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 longterm 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.

26

27

28

29

30

31

32

33

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 CO2

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.

CO2 capture and storage, which we have talked about, will be an

important CO2 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 CO2 to prove effectiveness. And

finally, policy and research needs to match this accelerated approach to efficiency enhancements, CO2 capture and storage.

To expand on these briefly, recent analytical work by EPRI estimates that in order to significantly reduce CO2 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 CO2 capture and storage as a major part of the overall

CO2 reduction program.

34

Existing and new plants can improve efficiency, and reduce CO2

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 CO2 reductions of up to 20 percent per megawatt-hour

without additional CO2 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 CO2 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 CO2 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, TenVerDate 11-MAY-2000 19:17 Feb 09, 2008 Jkt 035234 PO 00000 Frm 00038 Fmt 6633 Sfmt 6621 C:\WORKD\E&E07\051507\35234 SCIENCE1 PsN: SCIENCE1
35

nessee. 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 (CO2) emissions from power

plants that use coal as an energy source through both efficiency gains and CO2 capture and sequestration (2) policy and research gaps where we believe the federal

government can do more to facilitate the reduction of CO2 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 CO2, coal presents a greater challenge to

achieving reduced greenhouse gas emissions.

Technologies to reduce CO2 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 CO2 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 CO2 emissions from coal power plants. These needs

can be described in three major aspects:

• Substantially increased thermodynamic efficiency of coal plants

• Cost-effective, efficient, commercially available technologies for capture of

CO2 from coal plants

• Cost-effective, commercially available technologies for storage of captured CO2

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

36

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

CO2 regulations (and efforts by power producers to demonstrate voluntary CO2 re- ductions), 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°F to an ‘‘advanced’’ ultra-super-critical steam temperature of 1400°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 CO2

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 CO2 production and coal

use). If capture of the remaining CO2 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°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 CO2 capture.

A number of technologies are being developed that promise to decrease the

amount of CO2 per unit of power produced (e.g., pounds CO2/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 CO2/kWh. Neither achieves

CO2 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.

CO2 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 CO2 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 CO2 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

37

recent EPRI study (report 1014510 available publicly) shows PC with CO2 capture

as competitive with IGCC with CO2 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 CO2 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 CO2 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 CO2

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 CO2 capture costs by allowing the flue gas to be compressed directly, without any CO2 separation process while also allowing the size of the supercritical 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 CO2 Capture

CO2 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 CO2 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 sitespecific factors.

It should be noted that IGCC plants (like PC plants) do not capture CO2 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 CO2 capture technologies as the installed base of

plants with CO2 capture grows. An International Energy Agency study led by Carnegie Mellon University suggested that overall electricity costs from plants with

CO2 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 CO2 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.

38

Engineering analyses by EPRI, DOE and the Coal Utilization Research Council

suggest that costs could come down faster through CO2 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 CO2 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.

CO2 Transportation and Geologic Storage

Geologic sequestration of CO2 has been proven effective by nature, as evidenced

by the numerous natural underground CO2 reservoirs in Colorado, Utah and other

western states. CO2 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 CO2 for millennia or longer. Geologic sequestration as a strategy for reducing CO2 emissions is being demonstrated in numerous

projects around the world.

Three relatively large projects—the Sleipner Saline Aquifer CO2 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 CO2 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 CO2 storage in deep geologic formations can

be carried out safely and reliably. Furthermore, CO2 injection technology and subsurface behavior modeling have been proven in the oil industry, where CO2 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

CO2 storage and conducting pilot-scale CO2 injection validation tests across the

country. These tests, as well as most commercial applications for long-term storage,

will compress CO2 to a liquid-like ‘‘super-critical’’ state to maximize the amount that

can be stored. Virtually all CO2 storage will be at least a half-mile underground,

where the CO2 will be injected into a porous sandstone-like material saturated with

salty water. CO2 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 CO2 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’’ CO2 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 CO2 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, CO2 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

CO2 pipeline technology has been proven in oil field FOR applications. As CCS is

applied commercially, EPRI expects that early projects would take place at coalbased power plants near to sequestration sites or to existing CO2 pipelines. As the

number of projects increases, regional CO2 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 CO2 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 CO2 storage underlie

39

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 CO2 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

CO2 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 CO2).

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 CO2 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 CO2

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.

40

Efforts toward reducing the cost of IGCC plants with CO2 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.

41

For PC plants, the progression to advanced ultra-super-critical steam conditions

will steadily increase plant efficiency and reduce CO2 production. Improved solvents

are expected to greatly reduce post-combustion CO2 capture process. EPRI is working to accelerate the introduction of novel, alternative CO2 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

CO2 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 scaleup to a larger pilot or pre-commercial plant. An EPRI timeline (compatible with

DOE’s timeframe) for the possible commercial introduction of post-combustion CO2

capture follows.

42

The introduction of oxy-fuel combustion may allow further reductions in CO2 capture costs by allowing the flue gas to be compressed directly, without any CO2 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 CO2 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.

Policy Gaps

Without incentives or regulatory requirements, or a market for CO2, 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 CO2. This is perhaps the biggest unknown. No company

43

can take on unlimited liability—options will be needed to allow firms to make longterm 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 CO2. 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 CO2 emissions

from coal and it will require multiple technological approaches for capture and multiple storage demonstrations to prove the cost, efficiency, and effectiveness of CO2

capture and storage. These must be pursued in the near future to provide options

for CO2 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 CO2 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 CO2 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 coalbased 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 CO2 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 CO2 reductions of up to 20 percent per megawatt hour of electricity before

the addition of any dedicated CO2 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 CO2 capture and sequestration (CCS) technologies

for coal-based power plants will be an indispensable technology for achieving the

deep cuts in man-made CO2 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 CO2 capture technology options is evolving quickly at small-scale,

but large demonstrations are vital. Sites for long-term geologic storage of CO2 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 CO2 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

44

generation, renewables, and coal-based generation, emission controls, and CO2 capture and storage.

Mr. Dalton joined EPRI in 1976 as a Project Manager focused on SO2 control and

later led this area for 20 years, additionally working on integrated emission controls

for NOΧ, 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 NOΧ

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 CO2 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 CO2 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 CO2 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 CO2 geological storage have been

practiced for over 30 years in activities such as: Enhanced Oil Recovery (EOR), where we typically use CO2 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 CO2 per year is currently injected into geological formations for EOR, so we already

have a lot of experience.

So, what have we learned about CO2 geological storage over this

time and through subsequent technology R&D? Well, we know the

best rocks for CO2 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 CO2 storage is likely to exceed 2,000 gigatons or 2,000 billion tons of CO2, with the

largest capacity likely to exist in saline formations.

So, given that today’s CO2 emissions are approximately 24

gigatons of CO2 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 CO2 is stored through the use of

45

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 CO2 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 CO2 is stored. And one

is the important regulatory framework for CCS, and the second one

is a CO2 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 CO2? The second one is injectivity. Can

you actually get the CO2 in the rock and actually fill it up? And

the third one, importantly, is integrity. Will the site store the CO2

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 CO2 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 CO2 moving up.

The second mechanism is called residual phase trapping. That is

simply CO2 going into like a sponge. You have a sponge you have

in your bath that you fill with water, sinking the CO2 in a rock,

the CO2 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 CO2 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

46

reservoir, and can’t possibly come out, because of the density difference.

And the fourth one is mineral trapping, and that is where the

CO2 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 CO2 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 CO2 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

CO2. 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 CO2 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 fossilfuel powered power plants with carbon capture and sequestration (CCS). We have

47

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 CO2 into depleted oil reservoirs, recovering the remaining oil, and inevitably leaving CO2 behind. In other words, CO2 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 CO2 emissions into the atmosphere, helping to

combat climate change.

My role today is to explain how CO2 stays underground. It is important to understand that many natural geological stores of CO2 have been discovered underground—often by people looking for oil and gas. In many cases, the CO2 has been

trapped underground for millions of years in geological traps, plus CO2 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, CO2 does leak

naturally from underground. Indeed the world’s natural carbonated mineral waters,

long prized and bottled for drinking, come from natural CO2 sources. The reasons

why some rock formations trap the CO2 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 CO2 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 CO2 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 CO2 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

CO2 storage, but the potential appears to be huge!

So why does CO2 stay underground? As CO2 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 CO2

remains underground, the more securely it is stored. There are four different ways

that CO2 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 CO2. Once it reaches the surface, the natural gas is separated into methane and CO2. The Methane gas is

pumped North to Europe, while the CO2 is pumped deep underground—back into

the rock formations from which the natural gas was originally extracted. One million tons per year of captured CO2 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 CO2 stored in the underground reservoir. The wells that were

drilled to place the CO2 in storage can be sealed with plugs made of steel and cement.

The second mechanism is where CO2 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 CO2 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, CO2 dissolves

in salty water, just like sugar dissolves in tea. The water with CO2 dissolved in it

is then heavier than the water around it and so it sinks to the bottom of the rock,

trapping the CO2 indefinitely.

And finally, the fourth mechanism is when CO2 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 CO2 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

48

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 CO2 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 CO2 storage is a technology that is available

today, as we have heard, and could play a significant role in reducing CO2 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 CO2? 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 largescale 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 CO2 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.

49

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 CO2, because of the increased buoyancy and the flammability of gas, many years of EOR, and indeed,

we actually have a number of CO2 natural gas fields that exist, or

CO2 natural reservoirs that exist in the U.S., that primarily are

used today for supplying CO2 for EOR.

So, we can actually go and look and study these CO2 natural reservoirs that have occurred for millions of years, and why CO2 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 CO2 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 largescale 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 largescale 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,

50

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 CO2 storage, like in Sowerfield, where we are injecting a

million tons per year of CO2 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 CO2 to where it can be safely

stored.

CARBON DIOXIDE TRANSPORTATION

Mr. INGLIS. So, then, we would likely be talking about moving

CO2, 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

51

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 CO2, 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

52

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 Administra- tion 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 CO2 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 CO2 for ten years, and the Dust Development in Salah. It

is also storing a million tons of CO2 per year in the bottom of a

gas reservoir.

Mr. COSTELLO. Now, is anyone currently capturing CO2 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.

53

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 largescale 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 CO2

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 CO2 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

54

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 CO2 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 CO2

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 CO2 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 CO2 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

55

that is in the back of a more conventional plant, to capture the

CO2. 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 CO2.

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 CO2

Mr. NEUGEBAUER. Mr. Finley, you indicated in, that in my part

of the world, West Texas, we have been using CO2 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 CO2 in the ground and disposing of it, use CO2 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

CO2 for more rapid plant growth, algae growth, taking the algae

as a quick uptake of CO2, 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 CO2 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 CO2 as a working fluid, to capture energy and

move it elsewhere, and in fact, even oxy-combustion plants previously mentioned, looked at recycling CO2 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.

56

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

CO2 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 ultrasuper 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.

57

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 CO2 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.

58

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 CO2, was

that of the algae process, and my understanding in dealing there

with the people at the Voinovich Center at Ohio University, we are

59

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 CO2.

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

CO2 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 CO2. 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.

60

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.

61

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 CO2 to capture from a pulverized coal unit, which

is one of the advantages the IGCC has. They have a higher concentration of CO2 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 NOΧ 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

62

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 CO2 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 CO2 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?

63

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. H2O, 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 CO2, 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 CO2,

and using it to reverse the process, which will take energy, but if

the economics are right, because of the pain of CO2 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 CO2 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

CO2 capture works.

64

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 CO2 in a pure stream. That CO2 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 CO2, 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 CO2 from the exhaust gas, and the challenge is the

CO2 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 CO2. 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, CO2 and hydrogen. But at other stages, there

are other chemicals you can get before you get to the CO2 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.

65

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 CO2 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 DEM- ONSTRATION 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.

66

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

67

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

CO2? 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.

68

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 CO2, inject

CO2 beneath a volcanic lake, which is a high risk situation, obviously, and in this case, it was natural CO2, 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. CO2 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.]

(69)

Appendix 1:

ANSWERS TO POST-HEARING QUESTIONS

70

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 postcombustion 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 NOΧ 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

71

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 NOΧ

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 CO2 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 CO2 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 NOΧ and CO2 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 CO2? 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 CO2 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.

(73)

Appendix 2:

ADDITIONAL MATERIAL FOR THE RECORD

74

75

76

77

78

79

80

81

82

83

84

85

86

87

88

89