[Senate Hearing 110-1155]
[From the U.S. Government Publishing Office]


                                                       S. Hrg. 110-1155
 
                   CARBON SEQUESTRATION TECHNOLOGIES

=======================================================================

                                HEARING

                               before the

          SUBCOMMITTEE ON SCIENCE, TECHNOLOGY, AND INNOVATION

                                 OF THE

                         COMMITTEE ON COMMERCE,
                      SCIENCE, AND TRANSPORTATION
                          UNITED STATES SENATE

                       ONE HUNDRED TENTH CONGRESS

                             FIRST SESSION

                               __________

                            NOVEMBER 7, 2007

                               __________

    Printed for the use of the Committee on Commerce, Science, and 
                             Transportation




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       SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION

                       ONE HUNDRED TENTH CONGRESS

                             FIRST SESSION

                   DANIEL K. INOUYE, Hawaii, Chairman
JOHN D. ROCKEFELLER IV, West         TED STEVENS, Alaska, Vice Chairman
    Virginia                         JOHN McCAIN, Arizona
JOHN F. KERRY, Massachusetts         TRENT LOTT, Mississippi
BYRON L. DORGAN, North Dakota        KAY BAILEY HUTCHISON, Texas
BARBARA BOXER, California            OLYMPIA J. SNOWE, Maine
BILL NELSON, Florida                 GORDON H. SMITH, Oregon
MARIA CANTWELL, Washington           JOHN ENSIGN, Nevada
FRANK R. LAUTENBERG, New Jersey      JOHN E. SUNUNU, New Hampshire
MARK PRYOR, Arkansas                 JIM DeMINT, South Carolina
THOMAS R. CARPER, Delaware           DAVID VITTER, Louisiana
CLAIRE McCASKILL, Missouri           JOHN THUNE, South Dakota
AMY KLOBUCHAR, Minnesota
   Margaret L. Cummisky, Democratic Staff Director and Chief Counsel
Lila Harper Helms, Democratic Deputy Staff Director and Policy Director
   Christine D. Kurth, Republican Staff Director and General Counsel
                  Paul Nagle, Republican Chief Counsel
                                 ------                                

          SUBCOMMITTEE ON SCIENCE, TECHNOLOGY, AND INNOVATION

JOHN F. KERRY, Massachusetts,        JOHN ENSIGN, Nevada, Ranking
    Chairman                         JOHN McCAIN, Arizona
JOHN D. ROCKEFELLER IV, West         KAY BAILEY HUTCHISON, Texas
    Virginia                         GORDON H. SMITH, Oregon
BYRON L. DORGAN, North Dakota        JOHN E. SUNUNU, New Hampshire
BARBARA BOXER, California            JIM DeMINT, South Carolina
MARIA CANTWELL, Washington           JOHN THUNE, South Dakota
MARK PRYOR, Arkansas
CLAIRE McCASKILL, Missouri
AMY KLOBUCHAR, Minnesota


                            C O N T E N T S

                              ----------                              
                                                                   Page
Hearing held on November 7, 2007.................................     1
Statement of Senator Dorgan......................................     3
Statement of Senator Ensign......................................     5
    Prepared statement...........................................     6
Statement of Senator Kerry.......................................     1
Statement of Senator Klobuchar...................................    60
Statement of Senator Stevens.....................................     4
    Prepared statement...........................................     4
Statement of Senator Thune.......................................    74

                               Witnesses

Benson, Professor Sally M., Executive Director, Global Climate 
  and Energy Project, Stanford University........................    22
    Prepared statement...........................................    24
Burruss, Dr. Robert C., Research Geologist, Energy Resources 
  Team, U.S. Geological Survey, U.S. Department of the Interior..    27
    Prepared statement...........................................    28
Fox, Charles E., Vice President, Kinder Morgan CO2 
  Company........................................................    11
    Prepared statement...........................................    12
Hannegan, Bryan, Vice President, Environment, Electric Power 
  Research Institute (EPRI)......................................    30
    Prepared statement...........................................    32
Herzog, Ch.E., Howard, Principal Research Engineer, Laboratory 
  for Energy and the Environment, Massachusetts Institute of 
  Technology.....................................................     6
    Prepared statement...........................................     8
Wolfe, Ron, Corporate Forester and Natural Resource Manager, 
  Sealaska Corporation...........................................    52
    Prepared statement...........................................    53

                                Appendix

Alstom Power, Inc., prepared statement...........................    77
Friedmann, Dr. S. Julio, Leader, Carbon Management Program, 
  Lawrence Livermore National Laboratory, prepared statement.....    82
Response to written questions submitted by Hon. John Thune to:
    Charles Fox..................................................    89
    Howard Herzog, Ch.E..........................................    89


                   CARBON SEQUESTRATION TECHNOLOGIES

                              ----------                              


                      WEDNESDAY, NOVEMBER 7, 2007

                               U.S. Senate,
          Subcommittee on Science, Technology, and 
                                        Innovation,
        Committee on Commerce, Science, and Transportation,
                                                    Washington, DC.
    The Subcommittee met, pursuant to notice, at 2:35 p.m. in 
room SR-253, Russell Senate Office Building, Hon. John F. 
Kerry, Chairman of the Subcommittee, presiding.

           OPENING STATEMENT OF HON. JOHN F. KERRY, 
                U.S. SENATOR FROM MASSACHUSETTS

    Senator Kerry. Thank you very much for being here. I 
apologize for being a little late, I had a meeting on the House 
side, and it takes a little longer to get over here.
    I want to thank the witnesses for joining us here today for 
this. This will be a single panel presentation on the critical 
issue of carbon sequestration and the technologies that apply 
to it.
    This is one of a series of hearings that this Subcommittee 
is engaged in on this topic. In April, we held a hearing on 
clean coal and carbon capture, focusing on the electric power 
industry, and today we're looking specifically on the 
sequestration issue. We intend to hold a hearing sometime in 
the not-too-distant future on gasification and capture 
technologies. It may be very early next year that we wind up 
doing that.
    Everybody, the concept of climate change is on everybody's 
tongue tips these days, with greater or lesser degrees of 
understanding, depending upon who's talking about it, and what 
sort of effort they've made to look at the science and the 
background on it.
    This Committee, I'm proud to say, right here, Al Gore and I 
and a few others, and very few others, held the very first 
hearings on climate change in 1987. And subsequently, we went 
to Rio for the Global Climate Conference, the Earth Summit as 
it was known, and from there to Buenos Aires, and ultimately to 
Kyoto. Now we're here, 20 years later, without a whole lot of 
progress, and without any real major government initiative and 
commitment to this urgent issue. That, in itself, is pretty 
stupefying.
    When you measure the science now, with respect to this 
issue, I think about a year and a half ago, 2 years ago, 
scientists were warning us that you needed to keep the 
concentration of greenhouse gases down to about 550 parts per 
million, and you could maybe tolerate a 3 degree centigrade 
increase in the earth's temperature.
    Because of the feedback from Earth itself over the course 
of these last years, we are now seeing reevaluations of all of 
those estimates, stark reevaluations.
    The IPCC study, on which most nations have based their 
initiatives, had a cutoff date of 2005. So, we've had almost 2 
years now of subsequent data. And, it's interesting, the other 
day I did a compilation of the scientific reports that have 
come out in those intervening 2 years. With respect to insect 
infestation in forests in Canada, Alaska, and northern Wyoming, 
Montana and elsewhere, with respect to understanding the 
importance of tropical forests, and the amount of deforestation 
that has taken place, that is adding to the amount of 
CO2. With respect to the melting of the Antarctic 
and West Antarctic and Greenland ice sheet, 100 billion metric 
tons of melt a year, for an ice sheet that was stable in 1990.
    With respect to the Super El Nino effects, with respect to 
the melt of the floating ice sheets on the Arctic, elsewhere, 
which is exposing more ocean to warming, and to therefore, not 
a cycle of reflection of the sun's rays, but of absorption of 
them, and therefore a faster rate of warming--you can run down 
the list, folks.
    I met with the Audubon the other day, and they talked about 
how their members are telling them of a hundred-mile vegetation 
movement, already discerned in the United States with respect 
to what grows where and how. So, things are changing, and 
they're changing fast.
    And the bottom line is that they now estimate that we can 
only tolerate a 2 degree centigrade increase before you reach 
the tipping point, the catastrophic tipping point, and 450 
parts per million is the allowable level.
    Now, that's a concern, for the simple reason that, since 
the Industrial Revolution, we've gone from 270 to 370, 380 
parts per million right now, right now. And what's already up 
in the atmosphere will continue to do damage for the next 80 to 
100 years, and nobody knows exactly what, or how, or how it 
compounds, so applying a precautionary principle, and being 
smart as public people is sort of screaming out at us, even as 
we still face some flat Earth caucus members, here in the 
Senate and elsewhere.
    This kind of gathering is really important, because in the 
end, we're looking at coal as one of the most critical 
components of dealing with this issue. We have 164 years of 
coal reserves, compared to about 41 years of oil reserves, by 
most estimates. And we have huge amounts of it in the United 
States, and China has huge amounts of it.
    At the rate we're going today, without a big change, we are 
going to produce somewhere between 600 to 900 parts per million 
of greenhouse gases at the current rate of burning fossil 
fuels. So, we've got a gigantic challenge. And everybody who is 
talking about use of coal is now talking about carbon capture 
and sequestration, CCS, as it's known.
    Today we want to hear the thoughts of those here, I know 
North Dakota, they already do some CCS, they use carbon for 
enhanced-oil recovery. The industry has used it for some 30 
years. But we need to know, what is the ability to capture, 
what's the ability to store, what length of time, what amounts, 
and how quickly can we achieve that?
    I will be introducing legislation today that will establish 
3 to 5 commercial-scale sequestration facilities, and 3 to 5 
coal-fired demonstration plants, with carbon capture and 
establish an interagency process to determine a regulatory 
framework for CCS, direct USGS to perform a capacity assessment 
of sequestration potential, and establish an aggressive CCS R&D 
program at DOE.
    Most people have suggested to me that we can only do this 
if we really kick in to high gear, in terms of demonstration 
projects and commercialization efforts. I think there's a lot 
we can do. We also need to authorize technology-sharing 
agreements with China, India, and other coal-intensive 
developing countries, and move on this in a joint fashion.
    So, we welcome our panel, Senator Dorgan, do you have any 
opening comment?

              STATEMENT OF HON. BYRON L. DORGAN, 
                 U.S. SENATOR FROM NORTH DAKOTA

    Senator Dorgan. Mr. Chairman, briefly, I regret I can't 
stay for the entire hearing, I have a meeting in the Leader's 
Office at three o'clock. The question is not whether we engage 
in carbon capture and sequestration, the question is how. Half 
of our electricity in this country comes from coal-based 
resources. We're going to continue to use coal, the question 
is--how do we use coal, and how do we capture and sequester?
    In North Dakota we have the Nation's only synthetic 
gasification plant, making synthetic natural gas from coal. We 
capture 50 percent of the carbon, put it in a pipe and move it 
to Canada for the purpose of enhanced oil recovery. So that, I 
think is the world's largest project of its kind, but we need 
to do a lot of that, we need to do a lot of things to 
understand what works and what doesn't.
    Frankly, the President, for example, in his budget, did not 
request nearly enough funding. I'm the Chairman of the Energy 
and Water Appropriations Subcommittee, I increased the funding 
for fossil fuels by 30 percent over the President's request. 
The only way we're going to get to where we need to get is to 
invest in the research and development, to make real 
investments in these projects. So, I've increased the funding 
by 30 percent. The President's complaining about those 
increases, but I think if we're going to solve this, it's 
absolutely essential that we provide the funding for the 
research.
    And just one final point, if I might, I think the solution, 
in many ways, to be able to continue to use our coal resources, 
is going to be in new technologies and new approaches. And 
sometimes they might represent old inquiries.
    I met a fellow who has left the government and is now with 
a company in Massachusetts, Senator Kerry, engaged in algae 
issues, you know, single-celled pond scum. Pond scum, called 
algae, is produced with sunlight and CO2. Well, 
guess what? This guy worked 17 years for our National Energy 
Lab in algae and then the funding was discontinued. I've just 
continued the funding in the ETL for algae research.
    But the interesting thing about algae is it feeds on 
CO2, and produces a super-fuel. Wouldn't it be 
interesting if we discover that we can use wastewater and 
produce algae, which increases in bulk in hours, and sequester 
the CO2, I should say, capture and use the 
CO2 to produce algae which, essentially, destroys 
the CO2 and produces a super fuel.
    And they were telling me, if you take soy beans, and 
produce ethanol, an acre of soy produces about 80 gallons of 
ethanol. An acre of corn produces about four or five hundred 
gallons of ethanol. An equivalent amount of algae would produce 
four to five thousand gallons of ethanol or super fuel.
    Wouldn't it be interesting if we unlocked the mystery of 
all of this, and used technology to solve some of these issues? 
I just mention that as one idea, but there are a series of them 
that are going to come from research. If we don't do the 
research, we're not going to unlock the opportunities.
    And I would say to my colleague, Senator Kerry, thank you 
for your leadership. You're absolutely correct, 20 years ago 
you were talking about these issues, I'm now talking about the 
need to continue to use coal, and use it the right way, by 
sequestering, capturing and sequestering carbon, because that's 
essential, in my judgment.
    So, I'm sorry I can't stay for the entire hearing, but I'll 
have a chance to read the testimony, and I appreciate this 
excellent group of witnesses being with us today.
    Senator Kerry. Senator Dorgan, let me just say that the 
meeting Senator Dorgan has to go to, I'm going to have to pop 
out too, very briefly, at three o'clock. It happens to be a 
meeting on this subject, with 30 CEOs of major groups involved 
in the issue of this alternative energy. So I will go out and 
come back. During it, Senator Stevens will be here, and he's 
agreed to cover for me during that, and I appreciate it.
    Senator Stevens, do you have any opening?

                STATEMENT OF HON. TED STEVENS, 
                    U.S. SENATOR FROM ALASKA

    Senator Stevens. I'll just put my statement in the record. 
I'd be pleased to introduce Mr. Wolfe when the time comes. But, 
this is an area in which I'm pleased to say, there ought to be 
bipartisan support, and I look forward to working with you on 
the whole prospect of getting some demonstration plants to go 
into this whole subject of carbon sequestration.
    I think it's one of the things we ought to know--if the 
technology is there, and if it works.
    Thank you.
    [The prepared statement of Senator Stevens follows:]

    Prepared Statement of Hon. Ted Stevens, U.S. Senator from Alaska

    Mr. Chairman, thank you for holding this hearing today on carbon 
sequestration technologies. I would like to thank the witnesses for 
their testimony.
    In particular, I would like to welcome Ron Wolfe. Mr. Wolfe is 
Sealaska's corporate forester and manager of the Office of Natural 
Resources. Mr. Wolfe has had a long and proud history of serving the 
Juneau community and Alaska as a whole. Prior to joining Sealaska, he 
was the forester for the Central Council of Tlingit and Haida Indian 
Tribes of Alaska and Chief Forester for the Klukwan Corporation. As a 
member of the Alaska Board of Forestry, Mr. Wolfe will provide valuable 
insight into forestry's critical role in carbon capture and 
sequestration and I look forward to hearing his testimony.
    Energy is the lifeblood of our economy, without it, our ability to 
compete globally would be lost. Therefore, it is vital that our 
country's energy needs continue to be met if we are to maintain a 
competitive edge in today's global economy. By expanding our 
alternative energy portfolio, improving efficiency, and developing ways 
to exploit more cleanly our abundant natural resources, I believe we 
can achieve environmental stability while still allowing the economy to 
prosper. Carbon capture and sequestration is one such technology that 
may provide part of the solution.
    This technology, while helping to reduce the amount of carbon 
dioxide entering the atmosphere, can also aid in recovering reserves of 
petroleum previously thought to be unrecoverable. Doing so will become 
more and more important as global oil reserves diminish and as 
petroleum prices rise. Further, forestry offers the widely understood 
option of capturing atmospheric carbon by growing more trees. This 
solution helps not only the environment, but also the economy and 
culture of many communities that depend on healthy forest management.
    While the promises of carbon sequestration technology are great, I 
believe it is important to have a full understanding of this technology 
before implementing it. For instance, understanding how long-term 
sequestration may affect ground water supplies is just one of many 
issues of vital importance. Further, we must also realize that 
different regions require different solutions.
    The Nation's energy needs must be met through a variety of 
solutions. The 21st century will be the proving ground for our 
commitment to achieve both energy independence and new, clean fuels. We 
can solve our current energy crisis through a combination of 
initiatives. Increased domestic production, conservation, and the 
development of alternative sources of energy will all be part of the 
broader solution, but the appropriate balance must be found between all 
options. Carbon capture, in its several forms, will inevitably be part 
of this balance.

    Senator Kerry. Thank you, Senator Stevens, and your 
statement will be put in the record.
    Senator Ensign?

                STATEMENT OF HON. JOHN ENSIGN, 
                    U.S. SENATOR FROM NEVADA

    Senator Ensign. Mr. Chairman, I'll put my formal statement 
also in the record, without objection but the--just a couple of 
quick comments.
    We all know the abundance of coal that we have in the 
United States, and in this world that we live in today, we're 
relying more and more on countries that are not exactly 
favorable to the United States. So, if we can develop more coal 
power plants, other uses for coal in our energy portfolio into 
the future, and we can do it in an environmentally sound way, 
it--from so many different ways, it makes sense for the United 
States.
    So, I appreciate you holding this important hearing, I do 
think this is a place where Republicans and Democrats can come 
together, with environmentalists, with industry folks, and try 
to work out some solutions.
    As much as we'd all like to have wind and solar, and 
geothermal and the rest of the renewables, we know that there 
is, they're not abundant enough with the current technology 
that exists, so we have to have some fossil fuels, so we can 
get carbon, as a fossil fuel, to be much more environmentally 
sound, we should be pursuing that with everything that we have.
    So, thanks for holding this hearing.
    [The prepared statement of Senator Ensign follows:]

      Prepared Statement of John Ensign, U.S. Senator from Nevada

    Mr. Chairman, I would like to thank you for holding this hearing 
today on coal and carbon capture technologies.
    It is widely recognized that continued reliance on Middle East oil 
is neither smart energy policy nor smart security policy. In order to 
meet the rapidly growing energy needs of this country we must develop 
the resources that are available domestically. This cannot be done 
using only one fuel or one technology. It must be done by using all of 
the resources at our disposal including coal.
    Coal is both abundant and inexpensive. In the United States alone, 
coal-fired power plants satisfy more than half of the Nation's energy 
needs and this percentage is likely to increase in the future.
    The key is to ensure that we are employing this resource in the 
most efficient and environmentally responsible manner possible. New 
technologies to make this possible are on the horizon. Carbon capture 
and sequestration is just one of many processes already in development. 
Groundbreaking research is being conducted to develop ways to burn coal 
in order to maximize energy yield and employ cleaner and more efficient 
processes.
    Nevada is a prime example of a state dedicated to doing its part to 
meet our growing energy needs and has been a national leader in the 
generation of renewable energy. Nevada also recognizes that there will 
be times when the wind is not blowing and the sun is not shining that 
people will still need electricity. In order to respond, Nevada is 
committed to keeping its energy supply diverse and is planning to build 
two state-of-the-art, environmentally compliant, clean pulverized coal 
plants. Both of these plants will be built to accommodate retrofits 
when large scale carbon capture and sequestration (CCS) technologies 
are demonstrated feasible.
    This project is an important part of Nevada's ongoing strategy to 
develop and maintain a balanced energy portfolio and reduce our 
emissions footprint. The plants in Nevada will be the catalyst for the 
development of more renewable energy resources (particularly wind 
energy in the mountains of eastern Nevada) by providing transmission 
access to northern and southern Nevada via a proposed 250-mile 
transmission line between the two operating companies.
    Like many of the alternative energy technologies currently in 
development, no one single solution will solve the problem of meeting 
energy needs in a responsible manner. However, if the technology proves 
commercially feasible and environmentally responsible, we should 
continue to explore the benefits clean coal can offer to our economy. I 
look forward to all of our witnesses' testimony and their insight into 
how we can achieve this goal.

    Senator Kerry. Thank you, Senator Ensign, your statement 
will also be put into the record.
    Thank you, members of the panel, for being patient with us, 
and we look forward to your testimonies.
    If you could try to summarize them in 5 minutes, the full 
written statement will be placed in the record, as if read in 
full. We appreciate the summaries, they give us a little more 
time to have some give and take.
    Mr. Herzog, would you begin, and we'll just run down the 
line? Introduce yourselves, and go to work.

               STATEMENT OF HOWARD HERZOG, Ch.E.,

          PRINCIPAL RESEARCH ENGINEER, LABORATORY FOR

    ENERGY AND THE ENVIRONMENT, MASSACHUSETTS INSTITUTE OF 
                           TECHNOLOGY

    Mr. Herzog. Howard Herzog, Principal Research Engineer at 
MIT.
    Mr. Chairman, and Members of the Committee, thank you for 
this opportunity to appear before you today to discuss carbon 
sequestration technologies, or more specifically, the 
sequestration of carbon dioxide into geologic formations.
    I've been involved with carbon dioxide capture and storage, 
referred to as CCS, for over 18 years.
    Senator Kerry. Can you pull the mic a little closer, I 
think we'll get a little more.
    Mr. Herzog. I was coordinating lead author on the 
Intergovernmental Panel on Climate Change, Special Report on 
Carbon Dioxide Capture and Storage, as well as a co-author on 
the MIT report, The Future of Coal. Over the past few years, 
I've also been a U.S. delegate to the Carbon Sequestration 
Leadership Forum.
    Coal is a critical fuel for the world, as you have just 
said in your statements. It supplies a majority of electricity 
at inexpensive prices in many countries, including the U.S., 
China and India.
    However, coal is responsible for about 40 percent of the 
world's carbon dioxide emissions. In the MIT Future of Coal 
study we concluded that carbon dioxide capture and 
sequestration is the critical enabling technology that will 
reduce carbon dioxide emissions significantly, while also 
allowing the world to meet its pressing energy needs.
    So, while we recognize that CCS is not a silver bullet, we 
do view it as a critical component in a portfolio of climate 
change mitigation options.
    For geologic sequestration, the MIT Coal Study finds 
current evidence indicates it is scientifically feasible to 
store large quantities of carbon dioxide in geologic 
formations. This statement is based on actual field experience 
with carbon sequestration; other types of carbon dioxide 
injections such as enhanced oil recovery or injection of other 
buoyant fluids like natural gas for seasonal storage; pilot 
tests; as well as modeling and assessment studies.
    However, to scale up from what we refer to as the current 
megaton, or millions of tons per year scale to the required 
gigaton, or billions of tons per year scale, is a major 
challenge and should not be underestimated. To move forward, we 
need to address the scientific and regulatory uncertainties 
associated with geologic storage at scale.
    The MIT coal study states that in order to address 
outstanding technological issues that need to be resolved to 
confirm CCS as a major mitigation option, and to establish 
public confidence that large-scale sequestration is practical 
and safe, it is urgent to undertake a number of large-scale 
experimental projects in reservoirs that are instrumented, 
monitored and analyzed to verify the practical reliability and 
implementation of sequestration.
    Specifically, we recommend about 10 sequestration 
demonstrations worldwide, with a minimum of 3 projects in the 
U.S. to represent the range of U.S. geology.
    It should be noted that all of the world's current large 
sequestration projects are offshoots of commercial projects, 
with the science coming as an afterthought. We need the next 
round of sequestration demonstrations designed with scientific 
data collection as a primary goal to enable us to reach the 
gigaton scale.
    In additional to the demonstration program, other key 
recommendations from the coal study are that the U.S. 
Geological Survey, and the DOE should embark on an assessment 
of U.S. geological storage capacity. The DOE should accelerate 
its research program in CCS science and technology, and that a 
regulatory capacity needs to be built.
    Regulations need to cover the injection of carbon dioxide 
accounting and crediting as part of a climate regime, and site 
closure and monitoring.
    While geologic sequestration is scientifically feasible, it 
is not technologically or institutionally ready. If the 
recommendations given above are pursued aggressively, we should 
be able to achieve technological readiness in 8 to 10 years.
    There's urgency to start moving sequestration 
demonstrations forward as quickly as possible. The goal should 
be to achieve technological readiness by the time climate 
legislation creates market opportunities for CCS technologies. 
Unfortunately, we are currently not on that path.
    The number one impediment to moving ahead is lack of 
funding. To achieve technological readiness both capture and 
sequestration, the MIT coal study recommends about a billion 
dollars a year for the U.S. CCS program. This is about 3 to 4 
times the existing level of commitment into the current R&D and 
demonstration programs.
    At current funding levels, demonstration projects will be 
forced to cut corners, which can result in a process to simply 
demonstrate we can inject carbon dioxide into the ground, which 
we routinely do right now, but will not advance the cause of 
technological readiness.
    Climate change is a challenge mankind must address for at 
least the coming decades, and possibly centuries. Even when 
policies to deal with climate change are implemented, the 
inherent dynamics of both the energy and climate system means 
that the benefits from our actions may take decades to appear. 
Therefore, while the debate on climate change proceeds, it 
seems both prudent and relatively inexpensive to strive toward 
technological readiness. We don't want to add further delays 
into the system by not having technological options available 
when needed. This is why there's urgency to get on the path to 
technological readiness now.
    Thank you.
    [The prepared statement of Mr. Herzog follows:]

    Prepared Statement of Howard Herzog, Ch.E., Principal Research 
  Engineer, Laboratory for Energy and the Environment, Massachusetts 
                        Institute of Technology

    Mr. Chairman and Members of the Committee, thank you for the 
opportunity to appear before you today to discuss carbon sequestration 
technologies or more specifically, the sequestration of CO2 
into geologic formations. I have been involved with CO2 
capture and sequestration (CCS) for over 18 years. I started my first 
research project in CCS in 1989. In 1992-93, under Department of Energy 
(DOE) funding, I led a 2-year effort that produced the first 
comprehensive research needs assessment in the field (see DOE/ER-
30194). More recently, I was a coordinating lead author on the 
Intergovernmental Panel on Climate Change (IPCC) Special Report on 
Carbon Dioxide Capture and Storage (see www.ipcc.ch), as well as one of 
13 co-authors on the just released MIT report on The Future of Coal 
(see www.mit.edu/coal). For the past few years, I have also been a U.S. 
delegate to the Technical Group of the Carbon Sequestration Leadership 
Forum (see www.cslforum.org).
    Coal is a critical fuel for the world. It supplies the majority of 
electricity at inexpensive prices in countries like the U.S., China, 
and India. However, coal also is responsible for about 40 percent of 
the world's CO2 emissions. In the MIT Future of Coal Study, 
``we conclude that CO2 capture and sequestration (CCS) is 
the critical enabling technology that would reduce CO2 
emissions significantly while also allowing coal to meet the world's 
pressing energy needs.'' So while we recognize that CCS is not a silver 
bullet, we do view it as a critical component in a portfolio of climate 
change mitigation options.
    For geological sequestration, the MIT Coal Study finds: ``current 
evidence indicates that it is scientifically feasible to store large 
quantities of CO2'' in geologic formations. This statement 
is based on actual field experience with CO2 sequestration 
(e.g., Sleipner, Weyburn, In-Salah), other types of CO2 
injections (e.g., enhanced oil recovery, acid gas disposal), injection 
of other buoyant fluids (e.g., natural gas storage), and pilot tests 
(e.g., Frio Brine), as well as modeling and assessment studies. 
However, to scale up from what we refer to as the current megaton 
(i.e., millions of tons per year) scale to the required gigaton (i.e., 
billions of tons per year) scale is a major challenge and should not be 
underestimated. To move forward, we need to address the scientific and 
regulatory uncertainties associated with geologic storage at scale.
    ``In order to address outstanding technical issues that need to be 
resolved to confirm CCS as a major mitigation option, and to establish 
public confidence that large scale sequestration is practical and safe, 
it is urgent to undertake a number of large scale (on the order of 1 
million tonnes/year injection) experimental projects in reservoirs that 
are instrumented, monitored, and analyzed to verify the practical 
reliability and implementation of sequestration.'' Specifically, the 
MIT Coal Study recommends about ten sequestration demonstrations 
worldwide, with about three projects in the U.S. to represent the range 
of U.S. geology. It should be noted that the world's current large 
sequestration projects operating today are all offshoots of commercial 
projects, with the science coming as an afterthought. We need the next 
round of sequestration demonstrations designed with scientific data 
collection as a primary goal to enable us to start scaling up to the 
gigaton scale.
    In addition to the demonstration program, other key recommendations 
from the coal study are:

   The U.S. Geological Survey and the DOE should embark on a 3 
        year ``bottom-up'' analysis of U.S. geological storage capacity 
        assessments.

   The DOE should accelerate its research program for CCS 
        Science and Technology.

   A regulatory capacity covering the injection of 
        CO2, accounting and crediting as part of a climate 
        regime, and site closure and monitoring needs to be built.

    Summing up the situation, while geologic sequestration is 
scientifically feasible, it is not technologically or institutionally 
ready. If the recommendations given above are pursued aggressively, we 
should be able to achieve technological readiness in about 8-10 years. 
There is urgency to start moving the sequestration demonstrations 
forward as quickly as possible. The goal should be to achieve 
technological readiness by the time climate legislation creates market 
opportunities for CCS technologies. Unfortunately, we are not currently 
on that path.
    The number one impediment to moving ahead is lack of funding. To 
achieve technological readiness for both capture and sequestration, the 
MIT Coal Study recommends about $1 billion/yr for the U.S. CCS program. 
This is about 3-4 times the existing level of commitment for current 
R&D and demonstration programs. The current funding levels will require 
proposed demonstrations to cut corners, which can result in projects 
that demonstrate we can inject CO2 into the ground (which we 
already know we can do), but will not advance the cause of 
technological readiness.
    In summary, climate change will not be solved overnight. Rather, it 
will be a challenge mankind must address for at least the coming 
decades and possibly centuries. Even when policies to deal with the 
climate challenge are implemented, the inherent dynamics of both the 
energy and climate systems means that the benefits from our actions may 
take decades to appear. Therefore, while the debate on climate policy 
proceeds, it seems both prudent and relatively inexpensive to achieve 
technological readiness. We don't want to add further delays into the 
system by not having technological options available when needed. That 
is why there is urgency to get on the path to technological readiness 
now.
    Thank you.

                               Attachment

    For more details on these topics, please see the MIT Coal Study at 
www.mit.edu/coal. Chapter 4 deals with the topic of geological 
sequestration. Below are the introduction and recommendations of that 
chapter.

Introduction
    Carbon sequestration is the long term isolation of carbon dioxide 
from the atmosphere through physical, chemical, biological, or 
engineered processes. The largest potential reservoirs for storing 
carbon are the deep oceans and geological reservoirs in the earth's 
upper crust. This chapter focuses on geological sequestration because 
it appears to be the most promising large-scale approach for the 2050 
timeframe. It does not discuss ocean or terrestrial sequestration.
    In order to achieve substantial GHG reductions, geological storage 
needs to be deployed at a large scale. For example, 1 Gt C/yr (3.6 Gt 
CO2/yr) abatement, requires carbon capture and storage (CCS) 
from 600 large pulverized coal plants (1000 MW each) or 3,600 
injection projects at the scale of Statoil's Sleipner project. At 
present, global carbon emissions from coal approximate 2.5 Gt C. 
However, given reasonable economic and demand growth projections in a 
business-as-usual context, global coal emissions could account for 9 Gt 
C [by 2050]. These volumes highlight the need to develop rapidly an 
understanding of typical crustal response to such large projects, and 
the magnitude of the effort prompts certain concerns regarding 
implementation, efficiency, and risk of the enterprise.
    The key questions of subsurface engineering and surface safety 
associated with carbon sequestration are:

    Subsurface issues:

   Is there enough capacity to store CO2 where 
        needed?

   Do we understand storage mechanisms well enough?

   Could we establish a process to certify injection sites with 
        our current level of understanding?

   Once injected, can we monitor and verify the movement of 
        subsurface CO2?

    Near surface issues:

   How might the siting of new coal plants be influenced by the 
        distribution of storage sites?

   What is the probability of CO2 escaping from 
        injection sites? What are the attendant risks? Can we detect 
        leakage if it occurs?

   Will surface leakage negate or reduce the benefits of CCS?

    Importantly, there do not appear to be unresolvable open technical 
issues underlying these questions. Of equal importance, the hurdles to 
answering these technical questions well appear manageable and 
surmountable. As such, it appears that geological carbon sequestration 
is likely to be safe, effective, and competitive with many other 
options on an economic basis. This chapter explains the technical basis 
for these statements, and makes recommendations about ways of achieving 
early resolution of these broad concerns.
          *        *        *        *        *        *        *

Recommendations
    Our overall judgment is that the prospect for geological 
CO2 sequestration is excellent. We base this judgment on 30 
years of injection experience and the ability of the earth's crust to 
trap CO2. That said, there remain substantial open issues 
about large-scale deployment of carbon sequestration. Our 
recommendations aim to address the largest and most important of these 
issues. Our recommendations call for action by the U.S. government; 
however, many of these recommendations are appropriate for OECD and 
developing nations who anticipate the use CCS.
    1. The U.S. Geological Survey and the DOE, and should embark of a 3 
year ``bottom-up'' analysis of U.S. geological storage capacity 
assessments. This effort might be modeled after the GEODISC effort in 
Australia.
    2. The DOE should launch a program to develop and deploy large-
scale sequestration demonstration projects. The program should consist 
of a minimum of three projects that would represent the range of U.S. 
geology and industrial emissions with the following characteristics:

   Injection of the order of 1 million tons CO2/year 
        for a minimum of 5 years.

   Intensive site characterization with forward simulation, and 
        baseline monitoring.

   Monitoring MMV arrays to measure the full complement of 
        relevant parameters. The data from this monitoring should be 
        fully integrated and analyzed.

    3. The DOE should accelerate its research program for CCS S&T. The 
program should begin by developing simulation platforms capable of 
rendering coupled models for hydrodynamic, geological, geochemical, and 
geomechanical processes. The geomechanical response to CO2 
injection and determination or risk probability-density functions 
should also be addressed.
    4. A regulatory capacity covering the injection of CO2, 
accounting and crediting as part of a climate regime, and site closure 
and monitoring needs to be built. Two possible paths should be 
considered--evolution from the existing EPA UIC program or a separate 
program that covers all the regulatory aspects of CO2 
sequestration.
    5. The government needs to assume liability for the sequestered 
CO2 once injection operations cease and the site is closed. 
The transfer of liability would be contingent on the site meeting a set 
of regulatory criteria (see recommendation 4 above) and the operators 
paying into an insurance pool to cover potential damages from any 
future CO2 leakage.

    Senator Kerry. That's very helpful, thank you, Mr. Herzog.
    Mr. Fox?

         STATEMENT OF CHARLES E. FOX, VICE PRESIDENT, 
              KINDER MORGAN CO2 COMPANY

    Mr. Fox. Mr. Chairman, Members of the Subcommittee, thank 
you for giving me the opportunity to testify on carbon capture 
sequestration technologies, also known as CCS.
    My name is Chuck Fox, and I serve as Vice President of 
Kinder Morgan CO2 Company. I've submitted a more 
detailed statement to the Committee, and ask it be made a part 
of the record.
    I will summarize my remarks along five specific categories. 
Kinder Morgan's background with CCS is related to technologies, 
carbon capture science issues, transportation technology 
issues, storage issues, and finally, non-technical barriers to 
creating CCS in the U.S.
    Kinder Morgan is one of the largest midstream energy 
companies in the U.S. It operates more than 30,000 miles of 
natural gas and products pipelines across the U.S., Canada and 
Mexico.
    Kinder Morgan CO2 Company is the largest 
pipeline transporter of CO2 in the world, the second 
largest CO2 EOR company, and the third largest oil 
producer in Texas. We have extensive experience in transporting 
CO2 and injecting it into the ground.
    Also, as a supplier of CO2 we have reviewed the 
capture processes in order to locate new sources.
    Of the various CCS components, capture is the most costly. 
Today, there are two viable processes--post-combustion capture, 
and pre-combustion capture, and one developing process--oxy-
fuel combustion.
    Post-combustion capture has been practiced for more than 60 
years. The technology is well-known, but unfortunately is 
costly. CO2 is captured by bubbling flue gas through 
a chemical absorbent. This process is energy intensive, since 
post-combustion gases have low concentrations of 
CO2.
    Flue gas is primarily composed of nitrogen, a major 
constituent of air. Large volumes of flue gases must be 
managed. The pre-combustion capture and oxy-fuel processes seek 
to cut costs by reducing the flue gas volume by removing 
nitrogen from the system.
    In pre-combustion capture, fossil fuel is injected with 
steam and air or oxygen to produce two gas streams--hydrogen 
and CO2. Pre-combustion capture could be used with 
IGCC's power plants. In fact, the gasification process is being 
used by the Dakota Gasification Company to splice 
CO2 to an oil field in Canada.
    In oxy-fuel combustion, oxygen is used instead of air for 
combustion of fuels, thereby eliminating nitrogen from the flue 
gas. The flue gas is composed primarily of water and 
CO2. Unfortunately, combusting with fuel and oxygen 
creates an extremely high-temperature flame, and existing steel 
cannot handle it. Given the relative cost, only the pre-
combustion process seems to be viable for large-scale capture 
in the near term.
    The most economical way to transport large volumes of 
CO2 is by pipelines. CO2 has been 
transported safely for over 35 years. CO2 is not as 
dangerous to transport by pipeline as other gases. It is not 
flammable, explosive or poisonous. Few accidents or leaks have 
been reported on CO2 pipelines. None of the dozen 
leaks that have occurred between 1986 and 2006 resulted in 
injuries. There are a few technical issues that must be 
resolved, regarding the transportation, and I made some 
suggestions in my written testimony.
    Geological storage may present the most formidable 
challenge of any CCS development. Like transport, storage has a 
well-established and documented history, through established 
EOR activities. Though the science and engineering knowledge 
gained through EOR are well-understood, the technology was not 
developed to store CO2 for long periods. Relatively 
little is known, for example, about saline aquifers, the 
largest and most widespread of CO2 storage options. 
These aquifers need to be characterized.
    In addition, technology created for EOR must be extended, 
so that the migration of CO2 through the subsurface 
can be monitored, and the ultimate fate of CO2 can 
be determined.
    Although some technological barriers exist that could delay 
the economical application of CCS to mitigate climate change, 
non-technical barriers must also be surmounted. Of all CCS 
issues, none is as contentious or as critical as the issue of 
ultimate liability. Companies may not be willing to enter the 
storage business unless there is some relief from an eternal 
and unlimited liability.
    Another topic discussed in the recent IOGCC report on CCS 
is ownership of the storage site. The issue of mineral rights 
versus surface rights must be settled prior to the creation of 
sites. In addition, the use of eminent domain to create storage 
sites and pipeline right-of-ways, must be defined by the states 
or Federal Government.
    In addition, much of the pipeline industry has migrated 
toward the Master Limited Partnership, or MLP structure. The 
current tax law may not define revenues received for 
transportation of CO2 for CCS to be qualifying 
income. As such, the tax structure would not support the 
development of a CCS transportation infrastructure.
    Even with these challenges, I believe that industry is 
prepared to respond positively to society's call to find 
economical methods to mitigate climate change.
    Thank you.
    [The prepared statement of Mr. Fox follows:]

         Prepared Statement of Charles E. Fox, Vice President, 
                  Kinder Morgan CO2 Company

    Mr. Chairman and Members of the Subcommittee, thank you for giving 
me the opportunity to testify on carbon capture sequestration 
technologies, also known as carbon capture and storage or CCS. My name 
is Charles E. Fox and I serve as Vice President of Kinder Morgan. This 
is my full written statement and this document covers several topics 
related to carbon sequestration also known as carbon capture and 
storage: the development of the related CO2 enhanced oil 
recovery (EOR) technology; the practical science behind carbon capture 
and sequestration technologies, the technical barriers to implementing 
such technologies and finally the non-technical barriers to creating a 
carbon capture and storage business in the United States.
    First, as introduction, Kinder Morgan is one of the largest 
midstream energy companies in the U.S., operating more than 30,000 
miles of natural gas and products pipelines across the United States, 
Canada and Mexico. Kinder Morgan CO2 Company LLP is the 
largest transporter of CO2 in the world; the second largest 
producer of oil through CO2 enhanced oil recovery processes, 
and the third largest oil producer in Texas. Mr. Fox is the Vice 
President of Operations and Technology for Kinder Morgan CO2 
Company and co-authored the monograph, Practical Aspects of 
CO2 Flooding, for the Society of Petroleum Engineers.

Development of CO2 Enhanced Oil Recovery
    The oil industry has over thirty-five years of experience producing 
and transporting CO2. Commercial scale CO2 
enhanced oil recovery (EOR) began in 1972 in the Permian Basin which is 
located in west Texas and eastern New Mexico (see Figure 1). 
Anthropogenic \1\ CO2 was recovered from natural gas plants 
in the Val Verde Basin in Texas and then pipelined to the Chevron 
operated SACROC and Shell operated North Cross oil fields. During the 
1970s the commerciality of CO2 EOR was established which set 
the stage for a major expansion in the 1980s. Major oil companies such 
as Shell, Mobil, Exxon, Amoco and Arco funded the construction of the 
Permian Basin infrastructure to source CO2 for their own oil 
fields. Natural, nearly pure, underground sources at the McElmo Dome 
(Colorado), Bravo Dome (New Mexico) and Sheep Mountain (Colorado) 
fields were developed. The major pipelines were laid (Cortez, Bravo and 
Sheep Mountain). Also during this decade Exxon began capturing 
anthropogenic CO2 from the natural gas and helium Shute 
Creek plant at the LaBarge (Wyoming) and began to supply the Chevron 
operated Rangley field in Colorado. Shell also developed the Jackson 
Dome field in Mississippi to supply its oil fields in Mississippi and 
Louisiana. In the 1990s Great Plains Gasification Company began 
capturing anthropogenic CO2 from its coal gasification plant 
in North Dakota and built a line to Saskatchewan to supply the Pan 
Canadian operated Weyburn oil field.
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    \1\ Anthropogenic CO2 (CO2a) is defined as 
man-made CO2 that is captured from an emissions source that 
otherwise would have been released to the atmosphere. Natural 
CO2 (CO2n) is CO2 which is produced 
from naturally occurring underground sources that are primarily 
operated to supply CO2. CO2 produced from McElmo 
Dome is CO2n. CO2 captured from a natural gas 
plant in the Val Verde basin is CO2a because even though the 
CO2 occurs naturally with the natural gas, the 
CO2 is a byproduct of the natural gas production operations.



    During this period several short lived or intermittent sources were 
developed. Fertilizer plants which emit pure CO2 at 
atmospheric pressures supplied small fields in Oklahoma and Texas. Of 
note was a capture project at the Lubbock Power and Light, Holly Street 
Plant. CO2 was captured from the flue stack, and a 
CO2 pipeline was laid to the Garza oil field.
    The oil price collapse in 1986 made the CO2 flooding 
uneconomic without inexpensive CO2. While the natural 
sources and the Val Verde basin capture plants with lower variable 
costs were able to offer CO2 for sale at reduced prices and 
stay in business, the Lubbock power plant was unable to sell 
CO2 at a price its customer could afford and the 
CO2 project was discontinued.
    From the 1970s to the 1990s, major oil companies (Shell, Mobil, 
Exxon, Amoco, Arco, etc.) had research centers which conducted much of 
the research and development that was needed to initiate the new 
CO2 EOR process. They and universities such as Stanford, the 
University of Texas, New Mexico Tech and the University of Alberta 
conducted research in topics such as intrinsic CO2 
properties, simulation of the underground movement of CO2, 
corrosion processes and its mitigation, flow through piping and 
separation of CO2 from impure sources. By the time many of 
the industry research facilities were shut down during the downturn in 
oil prices and the consolidation of the industry, the essential 
research was complete.
    Today more than 200,000 BOPD are being produced in the U.S. due to 
the injection of CO2. Approximately 37 million metric tons 
per year are purchased for injection into these fields. Approximately 7 
million metric tons per year (19 percent) are from anthropogenic 
sources (Val Verde Basin--1.4, LaBarge--4.1, Dakota Gasification 1.8 
million metric tons per year). To date, more than one billion barrels 
have been produced in the U.S. due to CO2 EOR.

Carbon Capture Science
    There are three pieces to the carbon capture and storage business: 
capture, transportation and storage. This document touches briefly on 
capture which Kinder Morgan has studied in order to locate economical 
sources of CO2 and focuses more on transportation and 
storage in which Kinder Morgan has more expertise.
    Capture of CO2 is the first part of the process. 
Research has identified three main types of capture processes: post 
combustion capture, pre-combustion capture and oxyfuel combustion. Pre-
combustion capture appears to have the most promise for wide spread, 
economical capture of CO2.

Post-Combustion Capture
    Having been practiced for over 60 years, though not for the primary 
purpose of capturing CO2, post-combustion capture is the 
most mature technology for CO2 capture. It involves removing 
the CO2 from air-fired flue gas after the combustion of 
fossil fuels (natural gas, coal, oil) or biomass. The capture pieces 
are located downstream of the combustor to separate and remove the 
CO2 from the flue gas. Air-fired combustors generally emit 
flue gases with low concentrations of CO2 (3-15 percent by 
volume). This fact plus the high gas flow rates and low pressures means 
that post-combustion capture plants must have large equipment in order 
to process huge amounts of flue gas. Due to the low concentration of 
CO2, chemical absorption appears to the most efficient means 
of separation.
    Before the CO2 can be removed by chemical absorption; 
however, the flue gas stream must be pretreated. First, the flue gas 
must be cooled. Next, acid gases like SOX (sulfur oxides) 
and NOX (nitrogen oxides), must be removed or significantly 
reduced. These acid gases react with the chemical solvent and reduce 
the solvent's ability to capture the CO2. Different levels 
of SOX and NOX are tolerable depending on the 
cost of the chemical solvent.
    Chemical absorption with amine solvents is usually used for the 
CO2 separation. Not only does it execute high capture 
efficiency, chemical absorption can also be utilized with relatively 
low costs and energy consumption in comparison to other existing post-
combustion capture processes. One of the most common absorbents used is 
monoethanolamine (MEA).
    The MEA chemical absorption process can recover 85-95 percent \2\ 
of the CO2 in the flue gas and produce a stream of 
CO2 with a purity of 99 percent by volume at low pressure. 
Unfortunately, large amounts of energy are consumed in the heating and 
regenerating the lean solvent, the steam production for stripping, the 
compression for transport, as well as in the powering of flue gas fans 
and pumps. As a result, there is a large energy penalty. 1-1.5 MW can 
be consumed in regenerating the solvent for every metric ton of 
CO2 recovered.\3\ Other problems with the MEA process 
include equipment corrosion, solvent degradation due to the presence of 
oxygen, and the formation of heat-stable salts when SOX and 
NOX molecules are allowed to react with the amine solution. 
Furthermore, if particulates (fly ash) are not satisfactorily removed 
prior to entering the absorber foaming and degradation of the solvent 
can occur. After cooling and dehydrating for water removal, the highly 
concentrated CO2 stream that results is compressed for 
transport and sequestration. Primarily due to the energy penalty, other 
technologies for carbon capture are being pursued.
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    \2\ http://www.netl.doe.gov/technologies/carbon_seq/partnerships/
phase1/pdfs/CarbonSepa
rationCapture.pdf.
    \3\ http://www.aseanenvironment.info/Abstract/41013970.pdf.
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Pre-Combustion Capture
    It is possible to capture CO2 before combustion. There 
are three main components to pre-combustion decarbonization. First, the 
fossil fuel is reacted with steam and air or oxygen to produce a 
synthesis gas primarily composed of hydrogen and carbon monoxide. 
Second, the carbon monoxide is reacted with steam to form 
CO2 and additional hydrogen in a catalytic reactor called a 
shift converter. Third, the CO2 can be separated, usually by 
physical or chemical absorption, creating two gas streams: one of 
CO2 and one of hydrogen.\4\ The CO2 is condensed 
and transported and the hydrogen is used as fuel gas in a gas turbine 
or boiler. Pre-combustion capture could be used in conjunction with 
(coal) integrated gasification combined cycle (IGCC) power plants that 
already produce syngas prior to combustion.
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    \4\ http://www.ipcc.ch/activity/srccs/SRCCS_Chapter3.pdf.
---------------------------------------------------------------------------
    Physical absorption can also used for CO2 separation 
(and hydrogen sulfide removal) from syngas by using solvents such as 
Selexol (dimethylether of polyethylene glycol) or Rectisol (cold 
methanol). Physical absorption works best when high partial pressures 
of CO2 are applied at low temperatures. For example, 
absorption with Selexol occurs at temperatures of 0-5 degrees 
Celsius.\5\ The solvents are then regenerated by heating or reduction 
of pressure thereby releasing the CO2.
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    \5\ http://www.delphi.ca/apec/Modules/Module2.pdf.
---------------------------------------------------------------------------
    Chemical absorption is an alternative technique that can be used to 
capture the CO2 from the syngas. The most common solvent 
used for pre-combustion chemical absorption is methyl-diethanolamine 
(MDEA). Although it is more expensive than MEA, the chemical solvent 
commonly used in post-combustion, MDEA is more attractive in pre-
combustion decarbonization because the chemical bonds that form with 
the CO2 are weaker and easier to break and thus less energy/
heat is required in the regenerator. While chemical absorption is 
feasible, physical absorption is a more energy efficient capture option 
in pre-combustion capture.
    Pre-combustion appears to be very advantageous for many reasons. 
First, hydrogen can be used as a chemical or refining feedstock in 
addition to a fuel. Second, the higher concentrations of CO2 
can lead to more compact, less expensive equipment since less gas 
volume must be treated. Third, the high partial pressure of the 
CO2 means that it is easier to separate CO2 from 
the gas streams. Solvents that form weaker bonds (like MDEA) which 
require lower energy to restore/regenerate are suitable thereby 
reducing the cost of capture. Last, pre-combustion capture can be 
accomplished with techniques that are currently available. Natural gas 
reforming is currently practiced, and IGCC plants have been 
successfully demonstrated. All of these reasons make pre-combustion the 
best and cheapest option strictly for carbon capture. However, building 
the new IGCC plants would be more expensive from an overall perspective 
than building conventional plants without capture.

Oxy-fuel Combustion
    In oxy-fuel combustion, pure or nearly pure oxygen gas is used 
instead of air for combustion of fuels or biomass thereby eliminating 
nitrogen from the flue gas. The combusted gas is primarily composed of 
water and CO2. When fuel is burned in pure oxygen, the flame 
temperature is extremely high and the system has to be adapted in some 
way to withstand such heat. Combusting fuel in pure oxygen can occur at 
temperatures as high as 3500 degrees Celsius. Unfortunately, gas 
turbines can only withstand combustion temperatures of 1300-1400 
degrees Celsius and oxy-fuel coal-fired boilers can withstand 
temperatures of 1900 degrees Celsius. CO2-rich flue gas 
recycling and water stream injections are two proposed methods to 
moderate combustion temperature.\6\ After a flue gas clean up and 
cooling of the resulting flue gas to condense and separate out the 
water vapor, the flue gas has a CO2 concentration of 80-98 
percent. This CO2 rich stream can then be compressed, dried, 
and further purified before storage or use.\7\
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    \6\ http://www.delphi.ca/apec/Modules/Module3.pdf.
    \7\ http://www.ipcc.ch/activity/srccs/SRCCS_Chapter3.pdf.
---------------------------------------------------------------------------
    Advantages of this system include lower investment costs, higher 
concentrations of CO2 and smaller flue gas volumes that must 
be separated. Impurities like SOX, NOX, and 
mercury are more concentrated in the lower volumes of flue gas, making 
purification easier and cheaper. Furthermore, there is a reduction in 
NOX since nitrogen was eliminated when oxygen is used for 
combustion.
    The oxygen required for this system is currently produced by low-
temperature (cryogenic) air separation. First, air is compressed and 
cooled and water vapor is removed. Additional water vapor and 
CO2 are removed by adsorption in molecular sieves. Next, the 
stream is sent through a heat exchanger and is cooled to -300 degrees 
Fahrenheit via refrigeration. Then high and low pressure distillation 
columns are used to separate the air streams into oxygen and nitrogen. 
Cryogenic oxygen production generates oxygen with concentrations as 
high as 99.9 percent possible.\8\ It is an expensive process.
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    \8\ http://gcep.stanford.edu/pdfs/RxsY3908kaqwVPacX9DLcQ/
kobayashi_coal_mar05.pdf.
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Transportation
    The most economical way to transport large volumes of 
CO2 is by pipelines, which is where Kinder Morgan 
CO2 Company's expertise lies and, thus, will be the focus of 
this testimony in regards to CO2 transportation.

Safety
    CO2 is not as dangerous to transport by pipeline as 
other gases. It is not flammable, explosive, or poisonous. The main 
safety concern with transporting CO2 is asphyxiation 
resulting from oxygen being displaced in the surrounding air with 
CO2 originating from a leak in the pipeline. In addition, 
CO2 is denser than air, and should it leak from a pipe, it 
would collect in areas of low elevation. However, few accidents/leaks 
have been reported in CO2 pipelines. None of the dozen leaks 
that occurred between 1986 and 2006 resulted in any injuries to 
people.\9\
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    \9\ http://opencrs.cdt.org/rpts/RL33971_20070419.pdf.
---------------------------------------------------------------------------
    Although CO2 is not flammable or explosive, when in the 
supercritical, dense phase, it is extremely sensitive to temperature 
fluctuations. In basic terms, as temperature increases, so does 
pressure. However, this is not a linear relationship in the 
supercritical region (where the CO2 has the characteristics 
of both liquids and gases). Relatively slight increases in temperature 
can result in relatively large increases in pressure, thus potentially 
exceeding the yield stress of the steel pipeline causing a rupture. 
This is easily avoided with properly designed and installed pressure 
relief devices.
    In circumstances where hydrogen sulfide is present in the stream, 
considerations must be made regarding protection from hydrogen sulfide 
releases. This is done in part by correct material selection, properly 
designed and installed monitoring systems, and education of the 
operators and the public about exposure to hydrogen sulfide.
Costs
    In 2003, an estimate for the annual cost of transporting 
CO2 was $1.5-$2/metric-ton of CO2 per 62 miles 
for a mass flow rate of 2.16 MM metric-tons of CO2 per 
year.\10\ Pipeline costs can vary in different regions. Pipelines built 
near heavily populated centers or in areas with mountains, rivers, and 
other obstacles tend to have higher costs. Onshore pipelines are 
generally less expensive than offshore pipelines that operate at higher 
pressures and lower temperatures.\11\ Transportation cost rates also 
tend to drop when the amount of CO2 (throughput) and 
distance covered is increased. As a result, it is more economically 
efficient to transport large amounts of CO2 over substantial 
distances.
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    \10\ http://www.delphi.ca/apec/Modules/Module4.pdf.
    \11\ http://www.ipcc.ch/activity/srccs/SRCCS_Chapter4.pdf.
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Operation and Quality Specifications
    CO2 is transported in pipelines as a supercritical, 
dense phase fluid, operating above the critical pressure or 
temperature. The critical pressure for CO2 is 1,071 pounds 
per square inch (psi) and the critical temperature is 88 degrees F. If 
a fluid is above its critical pressure then no matter how much the 
temperature changes, there will be no condensation or vaporization 
i.e., two phases will never exist at the same time. This is important 
because transporting and metering a two phase mixture (liquid and gas) 
is difficult. Normally CO2 is transported between 60-90 
degrees F and between 1,500-2,200 psig; although, CO2 
pipelines often operate at higher pressures to overcome for the 
frictional losses as the CO2 flows through the pipes.
    Before it can be moved through a pipeline, the CO2 must 
first be dehydrated to remove water from the stream, which is usually 
accomplished by standard glycol dehydration. Water content is 
significant because when CO2 dissolves in water it forms 
carbonic acid which causes corrosion. In addition, hydrates can form 
that could cause blockages in the pipes and heat exchangers. To avoid 
these issues, the maximum allowable water content in CO2 
pipeline transportation is typically 30 lb/MMscf.\12\
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    \12\ http://uregina.ca/ghgt7/PDF/papers/poster/350.pdf.
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    Pipeline integrity is maintained using standard pipeline 
techniques. The most common method to determine the condition of a 
pipeline is in-line inspection also known as smart pigging. Intelligent 
pig technology is successfully used in pipelines transporting products 
other than CO2, but has not been sufficiently developed for 
CO2 pipelines. To prevent internal corrosion in a 
CO2 pipeline, the water is removed in the process plants by 
the use of dehydration systems. The water content is continuously 
monitored to maintain the pipeline water content specification. In 
pipelines upstream of dehydration, non-corroding materials are used.
    In addition to water, CO2 can also contain impurities 
such as hydrogen sulfide (H2S), SOX, 
NOX, oxygen, nitrogen, and hydrocarbons. The presence of any 
of these in the fluid stream can create challenges not only in 
CO2 transportation but in EOR injection as well; i.e., 
minimum miscibility pressure (MMP) requirements,\13\ selection of 
construction materials, required treatment processes, etc. Oil field 
operators normally want to inject CO2 that will be miscible 
with the reservoir oil at the reservoir conditions. To mitigate such 
challenges, the following should be taken into consideration:
---------------------------------------------------------------------------
    \13\ The MMP is the pressure at which CO2 EOR works at 
maximum efficiency.

------------------------------------------------------------------------
       Constituent           Maximum Recommended           Concern
------------------------------------------------------------------------
Water                     30 lbs/MMscf              Corrosion
Hydrogen Sulfide          10-20 ppm                 Safety/Materials
Oxygen                    10 ppm                    Corrosion
Nitrogen                  4%                        Increases MMP
Hydrocarbons              5%                        Increases MMP
Glycol                    0.3 gal/MMscf             Operations
Temperature               120 deg F                 Materials
------------------------------------------------------------------------

    Reasons for these limits are provided:
    Water--CO2 and free water combine to form carbonic acid 
which is very corrosive. Transporters of CO2 want to 
transport a completely non-corrosive substance. 30 lbs/MMscf is a 
standard limit for CO2 to avoid moisture dropout at lower 
pressures.
    Hydrogen Sulfide--10 ppm is the maximum concentration of hydrogen 
sulfide that a person can work in for 8 continuous hours in the United 
States based on Occupational Safety and Health Administration (OSHA) 
standards. Thus, new pipeline specifications for H2S may be 
a maximum of 10 ppm. The old OSHA standard was 20 ppm, so pipelines 
establishing an H2S specification during that time period 
may have 20 ppm as the upper limit. Special materials must be used to 
mitigate the potential for sulfide stress cracking if the 
H2S concentration is too high. In typical CO2 
pipeline applications operating at or below 2,200 psia, the 
H2S concentration can be up to 20 ppm without special 
metallurgical considerations.
    Oxygen--Oxygen is limited due to corrosion concerns.
    Nitrogen--Nitrogen in CO2 increases the minimum 
miscibility pressure of the oil/CO2 mixture.
    Hydrocarbons--Methane in CO2 increases the minimum 
miscibility pressure of the oil/CO2 mixture.
    Glycol--Pipeline operations are more difficult when glycol is 
slugging through the pipe. Glycol plugs instrumentation lines, clogs 
pump seal faces and is harmful to some analyzers.
    Temperature--120 degrees F is chosen because higher temperatures 
degrade polymers utilized in pipeline coatings.
    CO2 custody transfer meters are typically orifice 
meters, which is a well known, long standing technology. They are 
accurate to within 1 percent. Other meters are also used to measure 
CO2, including turbine meters and wedge meters, although 
their use is not as accepted for custody transfer but are often used 
for allocation purposed downstream of the custody transfer meter.
    If the CO2 is not pure, an important part of accurate 
measurement is determining the density and molecular weight of the 
CO2 mixture. The density is important because it is used in 
determining the flow rate. Density can either be measured with an in-
line densitometer or it can be calculated based on a compositional 
analysis and the static pressure. Where the composition barely changes 
(underground source fields), the industry moved away from using 
densitometers to using compositional analysis, first utilizing in-line 
chromatographs and then by taking monthly samples. Where the 
CO2 composition is variable (processing plant sources), 
densitometers are used.

Material Selection
    Selection of materials is critical when designing and constructing 
CO2 processing and transportation facilities. Three key 
focuses are on internal pipeline corrosion, elastomer materials, and 
the presence of hydrogen sulfide.
    According to Practical Aspects of CO2 Flooding (SPE 
Monograph, 2002), ``Corrosion has been a concern in CO2 
flooding from its inception. It is well known that when CO2 
dissolves in water, a small fraction hydrolizes to form carbonic acid. 
(The remainder exists as physically dissolved carbon dioxide). Carbonic 
acid dissociates to form bicarbonate ions, and hydrogen ions. Carbonic 
acid is quite corrosive to most carbon steels.'' In addition, ``the 
combination of hydrogen sulfide (H2S) and CO2 
dissolved in water causes higher corrosion rates than either acid gas 
alone.'' \14\
---------------------------------------------------------------------------
    \14\ ``CO2 Surface Facilities'', Version PF81-P-03-02-
06. John M. Campbell & Co., 2006.
---------------------------------------------------------------------------
    Thus, when water is present, Kinder Morgan utilizes certain 
materials to mitigate internal pipeline and piping corrosion. Most 
commonly used is stainless steel due to its corrosion resistant 
properties; however, the high material cost makes it less economical. 
An alternative to stainless steel is carbon steel lined with a high-
density polyethylene (HDPE). The HDPE liner creates an adequate barrier 
between the corrosive fluid and the carbon steel. Internally coated 
carbon steel piping is also used, although not as frequently due to 
certain logistical and economic challenges. All of these alternatives 
have a history of success in CO2 operations; the driving 
factor in determining which technology to use is cost, availability, 
and constructability.
    Another key issue to consider is that CO2 will diffuse 
into elastomeric compounds under pressure and temperature. Repeated 
pressurizing and depressurizing of CO2 into an elastomer can 
cause the phenomenon called explosive decompression which will cause 
damage to the physical properties of the elastomer. This damage is 
known as blistering or fracturing.
    Three factors effecting explosive decompression are: the rate of 
decompression, the permeability of the elastomer and the strength of 
the elastomer. It is difficult to control the rate of decompression but 
one may be able to control the number of decompressions which occur. 
Commonly used elastomers are rated as follows: Nitrile, 
Epichlorohydrine, Fluorocarbon (Viton), and EPDM. Most of these have 
some permeability to CO2.
    Kinder Morgan is not aware of any consensus among industry 
engineers and operations personnel concerning the ``right'' elastomer 
to use. There is general agreement, however, that an effective way to 
reduce explosive decompression is to increase the hardness (strength) 
of the elastomeric compound. Usually a durometer rating of at least 90 
is specified. Further research into elastomer technology would benefit 
future CO2 operation and development.
    As is the case in any pipeline or piping system containing hydrogen 
sulfide, one must take into consideration the general principals, 
requirements, and recommendations for selection of cracking resistant 
materials as provided in the NACE International Standard NACE MR0175/
ISO 15156.

Storage
    Some sedimentary basins are more suitable for CO2 
storage than others. Ideal CO2 storage formations generally 
have sufficient storage capacities, injection sites, seals, and stable 
geological environments. This means that sedimentary basins in the 
middle of tectonic plates, where there is less geological disturbance, 
are generally more secure. In addition, colder basins are preferred 
because they can store dense CO2 at relatively shallow 
depths of 2,000 to 3,000 feet underground.\15\ Mature storage 
formations like oil and gas fields are currently the most economic 
option for CO2 storage. Oil and gas fields are well defined, 
their natural ability to store hydrocarbons for thousands of years 
proves their integrity, and an infrastructure is in place. Depleting 
oil and gas reservoirs and unmineable coal beds are the best near term 
storage options because they are mature storage formations and have 
value added production of oil and methane (or other gases). Deep saline 
reservoirs are the best long term storage options because they 
represent the largest storage potential.
---------------------------------------------------------------------------
    \15\ http://www.ipcc.ch/activity/srccs/SRCCS_Chapter5.pdf.
---------------------------------------------------------------------------
Depleted Oil and Gas Fields
    Depleted oil and gas fields are promising geologic storage options 
for many reasons. First, oil and natural gases have been naturally 
stored in them for millions of years which prove that there is a 
natural seal. Second, there are years of industrial experience in the 
injection of CO2 and the disposal of acid gas which contains 
CO2. Third, many abandoned oil and gas fields have been 
studied at length. These containers have considerable storage capacity. 
In the U.S. alone, depleted oil and gas fields have been estimated to 
have the capacity to theoretically store 47 Gt of CO2. 
Worldwide, these containers could theoretically hold a total of 820 Gt 
of CO2.
    Trapping mechanisms usually employed in oil and gas reservoirs are 
structural and stratigraphic, residual, mineral, and solubility.\16\ 
CO2 is generally compressed and injected into porous rock 
that is isolated by a layer of non-porous rock. After injection, some 
of the CO2 will go into solution and some will react with 
the rock to form stable carbonates.
---------------------------------------------------------------------------
    \16\ http://www.pnl.gov/gtsp/docs/ccs_report.pdf.
---------------------------------------------------------------------------
    There are a few problems that exist with storing CO2 in 
oil and gas fields. For example, the process can be costly when the 
distance between the fields and capturing source can be significant. 
Leakage is also a concern. Poorly plugged wells could allow the 
CO2 to escape. Furthermore the injection pressure must be 
closely monitored so the process does not fracture the cap-rock.

Unmineable Coal Beds and CO2 Enhance Coal Bed Methane 
        Production
    Deep unmineable coal beds provide another set of possible 
CO2 storage containers. It is estimated that there are 6 
trillion tons of coal sources in the U.S. and 90 percent of them are 
considered to by unmineable.\17\ Located anywhere from 1,000 to 5,000 
feet deep, these coal seams could theoretically store 140 Gt of 
CO2 globally and 30 Gt of CO2 in just the 
U.S.\18\
---------------------------------------------------------------------------
    \17\ http://www.fossil.energy.gov/programs//sequestration/geologic/
index.html or http://www.
netl.doe.gov/publications/proceedings/98/98ps/ps4-8.pdf.
    \18\ http://www.pnl.gov/gtsp/docs/ccs_report.pdf.
---------------------------------------------------------------------------
    The trapping mechanism employed in coal beds is primarily chemical 
adsorption.\19\ Coal is naturally fractured. Coal beds often have 
methane adsorbed onto (and weakly bonded to) pore surfaces and drilling 
wells can extract this coal bed methane (CBM). Additional methane can 
be recovered by injecting of CO2 gas to displace the 
methane. Coal has a higher affinity for CO2 than it does for 
methane. When a stream of CO2 is sent through the fracture 
system of a coal bed, it is selectively adsorbed onto the surfaces of 
the coal, effectively releasing the previously adsorbed methane. The 
selectively adsorbed CO2 is less likely to move. For every 2 
or 3 molecules of CO2 adsorbed, one molecule of methane is 
released.\20\
---------------------------------------------------------------------------
    \19\ http://www.pnl.gov/gtsp/docs/ccs_report.pdf.
    \20\ http://www.netl.doe.gov/technologies/carbon_seq/index.html.
---------------------------------------------------------------------------
    After rapid surface adsorption, the CO2 begins to slowly 
diffuse into the coal as it is absorbed in the internal structure of 
the coal. When coal adsorbs a certain amount of CO2, some 
scientists think that the glass-to-rubber transition temperature of the 
coal is lowered. As a result, some of the coal will become plasticized, 
allowing for increased diffusion of CO2 through the 
molecular network. As pressure increases, more CO2 is 
thought to be adsorbed by the coal and thus the easier the coal is 
plasticized and even more CO2 can be absorbed and 
sequestered.\21\
---------------------------------------------------------------------------
    \21\ http://www.netl.doe.gov/publications/carbon_seq/presentations/
awma-2003CriticalReview
.pdf.
---------------------------------------------------------------------------
    Some scientists also theorize that as pressure increases, swelling 
of the coal increases. Coal swelling can be problematic in enhanced 
coal bed methane (ECBM) recovery. When CO2 is adsorbed, it 
swells making the coal much less permeable. This inhibits the flow of 
CO2 and thus limits the recovery of methane and the storage 
of CO2.
    Storage capacity of coal beds depends on many factors. For example, 
since adsorption increases at higher pressures, one would expect a 
greater storage capacity of a deeper coal bed. Higher temperatures, 
however, decrease the storage capacity. The water content of a coal bed 
can also affect the CO2 storage capacity of a coal bed. When 
CO2 mixes with water, compounds can form which can plug up 
the coal microstructure and restrict CO2 flow throughout the 
coal bed system. Drier coal beds can, thus, store more 
CO2.\22\ Dewatering of a coal bed is often required prior to 
CBM recovery.
---------------------------------------------------------------------------
    \22\ http://www.netl.doe.gov/publications/carbon_seq/presentations/
awma-2003CriticalReview
.pdf.
---------------------------------------------------------------------------
    Enhanced coal bed methane recovery can potentially increase the 
amount of methane produced up to 90 percent of the original amount.\23\ 
This increased production of methane reduces the cost of CO2 
storage in coal beds. The injected CO2 does not need to be 
pure. In fact, flue gas can be directly injected into the coal 
formation.
---------------------------------------------------------------------------
    \23\ http://www.ipcc.ch/activity/srccs/SRCCS_Chapter5.pdf.
---------------------------------------------------------------------------
Saline Formations
    Deep saline formations are the largest and most widespread of the 
CO2 storage options. These formations represent an enormous 
potential for CO2 storage. An advantage of the common 
aquifers is that the distance from the CO2 capturing source 
can be small. In fact, one source estimates that 65 percent of 
CO2 from U.S. power plants can be injected into saline 
formations without long pipeline transport.\24\ These formations of 
porous sedimentary rock are saturated with brine and can contain high 
concentrations of dissolved salts.\25\
---------------------------------------------------------------------------
    \24\ http://www.netl.doe.gov/publications/carbon_seq/presentations/
awma-25002003CriticalReview
.pdf.
    \25\ http://www.ipcc.ch/activity/srccs/SRCCS_Chapter5.pdf.
---------------------------------------------------------------------------
    The CO2 must be injected below 2,500 feet so that it is 
in a dense phase, either liquid or supercritical. Many of these storage 
sites are located 12,000 feet underground far below the reservoirs 
containing drinkable water. While the actual amount of CO2 
that can be stored is yet to be determined, the fact that they are the 
largest potential reservoirs is widely accepted and educated guesses 
have been made. One estimate predicts that 500 billion tons of 
CO2 could potentially be stored in these formations in the 
U.S.\26\ Another source estimates that there is a potential global 
storage capacity of 350-11,000 Gt of CO2.\27\
---------------------------------------------------------------------------
    \26\ http://www.fossil.energy.gov/programs//sequestration/geologic/
index.html.
    \27\ http://www.netl.doe.gov/publications/carbon_seq/presentations/
awma-2003CriticalReview.pdf.
---------------------------------------------------------------------------
    The important trapping mechanisms for aquifers include structural/
stratigraphic, hydrodynamic, solubility, and mineral trapping. 
Initially, CO2 is contained mostly by physical trapping 
mechanisms, but after enough time has passed for CO2 to 
react with the surrounding rock and fluid, solubility and mineral 
trapping means prove to be the primary trapping mechanisms.

Technical Barriers to Implementing Carbon Capture and Storage
    This section will discuss several of the technical barriers to an 
economic CCS process. It is divided into three subsections: capture, 
transportation and storage.

Capture
    The primary technical barriers to implementing CCS are economic. We 
know how to capture CO2, but the cost is prohibitive for 
society. Advances in several technologies could significantly reduce 
the cost of capture.

Post-Combustion Capture
    Due to the elevated costs, post-combustion capture is unlikely to 
become the technology of choice. Nevertheless, the installed base of 
power plants and industrial processes makes research into reducing 
costs in this area advisable. Specific research topics could include 
creating chemical absorbents which are better able to tolerate 
impurities and regenerate at lower energy cost. Research could also be 
conducted on producing steel which corrodes less quickly in the 
presence of these chemical absorbents.

Pre-Combustion Capture
    Pre-combustion capture may be the most productive area of research. 
We know that gasification and similar processes work; however, due to a 
cost premium in a non-carbon constrained world, these processes are not 
widely pursued. Demonstration projects such as FutureGen would assist 
industry in designing more economical power plants.

Oxy-Fuel Combustion
    Oxy-fuel combustion seems further from commercialization than 
gasification (post combustion capture). Nevertheless, research into 
lowering the cost of producing pure oxygen and into developing 
materials that can withstand higher temperatures could prove 
productive.

Transportation
    Better tools with which to inspect CO2 pipelines are 
needed. The most common method to determine the condition of a pipeline 
is in-line inspection also known as smart pigging. When pigs are sent 
through a CO2 pipeline, the CO2 entrains into the 
sealing elements which keep the CO2 from contacting the 
electronics in the tool. When pigs are pulled from the pipeline, the 
elastomers swell and often destroy the pig. The pipeline industry has 
successfully tested smart pigs in smaller diameter pipelines, but 
larger diameter pigs need to be built and the industry needs to 
determine if smart pigging CO2 pipelines has unique 
elements.
    Transporting flue gas may be required. Since flue gas is highly 
corrosive, some research into this technology may be warranted.

Storage
    While CO2 has been injected into the ground for many 
years, the energy industry focused on monitoring the CO2 
over the span of years or decades not centuries. Several technologies 
already should be enhanced to better track the movement of 
CO2 in the subsurface. Seismic and a related technology, 
cross well tomography, can be better tuned to detect the presence of 
CO2 and therefore monitor the movement of CO2. 
Reservoir simulation can be improved to better model the movement of 
CO2 and the interaction of the CO2 with the rock. 
Mineralization, the process by which CO2 converts from a gas 
or liquid into rock needs more study.

General
    Several technologies which can be improved are common across the 
CCS processes. These technologies include compression, seal elements/
elastomer selection and corrosion control. Compression is one of the 
largest costs in CCS. More efficient methods of compression could 
significantly reduce costs. CO2, due to its low viscosity 
and tendency to remove hydrocarbon based sealants like grease, has a 
propensity to escape through valves. Improving sealing elements or 
elastomers would reduce CO2 losses to the atmosphere. 
CO2 and water form carbonic acid a highly corrosive 
substance. Where the CO2 cannot remain dehydrated, improved 
coatings and metals would reduce costs and inadvertent losses to the 
environment.

Non-Technical Barriers to Implementing Carbon Capture and Storage
    There are three categories of non-technical barriers to 
implementing carbon capture and storage: economic, legal and 
commercial. At this time, it is generally not economic to engage in 
carbon capture activities. Some legal uncertainties must be clarified 
before CCS can move forward, and commercial terms between various 
parties must be negotiated. Government action at the Federal and state 
level is needed to solve the first two barriers. Commercial issues can 
be worked between private parties once the playing field has been 
defined.
    Some of these barriers can be illustrated by examining how CCS and 
CO2 EOR could combine. When we talk about widespread CCS, 
people envision capturing CO2 from power plants and storing 
it in the ground. Because there is an economic benefit to using 
CO2 for EOR, and because the legal framework for EOR is 
already in place, many people think that EOR will a first step in 
developing the business; however, even with EOR, CCS cannot proceed 
without significant government action.
    When CO2 is used in EOR, it is an industrial commodity 
that must be supplied in relative abundance at an economic price. The 
only successful sources of CO2 for EOR have been natural 
underground CO2 fields, natural gas plants where nearly pure 
CO2 is stripped from the gas stream to make natural gas 
saleable, and a coal gasification plant. The reason is cost.
    For the past 25 years the price that oil producers have been 
willing to pay for CO2 is 3-4 percent of the oil price where 
the oil price is measured in $/barrel of oil and the CO2 is 
priced in terms of dollars per thousand cubic feet (MCF). This is based 
on personal knowledge of CO2 prices and oil prices over the 
period plus a series of economic evaluations of oil field projects 
while I worked at Shell and Kinder Morgan. That doesn't mean that 
today, with prices trending toward $100 per barrel, producers are 
willing to buy CO2 at $3-$4 per MCF ($57.75-$77.00 per 
metric ton). At this time, most producers are unwilling to bet on $100 
oil. With respect to investments in CO2 floods, they seem to 
be betting on $50 oil over the long haul which means that 
CO2 prices must be in the $30-$40 per metric ton range.
    The Intergovernmental Panel on Climate Change (IPCC) published a 
Special Report on CO2 Capture and Storage. In it they 
compared cost estimate for carbon capture for several technologies: 
retrofit of existing pulverized coal (PC) plants for capture ($31-$56 
per metric ton), installation of capture facilities in of new PC plants 
($23-$35 per metric ton), retrofit of natural gas combined cycle plants 
for capture and installation of capture facilities in new NGCC plants 
($33-$57 per metric ton) and installation of capture equipment in new 
integrated gasification and combined cycle plants (IGCC) ($11-$32 per 
metric ton). Only the gasification plant could reliably supply 
CO2 at price where the buyer could afford to transport the 
CO2 to an oil field.\28\
---------------------------------------------------------------------------
    \28\ The IPCC cost estimates were made in 2003-2005. During that 
period, based on the oil prices of that time, the CO2 price 
delivered at the field needed to be in the range of $12-$38 per metric 
ton. Since transportation costs are about $10 per metric ton per 100 
miles, transportation costs are about $10 per metric ton per 100 miles, 
only IGCC can supply CO2 at economic prices. Also note that 
since 2005, construction costs and energy costs which are the drivers 
of capture costs, have increased significantly.
---------------------------------------------------------------------------
    Because EOR provides an economic offset to carbon capture and 
storage, it may provide a first step for storage in some parts of the 
country. The legal framework regulating the injection of CO2 
into oil fields exists; however, some legal issues present themselves 
when an EOR project progresses to a storage project. The right to 
inject CO2 arises from the right to capture the minerals. 
Oil companies may inject CO2 in order to recover the 
minerals. On the other hand, oil companies have not purchased the right 
to access the pore space to store CO2. There is now some 
consensus that the pore space is owned by the surface owner and not the 
mineral owner. How does one define when EOR becomes storage? Can a 
surface owner block an EOR project from progressing to a storage 
project?
    Similar issues arise with respect to injection into saline 
aquifers. While there may be no competing mineral interests, at least 
with oil fields, a land area had been set aside for development. A 
large area may be needed to store the CO2. Will 
CO2 storage operators need to use condemnation in order to 
gather an appropriate injection area? What rights would condemnation 
give an operator to use the surface?
    Also of note is the liability for the storage site. This is both a 
commercial and legal challenge. The public does not want to pay for 
storage that is ineffective. Companies do not want to incur an eternal 
liability. Insurance companies may not be willing to insure facilities 
for leakage.
    Commercial terms must be developed between the power companies, 
capture companies, transportation companies, storage companies and 
monitoring companies. For example, the power companies prefer not to 
pay for removal of hydrogen sulfide from the CO2. 
Transportation companies prefer not to handle high concentrations of 
hydrogen sulfide because it is deadly at low concentrations. With 
respect to the structure of the industry, it is possible that power 
companies may vertically integrate from capture to storage. There will 
always need to be a third party to verify to the public and government 
that the storage site is operated properly.
    Finally, the public will need to feel that its safety is not 
compromised and that the environment will not be unduly affected. 
Finally the public needs to accept CCS as safe and effective. The 
public trusts the government and academia more than industry. They must 
take the lead in selling this carbon control solution to the public.

    Senator Kerry. Thank you very much, Mr. Fox, those were 
interesting questions.
    Dr. Benson?

  STATEMENT OF PROFESSOR SALLY M. BENSON, EXECUTIVE DIRECTOR, 
              GLOBAL CLIMATE AND ENERGY PROJECT, 
                      STANFORD UNIVERSITY

    Dr. Benson. Good afternoon, Mr. Chairman, and Members of 
the Subcommittee, thank you for the opportunity to talk with 
you today. I am Sally Benson, a Professor at Stanford 
University, and Executive Director of the Global Climate and 
Energy Project.
    The science behind carbon sequestration builds on concepts 
developed over a century in the oil and gas industry. Safe and 
secure sequestration can be achieved by injecting carbon 
dioxide into porous rocks, and trapping it underneath thick and 
continuous fine-textured rock, or so-called seals.
    Two mechanisms are responsible for trapping, and we know 
they are effective, because these are the exact same mechanisms 
that are responsible for the existence of oil and gas 
reservoirs. On this basis, it's straightforward to conclude 
that sequestration in oil and gas reservoirs is feasible.
    So, what about other types of formations that have been 
proposed for sequestration? Saline aquifers are extremely 
important sequestration resources, because they have the 
largest capacity, and are located closer to more emission 
sources. The sealing mechanisms for saline aquifers are the 
same as for oil and gas reservoir, but here we need scientific 
proof that the seals are sufficiently thick, have uniformly 
good sealing properties, and are not penetrated by active 
faults.
    While in principle, sequestration is straightforward, in 
practice, there is a great deal of science and engineering that 
underpins safe and effective sequestration, for example, 
seismic imaging for assessing and monitoring sequestration 
projects, and computer simulation models to predict 
sequestration performance.
    In addition, while there are many reasons to conclude that 
sequestration is feasible, the question of scale can not be 
ignored. Today, there are three active sequestration projects. 
To make a significant impact on emissions reductions, thousands 
of projects will be needed, and each of these will be from five 
to ten times larger than any of the existing projects. The 
potential for unforeseen consequences of large-scale 
sequestration must be assessed, and methods to avoid them 
developed.
    Worldwide, public and private research efforts continue to 
make steady progress on these issues. For example, last summer 
the Department of Energy funded an experiment to answer the 
question, what's the smallest leak that could be detected? 
Field testing results proved that a number of existing and 
innovative techniques have the sensitivity needed for reliable 
monitoring.
    As another example, over the past several years, the 
Department of Energy has funded two pilot tests in Texas. These 
tests demonstrated that the location of the plume could be 
tracked and modeled. The regional sequestration partnerships 
will replicate these tests in different geological 
environments, providing valuable firsthand knowledge and 
experience for state and local regulators, who will one day be 
called upon to oversee these projects.
    As a final example, the Global Climate and Energy Project 
has developed new theoretical models to predict how quickly 
secondary trapping mechanisms could permanently immobilize 
carbon dioxide, thus further reducing the potential for 
leakage.
    There is also an urgent need for demonstration projects at 
a scale commensurate with the five to ten million tons per year 
of carbon dioxide emitted from a large coal-fired power plant. 
Plans are underway for a number of publicly and privately 
funded demonstration projects, and it is important that these 
get started now. Without definitive results from these, and 
even larger scale tests, policymakers, investors and society 
will not have the confidence to proceed with widespread 
deployment of CCS.
    As interest in sequestration has grown, so too has the 
concern about long-term stewardship and liability. Who will be 
responsible for long-term monitoring? Who will pay to remediate 
a site if it starts to leak 100 years from now? The prospects 
of long-term stewardship and long-term financial responsibility 
make investors nervous, and if not addressed, will create a 
barrier to widespread deployment.
    In part, answers to these questions are legal and 
institutional in nature. However, scientific research has a 
role to play in bounding the probability of unforeseen events, 
in providing a scientific framework for addressing these 
issues.
    In particular, naturally occurring secondary trapping 
mechanisms, such as converting the carbon dioxide into solid 
minerals, can provide additional storage security, and these 
processes become more effective as time passes. Fundamental 
research is needed to quantify the potential and framework for 
completely reducing the risk of leakage, and for learning how 
to accelerate these processes, if needed.
    Long-term stewardship and financial responsibility are much 
less daunting if the risk of unforeseen events can be shown to 
predictably decrease with time.
    Now, coming to your final question--are there gaps in the 
public and private research activities? Certainly growth in 
Federal support for sequestration research has been impressive 
over the past decade, increasing from nearly nothing 10 years 
ago, to over $100 million in 2007.
    Industrial support is also growing. But while growth in 
interest and support is encouraging, at the current pace of 
progress, convincing answer about safety and effectiveness may 
not be available for more than a decade. Accelerating the pace 
of progress requires commitment to a parallel development 
pathway, simultaneously building a strong, fundamental science 
program, providing sufficient financial resources for the pilot 
projects, in order to learn as much as possible from them, and 
expediting full-scale demonstration projects.
    In closing, carbon sequestration is a promising and 
necessary technology. Thank you very much for the opportunity 
to discuss this important topic with you.
    [The prepared statement of Dr. Benson follows:]

 Prepared Statement of Professor Sally M. Benson, Executive Director, 
         Global Climate and Energy Project, Stanford University

    Good afternoon. Senator Kerry and Members of the Subcommittee, 
thank you for the opportunity to talk with you today. I am Sally 
Benson, a Professor at Stanford University and Executive Director of 
Stanford's Global Climate and Energy Project.

The Science Behind Safe and Effective Sequestration
    The science behind safe and effective carbon dioxide sequestration 
builds on concepts developed from over a century of experience in the 
oil and gas and groundwater supply industries. Safe and secure 
sequestration can be achieved by injecting carbon dioxide into porous 
rocks and trapping it underneath thick and continuous fine-textured 
rocks or so-called ``seals.'' \1\ Two mechanisms are responsible for 
trapping \2\ and we know they are effective because these are the exact 
same mechanisms that are responsible for the existence of oil and gas 
reservoirs.
---------------------------------------------------------------------------
    \1\ Since the density of carbon dioxide is less than water, 
unimpeded, when injected underground, it would migrate back to the land 
surface. Therefore ``seals'' are needed to trap carbon dioxide 
underground.
    \2\ Two mechanisms are responsible for effective trapping by seals: 
extremely low permeability--which limits the rate of flow through the 
seals; and extremely high capillary entry pressure--which prevents any 
separate phase carbon dioxide from moving into the seal (IPCC Special 
Report on Carbon Dioxide Capture and Storage, 2005, Cambridge 
University Press).
---------------------------------------------------------------------------
    On this basis, it is straight forward to conclude that 
sequestration in oil and gas reservoirs is feasible. So what about the 
other types of formations that have been proposed for sequestration?
    Saline aquifers are extremely important sequestration resources 
because they have the largest capacity and are located closer to more 
emission sources. The sealing mechanisms for saline aquifers are the 
same as for oil and gas reservoirs--but here we need scientific proof 
that the seals are sufficiently thick, have uniformly good sealing 
properties, and are not penetrated by active faults.
    While, in principle, sequestration is straight forward--in practice 
there is a great deal of science and engineering that underpin safe and 
effective sequestration, for example: geophysical imaging to locate and 
assess sequestration reservoirs and seals; computer simulation models 
to predict sequestration performance; and geophysical monitoring 
technology to assure that the carbon dioxide remains sequestered.
    In addition, while there many reasons to conclude that 
sequestration is feasible--the question of scale cannot be ignored. 
Today there are three active sequestration projects.\3\ To make a 
significant impact on emission reductions, thousands of projects will 
be needed--and each of the projects will be from 5 to 10 times larger 
than any of the existing projects. The potential for unforeseen 
consequences of large scale sequestration must be assessed and methods 
to avoid them developed.
---------------------------------------------------------------------------
    \3\ The three existing sequestration projects are the Sleipner 
Project off-shore of Norway, the Weyburn Project in Saskatchewan, and 
the In Salah Project in Algeria. The Sleipner Project began in 1996 and 
sequesters 1 Mt/year of CO2 in a saline aquifer. The Weyburn 
Project, which began in 2000, is a combined CO2 EOR and 
sequestration project that injects about 2 Mt/yr into an oil reservoir. 
The In Salah Project began in 2004 and sequesters about 1 Mt/yr in a 
depleting gas reservoir. A fourth project, the Snohvit Project, is 
expected to begin injecting 0.7 Mt/yr into a saline aquifer under the 
Barents Sea in 2007.
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Progress on Research and Development
    World-wide, public and private research efforts continue to make 
steady progress on basic and applied research that address these 
issues. For example:

   Last summer, the Department of Energy funded an experiment 
        to answer the question--what is the smallest leak that could be 
        detected? \4\ Field testing results proved that a number of 
        existing and innovative techniques could detect and quantify 
        extremely low leakage rates--and have the sensitivity needed 
        for reliable monitoring.
---------------------------------------------------------------------------
    \4\ The Detection Verification Facility is collaboration between 
several universities and national laboratories lead by Montana State 
University. The experiment showed that leakage of 100 kg/day over a 100 
m long feature could be detected and quantified using flux accumulation 
chambers. A second experiment demonstrated that 300 kg/day could be 
detected and quantified by several methods.

   As another example, over the past several years, the U.S. 
        DOE has funded two pilot tests in Texas--the so-called Frio I 
        and Frio II tests.\5\ These tests demonstrated that high-
        resolution seismic methods successfully tracked migration of 
        the plume and that, after calibration, computer simulation 
        models could predict where and how fast the carbon dioxide 
        moved. The U.S. DOE Regional Partnerships will replicate these 
        types of tests in a number of different geological 
        environments, providing valuable first-hand knowledge and 
        experience for state and local regulators who will one day be 
        called upon to oversee these projects.
---------------------------------------------------------------------------
    \5\ The Frio Pilot Tests, lead by the University of Texas at 
Austin, are a collaboration between university and national laboratory 
scientists. The first test in 2003 injected about 1,600 tons of carbon 
dioxide. The second test in 2006 injected about 500 tons. Extremely 
valuable scientific results were gained from the small-scale pilot 
tests, including new methods for tracking migration of carbon dioxide 
movement in the surface, fundamental insights about multi-phase flow of 
carbon dioxide and brine, and geochemical interactions between carbon 
dioxide and the reservoir rocks.

   As a final example, the Global Climate and Energy Project at 
        Stanford University \6\ has developed new theoretical concepts 
        to predict how quickly secondary trapping mechanisms \7\ could 
        permanently immobilize carbon dioxide--thus further reducing 
        the potential for leakage, even if, for example, degrading 
        cement in an old abandoned well breached the reservoir seal.
---------------------------------------------------------------------------
    \6\ The Global Climate and Energy Project at Stanford University 
funded by ExxonMobil, GE, Toyota and Schlumberger, performs fundamental 
breakthrough research to develop a wide range of low-carbon and carbon-
free energy supply technologies--including carbon sequestration. http:/
/gcep.stanford.edu/.
    \7\ Secondary trapping mechanisms include dissolutions of 
CO2 in brine, capillary trapping and mineralization (IPCC 
Special Report on Carbon Dioxide Chapter and Storage, Cambridge 
University Press, 2005).

    There is a also an urgent need for demonstration projects--at a 
scale commensurate with sequestering the 5 to 10 million tons of carbon 
dioxide emitted annually from a typical coal-fired power plant. Plans 
have been announced or are now underway in the U.S. for at number of 
publicly \8\ and privately \9\ funded mid-to-large scale demonstration 
projects--and it is important they get started now. Without definitive 
results from these and even larger scale tests, policymakers, investors 
and society will not have the confidence needed to proceed with 
widespread deployment of CCS.
---------------------------------------------------------------------------
    \8\ Federally funded project include FutureGen and 3 recently 
announced sequestration projects carried out by the Plains Carbon 
Dioxide Reduction Partnership; Southeast Regional Carbon Sequestration 
Partnership; and Southwest Regional Partnership for Carbon 
Sequestration. All will conduct large volume tests for the storage of 
one million tons of carbon dioxide (CO2) in deep saline 
reservoirs.
    \9\ Announcements for privately funded mid-to-large scale projects 
in the U.S. have been made by a number of companies. Examples include 
the BP Carson project and AEP's projects in West Virginia and Oklahoma. 
All of these are in the planning stage.
---------------------------------------------------------------------------
Barriers to Implementing Geological Storage
    As interest in sequestration has grown, so too has the concern 
about long term stewardship and liability grown. Who will be 
responsible for long term monitoring? Who will pay to remediate a site 
if it starts to leak 100 years from now? The prospects for long term 
stewardship and long term financial responsibility make investors 
nervous--and if not addressed they will create a barrier to widespread 
deployment. In part, answers to these questions are legal and 
institutional in nature. However, scientific research has a large role 
to play in bounding the potential for unforeseen events and providing a 
scientific framework for addressing these issues.
    In particular, naturally occurring secondary trapping mechanisms 
such as dissolving carbon dioxide into water, forming minerals, and 
capillary trapping can provide additional storage security--and these 
processes become more effective as time passes. Fundamental research is 
needed quantify the potential and time-frame for completely reducing 
the risk of leakage and for learning how accelerate these processes if 
needed. Long term stewardship and financial responsibility are much 
less daunting if the risk of unforeseen events can be shown to 
predictably decrease with time.

Gaps in Public and Private Research Activities
    Now, coming to your final question--are there gaps in public and 
private research activities? Certainly, growth in Federal support for 
sequestration research has been impressive over the past decade--
increasing from nearly nothing 10 years ago to over $100 M in 2007. 
Industrial support is also growing. But, while growing interest and 
support is encouraging, at the current pace of progress, convincing 
answers about safety and effectiveness may not be available for more 
than a decade. Accelerating the pace of progress requires commitment to 
a parallel development pathway, simultaneously

   building a strong fundamental scientific program; \10\
---------------------------------------------------------------------------
    \10\ DOE's Office of Science conducted a workshop in research 
opportunities in the geosciences related to sequestration (Basic 
Research Needs for Geosciences: Facilitating 21st Century Energy 
Systems, http://www.sc.doe.gov/bes/reports/files/GEO_rpt.pdf). Five 
priorities for improving our understanding of multiphase flow were 
identified:

     New approaches are needed to accurately predict migration 
of multiple fluid phases in environments that are highly heterogeneous, 
from the pore scale to the basin scale--over large spatial scales and 
long time-frames.

     Methods to quantify and predict rates of geochemical 
reactions between multi-phase, multi-component fluids and minerals are 
needed to understand how quickly dissolution and mineralization will 
occur.

     Fundamental scientific understanding of basin-scale 
geomechanical processes is needed to predict shallow crustal 
deformation and basin scale brine displacement caused by large and 
rapid anthropogenic perturbations such as injection or extraction of 
multiphase fluids in the subsurface.

     A new multi-disciplinary approach is needed to assess the 
multi-phase flow properties of membrane seals, faults and fractures--in 
order to determine whether or not a geological reservoir has an 
adequate seal.

     Dynamic field-scale imaging is needed to test and validate 
multi-phase flow models.

   providing sufficient financial resources for the pilot 
---------------------------------------------------------------------------
        projects in order to learn as much as possible from them; and

   expediting full-scale demonstration projects.

    Effective communication and coordination of these three parallel 
development pathways will also maximize progress and ensure efficient 
use of resources.
    In closing, carbon sequestration is a promising and necessary 
technology. Thank you very much for the opportunity to discuss this 
important topic with you.

    Senator Kerry. Thank you very much, Dr. Benson.
    Dr. Burruss?

          STATEMENT OF DR. ROBERT C. BURRUSS, RESEARCH

       GEOLOGIST, ENERGY RESOURCES TEAM, U.S. GEOLOGICAL

            SURVEY, U.S. DEPARTMENT OF THE INTERIOR

    Dr. Burruss. Mr. Chairman and Members of the Subcommittee, 
I'm Robert Burruss, a research geologist with the U.S. 
Geological Survey. Thank you for the opportunity to present 
testimony on geological sequestration of carbon dioxide. I will 
also briefly discuss terrestrial carbon sequestration.
    Of particular importance is the evaluation of the potential 
geologic storage capacity for CO2 and understanding 
the impact of the natural carbon cycle on the role of 
terrestrial sequestration to limit accumulation of 
CO2 in the atmosphere.
    Fossil fuel usage, a major source of carbon dioxide 
emissions into the atmosphere will continue in both 
industrialized and developing nations. The fraction of carbon 
emissions from all sources that must be eliminated to impact 
climate is large. For example, scenarios that stabilize 
CO2 concentrations at about 550 parts per million, 
suggest that emissions may need to be reduced by as much as 70 
percent. Reductions of this magnitude will involve many types 
of carbon management, including geologic and terrestrial 
sequestration, but also shifts from fossil fuels to biofuels, 
increased electricity generation from solar, wind and nuclear 
power, and increased efficiency of generation, transmission and 
end-use.
    In geologic sequestration, carbon dioxide is separated from 
flue gas and injected into subsurface rock formations at depths 
of one to three kilometers. At these depths, CO2 has 
the properties of a low-density liquid, it displaces the fluid 
that initially occupied the porous space, and rises buoyantly 
until it is retained beneath a non-permeable rock formation, 
otherwise known as a seal.
    A critical issue for evaluation of storage capacity is the 
integrity and effectiveness of these seals, especially in 
saline reservoirs. The IPCC Special Report on Carbon Dioxide 
Capture and Storage, concluded that the global storage capacity 
of geologic formations may be able to accommodate a large 
fraction of the captured carbon dioxide necessary to stabilize 
atmospheric concentrations between 250 and 750 ppm.
    However, geologic storage capacity varies on a regional and 
national scale, and better understanding of storage capacity is 
needed to address this knowledge gap. USGS experience with 
national and international assessments of natural resources 
provides the basis to develop a peer-reviewed set of methods to 
assess the distribution of the Nation's capacity for geologic 
storage of CO2.
    In addition, USGS knowledge of regional groundwater aquifer 
systems and groundwater chemistry will allow development of 
methods to assess the storage capacity of saline reservoirs. 
Saline reservoirs have the potential for very large storage 
capacities, but the extent to which these capacities can be 
utilized remains unknown.
    There are research questions that are important for 
addressing the performance and risks associated with wide scale 
deployment of geologic sequestration. These include 
understanding the capabilities of seals to recoup carbon 
dioxide, the potential role of abandoned wells to act as 
migration pathways for CO2 and formation water, and 
the potential for injected CO2 to mobilize naturally 
occurring trace metals and organic materials.
    Carbon can also be stored in the biosphere. Terrestrial 
sequestration attempts to enhance transfer and retention of 
CO2 from the atmosphere into vegetation and soils.
    While terrestrial storage of carbon can be enhanced by 
appropriate land use and soil management practices, the 
potential reductions in atmospheric CO2 are closely 
tied to the natural processes of the global carbon cycle. 
Although we know that naturally stored carbon is vulnerable to 
release to the atmosphere in a changing climate, the processes 
that preserve carbon in soils are poorly understood and 
represent a critical knowledge gap in evaluating the potential 
of terrestrial carbon sequestration to limit accumulation of 
CO2 in the atmosphere.
    In conclusion, it is clear that the challenge of reducing 
atmospheric carbon dioxide levels through both geological and 
terrestrial sequestration is a complex issue, evaluation of 
geologic storage capacity for carbon dioxide is needed to 
determine the full impact of this technology on climate change.
    This information, combined with research on the feedbacks 
between terrestrial carbon sequestration, the carbon cycle, and 
climate change, will provide a scientific foundation for 
decisions regarding all types of carbon management.
    Thank you for the opportunity to present this testimony, 
and I will be pleased to answer any questions you and the 
Members of the Committee have.
    [The prepared statement of Dr. Burruss follows:]

Prepared Statement of Dr. Robert C. Burruss, Research Geologist, Energy 
Resources Team, U.S. Geological Survey, U.S. Department of the Interior

    Mr. Chairman and Members of the Subcommittee, thank you for the 
opportunity to present testimony on terrestrial sequestration and 
geologic capture and storage of carbon dioxide and their role in 
reducing atmospheric carbon. In addition to these topics, I also plan 
to discuss in my statement today the role of science in evaluating the 
potential geologic storage capacity for industrial carbon dioxide and 
in furthering our understanding of the carbon cycle.

Introduction
    Let me begin by saying that the challenges of addressing carbon 
dioxide accumulation in the atmosphere are significant. Fossil fuel 
usage, a major source of carbon dioxide emissions to the atmosphere, 
will continue in both industrialized and developing nations. Therefore, 
a variety of strategies are being investigated to reduce emissions and 
remove carbon dioxide from the atmosphere. Such strategies include the 
facilitated sequestration of carbon from the air to terrestrial 
biomass, including soils and the capture and storage of carbon dioxide 
in geologic formations.
    The current atmospheric carbon dioxide concentration is 
approximately 380 parts per million volume and rising at a rate of 
approximately 2 parts per million volume annually, according to the 
most recent information from the Intergovernmental Panel on Climate 
Change (IPCC). The fraction of carbon emissions from all sources that 
must be eliminated or sequestered to impact the magnitude of climate 
change is large. For example, to stabilize carbon dioxide 
concentrations at about 550 parts per million volume, the extent to 
which carbon dioxide emissions would need to be reduced may be as much 
as 70 percent. Reductions of this magnitude could involve 
implementation of several mechanisms, including geologic storage and 
biological sequestration, fuel shifts from fossil sources to renewable 
biological sources, increased electricity generation from solar and 
wind systems and nuclear power, and increased efficiency of power 
generation, transmission, and end use. Each of these mechanisms has 
distinct geological, hydrological, ecological, economic and social 
implications that should be assessed on a wide range of scales, from 
molecular to basin scales, to allow informed policy discussions and 
decisions on implementation and deployment of technologies.

Geologic Storage of Carbon
    The 2005 IPCC Special Report on Carbon Dioxide Capture and Storage 
concluded that, in emissions reductions scenarios striving to stabilize 
global atmospheric carbon dioxide concentrations at targets ranging 
from 450 to 750 parts per million volume, the global storage capacity 
of geologic formations may be able to accommodate most of the captured 
carbon dioxide. However, geologic storage capacity may vary on a 
regional and national scale, and a more refined understanding of 
geologic storage capacity is needed to address this knowledge gap.
    Geological storage of carbon dioxide in porous and permeable rocks 
involves injection of carbon dioxide into a subsurface rock unit and 
displacement of the fluid or formation water that initially occupied 
the pore space. This principle operates in all types of potential 
geological storage formations such as oil and gas fields, deep saline 
water-bearing formations, or coal beds. Because the density of injected 
carbon dioxide is less than the density of formation water, carbon 
dioxide will be buoyant in pore space filled with water and rise 
vertically until it is retained beneath a nonpermeable barrier (seal). 
A critical issue for evaluation of storage capacity is the integrity 
and effectiveness of these seals.

Terrestrial Carbon Sequestration
    Terrestrial carbon sequestration practices seek to effect the 
transfer of carbon between the atmosphere and terrestrial biosphere 
(the earth and the living organisms that inhabit it) to reduce 
atmospheric carbon dioxide concentrations. Land management practices in 
the United States can affect the transfer of carbon from terrestrial 
systems into the atmosphere. Land conversion, especially deforestation, 
continues to be a significant source of global carbon dioxide 
emissions. Good land stewardship practices can reverse this and enhance 
biological uptake of carbon dioxide from the atmosphere, an approach 
termed terrestrial sequestration. Many of these practices, including 
tree planting and conservation tillage, are widely adopted and well 
understood. The Department of Agriculture is promoting the adoption of 
these practices through conservation programs implemented under the 
Farm Bill. The knowledge gained on the benefits of terrestrial 
sequestration will improve our understanding of the duration and extent 
to which the biological uptake of atmospheric carbon dioxide can be 
enhanced to reduce atmospheric concentration of carbon dioxide.

Role of the U.S. Geological Survey
    While the USGS currently has no experience assessing the national 
geologic storage capacity, USGS-generated data and information were 
included in the Carbon Sequestration Atlas of the United States and 
Canada developed by the Department of Energy. In addition, our 
experience with national and international assessments of natural 
resources could allow USGS to develop geologically based methodologies 
to assess the national capacity for geologic storage of carbon dioxide. 
We envision the national geologic carbon dioxide storage assessment 
methodology would be largely analogous to the peer-reviewed 
methodologies used in USGS oil, gas, and coal resource assessments. In 
addition, the USGS' knowledge of regional groundwater aquifer systems 
and groundwater chemistry would allow USGS to develop methods to assess 
potential carbon storage in saline aquifers. Previous studies have 
postulated the existence of very large carbon dioxide storage 
capacities in saline aquifers, but the extent to which these capacities 
can be utilized remains unknown.
    The USGS could create a scientifically based, multi-disciplinary 
methodology for geologic carbon dioxide storage assessment that can be 
consistently applied on a national scale. Some potential areas for 
further study include understanding the capabilities of seals to retain 
carbon dioxide and the role of abandoned wells that may act as 
migration pathways for carbon dioxide and formation water; defining the 
potential for mobilization of trace metals and organic materials by 
carbon dioxide reactions with minerals or dissolution of organic 
compounds; and understanding the role of bacteria and other 
microorganisms in water-rock-carbon dioxide interactions relevant to 
storage.
    There are also a number of potential issues for further study 
pertaining to terrestrial sequestration, including the natural 
processes that affect carbon cycling. It is now widely recognized that 
the global carbon cycle and climate varied together, before human 
influence, as interactive components in a highly complex system of 
global feedbacks. These feedbacks have profound implications for the 
response of climate to anthropogenic carbon dioxide emissions, and for 
the potential response of the carbon cycle to changes in climate.
    Along with our partners in the Department of Agriculture, the 
Department of Energy, and other agencies, ongoing USGS research 
addresses these issues. In particular, USGS research on soil carbon 
dynamics focuses on soil development and the buildup and stabilization 
of soil organic matter, a large carbon reservoir in the terrestrial 
biosphere, which play key roles in water distribution, and in turn 
control both sediment transport and carbon production and respiration. 
This research is critically important in explaining the processes 
affecting the flow of carbon dioxide from soils. The response of soils 
to human land use is a significant component in the global carbon 
dioxide budget, and their response to climate change may cause 
significant feedback on a global scale. Land use--particularly 
agriculture--significantly alters patterns of terrestrial carbon 
storage and transport, nutrient cycles, and erosion and sedimentation. 
Current models of the terrestrial carbon cycle do not adequately 
account for the interactions among changes in erosion, sedimentation, 
and soil dynamics. Additional research on variable scales (local to 
global) of carbon flow would provide a more thorough understanding of 
the carbon cycle.

Conclusion
    It is clear that addressing the challenge of reducing atmospheric 
carbon dioxide and understanding the effect of global climate change is 
a complex issue with many interrelated components. A better 
understanding of geologic storage potential for carbon dioxide combined 
with research to understand the implications of terrestrial carbon 
sequestration on the carbon cycle would provide a scientific foundation 
for future decisions regarding carbon management. We believe additional 
study of geologic and terrestrial opportunities will better prepare 
decisionmakers as they deal with these issues. Thank you for the 
opportunity to present this testimony. I am pleased to answer questions 
you and other Members of the Committee might have.

    Senator Kerry. Thank you, Dr. Burruss.
    Dr. Hannegan?

                STATEMENT OF DR. BRYAN HANNEGAN,

                  VICE PRESIDENT, ENVIRONMENT,

            ELECTRIC POWER RESEARCH INSTITUTE (EPRI)

    Dr. Hannegan. Thank you, Mr. Chairman, and Members of the 
Subcommittee, my name is Bryan Hannegan, and I am Environment 
Vice President for the Electric Power Research Institute, a 
non-profit, collaborative, R&D organization based in 
California, Tennessee and North Carolina. EPRI appreciates the 
opportunity to provide testimony to the Committee this 
afternoon on the topic of carbon sequestration technologies, 
and there is considerable detail in our written testimony, 
submitted for the record.
    I would like to summarize that testimony in a few key 
points. The first is that advanced coal power plant 
technologies with integrated CO2 capture and storage 
will be crucial to reducing future U.S. electric power sector 
CO2 emissions.
    As slide one, attached to my testimony and shown on the 
screen here demonstrates, a recent EPRI study looking at the 
technical potential for CO2 reductions from the U.S. 
electric sector identified that with aggressive development and 
deployment of low-carbon electricity technologies, and end-use 
efficiency, it is technically feasible to return those 
emissions back to their 1990 levels, sometime around 2025, and 
dramatically reduce those future emissions significantly in the 
decades thereafter. A key technology as shown by the red and 
the orange contributions on that chart is advanced coal 
technologies with CO2 capture and storage.
    The second point I'd like to make is that the availability 
of advanced coal power in integrated CO2 capture and 
storage and other technologies will dramatically reduce the 
projected increases in the cost of wholesale electricity under 
any given carbon constraint going forward.
    If I could get slide two, the impact under two scenarios we 
looked at with a macroeconomic model, on the left-hand side 
showing a world in which we had not advanced the ball with 
respect to R&D in these low-carbon energy technologies, and the 
right-hand one in which we had aggressively pushed energy 
technology R&D forward, you can see the differences between the 
generation mix, the limited case being defined primarily by 
switching to natural gas, which has its own set of challenges, 
as this Committee well knows, as well as significant amounts of 
demand reduction, which are fostered by a high price of 
wholesale electricity.
    On the right-hand side, if you invest in energy 
technologies, you drive an expansion in electric energy with 
CO2 capture and storage on coal plants, and with an 
advancement in nuclear power. The result is a difference in the 
price increase for delivered wholesale power between two and a 
half times today's value in real costs, in the limited case, 
and only the incremental cost of R&D in the advanced case. So, 
significantly, with the same amount of CO2 
abatement, the cost to the U.S. economy and to the U.S. 
consumer are significantly less.
    The key point to proving CCS capability is going to be--as 
others on the panel have mentioned, the large-scale deployment 
of both pre- and post-combustion capture with storage, in a 
variety of technologies. And we envision large combined 
demonstrations should be encouraged in different regions, with 
different coals and technologies.
    As shown on slide three, EPRI's CoalFleet for Tomorrow 
program has identified the R&D pathways to demonstrate after 
2020 a full portfolio of economically attractive and 
commercial-scale advanced coal power opportunities, suitable 
for use with a broad range of U.S. coal types and geologies 
around the Nation. The identified R&D is estimated to cost 
somewhere between $8 and $17 billion cumulatively between now 
and 2020.
    While there are well-proven methods for capturing 
CO2, resulting from coal gasification, no IGCC yet 
captures CO2. IGCC technology is still relatively 
new, and needs more commercial installation.
    Senator Kerry. What's the figure you gave there?
    Dr. Hannegan. It's an EPRI-derived figure for the 
incremental cost of additional investment to realize the 
promise of this development timeline by 2020.
    Senator Kerry. And what was it?
    Dr. Hannegan. Between $8 and $17 billion between now and 
2020.
    Senator Kerry. Big, big, big.
    Dr. Hannegan. In contrast to IGCC, pulverized coal 
technologies already mature, but it's the capture technologies 
which are not.
    So, it's important to avoid choosing between coal 
technology options, and any effort we make, both public and 
private, should foster a full portfolio.
    The final point I want to make is that in addition to the 
challenge of capturing the CO2, we also faced the 
challenges my colleagues have mentioned of the storage issues. 
And there are major, non-technical barriers associated with 
storage, that must be addressed concurrently, before CCS can 
become a commercial opportunity.
    That includes the permitting challenge, that includes 
public acceptance in the demonstration of no significant 
environmental impact, that includes the legal framework around 
the liability and who controls the pore space, and who takes 
liability in the event of a leakage, and it also means 
looking--as my colleagues have mentioned--at possible new uses 
of CO2. We've been able to turn sulfur into 
wallboard, it's quite possible we could turn CO2 
into a useable by-product.
    My testimony entails many more details behind my comments, 
and I look forward to your questions.
    [The prepared statement of Dr. Hannegan follows:]

       Prepared Statement of Dr. Bryan Hannegan, Vice President, 
         Environment, Electric Power Research Institute (EPRI)

Introduction
    Thank you, Mr. Chairman, Ranking Member Ensign, and Members of the 
Subcommittee. I am Bryan Hannegan, Vice President of Environment for 
the Electric Power Research Institute (EPRI), a non-profit, 
collaborative R&D organization. EPRI has principal locations in Palo 
Alto, California; Charlotte, North Carolina; and Knoxville, Tennessee. 
EPRI appreciates the opportunity to provide testimony to the Committee 
on the topic of carbon sequestration technologies.
    Through the development and deployment of advanced coal plants with 
integrated CO2 capture and storage (CCS) technologies, coal 
power can become part of the solution to satisfying both our energy 
needs and our global climate change concerns. However, a sustained RD&D 
program at heightened levels of investment and the resolution of legal 
and regulatory unknowns for long-term geologic CO2 storage 
will be required to achieve the promise of advanced coal with CCS 
technologies. The members of EPRI's CoalFleet for Tomorrow program--a 
research collaborative comprising more than 60 organizations 
representing U.S. utilities, international power generators, equipment 
suppliers, government research organizations, coal and oil companies, 
and a railroad--see crucial roles for both industry and governments 
worldwide in aggressively pursuing collaborative RD&D over the next 20+ 
years to create a full portfolio of commercially self-sustaining, 
competitive advanced coal power generation and CCS technologies.
    The key points I will make today include:

   Advanced coal power plant technologies with integrated 
        CO2 capture and storage (CCS) will be crucial to 
        lowering U.S. electric power sector CO2 emissions. 
        They will also be crucial to substantially lowering world 
        CO2 emissions.

   The availability of advanced coal power and integrated CCS 
        and other technologies could dramatically reduce the projected 
        increases in the cost of wholesale electricity under a carbon 
        cap, thereby saving the U.S. economy as much as $1 trillion by 
        2050.

   It is important to avoid choosing between coal technology 
        options. We should foster a full portfolio of technology 
        options.

   While there are well proven methods for capturing 
        CO2 resulting from coal gasification, no integrated 
        gasification combined cycle (IGCC) yet captures CO2. 
        IGCC technology is still relatively new and needs more 
        commercial installations. In contrast, pulverized coal (PC) 
        technology is already well proven commercially in the power 
        industry; the need is for demonstration of post-combustion 
        capture at a commercial and affordable scale.

   There will inevitably be additional costs associated with 
        CCS. EPRI's latest estimates suggest that the levelized cost of 
        electricity (COE) from new coal plants (IGCC or supercritical 
        PC) designed for capture, compression, transportation and 
        storage of the CO2 will be 40-80 percent higher than 
        the COE of a conventional supercritical PC (SCPC) plant.

   EPRI's technical assessment work indicates that the 
        preferred technology and the additional cost of electricity for 
        CCS will depend on the coal type, location and the technology 
        employed. Without CCS, supercritical pulverized coal (SCPC) has 
        an advantage over IGCC. However, the additional CCS cost is 
        generally lower with IGCC than for SCPC.

   Some studies show an advantage for IGCC with CCS with 
        bituminous coal. With lignite coal SCPC with CCS is generally 
        preferred. With sub-bituminous coals, SCPC with CCS and IGCC 
        with CCS appear to show similar costs.

   Our initial work with post-combustion CO2 capture 
        technologies suggests we can potentially reduce the current 
        estimated 30 percent energy penalty associated with CCS to 
        about to 15 percent over the longer-term. Improvements in IGCC 
        plants offer the same potential for reducing cost and energy 
        penalty as well.

   The key to proving CCS capability is the demonstration of 
        CCS at large-scale (on the order of 1 million tons 
        CO2/year) for both pre- and post-combustion capture 
        with storage in a variety of geologies. Large combined capture 
        and storage demonstrations should be encouraged in different 
        regions and with different coals and technologies.

   EPRI's CoalFleet for Tomorrow program has identified the 
        RD&D pathways to demonstrate, by 2025, a full portfolio of 
        economically attractive, commercial-scale advanced coal power 
        and integrated CCS technologies suitable for use with the broad 
        range of U.S. coal types. Some technologies will be ready for 
        some fuels sooner, but the economic benefits of competition 
        will not be realized until the full portfolio is developed.

   The identified RD&D is estimated to cost $8 billion between 
        now and 2017 and $17 billion cumulatively by 2025, and we need 
        to begin immediately to ensure that these climate change 
        solution technologies will be fully tested at scale by 2025.

   Major non-technical barriers associated with CO2 
        storage must be addressed before CCS can become a commercial 
        reality, including resolution of regulatory and long-term 
        liability uncertainties.

Background
    Coal currently provides over half of the electricity used in the 
United States, and most forecasts of future energy use in the United 
States 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. Through development of advanced 
pollution control technologies and sensible regulatory programs, 
emissions of criteria air pollutants from new coal-fired power plants 
have been reduced by more than 90 percent over the past three decades. 
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 increase 
by approximately 40 percent over 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 the 
benefits that energy provides. This is not a trivial matter--it implies 
a substantial change in the way we produce and consume electricity. 
Technologies to reduce CO2 emissions from coal will 
necessarily be one part of an economy-wide solution that includes 
greater end-use efficiency, increasing 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 climate policy 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. 
Paradoxically, as we seek greater limits on CO2 across our 
economy, our work at EPRI suggests we will see greater amounts of 
electrification--but only if the technologies to do so with near-zero 
emissions are at hand.

The Role of Advanced Coal Generation with CO2 Capture and 
        Storage in a Carbon-Constrained Future
    EPRI's ``Electricity Technology in a Carbon-Constrained Future'' 
study suggests that it is technically feasible to reduce U.S. electric 
sector CO2 emissions by 25-30 percent relative to current 
emissions by 2030 while meeting the increased demand for electricity. 
The study showed that the largest single contributor to emissions 
reduction would come from the integration of CCS technologies with 
advanced coal-based power plants coming on-line after 2020.
    Economic analyses of scenarios to achieve the study's emission 
reduction goals show that in 2050, a U.S. electricity generation mix 
based on a full portfolio of technologies, including advanced coal 
technologies with integrated CCS and advanced light water nuclear 
reactors, results in wholesale electricity prices at less than half of 
the wholesale electricity price for a generation mix without advanced 
coal/CCS and nuclear power. In the case with advanced coal/CCS and 
nuclear power, the cost to the U.S. economy of a CO2 
emissions reduction policy is $1 trillion less than in the case without 
advanced coal/CCS and nuclear power, with a much stronger manufacturing 
sector. Both of these analyses are documented in the 2007 EPRI Summer 
Seminar Discussion paper, ``The Power to Reduce CO2 
Emissions--the Full Portfolio,'' available at http://epri-reports.org/
DiscussionPaper2007.pdf.

Accelerating RD&D on Advanced Coal Technologies with CO2 
        Capture and Storage--Investment and Time Requirements
    The portfolio aspect of advanced coal with integrated CCS 
technologies must be emphasized because no single advanced coal 
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 minimizing economic disruption lies in developing a full 
portfolio of technologies from which power producers (and their 
regulators) can choose the option best suited to local conditions and 
preferences and provide power at the lowest cost to the customer. 
Toward this end, four major technology efforts related to 
CO2 emissions reduction from coal-based power systems must 
be undertaken:

        1. Increased efficiency and reliability of integrated 
        gasification combined cycle (IGCC) power plants.

        2. Increased thermodynamic efficiency of pulverized-coal (PC) 
        power plants.

        3. Improved technologies for capture of CO2 from 
        coal combustion- and gasification-based power plants.

        4. Reliable, acceptable technologies for long-term storage of 
        captured CO2.

    Identification of mechanisms to share RD&D financial and technical 
risks and to address legal and regulatory uncertainties must take place 
as well.
    In short, a comprehensive recognition of all the factors needed to 
hasten deployment of competitive, commercial advanced coal and 
integrated CO2 capture and storage technologies--and 
implementation of realistic, pragmatic plans to overcome barriers--is 
the key to meeting the challenge to supply affordable, environmentally 
responsible energy in a carbon-constrained world.
    A typical path to develop a technology to commercial maturity 
consists of moving from the conceptual stage to laboratory testing, to 
small pilot-scale tests, to larger-scale tests, to multiple full-scale 
demonstrations, and finally to deployment in full-scale commercial 
operations. For capital-intensive technologies such as advanced coal 
power systems, each stage can take years or even a decade to complete, 
and each sequential stage entails increasing levels of investment. As 
depicted in Figure 1, several key advanced coal power and CCS 
technologies are now in (or approaching) an ``adolescent'' stage of 
development. This is a time of particular vulnerability in the 
technology development cycle, as it is common for the expected costs of 
full-scale application to be higher than earlier estimates when less 
was known about scale-up and application challenges. Public agency and 
private funders can become disillusioned with a technology development 
effort at this point, but as long as fundamental technology performance 
results continue to meet expectations, and a path to cost reduction is 
clear, perseverance by project sponsors in maintaining momentum is 
crucial.
    Unexpectedly high costs at the mid-stage of technology development 
have historically come down following market introduction, experience 
gained from ``learning-by-doing,'' realization of economies of scale in 
design and production as order volumes rise, and removal of 
contingencies covering uncertainties and first-of-a-kind costs. An 
International Energy Agency study led by Carnegie Mellon University 
(CMU) observed this pattern of cost-reduction-over-time for power plant 
environmental controls, and CMU predicts a similar reduction in the 
cost of power plant CO2 capture technologies as the 
cumulative installed capacity grows.\1\ EPRI concurs with their 
expectations of experience-based cost reductions and believes that RD&D 
on specifically identified technology refinements can lead to greater 
cost reductions sooner in the deployment phase.
---------------------------------------------------------------------------
    \1\ IEA Greenhouse Gas R&D Programme (IEA GHG), ``Estimating Future 
Trends in the Cost of CO2 Capture Technologies,'' 2006/5, 
January 2006.


    Of the coal-based power generating and carbon sequestration 
technologies shown in Figure 1, only supercritical pulverized coal 
(SCPC) technology has reached commercial maturity. It is crucial that 
other technologies in the portfolio--namely ultra-supercritical (USC) 
PC, integrated gasification combined cycle (IGCC), CO2 
capture (pre-combustion, post-combustion, and oxy-combustion), and 
CO2 storage--be given sufficient support to reach the stage 
of declining constant dollar costs before society's requirements for 
greenhouse gas reductions compel their application in large numbers.
    Figure 2 depicts the major activities in each of the four 
technology areas that must take place to achieve a robust set of 
integral advanced coal/CCS solutions. Important, but not shown in the 
figure, are the interactions between RD&D activities. For example, the 
ion transport membrane (ITM) oxygen supply technology shown under IGCC 
can also be applied to oxy-combustion PC units. Further, while the 
individual goals related to efficiency, CO2 capture, and 
CO2 storage present major challenges, significant challenges 
also arise from complex interactions that occur when CO2 
capture processes are integrated with gasification- and combustion-
based power plant processes.



Reducing CO2 Emissions Through Improved Coal Power Plant 
        Efficiency--A Key Companion to CCS that Lowers Cost and Energy 
        Requirements
    Improved thermodynamic efficiency reduces CO2 emissions 
by reducing the amount of fuel required to generate a given amount of 
electricity. A two-percentage point gain in efficiency provides a 
reduction in fuel consumption of roughly 5 percent and a similar 
reduction in flue gas and CO2 output. Because the size and 
cost of CO2 capture equipment is determined by the volume of 
flue gas to be treated, higher power block efficiency reduces the 
capital and energy requirements for CCS. Depending on the technology 
used, improved efficiency can also provide similar reductions in 
criteria air pollutants, hazardous air pollutants, and water 
consumption.
    A typical baseloaded 500 MW (net) coal plant emits about 3 million 
metric tons of CO2 per year. Individual plant emissions vary 
considerably given differences in plant steam cycle, coal type, 
capacity factor, and operating regimes. For a given fuel, however, a 
new supercritical PC unit built today might produce 5-10 percent less 
CO2 per megawatt-hour (MWh) than the existing fleet average 
for that coal type.
    With an aggressive RD&D program on efficiency improvement, new 
ultra-supercritical (USC PC) plants could reduce CO2 
emissions per MWh by up to 25 percent relative to the existing fleet 
average. Significant efficiency gains are also possible for IGCC plants 
by employing advanced gas turbines and through more energy-efficient 
oxygen plants and synthesis (fuel) gas cleanup technologies.
    EPRI and the Coal Utilization Research Council (CURC), in 
consultation with DOE, have identified a challenging but achievable set 
of milestones for improvements in the efficiency, cost, and emissions 
of PC and coal-based IGCC plants. The EPRI-CURC Roadmap projects an 
overall improvement in the thermal efficiency of state-of-the art 
generating technology from 38-41 percent in 2010 to 44-49 percent by 
2025 (on a higher heating value [HHV] basis; see Table 1). As Table 1 
indicates, power-block efficiency gains (i.e., without capture systems) 
will be offset by the energy required for CO2 capture, but 
as noted, they are important in reducing the overall cost of CCS. 
Coupled with opportunities for major improvements in the energy 
efficiency of CO2 capture processes per se, aggressive 
pursuit of the EPRI-CURC RD&D program offers the prospect of coal power 
plants with CO2 capture in 2025 that have net efficiencies 
meeting or exceeding current-day power plants without CO2 
capture.
    It is also important to note that the numeric ranges in Table 1 are 
not simply a reflection of uncertainty, but rather they underscore an 
important point about differences among U.S. coals. The natural 
variations in moisture and ash content and combustion characteristics 
between coals have a significant impact on attainable efficiency. An 
advanced coal plant firing Wyoming and Montana's Powder River Basin 
(PRB) coal, for example, would likely have an HHV efficiency 2 
percentage points lower than the efficiency of a comparable plant 
firing Appalachian bituminous coals. Equally advanced plants firing 
lignite would likely have efficiencies 2 percentage points lower than 
their counterparts firing PRB. Any government incentive program with an 
efficiency-based qualification criterion should recognize these 
inherent differences in the attainable efficiencies for plants using 
different ranks of coal.

                              Table 1.--Efficiency Milestones in EPRI-CURC Roadmap
----------------------------------------------------------------------------------------------------------------
                                                    2010             2015             2020             2025
----------------------------------------------------------------------------------------------------------------
PC & IGCC Systems                                 38-41% HHV       39-43% HHV       42-46% HHV       44-49% HHV
(Without CO2 Capture)
----------------------------------------------------------------------------------------------------------------
PC & IGCC Systems                                 31-32% HHV       31-35% HHV       33-39% HHV       39-46% HHV
(With CO2 Capture*)
----------------------------------------------------------------------------------------------------------------
* Efficiency values reflect impact of 90 percent CO2 capture, but not compression or transportation.

New Plant Efficiency Improvements--IGCC
    Although IGCC is not yet a mature technology for coal-fired power 
plants, chemical plants around the world have accumulated a 100-year 
experience base operating coal-based gasification units and related gas 
cleanup processes. The most advanced of these units are similar to the 
front end of a modern IGCC facility. Similarly, several decades of 
experience firing natural gas and petroleum distillate have established 
a high level of maturity for the basic combined cycle generating 
technology. Nonetheless, ongoing RD&D continues to provide significant 
advances in the base technologies, as well as in the suite of 
technologies used to integrate them into an IGCC generating facility.
    Efficiency gains in currently proposed IGCC plants will come from 
the use of new ``FB-class'' gas turbines, which will provide an overall 
plant efficiency gain of about 0.6 percentage point (relative to IGCC 
units with FA-class models, such as Tampa Electric's Polk Power 
Station). This corresponds to a decrease in the rate of CO2 
emissions per MWh of about 1.5 percent. Alternatively, this means 1.5 
percent less fuel is required per MWh of output, and thus the required 
size of pre-combustion water-gas shift and CO2 separation 
equipment would be slightly smaller.
    Figure 3 depicts the anticipated time-frame for further 
developments identified by EPRI's CoalFleet for Tomorrow program that 
promise a succession of significant improvements in IGCC unit 
efficiency. Key technology advances under development include:

   larger capacity gasifiers (often via higher operating 
        pressures that boost throughput without a commensurate increase 
        in vessel size).

   integration of new gasifiers with larger, more efficient G- 
        and H-class gas turbines.

   use of ion transport membrane or other more energy-efficient 
        technologies in oxygen plants.

   warm synthesis gas cleanup and membrane separation processes 
        for CO2 capture that reduce energy losses in these 
        areas.

   recycle of liquefied CO2 to replace water in 
        gasifier feed slurry (reducing heat loss to water evaporation).

   hybrid combined cycles using fuel cells to achieve 
        generating efficiencies exceeding those of conventional 
        combined cycle technology.

    Improvements in gasifier reliability and in control systems also 
contribute to improved annual average efficiency by minimizing the 
number and duration of startups and shutdowns.



    Counteracting Gas Turbine Output Loss at High Elevations. IGCC 
plants designed for application in high-elevation locations must 
account for the natural reduction in gas turbine power output that 
occurs where the air is thin. This phenomenon is rooted in the 
fundamental volumetric flow limitation of a gas turbine, and can reduce 
power output by up to 15 percent at an elevation of 5,000 feet 
(relative to a comparable plant at sea level). EPRI is exploring 
measures to counteract this power loss, including inlet air chilling (a 
technique used at natural gas power plants to mitigate the power loss 
that comes from thinning of the air on a hot day) and use of 
supplemental burners between the gas turbine and steam turbine to boost 
the plant's steam turbine section generating capacity.
    Larger, Higher Firing Temperature Gas Turbines. For plants coming 
on-line around 2015, the larger size G-class gas turbines, which 
operate at higher firing temperatures (relative to F-class machines) 
can improve efficiency by 1 to 2 percentage points while also 
decreasing capital cost per kW capacity. The H-class gas turbines 
coming on-line in the same timeframe, which also feature higher firing 
temperatures as well as steam-based internal cooling of hot turbine 
components, will provide a further increase in efficiency and capacity.
    Ion Transport Membrane-Based Oxygen Plants. Most gasifiers used in 
IGCC plants require a large quantity of high-pressure, high purity 
oxygen, which is typically generated onsite with an expensive and 
energy-intensive cryogenic process. The ITM process allows the oxygen 
in high-temperature air to pass through a membrane while preventing 
passage of non-oxygen atoms. According to developers, an ITM-based 
oxygen plant consumes 35-60 percent less power and costs 35 percent 
less than a cryogenic plant. EPRI is performing a due diligence 
assessment of this technology in advance of potential participation in 
technology scale-up efforts.
    Supercritical Heat Recovery Steam Generators. In IGCC plants, hot 
exhaust gas exiting the gas turbine is ducted into a heat exchanger 
known as a heat recovery steam generator (HRSG) to transfer energy into 
water-filled tubes producing steam to drive a steam turbine. This 
combination of a gas turbine and steam turbine power cycles produces 
electricity more efficiently than either a gas turbine or steam turbine 
alone. As with conventional steam power plants, the efficiency of the 
steam cycle in a combined cycle plant increases when turbine inlet 
steam temperature and pressure are increased. The higher exhaust 
temperatures of G- and H-class gas turbines offer the potential for 
adoption of more-efficient supercritical steam cycles. Materials for 
use in a supercritical HRSG are generally established, and thus should 
not pose a barrier to technology implementation once G- and H-class gas 
turbines become the standard for IGCC designs.
    Synthesis Gas Cleaning at Higher Temperatures. The acid gas 
recovery (AGR) processes currently used to remove sulfur compounds from 
synthesis gas require that the gas and solvent be cooled to about 100 
+F, thereby causing a loss in efficiency. Further costs and efficiency 
loss are inherent in the process equipment and auxiliary steam required 
to recover the sulfur compounds from the solvent and convert them to 
useable products. Several DOE-sponsored RD&D efforts aim to reduce the 
energy losses and costs imposed by this recovery process. These 
technologies (described below) could be ready--with adequate RD&D 
support--by 2020:

   The Selective Catalytic Oxidation of Hydrogen Sulfide 
        process eliminates the Claus and Tail Gas Treating units, along 
        with the traditional solvent-based AGR contactor, regenerator, 
        and heat exchangers, by directly converting hydrogen sulfide 
        (H2S) to elemental sulfur. The process allows for a 
        higher operating temperature of approximately 300 +F, which 
        eliminates part of the low-temperature gas cooling train. The 
        anticipated benefit is a net capital cost reduction of about 
        $60/kW along with an efficiency gain of about 0.8 percentage 
        point.

   The RTI/Eastman High-Temperature Desulfurization System uses 
        a regenerable dry zinc oxide sorbent in a dual loop transport 
        reactor system to convert H2S and COS to 
        H2O, CO2, and SO2. Tests at 
        Eastman Chemical Company have shown sulfur species removal 
        rates above 99.9 percent, with 10 ppm output versus 8000+ ppm 
        input sulfur, using operating temperatures of 800-1000 +F. This 
        process is also being tested for its ability to provide a high-
        pressure CO2 by-product. The anticipated benefit for 
        IGCC, compared with using a standard oil-industry process for 
        sulfur removal, is a net capital cost reduction of $60-$90 per 
        kW, a thermal efficiency gain of 2-4 percent for the 
        gasification process, and a slight reduction in operating cost. 
        Tests are also under way for a multi-contaminant removal 
        processes that can be integrated with the transport 
        desulfurization system at temperatures above 480 +F.

    Liquid CO2-Coal Slurrying for Gasification of Low-Rank 
Coals. Future IGCC plants with CCS may recycle some of the recovered 
liquid CO2 to replace water as the slurrying medium for the 
coal feed. This is expected to increase gasification efficiency for all 
coals, but particularly for subbituminous coal and lignite, which have 
naturally high moisture contents. The liquid CO2 has a lower 
heat of vaporization than water and is able to carry more coal per unit 
mass of fluid. The liquid CO2-coal slurry will flash almost 
immediately upon entering the gasifier, providing good dispersion of 
the coal particles and potentially yielding the higher performance of a 
dry-fed gasifier with the simplicity of a slurry-fed system.
    Traditionally, slurry-fed gasification technologies have a cost 
advantage over conventional dry-fed fuel handling systems, but they 
suffer a large performance penalty when used with coals containing a 
large fraction of water and ash. EPRI identified CO2 coal 
slurrying as an innovative fuel preparation concept 20 years ago, when 
IGCC technology was in its infancy. At that time, however, the cost of 
producing liquid CO2 was too high to justify the improved 
thermodynamic performance. Requirements for CCS change that, as it will 
substantially reduce the incremental cost of producing a liquid 
CO2 stream.
    To date, CO2-coal slurrying has only been demonstrated 
at pilot scale and has yet to be assessed in feeding coal to a 
gasifier, so the estimated performance benefits remain to be confirmed. 
It will first be necessary, however, to update previous studies to 
quantify the potential benefit of liquid CO2 slurries with 
IGCC plants designed for CO2 capture. If the predicted 
benefit is economically advantageous, a significant amount of scale-up 
and demonstration work would be required to qualify this technology for 
commercial use.
    Fuel Cells and IGCC. No matter how far gasification and turbine 
technologies advance, IGCC power plant efficiency will never progress 
beyond the inherent thermodynamic limits of the gas turbine and steam 
turbine power cycles (along with lower limits imposed by available 
materials technology). Several IGCC-fuel cell hybrid power plant 
concepts (IGFC) aim to provide a path to coal-based power generation 
with net efficiencies that exceed those of conventional combined cycle 
generation.
    Along with its high thermal efficiency, the fuel cell hybrid cycle 
reduces the energy consumption for CO2 capture. The anode 
section of the fuel cell produces a stream that is highly concentrated 
in CO2. After removal of water, this stream can be 
compressed for sequestration. The concentrated CO2 stream is 
produced without having to include a water-gas shift reactor in the 
process (see Figure 4). This further improves the thermal efficiency 
and decreases capital cost. IGFC power systems are a long-term 
solution, however, and are unlikely to see full-scale demonstration 
until about 2030.



    Role of FutureGen. The FutureGen Industrial Alliance and DOE are 
building a first-of-its-kind, near-zero emissions coal-fed IGCC power 
plant integrated with CCS. The commencement of full-scale operations is 
targeted for 2013. The project aims to sequester CO2 in a 
representative geologic formation at a rate of at least one million 
metric tons per year.
    The FutureGen design will address scaling and integration issues 
for coal-based, zero emissions IGCC plants. In its role as a ``living 
laboratory,'' FutureGen is designed to validate additional advanced 
technologies that offer the promise of clean environmental performance 
at a reduced cost and increased reliability. FutureGen will have the 
flexibility to conduct full-scale and slipstream tests of such scalable 
advanced technologies as:

   Membrane processes to replace cryogenic separation for 
        oxygen production.

   An advanced transport reactor sidestream with 30 percent of 
        the capacity of the main gasifier.

   Advanced membrane and solvent processes for H2 
        and CO2 separation.

   A raw gas shift reactor that reduces the upstream clean-up 
        requirements.

   Ultra-low-NOX combustors that can be used with 
        high-hydrogen synthesis gas.

   A fuel cell hybrid combined cycle pilot.

   Challenging first-of-a-kind system integration.

   Smart dynamic plant controls including a CO2 
        management system.

    Figure 5 provides a schematic of the ``backbone'' and ``research 
platform'' process trains envisioned for the FutureGen plant.



    Figure 6 summarizes EPRI's recommended major RD&D activities for 
improving the efficiency and cost of IGCC technologies with 
CO2 capture.



New Plant Efficiency Improvements--Advanced Pulverized Coal
    Pulverized-coal power plants have long been a primary source of 
reliable and affordable power in the United States and around the 
world. The advanced level of maturity of the technology, along with 
basic thermodynamic principles, suggests that significant efficiency 
gains can most readily be realized by increasing the operating 
temperatures and pressures of the steam cycle. Such increases, in turn, 
can be achieved only if there is adequate development of suitable 
materials and new boiler and steam turbine designs that allow use of 
higher steam temperatures and pressures.
    Current state-of-the-art plants use supercritical main steam 
conditions (i.e., temperature and pressure above the ``critical point'' 
where the liquid and vapor phases of water are indistinguishable). SCPC 
plants typically have main steam conditions up to 1100 +F. The term 
``ultra-supercritical'' is used to describe plants with main steam 
temperatures in excess of 1100 +F and potentially as high as 1400 +F.
    Achieving higher steam temperatures and higher efficiency will 
require the development of new corrosion-resistant, high-temperature 
nickel alloys for use in the boiler and steam turbine. In the United 
States, these challenges are being address by the Ultra-Supercritical 
Materials Consortium, a DOE R&D program involving Energy Industries of 
Ohio, EPRI, the Ohio Coal Development Office, and numerous equipment 
suppliers. EPRI provides technical management for the consortium. 
Results are applicable to all ranks of coal. As noted, higher power 
block efficiencies translate to lower costs for post-combustion 
CO2 capture equipment.
    It is expected that a USC PC plant operating at about 1300 +F will 
be built during the next seven to 10 years, following the demonstration 
and commercial availability of advanced materials from these programs. 
This plant would achieve an efficiency (before installation of 
CO2 capture equipment) of about 45 percent (HHV) on 
bituminous coal, compared with 39 percent for a current state-of-the-
art plant, and would reduce CO2 production per net MWh by 
about 15 percent.
    Ultimately, nickel-base alloys are expected to enable stream 
temperatures in the neighborhood of 1400 +F and pre-capture generating 
efficiencies up to 47 percent HHV with bituminous coal. This 
approximately 10 percentage point improvement over the efficiency of a 
new subcritical pulverized-coal plant would equate to a decrease of 
about 25 percent in CO2 and other emissions per MWh. The 
resulting saving in the cost of subsequently installed CO2 
capture equipment is substantial.
    Figure 7 illustrates a timeline developed by EPRI's CoalFleet for 
Tomorrow program to establish efficiency improvement and cost 
reduction goals for USC PC plants with CO2 capture.



    UltraGen Ultra-Supercritical (USC) Pulverized Coal (PC) Commercial 
Projects. EPRI and industry representatives have proposed a program to 
support commercial projects that demonstrate advanced PC and CCS 
technologies. The vision entails construction of two (or more) 
commercially operated USC PC power plants that combine state-of-the-art 
pollution controls, ultra-supercritical steam power cycles, and 
innovative CO2 capture technologies.
    The UltraGen I plant will use the best of today's proven ferritic 
steels in high-temperature boiler and steam turbine components, while 
UltraGen II will be the first plant in the United States to feature 
nickel-based alloys that are able to withstand the higher temperatures 
of advanced ultra-supercritical steam conditions.
    UltraGen I will demonstrate CO2 capture modules that 
separate about 1 million tons CO2/yr using the best 
established technology. This system will be about 6 times the size of 
the largest CO2 capture system operating on a coal-fired 
boiler today. UltraGen II will double the size of the UltraGen I 
CO2 capture system, and may demonstrate a new class of 
chemical solvent if one of the emerging low-regeneration-energy 
processes has reached a sufficient stage of development. Both plants 
will demonstrate ultra-low emissions. Both UltraGen demonstration 
plants will dry and compress the captured CO2 for long-term 
geologic storage and/or use in enhanced oil or gas recovery operations. 
Figure 8 depicts the proposed key features of UltraGen I and II.



    To provide a platform for testing and developing emerging PC and 
CCS technologies, the UltraGen program will allow for technology trials 
at existing sites as well as at the sites of new projects. Unlike 
FutureGen, EPRI expects the UltraGen projects will be commercially 
dispatched by electricity grid operators. The differential cost to the 
host company for demonstrating these improved features are envisioned 
to be offset by any available tax credits (or other incentives) and by 
funds raised through an industry-led consortium formed by EPRI.
    The UltraGen projects represent the type of ``giant step'' 
collaborative efforts that need to be taken to advance integrated PC/
CCS technology to the next phase of evolution and assure 
competitiveness in a carbon-constrained world. Because of the time and 
expense for each ``design and build'' iteration for coal power plants 
(3 to 5 years not counting the permitting process and $2 billion), 
there is no room for hesitation in terms of commitment to advanced 
technology validation and demonstration projects.
    The UltraGen projects will resolve technical and economic barriers 
to the deployment of USC PC and CCS technology by providing a shared-
risk vehicle for testing and validating high-temperature materials, 
components, and designs in plants also providing superior environmental 
performance.
    Figure 9 summarizes EPRI's recommended major RD&D activities for 
improving the efficiency and cost of USC PC technologies with 
CO2 capture.



    Efficiency Improvement and CCS Retrofits for the Existing PC Fleet. 
It would be economically advantageous to operate the many reliable 
subcritical PC units in the U.S. fleet well into the future. Premature 
replacement of these units or mandatory retrofit of these units for 
CO2 capture en masse would be economically prohibitive. 
Their flexibility for load following and provision of support services 
to ensure grid stability makes them highly valuable. With equipment 
upgrades, many of these units can realize modest efficiency gains, 
which, when accumulated across the existing generating fleet could make 
a sizable reduction in CO2 emissions. For some existing 
plants, retrofit of CCS will make sense, but specific plant design 
features, space limitations, and economic and regulatory considerations 
must be carefully analyzed to determine whether retrofit-for-capture is 
feasible.
    These upgrades depend on the equipment configuration and operating 
parameters of a particular plant and may include:

   turbine blading and steam path upgrades.

   turbine control valve upgrades for more efficient regulation 
        of steam.

   cooling tower and condenser upgrades to reduce circulating 
        water temperature, steam turbine exhaust backpressure, and 
        auxiliary power consumption.

   cooling tower heat transfer media upgrades.

   condenser optimization to maximize heat transfer and 
        minimize condenser temperature.

   condenser air leakage prevention/detection.

   variable speed drive technology for pump and fan motors to 
        reduce power consumption.

   air heater upgrades to increase heat recovery and reduce 
        leakage.

   advanced control systems incorporating neural nets to 
        optimize temperature, pressure, and flow rates of fuel, air, 
        flue gas, steam, and water.

   optimization of water blowdown and blowdown energy recovery.

   optimization of attemperator design, control, and operating 
        scenarios.

   sootblower optimization via ``intelligent'' sootblower 
        system use.

   coal drying (for plants using lignite and subbituminous 
        coals).

    Coal Drying for Increased Generating Efficiency. Boilers designed 
for high-moisture lignite have traditionally employed higher feed rates 
(lb/hr) to account for the large latent heat load to evaporate fuel 
moisture. An innovative concept developed by Great River Energy (GRE) 
and Lehigh University uses low-grade heat recovered from within the 
plant to dry incoming fuel to the boiler, thereby boosting plant 
efficiency and output. [In contrast, traditional thermal drying 
processes are complex and require high-grade heat to remove moisture 
from the coal.] Specifically, the GRE approach uses steam condenser and 
boiler exhaust heat exchangers to heat air and water fed to a 
fluidized-bed coal dryer upstream of the plant pulverizers. Based on 
successful tests with a pilot-scale dryer and more than a year of 
continuous operation with a prototype dryer at its Coal Creek station, 
GRE (with U.S. Department of Energy support and EPRI technical 
consultation) is now building a full suite of dryers for Unit 2 (i.e., 
a commercial-scale demonstration). In addition to the efficiency and 
CO2 emission reduction benefits from reducing the lignite 
feed moisture content by about 25 percent, the plant's air emissions 
will be reduced as well.\2\ Application of this technology is not 
limited to PC units firing lignite. EPRI believes it may find 
application in PC units firing subbituminous coal and in IGCC units 
with dry-fed gasifiers using low-rank coals.
---------------------------------------------------------------------------
    \2\ C. Bullinger, M. Ness, and N. Sarunac, ``One Year of Operating 
Experience with Prototype Fluidized Bed Coal Dryer at Coal Creek 
Generating Station,'' 32nd International Technical Conference on Coal 
Utilization and Fuel Systems, Clearwater, FL, June 10-15, 2007.
---------------------------------------------------------------------------
Improving CO2 Capture Technologies
    CCS entails pre-combustion or post-combustion CO2 
capture technologies, CO2 drying and compression (and 
sometimes further removal of impurities), and the transportation of 
separated CO2 to locations where it can be stored away from 
the atmosphere for centuries or longer.
    Albeit at considerable cost, CO2 capture technologies 
can be integrated into all coal-based power plant technologies. For 
both new plants and retrofits, there is a tremendous need (and 
opportunity) to reduce the energy required to remove CO2 
from fuel gas or flue gas. Figure 10 shows a selection of the key 
technology developments and test programs needed to achieve commercial 
CO2 capture technologies for advanced coal combustion- and 
gasification-based power plants at a progressively shrinking constant-
dollar levelized cost-of-electricity premium. Specifically, the target 
is a premium of about $6/MWh in 2025 (relative to plants at that time 
without capture) compared with an estimated 2010 cost premium of 
perhaps $40/MWh (not counting the cost of transportation and storage). 
Such a goal poses substantial engineering challenges and will require 
major investments in RD&D to roughly halve the currently large energy 
requirements (operating costs) associated with CO2 solvent 
regeneration. Achieving this goal will allow power producers to meet 
the public demand for stable electricity prices while reducing 
CO2 emissions to address climate change concerns.



Pre-Combustion CO2 Capture (IGCC)
    IGCC technology allows for CO2 capture to take place via 
an added fuel gas processing step at elevated pressure, rather than at 
the atmospheric pressure of post-combustion flue gas, permitting 
capital savings through smaller equipment sizes as well as lower 
operating costs.
    Currently available technologies for such pre-combustion 
CO2 removal use a chemical and/or physical solvent that 
selectively absorbs CO2 and other ``acid gases,'' such as 
hydrogen sulfide. Application of this technology requires that the CO 
in synthesis gas (the principal component) first be ``shifted'' to 
CO2 and hydrogen via a catalytic reaction with water. The 
CO2 in the shifted synthesis gas is then removed via contact 
with the solvent in an absorber column, leaving a hydrogen-rich 
synthesis gas for combustion in the gas turbine. The CO2 is 
released from the solvent in a regeneration process that typically 
reduces pressure and/or increases temperature.
    Chemical plants currently employ such a process commercially using 
methyl diethanolamine (MDEA) as a chemical solvent or the Selexol and 
Rectisol processes, which rely on physical solvents. Physical solvents 
are generally preferred when extremely high (>99.8 percent) sulfur 
species removal is required. Although the required scale-up for IGCC 
power plant applications is less than that needed for scale-up of post-
combustion CO2 capture processes for PC plants, considerable 
engineering challenges remain and work on optimal integration with IGCC 
cycle processes has just begun.
    The impact of current pre-combustion CO2 removal 
processes on IGCC plant thermal efficiency and capital cost is 
significant. In particular, the water-gas shift reaction reduces the 
heating value of synthesis gas fed to the gas turbine. Because the 
gasifier outlet ratios of CO to methane to H2 are different 
for each gasifier technology, the relative impact of the water-gas 
shift reactor process also varies. In general, however, it can be on 
the order of a 10 percent fuel energy reduction. Heat regeneration of 
solvents further reduces the steam available for power generation. 
Other solvents, which are depressurized to release captured 
CO2, must be re-pressurized for reuse. Cooling water 
consumption is increased for solvents needing cooling after 
regeneration and for pre-cooling and interstage cooling during 
compression of separated CO2 to a supercritical state for 
transportation and storage. Heat integration with other IGCC cycle 
processes to minimize these energy impacts is complex and is currently 
the subject of considerable RD&D by EPRI and others.
    Membrane CO2 Separation. Technology for separating 
CO2 from shifted synthesis gas (or flue gas from PC plants) 
offers the promise of lower auxiliary power consumption but is 
currently only at the laboratory stage of development. Several 
organizations are pursuing different approaches to membrane-based 
applications. In general, however, CO2 recovery on the low-
pressure side of a selective membrane can take place at a higher 
pressure than is now possible with solvent processes, reducing the 
subsequent power demand for compressing CO2 to a 
supercritical state. Membrane-based processes can also eliminate steam 
and power consumption for regenerating and pumping solvent, 
respectively, but they require power to create the pressure difference 
between the source gas and CO2-rich sides. If membrane 
technology can be developed at scale to meet performance goals, it 
could enable up to a 50 percent reduction in capital cost and auxiliary 
power requirements relative to current CO2 capture and 
compression technology.

Post-Combustion CO2 Capture (PC and CFB Plants)
    The post-combustion CO2 capture processes being 
discussed for power plant boilers in the near-term draw upon commercial 
experience with amine solvent separation at much smaller scale in the 
food, beverage and chemical industries, including three U.S. 
applications of CO2 capture from coal-fired boilers.
    These processes contact flue gas with an amine solvent in an 
absorber column (much like a wet SO2 scrubber) where the 
CO2 chemically reacts with the solvent. The CO2-
rich liquid mixture then passes to a stripper column where it is heated 
to change the chemical equilibrium point, releasing the CO2. 
The ``regenerated'' solvent is then recirculated back to the absorber 
column, while the released CO2 may be further processed 
before compression to a supercritical state for efficient 
transportation to a storage location.
    After drying, the CO2 released from the regenerator is 
relatively pure. However, successful CO2 removal requires 
very low levels of SO2 and NO2 entering the 
CO2 absorber, as these species also react with the solvent, 
requiring removal of the degraded solvent and replacement with fresh 
feed. Thus, high-efficiency SO2 and NOX control 
systems are essential to minimizing solvent consumption costs for post-
combustion CO2 capture; currently the approach to achieving 
such ultra-low SO2 concentrations is to add a polishing 
scrubber, a costly venture. Extensive RD&D is in progress to improve 
the solvent and system designs for power boiler applications and to 
develop better solvents with greater absorption capacity, less energy 
demand for regeneration, and greater ability to accommodate flue gas 
contaminants.
    At present, monoethanolamine (MEA) is the ``default'' solvent for 
post-combustion CO2 capture studies and small-scale field 
applications. Processes based on improved amines, such as Fluor's 
Econamine FG Plus and Mitsubishi Heavy Industries' KS-1, await 
demonstration at power boiler scale and on coal-derived flue gas. The 
potential for improving amine-based processes appears significant. For 
example, a recent study based on KS-1 suggests that its impact on net 
power output for a supercritical PC unit would be 19 percent and its 
impact on the levelized cost-of-electricity would be 44 percent, 
whereas earlier studies based on suboptimal MEA applications yielded 
output penalties approaching 30 percent and cost-of-electricity 
penalties of up to 65 percent.
    Accordingly, amine-based engineered solvents are the subject of 
numerous ongoing efforts to improve performance in power boiler post-
combustion capture applications. Along with modifications to the 
chemical properties of the sorbents, these efforts are addressing the 
physical structure of the absorber and regenerator equipment, examining 
membrane contactors and other modifications to improve gas-liquid 
contact and/or heat transfer, and optimizing thermal integration with 
steam turbine and balance-of-plant systems. Although the challenge is 
daunting, the payoff is potentially massive, as these solutions may be 
applicable not only to new plants, but to retrofits where sufficient 
plot space is available at the back end of the plant.
    Finally, as discussed earlier, deploying USC PC technology to 
increase efficiency and lower uncontrolled CO2 per MWh can 
further reduce the cost impact of post-combustion CO2 
capture.
    Ammonia-Based Processes. Post-combustion CO2 capture 
using ammonia-based solvents offers the promise of significantly lower 
solvent regeneration requirements relative to MEA. In the ``chilled 
ammonia'' process currently under development and testing by ALSTOM and 
EPRI, respectively, CO2 is absorbed in a solution of 
ammonium carbonate, at low temperature and atmospheric pressure.
    Compared with amines, ammonium carbonate has over twice the 
CO2 absorption capacity and requires less than half the heat 
to regenerate. Further, regeneration can be performed under higher 
pressure than amines, so the released CO2 is already 
partially pressurized. Therefore, less energy is subsequently required 
for compression to a supercritical state for transportation to an 
injection location. Developers have estimated that the parasitic power 
loss from a full-scale supercritical PC plant using chilled ammonia 
CO2 capture could be as low as 15 percent, with an 
associated cost-of-electricity penalty of just 25 percent. Part of the 
reduction in power loss comes from the use of low quality heat to 
regenerate ammonia and reduce the quantity of steam required for 
regeneration. Following successful experiments at 0.25 MWe 
scale, ALSTOM and a consortium of EPRI members are constructing a 1.7 
MWe pilot unit to test the chilled ammonia process on a flue 
gas slipstream at We Energies' Pleasant Prairie Power Plant. The 
American Electric Power Co. (AEP) has announced plans to test a scaled-
up (20 MWe) design, incorporating the lessons learned on the 
1.7 MWe unit, at its Mountaineer station in West Virginia in 
the 2009 timeframe.
    Other ``multi-pollutant'' control system developers are also 
exploring ammonia-based processes for CO2 removal. For 
example, Powerspan and NRG Energy, Inc. just last week announced plans 
to demonstrate a 125 MWe design of Powerspan's 
ECO2 system at the Parish station in Texas starting up in 
2012.
    Other Processes. EPRI has identified over 40 potential 
CO2 separation processes that are being developed by various 
firms or institutes. They include absorption systems (typically 
solvent-based similar to the amine and ammonia processes discussed 
above), adsorbed (attachment of the CO2 to a solid that is 
then regenerated and re-used), membranes, and biological systems. 
Funding comes from a variety of sources, primarily DOE or internal 
funds, but the funding is neither sufficient or well-enough coordinated 
to advance the most promising technologies at the speed needed to 
achieve the goals of high CO2 capture at societally-
acceptable cost and energy drain.

Oxy-Fuel Combustion Boilers
    Fuel combustion in a blend of oxygen and recycled flue gas rather 
than in air (known as oxy-fuel combustion, oxy-coal combustion, or oxy-
combustion) is gaining interest as a viable CO2 capture 
alternative for PC and CFB plants. The process is applicable to 
virtually all fossil-fueled boiler types and is a candidate for 
retrofits as well as new power plants.
    Firing coal with high-purity oxygen alone would result in too high 
of a flame temperature, which would increase slagging, fouling, and 
corrosion problems, so the oxygen is diluted by mixing it with a 
slipstream of recycled flue gas. As a result, the flue gas downstream 
of the recycle slipstream take-off consists primarily of CO2 
and water vapor (although it also contains small amounts of nitrogen, 
oxygen, and criteria pollutants). After the water is condensed, the 
CO2-rich gas is compressed and purified to remove 
contaminants and prepare the CO2 for transportation and 
storage.
    Oxy-combustion boilers have been studied in laboratory-scale and 
small pilot units of up to 3 MWt. Two larger pilot units, at 
10 MWe, are now under construction by Babcock & Wilcox 
(B&W) and Vattenfall. An Australian-Japanese project team is pursuing a 
30 MWe repowering project in Australia. These larger tests 
will allow verification of mathematical models and provide engineering 
data useful for designing pre-commercial systems.

CO2 Transport and Geologic Storage
    Application of CO2 capture technologies implies that 
there will be secure and economical forms of long-term storage that can 
assure CO2 will be kept out of the atmosphere. Natural 
underground CO2 reservoirs in Colorado, Utah, and other 
western states testify to the effectiveness of long-term geologic 
CO2 storage. CO2 is also found in natural gas 
reservoirs, where it has resided for millions of years. Thus, evidence 
suggests that similarly sealed geologic formations will be ideal for 
storing CO2 for millennia or longer.
    The most developed approach for large-scale CO2 storage 
is injection into depleted or partially depleted oil and gas reservoirs 
and similar geologically sealed ``saline formations'' (porous rocks 
filled with brine that is impractical for desalination). Partially 
depleted oil reservoirs provide the potential added benefit of enhanced 
oil recovery (EOR). [EOR is used in mature fields to recover additional 
oil after standard extraction methods have been used. When 
CO2 is injected for EOR, it causes residual oil to swell and 
become less viscous, allowing some to flow to production wells, thus 
extending the field's productive life.] By providing a commercial 
market for CO2 captured from industrial sources, EOR may 
help the economics of CCS projects where it is applicable, and in some 
cases might reduce regulatory and liability uncertainties. Although 
less developed than EOR, researchers are exploring the effectiveness of 
CO2 injection for enhancing production from depleted natural 
gas fields (particularly in compartmentalized formations where pressure 
has dropped) and from deep methane-bearing coal seams. DOE and the 
International Energy Agency are among the sponsors of such efforts. 
However, at the scale that CCS needs to be deployed to help achieve 
atmospheric CO2 stabilization at an acceptable level, EPRI 
believes that the primary economic driver for CCS will be the value of 
carbon that results from a future climate policy.
    Geologic sequestration as a CCS strategy is currently being 
demonstrated in several RD&D projects around the world. The three 
largest projects (which are non-power)--Statoil's Sleipner Saline 
Aquifer CO2 Storage project in the North Sea off of Norway; 
the Weyburn Project in Saskatchewan, Canada; and the In Salah Project 
in Algeria--each sequester about 1 million metric tons of 
CO2 per year, which matches the output of one baseloaded 
150-200 MW coal-fired power plant. With 17 collective operating years 
of experience, these projects have thus far demonstrated that 
CO2 storage in deep geologic formations can be carried out 
safely and reliably. Statoil estimates that Norwegian greenhouse gas 
emissions would have risen incrementally by 3 percent if the 
CO2 from the Sleipner project had been vented rather than 
sequestered.\3\
---------------------------------------------------------------------------
    \3\ http://www.co2captureandstorage.info/
project_specific.php?project_id=26.
---------------------------------------------------------------------------
    Table 2 lists a selection of current and planned CO2 
storage projects as of early 2007. In October 2007, the DOE awarded the 
first three large scale carbon sequestration projects in the United 
States. The Plains Carbon Dioxide Reduction Partnership, Southeast 
Regional Carbon Sequestration Partnership, and Southwest Regional 
Partnership for Carbon Sequestration, will conduct large volume tests 
for the storage of one million or more tons of CO2 in deep 
saline reservoirs in the U.S.

                   Table 2.--Select Existing and Planned CO Storage Projects as of Early 2007
----------------------------------------------------------------------------------------------------------------
                                                                                 Anticipated amount injected by:
                 Project                   CO2 Source      Country      Start   --------------------------------
                                                                                    2006       2010       2015
----------------------------------------------------------------------------------------------------------------
Sleipner                                   Gas. Proc.        Norway       1996       9 MT      13 MT      18 MT
----------------------------------------------------------------------------------------------------------------
Weyburn                                              Coal          Canada 2000       5 MT      12 MT      17 MT
----------------------------------------------------------------------------------------------------------------
In Salah                                   Gas. Proc.       Algeria       2004       2 MT       7 MT      12 MT
----------------------------------------------------------------------------------------------------------------
Snohvit                                    Gas. Proc.        Norway       2007          0       2 MT       5 MT
----------------------------------------------------------------------------------------------------------------
Gorgon                                     Gas. Proc.     Australia       2010          0          0      12 MT
----------------------------------------------------------------------------------------------------------------
DF-1 Miller                                       Gas          U.K.       2009          0       1 MT       8 MT
----------------------------------------------------------------------------------------------------------------
DF-2 Carson                                      Pet Coke      U.S.       2011          0          0      16 MT
----------------------------------------------------------------------------------------------------------------
Draugen                                           Gas        Norway       2012          0          0       7 MT
----------------------------------------------------------------------------------------------------------------
FutureGen                                            Coal      U.S.       2012          0          0       2 MT
----------------------------------------------------------------------------------------------------------------
Monash                                               Coal Australia         NA          0          0         NA
----------------------------------------------------------------------------------------------------------------
SaskPower                                            Coal          Canada   NA          0          0         NA
----------------------------------------------------------------------------------------------------------------
Ketzin/CO2 STORE                                   NA       Germany       2007          0      50 KT      50 KT
----------------------------------------------------------------------------------------------------------------
Otway                                         Natural     Australia       2007          0     100 KT     100 KT
----------------------------------------------------------------------------------------------------------------
    Totals                                                                          16 MT      35 MT      99 MT
----------------------------------------------------------------------------------------------------------------
Source: Sally M. Benson (Stanford University GCEP), ``Can CO2 Capture and Storage in Deep Geological Formations
  Make Coal-Fired Electricity Generation Climate Friendly?'' Presentation at Emerging Energy Technologies
  Summit, UC Santa Barbara, California, February 9, 2007. [Note: Statoil has subsequently suspended plans for
  the Draugen project and announced a study of CO2 capture at a gas-fired power plant at Tjeldbergodden. BP and
  Rio Tinto have announced the coal-based ``DF-3'' project in Australia.]

    Enhanced Oil Recovery. Experience relevant to CCS comes from the 
oil industry, where CO2 injection technology and modeling of 
its subsurface behavior have a proven record of accomplishment. EOR has 
been conducted successfully for 35 years in the Permian Basin fields of 
west Texas and Oklahoma. Regulatory oversight and community acceptance 
of injection operations for EOR seem well established.
    Although the purpose of EOR heretofore has not been to sequester 
CO2, the practice can be adapted to include large-volume 
residual CO2 storage. This approach is being demonstrated in 
the Weyburn-Midale CO2 monitoring projects in Saskatchewan, 
Canada. The Weyburn project uses captured and dried CO2 from 
the Dakota Gasification Company's Great Plains synfuels plant near 
Beulah, North Dakota. The CO2 is transported via a 200-mile 
pipeline constructed of standard carbon steel. Over the life of the 
project, the net CO2 storage is estimated at 20 million 
metric tons, while an additional 130 million barrels of oil will be 
produced.
    Although EOR might help the economics of early CCS projects in oil-
patch areas, EOR sites are ultimately too few and too geographically 
isolated to accommodate much of the CO2 from widespread 
industrial CO2 capture operations. In contrast, saline 
formations are available in many--but not all--U.S. locations.

CCS in the United States
    A DOE-sponsored R&D program, the ``Regional Carbon Sequestration 
Partnerships,'' is engaged in mapping U.S. geologic formations suitable 
for CO2 storage. Evaluations by these Regional Partnerships 
and others suggest that enough geologic storage capacity exists in the 
U.S. to hold many centuries' production of CO2 from coal-
based power plants and other large point sources.
    The Regional Partnerships are also conducting pilot-scale 
CO2 injection validation tests across the country in 
differing geologic formations, including saline formations, deep 
unmineable coal seams, and older oil and gas reservoirs. Figure 11 
illustrates some of these options. These tests, as well as most 
commercial applications for long-term storage, will use CO2 
compressed for volumetric efficiency to a liquid-like ``supercritical'' 
state; thus, virtually all CO2 storage will take place in 
formations at least a half-mile deep, where the risk of leakage to 
shallower groundwater aquifers or to the surface is usually very low.



    After successful completion of pilot-scale CO2 storage 
validation tests, the Partnerships will undertake large-volume storage 
tests, injecting quantities of 1 million metric tons of CO2 
or more over a several year period, along with post-injection 
monitoring to track the absorption of the CO2 in the target 
formation(s) and to check for potential leakage.
    The EPRI-CURC Roadmap identifies the need for several large-scale 
integrated demonstrations of CO2 capture and storage. This 
assessment was echoed by MIT in its recent Future of Coal report, which 
calls for three to five U.S. demonstrations of about 1 million metric 
tons of CO2 per year and about 10 worldwide.\4\ These 
demonstrations could be the critical path item in commercialization of 
CCS technology. In addition, EPRI has identified 10 key topics \5\ 
where further technical and/or policy development is needed before CCS 
can become fully commercial:
---------------------------------------------------------------------------
    \4\ http://web.mit.edu/coal/The_Future_of_Coal.pdf .
    \5\ EPRI, Overview of Geological Storage of CO2, Report 
ID 1012798

---------------------------------------------------------------------------
   Caprock integrity.

   Injectivity and storage capacity.

   CO2 trapping mechanisms.

   CO2 leakage and permanence.

   CO2 and mineral interactions.

   Reliable, low-cost monitoring systems.

   Quick response and mitigation and remediation procedures.

   Protection of potable water.

   Mineral rights.

   Long-term liability.

    Figure 12 shows that EPRI's recommended large-scale integrated 
CO2 capture and storage demonstrations is temporally 
consistent with the Regional Partnerships' ``Phase III'' large-volume 
CO2 storage test program. EPRI believes that many of the 
storage demonstrations should use CO2 that comes from coal-
fired boilers to address any uncertainties that may exist about the 
impact of coal-derived CO2 on its behavior in underground 
formations.



CO2 Transportation
    Mapping of the distribution of potentially suitable CO2 
storage formations across the country, as part of the research by the 
Regional Partnerships, shows that some areas have ample storage 
capacity while others appear to have little or none. Thus, implementing 
CO2 capture at some power plants may require pipeline 
transportation for several hundred miles to suitable injection 
locations, possibly in other states. Although this adds cost, it should 
not represent a technical hurdle because long-distance, interstate 
CO2 pipelines have been used commercially in oilfield EOR 
applications. Economic considerations dictate that the purity 
requirements of coal-derived CO2 be established so that the 
least-cost pipeline and compressor materials can be used at each 
application. From an infrastructure perspective, EPRI expects that 
early commercial CCS projects will take place at coal-based power 
plants near sequestration sites or an existing CO2 pipeline. 
As the number of projects increases, regional CO2 pipeline 
networks connecting multiple industrial sources and storage sites will 
be needed.

Policy-Related Long-Term CO2 Storage Issues
    Beyond developing the technological aspects of CCS, public policy 
needs to address issues such as CO2 storage site permitting, 
long-term monitoring requirements, and post-closure liability. CCS 
represents an emerging industry, and the jurisdictional roles among 
Federal and state agencies for regulations and their relationship to 
private carbon credit markets operating under Federal oversight has yet 
to be determined.
    Currently, efforts are under way in some states to establish 
regulatory frameworks for long-term geologic CO2 storage. 
Additionally, stakeholder organizations such as the Interstate Oil and 
Gas Compact Commission (IOGCC) are developing their own suggested 
regulatory recommendations for states drafting legislation and 
regulatory procedures for CO2 injection and storage 
operations.\5\ Other stakeholders, such as environmental groups, are 
also offering policy recommendations. EPRI expects this field to become 
very active soon.
---------------------------------------------------------------------------
    \5\ http://www.iogcc.state.ok.us/PDFS/
CarbonCaptureandStorageReportandSummary.pdf.
---------------------------------------------------------------------------
    A state-by-state approach to sequestration may not be adequate 
because some geologic formations, which are ideal for storing 
CO2, underlie multiple states. At the Federal level, the 
U.S. EPA published a first-of-its-kind guidance (UICPG #83) on March 1, 
2007, for permitting underground injection of CO2.\6\ This 
guidance offers flexibility for pilot projects evaluating the practice 
of CCS, while leaving unresolved the requirements that could apply to 
future large-scale CCS projects.
---------------------------------------------------------------------------
    \6\ http://www.epa.gov/safewater/uic/pdfs/
guide_uic_carbonsequestratione_final-03-07.pdf.
---------------------------------------------------------------------------
Long-Term CO2 Storage Liability Issues
    Long-term liability for injected CO2 will need to be 
assigned before CCS can become fully commercial. Because CCS activities 
will be undertaken to serve the public good, as determined by 
government policy, and will be implemented in response to anticipated 
or actual government-imposed limits on CO2 emissions, a 
number of policy analysts have suggested that the entities performing 
these activities should be granted a measure of long-term risk 
reduction assuming adherence to proper procedures during the storage 
site injection operations and closure phases.

RD&D Investment for Advanced Coal and CCS Technologies
    Developing the suite of technologies needed to achieve competitive 
advanced coal and CCS technologies will require a sustained major 
investment in RD&D. As shown in Table 3, EPRI estimates that an 
expenditure of approximately $8 billion will be required in the 10-year 
period from 2008-17. The MIT Future of Coal report estimates the 
funding need at up to $800-$850 million per year, which approaches the 
EPRI value. Further, EPRI expects that an RD&D investment of roughly 
$17 billion will be required over the next 25 years.
    Investment in earlier years may be weighted toward IGCC, as this 
technology is less developed and will require more RD&D investment to 
reach the desired level of commercial viability. As interim progress 
and future needs cannot be adequately forecast at this time, the years 
after 2023 do not distinguish between IGCC and PC.

     Table 3.--RD&D Funding Needs for Advanced Coal Power Generation
                      Technologies  with CO Capture
------------------------------------------------------------------------
                2008-12     2013-17     2018-22     2023-27     2028-32
------------------------------------------------------------------------
Total
 Estimated
 RD&D
Funding        $830M/yr    $800M/yr    $800M/yr    $620M/yr    $400M/yr
 Needs
(Public +
 Private
 Sectors)
------------------------------------------------------------------------
Advanced            25%         25%         40%
 Combustion,
 CO2
Capture
--------------------------------------------------
Integrated                                              80%         80%
 Gasificatio
 n
Combined            50%         50%         40%
 Cycle
 (IGCC), CO2
Capture
------------------------------------------------------------------------
CO2 Storage         25%         25%         20%         20%         20%
------------------------------------------------------------------------

    By any measure, these estimated RD&D investments are substantial. 
EPRI and the members of the CoalFleet for Tomorrow program, by 
promoting collaborative ventures among industry stakeholders and 
governments, believe that the costs of developing critical-path 
technologies for advanced coal and CCS can be shouldered by multiple 
participants. EPRI believes that government policy and incentives will 
also play a key role in fostering CCS technologies through early RD&D 
stages to achieve widespread, economically feasible deployment capable 
of achieving major reductions in U.S. CO2 emissions.

    Senator Kerry. Thank you very much, Dr. Hannegan.
    Mr. Wolfe?

STATEMENT OF RON WOLFE, CORPORATE FORESTER AND NATURAL RESOURCE 
                 MANAGER, SEALASKA CORPORATION

    Mr. Wolfe. Good afternoon, Mr. Chairman, Members of the 
Subcommittee, my name is Ron Wolfe, and I am Corporate Forester 
and Natural Resource Manager for Sealaska Corporation. It's my 
pleasure to be here today to offer testimony on greenhouse gas 
emissions. I have submitted testimony in written form, and I 
ask that it be part of the record.
    I would like to first begin by introducing Sealaska. 
Sealaska is an Alaska Native regional corporation that was 
created as authorized by the Alaska Native Claims Settlement 
Act for Southeast Alaska. We have over 17,000 Tlingit, Haida 
and Tsimshian shareholders that are the descendents of the 
original inhabitants of Southeast Alaska. Our land and natural 
resources are the very foundation for which we are able to 
provide benefits to our shareholders, such as education and 
training, culture preservation, and yes our very economies in 
our villages.
    We see many opportunities to contribute to efforts to curb 
greenhouse gas emissions. But first we must ask ourselves, why 
are we sequestering carbon? And ultimately, it is to preserve 
the Earth's ecological functions. And for that reason, we 
believe that any program designed to encourage carbon 
sequestration, must create incentives and rewards for both 
carbon sequestration and maintenance of ecological functions. 
Trees are over 50 percent carbon, and forests have a tremendous 
capacity to take up and store carbon, but they also serve many 
ecological functions. Wood products store carbons for the 
duration of their use. A wood 2 by 4 in house construction 
stores carbon for as long as the house continues to serve as a 
house, and even, perhaps, longer, depending on what happens to 
the 2 by 4.
    More importantly, wood products require less carbon to 
manufacture than substitute products, such as aluminum, plastic 
or concrete. Woody biomass can be converted into ethanol or 
other renewable fuels, such as fuel pellet wood. All of these 
offer carbon savings over alternate fossil fuels.
    Providing carbon offset savings over fossil fuels will 
develop the commercialization of these technologies. Forest 
management practices in doing these things provides commerce 
and job opportunities to some of the poorest rural and 
predominantly Alaska Native areas of Southeast Alaska. Active 
management of these forests fits with the principle that we 
should first keep what we have.
    A program that rewards landowners for only the delta, or 
the increase in sequestration from carbon practices is not an 
incentive for keeping forests remaining as forests, and for 
managing them for the long-term carbon sinks that they can 
provide.
    For these opportunities to occur, the entire carbon forest 
budget and related ecological co-benefits must be taken into 
account, so purchasers get what they are paying for, sellers 
receive fair compensation for what they are providing, and this 
must be done with the appropriate verification, systems and 
protocols.
    In summary, Mr. Chairman, climate change solutions require 
a sequestration strategy. However, the ultimate reason to 
manage climate change is to preserve the earth's ecological 
functions. Any forestry sequestration strategy must ensure that 
we get the right outcome. Single-focus sequestration strategies 
can negatively impact ecosystem diversity, strategies to 
provide incentives in sequestration and maintaining co-benefits 
of ecological functions should be rewarded. A national policy 
should reward all carbon sequestered in a forest, it should 
clarify that harvesting forests for renewable fuels and 
products is within sequestration objectives.
    I am happy to answer any questions of the Committee. Thank 
you, Mr. Chairman.
    [The prepared statement of Mr. Wolfe follows:]

    Prepared Statement of Ron Wolfe, Corporate Forester and Natural 
                 Resource Manager, Sealaska Corporation

Introduction
    Good afternoon Mr. Chairman, Members of the Subcommittee. My name 
is Ron Wolfe, Corporate Forester and Natural Resource Manager for 
Sealaska Corporation. Thank you for this opportunity to present 
testimony on the United States' efforts to control greenhouse gas 
emissions.
    I would like to begin by telling you who we are. Sealaska 
Corporation (Sealaska) is one of 12 Regional Corporations established 
pursuant to the Alaska Native Claims Settlement Act (ANCSA) of 1971. 
Sealaska is the Regional Corporation for Southeast Alaska. Sealaska has 
over 17,000 shareholders and is the largest private landowner in 
Southeast Alaska. Our shareholders are the descendants of the original 
inhabitants of Southeast Alaska, the Tlingit, Haida and Tsimshian 
Indians. Our land and natural resources provide the foundation for our 
business strategies to deliver benefits to our Native shareholders. 
Sealaska also plays an important role in educating and training its 
Native shareholders, through scholarships and internship programs, and 
in preserving the culture of the Native people of Southeast Alaska.
    Sealaska and other southeast Alaska Native entities own more than 
575,000 acres of coastal temperate rainforest located in the panhandle 
of Southeast Alaska from as far north as Yakutat on the outer coast of 
the Gulf of Alaska to the Prince of Wales/Dall Island area at Dixon 
Entrance, the boundary between Alaska and Canada.
    Given our substantial forest land holdings, we see many 
opportunities for Alaska Natives to contribute to the global efforts to 
address global warming as well as to create economic benefits for 
themselves and others. My testimony today outlines Sealaska's current 
thinking with respect to these opportunities.

Our Carbon Mission
    Sealaska strives to manage its natural resource holdings in a 
manner that maximizes the various multiple uses of those resources. As 
we consider carbon sequestration strategies and technologies we need to 
ask what our motivation is for sequestering carbon. Ultimately the goal 
is to preserve earth's ecological functions. As such we should not 
focus exclusively on carbon sequestration as a panacea without 
understanding the ecological consequence of our actions. We believe 
that any Federal program designed to encourage carbon sequestration 
must create incentives that reward systems that both sequester carbon 
and protect and enhance ecological functions.
    Trees are mostly carbon, about 50 percent or more by weight (the 
balance being primarily water), and have a tremendous capacity to take 
up and store carbon. The forests of Southeast Alaska are a coastal 
temperate rain forest with few disturbance agents and for several 
centuries have been free of catastrophic forest fires, creating a 
relatively stable carbon storage unit. But these forests do much more 
than store carbon. They also provide clean air, clean water, wildlife 
habitat, stream habitat, erosion control and soils protection, 
ecosystem and ecological functions, as well as recreation, hunting and 
fishing, subsistence, reverent religious experiences and spiritual well 
being opportunities.
    Sealaska has embarked on an effort to document how management of 
the temperate rainforests of S.E. Alaska sequesters carbon and provide 
other co-benefits. These efforts can help guide development of policies 
and regulations that create the right incentives to induce forest land 
owners to ``grow carbon'' and to create other co-benefits including 
ecological functions.
    We all understand that carbon sequestration using trees is not a 
silver bullet that will absorb the huge influx in carbon emissions that 
needs to occur to stabilize climate change. But, forests can be managed 
to sequester carbon and to be part of a combination of solutions needed 
to solve the climate change crisis. To that extent the Committee needs 
to appreciate that a policy directed to keep forest lands in tree 
production is an important component of a carbon sequestering strategy. 
The right policies and inducements can entice forest land owners to 
manage lands to optimize carbon sequestration.
    Our analysis concludes that managing a forest purely for maximum 
sequestration may cause a deterioration of the ecological functioning 
of forest lands. I have provided two graphic attachments from a 
computer model that predicts tree growth. The pictures show the results 
of two different management strategies. The first illustration depicts 
a strategy to maximize carbon sequestration:



    The second illustration depicts a strategy to optimize carbon 
retention and protect other ecological functions:



    Both forests are the same age, but one has many small trees with 
less ecological function, whereas the other has larger trees and much 
better ecological function.
    Modern forest managers of today require inventory systems and data 
capable of planning at both the individual ``stand'' level and at the 
landscape level. Sealaska's forest planning software (FPS) \1\ is 
designed to assist us to manage forest stands for optimum benefits. 
From FPS we are able to provide visual representation of the forest 
condition over time and to calculate the amount of carbon our forests 
grow over time for a variety of management regimes and prescriptions.
---------------------------------------------------------------------------
    \1\ Information about this software program can be found at http://
www.forestbiometrics.com/
---------------------------------------------------------------------------
    These diagrams demonstrate two principals:

        1. A tree canopy that is dense will block sunlight reaching the 
        forest floor, significantly retarding growth of ground 
        vegetation important for forest diversity. This is the best 
        strategy to maximize carbon sequestration in our forests.

        2. Conversely a tree canopy that is managed to create open 
        spaces allows sunlight to reach the forest floor enhancing 
        brush, shrubs and forbs production that serve as food for 
        wildlife and other important ecosystem functions. This is the 
        best strategy to optimize both carbon sequestration and 
        ecological functions.

    Close inspection of the diagrams for an unmanaged forest reveals a 
very densely stocked stand of trees that shuts out virtually all 
sunlight beginning at age 30 and persists until age 180 when individual 
trees begin to die and fall to the forest floor; even then little 
sunlight reaches the forest floor. Compare now a stand that has been 
thinned early in its development by removing the small trees at age 15; 
much more sunlight is allowed to reach the forest floor, and this 
condition persists with time. Herein lies the co-benefits to wildlife 
and ecosystem functions. While the unmanaged forest shades all sunlight 
to the forest floor, the managed forest allows the sunlight to reach 
the forest floor.
    Consistent with the ultimate goal of carbon sequestration we 
believe that any Federal climate change regulatory program should 
reward for both sequestration of carbon and enhancing ecological 
function. Likewise, Federal research and development initiatives should 
be focused on how best to maximize carbon sequestration, while also 
maintaining and enhancing the other ecological functions provided by 
the forest.
    Mr. Chairman, I would also like to point out that proper management 
of the forest is not the only way to store and save carbon. Products 
made from wood store carbon for the duration of their use. A wood 2 x 4 
stud used in house construction stores carbon so long as the house 
stands and perhaps longer depending on what happens to the 2 x 4 when 
the house is taken down. Further, and perhaps more importantly, a wood 
2 x 4 requires less carbon to manufacture than substitute products such 
as aluminum, cinder blocks, bricks or concrete, creating a savings in 
carbon.
    Similarly, use of forest materials can reduce carbon emissions in 
the energy sector. Sealaska has investigated a variety of technologies 
to convert lignocellulosic biomass (wood and bark) into ethanol and 
other renewable fuels. Our studies with the Department of Energy have 
proven several viable technologies for creation of renewable fuels. 
Pellet fuel wood produced from biomass that is currently waste in the 
forest, or from the manufacture of wood products, also offers savings 
in carbon over alternate fossil fuels. Providing carbon offset credits 
for these benefits would facilitate the development and 
commercialization of these technologies.
    Lastly, it is important to point out that active management of 
forests is not a silver bullet in the total sequestration game, but 
fits within what should be the first rule of sequestration policy 
``keep what you have.'' Consistent with this rule, Sealaska believes 
that any Federal climate change program should provide incentives to 
forest land owners and managers to keep lands in forest production and 
not convert forest lands to other uses. The argument that forest land 
owners should be awarded for only the delta or increase in 
sequestration from current practices is not an incentive for retaining 
forest lands and managing to be long-term carbon sinks.
    In summary, Mr. Chairman, climate change solutions require a 
sequestration strategy. However, the ultimate reason for addressing and 
attempting to manage climate change is to preserve the earth's 
ecological functions. Any forestry sequestration strategy must ensure 
we get the right outcome:

   Single focus sequestration strategies can negatively impact 
        ecosystem diversity.

   Strategies to provide incentives for sequestration and 
        maintaining co-benefits should be rewarded.

   A national policy for forest sequestration should reward for 
        all carbon sequestered in a forest and clarify that within 
        appropriate management prescriptions harvesting forests for 
        renewable fuel and wood products is within the sequestration 
        objectives.

    Southeast Alaska's forests generate a broad spectrum of ecosystem 
goods and services (both carbon and other ecological co-benefits). 
Forest management practices directed to sequester carbon can provide a 
wide array of economic opportunities important to the public, 
especially to American Indians and Alaska Natives. Sequestering 
activities can create new commerce and job opportunities in some of the 
poorest rural, predominately Native areas of S.E. Alaska, while 
enhancing the forest's ecological functions.
    By creating a regulatory framework that expands the economic 
opportunity to sequester carbon in these forests, the American public 
will benefit by managed landscapes that promote enhanced biodiversity 
and contribute in a positive way to greenhouse gas climate control. For 
these benefits to occur public policy must allow accounting of the 
entire forest carbon budget and related co-ecological benefits so 
purchasers get what they are paying for and sellers receive fair 
compensation for what they are providing with appropriate carbon 
sequestration verification systems and protocols.

Comments on S. 2191--America's Climate Security Act
    Mr. Chairman, the Subcommittee on Private Sector and Consumer 
Solutions to Global Warming and Wildlife Protection of the Committee on 
Environment and Public Works has just reported S. 2191, the America's 
Climate Security Act. Since it appears that S. 2191 is a likely vehicle 
for Senate consideration of a climate change regulatory program, we 
would like to take this opportunity to provide our views on the 
legislation.
    Sealaska strongly supports the provisions of S. 2191 that create 
two opportunities for forestry landowners to participate and earn 
revenue through sequestration--

   the set aside of 5 percent of the annual emission allowance 
        budget for agricultural and forestry projects under section 
        3701; and

   the opportunity to generate and sell offset allowances under 
        section 2402.

    Both of these programs could provide significant contribution to 
the ultimate success of the U.S. efforts to control and reduce 
greenhouse gas emissions as well as provide substantial economic 
benefits to Sealaska and similarly situated land owners if the rules 
are right.
    It is critical that the rules for what projects are eligible for 
emission allowances or offset allowances be consistent with our above 
testimony and focus on the credibility of each project. The rules 
should not limit the universe of projects that may qualify.
    If the offsets from a project meet the legislation's test of 
representing ``real, verifiable, additional, permanent, and enforceable 
reductions in greenhouse gas emissions or increases in biological 
sequestration'' then that ought to be sufficient to receive allowances. 
There should not be any other artificial constraints on the ability of 
a particular project to earn such allowances.
    To ensure maximum benefit from these two opportunities and maximum 
participation from forestry and agriculture land owners, the outreach 
program called for in Section 2401 and the research and development 
program called for in Section 3702 are essential. They need to be 
comprehensive, robust and well-funded.

Conclusion
    Sealaska appreciates the opportunity to testify on this very 
important subject. Forest conservation and management needs to be a 
critical component of any cap and trade system designed to mitigate 
global green house emissions based on the voluntary participation of 
landowners. This business and regulatory framework must provide 
economic incentives that exceed the opportunity costs of other resource 
uses or land conversion for landowners to be successful. Managing 
organizations with a fiduciary responsibility must adhere to a higher 
standard of economic decision-making and carefully weigh future land 
uses and opportunities to generate sustainable sources of revenue. A 
properly designed national climate change regulatory program can be a 
``win/win'' situation for the Nation and Sealaska. We stand ready to do 
our part to benefit the global climate, mankind and our shareholders 
and look forward to working with the Congress in that endeavor.
    I am happy to address any questions the Subcommittee may have, Mr. 
Chairman.
    Thank you.

    Senator Stevens [presiding]. Thank you very much.
    Amy, you came in late, do you want to have--do you have an 
opening statement?
    Senator Klobuchar. I can do it with my questions, go ahead.
    Senator Stevens. All right, thanks.
    Mr. Wolfe, I know you have a real background in terms of 
serving the Alaska community, and in particularly the Native 
communities--I wonder if, you know, through your history you 
could tell us--this carbon sequestration must be a diversified 
effort, utilizing a variety of technologies, such as forest 
management. How, really, tell us how this forest management 
will, in terms of the percentage of overall carbon 
sequestration, how will it increase the goals of sequestration?
    Mr. Wolfe. Senator Stevens, I'll be happy to provide more 
information on that for the record.
    I believe that the ability of forests to sequester and 
store carbon is a part of an overall strategy----
    Senator Stevens. Let me interrupt you--is it just a 
standing forest? Or new timber? Or old timber? How does it--
does it vary with age, in terms of its ability to sequester 
carbon?
    Mr. Wolfe. Senator Stevens, actually, younger forests are 
better at taking up carbon and absorbing it, and in my 
testimony, I offer that for this to properly be accounted for, 
we need to look at the total carbon budget, and that includes 
not only the growing in the forest, but storing of carbon in 
the form of standing trees, but also in the products in which 
we produce and the, viewing the substitutes, alternative 
products in lieu of wood products.
    Senator Stevens. Dr. Benson, our State has half of the coal 
in the United States, most people don't realize that. Is it 
possible to have sequestration take place in terms of the 
functions we're looking at now, of coal gasification and coal 
liquefaction?
    Dr. Benson. Yes, it certainly is, and it's also possible to 
sequester carbon dioxide in deep un-mineable coal beds, as 
well. And there are very significant, in Alaska and actually in 
many places in this country, where carbon dioxide could be 
stored in deep un-mineable coal beds, as well, and it's also 
possible to increase methane recovery in the course of those 
operations.
    Senator Stevens. When I recently had a briefing from the 
University of Alaska about the increased methane that's seeping 
out from the permafrost as it's more and more exposed in Russia 
and in Alaska, is there a concept of methane sequestration, is 
that possible?
    Dr. Benson. Thus far, I'm not familiar with a methane 
sequestration strategy. The issue you bring up is really very 
significant, having to do with the melting of the permafrost, 
and large methane emission into the atmosphere, which are much 
more potent greenhouse gases than are carbon dioxide.
    I'm not familiar with a strategy to manage those emissions.
    Senator Stevens. Well, I was told each unit of methane 
contains 22 units, 21--22 units of carbon monoxide, is that 
right?
    Dr. Benson. They have the power of greenhouse gas, a global 
warming power about 22 times higher than carbon dioxide does.
    Senator Stevens. So, and I'm happy to join Senator Kerry in 
his bill about these demonstration projects, but should we have 
demonstration projects on other substances such as methane?
    Dr. Benson. I think you bring up a very interesting point, 
and remedial strategies to avoid those methane emissions would 
be a very useful element of a way to manage greenhouse gas 
emissions. So, yes, I think it's a good idea.
    Senator Stevens. I was told it might be possible to capture 
them, and to use them in the form of natural gas and when that 
was burned it would emit less, fewer units of carbon monoxide, 
is that correct?
    Dr. Benson. If you burn methane, it emits less carbon 
dioxide than does coal. So, yes, it's very beneficial. It could 
be quite difficult to capture, though, these emissions which 
are occurring over, you know, many thousands of acres, and a 
whole new strategy to capture those emissions from the land 
surface into the atmosphere would be needed, with regard to 
those methane emissions.
    Senator Stevens. Well, I've got to get, there's a young 
scientist at the University of Alaska that, she has briefed us 
on what might be possible to capture a substantial portion of 
those emissions, those leakages, I call them, of methane, as 
the permafrost warms.
    Are we still following the early bird rule?
    Dr. Hannegan. Senator Stevens? If I might add, if we're 
successful at developing these CO2 capture 
technologies for coal plants, those are also applicable to 
natural gas units, as well. So, if you're successful at 
harnessing the natural gas from the permafrost, that is of 
concern to you, and you use that to generate electricity, 
number one, they generate fewer CO2 emissions per 
kilowatt hour of electricity, but number two, you can also 
benefit from this research in terms of capturing the 
CO2 from those plants, as well.
    Senator Stevens. I have to--I think it's very interesting 
that the amount of this methane that was projected to be coming 
out of the Arctic, compared to the history of methane seepages 
is just overwhelming. And, I think we ought to do something 
about trying to capture as much as we can.
    Senator Ensign?
    Senator Ensign. Thank you, I found your testimony 
fascinating, and I think that we're dealing with an exciting 
area, but also it sounds like a very technologically 
challenging area, dealing with the environment and energy 
production.
    What I didn't hear was--there was mention, I forget which 
one of you mentioned that we should at least study three of the 
geologic formations that should have potential for carbon 
capture sequestration--what are the three types, I mean, the 
one that was mentioned--but what are the other types? Does 
anybody want to take a--Mr. Herzog?
    Mr. Herzog. I mentioned that we should do at least three 
demonstrations to get a representative geology. But, what you 
need to understand is, say we say saline formations----
    Senator Ensign. Right.
    Mr. Herzog. They're very--what we call--heterogeneous. So, 
one saline formation may look very different than the others. 
Some may have low permeability, some may have high 
permeability. There's lots of different characteristics. So, 
there's different cuts you can make, so one thing one has to do 
when you look at these demonstrations is say, what's the type 
of, you know, when you look at these formations, what's the 
main type of characteristics they have, and sample 
representative ones to do these demonstrations in. I think some 
of my colleagues here know a little more about the geology than 
me.
    Senator Ensign. And also in that, have you identified, you 
know, potential sites where these things could occur in the 
United States, could you give me a few examples?
    Mr. Herzog. There's a large set of aquifers under the 
Midwest, there's a whole set of aquifers in the Gulf Coast and 
the Southeast U.S., there's some out in the Western U.S., and 
we haven't sat down and specifically said which ones should be 
done, and there's probably a lot more than three if you want to 
do, but we think three could cover a large majority of traits 
of those aquifers.
    Senator Ensign. Dr. Benson?
    Dr. Benson. Could I provide a remark? So, there--a National 
Sequestration Atlas has been developed now, so there's quite a 
lot of information on the distribution of sequestration 
options, both in terms of saline aquifers, oil and gas 
reservoirs and coal formations.
    And, so basically if you look at the United States, with 
the exception of parts of the Northeast, and parts of the 
Southeast, in particular the coastal plain, there are a wide 
variety of resources that are available, and many attractive 
targets for sequestration.
    Senator Ensign. Just, because, obviously, being a 
layperson, just to give us some idea of volume. When you're--
how much, let's say we have a coal-fired power plant, let's say 
it's a 400-megawatt coal-fired power plant. The amount of 
CO2 that that produces in a year, how much physical 
volume would that take up? Yes?
    Dr. Burruss. I'd like to address that, Senator.
    A power plant on the order of 500 megawatts, or 400-500 
megawatts, would produce on the order of 300 million tons of 
carbon dioxide each year. And if you envision taking that and 
injecting it into the subsurface, and convert that into volume 
of the fluid in the subsurface, over a 20 to 50 year lifetime, 
envisioning an actual working project, that kind of project 
would use the equivalent of about a 1 to 2 billion barrel oil 
field. If you, sort of, think in terms of those of you who are 
from oil-producing states--that's a fairly large oil field. 
There are not a lot of them, but we do know that they have the 
capability of storing CO2, but I think that gives 
you some scale to envision a storage operation for a single 
project.
    Dr. Hannegan. And to put that in perspective, the largest 
existing post-combustion pulverized coal equivalent, or excuse 
me, yes, post-combustion unit in current operation is about 800 
tons per day, or about 50,000 tons per year. So, you're talking 
about a scale up to 50,000 to 300 million--there's a lot of 
research work that needs to be done. And not only just in a 
variety of geologies, but also with a variety of coals--how you 
handle bituminous versus lignite, versus subituminous will 
vary, just as the geologies will vary, as well.
    Senator Ensign. One of the reasons that I wanted to have an 
idea of the volume is that if we are talking about trying to do 
even more coal plants into the future, do we have that volume 
available? I mean, it sounds like that the, you know, that size 
of an oil field, and if there aren't that many of those types 
of oil fields, at least in the United States, that those other 
types of aquifers that we're talking about would have to be 
used. And, is there that volume out there, I guess?
    Dr. Benson. So, I'll address that, and answer two contexts. 
But, I want to answer your first question--4,000 Olympic-sized 
swimming pools is one coal plant for 1 year, so just as a, sort 
of, back of the pocket number.
    So, the question about worldwide capacity and U.S. 
capacity. So, estimates worldwide are that we have anywhere 
between 2,000 and 10,000 billion tons worth of storage 
capacity. That's at the low-end of the range, that's enough for 
about 100 years of the maximum amount of carbon dioxide that we 
can imagine sequestering.
    If we look in the U.S., the current estimates are that 
there are about 3,000 million tons worth of sequestration 
capacity--3,000 billion tons--again, in the range of hundreds 
of years of capacity.
    However, though, the global numbers, or the U.S. numbers 
are quite impressive, regionally it can be quite different, and 
there may be smaller resources, and that's why these detailed 
capacity--regional capacity assessments are important.
    But, the bottom line is the number is big. Hundreds of 
years worth of capacity.
    Senator Ensign. Just--and I don't know, my time's up, but 
it would seem to me that if we can make at least a difference 
into the future, and maybe with new plants that come online, 
you know, we might not need every coal plant to have its carbon 
captured. But if we can make a difference, and like, Dr. 
Hannegan, I think you talked about, combining that with 
nuclear, combining that with other alternative energies into 
the future, that the greenhouse-type gases that are released 
into the atmosphere, you can make a serious dent in it through 
technology, and I think that that's really the underlying 
purpose of the hearing.
    Dr. Hannegan. Just as a further point to that, the 
challenge with retrofitting today's existing coal units with 
CO2 capture and storage really can't be understated. 
You're talking about putting a small chemical facility 
alongside an existing plant, which probably has space 
constraints, which probably would need significant re-
engineering, and so we're primarily looking at new units as the 
first place in which these technologies would be deployed.
    Senator Stevens. Senator Klobuchar?

               STATEMENT OF HON. AMY KLOBUCHAR, 
                  U.S. SENATOR FROM MINNESOTA

    Senator Klobuchar. Thank you very much, and I'd like to 
thank my Senate colleagues for holding this hearing. I'm 
fortunate to not only serve on this Committee, but also the 
Environment and Public Works Committee. And as you know, we're 
working hard on comprehensive legislation on climate change, 
and in fact, have a bipartisan bill, the Lieberman-Warner bill, 
I'm a co-sponsor of it, and we are working very hard to get 
that through the Committee in the next few weeks.
    One of the many provisions of the bill establishes a 
framework for the geological sequestration and storage of 
carbon dioxide, Title VII of the bill initiates a series of 
rulemakings in geological surveys and scientific studies 
designed to pave the way toward a national infrastructure for 
carbon capture, transportation and storage. So, I was very 
interested in what you were talking about today.
    My first questions were just to follow up a little bit, I 
know Senator Ensign was getting at this with you, Mr. Herzog, 
but how this would work with these demonstration projects, or 
some projects going on right now, but they're in Texas, is that 
right? Or other places? That aren't a full-scale demonstration 
that you're talking about?
    Mr. Herzog. There are some, what I would call pilot 
projects that inject maybe a couple of thousand tons, maybe up 
to 10,000 tons of CO2. What we're interested in are 
demonstrations on the scale of about a million tons a year, you 
know----
    Senator Klobuchar. Exactly.
    Mr. Herzog. Not exactly a million, but that type of scale.
    Because, what you need to do is put enough in a reservoir 
so that you see what happens to the features at, sort of, this 
commercial scale. So, you get feedback from the pressure, 
seeing those that get sent in, and you start seeing what 
happens on these scales. The small tests you can learn some 
things, but you can never learn----
    Senator Klobuchar. Exactly.
    Mr. Herzog.--the big scale.
    Senator Klobuchar. And what's the timeline, do you think, 
that you could have for this, in terms of getting this done?
    Mr. Herzog. Well, we think you could have a series of these 
things, and they have to go in parallel, not one after another, 
but I think you're looking at an 8 to 10 year period, partially 
because you want to have several years of injection with each 
of these projects, it would take 2 or 3 years to get them 
started----
    Senator Klobuchar. And you think they'd be commercially 
viable at that time?
    Mr. Herzog. I think what we would say that the technology 
will be commercially ready, whether it's totally commercial 
depends partly on the cost, what type of climate regulations 
there are in the marketplace.
    Senator Klobuchar. Do you agree with Dr. Hannegan's 
assessment that it's better to go forward with new projects, 
rather than retrofitting?
    Mr. Herzog. I think it's going to be less expensive with 
new projects than with retrofitting. I think that as we learn, 
I think hopefully we have the technology to be able to retrofit 
at least some of the plants, and----
    Senator Klobuchar. So, it would be possible?
    Mr. Herzog.--over time you may have, whether it's a 
retrofit, or a plant gets shut down and a new plant gets built 
on that same site, eventually over time, that could happen, 
too. So, I think----
    Senator Klobuchar. So, you think that maybe working on 
these demonstration projects could help with the retrofitting 
technology as well?
    Mr. Herzog. Well, I think the same technology that you 
would use for new plants would also be for retrofits. At least 
for some. I mean, if you're looking, say, the pathway with 
gasification, most of our current plants are combustion, so 
they may not work well with that, but we recommend in our 
report they should work on both gasification and combustion 
pathways as you go forward.
    Senator Klobuchar. And, Mr. Fox, you talked about how the 
most economical way to transport large volumes of 
CO2 would be by pipeline, and if carbon capture and 
sequestration becomes a commercial reality, what increases in 
the pipeline infrastructure would be needed, if any? Are there 
any other ways to transport this?
    Mr. Fox. There are other ways to transport it, but they are 
very expensive. You can put it in a truck, but it's only small 
volumes, it's about three times as expensive. You could put it 
into railcars, again, it's very expensive, so--what we're 
talking about here with such a pervasive problem, you'll either 
put it into pipelines, or if possible, you could put it into 
ships, if you were going to take it offshore.
    Senator Klobuchar. So, do you think we'd need more 
infrastructure if we really----
    Mr. Fox. We would definitely need more infrastructure--it's 
taken about 20 years to build a fair sized infrastructure in 
the Permian Basin, to replicate something like that would be 
about $3 billion today, and there was a Professor, Dr. Sokolow, 
who said that--broke down this whole carbon capture, carbon 
problem into 7 wedges, one of which was carbon sequestration. 
Worldwide, by 2050 you'd have to build 150 Permian Basins, 
about 40 of those would have to be in the United States. So, it 
would be----
    Senator Klobuchar. Because I would think--what is it, China 
is constructing the equivalent of two 500-megawatt coal-fired 
plants a week? Is that right?
    Mr. Fox. Yes.
    Senator Klobuchar. And is this when you, Dr. Benson, were 
going through these projections, you figured that into it as 
well? With your Olympic swimming pools?
    Dr. Benson. Right, well, certainly, yes. We need thousands 
of these projects.
    Senator Klobuchar. OK. And, so, Mr. Fox I should have let 
you finish.
    Mr. Fox. I think that we certainly know how to pipeline the 
CO2 safely. One of the issues that is going to come 
up is, I think that the coal plants are not going to want to, 
may not want to clean up the CO2 to what is now 
pipeline specs, and if you put impurities in there like 
hydrogen sulfide, or SOX and NOX, it 
makes it a little more difficult, a little bit more dangerous 
to transport. Certainly not something you couldn't do in a 
rural area, but if you're doing it in a city, an urban area, it 
raises some issues that we really haven't addressed, there 
hasn't been anybody, bothered to look at how to do that safely.
    Senator Klobuchar. Dr. Burruss?
    Dr. Burruss. Yes, Senator, I'd like to make a comment that 
one issue that you've raised with pipelines and the issue with 
retrofitting where they interact is the fact that the largest 
coal-fired power plants in the country today are basically 
along the Ohio and Mississippi River Valleys. They're basically 
in the Midwest, and also in the East. But the storage that we 
know the most about, the large oil fields of the kind that Mr. 
Fox has worked on for enhanced oil recovery, are in West Texas, 
and along the Texas Gulf Coast, so there's actually at present 
day, a mismatch between the largest existing sources of power 
plants, and the places we know the most about storage today. 
So, that would basically imply, if we're going to connect the 
two, we clearly have to build more pipeline infrastructure. 
Otherwise, we have to go forward with new plants that might be 
co-located with the best storage, and decrease the amount of 
pipeline necessary to connect those.
    So, there's some important tradeoffs to consider in 
infrastructure between new technologies, retrofit, and 
pipelines.
    Senator Klobuchar. Just one last question before I turn it 
over to Senator Stevens, just to follow up on the retrofitting 
and the cost you foresee for this and the future of this, if 
anyone else wanted to comment on that----
    Dr. Hannegan. Sure. Senator, I'm happy to do that, and 
clarify, a bit, my earlier comments.
    Retrofit is, from an engineering standpoint, more 
difficult, with existing units primarily because of the space 
requirements, and because of the fact that these plants were 
not engineered to capture and store the CO2 in the 
first place. That doesn't mean it can't be done, it certainly 
can be done, and one of the ways in which we foster that 
possibility is to do work, not only on gasification, but on 
post-combustion capture as well, from pulverized coal units, 
since they make up the majority of what's in the fleet right 
now. So, that underscores the need to do research on this, 
across the wide range of coal technologies.
    Our work has shown that the energy penalty, and thus, the 
economic cost associated with capturing CO2 from a 
pulverized coal unit, is presently around 30 percent, and that 
with advances in technology of the kind that we envision in our 
road map, you can bring that down to a 10 or a 15 percent 
increment, and in so doing coal--even with CO2 
capture--becomes part of the--you know, it stays the backbone 
of the electric system, even under a carbon constraint.
    Senator Klobuchar. All right. Thank you very much.
    Senator Stevens?
    Senator Stevens. Dr. Hannegan, you have given us a 
description of your UltraGen project, and you had the option 
there of capturing 25 percent of the CO2 from the 
plant. Why 25 percent? Why not 10? Why not 50? Is this cost-
related?
    Dr. Hannegan. Thank you for asking that question, Senator 
Stevens. The UltraGen project that we've proposed and put 
before a number of folks in the industry to consider, is a new 
large, 800-megawatt clean and efficient pulverized coal plant. 
So, 25 percent of the CO2 from that 800-megawatt 
plant is effectively a 200-megawatt, fully captured, activity. 
Which is larger than what's currently being done out there, at 
a pilot stage, and it's frankly, the maximum level to which we 
think we can pilot existing developmental technologies for 
post-combustion capture with some reasonable certainty that 
this will actually work. We could scale it up, but the risk 
involved in scaling that project up even further to 50 or 80 or 
90 percent, technologically we're not ready to support that, 
given the research that we've done so far, and the basis for 
the pilot projects that we've done to date.
    Senator Stevens. On that same project, would the 
demonstration proposed there for UltraGen I qualify for Federal 
funding under existing law? That's the Energy Act of 2007?
    Dr. Hannegan. As it presently reads, Section 304 of H.R. 6 
requires an 85 percent of the produced carbon dioxide at the 
facility to be captured in order to qualify for funding under 
that section. It also requires it to be half a million short 
tons per years.
    In the case of UltraGen I, the first of the two that we 
would foresee going forward at 25 percent, it would not qualify 
for that funding. But the second, the follow-on, UltraGen II, 
we would treat at least 50 percent of the flue gas, with a 90 
percent removal process. And then the Ultimate Plant, sometime 
into the future beyond UltraGen II there, would be a full-scale 
90 percent capture and deployment that it would, clearly 
satisfy the requirements in the Senate language.
    Senator Stevens. Let me ask this for the panel, this will 
be my next to last question. There are sizable areas of 
production of coal, or gas, and the consumers, the plants where 
that energy is used are fairly far from the place of 
production. Has anyone looked into the question of, can we 
sequester this carbon before it's transported to a plant in, 
you know, somewhere in Texas, to Ohio, and then it's burned 
there, and then you want to transport the CO2 back 
to Texas? It does seem to me that one of the answers might be 
to try to find some way to sequester this carbon at the point 
of production of the energy itself, am I off base?
    Dr. Benson, am I off base?
    Dr. Benson. No, and I think as we look to the future energy 
system, co-location of generating capability with storage 
capability will become a very desirable attribute. The 
situation we're in right now----
    Senator Kerry [presiding]. Doctor, I think the Senator's 
asking about extraction, production----
    Senator Stevens. But she's talking about at the point of 
extraction, right?
    Dr. Benson. Right.
    Senator Kerry. You're talking about production of the 
energy.
    Dr. Benson. Right, so it would be desirable to locate the, 
our plant where you can store the CO2.
    Senator Stevens. That's what we were experimenting with 20 
years ago, but we ran into the problem of the line loss. It's 
my understanding now that the line loss of high voltage is 
miniscule to what it was 20 years ago. Why aren't we pursuing 
the sequestration at the point of production?
    Dr. Burruss, you started to answer that.
    Dr. Burruss. Well, I don't, I think the question--you've 
raised an excellent question, the only way we can answer that 
is to basically decide to go forward with these large 
demonstration plants and make a decision--should we locate them 
where the best storage is, and then if there are electrical 
generating plants, move the electricity, versus the question of 
capturing CO2 where it may be present, generated at 
present, and then move the CO2 to a storage site. We 
simply--those questions have been considered in economic 
models, but there's no final decision about which one would be 
the best choice.
    Senator Stevens. My last question, and thank you, Senator, 
when it comes right down to it, is this finally going to be a 
question of cost? We know the problem, and we have to move 
forward. Is anyone analyzing what is the best use of the 
investment now? I know we're going to go with these 
demonstration projects, and I support that bill as I said, but 
has anyone looked at the overall national program of how to do 
this job of sequestration and do so the most efficiently, and 
effectively from the point of view of the use of investment?
    Dr. Hannegan. Yes, Senator, we--as I mentioned in my 
testimony if you would look at the slide number 2 in our 
submittal, we've actually done some very detailed economic 
analysis of what an efficient pathway to de-carbonizing the 
U.S. economy would look like, and it involves making some 
significant investments in research and development today that 
put us in better stead to efficiently and economically de-
carbonize the economy over the next several decades, and the 
data that we show here out to 2050.
    What we've done is we've contrasted an approach on the 
left-hand side, which waits until the carbon constraint 
arrives, and then begins the research, versus one which does 
the research in advance of the carbon constraint, and actually 
develops more tools in your toolbox.
    Senator Stevens. Respectfully, that doesn't deal with my 
mind, I'm an appropriator, looking at money.
    Dr. Hannegan. Yes, sir, I understand.
    Senator Stevens. How are we going to use the money we have 
available now most effectively to achieve our goals in the 
future?
    Dr. Hannegan. The underlying work behind this analysis, 
Senator, contains very detailed timetables and research road 
maps and actual expenditure amounts that we believe are 
necessary to achieve the R&D goals outlined in our work, and 
I'm happy to put that into the record if you're interested.
    Senator Stevens. I would.
    Senator Kerry. We would like that.
    Senator Stevens. I said last question, but Dr. Benson wants 
to answer. What do you have?
    Dr. Benson. I just want to add something--I think that the 
demonstration projects are incredibly important, but at the 
same time we need to be sure that we're building the 
fundamental research base. And there's a high amount of 
leverage for a tiny fraction of the amount that you're putting 
into these very large-scale demonstration, you can have a 
tremendous amount of learning that's occurring. In addition, 
you'll be developing the capacity for students, and the future 
workforce will be able to do this.
    So, I think that fundamental research is an important 
component, and I also believe that these small-scale pilot 
tests are also very important, because in reality, we're going 
to have, you know, maybe 5 demonstration projects, while in 
reality, we probably have 40 or 50 places where we would like 
to sequester CO2. The very small-scale pilots are 
complementary to the big demonstration projects, so that 
there's a readiness that's being developed, both in terms of 
the regulatory community and detailed geologic knowledge. So, 
all three, I think, are very, very important now.
    Senator Stevens. Thank you very much.
    Senator Kerry. Just before Senator Stevens leaves, a 
quick--what shape should that research funding take? I mean, 
how do you structure that?
    Dr. Benson. I mean, I think that there are certainly very 
good models for the fundamental research that takes place, for 
example, through the Department of Energy's Office of Science 
that, you know, funds graduate student research, and so forth--
--
    Senator Kerry. Should it be targeted to a specific set of 
disciplined questions?
    Dr. Benson. Yes, absolutely.
    Senator Kerry. You want to help shape that, give some 
ideas?
    Dr. Benson. It's basically use-inspired fundamental 
research. We have to know what we're trying to achieve, we're 
going to know the questions we're trying to answer, and then 
get the best minds working on those problems.
    Senator Kerry. And the second question just in terms of the 
appropriator role Senator Stevens plays, which is pretty 
critical, how urgent is that kind of commitment here?
    Dr. Benson. Well, my view we need to do it now, we needed 
to do it yesterday. I think this is urgent. I think that we 
need to move ahead now.
    Senator Stevens. Do we need a Los Alamos-type project on 
this? Do we need to get the scientific community together to 
get them into an agreement before we go forward?
    Dr. Hannegan. Excuse me, much of the scientific community, 
much of the technical community which is here on this panel, is 
in agreement on many of the steps that we need to take to 
develop carbon capture and storage as a tool that we can use to 
address climate change. The sooner we do that----
    Senator Stevens. But there's not an agreement on the 
technology.
    Dr. Hannegan. Well, you need a portfolio of technologies, 
in our view, because you're going to be dealing with different 
coals, you're going to be dealing with different resources and 
requirements, you need both pulverized coal, IGCC, oxy-fuel--
these are things that we can develop a very specific road map, 
in fact, we have--with targets and timetables, and these are 
the kinds of things that if we do it, then we can accelerate 
the rate at which we can then de-carbonize the broader economy.
    Senator Kerry. Mr. Herzog, I was wondering, I know Senator 
Stevens has to go, but did MIT work through any of those best 
practices, best routes with respect to the fuel, i.e., 
different kinds of coal?
    Mr. Herzog. In our report we gave some breakdowns of 
general categories and general ways you can go on there. 
Subsequent to the report, I've been in meetings with EPRI, 
people like the Coal Utilization Research Council, several 
other, I guess, Edison Electric--and while there's some subtle 
differences in the approaches, I think the basic thrust of what 
everybody's saying is fairly similar. And when you look at, 
say, in the underground, in the sequestration, we all know we 
need to work on the geochemistry, the geomechanics, the biology 
down there, we have to look at the modeling at the basin scale. 
So I think there's a pretty good agreement throughout the 
community of the major directions and what the gaps are in our 
knowledge to move forward.
    Senator Kerry. Now, some people have raised the question 
occasionally and said, ``Well, we don't know how to do this.'' 
And I've heard this argued by some Senators. The fact is, we do 
know how to do it, do we not?
    Mr. Herzog. Yes.
    Senator Kerry. Literally in the Finance Committee, we had a 
struggle over whether or not we have the technology to do this. 
We had some people arguing, well we don't know how to do it, we 
can't do it, so we couldn't create an incentive. It's my 
understanding not only do we know how to do it, but there are 
several countries, three of them, specifically, that are 
already doing it, is that correct?
    Mr. Fox. Yes, Senator. We operate plants that capture 
CO2 right now, and we've been--people have been 
capturing CO2 for over 60 years. We have--there's, 
in the United States, the Dakota Gasification Company is 
capturing CO2 from a gasification plant. That works. 
We've been injecting CO2 in the ground for 35 years 
and tracking it. This--much of this is just an extension of 
technology we're already----
    Senator Kerry. We've been injecting it, we've been 
injecting it for the purpose of forcing oil--out of pockets 
where it's hard to get it.
    Mr. Fox. Yes.
    Senator Kerry. Without regard to whether or not it stays 
where we forced it.
    Mr. Fox. That's correct, although we have no--we do not 
believe it's going anywhere else.
    Senator Kerry. But that's because the effective sealing 
that you talked about earlier, if it seals the oil in, or the 
natural gas, it's going to seal the CO2, likewise.
    Mr. Fox. Correct. This is something we know how to do, it's 
a question of doing it the least expensively, and having the 
smallest effect on the economy.
    Dr. Hannegan. Mr. Chairman, with all due respect to the 
contributions of my colleague, the examples that he's cited are 
from chemical plants and other sorts of activities which are 
not electric power plants. And when you look at coal-fired 
electric power plants, we are at a much smaller scale of 
CO2 capture and storage than you would like to have 
in order to make an investment at commercial scale today. And 
so, you need a set of steps that will scale you up to that.
    Senator Kerry. That's because of the post-combustion, pre-
combustion----
    Dr. Hannegan. That's correct.
    Senator Kerry.--issue that you raised earlier.
    Dr. Hannegan. The difficulty is in capturing the 
CO2 from a conventional pulverized coal unit, and 
from operating the IGCC unit, at scale, which we have not yet 
done in the United States.
    Senator Kerry. But, we do know that we have the technical 
capacity to capture, either in post- or pre-combustion.
    Dr. Hannegan. That is correct.
    Senator Kerry. The real issue here is the efficiency and 
cost of a commercial-scale operation.
    Dr. Hannegan. And, I would add, scale. The question of----
    Senator Kerry. Fair enough.
    Dr. Hannegan.--what do you do with all that CO2.
    Senator Kerry. Which is precisely why there's an urgency to 
doing it. Get it out there, correct?
    Dr. Hannegan. Correct.
    Senator Kerry. Now, some private entities are moving to do 
this, isn't that correct? AEP, I think, is doing an IGCC in 
West Virginia or in Ohio.
    Dr. Hannegan. At a 20-megawatt scale, on a much, much 
larger unit, yes.
    Senator Kerry. Now, someone might ask the question, well, 
if the private sector is going to start to move toward this, 
and electricity rates ought to reflect the investment, why 
should the government be involved? I think I have an answer, 
but I want to hear from you, what your take is on that.
    Dr. Burruss?
    Dr. Burruss. Mr. Chairman, I would say that you raised the 
basic issue in your opening statement. The issue is urgency, 
the rate at which this technology has to be deployed, in order 
to ultimately impact climate change. Because, if we're not 
going to do that, there's not a lot of point to the technology. 
So, the fact is that----
    Senator Kerry. Well, I would assume, also, that we have a 
much better ability to deal with both the eminent domain and 
the liability issue, which is going to be critical to moving 
rapidly.
    Dr. Burruss. That's true, and I think there's also a 
separation that we have to be aware of. I think those of us on 
the geological side know that we can, in fact, store 
CO2. There's some scale issues, and some questions 
we need to answer.
    Senator Kerry. Can you answer the question whether or not 
we have the capacity in the U.S. to sequester the amount of 
CO2 necessary to get a 60 to 80 percent reduction?
    Dr. Burruss. I believe----
    Senator Kerry. Let's kill the 60. An 80 to 90 percent 
reduction?
    Dr. Burruss. An 80 to 90 percent reduction in total 
CO2 emissions in the United States? Boy, that's a 
tough question, Senator.
    Senator Kerry. What is the capacity?
    Dr. Burruss. And----
    Senator Kerry. What is the known current capacity?
    Dr. Burruss. We have an estimate, based on the DOE----
    Senator Kerry. Without saline, correct?
    Dr. Burruss. Excuse me?
    Senator Kerry. That's without the saline pocket, correct?
    Dr. Burruss. The estimate that we know about, in oil and 
gas reservoirs----
    Senator Kerry. Is that based on oil and gas reservoirs?
    Dr. Burruss. That's correct, and that----
    Senator Kerry. And how much do we get out of the current 
estimate on oil and gas that we believe is sealable?
    Dr. Burruss. I'd say that's still a subject of additional 
evaluation to understand which part of those oil and gas 
reservoirs, which fraction of them, are the best storage sites. 
We, I think, we can make a reasonable estimate that, that is on 
the same order that, you know, DOE has published, because these 
are based on things we know a lot about, it's about 100 billion 
tons, maybe 100 billion tons of CO2 in known oil and 
gas reservoirs.
    But that doesn't get the job done if you tell me that we 
need to capture 90 percent of the CO2 emitted by all 
industrial processes in the United States.
    Senator Kerry. Well, I'm not telling you, the scientists 
are telling us that it is going to take, in order to avoid the 
tipping point, if you accept the science, does anybody here 
argue with the science? Anybody on the panel argue with the 
science?
    Dr. Burruss. No.
    Senator Kerry. So, if you don't argue with the science, if 
you accept the science you can't be half-pregnant on this 
thing. You accept the science, you've got to accept the 
predictions of the consequence that the science, not only the 
science is telling us is going to happen, but the science is 
showing is happening to a greater degree and faster than the 
science previously predicted.
    So, that said, it seems to me that when they tell you, 
you've got about 10 years to get it right, and you now have to 
reduce your goal from 550 to 450 and from 3 degrees to 2 
degrees, we're operating with a very small cushion, here. If 
you're already at 370, and you can only go to 450, and we 
already know that at the rate China and the U.S. are currently 
building pulverized coal-fired power plants, we're going to be 
at 600 to 900 parts per million very quickly here.
    What do we do? How do we grab this fast?
    Dr. Benson. Could I answer your--so, the DOE Atlas does 
include saline aquifers.
    Senator Kerry. It does?
    Dr. Benson. Yes, it does include saline aquifers, and----
    Senator Kerry. Is that a percentage that they give you, as 
well as a metric--?
    Dr. Benson. It's a quantitative number, it's about 3,000 
billion tons of carbon dioxide.
    Senator Kerry. Where does that fall on the percentage that 
we have to get?
    Dr. Benson. In terms--so what that--if you took all of the 
stationary sources over 100,000 tons per year, you could 
sequester hundreds of years of those CO2 emissions, 
from the stationary sources. It doesn't include the 
transportation sector. So, yes, it's a big chunk, and so what's 
that--about 40 percent or so of U.S. emissions for hundreds of 
years.
    Senator Kerry. Well, at the meeting I was just at, we were 
talking about the Energy bill, and how we're going to try to do 
the transportation sector piece, and hopefully get some of that 
done in December.
    Dr. Hannegan. Senator, if I might add a point to the 
previous discussion? When you think about 60, 80, 90 percent 
reductions across the broader economy, we're not going to be 
relying just on carbon capture and storage to meet that.
    Senator Kerry. Absolutely correct.
    Dr. Hannegan. And so, some of the pressure that might have 
been implied on the reservoir space----
    Senator Kerry. That why I'm trying to get a handle on what 
the estimate is of the percentage that we get out of the carbon 
capture? Reliably.
    Dr. Hannegan. Well, our work, looking at just the electric 
sector, showed that a considerable amount of the future 
emissions reductions from that sector would come in the form of 
carbon capture and storage and advanced coal technologies.
    As far as the transportation sector goes, one of the more 
promising options that we see is, if you're able to de-
carbonize the electric supply, early, through a technology like 
CCS, then that provides a low-carbon and affordable source of 
fuel for other sectors of the economy, including transport.
    Senator Kerry. So, what are the three most important steps 
that we ought to take to get moving on this? Fund the 
demonstration project? Is that number one? What's number two 
and three? Research, liability?
    Mr. Fox. I think, Senator, I would echo what Dr. Benson 
said earlier, was that, or it was Mr. Herzog--that we need to 
fund the larger demonstration projects to find out what happens 
when you put a lot of CO2 into the ground, but we 
also need to do some of the smaller projects. When I think 
about trying to invest money to develop a carbon, or a storage 
facility, and invest hundreds of millions of dollars into 
that--we would have, you'd have to have more than just three 
places to go. You'd really want to have, you know, have a few 
things that you can know a lot about, and a lot of them where 
you might know a little bit about it, and then you could 
extrapolate to that. So, I think it's important to have both of 
that.
    And----
    Senator Kerry. Anybody want to add a third?
    Dr. Hannegan. Yes, Mr. Chairman, I'll take a crack. The 
first is, obviously as you pointed out, the need for 
demonstrations, a variety of technologies, variety of 
geologies, variety of scales. The second is getting the 
regulatory regime in place that gives investors confidence to 
move forward, and it gives the opportunity for folks like those 
seated at the table to participate, and the third, one that 
we----
    Senator Kerry. What's the, before you--go ahead.
    Dr. Hannegan. Sure. The third that we haven't really talked 
a whole lot about is, I think environmental aspects are 
important--measuring, monitoring, verifying the storage of the 
CO2, the fact that there are not adverse, 
unanticipated environmental consequences--really, using our 
demonstration projects as a basis to get that right is going to 
be key to also getting public acceptance.
    Senator Kerry. And the key regulatory issues, in your 
judgment?
    Dr. Hannegan. The first is probably the ownership of the 
CO2, in terms of, at what point, when you put a 
CO2 molecule into the ground, and you expect it to 
stay there for a century or more, who owns that CO2? 
Who owns the porous space between the rocks? I think as one of 
my colleagues mentioned, and they may add some additional 
issues. When it comes to the transfer of liability when it 
moves into one of Mr. Fox's pipelines, for example. These are 
all issues that I think we can work collaboratively on.
    Senator Kerry. It seems to me, that if we're going to get 
this done, and get it done at the scale and speed we need to, 
you can't ask a company to take the risk of assuming that 
liability. You're going to have to provide something, as we did 
with nuclear, with the Anderson Act, where you give some kind 
of immunity there for at least the initial thing, until you 
figure it out, what those consequences and other things may be. 
I just don't know how you do it, otherwise. Because, I think a 
lot of people are going to be very reluctant from an investor 
point of view, let alone, Board of Directors, director of 
exposure, all of those other things, to get involved.
    Dr. Hannegan. Yes. There's also the economic risk, given 
that many of these coal plants that we're thinking about are 
now billion dollar investments. And that, when we're talking 
about having them add carbon capture on the end of it, we're 
talking about a significant increase in the capital outlay up 
front, and that's where Federal assistance can be of great 
value.
    Senator Kerry. Are any of you aware of any other 
technologies or alternatives currently being explored? Not 
dissimilar to what Senator Dorgan mentioned in terms of, until 
this moment unheralded, or un-focused on by-products and 
alternatives to how one may deal with CO2, beyond 
the capture and sequestration?
    Dr. Benson. I think something at this level of maturity and 
the potential for very large-scale reductions, I think at this 
point, capture with geological storage is the primary option 
available. And that was certainly the conclusion of the IPCC 
Special Report on Carbon Capture and Storage that was done 
about 2 years ago.
    Dr. Hannegan. There are, however, Senator, I think, some 
enterprising folks out there, like the algae folks that were 
discussed in Senator Dorgan's comments.
    I'm also aware that there are some, there's an activity in 
Texas to get to a point Senator Stevens made before he departed 
about a plant that's generating electricity at the mine mouth, 
and actually capturing the CO2 and turning it into a 
carbonate material. Now, they haven't figured out what to do 
with all of that carbonate yet, but one could imagine if there 
is a market for that as a commercializable product, then that 
would be a very useful thing to pursue, as well. And these are 
things we're looking at, at EPRI as part of our program.
    Senator Kerry. Dr. Burruss, why doesn't the USGS have a 
role in assessing the capacity? What's going on here?
    Dr. Burruss. Senator, that's a--I guess I'm rather 
sensitive to that. I--I mean, the simple truth is we're not 
funded to do the work. We have no project to pursue that, and 
no authorization to do so.
    Senator Kerry. So, it's really just a budget issue, lack of 
priority?
    Dr. Burruss. It's--yes. There was a----
    Senator Kerry. Don't you have the best expertise, frankly?
    Dr. Burruss. We believe that we have the best expertise for 
doing storage assessments and treating them as a natural 
resource, and using our methodologies for oil and gas and 
mineral resources and applying them to storage capacity. But, 
you know, until we have the authorization to move forward, we, 
you know, we literally cannot do so.
    Senator Kerry. This year the DOE published the Carbon 
Sequestration Atlas, which I am told, while it's useful to some 
degree, it does not have the kind of resolution necessary to 
really help identify, select, and manage injection projects, is 
that a fair statement? Who's qualified to answer that?
    Dr. Burruss?
    Dr. Burruss. That's a fair statement, Senator, but I also 
think that if you were to turn the question around and say, 
could we as the USGS do that, to identify sites that could be 
utilized for storage, we would have to say no, because we do 
not identify commercial projects. We assess resources and their 
distribution and----
    Senator Kerry. But a capacity assessment, it seems to me 
would be a fairly generic and important assessment.
    Dr. Burruss. Absolutely. And that----
    Senator Kerry. So, wouldn't that be part of the study and 
funding analysis that we do?
    Dr. Burruss. Absolutely. It has to be.
    Senator Kerry. It's my sense that it would be.
    Dr. Burruss. And, as part of that, there is the very basic 
question about the storage capacity of saline aquifers. We know 
the number is very large. But we really don't know where the 
most effective storage is, and what fraction we could actually 
use.
    Senator Kerry. What are the known, if any, risks associated 
with CCS?
    Mr. Herzog. One of the biggest is leakage, but it's a 
fairly minimal risk to health and environment, because, in 
general, a leak would probably be fairly dilute. There's 
CO2 all around us, and we put it up in the air so, 
only if it gets concentrated could it be a risk. Like radon, it 
seeps out of the subsurface, collects in things like basements, 
but that is easily mitigated if that's the case. But that's one 
of the worst cases you could see.
    I think the biggest risk is it leaks out, and we spent all 
of this money to put it into the ground, we would not get the 
benefit from it.
    Senator Kerry. Is there any risk with respect to beyond, 
perhaps, acidification, if it moves down into a water supply 
channel?
    Mr. Herzog. It would have to--we're going to inject below 
all of the potable water, so it would be moving up and getting 
into drinking aquifers. I don't think acidification is such a 
big risk, what some people think is, if it leaches out other 
materials and brings them up with it, it is a risk. But, at 
this point that's, people are researching that, at this point 
it's hard to really quantify it as a major risk or not.
    Dr. Benson. So, I think there's another risk, and that is--
--
    Senator Kerry. Could I just, before you mention the other 
risk, could I just close off on that? I thought the increased 
CO2, to the degree the oceans have acted as a sink, 
that increase of CO2 storage has raised the acidity 
of the oceans by some 35 percent?
    Mr. Herzog. The surface layer of the ocean has changed by 
about .1 ph unit. I'm not sure what percent that is. But, I 
think what will happen in the ground water, it's like 
CO2 that doesn't stay in the soda pop bottle once 
you have the thing open, it diffuses out into the atmosphere. 
The ocean, it gets down into the deep ocean. The surface ocean 
has equilibrium with the atmosphere, and that controls the pH. 
But the surface level of the ocean is actually basic, not 
acidic.
    Senator Kerry. So we'd maybe turn all drinking water into 
San Pellegrino or something?
    Mr. Herzog. Well, theoretically, but unlikely.
    Senator Kerry. Are there any areas of this that we ought to 
be aware of that have not been asked about by any of my 
colleagues or any of us, at this point? Is there something 
relevant to the Committee? We're going to leave the record open 
for a couple of weeks, just to get any other colleagues who may 
have some questions.
    Mr. Wolfe, you--?
    Mr. Wolfe. Yes, Mr. Chairman, as a representative of a 
forest landowner, it's a little bit of a different audience 
then the rest of my esteemed colleagues on this panel, but 
Sealaska Corporation, with the Department of Energy has 
investigated a variety of technologies to convert cellulosic, 
lignocellulosic material which is woody bark and material and 
stuff like that, into ethanol. The technologies are available, 
but we have not been able to move this from the laboratory into 
production scale. So, we think that this creates some 
opportunities.
    There are us--the other incentives that need to happen for 
things such as taking wood waste material and turning it into 
pellet fuel technologies, now what these do is basically offer 
a savings over alternate fossil fuels. So, from the wood sector 
and from the forest sector, we think that there are such 
opportunities that need to be, need to have assistance, not 
only in the development of the technologies, but incentives to 
be able to get people to invest in this type of technology and 
deliver it to the marketplace.
    Just one last thing, too--I think this is really quite 
important for our rural villages in Alaska. Rural village costs 
are like $4 and $5 a gallon for diesel, and this is a 
tremendous burden for our rural villages, in terms of simply 
heating their homes.
    Senator Kerry. Sure.
    Mr. Wolfe. So, alternate fuels and these sorts of things 
might be quite helpful.
    Senator Kerry. Absolutely. And I might add, one of our top 
venture capitalists who has been involved in U.S. capture and 
sequestration, and with others as we're discussing these 
issues, is investing heavily in a wood chip-based cellulosic 
ethanol plant down in Georgia right now. Partly to prove that 
you don't have to be corn-based, grain-based, and you can do it 
almost anywhere, so there are a lot of options there.
    The other thing I might mention, as I was reading recently, 
is in an analysis of tropical forests versus Northeast forests, 
obviously all forests act as a sink, and they are important, 
but it turns out that the Northeast forest is less important 
than we thought, whereas tropical is far more important. I 
think the deforestation that has taken place, just in the last 
year or so, has added the equivalent of 20 percent of our 
CO2 creation today. And if we continue down that 
road, in deforestation of the tropical forest, we're in serious 
trouble, it's going to be a big add-on, a very serious add-on.
    Dr. Hannegan. Mr. Chairman, if I could add one point to my 
colleagues' discussion of biomass--the promise of biomass and 
CCS coming together is rather an intriguing one, because 
biomass takes up CO2 from the atmosphere as it 
grows, and if you were to combust that, or gasify that biomass 
to create power, and then capture the resulting CO2, 
the end result is actually, you're removing CO2 from 
the atmosphere and putting it in these deep reservoirs, you're 
effectively lowering the burden. And as a long-term objective, 
there's an opportunity for some synergy here that's worth 
pursuing.
    Senator Kerry. Absolutely. Well, it's a very, very 
interesting topic, and this has been a very important 
foundation being laid for our ability to do some important 
investing, the Federal Government, and try to move this 
forward. So, I'm very grateful to all of you. And I hope you'll 
keep pushing in your individual bailiwicks and jointly, because 
we really need to get some folks moving on this, in a very, 
very serious way.
    Senator Thune, you haven't had a shot yet, and I apologize.

                 STATEMENT OF HON. JOHN THUNE, 
                 U.S. SENATOR FROM SOUTH DAKOTA

    Senator Thune. All right, that's all right, Mr. Chairman.
    I want to thank you for holding this hearing on what is a 
very important topic and that's the critical role that clean 
coal and carbon capture and sequestration will play in securing 
our energy independence, and I appreciate the panel's input. I 
apologize for not being able to get here a little bit earlier, 
but I wanted to just make it, I guess, maybe one observation 
and maybe ask one question, I realize you're probably getting 
ready to wrap this up, Mr. Chairman.
    But I know the focus of the hearing today has been on 
geological carbon storage, but I would like to highlight with 
the Committee, also, that there's another very potent tool out 
there for carbon sequestration, in our Nation's heartland, and 
that's biological carbon sequestration, which uses land 
management to enhance natural carbon storage in plants and 
soil.
    Altering crop planning practices, preventing soil erosion, 
changing grazing practices are all things that have a 
measurable impact on carbon sequestration, and according to the 
CBO, biological sequestration has the technological potential 
to sequester about 40 billion to 60 billion tons of carbon 
dioxide over the next 50 years. And while that potential is 
considerably smaller than the potential for geological 
sequestration, it's an important component of managing carbon 
dioxide concentration in the atmosphere, and I look forward to 
further discussing this issue with the Committee in the future.
    It is going to require leadership from the private and 
public sectors in order to overcome some of the technological 
and market barriers of developing and applying carbon capture 
and sequestration technologies, and so I appreciate the 
insights the panel has shared today, and we'll review the 
record and some of the testimony and look at how we can find a 
way forward.
    Just one question, I guess, I'd pose for the panel, and 
whoever would like to can answer this. But, the carbon offset 
issue right now, the range is between $5 and $20 a ton. 
According to Mr. Fox's testimony, the cost of carbon capture 
and sequestration ranges between $11 and $57 per metric ton. Do 
you expect future advances in technology to make CCS more 
competitive with other ways of limiting carbon emissions, and 
how long is it going to take for that to happen?
    Mr. Herzog. I would say in the type of cuts that we're 
talking about, whether it's 80 or 90 percent, that Senator 
Kerry mentioned or even more modest cuts of 50 or 60 percent, 
when you're talking those type of cuts, the technology at its 
current level is going to be competitive with other types of 
mitigation options.
    The, I think initially you actually see costs a little on 
the higher side, because you have to go through new technology, 
you always have first of a kind costs. Any time you try new 
technology it's going to be more expensive until you start to 
do a few of them and learn how to do it.
    I think there's a lot of technology in the pipeline that 
has a chance to significantly reduce the cost of this, maybe 
even 50 percent. But those technologies need to be nurtured 
through the R&D program, and that, I think should be something 
that's done in parallel with some of the demonstration programs 
that we talked about here.
    Dr. Hannegan. And our work, Senator, has shown similar cost 
estimates to the MIT work around $40 to $50 to $60 per ton 
CO2, with the current technologies that are out 
there. We've identified R&D that will bring those costs down by 
a considerable amount.
    It's also important to recognize that, in general, 
investing in technology before you apply a carbon constraint, 
our economic analysis has shown that that's a far preferable 
economic outcome to applying the constraint first, and then 
expecting the technologies to come along behind. And that's 
work that we've detailed in our testimony.
    Mr. Wolfe. Senator, if I may, from a different perspective, 
at $20 a ton, that starts to be a number that private 
landowners can get quite motivated in terms of management 
regimes to sequester carbon in forests or through annual 
agricultural crop productions such as the heartland that you've 
referred to. The analysis that we've done indicates that that 
could be a very attractive management regime for a forest land 
owner.
    Mr. Fox. And I would like to note on those costs, the $11 a 
ton is on the very low end, and those were costs at which we 
could, as a company who is trying to acquire CO2, 
could get it from an emitter, as opposed to what it would cost 
a power plant that would build something and then they would 
have to incur a lot more costs up to that point that they'd 
have to eat. So, those were on the low end, but it's, I think, 
very important that we have some research to drop those costs, 
because on a widespread basis throughout the economy, it is--
it's very expensive.
    Senator Thune. Thank you, Mr. Chairman.
    Thank you all very much.
    Senator Kerry. Thank you, Senator.
    And thank you very much. We have a roll call vote on now, 
so it's a good moment, notwithstanding I think we've sort of 
reached the end.
    Thank you all very much. Enormously helpful, very, very 
important and I'm confident that, together with Senator 
Stevens' efforts and others, we can get going on this. So, we 
appreciate it.
    We stand adjourned.
    [Whereupon, at 4:20 p.m., the hearing was adjourned.]

                            A P P E N D I X

                Prepared Statement of Alstom Power, Inc.

    Alstom Power Inc. welcomes this opportunity to submit its views on 
the role of technology innovation and the need for Federal support of 
research, development, and deployment (RD&D) for CO2 capture 
and storage technology in coal-fired power generation. America's long-
term energy and economic security depends on the availability of a 
strong portfolio of clean, reliable, and economic technologies for 
power generation including renewables, nuclear, and clean use of fossil 
fuels. Alstom strongly believes that CO2 capture and storage 
is critical to a sustainable long-term energy supply. As such, our 
company is a global leader in innovative R&D to meet the technological 
and economic challenges of capturing CO2. A policy framework 
that includes adequate Federal funding for technology demonstrations, 
coupled with incentives for early deployment, can help to accelerate 
commercialization of these and other crucial technologies that help 
utilities address CO2 restrictions.
    Alstom has a 100+ year history of providing power generation and 
environmental control technologies to the global electric industry. 
Alstom is a global specialist in energy and transportation 
infrastructure with annual sales of over $21 billion. In the U.S., 
Alstom has 65 locations in 22 states, including its U.S. corporate 
headquarters in Windsor, CT. The company serves the energy market 
through its activities in power generation, power transmission and 
distribution, and power conversion. Alstom offers a comprehensive range 
of power generation solutions from turnkey plants to all types of 
turbine (gas, steam, hydro) generators, boilers, environmental control 
products and control systems, as well as a full range of services 
including plant modernization, maintenance and long-term operation.

Clean Coal Technology--Moving Toward Low Carbon Emissions
    While our corporate interests and technical capabilities span all 
forms of energy resources and applications for power generation, we 
recognize that the Nation faces a particular challenge in ensuring 
environmentally sustainable options to continue use of coal while 
moving toward restrictions on CO2 emissions. Coal is an 
abundant, low cost, and secure domestic energy resource that has 
steadily and reliably provided over 50 percent of our Nation's 
electricity over the past two decades. In recent years, coal's stable 
performance has helped moderate price volatility from rapidly rising 
gas prices.
    Because Alstom is active in global power markets, many of our 
international clients already face restrictions on CO2. As a 
result, we have been working for over a decade on the development of 
advanced coal combustion technologies focused on reducing 
CO2 and enabling CO2 capture and storage. Some of 
these technologies, such as high efficiency supercritical steam cycles, 
are now being placed in commercial operation. Other technologies, such 
as ultrasupercritical, are in laboratory and proven at bench scale. 
Still others, including our post-combustion CO2 capture 
processes are moving into initial demonstration and deployment with 
utility partners. These technology options are discussed in the 
testimony below.

Efficiency--the First Step to Lower Emissions, Including Carbon
    For coal based power, plant efficiency improvement is by far the 
most predictable lowest cost, and nearest term, method to reduce all 
emissions, including CO2. Higher efficiency in conversion 
means less coal (i.e., carbon) is used per megawatt hour of electricity 
produced, resulting in less emissions to reduce/capture, as well as 
less coal mined and transported. Therefore, it is prudent to first 
minimize CO2 emissions by higher plant efficiency before 
incorporating more expensive carbon capture and sequestration.
    Upgrades to the operating fleet can produce modest, but very real 
and near term, reductions in CO2 emissions. A recent study 
by the National Coal Council, in which Alstom participated, concluded 
that:

        Any framework for managing CO2 emissions must take 
        into account the realities of the existing infrastructure of 
        energy production and use in our nations. Immediate 
        opportunities focus on efficiency improvements within the 
        current fleet of plants. These gains can be made at several 
        points withing the system and included turbine blade upgrades, 
        condenser system and boiler feed water system improvements, 
        washing and cleaning the coal that is used and improving the 
        milling systems used to grind the coal. The development of 
        regulatory incentives would dramatically speed up achievement 
        of these efficiencies. (National Coal Council, ``Technologies 
        to Reduce or Capture and Store Carbon Dioxide Emissions'', June 
        2007)

    However, improvements produced through upgrades are modest due to 
the limitations of the installed technology. Further significant 
efficiency increases will be possible only with deployment of new 
technology. These technologies include supercritical pulverized coal 
(SCPC) and circulating fluidised bed (CFB) and integrated gasification 
combined cycles (IGCC).
    Increasing the temperature and pressure of the steam cycle for PC/
CFB technology from that of older subcritical designs to today's 
supercritical cycles can reduce CO2 (and other) emissions 
per megawatt hour by as much as 5-15 percent. Today, U.S. utilities and 
independent power producers are ordering and installing these high 
efficiency SCPC cycles, tailored to U.S. coals and site requirements. A 
few are taking the next step to ultrasupercritical PC (USCPC), 
incurring first of kind risk, but realizing additional efficiency 
gains, with potential benefits of 2-5 percent additional emissions 
reductions.
    Further increases in steam cycle efficiency are technically 
feasible, with the potential to reduce CO2 emissions by as 
much as 25 percent from the existing fleet average. These technologies 
will require investment in advanced materials research and system 
design to allow operation at even higher temperatures. The Committee 
has previously received testimony from both the Electric Power Research 
Institute (EPRI) and the U.S. Department of Energy (DOE) describing 
their ongoing programs in materials development for advanced USCPC 
power plants, including EPRI's proposed UltraGen program to bring these 
technologies to first of kind demonstration. Alstom is an active 
participant in these programs.
    Systematic replacement of the oldest portion of the existing fleet 
by new high efficiency USCPC and IGCC power plants over the next two 
decades can be a basic building block for a CO2 strategy. 
Support of demonstration/deployment in the U.S., for example, provides 
a platform for proving high efficiency USCPC technology for future 
export, thus contributing to global CO2 emissions reductions 
in the rapidly growing markets in India, China, and Asia.

Beyond Efficiency to Carbon Capture and Storage (CCS)
    Beyond the potential 25 percent reduction that could be achieved 
via improved efficiencies, technologies are needed to capture remaining 
CO2 from the gas streams and to effectively store/sequester 
the CO2 long term if more extensive carbon reduction goals 
are to be met. There are three main CO2 capture 
technologies: post-combustion processes, oxy-firing/chemical looping, 
and pre-combustion capture. CO2 can be removed from the gas 
stream of all coal-based technologies, both combustion and gasification 
based. After capture and compression, the nature of the CO2 
from both gasification and combustion is identical and the costs to 
transport and store this CO2 would be the same. (Figure 1 
presents Alstom's view on the timeline for demonstration of first of 
kind demonstrations and commercial deployment of these technologies. A 
full description of the technologies is included in the attached 
Appendix.)



    However, there are differences in the current cost of capture 
technologies, their stage of development and scale-up, and the 
forecasts of future costs and performance. If implemented today, 
capture costs from oxygen-fired IGCC may be somewhat lower than from a 
PC/CFB using existing older commercial amine processes. However, 
today's costs of IGCC are high and future cost reductions for IGCC are 
uncertain. More importantly, the cost for CO2 capture would 
be excessively high for both combustion and gasification technologies. 
Better technologies are needed for carbon capture and storage to 
minimize the potential impact on energy costs. Alstom's own corporate 
interests are focused on demonstration and commercialization of 
technology options for cost competitive CO2 capture from 
combustion technologies. Nevertheless, as technologies to capture 
CO2 from both combustion and gasification are still under 
development and continue to evolve, Alstom believes strongly that 
Federal policy should encourage development of the full range of 
options, rather than bias selection or predict technology winners 
related to only one technology.

Incentives and Models for Early Deployment
    As a technology innovator, Alstom firmly believes that carbon 
reduction, capture and sequestration technologies at competitive costs 
are a critical and achievable goal for coal-based power. However, 
realizing this goal will not be easy, it will require the combined 
skills and knowledge of the public and private sector, working in close 
cooperation over, at a minimum, the next decade. Due to the large 
investment required to support R&D and commercial demonstration/
deployment of new technologies, Alstom believes that both Congressional 
and Administrative support will be critical to the successful 
deployment of new these technologies. The U.S. Government must play a 
leadership role to support this critical effort through legislation and 
appropriation of funds to support research, development and deployment 
of the next generation of clean coal technologies.
    Alstom believes that the models of development and deployment 
successfully utilized for currently regulated emissions could be 
applied to achieve deployment of technologies to meet the next 
challenge of lowering carbon emissions.
    Two aspects of this model are important to recognize. First, 
development and deployment of new large capital intensive technologies 
for power generation is risky and complex, requiring major R&D 
expenditures and a long term commitment by all industry stakeholders. 
Second, successful deployment requires strong cooperative efforts 
between generators, technology suppliers and government to manage risk 
and to ultimately provide the most effective, reliable, and cost 
effective solutions. It is also critical that legislative and 
regulatory initiatives reflect realistic, achievable timelines for 
technology development and deployment.
    A solid example of successful innovation and deployment in 
environmental controls for coal-based power was the development of flue 
gas desulfurization (FGD) for sulfur dioxide (SO2) emissions 
control.
    Alstom and other companies began laboratory bench scale testing of 
post-combustion FGD systems in the 1960s, followed by pilot scale 
demonstrations in the early 1970s. The first generation of commercial 
units followed these demonstrations. These first of kind units achieved 
SO2 emissions reductions of approximately 70 percent, but 
they were relatively expensive, requiring redundant systems to ensure 
reliability. As technology suppliers and utilities installed more FGD 
units, lessons learned from this initial operating fleet resulted in 
improved designs with better emissions performance. Collaborative 
learning, supported by strong government technology programs such as 
the DOE's Clean Coal Power Initiative, produced capital and operating 
cost reductions as a range of system designs were explored and 
optimized. Over time, the most reliable, effective and cost efficient 
processes became evident and FGD technologies moved from first and 
second generation `proof of concept' to solid commercial offerings. 
Concurrent with this technology development, Federal and state 
regulators implemented a series of flexible, stepwise and increasingly 
stringent emissions regulations which drove technology advancements 
while recognizing the time required to achieve each incremental 
reduction goal. A combination of cap and trade and national ambient air 
quality goals gave generators the ability to implement emissions 
reductions in an efficient manner across their fleet.
    Today, with 25 years of experience and deployment, FGD systems 
routinely achieve 95-99 percent reductions of SO2 at capital 
costs approximately 50 percent of early FGD systems. The competitive 
marketplace has effectively replaced the initially vital government and 
industry funding support.
    Equally important, many of the FGD technologies developed and 
proven on U.S. power plants are now being deployed globally as 
developing nations, most notably China, begin to address environmental 
issues. Thus, U.S. technology FGD technology expertise is being 
exported to improve the global environment.

Conclusions
    Alstom Power applauds the directions set forth in S. 2323 to 
provide Federal support for demonstration of capture technologies on 
coal-fired power plants, accompanied by sequestration. We urge the 
Committee to ensure that such programs will support a portfolio of coal 
generation technologies, with adequate focus given to advanced 
combustion processes, as well as gasification. There is a very strong 
case for pursuing all technology options to significantly increase the 
probability of achieving the complex goals of environmental 
performance, reliability and reasonable costs for all applications. In 
addition, support for CO2 capture processes applicable to 
SCPC plants has major implications for future technology exports to 
address the large supercritical fleet being built today in China and 
India.
    We ask that the Committee recognize the importance of supporting 
adequate funding for key programs such as DOE's Advanced Materials 
Research, which provides fundamental advances to support CCS technology 
development.
    Alstom participates in groups such as EPRI and the Coal Utilization 
Research Council (CURC) who have both outlined recommendations for 
incentives to support initial demonstration/deployment at large scale 
and rapid early deployment. We highlight the following recommendations 
for the Committee's consideration to better achieve objectives for 
technology deployment.

   Support appropriate scale-up for first of kind 
        demonstrations, but do not burden these projects with excessive 
        requirements of scale.

      Post combustion capture processes can readily be evaluated and 
            demonstrated on slip streams of exhaust gases from new or 
            existing PC or CFB plants. Levels of capture (such as 50 
            percent removal, 70 percent removal, etc.) can be 
            demonstrated on this partial gas flow and are readily 
            translated to full plant scale-up. However, the most 
            efficient method of initial deployment is to build first of 
            kind at a scale sufficient to: (1) utilize commercial size 
            modules/components, and (2) provide sufficient 
            CO2 to support viable integrated storage/EOR 
            testing. There is no technical rationale for first of kind 
            demonstrations to be larger than necessary for initial 
            proof of technology. In fact, this would result in 
            unnecessary cost, as it is very likely that initial capture 
            systems designs will be improved and modified as 
            operational experience accrues. Improved systems designs 
            can be added to the same plant as additional modules of the 
            advanced designs, after the learning takes place.

   First of kind demonstrations for post combustion capture can 
        be installed on either new units or as retrofits. Each has 
        benefits. Installation on existing units has a shorter timeline 
        and moves the technology to demonstration earlier. However, 
        retrofits are limited in the ability to optimize the integrated 
        power plant design with the capture technology; application to 
        new units will likely yield the highest performance in terms of 
        reduced energy penalty for capture. Both types of projects 
        should be pursued, with incentives to move first of kind into 
        operation.

    For more information, please contact:

Lori A. Perine
Vice President, U.S. Government Affairs
Alstom Power, Inc.
Tobyn Anderson
Vice President
Lighthouse Consulting Group
      
                                 ______
                                 
                                Appendix

Description of Key Carbon Capture Technologies for Electric Power 
        Plants
Provided by Alstom Power, Inc.
Post-Combustion Capture
    Alstom is developing post-combustion capture technologies, which 
have the advantage of being applicable to new USCPC and CFB plants, as 
well as potentially retrofittable to a portion of the global installed 
base of coal and gas units. In post-combustion capture, CO2 
is selectively removed from the flue gas, typically via a regenerable 
solvent which is recycled within the capture process. The concentrated 
CO2 stream thus produced is compressed to a liquid for 
either on-site storage or transported via pipeline to off-site storage 
or to use in enhanced oil recovery (EOR).
    Post-combustion CO2 capture based on amines currently is 
in use in other industries. These systems, which use MEA as the capture 
solvent, are not at the scale required for large power plants and are 
expensive due to the high parasitic energy load to run the capture 
system. Alstom is an active participant in the European CASTOR program 
that aims to develop advanced amine capture systems which will 
significantly reduce the cost and high energy requirements. A new 
state-of-the art advanced amine capture pilot plant was recently 
launched at Esbjerg Power Station in Denmark.
    Alstom also is aggressively pursuing a very promising new post-
combustion process utilizing chilled ammonia as the capture solvent. 
This technology has the potential for significantly lower energy 
requirements, thus reducing the impact on plant output and efficiency, 
which would in turn significantly reduce the cost of CO2 
capture. Key projects underway to evaluate and demonstrate the chilled 
ammonia process include:

   5 MWt pilot plant in association with EPRI for We 
        Energies at their coal-fired Pleasant Prairie plant in 
        Wisconsin.

   5 MWt demonstration plant for E.ON in Sweden (oil 
        and gas).

   30 MWt product validation unit for American 
        Electric Power (AEP) at their Mountaineer coal power plant in 
        West Virginia, followed by the design, construction and 
        commissioning of a commercial scale CO2 capture 
        system of up to 200 MW.

   40 MWt test and product validation facility for a 
        natural gas combined cycle for Statoil in Norway.

    Alstom has garnered significant interest from potential utility 
customers in this ambitious technology development and deployment 
program. Its success will depend not only on utility participation, but 
also appropriate funding and incentives to mitigate technical and 
financial risks for these early innovators.
Oxy-Firing/Chemical Looping
    In addition to post combustion capture, Alstom is developing 
combustion-based technologies that incorporate direct CO2 
capture: oxygen-firing (oxy-firing) and chemical looping. Oxy-firing 
burns solid fuel with pure oxygen rather than air. The flue gas thus 
obtained mainly is composed of water and CO2, the latter 
being easily removed from the flue gas by water separation. Oxy-firing 
applies to new units but may suit some selected retrofits as well.
    The main challenge of oxy-firing technology lies in the current 
cost of producing oxygen on a large scale through air separation units 
(ASU). Energy required for air separation results in a 20-25 percent 
drop in net plant output compared to an air-fired plant. This issue is 
currently being addressed by major gas specialists, who are working on 
improving ASU technology and exploring new oxygen-production 
techniques. DOE is also actively supporting advancements in air 
separation, as oxygen is also used for many IGCC technologies.
    Alstom is playing a key role in developing oxy-firing PC and CFB 
techniques and has been selected to set up the first pilot scale power 
plant using oxygen combustion of brown coal for the power producer 
Vattenfall at a power plant in Germany. We are also in studies to 
evaluate the retrofit of small plants to oxy-firing in France and 
Canada. With the potential for breakthrough in reducing costs of air 
separation, oxy-firing warrants support to move to demonstration.
    Based on its CFB know-how, Alstom is also investigating 
breakthrough technologies such as chemical looping. This unique system 
replaces the traditional boiler with a two stage chemical conversion 
process, using an oxygen ``carrier'' to transfer oxygen to the fuel. 
The exhaust gas is similar to oxy-firing, enabling easy CO2 
capture. Preliminary tests at the 10 kW Chalmers unit (under the EU 
ENCAP programme) and on-going research on the Chemical Looping process 
development unit of Alstom in Windsor, CT, supported in part by DOE 
funding, are very promising.

Pre-Combustion Capture from Gasification/IGCC
    The integrated gasification combined cycle (IGCC) process 
transforms a carbon-rich fuel such as coal, through a chemical 
reaction, into a syngas (carbon monoxide (CO) and hydrogen 
(H2)), which can then be burned in a combined cycle plant. 
The level of carbon emissions from an IGCC plant is similar to that of 
a SCPC plant due to comparable efficiency levels. Carbon capture with 
IGCC is considered ``pre-combustion'' because the carbon is separated 
right after the gasification phase, prior to burning the syngas in a 
gas turbine. (In fact, the gasification phase is actually partial 
combustion to CO, rather than full combustion to CO2 as 
occurs in a PC or CFB plant.) IGCC technology, with or without carbon 
capture, is used in new plant construction, since repowering of PC or 
CFB into an IGCC plant is very complex.
    To capture carbon from an IGCC unit, additional processing steps 
are added, including a shift reaction from the original syngas blend to 
a mixture of CO2 and hydrogen, followed by separation of the 
CO2 using a physical solvent. The pre-combustion capture 
process is in itself cheaper than currently available post-combustion 
capture systems and has been validated in other industries. Alstom is 
not aware of any existing commercial applications of CO2 
removal technologies installed on coal-fired IGCC facilities.
    For IGCC, the challenge lies not so much in the capture itself, but 
in the fact that syngas--after CO2 removal--essentially 
contains only hydrogen. Burning a hydrogen-rich syngas raises 
significant issues for gas turbines and is a technological hurdle to be 
overcome. Alstom and other gas turbine suppliers are working to 
generate fundamental knowledge on the combustion of H2-rich 
fuels, and to direct this knowledge to the development of gas turbine 
combustors. The burners must be compatible with established industrial 
standards governing emissions, safety, operability, fuel flexibility, 
reliability and durability.
    In addition to longer-term CO2 challenges, IGCC faces 
two major issues--its: (1) reliability (operating IGCC availability is 
currently several percentage points below that of SCPC plants), and (2) 
cost (currently around 20-30 percent more expensive than SCPC 
technology ).
    Alstom is participating in IGCC developments for the future and has 
put in place in-house programs to develop its GT fuel flexibility for 
syngas and H2 combustion. We already participate in the 
gasification market as a supplier of components, including synthesis 
gas cooling equipment and low calorific value fuel gas turbines.
                                 ______
                                 
Prepared Statement of Dr. S. Julio Friedmann, Leader, Carbon Management 
            Program, Lawrence Livermore National Laboratory

    Mr. Chairman, and Members of the Committee: Thank you for inviting 
me to testify today on the technical aspects of carbon capture and 
sequestration, specifically on the current status of technology, on 
readiness for deployment, what current standards and protocols exist, 
and on what the Federal Government can do to narrow these gaps. I am 
pleased to be here in my capacity as leader of the Carbon Management 
Program at the Lawrence Livermore National Laboratory and report on 
this important technology pathway, which could help America continue to 
meet its domestic energy needs while dramatically reducing the emission 
of greenhouse gases. Carbon capture and sequestration can be a vital 
element of a comprehensive energy strategy that includes efficiency 
gains, conservation, and carbon free energy supplies such as renewable 
or nuclear power. It can also support environmentally sound domestic 
development of transportation fuels including biofuels, coal-to-
liquids, and hydrogen, and a smooth transition to a carbon-free energy 
infrastructure.
    Over the past 2 years, much has been written on the subject of 
carbon capture and sequestration (CCS). The Intergovernmental Panel on 
Climate Change (IPCC) 2005 special report includes a 135-page chapter 
on geological carbon sequestration (GCS). The MIT Report on the Future 
of Coal in a Carbon Constrained World, released in March, discusses 
geological sequestration in detail. The National Petroleum Council 
report ``Facing Hard Truths'' includes a chapter on capture and 
sequestration. The state of California has recently assembled a 
document for the legislature that covers many CCS topics including GCS, 
and the Interstate Oil and Gas Compact Commission recently published a 
set of draft guidelines for commercial deployment. These documents and 
others listed at the end of this testimony provide more technical 
details about matters that underlie my testimony.
    I was specifically asked to comment on what we do and do not know 
about CCS as an option for addressing climate change. My testimony 
starts with an overview of what is known about GCS. I will then discuss 
the prospects for GCS on a commercial scale together with estimates of 
cost and impact on reducing global carbon emissions. My presentation 
concludes with a discussion of three particular immediate needs to 
resolve unknowns: an assessment of geological resources within the 
U.S., the pursuit of some large-scale CCS projects, and improved 
hazards assessment and management to reduce risks.

Overview of Geological Carbon Sequestration
    Carbon capture and sequestration has two components. The first is 
the separation and concentration of CO2 from point source 
flue gases, which are produced at power plants, refineries, ethanol 
plants, fertilizer plants, and other sources like cement factories. 
This step is needed to bring CO2 concentrations up to 95 
percent before the second step, sequestration. Geological carbon 
sequestration (GCS) or carbon storage, involves injection of 
CO2 into porous rock formations deep below the surface. The 
goal is to keep CO2 out of the atmosphere so as to avoid 
atmospheric warming and the consequences of climate change while 
allowing the continued use of fossil fuels for power generation and 
industrial purposes. This hearing and my remarks will focus on GCS.
    GCS involves compressing CO2 and injecting it into 
geological formations at great depth (from 3,000 to 20,000 feet). The 
most promising reservoirs are porous and permeable rock bodies, 
generally at 1 km depth or more and pressures and temperatures where 
CO2 would be in a supercritical phase in which it behaves 
like a very dense, liquid-like gas. These potential reservoirs include:

   Saline formations, which contain brine in their pore 
        volumes, commonly of salinities greater than 10,000 ppm.

   Depleted oil and gas fields that have some combination of 
        water and hydrocarbons in their pore volumes and a demonstrated 
        seal. Injection of CO2 into these reservoirs can 
        stimulate enhanced oil recovery (EOR) or enhanced gas recovery 
        and increase domestic fuel supply; substantial CO2 
        EOR already occurs in the U.S. with both natural and 
        anthropogenic CO2.

   Deep coal seams, often called unmineable coal seams, which 
        comprise organic minerals with brines and gases in their pore 
        and fracture volumes.

    Once the CO2 is injected into the subsurface, it will 
flow throughout the storage formation where it will remain trapped. 
This trapping will keep those greenhouse gases out of the atmosphere 
indefinitely. The IPCC issued a special report in 2005 on the topic of 
carbon sequestration, stating that if a site is chosen well and 
operated well, then it is highly likely (>90 percent) to store 99.9 
percent of injected CO2 in place for 100s of years, and 
likely to store 99 percent for 1,000s of years.
    The Earth's shallow crust is well suited to the indefinite trapping 
and storage of CO2 because of its physical and chemical 
properties. To begin, CO2 sequestration targets will be 
selected that have physical barriers to CO2 migration out of 
the crust to the surface. These barriers will commonly take the form of 
impermeable layers (e.g., shales, evaporites) overlying the reservoir 
target and act immediately to limit CO2 flow. Four different 
mechanisms serve to trap CO2 in the subsurface. At the pore 
scale, capillary forces will immobilize a substantial fraction of 
CO2 as tiny, isolated bubbles trapped as a residual phase. 
Over a period of tens to hundreds of years, CO2 in the 
formation will dissolve into other pore fluids, including hydrocarbon 
species (oil and gas) or brines, where the CO2 cannot be 
released without active intervention. Over longer time scales (hundreds 
to thousands of years) the dissolved CO2 may react with 
minerals in the rock volume to precipitate the CO2 as new 
carbonate minerals. Finally, in the case of organic mineral frameworks 
such as coals, the CO2 will physically adsorb onto the rock 
surface, sometimes displacing other gases (e.g., methane, nitrogen). 
These trapping mechanisms have been documented and observed in natural 
analogs (e.g., the natural CO2 domes in Colorado) and 
laboratory experiments, and they have been simulated in integrated 
geological models. Although substantial work remains to characterize 
and quantify these mechanisms, they are sufficiently well understood 
today to trust estimates of the percentage of CO2 stored 
over the timeframes discussed by the IPCC.
    Because of their large storage potential and broad distribution, 
saline formations are likely sites for most geological sequestration. 
However, initial projects probably will undertaken in depleted oil and 
gas fields, accompanying EOR, due to the density and quality of 
existing subsurface data and the potential for economic return; the 
Weyburn EOR and storage project in Saskatchewan is one example. 
Availability of pore volumes in suitable formations for sequestration 
may be considered a natural resource. Areas that have this resource in 
abundance have a competitive advantage in a carbon constrained world 
compared to those that lack storage capacity.

Status of Geological Carbon Sequestration (GCS)
    GCS is very analogous to the injection of CO2 for 
enhanced oil recovery, which has been done in the U.S. for over 30 
years. Sequestration also has similarities with natural gas storage, 
hazardous waste disposal, and acid gas management as well as other 
aspects of oil and gas production in addition to EOR. These activities 
use the same technologies as GCS, and their technical basis provides 
confidence in the viability of commercial GCS deployment. Furthermore, 
natural accumulations of CO2 have demonstrably retained 
large CO2 volumes for 10s to 100s of millions of years. This 
provides confidence in the possibility of long-term storage of 
CO2 in suitable rock formations.
    Commercial projects in carbon storage are underway in the U.S. and 
elsewhere in the world. In the U.S., the DOE's Regional Carbon 
Sequestration Partnership program has announced three large-scale 
projects last month, which are slated to begin injection within 4 
years. These projects anticipate commercial programs. BP has announced 
a project in Carson California that will inject 4 million tons of 
CO2 each year while producing 500 megawatts (MW) of zero-
emission power. Xcel Energy, Duke Energy, and American Electric Power 
have all announced projects to generate zero-emission power from coal 
power using CCS. Other countries (Sleipner in Norway, In Salah in 
Algeria, and Weyburn in Canada) have projects that have been on-going 
for 10 years and annually inject over 1 million tons of CO2 
from anthropogenic sources. Several more projects will come online in 
2008 in Norway and Australia, and nearly a dozen are on track worldwide 
for completion and injection before 2012. Finally, the DOE's FutureGen 
project is in the final stage of selection among four outstanding 
sites. This project will provide insight into the design, engineering, 
and likely unit economics of combined generation and sequestration 
efforts. A few of these examples are enhanced oil recovery projects, 
which will produce additional liquid fuels. Most of these projects will 
inject into saline formations, which represent the largest potential 
CO2 sinks in the U.S. and the world. These activities 
demonstrate tremendous technical readiness in the U.S. and the world 
for commercial deployment.
    A key difference between GCS and applications mentioned above 
(e.g., EOR, natural gas storage) is that the GCS goal is to keep the 
CO2 in the target reservoir indefinitely. There are many 
technologies used in industry today that can monitor CO2 in 
the subsurface and the surface, including time-lapse reflection seismic 
surveying, use of tracers, and electrical soundings. Some of these 
approaches have been tested in commercial and experimental projects, 
including DOE sponsored efforts like the Frio Brine Pilot and current 
efforts in the Regional Partnerships program. However, to date there 
has not been a concerted effort to apply these technologies in a 
comprehensive or integrated manner to monitor CO2.
    This new application will have new requirements, such as a 
monitoring and verification (M&V) program. A site M&V program to 
support GCS should provide these services:

   identify any early concerns or problems (as mentioned below) 
        and protect public health and safety;

   assign credits or offsets for commercial GCS, especially 
        under a cap-and-trade regime;

   validate simulations and current understanding of 
        sequestration science; and

   guide any necessary mitigation efforts.

    Several hazards could affect CCS operations at a site. These 
hazards, such as well failure or CO2 seepage along faults, 
could lead to problems such as atmospheric release of CO2 or 
groundwater contamination. Pre-existing wells present the largest risks 
as potential leakage paths, but leakage through wells is the simplest 
to detect and mitigate. Preliminary analyses through analog studies and 
simulation, which have been performed by industry, academia and 
national laboratories, suggest that the risks posed by these hazards 
are both very small and manageable. As such, the technical community 
has considerable confidence that carbon capture and sequestration can 
be safely and effectively deployed widely within the U.S.. Key steps to 
avoiding hazards are careful site characterization before injection and 
appropriate M&V programs during injection. If good sites are selected 
and effectively monitored, there is little chance of site failure or 
CO2 leakage.
    In short, there is enough knowledge and experience available today 
to safely and effectively choose a site, characterize it, operate it, 
monitor it, and close it. On a project basis, then, sequestration is 
technically ready, but it is rarely commercially deployed since 
potential operators have few mechanisms to recover their costs. In 
contrast, there is not enough information to proceed with regulations 
and legal structures to enable sequestration on a regional or national 
basis. This lack of technically founded regulation is important to 
bring sequestration into commercial operation, and the government has a 
role both in supporting projects that provide this technical 
information and in integrating these results rapidly into guidelines, 
statutes, standards, and ultimately regulations that provide market 
clarity and sureness.

The Potential for Commercial GCS
    Today, the U.S. emits annually 2 billion tons CO2 from 
large point sources, and 25 percent of U.S. CO2 emissions 
come from coal power generation (1.5 billion tons). To help you 
appreciate the scales involved, 1 billion tons is greater than the mass 
of all human beings on Earth. Alternatively, the volumes of 
CO2 at depth represented by this mass exceed current annual 
U.S. oil and natural gas production combined. A single 1,000 MW coal 
power plant will emit from 5 to 8 million tons of CO2 each 
year, roughly the same emissions as a 25,000 barrel/day coal-to-liquids 
plant. With sequestration in an appropriate geological formation, a 50 
year injection program for one of these plants would accumulate in 
excess of 2 billion barrels of CO2. It is the necessary 
scale of sequestration projects and enterprise that present challenges 
to deployment.
    The good news is that it appears that the U.S. has more than enough 
capacity to deploy CCS at large scale. Conservative estimates 
(including some I've published) are that the U.S. has 2,200 billion 
tons capacity. The DOE Office of Fossil Energy has recently published a 
Carbon Sequestration Atlas for North America that estimates capacity 
between 1,000 billion and 3,700 billion tons. Large sequestration 
resources occur in the Midwest, Texas, and the intermountain West, and 
substantial opportunities also exist in California, the Dakotas, 
Michigan, and offshore of the eastern U.S. The largest of these 
resources lie in saline formations and depleted oil and gas fields. 
While these published estimates are uncertain, it is likely that they 
substantially underestimate total U.S. capacity. Said another way, we 
appear to have enough capacity to comfortably inject all of our current 
point source CO2 emissions for more than 100 years, and are 
likely to be able to do so comfortably for more than 1,000 years.

Potential Climate Change Abatement and Cost
    CCS has the potential to substantially reduce U.S. and global 
greenhouse gas emissions. From a technical basis, that potential is 
only limited by the characteristics of the geology. Three conditions 
are important, sometimes called the ICE characteristics:

   I: sufficient injectivity to receive large volumes of 
        CO2 rapidly (up to several million tons 
        CO2/year for each project).

   C: sufficient capacity to accept large volumes of 
        CO2 (for some projects, in excess of 300 million 
        tons over the project lifetime).

   E: effectiveness in trapping CO2 for long time 
        spans (100s to 1,000s of years).

    Based on these characteristics, it appears that CCS provides both 
the U.S. and world a potential to reduce global emissions between 15 
and 55 percent by 2050. This abatement estimate is based on current 
understandings of global geological options and energy supply 
infrastructure. The high reductions can be achieved through advanced 
technology options which connect the transportation sector to a 
decarbonized electric power sector that includes CCS (e.g., plug-in 
hybrid deployment, biofuels, or hydrogen). Importantly, this is a very 
attractive option for rapidly developing countries like China and India 
with large coal resources.
    Most experts see CCS as a bridging technology providing time for 
new carbon free technologies, including renewables, advanced fission 
and fusion power, and other developing technologies, to grow in the 
marketplace. The technology is actionable immediately and could be 
sustained for many years, allowing us to dramatically reduce greenhouse 
gas emissions while maintaining the economic benefits of fossil fuel 
power generation and making use of the current infrastructure. CCS 
could be sustained in the U.S. for a century serving as an affordable 
interim measure to buy time while an energy strategy and infrastructure 
is developed to support long-term needs.
    Others testifying before this committee have discussed the costs of 
carbon capture and separation. By comparison, the costs of 
sequestration are much lower. For most U.S. targets, the estimated cost 
of storage injection projects ranges from $1 to $12 per ton 
CO2, and average cases range from $5 to $8 per ton 
CO2. This is roughly 10 percent the total cost of capture 
and separation. The cost of monitoring and verification is much lower, 
with estimates from $0.25 to $1.00 per ton CO2. The costs of 
assessment and site characterization are even less, estimated to be 
much less than $0.001 per ton CO2.
    One important way to consider cost vs. benefit of carbon capture 
and sequestration is its potential role in managing global climate 
change. Recent reports published by the UK's Stern Review and Pacific 
Northwest National Laboratory suggest that if CCS were not available as 
an option, the costs of addressing climate change would be 50-80 
percent higher than if CCS were a major contributor.

Technical Needs
    I want to focus on three particular immediate technical needs: an 
assessment of geological resources within the U.S., the pursuit of 
large-scale sequestration projects, and improved hazard assessment and 
management to reduce risks.

Resource Assessment
    To better bound the 15 to 55 percent estimate of potential 
greenhouse emission abatement through carbon sequestration, we need to 
increase the current understanding of global and national geological 
storage resources. Ultimately, GCS potential will depend on local 
geological conditions and energy infrastructure choices. Future energy 
infrastructure decisions (e.g., plant type and location) should be 
informed by understandings of storage resources. Assessment of this 
resource can be accomplished through careful and detailed geological 
studies and validated by a handful of large-scale demonstrations in 
representative geology. Those demonstrations should both confirm the 
safe and effective storage of CO2 in the key formations and 
should provide the technical basis for future regulatory framework and 
operation protocols.
    A national capacity assessment would provide the same kinds of 
information that the national hydrocarbon assessments offer in mapping 
the natural resources of the country with respect to this purpose. In 
this context, available pore volume to store CO2 is such a 
resource. An assessment of geological storage resources should provide 
several key pieces of technical information:

   A uniform, documented methodology that allows 
        intercomparisons of geologic opportunities and accounts for the 
        different trapping mechanisms.

   A capacity estimate for each region or state and for the 
        Nation as a whole.

   A relative ranking of potential sites by storage 
        effectiveness, and their associated capacities.

   Rate information indicating the likely maximum sustainable 
        injection rates for formations and regions.

   Data needed to develop economic models for GCS projects.

    As mentioned above, DOE's Office of Fossil Energy published the 
Carbon Sequestration Atlas, which provided preliminary estimates of 
capacity in saline formations, depleted oil and gas fields, and 
unmineable coal seams. This was an important initial step in 
understanding the U.S. sequestration resource. This work can continue 
to be refined and improved to provide greater understanding of the 
location and density of high quality sequestration resource. The DOE 
and the U.S. Geological Survey have only begun joint work on this 
effort, and should be funded to pursue development of methodology and 
maps.

Large-scale, Long-term Experiments
    Large projects are crucial to confirming our understanding of how 
CO2 is trapped and stored, refining deployment operations, 
and demonstrating success. Because of the enormous scale required for 
commercial CCS operation,. While smaller projects provide a partial 
learning platform; however, the key unresolved questions pertaining to 
commercial-scale injections can only be resolved at large scale. This 
is due to the hydrological, chemical, and mechanical response of the 
crust to changes in pressure and fluid composition from CO2 
injection. Many important responses only occur when thresholds are 
reached, and these will not be reached by small-scale injections. For 
example, the pressure build-up could cause mechanical failure of the 
caprock, faults, or wells only when their yield strength is exceeded. 
That cannot be tested with small-scale injections. Similarly, the rock 
heterogeneities that control flow in target reservoirs do not become 
apparent until large volumes are injected for long periods of time.
    These issues are critical for establishing long-term commercially 
viable operational and regulatory frameworks. Of equal importance, 
these technical issues should advise the formation of practices, 
protocols, and ultimately standards for CCS. We currently lack 
guidelines and protocols on minimal requirements for site 
characterization, operational safety, monitoring and verification, 
hazard management, and site closure. Implementing a select number of 
large-scale experimental projects (on the order of 1 million tons 
CO2/year injection) in target reservoirs of different 
characteristics that are instrumented, monitored, and analyzed to 
verify the practical reliability and implementation of sequestration. 
With appropriate, integrated science and technology program to provide 
the needed analysis, large experiments will provide the critical segue 
way to commercial operation and significant abatement of CO2 
in our atmosphere. To help assure the delivery of the scientific 
information most crucial to success, a minimum project budget of $120 
million would be prudent, with a minimum scientific budget of $40-$70 
million.
    The specifics of an individual large sequestration experimental 
project are detailed in MIT (2007), Friedmann (2006), and U.S. DOE 
(2007) studies.
    Initial sets of projects could be most rapidly brought forward 
where low-cost, pure CO2 streams are available. These 
include natural CO2 supplies, hydrogen plants, ethanol 
plants, fertilizer plants, synthetic natural gas plants, and gas 
processing plants. This mix is well reflected in the current effort of 
the regional partnerships, such as the DOE Regional Carbon 
Sequestration Partnership previously mentioned, which is configured in 
a way to produce the necessary learnings. It must be stressed that the 
very first projects should be selected with the utmost care and due 
diligence both to help ensure project success and to guard against 
potential unanticipated hazards (the FutureGen selection process was 
constructed with this goal in mind). Most importantly, these projects 
must serve the urgent need to provide answers to key questions asked by 
potential operators, regulators, insurers, financiers, and public 
stakeholders. These questions involve questions of site selection, 
monitoring, hazard identification and management, and subsurface 
process. As such, they must be both appropriately funded and 
appropriately managed to achieve these goals. Finally, as the projects 
proceed, the learnings should be integrated in a staged way. For 
example, an operational protocol onsite characterization could be 
released after just 2-3 years of work, followed by other protocols and 
guidelines on infrastructure development, baseline monitoring, hazard 
assessment and evaluation, operations, and monitoring and verification.

Hazards Assessment and Management
    As mentioned above, a number of potential hazards to long-term 
storage have been identified (such as wells and faults). While it is 
believed that these hazards can be readily avoided and managed, 
prudence suggests a more concerted and technically grounded effort to 
understand the risks posed by these hazards. Three issues are of 
greatest interest:

   Protocols and standards for hazard identification and 
        characterization.

   Improved understanding of the potential failure modes of 
        these hazards.

   Protocols and standards for avoiding hazard failure.

    By focusing on hazards management in addition to understanding 
risks, it is possible to provide potential operators, regulators, and 
investors the information they need to make key decisions swiftly. Such 
a program would help bring GCS projects to operational readiness more 
quickly.
    A concerted program that combines field, laboratory, and numerical 
approaches could provide the technical basis for hazard assessment and 
management within 5 years. This work should include a focus on those 
hazards, failure modes, and consequences that present credible, 
substantial health, safety and environmental risks. Additional funding 
to rapidly begin and execute this effort is warranted.

Summary
    Opportunities for rapid deployment of GCS exist in the U.S. There 
is enough technical knowledge to select a safe and effective storage 
site, plan a large-scale injection, monitor CO2, and 
remediate and mitigate any problems that might arise (e.g., well-bore 
leakage).
    This knowledge derives from over 100 years of groundwater resource 
work, oil and gas exploration and production, studies of geological 
analogs, natural gas storage site selection and operation, and 
hazardous waste disposal. A careful operator could begin work today at 
a commercial scale and confidently select and operate a site for 30 to 
50 years.
    National deployment of commercial CCS poses technical challenges 
and concerns due to the required operational scale to make a tangible 
impact on CO2 emissions. In particular, there is an acute 
lack of standards and protocols to guide the decisions of potential 
operators, regulators, and investors. An aggressive research, 
development, and deployment program focused on large, sustained field 
experiments could answer the key technical questions and provide these 
protocols within 10 years and could advise the formation of a legal and 
regulatory framework to protect the public without undue burden to 
industry.

Key References
    Benson S.M., Cook P., 2005, Chapter 5: Underground Geological 
Storage, IPCC Special Report on Carbon Dioxide Capture and Storage, 
Intergovernmental Panel on Climate Change, Interlachen, Switzerland, 
www.ipcc.ch, pp. 5-1 to 5-134.
    MIT, 2007, Future of Coal in a Carbon Constrained World, MIT Press.
    U.S. DOE, 2007, Carbon Sequestration Technology Roadmap and Program 
Plan for 2007, Morgantown, W.V., 39 p.
    Intergovernmental Panel on Climate Change, 2005, Summary for Policy 
Makers, IPCC Special Report on Carbon Dioxide Capture and Storage, 
Intergovernmental Panel on Climate Change, Interlachen, Switzerland, 
www.ipcc.ch.
    Jarrell P.M., Fox C.E., Stein M.H., Webb S.L., 2002, Practical 
aspects of CO2 flooding. Monograph 22. Society of Petroleum 
Engineers, Richardson, TX, USA.
    Pacala S., Socolow R., Stabilization Wedges: Solving the Climate 
Problem for the Next 50 Years Using Current Technologies, Science, 
2004, v.305, pp. 986.
    National Petroleum Council, 2007, Facing the Hard Truths About 
Energy, Washington, D.C., 442 p.
    California Energy Commission, 2007, Geological carbon sequestration 
strategies for California: The Assembly bill 1925 report to the 
California legislature, Report # CEC-500-2007-100-SD, 161 p.
    Interstate Oil and Gas Compact Commission, 2007, Storage of Carbon 
Dioxide in Geological Structures: A Legal and Regulatory Guideline for 
the States and 
Provinces, 49 p. http://www.iogcc.state.ok.us/PDFS/
CarbonCaptureandStorage
ReportandSummary.pdf.

Current Large Projects
    Arts R., Eiken O., Chadwick A., Zweigel P., van der Meer L., 
Zinszner B., 2004, Monitoring of CO2 injected at Sleipner 
using time-lapse seismic data, Energy, 29, pp. 1383-1392
    Wilson M., Monea M.. (Eds.), IEA GHG Weyburn CO2 
Monitoring & Storage Project Summary Report 2000-2004, 2004, 273 p.
    Riddiford F., Wright I., Espie T., Torqui A., 2004, Monitoring 
geological storage: In Salah Gas CO2 Storage Project, GHGT-
7, Vancouver.

Natural Analogs
    Allis R., Chidsey T., Gwynn W., Morgan C., White S., Adams M., 
Moore J., 2001, Natural CO2 reservoirs on the Colorado 
Plateau and southern Rocky Mountains: Candidates for CO2 
sequestration. Proceedings of the First National Conference on Carbon 
Sequestration, May 2001, DOE NETL, Washington, D.C.
    Czernichoswki-Lauriol, I., et al., 2002, The French carbogaseous 
province: an illustration of the natural processes of CO2 
generation, migration, accumulation, and leakage, Proc. of GHGT-6, 
Kyoto, E1-2.
    IEA International Energy Agency (2006) Natural Emissions of Carbon 
Dioxide. International Energy Agency Greenhouse Gas Programme. http://
www.iea
green.org.uk/.
    IEA International Energy Agency (2005) A review of natural 
CO2 emissions and releases and their relevance to 
CO2 storage. International Energy Agency Greenhouse Gas 
Programme, Report 2005/8. http://www.ieagreen.org.uk/.
Capacity Assessments
    U.S. DOE, 2007, Carbon Sequestration Atlas of the United States and 
Canada, Office of Fossil Energy, National Energy Technology Laboratory, 
Morgantown, W.V., 90 p.
    Gibson-Poole C.M., Lang S.C., Streit J.E., Kraishan G.M., Hillis 
R.R., Assessing a basin's potential for geological sequestration of 
carbon dioxide: an example from the Mesozoic of the Petrel Sub-basin, 
NW Australia; Keep, M. & Moss, S.J. (eds). The Sedimentary Basins of 
Western Australia 3: Proceedings of the Petroleum Exploration Society 
of Australia Symposium, Perth, 2002, pp. 439.
    Bradshaw J., Allison G., Bradshaw B.E., Nguyen V., Rigg A.J., 
Spencer L., Wilson, P., Australia's CO2 Geological storage 
potential and matching of emission sources to potential sinks. In: 
Greenhouse gas control technologies: Proceedings of the 6th 
International Conference on Greenhouse Gas Control Technologies, 1-4 
October 2002, Kyoto, 2003.
    Carbon Sequestration Leadership Forum, Discussion Paper on Capacity 
Estimation, Technical Working Group, Olveida, Spain, 2005. http://
www.cslforum.org/presentations.htm.
    Friedmann S.J., Dooley J.J., Held H., Edenhofer O., 2006, The low 
cost of geological assessment for underground CO2 storage: 
Policy and economic implications, Energy Conversion Management, v47, 
pp. 1894-1901.
    Dooley J.J., Friedmann S.J., A regionally disaggregated global 
accounting of CO2 storage capacity: data and assumptions, 
Pacific Northwest National Laboratory, Report PNWD-3431, 2004.
Large Project Design and Policy Support
    Friedmann S.J., 2006, The scientific case for large CO2 
storage projects worldwide: Where they should go, what they should look 
like, and how much they should cost, 8th Greenhouse Gas Technology 
Conference, Trondjheim, Norway, Poster session II.
    Wilson E.J., Friedmann S.J., Pollak M.F., 2007, Research for 
Deployment: Incorporating Risk, Regulation and Liability for Carbon 
Capture and Sequestration, Environment and Science Policy, v41, 5945-
5952.
                                 ______
                                 
     Response to Written Questions Submitted by Hon. John Thune to 
                          Howard Herzog, Ch.E.

    Question 1. As is noted in some of your testimony, China and India 
also use coal to meet significant portions of their energy needs and 
are quickly becoming some of the world's largest polluters. What is the 
potential of these countries to use CCS to limit their emissions? Will 
technologies that we develop be of use to them, or do they face a 
different set of technical and non-technical limitations?
    Answer. The biggest factor in determining a country's CCS potential 
is the availability of the appropriate geologic reservoirs. To my 
knowledge, no detailed studies have been conducted in China or India to 
determine their resource base. The general feeling is that their 
opportunities will be more limited than the U.S. (which has a very good 
resource base), but that significant opportunities should exist.
    In general, the technologies developed in the U.S. should be 
transferable to India and China, but they may need to be adapted for 
local conditions. A key factor in determining the type of capture 
technology to use is the coal grade and quality.

    Question 2. A number of you mention the necessity of large scale 
experiments on CCS. Is government funding for these projects necessary, 
or is it possible that there can be partnerships between various 
private entities that could conduct this research? In addition to 
funding, what role should the Federal Government play in these 
experiments?
    Answer. Based on observing industry trying to address this issue, 
it is my strong feeling that significant government funding will be 
needed for the initial round of large-scale projects. Other government 
roles include (1) setting experimental objectives so these projects 
produce the data needed for wide-scale implementation and (2) helping 
deal with nontechnical issues such as permitting and liability.

    Question 3. Mr. Herzog, The National Energy Technology Laboratory 
reports that the United States has the largest coal deposits in the 
world the most suitable geology for carbon sequestration. Moreover, the 
Department of Energy is about to embark on an $800M carbon dioxide 
sequestration program that will be conducted at seven sites in the U.S. 
If carbon dioxide sequestration is proven to work, is there any reason 
not to do it immediately so we can take advantage of our large coal 
deposits?
    Answer. From a technical standpoint, there is no reason we will not 
be able to proceed immediately. The question on how fast to proceed 
will be mainly economic.
                                 ______
                                 
     Response to Written Questions Submitted by Hon. John Thune to 
                              Charles Fox

    Question 1. You mention that there is a great amount of energy 
needed for post combustion capture of carbon. Could you compare the 
current lifecycle energy usage and emissions of post-combustion capture 
and pre-combustion capture? With reasonable advances in technology, how 
is this expected to change?
    Answer. I cannot compare the total lifecycle energy usage of post-
combustion capture and pre-combustion capture because I don't know how 
much carbon is emitted in the manufacture and construction of the 
facilities. I don't think that there would be much difference, but I 
have never seen a comparison.
    I will base a partial response on the IPCC Special Report: Carbon 
Dioxide Capture and Storage. The increased fuel requirement for capture 
for a new pulverized coal (PC) plant (post-combustion) is 24-40 
percent. The increased fuel requirement for an Integrated Coal 
Gasification and Combined Cycle power (IGCC) plant (pre-combustion) is 
14-25 percent. The net plant energy efficiency for the new PC plants is 
estimated to be 41 to 45 percent while the estimated net plant energy 
efficiency of the IGCC plants is a similar value of 38-47 percent. 
Based on these numbers, the increased fuel requirement for 
CO2 capture is about 64 percent greater for capture at a new 
PC plant vs. a new IGCC plant.
    This information along with the information on CO2 
emissions is provided in the table below:

------------------------------------------------------------------------
                                     New PC Plant       New IGCC Plant
    Power Plant with Capture       (Post-Combustion)   (Pre-Combustion)
------------------------------------------------------------------------
Increased Fuel Requirement (%)                24-40               14-25
Net Plant Energy Efficiency (%)               41-45               38-47
CO2 Emissions Rate after Capture          0.09-0.15           0.07-0.15
 (t/MWh)
------------------------------------------------------------------------

    I don't know how much new technology would change these values. I 
believe that one of the most valuable process improvements will be 
better integration of the capture technology into new plants. Mr. 
Herzog, who was on the panel, is an expert in this area.

    Question 2. Currently, carbon offsets range between $5 and $20 per 
ton and according to your testimony, the cost of carbon capture and 
sequestration ranges between $11 and $57 per metric ton. Do you expect 
future advances in technology to make CCS more competitive with other 
ways of limiting carbon emissions? How long will this take to happen?
    Answer. I believe that advances in technology will reduce the cost 
of CCS; however, I also expect that we will see new technology reduce 
the cost of limiting carbon emissions in other areas. Given the 
numerous other ways to limit carbon emissions, I believe that CCS will 
continue to be a relatively expensive method to combat climate change 
because it is energy intensive in itself. Nevertheless, society will 
continue to need electricity. I doubt that other sources such as 
nuclear, solar and wind energy will completely displace coal (and 
natural gas) during the next half century. In a world largely dependent 
on coal-fired electrical plants, we will need to develop a CCS 
program--at least as a bridging technology.
    With respect to timing, I think that it would take approximately 5 
years to field test a capture technology and advance to another level. 
Capture technology could improve in several areas: improved chemical 
solvents, better integration of the capture process into the power 
plant, higher efficiency compression and pumping technologies and 
perhaps usage of membranes to separate the CO2. It may take 
several rounds to improve the process to the point where society 
chooses to pay for CCS rather than for other carbon mitigating 
techniques.
    Unlike capture, transportation and storage will not drive the 
costs. Issues related to storage should be answered during the next 10 
years. Injection into depleted oil and gas fields may be a first step 
toward injection into saline reservoirs because reservoir descriptions 
were completed for hydrocarbon recovery.

    Question 3. I have been following the issue of carbon sequestration 
closely. This is an issue which is vital to our future energy needs and 
to our national security. As many of you know, the United States Air 
Force has been working with coal-to-liquids technology in order to 
provide a domestic source of fuel for their air fleet. They have also 
been a proponent of carbon dioxide reuse. Can you tell us what emerging 
technologies exist for commercial use of substantial volumes of carbon 
dioxide other than enhanced oil or coal bed methane recovery?
    Answer. I am familiar with one emerging technology that could use 
substantial volumes of CO2, enhanced gas recovery (EGR). 
This is a process somewhat similar to Enhanced Oil Recovery (EOR) and 
coal bed methane (CBM) recovery. In this process, (liquid or 
supercritical) CO2 is injected in the bottom of a natural 
gas reservoir while the natural gas (methane) is produced in wells some 
distance away and at higher depths. The idea is to repressure the 
reservoir with a substance that fills up the bottom of the reservoir 
and does not diffuse rapidly into the methane.
    This process is not yet in commercial use. It is being field tested 
in The Netherlands, perhaps elsewhere. Curtiss Oldenburg at the 
Lawrence Berkeley National Laboratory is a U.S. expert.
    In the U.S. about 70 percent of CO2 usage is for 
enhanced oil recovery. According to SRI Consulting (Chemical Economics 
Handbook--2007) in 2004, 31,900 short tons of CO2 was 
produced for EOR vs. 14,900 short tons which were produced for other 
commercial sales. This split of underground usage vs. surface usage has 
been fairly consistent for over a decade. I believe that finding new 
large scale usages (other than EGR) is unlikely.

                                  
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