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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

(

(II)

SENATE COMMITTEE ON COMMERCE, SCIENCE, AND TRANSPORTATION

ONE HUNDRED TENTH CONGRESS

FIRST SESSION

DANIEL K. INOUYE, Hawaii, Chairman

JOHN D. ROCKEFELLER IV, West Virginia

JOHN F. KERRY, Massachusetts

BYRON L. DORGAN, North Dakota

BARBARA BOXER, California

BILL NELSON, Florida

MARIA CANTWELL, Washington

FRANK R. LAUTENBERG, New Jersey

MARK PRYOR, Arkansas

THOMAS R. CARPER, Delaware

CLAIRE MCCASKILL, Missouri

AMY KLOBUCHAR, Minnesota

TED STEVENS, Alaska, Vice Chairman

JOHN MCCAIN, Arizona

TRENT LOTT, Mississippi

KAY BAILEY HUTCHISON, Texas

OLYMPIA J. SNOWE, Maine

GORDON H. SMITH, Oregon

JOHN ENSIGN, Nevada

JOHN E. SUNUNU, New Hampshire

JIM DEMINT, South Carolina

DAVID VITTER, Louisiana

JOHN THUNE, South Dakota

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, Chairman

JOHN D. ROCKEFELLER IV, West Virginia

BYRON L. DORGAN, North Dakota

BARBARA BOXER, California

MARIA CANTWELL, Washington

MARK PRYOR, Arkansas

CLAIRE MCCASKILL, Missouri

AMY KLOBUCHAR, Minnesota

JOHN ENSIGN, Nevada, Ranking

JOHN MCCAIN, Arizona

KAY BAILEY HUTCHISON, Texas

GORDON H. SMITH, Oregon

JOHN E. SUNUNU, New Hampshire

JIM DEMINT, South Carolina

JOHN THUNE, South Dakota

(III)

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

(1)

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

2

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 Nin ̃ o 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 enhancedoil 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

3

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.

4

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

5

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:]

6

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.

7

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.

8

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.

9

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 ‘‘bottomup’’ 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

10

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.

11

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. Precombustion 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,

12

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, nontechnical 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) techVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00016 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
13

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.

nology; 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.


1107FOX1.eps
14

2http://www.netl.doe.gov/technologies/carbonlseq/partnerships/phase1/pdfs/CarbonSepa

rationCapture.pdf.

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

15

3http://www.aseanenvironment.info/Abstract/41013970.pdf.

4http://www.ipcc.ch/activity/srccs/SRCCSlChapter3.pdf.

5http://www.delphi.ca/apec/Modules/Module2.pdf.

6http://www.delphi.ca/apec/Modules/Module3.pdf.

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.

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.

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.

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 coalfired 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

16

7http://www.ipcc.ch/activity/srccs/SRCCSlChapter3.pdf.

8http://gcep.stanford.edu/pdfs/RxsY3908kaqwVPacX9DLcQ/kobayashilcoallmar05.pdf.

9http://opencrs.cdt.org/rpts/RL33971l20070419.pdf.

10http://www.delphi.ca/apec/Modules/Module4.pdf.

11http://www.ipcc.ch/activity/srccs/SRCCSlChapter4.pdf.

of 80–98 percent. This CO2 rich stream can then be compressed, dried, and further

purified before storage or use.7

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.

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

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/metricton 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.

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

17

12http://uregina.ca/ghgt7/PDF/papers/poster/350.pdf.

13The MMP is the pressure at which CO2 EOR works at maximum efficiency.

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

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:

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.

18

14 ‘‘CO2 Surface Facilities’’, Version PF81–P–03–02–06. John M. Campbell & Co., 2006.

15http://www.ipcc.ch/activity/srccs/SRCCSlChapter5.pdf.

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

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

19

16http://www.pnl.gov/gtsp/docs/ccslreport.pdf.

17http://www.fossil.energy.gov/programs//sequestration/geologic/index.html or http://www.

netl.doe.gov/publications/proceedings/98/98ps/ps4-8.pdf.

18http://www.pnl.gov/gtsp/docs/ccslreport.pdf.

19http://www.pnl.gov/gtsp/docs/ccslreport.pdf.

20http://www.netl.doe.gov/technologies/carbonlseq/index.html.

21http://www.netl.doe.gov/publications/carbonlseq/presentations/awma-2003CriticalReview

.pdf.

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.

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.

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

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

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

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,

20

22http://www.netl.doe.gov/publications/carbonlseq/presentations/awma-2003CriticalReview

.pdf.

23http://www.ipcc.ch/activity/srccs/SRCCSlChapter5.pdf.

24http://www.netl.doe.gov/publications/carbonlseq/presentations/awma25002003CriticalReview

.pdf.

25http://www.ipcc.ch/activity/srccs/SRCCSlChapter5.pdf.

26http://www.fossil.energy.gov/programs//sequestration/geologic/index.html.

27http://www.netl.doe.gov/publications/carbonlseq/presentations/awma–

2003CriticalReview.pdf.

thus, store more CO2.

22 Dewatering of a coal bed is often required prior to CBM

recovery.

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.

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

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

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.

21

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)

22

28The 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.

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

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 finetextured 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

23

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 nervVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00027 Fmt 6633 Sfmt 6601 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
24

1Since 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.

2Two 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).

ous, 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.

25

3The 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.

4The 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.

5The 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.

6The 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/.

7Secondary 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).

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.

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.

• 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.

• 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 furVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00029 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
26

8Federally 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.

10DOE’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/GEOlrpt.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, multicomponent 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.

ther reducing the potential for leakage, even if, for example, degrading cement

in an old abandoned well breached the reservoir seal.

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.

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

• providing sufficient financial resources for the pilot projects in order to learn

as much as possible from them; and

• expediting full-scale demonstration projects.

27

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

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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

29

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.

30

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

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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.

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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.

33

• 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, commercialscale 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.

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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 coalbased 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 largerscale tests, to multiple full-scale demonstrations, and finally to deployment in fullscale 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 fullscale 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 ‘‘learningby-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

35

1 IEA Greenhouse Gas R&D Programme (IEA GHG), ‘‘Estimating Future Trends in the Cost

of CO2 Capture Technologies,’’ 2006/5, January 2006.

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.

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 ultrasupercritical (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.


1107HANN1.eps
36

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 difVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00040 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE

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ferences 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.

38

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


1107HANN3.eps
39

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 multicontaminant 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 furVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00043 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
40

ther 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.


1107HANN4.eps
41

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 EnVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00045 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE

1107HANN5.eps 1107HANN6.eps
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ergy 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 hightemperature 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


1107HANN7.eps
43

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.


1107HANN8.eps
44

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


1107HANN9.eps
45

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.

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.

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 postcombustion 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 scaleup of post-combustion CO2 capture processes for PC plants, considerable engineering


1107HANN10.eps
46

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 potenVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00050 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
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tially 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 postcombustion 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 ammoniabased 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 reused), membranes, and biological systems. Funding comes from a variety of sources,

primarily DOE or internal funds, but the funding is neither sufficient or wellenough 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, eviVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00051 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
48

3http://www.co2captureandstorage.info/projectlspecific.php?projectlid=26.

dence 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 nonpower)—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

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 CO2 Storage Projects as of Early 2007

Project CO2 Source Country Start

Anticipated amount injected

by:

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.]

49

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 longterm 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


1107HANN11.eps
50

4http://web.mit.edu/coal/ThelFutureloflCoal.pdf .

5 EPRI, Overview of Geological Storage of CO2, Report ID 1012798

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:

• 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 coalderived 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 priVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00054 Fmt 6633 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE

1107HANN12.eps
51

5http://www.iogcc.state.ok.us/PDFS/CarbonCaptureandStorageReportandSummary.pdf.

6http://www.epa.gov/safewater/uic/pdfs/guideluiclcarbonsequestrationelfinal-03-07.pdf.

vate 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.

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.

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 Needs $830M/yr $800M/yr $800M/yr $620M/yr $400M/yr

(Public + Private Sectors)

Advanced Combustion, CO2

Capture 25% 25% 40%

Integrated Gasification 80% 80%

Combined Cycle (IGCC), CO2 50% 50% 40%

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.

52

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

53

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.

54

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.


1107WOLF1.eps 1107WOLF2.eps
55

1 Information about this software program can be found at http://www.forestbiometrics.com/

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.

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

56

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.

57

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 unmineable 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?

58

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

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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 coalfired 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

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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

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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.

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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

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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.

64

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.

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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 lefthand 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.

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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

67

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.

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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,

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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——

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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

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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,

72

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.

73

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 cornbased, 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

74

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?

75

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.]

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APPENDIX

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. ImmeVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00081 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
78

diate 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.)

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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.


1107ALST1.eps
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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

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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 postcombustion 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 airfired 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.

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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 carbonrich 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 ‘‘precombustion’’ 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 coalfired 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)

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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

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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

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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 susVerDate Nov 24 2008 13:48 Jul 31, 2012 Jkt 052754 PO 00000 Frm 00089 Fmt 6601 Sfmt 6621 S:\GPO\DOCS\75343.TXT SCOM1 PsN: JACKIE
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tained 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

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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

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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.

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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?

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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 (precombustion) 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:

Power Plant with Capture New PC Plant

(Post-Combustion)

New IGCC Plant

(Pre-Combustion)

Increased Fuel Requirement (%) 24–40 14–25

Net Plant Energy Efficiency (%) 41–45 38–47

CO2 Emissions Rate after Capture (t/MWh) 0.09–0.15 0.07–0.15

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-toliquids 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.

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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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