[Senate Hearing 110-120]
[From the U.S. Government Publishing Office]
S. Hrg. 110-120
COAL GASIFICATION: OPPORTUNITIES
AND CHALLENGES
=======================================================================
HEARING
before the
COMMITTEE ON
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED TENTH CONGRESS
FIRST SESSION
TO
ADDRESS OPPORTUNITIES AND CHALLENGES ASSOCIATED WITH COAL GASIFICATION,
INCLUDING COAL-TO-LIQUIDS AND INDUSTRIAL GASIFICATION
__________
MAY 24, 2007
Printed for the use of the
Committee on Energy and Natural Resources
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COMMITTEE ON ENERGY AND NATURAL RESOURCES
JEFF BINGAMAN, New Mexico, Chairman
DANIEL K. AKAKA, Hawaii PETE V. DOMENICI, New Mexico
BYRON L. DORGAN, North Dakota LARRY E. CRAIG, Idaho
RON WYDEN, Oregon CRAIG THOMAS, Wyoming
TIM JOHNSON, South Dakota LISA MURKOWSKI, Alaska
MARY L. LANDRIEU, Louisiana RICHARD BURR, North Carolina
MARIA CANTWELL, Washington JIM DeMINT, South Carolina
KEN SALAZAR, Colorado BOB CORKER, Tennessee
ROBERT MENENDEZ, New Jersey JEFF SESSIONS, Alabama
BLANCHE L. LINCOLN, Arkansas GORDON H. SMITH, Oregon
BERNARD SANDERS, Vermont JIM BUNNING, Kentucky
JON TESTER, Montana MEL MARTINEZ, Florida
Robert M. Simon, Staff Director
Sam E. Fowler, Chief Counsel
Frank Macchiarola, Republican Staff Director
Judith K. Pensabene, Republican Chief Counsel
C O N T E N T S
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STATEMENTS
Page
Bartis, James, Senior Policy Researcher, Rand Corporation,
Arlington, VA.................................................. 23
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................ 1
Bunning, Hon. Jim, U.S. Senator from Kentucky.................... 6
Denton, David, Director, Business Development, Eastman
Gasification Services Company, Kingsport, TN................... 31
Domenici, Hon. Pete V., U.S. Senator from New Mexico............. 3
Dorgan, Hon. Byron L., U.S. Senator from North Dakota............ 4
Fulkerson, William, Senior Fellow, Institute for a Secure and
Sustainable Environment, University of Tennessee, Knoxville, TN 20
Herzog, Antonia, Staff Scientist, Climate Center, Natural
Resources Defense Council...................................... 7
Ratafia-Brown, Jay, Senior Engineer and Supervisor, SAIC--Energy
Solutions Group, McLean, VA.................................... 37
Salazar, Hon. Ken, U.S. Senator from Colorado.................... 2
APPENDIX
Responses to additional questions................................ 65
COAL GASIFICATION: OPPORTUNITIES
AND CHALLENGES
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THURSDAY, MAY 24, 2007
U.S. Senate,
Committee on Energy and Natural Resources,
Washington, DC.
The committee met, pursuant to notice, at 9:35 a.m., in
room SD-366, Dirksen Senate Office Building, Hon. Jeff
Bingaman, chairman, presiding.
OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW
MEXICO
The Chairman. Why don't we go ahead and get started?
Thank you all for coming today. We're here to talk about
coal gasification technology and how it can be used to meet our
needs, both for energy security and reducing our contribution
to global warming. Although the fundamental technology we're
talking about today has been around for many decades,
relatively recent developments in the technology point to a
pathway that may allow us to use the abundant coal reserves
that we have in a way that's responsible, for future
generations. Our testimony today will help develop the policies
that will guide that development in the right direction.
Let me first indicate that this hearing will not be the
last that we have on this subject, or the last hearing or
workshop that we have on this subject. We will be holding a
longer, more in-depth hearing or workshop on coal gasification,
including coal-to-liquids, sometime in the next month or so.
Senators Tester, Corker, Dorgan, Salazar, and Conrad, have all
requested that we do so. I believe Senator Bunning has joined
in that. Coal-to-liquids, in particular, has received great
attention lately, due to the strong advocacy of various people
on this committee, and also, Montana's Governor, Brian
Schweitzer. I believe that we have much more to explore in that
area, and in the related areas of industrial use of coal. So, I
hope that today's hearing will be a good first step in
assessing the future uses of clean coal technologies.
We're entering a challenging time for energy in the United
States. While our fuel prices are going up, we're becoming
increasingly reliant on unstable, or unsavory, regimes for that
fuel. We're facing an increasingly urgent need to begin
addressing the real problems of global warming. I think we've
reached a point of consensus around this place on those issues,
and that's a positive development.
As the stabilization wedges that were developed at
Princeton, and are going to be referenced by at least some of
our witnesses today, make clear, we need to make advances on
many fronts at the same time if we're to deal with the issue of
greenhouse gas emissions. No one technology or policy will
suffice. It's very difficult to be sure which technology is
going to be the most important for the future.
The investments that we're going to be making in coming
years are significant. I think we're well advised to be careful
to make sure we don't make our challenges greater in other
areas in trying to address our fuel needs.
I don't think anyone here would seriously dispute that coal
is an important part of our fuel mix for the foreseeable
future. Our domestic reserves are abundant. The price spread
between coal and other fossil fuels is likely to make coal a
very attractive option for a long time.
However, the capital associated with coal facilities, and
particularly coal gasification facilities, is very high, often
in the range of $3 or $4 billion, or even more. Their expected
useful life is substantially more than 20 years. As a result,
if we make a mistake and encourage the development of plants
that we later find to be incompatible with our need to reduce
greenhouse gas emissions, this could prove to be a costly
mistake. For that reason, it makes sense for us to be careful
to structure incentives so that we don't lose sight of where we
need to be in the years ahead.
I believe we need to try to get a greenhouse gas emissions
framework in place as soon as possible. But, if that does not
happen this year, I think most would agree that it is going to
happen sometime in the relatively near future. The price
signals are not in place today to force deployment of the
cleanest technologies that we have available. That does not
mean commercial development and demonstration of those
technologies should have to wait.
The best way to avoid economic shocks down the road is to
lay the foundations today for the clean technologies that we
will be deploying tomorrow throughout forward-looking,
technology-forcing incentives.
So, we have some very good witnesses today. I look forward
to hearing from them. But, before introducing them, let me call
on Senator Domenici for any comments he has.
[The prepared statement of Sentor Salazar follows:]
Prepared Statement of Hon. Ken Salazar, U.S. Senator From Colorado
I want to thank Chairman Bingaman and Ranking Member
Domenici for holding today's hearing on coal gasification, and
efforts to convert coal to liquid fuels. During the Energy and
Natural Resources Committee mark-up of the Energy Savings Act
of 2007, we asked Chairman Bingaman and Ranking Member Domenici
to hold a hearing on issues related to converting coal to
liquid fuels. I appreciate the efforts of Chairman Bingaman,
Ranking Member Domenici, and the committee staff that went into
putting this hearing together so quickly.
My home state of Colorado is endowed with many natural
resources, including vast coal resources. In Colorado, 71% of
the electricity we produce is generated with coal. Colorado
consumed 18.9 million tons of coal in 2004, generating 37.5
million megawatts of electricity. Most of this coal comes from
Colorado, but some of it is from Wyoming.
Coal is our most abundant domestic energy source. It
provides more than 50% of our nation's electricity needs, and
America has enough coal to last more than 200 years.
Unfortunately, CO2 pollution from coal combustion is
a main cause of global warming, which threatens my state's
water resources, our economy, and our quality of life.
Fortunately, there seems to be more than one way to
reconcile coal use with protecting our climate, through new
low-carbon technologies such as Integrated Gasification
Combined Cycle (IGCC), oxy-coal combustion, coal gasification
and ultra-supercritical generation. In addition, advancements
in capturing carbon and safely sequestering it underground will
allow our country to use coal, and at the same time reduce
CO2 emissions. I am proud of the work this Committee
did in the Energy Savings Act of 2007 to promote research,
development and deployment of carbon capture and sequestration
technologies, and to do an assessment of our nation's carbon
storage capacity. What we learn from the national assessment
may be valuable in determining optimal locations to place coal-
to-liquid plants in order for them to be near areas where the
CO2 emissions can be safely sequestered.
Advances in technology indicate that a coal-to-liquid plant
using combined cycle technology, carbon capture and storage,
and biomass as part of the fuel source can result in far lower
greenhouse gas emissions. It is my understanding that some
coal-to-liquid processes can use up to 30% biomass in the
feedstock, which reduces the CO2 emissions from the
process. The use of a renewable fuel like biomass in these
plants presents a great opportunity to allow for an expanded
use of coal without adding to global warming.
Thank you Chairman Bingaman and Ranking Member Domenici for
holding today's hearing so that we can learn more about how our
country's greatest fossil fuel resource can be used to expand
the production of domestic fuels.
STATEMENT OF HON. PETE V. DOMENICI, U.S. SENATOR FROM NEW
MEXICO
Senator Domenici. Thank you very much, Mr. Chairman.
I apologize for being a couple of minutes late, but it was
impossible to get out of a traffic jam and get here any sooner.
But I want to thank you, Senator, for holding this hearing.
This hearing is not new to the committee. We've had several
hearings and conferences on this issue since 2005. All of our
sources of energy are going to be needed to help meet our
Nation's energy needs, and strengthen our energy security. We
will need wind, solar, geothermal, and all types of biomass. We
will need nuclear energy, and, yes, we will need America's most
abundant source of energy: coal. I have said, on numerous
occasions, that the Nation will be using greater amounts of
coal to meet our future energy demands. Today, coal-fired power
plants account for 50 percent of electricity generation in the
United States. EIA estimated that by 2030 this percentage will
be 57 percent, up by a full 7 points. Today, we look at the
usefulness of coal as a source of transportation fuel. I have
many questions regarding the environmental issues surrounding
this; however, I hope people will look at coal-to-liquids and
ask, ``What are the challenges we must face?'' instead of
asking how these challenges can be used to scare people. This
issue deserves a full and fair debate, and we must consider our
Nation's energy security.
The rest of the world is competing against us for every
drop of available oil and natural gas, and that competition
will become more intense, not less. These nations--often with
massive State-owned entities--will be competing against us to
find new energy sources and intellectual resources to find,
develop, and implement these new technologies. We must lead in
developing clean coal technology, renewable technologies, and
carbon sequestration technologies. The decision that this
Congress will be making this year will set the American energy
course for a number of generations to come.
Coal is a source that we have an abundance of, and if we
develop it wisely and lead the march to new clean coal, we will
be, without any question, leading the parade of technologies to
coal technology. It will give us economic potential to compete
with the world's emerging economies.
Here is what we know about coal-to-liquids: other
countries, like South Africa, have been converting coal into
transportation fuels through the Fischer-Tropsch process full-
time for some time. This is not a new technology. It has been
around since prior to the second World War. A number of these
processes to convert coal to transportation fuel have been
invented and are being tested and implemented in various parts
of the world, including China. Currently, China is constructing
an 800,000-barrel-per-day coal-to-liquid facility, and the
Chinese government proposes to build as much as 1 million
barrels of daily coal-to-liquid capacity by 2020. Though there
are many challenges to this, we should try to meet them, not
run away from them. The National Energy Technology Laboratory
recently released a report that indicates that the Fischer-
Tropsch's liquids facility, with carbon dioxide captured, is
both technically and economically feasible. Many agree that
technologies to remove carbon dioxide, and then sequester that
carbon dioxide, exist, but large-scale tests of carbon dioxide
sequestration must be completed.
Some of our witnesses today will discuss ways to integrate
biomass and coal-to-liquid technologies that would be nearly
carbon-neutral.
The United States Air Force is currently working with the
National Energy Technology Laboratory and others to develop a
domestically produced coal-based aviation fuel to supply all of
the Air Force's aviation fuel needs. It would be cleaner
burning, and it would also be domestically secure.
I look forward to hearing from our witnesses today, and I'm
excited by those who suggest that we can integrate coal-to-
liquid, gasification, and biomass, and produce transportation
fuels in an environmentally safe manner.
With that, I will close, and I look forward to the
testimony today.
Thank you very much, Mr. Chairman.
The Chairman. Thank you very much.
Senator Dorgan indicated he'd like to make a short
statement, and then, if any of the other members would, we'll
do that before we introduce the witnesses.
Senator Dorgan.
STATEMENT OF HON. BYRON L. DORGAN, U.S. SENATOR FROM NORTH
DAKOTA
Senator Dorgan. Mr. Chairman, not so much a statement as a
comment: I am told I'm going to be called to offer an amendment
on the floor on the temporary worker provision in a few short
minutes, and it'll be an amendment to sunset that provision.
So, before I get called away, I did want to make one point.
Back in the 1970's, we began a movement toward coal
gasification and a very big project. One was built on the
prairies of North Dakota, called the Great Plains Coal
Gasification Plant. Today, as we speak, it will be producing
synthetic natural gas from lignite coal. It is a technological
marvel. It exceeds everybody's expectation, produces not only
synthetic gas, but also chemical byproducts. At the same time
that we're doing that, we built a pipeline to transport the
CO2 into Canada, and so the CO2 from this
coal gasification plant--as we produce synthetic gas from
lignite coal--the CO2 goes to Alberta, Canada, where
it is invested into marginal oil wells to increase the
productivity of oil recovery in Canada. It is, I think, the
largest CO2 capture and beneficial use in the world.
I just wanted to make that point, because the Fischer-
Tropsch process, and associated processes--much of this is not
particularly new. We know we can do this. We have carbon-
capture issues, but we're showing, in North Dakota, with the
largest example of that in the world, that we can do that, as
well. So, I just wanted to make that point, in the event I get
called away for my amendment, I wanted that to be understood,
that this is working in our country, and we can do much, much
more of it.
[The prepared statement of Senator Dorgan follows:]
Prepared Statement of Hon. Senator Byron Dorgan, U.S. Senator From
North Dakota
We all recognize that important energy legislation will be
coming to the floor of the Senate in early June. The Energy and
Natural Resources Committee has worked in a bipartisan way on a
number of bills and has proven to be very productive.
During this time of high energy prices, U. S. dependence on
foreign sources of energy (particularly oil and natural gas),
our need for more renewable and alternative energy, and our
need to address climate change, all provide a clear signal that
more must be done.
Coal is our most abundant, most secure, and lowest cost
American energy resource. Coal is a major base load resource
for power generation, and has to play a significant role in our
energy mix.
We have the world's largest coal reserves, with more than
275 billion tons (250 years supply at current usage rates) and
we are the second largest consumer with over 1 billion tones
per year.
Lignite produces about 8% of our nation's coal needs and is
vital to North Dakota since we have about 800 years worth of it
in North Dakota.
We can and should find new and different ways to use coal.
Opportunities for coal use in the production of hydrogen,
chemicals, fertilizer, and liquid fuels must be explored.
I want to look at all of these options.
energy security and climate change
We have come to a new intersection of energy policy and
climate change, and there is an opportunity.
The debate over climate change science has ended, and many
of my colleagues have ideas and proposals to curb emissions.
I believe there has been an attitude shift in the country
recognizing the potential impacts of climate change, and we
need to address climate change legislation in a thoughtful and
comprehensive manner.
Curbing carbon emissions is a long-term issue, but we have
commercially ready technologies and opportunities such as
enhanced oil and gas recovery and recovery of coal bed methane.
Experts estimate that the U.S. has over 40 years of carbon
dioxide storage capacity in our oil and gas fields, and the use
of the carbon dioxide in this way could more than double our
domestic oil and gas production and reserve base. This would
enhance our energy security.
Another 35 years of carbon dioxide storage capacity can be
placed in un-mineable coal seams to possibly yield more natural
gas.
The long-term solution is storage in deep saline formations
where we have the capacity to store hundreds of years of carbon
dioxide.
industrial gasification and coal-to-liquids
In order to unlock coal's potential, we need to do more than
offer half-baked ideas.
I had several concerns with the original Thomas/Bunning
approach. It was very late in coming and had not been fully
vetted.
We need to require carbon capture and storage for these
projects, but the Thomas approach only said that it was an
option.
If we don't find ways to incorporate carbon capture and
storage then the total CO2 emissions from coal-to-
liquids is almost twice that of petroleum today.
The Thomas/Bunning approach had set a standard for coal
fuels at 21 billion gallons by 2022. But we still don't know
where that came from, what it is based on, or if that is an
achieveable figure.
Our primary need is to focus on the right incentives to work
with public funds to develop a core number of these facilities
(like 4-5) with carbon capture so that they become viable to
investors.
There is a pathway forward. I want to work with others on
the Energy Committee to find a way to make these happen.
I look forward to the testimony and discussion with our
panel of witnesses.
Senator Bunning. Just very short.
The Chairman. Yes. Senator Bunning.
STATEMENT OF HON. JIM BUNNING, U.S. SENATOR
FROM KENTUCKY
Senator Bunning. I really want to thank you, Mr. Chairman
and Senator Domenici, for following up and having this hearing,
and more hearings in relationship, so that we can put the
record straight on the use of coal-to-liquids or coal
gasification, carbon capture, carbon sequestration, the
cleanness of which it burns--the fuel, I'm speaking about and
the Air Force's direct interest in a domestic-based fuel. And I
thank you, from the bottom of my heart, for holding this
hearing.
The Chairman. Great.
Senator Tester, do you want to make any statement, or
Senator Corker, either one?
[No response.]
The Chairman. OK, I'll introduce three of the witnesses,
and then call on Senator Corker to introduce the other two that
are from his State of Tennessee.
The three that I'll introduce are: first, Dr. Antonia
Herzog, who is the staff scientist with the Climate Center, the
Natural Resources Defense Council, here in Washington. Thank
you for being here. James Bartis is here, who is a senior
policy researcher with RAND Corporation, here in Arlington,
Virginia. Thank you for being here. Dr. Jay Ratafia-Brown is a
senior engineer and supervisor with SAIC--Energy Solutions
Group, in McLean, Virginia.
Senator Corker, did you want to introduce the other two
witnesses from your home State?
Senator Corker. I'd be delighted to.
I want to thank you, with the other Senators, for having
these hearings. I know we've had numerous hearings in the past,
along with the Finance Committee. I, too, want to thank you for
following through and having these hearings again. I'm thrilled
with the resources that we have in our own State as it relates
to conquering these types of issues, and dealing with them,
which makes me even more interested, obviously, in these types
of technologies.
I'm really pleased that today we have two great
Tennesseans. Bill Fulkerson is a senior fellow at the Institute
for a Secure and Sustainable Environment at the University of
Tennessee, my alma mater. Before he joined the Institute, he
was for 32 years at Oak Ridge Laboratory, a leader in helping
us develop energy security here in our country. After that, he
chaired the Department of Energy Laboratory R&D Working Group,
and he's worked with an organization of R&D managers from 14
laboratories, working on energy issues. He drove up from
Tennessee. He's driving back after these hearings. We thank him
for being here.
David Denton is also from Tennessee. Eastman Chemical,
since 1983, has been utilizing these technologies in a way that
has led industry throughout America. In many ways, they are my
inspiration, if you will, as it relates to this type of
technology. David certainly is very highly involved in that,
searching for new customers, if you will, in this particular
technology. I welcome both of them here.
Thank you very much.
The Chairman. Thank you.
Thank you all for being here. Why don't we just start with
Dr. Herzog. Why don't you go ahead. If each of you will take 5
to 6 minutes, and summarize the main points you'd like us to
understand, we will include your full statement in the record.
Go right ahead.
STATEMENT OF ANTONIA HERZOG, STAFF SCIENTIST, CLIMATE CENTER,
NATURAL RESOURCES DEFENSE COUNCIL
Ms.Herzog. Thank you very much. Thank you for this
opportunity to testify today on the subject of coal
gasification technology and its challenges and environmental
impacts.
I'm staff scientist in the Climate Center at NRDC, a
national nonprofit organization of scientists, lawyers
dedicated to protecting public health and the environment.
I'd like to start by taking a broader perspective and
considering the primary motivation for pursuing coal
gasification technology. They are: its potential to reduce our
dependence on foreign energy sources and reduce our
CO2 emissions from conventional coal use.
The first issue is tied to both national security concerns
and the impact that several years of volatile and high natural-
gas and oil prices have had on our businesses and consumers.
The second is the result of the urgent need to turn the tide on
global warming.
To the first motivation, coal has the advantages of being a
cheap, abundant, and domestic resource, compared with oil and
natural gas, and the process of coal gasification can produce
substitutes for both of these.
To the second, coal gasification allows for more efficient,
cost-effective capture of CO2 from coal, which, if
the CO2 is then permanently disposed of, can provide
a lower carbon energy source than conventional coal use. Any
use of coal gasification must meet both these needs adequately.
Furthermore, I have to add that there are many disadvantages of
coal, beyond its CO2 emissions, which simply cannot
be ignored. From underground mining accidents and mountaintop-
removal mining to air emissions of acidic and toxic pollution,
from coal combustion, to water pollution, from coal mining and
combustion rates, the conventional coal fuel cycle is among the
most environmentally destructive activities on Earth, and we
simply cannot forget this. This is why we believe, at NRDC, we
must first turn to energy efficiency and renewable energy.
Energy efficiency remains the cheapest, cleanest, and fastest
way to meet our environmental challenges and energy needs,
while renewable energy is the fastest growing supply option
today.
Only then should we consider turning to methods that can
potentially make coal more compatible with protecting health
and the environment, and reducing our dependence on foreign
energy sources. With the right standards and incentives, we can
fundamentally transform the way coal is produced and used in
the United States and around the world.
Congress is now considering proposals to promote coal
gasification technologies with the goals of replacing natural
gas, oil, and conventional coal combustion for electricity.
These proposals can not only be evaluated in terms of our
energy security concerns, but must also be evaluated in the
context of the compelling need to reduce global warming
emissions steadily, significantly, starting now, and proceeding
along a declining pathway throughout the century.
My specialty is global warming, and so that's what I will
focus on here. This is not in any way to downplay the other
land, air, and water impacts, which are equally relevant and
concerning to us.
To avoid catastrophic global warming, the United States and
other nations will need to deploy energy resources that result
in much lower releases of CO2 than today's use of
oil, gas, and coal. In short, we need to start now, and a slow
start would mean a crash finish if we delayed starting soon. If
we wait too long to deploy low-carbon technologies, then we
would need to deploy them much faster than any conventional
technology that has been deployed in recent decades. In
addition, the effort would require prematurely retiring
billions of dollars in capital stocks that will be built or
bought online during the next 10 to 20 years, in the absence of
appropriate CO2 limits.
For the electricity sector, we believe that coal
gasification technologies could play a significant role. More
than 90 percent of the U.S. coal supply is used to generate
electricity currently, and a little over half of the U.S.
electricity supply is generated----
Senator Domenici. Senator Bingaman--excuse me--could we ask
the witness where her testimony is? Where is she testifying
from?
The Chairman. You're giving us a summary of the testimony
you submitted to the committee, is that correct?
Ms. Herzog. Yes. That's right.
The Chairman. I think that--the testimony she gave us is
right here in your book. It should be.
Senator Domenici. Right.
The Chairman. But she's just--yes--and she's just
summarizing it for us.
Senator Domenici. OK. I couldn't find a summary. The
summary is not in here.
Ms. Herzog. It isn't. I apologize.
Senator Domenici. That's fine.
Ms. Herzog. OK.
Senator Domenici. I'll keep looking, and you'll be
finished, and I'll still be looking.
Ms. Herzog. Right, right.
[Laughter.]
Ms. Herzog. Well, I'll certainly supply my summary
afterwards. I admit to having worked on it last night.
Anyway, continuing, we do believe that you can use coal
gasification to generate electricity, replacing conventional
coal combustion, capturing 85 to 90 percent of the carbon,
disposing of it permanently in geologic reservoirs, and this
technology can be consistent with reducing our global warming
emissions for the long term.
Now moving on to liquid fuels. We do not believe this
happens to be the case for liquid fuels produced using coal
gasification currently. To assess the global warming
implications of a large coal-to-liquids program, we need to
examine the total life cycle or well-to-wheel emissions of
these fuels. Coal contains about 20 percent more carbon per
unit of energy, compared to petroleum. When the coal is
converted to liquid fuels, two streams of CO2 are
produced, one at the coal-to-liquids production plant, and the
second from the vehicles when they burn the fuel. The
unavoidable fact is that liquid fuel from coal contains the
same amount of carbon as a gallon of gasoline or diesel made
from crude. Thus, the potential for achieving significant
CO2 emission reductions compared to crude is
limited.
Based on our analysis, that of EPA and Argonne National
Lab, the total well-to-wheel CO2 emissions from
liquid coal plants is twice as high as crude oil if the
CO2 is released to the atmosphere. Obviously,
introducing new fuel with twice the CO2 emissions is
simply not compatible with addressing global warming. Even if
the CO2 from the coal-to-liquids plants is captured,
the well-to-wheels CO2 emissions would still be
higher than today's crude oil system, and it is not clear how
efficiently and effectively we can capture that CO2
in the production process.
Using coal to produce a significant amount of liquid for
transportation fuels, we do not believe is compatible for our
need to develop a low-CO2-emitting transportation
sector.
Let me just give a quick example of some of the problems.
It's half of the alternative fuels----
The Chairman. Could you summarize your----
Ms. Herzog. Finish up?
The Chairman. Yes, if you could----
Ms. Herzog. OK.
The Chairman [continuing]. That would be great, too.
Ms. Herzog. I'm going to give you one example here.
The Chairman. OK.
Ms. Herzog. What is the best use of coal for the
transportation sector? There are better paths, we believe, to
take using coal. A ton of coal used in a power plant employing
carbon capture and disposal to generate electricity for a plug-
in hybrid vehicle will displace more than twice as much oil as
using the same coal to make liquid fuel in a plant that also
uses carbon capture and disposal.
Second, a hybrid vehicle running on liquid coal will emit
ten times as much carbon dioxide per mile as that plug-in
hybrid vehicle running on electricity made from coal using
carbon capture and disposal.
So, I'll leave that thought in mind as to which is the best
path to take for coal gasification technology.
[The prepared statement of Dr. Herzog follows:]
prepared statement of antonia herzog, staff scientist, climate center,
natural resources defense council
Thank you for the opportunity to testify today on the subject of
coal gasification technology and the challenges it faces. My name is
Antonia Herzog. I am a staff scientist in the Climate Center at the
Natural Resources Defense Council (NRDC). NRDC is a national, nonprofit
organization of scientists, lawyers and environmental specialists
dedicated to protecting public health and the environment. Founded in
1970, NRDC has more than 1.2 million members and online activists
nationwide, served from offices in New York, Washington, Los Angeles
and San Francisco.
One of the primary reasons that the electric power, chemical, and
liquid fuels industries have become increasingly interested in coal
gasification technology in the last several years is the volatility and
high cost of both natural gas and oil. Coal has the advantages of being
a cheap, abundant, and domestic resource compared with oil and natural
gas. However, the disadvantages of conventional coal use cannot be
ignored. From underground accidents and mountain top removal mining, to
collisions at coal train crossings, to air emissions of acidic, toxic,
and heat-trapping pollution from coal combustion, to water pollution
from coal mining and combustion wastes, the conventional coal fuel
cycle is among the most environmentally destructive activities on
earth.\1\
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\1\ ``Coal in a Changing Climate,'' NRDC position paper, February
2007, http://www.nrdc.org/globalWarming/coal/coalclimate.pdf.
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But we can do better with both production and use of coal. And
because the world is likely to continue to use significant amounts of
coal for some time to come, we must do better. Energy efficiency
remains the cheapest, cleanest, and fastest way to meet our energy and
environmental challenges, while renewable energy is the fastest growing
supply option. Increasing energy efficiency and expanding renewable
energy supplies must continue to be the top priority, but we have the
tools to make coal more compatible with protecting public health and
the environment. With the right standards and incentives we can
fundamentally transform the way coal is produced and used in the United
States and around the world.
In particular, coal use and climate protection do not need to be
irreconcilable activities. While energy efficiency and greater use of
renewable resources must remain core components of a comprehensive
strategy to address global warming, development and use of technologies
such as coal gasification in combination with carbon dioxide
(CO2) capture and permanent disposal in geologic
repositories under certain circumstances could enhance our ability to
avoid a dangerous build-up of this heat-trapping gas in the atmosphere
while creating a future for continued coal use.
However, because of the long lifetime of carbon dioxide in the
atmosphere and the slow turnover of large energy systems we must act
without delay to start deploying these technologies as appropriate.
Current government policies are inadequate to drive the private sector
to invest in carbon capture and disposal systems in the timeframe we
need them. To accelerate the development of these systems and to create
the market conditions for their use, we need to focus government
funding more sharply on the most promising technologies. More
importantly, we need to adopt binding measures and standards that limit
global warming emissions so that the private sector has a business
rationale for prioritizing investment in this area.
In addition, Congress should only allow new authorizations for
expenditures or the commitment of federal fiscal resources, including
an authorization for an appropriation, direct spending, tax measures,
loan guarantees or other credit instruments, to support the research,
development, demonstration or commercial deployment of an energy
producing technology if that technology, when commercially deployed:
(A) reduces greenhouse gas emissions, (B) reduces our dependence on
oil; and (C) provides an economic benefit to the U.S. economy.
Congress is now considering a variety of proposals to gasify coal
as a replacement for natural gas and oil. These proposals need to be
evaluated in the context of the compelling need to reduce global
warming emissions steadily and significantly, starting now and
proceeding constantly throughout this century. Furthermore, because
today's coal mining and use also continues to impose a heavy toll on
America's land, water, and air, damaging human health and the
environment, it is also critical to examine the implications of a
substantial coal gasification program on these values as well.
reducing natural gas and oil demand
The nation's economy, our health and our quality of life depend on
a reliable supply of affordable energy services. The most significant
way in which we can achieve these national goals is to exploit the
enormous scope to wring more services out of each unit of energy used
and by aggressively promoting renewable resources. While coal
gasification technology has been touted as the technology solution to
supplement our natural gas and oil supply and reduce our dependence on
natural gas and oil imports, the most effective way to lower natural
gas and oil demand, and prices, is to waste less. America needs to
first invest in energy efficiency and conservation to reduce demand,
and to second promote renewable energy alternatives to supplement
supply. Gasified coal may have a role to play, but in both the short-
term and over the next two decades, efficiency and renewables are the
lead actors in an effective strategy to moderate natural gas and oil
prices and balance our demand with reasonable expectations of supply.
Natural Gas
Increasing energy efficiency is far-and-away the most cost-
effective way to reduce natural gas consumption and avoid emitting
carbon dioxide and other damaging environmental impacts. Available
technologies range from efficient lighting, including emerging L.E.D.
lamps, to advanced selective membranes which reduce industrial process
energy needs. Critical national and state policies include appliance
efficiency standards, performance-based tax incentives, utility-
administered deployment programs, and innovative market transformation
strategies that make more efficient designs standard industry practice.
Conservation and efficiency measures such as these can have
dramatic impacts in terms of price and savings.\2\ Moreover, all of
these untapped gas efficiency ``resources'' will expand steadily, as a
growing economy adds more opportunities to secure long-lived savings.
California has aquarter century record of using comparable strategies
to reduce both natural gas consumption and the accompanying utility
bills. Recent studies commissioned by the Pacific Gas & Electric
Company showed that by 2001 longstanding incentives and standards
targeting natural gas equipment and use had cut statewide consumption
for residential, commercial, and industrial purposes (excluding
electric generation) by more than 20 percent.
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\2\ American Council for an Energy-Efficient Economy (ACEEE), Fall
2004 Update on Natural Gas Markets, November 3, 2004. See also Consumer
Federation of America, ``Responding to Turmoil in Natural Gas Markets:
The Consumer Case for Aggressive Policies to Balance Supply and
Demand,'' pp. 28, December 2004.
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Studies have consistently shown that reducing demand for natural
gas by increasing renewable energy use will reduce natural gas prices.
According to a report released by the U.S. Department of Energy's
Lawrence Berkeley National Laboratory, ``studies generally show that
each 1% reduction in national gas demand is likely to lead to a long-
term (effectively permanent) average reduction in wellhead gas prices
of 0.8% to 2%. Reductions in wellhead prices will reduce wholesale and
retail electricity rates and will also reduce residential, commercial,
and industrial gas bills.''\3\
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\3\ U.S. Department of Energy, Lawrence Berkeley National
Laboratory, Easing the Natural Gas Crisis: Reducing Natural Gas Prices
Through Increased Deployment of Renewable Energy and Energy Efficiency,
January, 2005, p. 13.
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Adoption of a national renewable energy standard (RES) can
significantly reduce the demand for natural gas, alleviating potential
shortages. The Energy Information Administration (EIA) has found that a
national 10 percent renewable energy standard could reduce gas
consumption by 1.4 trillion cubic feet per year in 2020 compared to
business as usual, or roughly 5 percent of annual demand. Furthermore,
there would be a $4.9 billion cumulative present value savings for
industrial gas consumers, $1.8 billion to commercial customers, and
$2.4 billion to residential customers.\4\ EIA also found that renewable
energy can help reduce electricity bills. Lower natural gas prices for
electricity generators and other consumers offset the slightly higher
cost of renewable electricity technology.\5\
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\4\ EIA, Impacts of a 10-Percent Renewable Portfolio Standard, SR/
OIAF/2002-03, February 2002. EIA, Analysis of a 10-Percent Renewable
Portfolio Standard, SR/OIAF/2003-01, May 2003.
\5\ UCS, Renewable Energy Can Help Alleviate Natural Gas Crisis,
June 2003, at 2.
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Implementing effective energy efficiency measures is the fastest
and most cost effective approach to balancing natural gas demand and
supply. Renewable energy provides a critical mid-term to long-term
supplement. Analysis by the Union of Concerned Scientists found that a
combined efficiency and renewable energy scenario could reduce gas use
by 31 percent and natural gas prices by 27 percent compared to business
as usual in 2020.\6\
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\6\ UCS, Clean Energy Blueprint: A Smarter National Energy Policy
for Today and the Future, October 2001.
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In contrast to these strategies, pursuing coal gasification
implementation strategies that address only natural gas supply
concerns, while ignoring impacts of coal, is a recipe for huge and
costly mistakes. Fortunately, we have in our tool box energy resource
options that can reduce natural gas demand and global warming emissions
as well as protecting America's land, water, and air.
Oil
NRDC fully agrees that reducing oil dependence should be a national
priority and that new policies and programs are needed to avert the
mounting problems associated with today's dependence and the much
greater dependence that lies ahead if we do not act. A critical issue
is the path we pursue in reducing oil dependence: a ``green'' path that
helps us address the urgent problem of global warming and our need to
reduce the impacts of energy use on the environment and human health;
or a ``brown'' path that would increase global warming emissions as
well as other health and environmental damage. In deciding what role
coal might play as a source of transportation fuel NRDC believes we
must thoroughly assess whether it is possible to use coal to make
liquid fuels without exacerbating the problems of global warming,
conventional air pollution and impacts of coal production and
transportation.
If coal were to play a significant role in displacing oil, it is
clear that the enterprise would be huge, so the health and
environmental stakes are correspondingly huge. The coal company Peabody
Energy is promoting a vision that would call for production of 2.6
million barrels per day of synthetic transportation fuel from coal by
2025, about 10% of forecasted oil demand in that year. According to
Peabody, using coal to achieve that amount of crude oil displacement
would require construction of 33 very large coal-to-liquids plants,
each plant consuming 14.4 million tons of coal per year to produce
80,000 barrels per day of liquid fuel. Each of these plants would cost
$6.4 billion to build. Total additional coal production required for
this program would be 475 million tons of coal annually--requiring an
expansion of coal mining of 43% above today's leve1.\7\ This testimony
does not attempt a thorough analysis of the impacts of a program of
this scale. Rather, it will highlight the issues that should be
addressed in a detailed assessment.
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\7\ Peabody's ``Eight-Point Plan'' calls for a total of 1.3 billion
tons of additional coal production by 2025, proposing that coal be used
to produce synthetic pipeline gas, additional coal-fired electricity,
hydrogen, and fuel for ethanol plants. The entire program would more
than double U.S. coal mining and consumption.
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environmental impacts of coal
Some call coal ``clean.'' It is not and likely never will be
compared to other energy options. Nonetheless, it appears inevitable
that the U.S. and other countries will continue to rely heavily on coal
for many years. The good news is that with the right standards and
incentives it is possible to chart a future for coal that is compatible
with protecting public health, preserving special places, and avoiding
dangerous global warming. It may not be possible to make coal clean,
but by transforming the way coal is produced and used, it is possible
to make coal significantly cleaner--and safer--than it is today.
Global Warming Pollution
To avoid catastrophic global warming the U.S. and other nations
will need to deploy energy resources that result in much lower releases
of CO2 than today's use of oil, gas and coal. To keep global
temperatures from rising to levels not seen since before the dawn of
human civilization, the best expert opinion is that we need to get on a
pathway now to allow us to cut global warming emissions by up to 80
percent from today's levels over the decades ahead. The technologies we
choose to meet our future energy needs must have the potential to
perform at these improved emission levels.
Most serious climate scientists now warn that there is a very short
window of time for beginning serious emission reductions if we are to
avoid truly dangerous greenhouse gas reductions without severe economic
impact. Delay makes the job harder. The National Academy of Sciences
recently stated: ``Failure to implement significant reductions in net
greenhouse gases will make the job much harder in the future--both in
terms of stabilizing their atmospheric abundances and in terms of
experiencing more significant impacts.''\8\
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\8\ National Academy of Sciences, Understanding and Responding to
Climate Change: Highlights of National Academies Reports, p.16 (October
2005), http://dels.nas.edu/dels/rpt briefs/climate-change-final.pdf.
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In short, a slow start means a crash finish--the longer emissions
growth continues, the steeper and more disruptive the cuts required
later. To prevent dangerous global warming we need to stabilize
atmospheric concentration at or below 450 ppm, which would keep total
warming below 2 degrees Celsius (3.6 degrees Fahrenheit). If we start
soon, we can stay on the 450 ppm path with an annual emission reduction
rate that gradually ramps up, but if we delay a serious start by 10
years or more and continue emission growth at or close to the business-
as-usual trajectory, the annual emission reduction rate required to
stay on the 450 ppm pathway jumps many-fold\9\. Even if you do not
accept today that the 450 ppm path will be needed consider this point.
If we do not act to preserve our ability to get on this path we will
foreclose the path not just for ourselves but for our children and
their children. We are now going down a much riskier path and if we do
not start reducing emissions soon neither we nor our children can turn
back no matter how dangerous the path becomes.
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\9\ D. D. Doniger, A.V. Herzog, D. A. Lashof, ``An Ambitious,
Centrist Approach to Global warming Legislation,'' Science, vol. 314,
p. 764 (November, 2006).
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In the past, some analysts have argued that the delay/crash action
scenario is actually the cheaper course, because in the future
(somehow) we will have developed breakthrough technologies. But it
should be apparent that the crash reductions scenario is implausible
for two reasons. First, reducing emissions by a very high rate each
year would require deploying advanced low-emission technologies at
least several times faster than conventional technologies have been
deployed over recent decades. Second, the effort would require
prematurely retiring billions of dollars in capital stock--high-
emitting power plants, vehicles, etc.--that will be built or bought
during the next 10-20 years under in the absence of appropriate
CO2 emission limits. It also goes without saying that U.S.
leadership is critical. Preserving the 450 ppm pathway requires other
developed countries to reduce emissions at similar rates, and requires
the key developing countries to dramatically reduce and ultimately
reverse their emissions growth. U.S. leadership can make that happen
faster.
To assess the global warming implications of a large coal
gasification program we need to carefully examine the total life-cycle
emissions associated with the end product, whether electricity,
synthetic gas, liquid fuels or chemicals, and to assess if the relevant
industry sector will meet the emission reductions required to be
consistent with what we need to achieve in the U.S.
Electricity Sector
More than 90 percent of the U.S. coal supply is used to generate
electricity in some 600 coal-fired power plants scattered around the
country, with most of the remainder is used for process heat in heavy
industrial and in steel production. Coal is used for power production
in all regionsof the country, with the Southeast, Midwest, and Mountain
states most reliant on coal-fired power. Texas uses more coal than any
other state, followed by Indiana, Illinois, Ohio, and Pennsylvania.\10\
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\10\ http://www.eia.doe.gov/cneaf/coal/page/acr/table26.html.
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About half of the U.S. electricity supply is generated using coal-
fired power plants. This share varies considerably from state to state,
but even California, which uses very little coal to generate
electricity within its borders, consumes a significant amount of
electricity generated by coal in neighboring Arizona and Nevada,
bringing coal's share of total electricity consumed in California to 20
percent.\11\ National coal-fired capacity totals 330 billion watts
(GW), with individual plants ranging in size from a few million watts
(MW) to over 3000 MW. More than one-third of this capacity was built
before 1970, and over 400 units built in the 1950s--with capacity
equivalent to roughly 100 large modern plants (48 GW)--are still
operating today.
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\11\ California Energy Commission, 2005. 2004 Net System Power
Calculation (April.) Table 3: Gross System Power. http://
www.energy.ca.gov/2005publications/CEC-300-2005-004/CEC-300-2005-
004.PDF.
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The future of coal in the U.S. electric power sector is an
uncertain one. The major cause of this uncertainty is the government's
failure to define future requirements for limiting greenhouse gas
emissions, especially carbon dioxide (CO2). Coal is the
fossil fuel with the highest uncontrolled CO2 emission rate
of any fuel and is responsible for 36 percent of U.S. carbon dioxide
emissions. Furthermore, coal power plants are expensive, long-lived
investments. Key decision makers understand that the problem of global
warming will need to be addressed within the time needed to recoup
investments in power projects now in the planning stage. Since the
status quo is unstable and future requirements for coal plants and
other emission sources are inevitable but unclear, there will be
increasing hesitation to commit the large amounts of capital required
for new coal projects.
Electricity production is the largest source of global warming
pollution in the U.S. today. In contrast to nitrogen and sulfur oxide
emissions, which have declined significantly in recent years as a
result of Clean Air Act standards, CO2 emissions from power
plants have increased by 27 percent since 1990. Any solution to global
warming must include large reductions from the electric sector. Energy
efficiency and renewable energy are well-known low-carbon methods that
are essential to any climate protection strategy. But technology exists
to create a more sustainable path for continued coal use in the
electricity sector as well. Coal gasification can be compatible with
significantly reducing global warming emissions in the electric sector
if it replaces conventional coal combustion technologies, directly
produces electricity in an integrated manner, and most importantly
captures and disposes of the carbon in geologic formations. IGCC
technology without CO2 capture and disposal achieves only
modest reductions in CO2 emissions compared to conventional
coal plants.
A coal integrated gasification combined cycle (IGCC) power plant
with carbon capture and disposal can capture up to 90 percent of its
emissions, thereby being part of the global warming solution. In
addition to enabling lower-cost CO2 capture, gasification
technology has very low emissions of most conventional pollutants and
can achieve high levels of mercury control with low-cost carbon-bed
systems. However, it still does not address the other environmental
impacts from coal production and transportation.
The electric power industry has been slow to take up gasification
technology, but two commercial-scale units are operating in the U.S.--
in Indiana and Florida. The Florida unit, owned by TECO, is reported by
the company to be the most reliable and economic unit on its system.
Two coal-based power companies, AEP and Cinergy, have announced their
intention to build coal gasification units. The first proposed coal
gasification plant that will capture and dispose of its CO2
was announced in February, 2006 by BP and Edison Mission Group. The
plant will be built in Southern California and its CO2
emissions will be pipelined to an oil field nearby and injected into
the ground to recover domestic oil. BP's proposal shows the
technologies are available now to cut global warming pollution and that
integrated IGCC with CO2 capture and disposal are
commercially feasible.
Liquid Fuels
To assess the global warming implications of a large coal-to-
liquids program we need to examine the total life-cycle or ``well-to-
wheel'' emissions of these new fuels. Coal is a carbon-intensive fuel,
containing double the amount of carbon per unit of energy compared to
natural gas and about 20% more than petroleum. When coal is converted
to liquid fuels, two streams of CO2 are produced: one at the
coal-to-liquids production plant and the second from the exhausts of
the vehicles that burn the fuel. With the technology in hand today and
on the horizon it is difficult to see how a large coal-to-liquids
program can be compatible with the low-CO2-emitting
transportation system we need to design to prevent global warming.
Today, our system of refining crude oil to produce gasoline,
diesel, jet fuel and other transportation fuels, results in a total
``well-to-wheels'' emission rate of about 27.5 pounds of CO2
per gallon of fuel. Based on available information about coal-to-
liquids plants being proposed, the total well to wheels CO2
emissions from such plants would be about 49.5 pounds of CO2
per gallon, nearly twice as high as using crude oil, if the
CO2 from the coal-to-liquids plant is released to the
atmosphere.\12\ Obviously, introducing a new fuel system with close to
double the CO2 emissions of today's crude oil system would
conflict with the need to reduce global warming emissions. If the
CO2 from coal-to-liquids plants is captured, then well-to-
wheels CO2 emissions would be reduced but would still be
higher than emissions from today's crude oil system.\13\
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\12\ Calculated well-to-wheel CO2 emissions for coal-
based ``Fischer-Tropsch'' are about 1.8 greater than producing and
consuming gasoline or diesel fuel from crude oil. If the coal-to-
liquids plant makes electricity as well, the relative emissions from
the liquid fuels depends on the amount of electricity produced and what
is assumed about the emissions of from an alternative source of
electricity.
\13\ Capturing 90 percent of the emissions from coal-to-liquid
plants reduces the emissions from the plant to levels close to those
from petroleum production and refining while emissions from the vehicle
are equivalent to those from a gasoline vehicle. With such
CO2 capture, well to wheels emissions from coal-to-liquids
fuels would be 8 percent higher than for petroleum.
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This comparison indicates that using coal to produce a significant
amount of liquids for transportation fuel would not be compatible with
the need to develop a low-CO2 emitting transportation sector
unless technologies are developed to significantly reduce emissions
from the overall process. But here one confronts the unavoidable fact
that the liquid fuel from coal contains the same amount of carbon as is
in gasoline or diesel made from crude. Thus, the potential for
achieving significant CO2 emission reductions compared to
crude is inherently limited. This means that using a significant amount
of coal to make liquid fuel for transportation needs would make the
task of achieving any given level of global warming emission reduction
much more difficult. Proceeding with coal-to-liquids plants now could
leave those investments stranded or impose unnecessarily high abatement
costs on the economy if the plants continue to operate.
NRDC has examined the greenhouse gas emissions from a wide variety
of feedstock and conversion process combinations using the Argonne
GREET model (see figure 1* and Appendix 1). EPA conducted a similar
analysis for a factsheet released in conjunction with its final rule
for implementing the Renewable Fuels Standard enacted in EPACT
2005.\14\ EPA's results are shown in Figure 2 and are very similar to
ours (note that EPA displays results relative to conventional diesel
gasoline, which is set to zero on their chart). Most recently Argonne
National Laboratory scientist released a new analysis using their GREET
model to assess the life-cycle greenhouse gas emissions of Fischer-
Tropsch diesel products from natural gas, coal and biomass (see figure
3).\15\ Again their results are similar to ours. They find that liquid
coal without carbon capture and disposal can emit from 2.2 to 2.5 times
more greenhouse gases than the equivalent gallon of petroleum-based
diesel fuel. And even with carbon capture and disposal the life-cycle
emissions are still 1.19-1.25 times higher.
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* Figures 1-5 have been retained in committee files.
\14\ http://www.epa.gov/otaq/renewablefuels/420f07035.htm
\15\ M. Wang, M. Wu, H. Huo, ``Life-cycle energy and greenhouse gas
results of Fischer-Tropsch diesel produced from natural gas, coal, and
biomass,'' Center for Transportation Research, Argonne National
laboratory, presented at 2007 SAE Government/Industry meeting,
Washington, DC, May 2007.
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From these charts we can clearly see that there are much more
environmentally friendly methods for producing transportation fuels.
Biofuels are an obvious alternative, which has gotten a lot of
attention recently, and about which NRDC recently testified before the
committee.\16\ Another alternative transportation fuel that is worthy
of note is electricity used in plug-in hybrid electric vehicles. If
coal is to be used to replace gasoline, generating electricity for use
in plug-in hybrid vehicles (PHEVs) can be far more efficient and
cleaner than making liquid fuels. In fact, a ton of coal used to
generate electricity used in a PHEV will displace more than twice as
much oil as using the same coal to make liquid fuels, even using
optimistic assumptions about the conversion efficiency of liquid coal
plants.\17\ The difference in CO2 emissions is even more
dramatic. Liquid coal produced with CCS and used in a hybrid vehicle
would still result in lifecycle greenhouse gas emissions of
approximately 330 grams/mile, or ten times as much as the 33 grams/mile
that could be achieve by a PHEV operating on electricity generated in a
coal-fired power plant equipped with CCS.\18\ GM has recently announced
plans to commercialize plug-in hybrid electric vehicles.
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\16\ Daniel Lashof, Testimony on S.987, the Biofuels for Energy
Security and Transportation Act of 2007 before the Senate Energy and
Natural Resources Committee, April 12, 2007. http://docs.nrdc.org/
globalwarming/glo_07041201A.pdf.
\17\ Assumes production of 84 gallons of liquid fuel per ton of
coal, based on the National Coal Council report. Vehicle efficiency is
assumed to be 37.1 miles/gallon on liquid fuel and 3.14 miles/kWh on
electricity.
\18\ Assumes lifecycle greenhouse gas emission from liquid coal of
27.3 lbs/gallon and lifecycle greenhouse gas emissions from an IGCC
power plant with CCS of 106 grams/kWh, based on R. Williams et al.,
paper presented to GHGT-8 Conference, June 2006.
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Simply put, liquid coal is highly unlikely to be compatible with
long-term climate protection. A recent analysis by Jim Dooley of
Battelle National Laboratory shows that liquid coal is not part of an
energy system that is consistent with stabilizing greenhouse gas
concentrations at or below 450ppm. (see figure 4).\19\ Furthermore,
using high-carbon fuels for transportation means we would have to do
that much more in improving other areas of transportation, such as
increased vehicle efficiency and reduced vehicle miles traveled. The
Administration's alternative fuels proposal highlights this fact. If
half of the alternative fuels mandate proposed by the administration
were satisfied with coal-derived liquid fuels then CO2
emissions would be 175 million tons higher in 2017 than the
administration's target. To offset this increase through automobile
fuel efficiency standards would have to increase by 8.6 percent per
year, rather than the 4 percent per year as suggested by the
administration.
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\19\ Jim Dooley, Robert Dahowski, Marshall Wise, Casie Davidson
``Coal-to-Liquids and Advanced Low-Emissions Coal-fired Electricity
Generation,'' presentation at NETL conference, May 9, 2007, PNWD-SA-
7804.
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With liquid coal proposals proliferating in Congress it is critical
to evaluate the environmental ramifications of these proposals. In
particular, recently offered before the Senate Energy and Natural
Resources committee during their May 2, 2007 energy legislation markup
was an amendment co-authored by Senators Thomas and Bunning mandating
21 billion gallons of liquid coal synfuels per year by 2022.
Producing 21 billion gallons of liquid coal synfuels per year would
require building up to 40 new medium sized (35,000 barrels/day) liquid
coal plants. This in turn would:
Increase global warming pollution by almost 600 million
metric tons CO2 per year. Even with carbon capture
and disposal CO2 emissions are still higher than
conventional fuels, and while cofiring with biomass with carbon
capture and disposal can produce diesel fuels with life-cycle
emissions below conventional diesel fuels, this technology is
still in the development stages.
Create water shortages in the West by requiring an
additional 100 billion gallons of water usage per year, the
equivalent of 375 empire state buildings of water per year. One
gallon of liquid coal requires five gallons of water to
produce. It is expected that many of the forty new coal plants
required to produce this fuel would be built in the West where
water shortages are already a severe problem.
Scar the landscape by requiring 250 million additional tons
of coal, a 23% increase in coal mining compared to 2006 coal
mining production. This increase would have severe impacts on
our land, air and water.
While Senators Thomas and Bunning have acknowledged the importance
of global warming pollution by requiring that emissions from liquid
coal synfuels not exceed those from conventional gasoline we need to be
doing much better than that to meet the emission reductions that will
be necessary from the transportation sector (see figure 4).
Synthetic Gas
Another area that has received interest is coal gasification to
produce synthetic natural gas as a direct method of supplementing our
natural gas supply from domestic resources. However, without
CO2 capture and disposal this process results in more than
twice as much CO2 per 1000 cubic feet of natural gas
consumed compared to conventional resources.\20\ From a global warming
perspective this is unacceptable. With capture and disposal the
CO2 emissions can be substantially reduced, but still remain
12 percent higher than natural gas.
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\20\ The National Coal Council, ``Coal: America's Energy Future,''
March 22, 2006. This report actually assumes a less efficient coal to
synthetic gas conversion process of 50% leading to three times as much
CO2 per 1000 cubic feet of natural gas consumed compared to
conventional resources.
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In Beulah, North Dakota the Basin Electric owned Dakota
Gasification Company's Great Plains Synfuels Plant is a 900MW facility
which gasifies coal to produce synthetic ``natural'' gas. It can
produce 150 million cubic feet of synthetic gas per day and 11,000 tons
of CO2 per day. However, it no longer releases all of its
CO2 to the atmosphere, but captures most of it and pipes it
200 miles to an oil field near Weyburn, Saskatchewan. There the
CO2 is pumped underground into an aging oil field to recover
more oil. EnCana, operator of this oil field, pays $2.5 million per
month for the CO2. They expect to sequester 20 million tons
of CO2 over the lifetime of this injection project.
A potential use for coal-produced synthetic gas would be to burn it
in a gas turbine at another site for electricity generation. This
approach would result in substantially higher CO2 emissions
than producing electricity in an integrated system at the coal
gasification plant with CO2 capture at the site (i.e., in an
IGCC plant with carbon capture and disposal). Coal produced synthetic
natural gas could also be used directly for home heating. As a
distributed source of emissions the CO2 would be prohibitive
to capture with known technology.
Before producing synthetic pipeline gas from coal a careful
assessment of the full fuel cycle emissions against the baseline and
alternatives and the emission reductions that are required from that
sector must be carried out before decisions are made to invest in these
systems.
Chemical Products
The chemical industry has also been looking carefully at coal
gasification technology as a way to replace the natural gas feedstock
used in chemical production. The motivator has been the escalating and
volatile costs of natural gas in the last few years. A notable example
in the U.S. of such a use is the Tennessee Eastman plant, which has
been operating for more than 20 years using coal instead of natural gas
to make chemicals and industrial feedstocks. If natural gas is replaced
by coal gasification as a feedstock for the chemical industry, first
and foremost CO2 capture and disposal must be an integral
part of such plants. In this case, the net global warming emissions
will change relatively little from this sector compared to the
conventional natural gas based process. Steam reforming of natural gas,
however, could also potentially capture its emissions too, resulting in
even lower emissions. Therefore, before such a transformation occurs
with coal as a feedstock, a careful analysis of the entire life cycle
emissions needs to be carried out against the baseline and
alternatives, along with an assessment of how future emissions
reductions from this sector can be most effectively accomplished.
Conventional Air Pollution
Dramatic reductions in power plant emissions of criteria
pollutants, toxic compounds, and global warming emissions are essential
if coal is to remain a viable energy resource for the 21st Century.
Such reductions are achievable in integrated gasification combined
cycle (IGCC) systems, which enable cost-effective advanced pollution
controls that can yield extremely low criteria pollutant and mercury
emission rates and facilitates carbon dioxide capture and geologic
disposal. Gasifying coal at high pressure facilitates removal of
pollutants that would otherwise be released into the air such that
these pollutant emissions are well below those from conventional
pulverized coal power plants with post combustion cleanup.
Conventional air emissions from coal-to-liquids plants include
sulfur oxides, nitrogen oxides, particulate matter, mercury and other
hazardous metals and organics. While it appears that technologies exist
to achieve high levels of control for all or most of these pollutants,
the operating experience of coal-to-liquids plants in South Africa
demonstrates that coal-to-liquids plants are not inherently ``clean.''
If such plants are to operate with minimum emissions of conventional
pollutants, performance standards will need to be written--standards
that do not exist today in the U.S. as far as we are aware.
In addition, the various federal emission cap programs now in force
would apply to few, if any, coal-to-liquids plants.\21\
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\21\ The sulfur and nitrogen caps in EPA's ``Clean Air Interstate
Rule'' (``CAIR'') may cover emissions from coal-toliquids plants built
in the eastern states covered by the rule but would not apply to plants
built in the western states. Neither the national ``acid rain'' caps
nor EPA's mercury rule would apply to coal-to-liquids plants.
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Thus, we cannot say today that coal-to-liquids plants will be
required to meet stringent emission performance standards adequate to
prevent either significant localized impacts or regional emissions
impacts.
Mining, Processing and Transporting Coal
The impacts of mining, processing, and transporting 1.1 billion
tons of coal today on health, landscapes, and water are large. To
understand the implications of continuing our current level of as well
as expanding coal production, it is important to have a detailed
understanding of the impacts from today's level of coal production. It
is clear that we must find more effective ways to reduce the impacts of
mining, processing and transporting coal before we follow a path that
would result in even larger amounts of coal production and
transportation.
the path forward: an action plan to reduce u.s. global warming
pollution
The United Nations Framework Convention on Climate Change (UNFCCC)
establishes the objective of preventing ``dangerous anthropogenic
interference with the climate system.'' While a ``non-dangerous''
concentration level has not been defined under the UNFCCC and is not a
purely scientific concept, the European Union has set a goal of
avoiding an increase of more than 2 degrees Celsius from pre-industrial
levels in order to avoid the most dangerous changes to climate. We
believe this is a sound goal and U.S. emission reduction policies
should have a similar objective.
To prevent dangerous global warming while allowing for a reasonable
transition in developing nations, the U.S. needs to start to cut global
warming pollution as soon as possible and keep steadily reducing
emissions over time. Specifically, U.S. emissions in 2020 should be at
least 15-20% below current levels.\22\ By mid-century, U.S. emissions
need to be reduced on the order of 80 percent. A variety of existing
technologies can be deployed to achieve these goals--and, in addition,
the right policies will spur investment and innovation to create new
fuels and technologies. By solving this smartly, we can create jobs and
improve our standard of living even as we tackle this dangerous
problem.
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\22\ 15% below 2005 levels is equivalent to 1990 levels, and is
also equivalent to approximately 35% below businessas-usual levels for
2020. The Sander-Boxer Global Warming Pollution Reduction Act, S. 309,
meets these emission reduction goals.
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A valuable framework in which to visualize a long-term emissions
reductions pathway is through the ``wedges'' analysis pioneered by
Professors Robert Socolow and Steve Pacala at Princeton University.\23\
NRDC has modified their study, which analyzed global emission reduction
pathways, to consider potential U.S. emission reduction pathways.
---------------------------------------------------------------------------
\23\ S. Pacala and R. Socolow, ``Stabilization Wedges: Solving the
Climate Problem for the Next 50 Years with Current Technologies,''
Science, v. 305, p. 968 (2004).
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The structure of our analysis is a detailed extension of the
Socolow-Pacala concept of emission reduction ``stabilization wedges''
decreases in emissions in measurable increments from a business as
usual projection attributable to specific technologies. These wedge
increments can then be summed up in various ways (as ``paths'') to the
desired emission reduction total (See figure 5).
NRDC used a spreadsheet model developed by Kuuskraa et al. to
examine U.S. emissions scenarios out to 2050.\24\ This analysis
segregates the wedges into four sectors: electricity, transportation,
stationary end-use fuel combustion, and non-CO2 gases. This
segregation helps to avoid double counting different measure so as to
develop self-consistent scenarios for the U.S. energy system (for
example, taking credit for reducing the demand of electricity from
appliances while at the same time reducing emissions at power plants
that supply the power).
---------------------------------------------------------------------------
\24\ V. Kuuskraa, P. Dipietro, S. Klara, S. Forbes, ``Future U.S.
Greenhouse Gas Emission Reduction Scenarios Consistent with Atmospheric
Stabilization Concentrations,'' GHGT-7, .506 (2004).
---------------------------------------------------------------------------
Their spreadsheet model is used here to construct an emissions
scenario consistent with the U.S. carbon budget that meets an 80
percent reduction below 1990 levels by 2050 using technologies that are
likely to be available and affordable during that timeframe. In this
scenario the largest reductions are obtained from energy efficiency
improvements in electrical end uses, non-electric stationary end uses,
and motor vehicles. Additional reductions come from renewable fuels and
electricity and carbon capture and disposal at coal-fired power plants
and other high-concentration industrial CO2 vents. The
elements of this scenario are briefly outlined below.
Electricity (first 3 wedges)--The U.S. gets just over half of its
electricity from coal, about a fifth from nuclear power, and the
balance mainly from natural gas and renewable energy sources. Natural
gas is considered limited by supply and price constraints and
hydroelectric power, the dominant renewable resource, is limited by the
fact that the best available sites have already been dammed. In
addition, the expansion of nuclear power continues to hit a variety of
impediments. Therefore, for the electricity sector we assume:
High levels of efficiency in end-use consumption and supply
production and distribution to meet growing energy needs,
thereby reducing the need to construct new baseload power
plants while expanding renewable energy sources.
--40% of electricity (1600 Billion kWh) is generated from non-hydro
renewables: Wind, geothermal, solar thermal, PV, and
biomass (coproduced with biofuels).
Building some coal plants with geologic carbon dioxide
disposal to replace existing coal-fired plants as they reach
retirement age.
--16% of electricity (660 Billion kWh) is generated from coal with
carbon capture and geologic disposal.
Nuclear would remain roughly the same proportion of
electricity that it does currently.
Transportation (second 3 wedges)--Controlling emission from the
burning of oil by the transportation sector requires a combination of
reducing the number of miles people drive in their cars and other
vehicles (Vehicle Miles Traveled or VMT), the efficiency of those
vehicles in consuming as little fuel as possible, and the using low-
carbon fuels. The low-carbon fuels wedge assumes that there will be
adequate environmental protections for the production of these fuels,
while at the same time promoting maximum efficiency and electrification
of the vehicle fleet.
The scenario analyzed assumes:
New vehicle fuel efficiency triples by 2050 and VMT is
reduced by 20% through smart growth policies.
--New vehicle fuel efficiency is 3 times current level by 2050. On
road fleet average 55 mpg.
Of the remaining fuel demand, 45% is satisfied with
electricity used in plug-in hybrid vehicles and 40% is
satisfied by biofuels, such that biofuels displace 36 billion
gallons of gasoline equivalent in 2050.\25\
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\25\ Assuming that about half of corn stover can be collected for
energy use (200 million tons of waste material altogether), 22 million
acres would have to be dedicated to energy crop production.
Biological Sequestration and Other--There is a wedge that allows
for a small amount of carbon dioxide to be absorbed by biological
sources. While we do not support an over reliance on biological
sequestration, because of a lack of reliability of such a mechanism,
some biological sequestration is likely to occur. The other efficiency
wedge incorporates efficiency improvements made in direct fuel demand
by stationary sources and the other renewables wedge comes from
renewables supplying 30 percent of other stationary source energy
demand. Finally, there are other unidentified reduction opportunities,
including international emissions trading.
This analysis clearly shows how we can meet the required emission
reduction targets through the deployment of a wide variety of low-
carbon technologies in multiple sectors of the economy over the next
four decades. It is also clear that liquid coal is not compatible with
this visions and would require the expansion of other low-carbon wedges
to cover its emissions profile. Coal gasification for electricity
production is consistent and integrated into the analysis. Further
analysis is needed to assess whether the use of coal gasification for
other products such as synthetic natural gas or chemicals would be at
odds with the necessary reduction pathway.
conclusion
The impacts that a large coal gasification program could have on
global warming pollution, conventional air pollution and environmental
damage resulting from the mining, processing and transportation of the
coal are substantial. Before deciding whether to invest scores, perhaps
hundreds of billions of dollars in deploying this technology, we must
have a program to manage our global warming pollution and other coal
related impacts. Otherwise we will not be developing and deploying an
optimal energy system.
One of the primary motivators for pushing coal gasification
technologies has been to reduce natural gas prices. Fortunately, the
U.S. can have a robust and effective program to reduce natural gas
demand, and therefore prices, without rushing to embrace coal
gasification technologies. A combination of efficiency and renewables
can reduce our natural gas demand more quickly and more cleanly.
The other major motivator for the push to use coal gasification is
to produce liquid fuels to reduce our oil dependence. The U.S. can have
a robust and effective program to reduce oil dependence without rushing
into an embrace of liquid coal technologies. A combination of more
efficient cars, trucks and planes, biofuels, and ``smart growth''
transportation options outlined above and in the report ``Securing
America,'' produced by NRDC and the Institute for the Analysis of
Global Security, which shows how to cut oil dependence by more than 3
million barrels a day in 10 years, and achieve cuts of more than 11
million barrels a day by 2025.
To reduce our dependence on natural gas and oil we should follow a
simple rule: start with the measures that will produce the quickest,
cleanest and least expensive reductions in natural gas and oil use;
measures that will put us on track to achieve the reductions in global
warming emissions we need to protect the climate. If we are thoughtful
about the actions we take, our country can pursue an energy path that
enhances our security, our economy, and our environment.
With current coal and oil consumption trends, we are headed for a
doubling of CO2 concentrations by mid-century if we don't
redirect energy investments away from carbon based fuels and toward new
climate friendly energy technologies. We have to accelerate the
progress underway and adopt policies in the next few years to turn the
corner on our global warming emissions, if we are to avoid locking
ourselves and future generations into a dangerously disrupted climate.
Scientists are very concerned that we are very near this threshold now.
Most say we must keep atmosphere concentrations of CO2 below
450 parts per million, which would keep total warming below 2 degrees
Celsius (3.6 degrees Fahrenheit). Beyond this point we risk severe
impacts, including the irreversible collapse of the Greenland Ice Sheet
and dramatic sea level rise. With CO2 concentrations now
rising at a rate of 1.5 to 2 parts per million per year, we will pass
the 450ppm threshold within two or three decades unless we change
course soon.
In the United States, a national program to limit carbon dioxide
emissions must be enacted soon to create the market incentives
necessary to shift investment into the least-polluting energy
technologies on the scale and timetable that is needed. There is
growing agreement between business and policy experts that quantifiable
and enforceable limits on global warming emissions are needed and
inevitable.\26\ To ensure the most cost-effective reductions are made,
these limits can then be allocated to major pollution sources and
traded between companies, as is currently the practice with sulfur
emissions that cause acid rain. Further complimentary and targeted
energy efficiency and renewable energy policies are critical to
achieving CO2 limits at the lowest possible cost, but they
are no substitute for explicit caps on emissions.
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\26\ U.S. Climate Action Partnership, http://www.us-cap.org.
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A coal integrated gasification combined cycle (IGCC) power plant
with carbon capture and disposal can also be part of a sustainable path
that reduces both natural gas demand and global warming emissions in
the electricity sector. Methods to capture CO2 from coal
gasification plants are commercially demonstrated, as is the injection
of CO2 into geologic formations for disposal.\27\ On the
other hand, coal gasification to produce a significant amount of
liquids for transportation fuel would not be compatible with the need
to develop a low-CO2 emitting transportation sector.
Finally, gasifying coal to produce synthetic pipeline gas or chemical
products needs a careful assessment of the full life cycle emission
implications and the emission reductions that are required from those
sectors before decisions are made to invest in these practices.
---------------------------------------------------------------------------
\27\ David Hawkins, Testimony on S. 731 and S. 962: Carbon Capture
and Sequestration before the Senate Energy and Natural Resources
Committee, April 16, 2007. http://docs.nrdc.org/globalwarming/
glo_07041601A.pdf.
The Chairman. All right. Thank you very much. That's very
useful.
Mr. Fulkerson, go right ahead.
STATEMENT OF WILLIAM FULKERSON, SENIOR FELLOW, INSTITUTE FOR A
SECURE AND SUSTAINABLE ENVIRONMENT, UNIVERSITY OF TENNESSEE,
KNOXVILLE, TN
Mr. Fulkerson. Mr. Chairman and members of the committee, I
am very pleased to have been invited to testify at this hearing
on coal gasification, synfuels, and related topics.
What I'm going to say today derives mostly from what I
consider to be the brilliant work of Bob Williams and his
colleagues at Princeton University. I'm pinch-hitting for Bob
today, since he is lecturing in China right now.
The story Bob would have told you, however, I think is
extremely important for the committee's deliberations. So,
maybe my pinch-hitting, no matter how bad it is, is warranted.
Let me give you a little background. Since retiring from
the Oak Ridge National Laboratory in 1994, I have had the
privilege of chairing a committee of people from 14 DOE
National Labs, which we call the Laboratory Energy R&D Working
Group, or LERDWG. We meet several times a year in Washington to
talk about energy R&D policy, and about what's new and exciting
in energy science and technology. At the April meeting of our
group, Bob Williams talked about his idea for coal biomass
gasification in a complex producing gasoline and diesel fuels
via the Fischer-Tropsch synthesis process, as well as coal
production of electricity and the sequestration of excess
CO2 produced. This idea addresses the coupled
problems that everybody has said already of oil security, or
oil dependence, and climate change mitigation. I call this
scheme biocoal fuels.
By carefully matching the feedstocks of biomass and coal in
this process, and capturing and storing the excess
CO2, sufficient CO2 can be captured to
offset the carbon in the product fuels that you produce--
conventional, diesel, and gasoline--and that's a big idea.
That's a big idea.
Why does that work? Well, it works, because most of the
carbon in the biomass is sequestered. That's a net negative
which offsets the emission of carbon from burning gasoline and
diesel that you produce.
Bob shows that if CO2, sequestered, has a value
greater than, let's say, about $25 per ton, which is roughly
the magnitude of the MIT report, where sequestration begins to
become economically justified, then the process can produce
competitive fuels at a competitive price, compared to
petroleum, if oil prices are greater than $50 a barrel, which
they're presently at, of course.
Another really important part of this scheme is that the
ratio of the biomass that you need--biomass energy input that
you need to produce a unit of energy fuel output is about one
or less, and that means that this process would be two or three
times--could produce two or three times as much carbon-free
fuel as, for example, cellulosic, enzymatic ethanol would
produce. Now, this remarkable result derives from the fact that
much of the energy to run the process, the overall process,
comes from coal. This means that biomass resource productivity
can be greatly expanded. In fact, Williams makes a very
interesting thought experiment. He asks, ``What fraction of the
transportation fuels from North America might his carbon-
neutral biocoal route provide?'' The answer is that all the
fuels estimated to be required by 2050, for transportation of
all sorts for North America, could be produced from the
estimated 1.3 billion tons per year of biomass potentially
available on a sustainable basis for energy, as estimated by
the Department of Energy and the United States--and the USDA.
This resource includes agricultural and forest residues,
municipal waste, as well as biomass energy crops, the latter
providing maybe 30 percent of the total resource to avoid
excessive land use.
But this can only be accomplished--as Dr. Herzog
indicated--it can only be accomplished, however, if light-duty
vehicle fleet has an average fuel efficiency of about 60 miles
per gallon. I drove up in my Prius car, and I only got, well,
close to 50 miles per gallon. So, can we get 60, on average, by
2050? That's the question. So, that's one requirement.
Also, such a huge syn-fuels thing, which, of course, is
much bigger would double the current use of coal. But we're
pretty rich in coal, if we can just solve the other
environmental problems associated with increased use.
Well, this is a rough summary of Bob Williams' great idea.
I understand that he will submit written testimony to the
committee to supply the details.
The scheme depends, of course, on sequestered
CO2 having a value--and that's up to you guys--and
sequestration working at a large scale.
Finally, in my written testimony, I list six policies
suggested by Williams that I believe could encourage innovation
in developing solutions to our coupled problems of oil
dependence and climate change mitigation. The policies are
designed to be largely technology-neutral to avoid picking
winners. Of course, it's easy to make such a list. The hard
work comes from sorting out the many options so that policies
are effective, and that they're fair, and that they're
politically possible. And I think that's your job, and it's a
difficult one, and I don't envy you at all. But it is so
important that you take on the challenge. And I'm glad to see
you're doing it.
[The prepared statement of Mr. Fulkerson follows:]
Prepared Statement of William Fulkerson, Senior Fellow, Institute for a
Secure and Sustainable Environment, University of Tennessee, Knoxville,
TN
Mr. Chairman and Members of the Committee, I am pleased to have
been asked to testify at this hearing on coal gasification, synfuels
and related topics. What I will say today derives mostly from the
brilliant work of Bob Williams and his colleagues at Princeton
University. I am pinch-hitting for Bob since he is lecturing in China
today. What Bob and his colleagues have concluded from their analysis
is very important to the issues being considered by this Committee. I
believe he is right else I wouldn't be here.
Since retiring from the Oak Ridge National Laboratory in 1994 I
have had the pleasure of chairing a committee of people from 14 DOE
national laboratories. It is called the Laboratory Energy R&D Working
Group or LERDWG. We meet several times a year in Washington to talk
about energy R&D policy and about what is new and exciting in energy
science and technology. In fact staff from this Committee often come to
our meetings.
At our April meeting Bob Williams talked to us about his idea for a
coal/biomass gasification complex producing gasoline and Diesel fuel
via Fisher-Tropsch synthesis as well as co-production of electricity.
Bob is interested in addressing the coupled challenges of oil security
and climate change mitigation. Of course, liquid fuels from coal can be
produced using oxygen blown gasification and Fisher-Tropsch, but this
will result in about twice the amount of CO2 vented compared
to producing the same quantity of fuels from petroleum. If petroleum
costs $50/bbl or more this synfuels process can be competitive. If the
excess CO2 produced is sequestered instead of vented then
the coal synfuels process can be equivalent to petroleum in net
CO2 emissions.
But Williams points out we can do much better than petroleum if we
gasify biomass with the coal in the same facility, and if the excess
CO2 produced is captured and stored in deep saline aquifers
or is used for enhanced oil recovery from depleted oil reservoirs. In
fact, the CO2 captured and stored can be sufficient to
offset the carbon in the fuel product so that the overall system
including the carbon released by burning of the fuel produced can be a
net zero in emissions. This is because most of the carbon in the
biomass is captured as CO2 and is sequestered offsetting the
carbon released in product fuel burning. Of course the carbon in the
biomass is extracted from the air during its growing. Burning the fuel
produced merely returns carbon to the atmosphere from whence it came,
and the cycle is completed with no net additions to the atmosphere. So,
Bob shows that if CO2 sequestered has a value of greater
than $25/t the process can be competitive with fuels derived from
petroleum if petroleum costs more than $50/bbl.
Another important feature of this scheme is that the ratio of
biomass energy input to product fuel energy output is of the order of
unity. This means that 2-3 times as much fuel can be produced per unit
of biomass energy as from the cellulosic ethanol enzymatic process, for
example. This remarkable result derives from the fact that much of the
energy to run the process comes from coal. This means that the biomass
resource productivity can be greatly expanded.
The productivity can be pushed even further by using mixed prairie
grasses grown on carbon deficient soils as suggested in the recent
paper in Science Magazine (Tilman, D., et al, Science, 314, 1598-1600,
8 Dec. 2006). These researchers from the University of Minnesota found
that mixed prairie grasses sequestered up to 0.6 kg of carbon in roots
and soil per kg of prairie grass harvested and this can happen year
after year since the grasses are perennials. Using mixed prairie grass
as the biomass feedstock in the process requires only about 0.6 GJ of
biomass per GJ of product fuel is required. This biomass productivity
is most important because the biomass resource is limited.
Williams makes a very interesting thought experiment. He asks what
fraction of the transportation fuels for North America can his coal/
biomass/sequestration route provide. The answer is that all fuels
estimated to be required by 2050 for transportation of all sorts could
be produced from the estimated 1.3 B tones per year of biomass
potentially available on a sustainable basis as estimated by DOE and
USDA. This resource includes agricultural and forest residues and
municipal waste as well as biomass energy crops. The latter provides
only about 30% of the total resource. This can only be accomplished,
however, if the light duty vehicle fleet has an average fuel efficiency
of 60 mpg or greater by 2050, not an impossible target. Also, such a
synfuels enterprise would double current use of coal.
This is a rough summary of Bob Williams great idea. I understand
that he will submit written testimony to the Committee to supply
details. He has done very elaborate and detailed calculations for many
variations on his theme.
Finally, here is a set of policies suggested by Williams that I
believe could encourage innovation in developing solutions to the
coupled problems of oil security and climate change mitigation. The
policies are designed to be largely technology independent to avoid
picking winners.
First, the greenhouse gas emission externality must be reduced by
putting a cost on emissions by cap and trade or tax or whatever. The
Congress through various pieces of legislation is actively considering
this, and no doubt something will emerge.
Second, a low-carbon fuel standard such as is being developed by
the State of California should be adopted and existing subsidies on low
carbon fuels should be discontinued.
Third, regulations should be adopted to assure that no new coal
synfuels plants are built without carbon capture and storage.
Fourth, an oil security feebate might be enacted to put a floor on
transportation fuel prices. If oil prices crash, say to $30/bbl from
$60, transportation fuel could be taxed and part of the tax rebated to
synfuels plants to help them compete and produce even with low world
oil prices. Part of the tax revenues could be returned to the public.
Fifth, regulations (such as improved CAFE standards) to promote
more efficient use of transportation fuels need to be aggressively
strengthened over time.
Sixth, regulations and R&D to improve coalmine safety, worker
health, and environmental improvement need to be periodically reviewed
and upgraded if necessary.
Of course it is easy to make such a list. The hard work comes in
sorting out the many options so policies are effective, fair and
politically possible. I think that is your job, and it is a difficult
one.
The Chairman. Thank you very much for your testimony.
Mr. Bartis, go right ahead.
STATEMENT OF JAMES BARTIS, SENIOR POLICY RESEARCHER, RAND
CORPORATION, ARLINGTON, VA
Mr. Bartis. Mr. Chairman and distinguished members, thank
you for inviting me to testify. My remarks today are based on
RAND research, some of which is ongoing, sponsored by the
National Energy Technology Laboratory, the United States Air
Force, the Federal Aviation Administration, and the National
Commission on Energy Policy.
Congress has before it the two major energy challenges:
first, what to do about large well transfers from oil consumers
to OPEC; and second, how can we reduce our greenhouse gas
emissions?
OPEC revenues from oil exports are currently about $500
billion per year, and are heading higher. These high revenues
raise serious national security concerns because some of the
OPEC member states are governed by regimes that are not
supportive of U.S. foreign policy objectives. Oil revenues have
been, and are being, used to purchase weapons. Moreover, the
higher oil prices rise, the greater the chances that oil
importing countries will pursue special relationships with oil
exporters and defer joining the United States in multilateral
diplomatic efforts. We see this happening right now in South
America and Africa.
No less pressing is the importance of addressing the threat
of global climate change. For example, as you just heard,
without measures to address carbon dioxide emissions, the use
of coal-derived liquids to displace petroleum fuels for
transportation will roughly double greenhouse gas emissions.
This is clearly not acceptable.
The emphasis of RAND's research on unconventional fuels has
been on these two potentially conflicting policy objectives. We
have concentrated our efforts on coal-to-liquids because that
option is one of the only two approaches that are commercially
ready and capable of displacing significant amounts of imported
petroleum. The only other technical option that meets these
criteria is ethanol production from food crops. Moreover, only
the coal-to-liquids approach produces a fuel suitable for use
in heavy-duty trucks, railroad engines, commercial aircraft, or
military vehicles and weapons systems.
When we look to the future, the only near-term, low-risk
option beyond the two I just mentioned is a variance of the
same technology that is used for producing liquids from coal;
namely, gasification, in Fischer-Tropsch synthesis, as applied
to biomass, such as crop residues or a combination of biomass
and coal, as just discussed by Mr. Fulkerson.
Producing large amounts of coal-derived liquid fuels will
cause world oil prices to decrease. Our research shows that,
under reasonable assumptions, this price reduction effect could
be very large and would likely result in large benefits to U.S.
consumers and large decreases in OPEC revenues. Savings by the
average household in the United States would range from a few
hundred to a few thousand dollars per year. OPEC export
revenues could decrease by hundreds of billions of dollars per
year.
We also examined whether a coal-to-liquids industry can be
developed consistent with the need to manage carbon dioxide
emissions. If we are willing to accept emission levels that are
similar to those associated with conventional petroleum, the
answer is definitely yes.
Two technical approaches are available that allow this
level of control: the first involves the capture and geological
sequestration of carbon dioxide at the plant site. This
approach appears feasible, but it has not been proven, and it
will not be proven until multiple large-scale demonstrations
are successfully conducted, and fortunately, the second
approach is a very low-risk approach; namely, using a
combination of coal and biomass, as you just heard, in a
Fischer-Tropsch plant. Now, given the large demand on OPEC oil
that we anticipate over the next 50 years, this is a great
answer. We can at least address a major economic and national
security problem while not worsening environmental impacts.
If, however, we demand a significant reduction in emission
levels, as compared to conventional petroleum, the answer is a
qualified yes. The only way we know of reaching this level of
carbon dioxide control when making coal-derived liquids is to
use the combination of coal and biomass, and to capture and
sequester most of the carbon dioxide generated at the plant
site. The reason I give a qualified yes is that there does
remain considerable uncertainty regarding the viability of
sequestering carbon dioxide in geological formations.
Stepping back a bit, we have, at RAND, reviewed the
prospects of coal-to-liquids production in the United States,
and we see three major uncertainties that are impeding private-
sector investment.
The first uncertainty centers on the cost and performance
of coal-to-liquid plants. Our current best estimate is that
coal-to-liquids production is not competitive unless crude oil
prices are in the range of $50 to $60 per barrel. However, this
estimate is based on highly conceptual engineering designs that
are only intended to provide a rough estimate of costs. At
RAND, we have learned that, when it comes to cost estimates, it
is often the case that the less you know, the more attractive
the course.
The second uncertainty concerns the future direction of
world oil prices. The third uncertainty, I've already touched
upon is namely, whether, and how greenhouse gas emissions might
be controlled in the United States.
Just as these three uncertainties are impeding private
sector investment, they should also deter an immediate national
commitment to rapidly put in place a multimillion-barrel-per-
day coal-to-liquids industry. However, the traditional hands-
off, or research-only, approach is not commensurate with the
continuing adverse economic, national security, and global
environmental consequences of relying on imported petroleum.
For these reasons, Congress should consider a middle path that
focuses on reducing uncertainties and fostering early
commercial experience by: No. 1, providing Federal cost-sharing
of front-end engineering designs for a few commercial plants;
and No. 2, promoting the construction and operations of a
limited number of commercial-scale plants by establishing a
flexible incentive program capable of attracting the
participation of America's top technology firms. We
characterize this middle path as an insurance strategy, since,
for modest payments, it significantly improves the ability of
the private sector to respond officially to future market
developments as both government and industry learn more about
the future course of world oil prices and as the policy and
technical mechanisms for carbon management become clearer.
Thank you very much.
[The prepared statement of Mr. Bartis follows:]
Prepared Statement of James T. Bartis,\1\ Senior Policy Researcher,
RAND Corporation, Arlington, VA
Policy Issues for coal-to-Liquid Development\2\
Chairman and distinguished Members: Thank you for inviting me to
speak on the potential use of our nation's coal resources to produce
liquid fuels. I am a Senior Policy Researcher at the RAND Corporation
with over 25 years of experience in analyzing and assessing energy
technology and policy issues. At RAND, I am actively involved in
research directed at understanding the costs and benefits associated
with alternative approaches for promoting the use of coal and other
domestically abundant resources, such as oil shale and biomass, to
lessen our nation's dependence on imported petroleum. Various aspects
of this work are sponsored and funded by the National Energy Technology
Laboratory (NETL) of the U.S. Department of Energy, the United States
Air Force, the Federal Aviation Administration, and the National
Commission on Energy Policy.
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\1\ The opinions and conclusions expressed in this testimony are
the author's alone and should not be interpreted as representing those
of RAND or any of the sponsors of its research. This product is part of
the RAND Corporation testimony series. RAND testimonies record
testimony presented by RAND associates to federal, state, or local
legislative committees; government-appointed commissions and panels;
and private review and oversight bodies. The RAND Corporation is a
nonprofit research organization providing objective analysis and
effective solutions that address the challenges facing the public and
private sectors around the world. RAND's publications do not
necessarily reflect the opinions of its research clients and sponsors.
\2\ This testimony is available for free download at http://
www.rand.org/pubs/testimonies/CT281.
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Today, I will discuss the key problems and policy issues associated
with developing a domestic coal-to-liquids industry and the approaches
Congress can take to address these issues. My key conclusions are as
follows. First, successfully developing a coal-to-liquids industry in
the United States would bring significant economic and national
security benefits by reducing wealth transfers to oil-exporting
nations. Second, the production of petroleum substitutes from coal may
cause a significant increase in carbon dioxide emissions; however,
technical approaches exist that could lower carbon dioxide emissions to
levels well below those associated with producing and using
conventional petroleum. Third, without federal assistance, private-
sector investment in coal-toliquids production plants is unlikely to
occur, because of uncertainties about the future of world oil prices,
the costs and performance of initial commercial plants, and the
viability of carbon management options. Finally, a federal program
directed at reducing these uncertainties and obtaining early, but
limited, commercial experience appears to offer the greatest strategic
benefits, given both economic and national security benefits and the
uncertainties associated witheconomic viability and environmental
performance, most notably the control of greenhouse gas emissions.
Some of the topics I will be discussing today are supported by
research that RAND has only recently completed; consequently, the
results have not yet undergone the thorough internal and peer reviews
that typify RAND research reports. Out of respect for this Committee
and the sponsors of this research, and in compliance with RAND's core
values, I will only present findings in which RAND and I have full
confidence at this time.
Coal Gasification and Liquid Fuels Production
There are two major approaches for using coal to produce liquid
transportation fuels: direct liquefaction and the Fischer-Tropsch (F-T)
processes. Both processes were developed in pre-World War II Germany
and both were used, but on fairly small scales, to meet Germany's and
Japan's wartime needs for fuel. In the direct liquefaction approach,
hydrogen is added directly to the organic structure of coal at high
pressures and temperatures. At present, a large first-of-a-kind
commercial plant based on direct liquefaction is being built in China.
Pending the completion and successful operation of that plant, we do
not anticipate that there will be industrial interest in the direct
liquefaction approach within the United States. For this reason, I will
confine my remarks to the F-T process, which is the focus of
considerable industrial interest in the United States.
In the F-T approach, coal is first gasified to produce a mixture
that consists mostly of three gases: carbon monoxide, hydrogen, and
carbon dioxide. This gas mixture is further processed to remove carbon
dioxide, as well as trace contaminants, and the resulting mixture of
clean hydrogen and carbon monoxide is sent to a chemical reactor where
the gaseous mixture is catalytically converted to liquid products.
After a moderate amount of fuel processing that would be performed on-
site, a commercial F-T plant would produce a near-zero sulfur, high-
performance diesel fuel for automotive applications and a near-zero
sulfur jet fuel that can be used for commercial aviation applications
or in military weapon systems. Between a third and one half of the
product of commercial F-T coal-to-liquid plants would be a mixture of
liquids that can be used to manufacture motor gasoline, either at the
F-T plant site or at nearby refineries.
Since the end of World War II, the only commercial experience in F-
T coal-to-liquids production has occurred in South Africa under
government subsidy. In particular, a South African plant constructed in
the early 1980s currently produces fuels and chemicals that are the
energy equivalent of about 160,000 barrels per day of oil.
An interesting feature of the F-T approach to liquid fuels
production is that it is not limited to coal. For example, large
commercial F-T plants producing liquid fuels from natural gas are
operating in Malaysia, Qatar, and South Africa. Other options are to
use biomass or a combination of coal and biomass as the feedstock
instead of straight coal. While these options are not being used on
acommercial scale, our assessment of approaches using biomass or a
combination of coal and biomass is that they involve very limited, low-
risk technology development. As I elaborate on below, these two
approaches involving biomass offer liquid fuels production and use that
entail near-zero emissions of carbon dioxide.
Technical Readiness and Production Potential
As part of RAND's examination of coal-to-liquids fuels development,
we have reviewed the technical, economic, and environmental viability
and production potential of a range of options for producing liquid
fuels from domestic resources. If we focus on unconventional fuel
technologies that are now ready for large-scale commercial production
and that can displace at least a million barrels per day of imported
oil, we find only two candidates: grain-derived ethanol and F-T coal-
toliquids. Moreover, only the F-T coal-to-liquids candidate produces a
fuel that is suitable for use in heavy-duty trucks, railroad engines,
commercial aircraft, or military vehicles and weapon systems. If we
expand our time horizon to consider technologies that might be ready
for use in initial commercial plants within the next five years, only
one or two new technologies become available: the in-situ oil shale
approaches being pursued by a number of firms and the F-T approaches
for converting biomass or a combination of coal and biomass to liquid
fuels. We have also looked carefully at the development prospects for
technologies that offer to produce alcohol fuels from sources other
than food crops, so-called cellulosic materials. Our finding is that
while this is an important area for research and development, the
technology base is not yet sufficiently developed to support an
assessment that alcohol production from cellulosic materials will be
competitive with F-T biomass-to-liquid fuels within the next ten years,
if ever.
The Strategic Benefits of Coal-to-Liquids Production
As part of RAND's examination of coal-to-liquid fuels development,
our research is addressing the strategic benefits of having in place a
mature coal-to-liquid fuels industry producing millions of barrels of
oil per day. If coal-derived liquids were added to the world oil
market, such liquids would cause world oil prices to be lower than what
would be the case if they were not produced. This effect occurs
regardless of what fuel is being considered. It holds for coal-derived
liquids and for oil shale, heavy oils, tar sands, and biomass-derived
liquids, as well as, for that matter, additional supplies of
conventional petroleum. The price reduction effect also occurs when oil
demand is reduced through fiscal measures, such as taxes on oil, or
through the introduction of advanced technologies that use less
petroleum, such as higher mileage vehicles. Moreover, this reduction in
world oil prices is independent of where such additional production or
energy conservation occurs, as long as the additional production is
outside of OPEC and OPEC-cooperating nations.
In a 2005 analysis of the strategic benefits of oil shale
development, RAND estimated that 3 million barrels per day of
additional liquid fuels production would yield a world oil price drop
of between 3 and 5 percent.\3\ Our ongoing research supports that
estimated range and shows that the price drop increases in proportion
to production increases. For instance, an increase of 6 million barrels
per day would likely yield a world oil price drop of between 6 and 10
percent. This more recent research also shows that even larger price
reductions may occur in situations in which oil markets are
particularly tight or in which OPEC is unable to enforce a profit-
optimizing response among its members.
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\3\ Oil Shale Development in the United States: Prospects and
Policy Issues, Santa Monica, CA: RAND MG414-NETL, 2005.
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This anticipated reduction in world oil prices yields important
economic benefits. In particular, American consumers would pay tens of
billions of dollars less for oil or, under some future situations,
hundreds of billions of dollars less for oil per year. On a per-
household basis, we estimate that the average annual benefit would
range from a few hundred to a few thousand dollars.
This anticipated reduction in world oil prices associated with
coal-to-liquids development also yields a major national security
benefit. At present, OPEC revenues from oil exports are about $500
billion per year. Projections of future petroleum supply and demand
published by the Department of Energy indicate that unless measures are
taken to reduce the prices of, and demand for, OPEC petroleum, such
revenues will grow considerably. These high revenues raise serious
national security concerns, because some OPEC member nations are
governed by regimes that are not supportive of U.S. foreign policy
objectives. Income from petroleum exports has been used by unfriendly
nations, such as Iran and Iraq under Saddam Hussein, to support weapons
purchases, or to develop their own industrial base for munitions
manufacture. Also, the higher prices rise, the greater the chances that
oil-importing countries will pursue special relationships with oil
exporters and defer joining the United States in multilateral
diplomatic efforts.
Our research shows that developing an unconventional fuels industry
that displaces millions of barrels of petroleum per day will cause a
significant decrease in OPEC revenues from oil exports. This decrease
results from a combination of lower prices and a lower demand for OPEC
production. The size of this reduction in OPEC revenues is determined
by the volume of unconventional fuels produced and future market
conditions, but our ongoing research indicates that annual reductions
of hundreds of billions of dollars are not unreasonable. The
significant reduction in wealth transfers to OPEC and the geopolitical
consequences of reduced demand for OPEC oil represent the major
national security benefits associated with the development of an
unconventional liquid fuels production industry.
The above-described strategic benefits derive from the existence of
the OPEC cartel. The favorable benefits of reduced oil prices accrue to
our nation as a whole; however, they are not captured by the private
firms that would invest in coal-to-liquids development.
The Direct Benefits of Coal-to-Liquids Production
Beyond the strategic benefits for the nation associated with coal-
to-liquids production are certain direct benefits. If coal-derived
liquid fuels can be produced at prices well below world oil prices,
then the private firms that invest in coal-derived liquid fuels
development could garner economic profits above and beyond what is
considered a normal return on their investments. Through taxes on these
profits and, in some cases, lease and royalty payments, we estimate
that roughly 35 percent of these economic profits could go to federal,
state, and local governments and, thereby, broadly benefit the public.
A second direct benefit derives from the broad regional dispersion
of the U.S. coal resource base and the fact that coal-to-liquids plants
are able to produce finished motor fuel products that are ready for
retail distribution. As such, developing a coal-to-liquids industry
should increase the resiliency of the overall petroleum supply chain.
The remaining direct benefits of developing a coal-to-liquids
production industry are local or regional, as opposed to national. In
particular, coal-to-liquids industrial development offers significant
opportunities for economic development and would increase employment in
coal-rich states.
Greenhouse Gas Emissions
Given the Committee's interest in greenhouse gas emissions, I limit
my remarks to that topic and simply point out that the environmental
impacts associated with certain types of coal mining and water usage
requirements, especially in the West, may limit the number of locations
at which F-T coal-to-liquid plants can be operated.
If no provisions are in place to manage carbon dioxide emissions,
then the use of F-T coal-toliquids fuels to displace petroleum fuels
for transportation uses will roughly double greenhouse gas emissions.
This finding is relevant to the total fuel lifecycle, i.e., well-to-
wheels or coal-mine-to-wheels. This increase in greenhouse gas
emissions is primarily attributable to the large amount of carbon
dioxide emissions that come from a F-T coal-to-liquids production plant
relative to a conventional oil refinery. In fact, looking solely at the
combustion of F-T derived fuel as opposed to its production, our
analyses show that combustion of an F-T coal-derived fuel would produce
somewhat, although not significantly, lower greenhouse gas emissions
relative to the combustion of a gasoline or diesel motor fuel prepared
by refining petroleum.
In our judgment, the high greenhouse gas emissions of F-T coal-to-
liquids plants that do not manage such emissions preclude their
widespread use as a means of displacing imported petroleum. We now turn
to some options for managing greenhouse gas emissions.
Options for Managing Greenhouse Gas Emissions
For managing greenhouse gas emissions for F-T coal-to-liquid
plants, RAND examined three options: (1) carbon capture and
sequestration, (2) carbon dioxide capture and use in enhanced oil
recovery, and (3) gasification of both coal and biomass followed by F-T
synthesis of liquid fuels. We discuss each below in turn.
Carbon Capture and Sequestration.--By carbon capture and
sequestration, I refer to technical approaches being developed in the
United States, primarily through funding from the U.S. Department of
Energy, and abroad that are designed to capture carbon dioxide produced
in coal-fired power plants and sequester that carbon dioxide in various
types of geological formations, such as deep saline aquifers. This same
approach can be used to capture and sequester carbon dioxide emissions
from F-T coal-to-liquids plants and from F-T plants operating on
biomass or a combination of coal and biomass. When applied to F-T coal-
to-liquids plants, carbon capture and sequestration should cause
``mine-to-wheels'' greenhouse gas emissions to drop to levels
comparable to the ``well-to-wheels'' emissions associated with
conventional petroleum-derived motor fuels. Moreover, any incentive
adequate to promote carbon capture at coal-fired power plants should be
equally, if not more, effective in promoting carbon capture at F-T
plants producing liquid fuels.
The U.S. Department of Energy program on carbon capture and
sequestration appears to be well managed and has made considerable
technical progress. However, considering the continued and growing
importance of coal for both power and liquids production and the
potential adverse impacts of greenhouse gas emissions, we believe this
program has been considerably underfunded. While we are optimistic that
carbon capture and geologic sequestration can be successfully developed
as a viable approach for carbon management, we also recognize that
successful development constitutes a major technical challenge and that
the road to success requires multiple, large-scale demonstrations that
go well beyond the current DOE plans and budget for the efforts that
are now under way.
Carbon Capture and Enhanced Oil Recovery.--In coal-to-liquids
plants, about 0.8 tons of carbon dioxide are produced along with each
barrel of liquid fuel. For coal-to-liquids plants located near
currently producing oil fields, this carbon dioxide can be used to
drive additional oil recovery. We anticipate that each ton of carbon
dioxide applied to enhanced oil recovery will cause the additional
production of 2 to 3 barrels of oil, although this ratio depends highly
on reservoir properties and oil prices. Based on recent studies
sponsored by the U.S. Department of Energy, opportunities for enhanced
oil recovery provide carbon management options for at least a half
million barrels per year of coal-to-liquids production capacity. A
favorable collateral consequence of this approach to carbon management
is that a half million barrels per day of coal-to-liquids production
will promote additional domestic petroleum production of roughly 1
million barrels per day.
The use of pressurized carbon dioxide for enhanced oil recovery is
a well-established practice in the petroleum industry. Technology for
capturing carbon dioxide at a coal-to-liquids plant is also well
established. There are no technical risks, but questions do remain
about methods to optimize the fraction of carbon dioxide that would be
permanently sequestered.
Combined Gasification of Coal and Biomass.--Non-food crop biomass
resources suitable as feedstocks for F-T biomass-to-liquid production
plants include mixed prairie grasses, switch grass, corn stover and
other crop residues, forest residues, and crops that might be grown on
dedicated energy plantations. When such biomass resources are used to
produce liquids through the F-T method, our research shows that
greenhouse gas emissions should be well below those associated with the
use of conventional petroleum fuels. Moreover, when a combination of
coal and biomass is used, for example, a 50-50 mix, we estimate that
net carbon dioxide emissions will be comparable to or, more likely,
lower than well-to-wheels emissions of conventional petroleum-derived
motor fuels. Finally, we have examined liquid fuel production concepts
in which carbon capture and sequestration is combined with the combined
gasification of coal and biomass. Our preliminary estimate is that a
50-50 coal-biomass mix combined with carbon capture and sequestration
should yield zero, and possibly negative, carbon dioxide emissions. In
the case of negative emissions, the net result of producing and using
the fuel would be the removal of carbon dioxide from the atmosphere.
One perspective on the combined gasification of coal and biomass is
that biomass enables F-T coal-to-liquids, in that the combined
feedstock approach provides an immediate pathway to unconventional
liquids with no net increase in greenhouse gas emissions, and an
ultimate vision, with carbon capture and sequestration, of zero net
emissions. Another perspective is that coal enables F-T biomass-to-
liquids, in that the combined approach reduces overall production costs
by reducing fuel delivery costs, allowing larger plants that take
advantage of economies of scale, and smoothing over the inevitable
fluctuations in biomass availability associated with annual and multi-
year fluctuations in weather patterns, especially rainfall.
Prospects for a Commercial Coal-to-Liquids Industry
The prospects for a commercial coal-to-liquids industry in the
United States remain unclear. Three major impediments block the way
forward:
1. Uncertainty about the costs and performance of coal-to-
liquids plants;
2. Uncertainty about the future course of world oil prices;
3. Uncertainty about whether and how greenhouse gas
emissions, especially carbon dioxide emissions, might be
controlled in the United States.
As part of our ongoing work, RAND researchers have met with a
number of firms that are promoting coal-to-liquids development or that
clearly have the management, financial, and technical capabilities to
play a leading role in developing of a commercial industry. Our
findings are that the three uncertainties noted above are impeding and
will continue to impede private-sector investment in a coal-to-liquids
industry unless the government provides fairly significant financial
incentives, especially incentives that mitigate the risks of a fall in
world oil prices.
But just as these three uncertainties are impeding private-sector
investment, they should also deter an immediate national commitment to
establish rapidly a multi-million-barrel-per-day coal-to-liquids
industry. However, the traditional hands-off or ``research only''
approach is not commensurate with continuing adverse economic, national
security, and global environmental consequences of relying on imported
petroleum. For this reason, Congress should consider a middle path to
developing a coal-to-liquids industry, which focuses on reducing
uncertainties and fostering early operating experience by promoting the
construction and operation of a limited number of commercial-scale
plants. We consider this approach an ``insurance strategy,'' in that it
is an affordable approach that significantly improves the national
capability to build a domestic unconventional fuels industry as
government and industry learn more about the future course of world oil
prices and as the policy and technical mechanisms for carbon management
become clearer.
Designing, building, and gaining early operating experience from a
few coal-to-liquids plants would reduce the cost and performance
uncertainties that currently impede private-sector investments. At
present, the knowledge base for coal-to-liquid plant construction costs
and environmental performance is very limited. Our current best
estimate is that coal-to-liquids production from large first-of-a-kind
commercial plants is competitive when crude oil prices average in the
range of $50 to $60 per barrel. However, this estimate is based on
highly conceptual engineering design analyses that are only intended to
provide a rough estimate of costs. At RAND, we have learned that, when
it comes to cost estimates, typically the less you know, the more
attractive the costs. Details are important, and they are not yet
available. For this reason, we believe that it is essential that the
Department of Energy and Congress have access to the more reliable
costing that is generally associated with the completion of a front-end
engineering design.
Early operating experience would promote post-production learning,
leading to future plants with lower costs and improved performance.
Post-production cost improvement--sometimes called the learning curve--
plays a crucial role in the chemical process industry, and we
anticipate that this effect will eventually result in a major reduction
of the costs of coal-derived liquid fuels. Most important, by reducing
cost and performance uncertainties and production costs, a small number
of early plants could form the basis of a rapid expansion of a more
economically competitive coalto-liquids industry, depending on future
developments in world oil markets.
Options for Federal Action
The Federal government could take several productive measures to
address the three major uncertainties noted above--production risks,
market risks, and global warming--so that industry can move forward
with a limited commercial production program consistent with an
insurance strategy. A key step, as noted above, is reducing
uncertainties about plant costs and performance by encouraging the
design, construction, and operation of a few coal-to-liquid plants. An
engineering design adequate to obtain a confident estimate of costs, to
establish environmental performance, and to support federal, state, and
local permitting requirements will cost roughly $30 million. The
Federal government should consider cost-sharing options that would
promote the development of a few site-specific designs. The information
from such efforts would also provide Congress with a much stronger
basis for designing broader measures to promote unconventional fuel
development.
At present, RAND is analyzing alternative incentive packages for
promoting early commercial operating experience. In this analysis of
incentives, we are examining not only the extent that the incentive
motivates private-sector investment but also the potential impact on
federal expenditures over a broad range of potential future outcomes.
At this time, we are able to report that more attractive incentive
packages generally involve a combination of the following three
mechanisms: (1) a reduction in front-end investment costs, such as what
would be offered by an investment tax credit; (2) a reduction in
downside risks by a floor price guarantee; and (3) a sharing of upside
benefits such as what would be offered by a profit sharing agreement
between the government and producers when oil prices are high enough to
justify such sharing. We also caution against the use of federal loan
guarantees. Firms with the technical and management wherewithal to
build and operate first-of-a-kind coal-to-liquids plants--and then move
forward with subsequent plants--generally have access to needed
financial resources. Loan guarantees can induce the participation of
less capable firms, while isolating the project developer from the
risks associated with cost overruns and shortfalls in plant
performance. The public then ends up absorbing the costs if the project
fails.
Given the importance of controlling greenhouse gas emissions, it is
appropriate that Congress demand that the initial round of commercial
plants receiving government incentives employ carbon management
approaches so that net greenhouse gas emissions are at least comparable
to those anticipated from refining and using motor fuels derived from
conventional petroleum.
If the Federal government is prepared to promote early production
experience, then expanded federal efforts in other areas would also be
needed. Most important, consideration should be given to accelerating
the development and testing (including large-scale testing) of methods
for the longterm sequestration of carbon dioxide. This could involve
using one or more of the early coal-to-liquids production plants as a
source of carbon dioxide for the testing of sequestration options.
At present, federal support for research on F-T approaches for
liquids production is minimal. A near-term technology development
effort designed to establish the commercial viability of a few
techniques for the combined use of coal and biomass in a F-T liquids
facility could offer significant cost and environmental payoffs. In
promoting the production of alcohol fuels from cellulosic feedstocks,
the federal government is making major R&D investments. In our
judgment, the appropriate approach to balance this fuels production
portfolio is not to lower the investment in cellulosic conversion, but
rather to significantly increase the investment in F-T approaches,
including coal, biomass, and combined coal and biomass gasification.
This research investment should also include high-risk, high-payoff
opportunities for cost reduction and improved environmental
performance. Such efforts would significantly enhance the learning/cost
reduction potential associated with early production experience. Such
longer-term research efforts would also support the training of
specialized scientific and engineering talent required for long-term
progress.
In closing, I commend the Committee for addressing the important
and intertwined topics of reducing demand for crude oil and reducing
greenhouse gas emissions. The United States has before it many
opportunities--including coal and oil shale, renewables, improved
energy efficiency, and fiscal and regulatory actions--that can promote
greater energy security. Coal-to-liquids and more generally F-T
gasification processes can be important parts of the portfolio as the
nation responds to the realities of world energy markets, the presence
of growing energy demand, and the need to protect the environment.
The Chairman. Thank you very much.
Mr. Denton, go right ahead.
STATEMENT OF DAVID DENTON, DIRECTOR, BUSINESS DEVELOPMENT,
EASTMAN GASIFICATION SERVICES COMPANY, KINGSPORT, TN
Mr. Denton. Mr. Chairman and distinguished members of the
Committee, thank you for inviting Eastman Chemical Company to
share its views regarding the opportunities and challenges of
industrial gasification, meaning the gasification driving
production of industrial chemicals or products.
I'm David Denton, director of business development for
Eastman Gasification Services Company, a wholly owned
subsidiary of Eastman Chemical Company. I'm a chemical engineer
by profession, have worked in a number of technical and
management positions within Eastman's research and technology
organizations for the past 32 years. I also hold the title of
technology fellow within Eastman.
In my present position, I identify and develop customers
and project opportunities for our gasification business, and
coordinate the public policy and technology initiatives.
My company, Eastman Chemical, manufactures and markets
chemicals, fibers, and plastics worldwide. We were founded in
1920, headquartered in Kingsport, Tennessee. We're a Fortune
500 company with 2006 sales of $7.5 billion, and approximately
11,000 employees. Approximately 7,000 of those are employed in
Senator Corker's State, and another 2,600 are located elsewhere
in the United States. We are a U.S. company.
The chemicals industry, as a whole, employs nearly 900,000
people in the United States in high-paying jobs. There are an
additional 4.5 million jobs in the chemical industry supply
chain and services industries.
Natural gas is the key feedstock for the production of most
chemicals. Unfortunately, the rapid increase in natural gas
prices this decade puts the majority of domestic chemical
industry jobs at great risk. To put the price increase in
perspective, natural gas prices have risen 41 percent more than
gasoline prices since the year 2000. We all know how much
gasoline has risen. The NYMEX price for January delivery is 35
percent higher than today's price for natural gas.
Electric generation has surpassed the chemical industry
this decade as the largest consumer of natural gas. Natural gas
use in electric generation has increased by 75 percent over the
past 10 years, and now accounts for 27 percent of all electric
generation, more than nuclear.
Environmental considerations, particularly greenhouse gas
reduction, will inevitably drive natural gas demand and prices
even higher in the future. These rising natural gas prices
ripple through the economy. Chemicals, food, packaging, steel,
glass, all cost more when natural gas prices go up and jobs in
these industries decline. In the ammonia-based fertilizer
industry, for example, 50 percent of our jobs have been lost
this decade to countries with lower natural gas cost
components, countries such as Russia and those in the Middle
East.
The committee should do all it can to increase natural gas
supplies in an environmentally sustainable way. Under any
circumstances, however, the United States must move to develop
substitutes for natural gas from domestic resources that are
clean, inexpensive, plentiful, readily available, and secure.
Eastman has extensive experience developing and using just
such a substitute, and that is gasified coal. We pioneered the
first commercial U.S. chemicals-from-coal facility in 1983 at
our site in Kingsport, Tennessee. Our east coal gasification
operating performance is industry-leading and highly regarded
worldwide. Our forced outage rate has averaged less than 2
percent since initial startup. This availability record of
greater than 98 percent for over two decades of operation is
exceptional for any coal-fed facility. Today, Eastman operates
its gas fires with the highest syngas output per unit volume of
any GE syn-gasifier in the world, and has over 600 person-years
of combined operating experience in coal gasification. We're
confident enough in coal gasification and its ability to
develop high-valued products that in November of last year our
chairman and CEO, Brian Ferguson, announced to the financial
markets that we intend to drive at least 50 percent of our
product volume from coal or feedstock within the next 10 years.
Gasification, particularly industrial gasification of coal
and other feedstocks, presents great opportunities for reduced
natural gas demand, and, consequently, to reduce prices for all
domestic consumers. The potential benefits for U.S. jobs
preservation, our economy, trade balance, energy security, and
the environment are tremendous. Our gasification is a very
general term. It's not a single technology. There are many
different gasifiers and gasification concepts.
There are fundamental differences between gasification
technology systems suitable for industrial gasification
applications and those suitable for standalone power
generation, or IGCC. These differences have significant
implications for total system efficiencies and for the
readiness to separate carbon from other constituents in the
syngas stream.
Industrial-based gasification systems, such as Eastman's
facility, are designed, inherently and specifically, to capture
carbon as part of their product stream. Typically, over 90
percent of any CO2 in an industrial synthesis gas
stream is captured because downstream process steps require it.
The cost of this capture is thus included in the price of the
final industrial products. This is unlike industrial
gasification processes. Gasifiers designed for power generation
do not currently separate CO2 or carbon from the
syngas stream because there is no current economic reason or
process requirements to do so. I believe that carbon capture
for these power systems will be economically acceptable in the
future, driven by market forces, R&D improvements, and
regulatory requirements, but IGCC systems today don't have the
ability and the equipment to capture CO2, as do
industrial gasifiers.
In my written statement, I've identified a number of unique
characteristics of industrial gasification processes that
inherently enable or advantage high levels of carbon capture.
In addition to these technology distinctions, much of America's
chemical industry infrastructure is located in, or near,
geographic regions where carbon sequestration may present a
win-win opportunity with enhanced oil recovery.
So, industrial gasification systems prevent real and high-
value opportunities with respect to carbon capture and geologic
sequestration.
At the risk of using an overworked phrase, industrial
gasification represents the low-hanging fruit, as the Congress
and administration consider a program to test and develop
carbon capture and sequestration technologies, protocols,
regulations, and financing issues in commercial settings.
Industrial gasification opportunities represent the logical
economic and technological path forward to achieve four policy
objectives I believe are key to America's economic and
environmental health. Those are cost-effective environmental
protection, energy security through the reliance on domestic
fuel resources, reduction of natural gas prices and price
volatility to all consumers, and global competitiveness and the
preservation and expansion of millions of high-technology jobs
in America's industrial sector.
As promising as industrial gasification is for the policy
objectives above, deployment of commercial plants will not
occur, and the proving ground for carbon capture and
sequestration will not be available, unless Federal and State
governments provide the necessary incentives and framework to
attract these first-adopter projects.
As the MIT future coal study correctly points out, in our
view, similar incentives, such as production tax credits,
should be applied to carbon capture and geologic sequestration.
There are considerable market, legal, and regulatory hurdles to
be overcome or addressed before these first-adopters can
attempt carbon sequestration, particularly in deep saline
aquifers. However, doing so now could have significant benefits
for the entire Nation.
Federal incentives necessary to stimulate carbon capture
and sequestration will be expensive, but, by paying for much of
the cost of carbon capture in the price of its products,
leading primarily carbon dioxide compression and sequestration
costs to be incentivized, industrial gasification can provide
the lowest cost and quickest route to for incentivizing and
implementing such commercial demonstrations.
Thank you for the opportunity to share Eastman's views on
the opportunities and challenges associated with industrial
gasification.
[The prepared statement of Mr. Denton follows:]
Prepared Statement of David Denton, Director, Business Development,
Eastman Gasification Services Company, Kingsport, TN
Mr. Chairman, members of the committee, I am David Denton, Business
Development Director for Eastman Gasification Services Company, a
wholly-owned subsidiary of Eastman Chemical Company. I am a chemical
engineer and registered professional engineer. I am a Technology Fellow
within Eastman. In my present position, I identify and develop
customers and project opportunities for Eastman's gasification
business, and coordinate with public policy and technology initiatives.
Over my 32 years experience with Eastman Chemical Company I have worked
in a number of technical and management positions within Eastman's
Research and Technology organizations.
introduction to eastman
Eastman Chemical Company manufactures and markets chemicals, fibers
and plastics worldwide. It provides key differentiated coatings, and
adhesives and specialty products; is the world's largest producer of
PET polymers for packaging; and is a major supplier of cellulose
acetate fibers. Founded in 1920 and headquartered in Kingsport,
Tennessee, Eastman is a FORTUNE 500 company with 2006 sales of $7.5
billion and approximately 11,000 employees. Approximately 7,000 of
those are employed in Senator Corker's state and another 2,600 are
located elsewhere in the United States. For more information about
Eastman, and its products, visit www.eastman.com.
eastman and gasification
Eastman was a pioneer in commercializing the first U.S. chemicals
from coal facility in 1983. Eastman received Chemical Engineering
magazine's Kirkpatrick Award for Engineering Excellence for recognition
of its ``chemicals from coal'' facility in Kingsport, Tennessee, and
the facility has been designated an American Chemical Society National
Historic Chemical Landmark.
Eastman's coal gasification operating performance is industry-
leading and is highly regarded world wide. The first full year of
operation (1984), Eastman's forced outage rate was between 8% and 9%
and has averaged less than 2% ever since. Forced outage rate for the
past full three year maintenance cycle was 1.06%, and the gasification
facility was on-stream over 98% of the time.
Eastman has a strong commitment to process improvement and has
continually improved and optimized its gasification operations over
time. Today, Eastman operates its coal gasifiers at the highest syngas
output per unit gasifier volume of any GE Energy designed solids-fed
gasifier in the world. In addition, Eastman has built a tremendous
support infrastructure for gasification during the past two decades.
Some examples of that support infrastructure include:
A large data base of equipment reliability data and root
cause failure analyses
Gasification modeling and simulation
Advanced process control systems
Process instrumentation and analysis (including on-line
analyses)
Refractory design, inspection, and installation services
Reliability-based predictive maintenance systems
Coal, petcoke, and slag chemistry and characterization
Optimized standard operating procedures
Rapid gasifier start-up and switch-over procedures
Multiple gasifier operation and integration experience
Specialized materials science and metallurgy
A large code-rated machine shop for critical parts
fabrication and repair
Proven environmental and safety systems and procedures
Eastman's technical, operations, and support staff have over 600
years of combined experience in coal gasification, an experience base
which is unrivaled in the chemical industry. In addition to experience
with Eastman's gasifiers, Eastman has made selective hires of
gasification experts with broad experience at other companies and
facilities. Eastman engineers have had direct experience with start-up,
trouble-shooting, and/or operations at over 20 gasification facilities
around the world, including a number of petcoke and coal-fed gasifiers.
In addition to gasification expertise, Eastman and its subsidiaries
have over 80 years of experience in managing large integrated
manufacturing sites. Eastman owns and operates a number of large
integrated plant sites in the U.S. and overseas. Eastman's largest site
in Kingsport, Tennessee, has over 7,000 employees and manufactures
hundreds of products.
Eastman has also developed an extensive and respected expertise in
the management, execution, and commissioning of major capital projects.
In external benchmarking studies, Eastman was recognized for top
quintile performance in overall capital cost, schedule performance, and
overall capital effectiveness, as well as being ranked best-in-class in
several areas.
opportunities
My testimony today will focus on technology ``opportunities and
challenges'' of gasification, particularly industrial gasification, and
on technical and institutional issues related to the potential for
carbon capture and geologic sequestration (CCGS).
As we begin to talk about ``gasification,'' I want to emphasis that
this is a very general term. Gasification is not a single technology;
there are as many different gasifiers and gasification concepts as
there are members of this Committee, actually more. The choice of
gasifiers and technical systems approach for a given project depends on
many factors, principal of which are the intended product and the
intended feedstock.
There are fundamental differences between gasification technology
and systems suitable for industrial processes and gasifiers that are
designed for Integrated Gasification Combined Cycle (IGCC) power
generation applications. These differences have significant
implications for total system efficiencies and for readiness to
separate carbon from other constituents in the synthesis gas stream.
Industrial-based gasification systems, such as Eastman Chemical
Company's facility in Kingsport, Tennessee, are inherently designed to
capture carbon and are more thermally efficient than stand-alone coal-
fueled IGCC power generation facilities. This is also true of existing,
or planned, industrial polygeneration gasification facilities that co-
produce chemicals, fuels or fertilizers, in addition to electric power,
or some other baseload product.
Unique characteristics of industrial gasification processes that
enable or advantage high levels of carbon capture include:
Shift Reaction--Most industrial gasification products
(chemicals, fertilizers, transportation fuels, or hydrogen)
require the syngas (the initial gaseous product from the
gasifier, composed primarily of carbon monoxide and hydrogen)
to be ``shifted,'' or enriched in hydrogen. To ``shift'' the
syngas, water is reacted with carbon monoxide in the syngas to
create additional hydrogen and carbon dioxide. This ``shift''
step is not utilized in the non-capture IGCC systems.
Quench Gasifier--The water ``shift'' reaction is
accomplished with a ``quench-type'' gasifier. Hot syngas from
the gasifier is quenched in water, saturating the syngas with
water for the subsequent ``shift'' reaction. For reasons that
are explained below under ``Capture Required'' most industrial
gasification plants will be designed with gasifiers that are
optimized for carbon capture.
High Pressure Efficiencies--Downstream chemical conversion
processes require most industrial or polygeneration
gasification plants to operate at high pressures, higher than
those typically required for stand-alone electric power
generation. Fortunately, this same high pressure required for
chemical processing also makes most carbon dioxide capture
technologies operate more efficiently, further enhancing the
synergies between industrial gasification and carbon capture
systems.
Capture Required--In order to use ``shifted'' syngas for its
industrial purpose(s), the carbon dioxide formed must typically
be captured, and removed to low levels prior to any subsequent
chemical conversion of the syngas. (To the contrary, in the
IGCC case presented in the MIT study The Future of Coal, carbon
capture is a parasitic cost and is undesirable absent a
regulatory requirement.) Most residual carbon in the
industrial-use syngas is destined for ultimate chemical
conversion and is thus incorporated (or sequestered) into the
final desired industrial product, rather than vented. A few
examples of durable industrial products made from chemicals in
which carbon is routinely sequestered include plastic handles
on screwdrivers and toothbrushes, tape, and automobile paint,
among many others. (Note: the carbon capture rate is normally
zero for IGCC, but can be 90+% if so designed, or added later).
Industrial gasification capture rates can vary widely based on
products, and split of products/coproducts. Typically,
industrial gasification projects would initially capture 50-90%
of feedstock carbon as CO2 or final products, but
can be expanded to 90+% relatively easily compared to a stand-
alone IGCC.
Thermal Efficiency--Industrial polygeneration has the
additional advantage of inherently greater thermal efficiency
than IGCC systems. Thermal efficiencies can vary widely, but
would typically be 40% for stand-alone IGCC, and 50-75% for
industrial gasification.
These differences are indicated in the two illustrations that
appear in the Appendix (pp. 7-8).*
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* The appendix has been retained in committee files.
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In addition to these technology distinctions, much of America's
chemical industry infrastructure is located in or near geographic
regions where carbon sequestration may present a win-win opportunity
with enhanced oil recovery.
So, Industrial Gasification systems present opportunities with
respect to carbon capture and geologic sequestration. At the risk of
using an overworked phrase, Industrial Gasification represents the
``low hanging fruit'' as the Congress and the Administration consider a
program to test and develop CCGS technologies, protocols regulations
and financing issues in a commercial setting as Drs. Deutch and Moniz
of MIT recommended to the Committee on March 22nd.
Industrial gasification opportunities represent the logical
economic and technological path forward to achieve four policy
objectives that I believe are key to America's economic and
environmental health. Those are:
1. cost-effective environmental protection;
2. energy security through reliance on domestic fuel
resources;
3. reduction of natural gas prices and price volatility to
all consumers; and
4. global competitiveness and millions of high technology
jobs in America's industrial sector.
challenges
As promising as Industrial Gasification is for the policy
objectives noted above, deployment of commercial gasification plants
will not occur and the ``proving ground'' for CCGS will not be
available unless federal and state governments provide the necessary
incentives and framework to attract ``first adopter'' projects.
Contrary to arguments made in the MIT study The Future of Coal,
gasification technology is not ``commercial'' today. We at Eastman have
the country's most experienced and successful practitioners of
industrial gasification. But our experience of more than 20 years at
Kingsport is, by itself, inadequate to persuade A&E firms and
financiers to reduce the risk premiums they are currently charging for
first-of-a-kind gasification projects in the U.S. This premium is
currently about twenty percent higher than the cost of such plants is
expected to be after the first dozen or so are successfully deployed
and operated in commercial service.
Incentives, such as Section 48A and 48B tax credits, are necessary
to encourage commercialization of gasification projects. The use of
gasification will cause the substitution of coal, petcoke and other
materials for natural gas, thus resulting in decreases in demand (and
presumably prices) for natural gas. The benefits to all Americans from
lower and stable natural gas prices will pay for the expense of the
Section 48A & B tax credit programs in short order. The other benefits
previously noted make these tax programs even more compelling. However,
none of these benefits accrue directly to the first adopters of
gasification technology. In fact, first adopters of industrial
gasification technology, operating in a globally competitive market,
would be taking on more cost and risk than their competitors absent the
Section 48B incentives. Financiers will be more likely to lend money to
such ventures if there are external incentives to ``buy down'' the risk
and cost for a novel project.
As the MIT study correctly points out, in Eastman's view, the same
incentives should apply to carbon capture and geologic sequestration.
With the exception of conventional EOR projects, where sequestration
may or may not occur, there is no practical reason why a company would
spend hundreds of millions of dollars to separate, transport and store
carbon underground. However, doing so now could have significant
informative benefits for the entire nation if carbon management is a
policy objective in the future.
Federal incentives necessary to stimulate experience in carbon
capture and long-term geologic sequestration and the subsequent
development of protocols will be expensive. Twelve projects, based on
different technologies and geologic circumstances will likely cost up
to $10 billion just for the carbon capture, transportation and storage
aspects of the projects. Incentives for gasification technology
deployment would be a few billion additional dollars. However, the cost
of imposing greenhouse gas reduction regulations in the future without
a program of technology development and commercial scale deployment
would certainly lead to inefficient choices, much greater expense to
the country and serious loss of productivity for our economy.
Thank you for the opportunity to share Eastman's views on the
opportunities and challenges associated with Industrial Gasification.
The Chairman. Thank you very much.
Dr. Ratafia-Brown, you go right ahead.
STATEMENT OF JAY RATAFIA-BROWN, SENIOR ENGINEER AND SUPERVISOR,
SAIC--ENERGY SOLUTIONS GROUP, McLEAN, VA
Mr. Ratafia-Brown. Good morning, Mr. Chairman, Senator
Domenici, and members of the committee. Thanks so much for the
opportunity to appear this morning to discuss the technical
feasibility of co-converting coal and biomass to clean
transportation fuels via gasification technology. My testimony
is based on over 30 years of broad experience conducting
technical and environmental analysis of energy conversion
methods, including recent project work that specifically
focuses on combining biomass with coal in a so-called coal-
biomass-to-liquids, or CBTL, facility.
Co-gasification of combined coal and biomass feedstock is
being advocated as a potential means of producing substantial
quantities of clean diesel fuel while yielding very low levels
of pollutant discharges, including carbon dioxide. To both
rapidly and cost-effectively achieve these goals, this concept
needs to utilize the technological strengths of large-scale
coal gasification technology, which enables co-conversion to
produce a clean syngas at the high-pressure and-temperature
conditions required for further processing into fuels and
capturing carbon dioxide for sequestration.
Since the addition of biomass into a coal-based conversion
system introduces unique technical challenges, the goal of my
testimony is to convey that there is great promise for the
successful engineering of such a hybrid energy conversion
system.
Key roadblocks to future coal and biomass conversion are
associated with the environmental consequences of increasing
coal consumption, the relatively small scale and high specific
cost of available biomass-only conversion systems, availability
and handling of sufficient biomass feedstock for an economic
biomass-only plant size, and shutoff risk or curtailment of
operations if there is a biomass supply shortage or supply
reduction.
A very promising approach to the resolution of many of
these roadblocks is to combine conversion of coal and biomass
within a single large facility that incorporates gasification
technology to convert solid feedstock to syngas, syngas
processing to remove contaminants, Fischer-Tropsch synthesis
technology to convert syngas to clean fuel, and carbon capture
and storage technologies for efficient and safe sequestration
of CO2. Individual plants would have to be very
large to capture required economies of scale: for the
transportation sector, 25,000 to 50,000 barrels per day; in the
chemical sector, 5,000 barrels-per-day equivalent.
The gasifier represents the most critical component that
impacts system design and operation. Fortunately, joint
industry and DOE R&D efforts over the past 25 years have
developed large-scale entrained flow gasification, which
demonstrates the design and operational characteristics needed
to effectively co-gasify coal with a variety of biomass types.
Recent commercial-scale tests have validated the efficacy of
co-gasification in such gasifiers located at the 250-megawatt
Polk power plant in Florida and a similar one operating in the
Netherlands. They were able to successfully process up to 30
percent biomass by weight, or 17 percent on an energy input
basis.
My work is primarily focused on crop-based biomass,
particularly switchgrass and short-rotation woody crops, such
as poplar and eucalyptus. Unfortunately, their overall energy
density--energy content per unit volume--is only about 10
percent that of coal. As a consequence, biomass requirements
with regard to transport, storage, and handling are very high
in comparison to heat contribution to the plant. Therefore,
densification is required to mitigate such handling issues. In
this regard, a number of relatively small-scale methods have
been developed that are applicable. Pelletization,
torrefaction, and pyrolysis are methods that can increase
energy density from 5 to 20 times, but we really need larger-
scale capabilities than currently available.
The CBTL concept also requires strict limits on various
contaminants in the syngas, most of which come from coal, but
biomass co-contributes elements such as calcium, phosphorous,
chlorine, sodium, and potassium. Parts-per-billion limits are
intended to prevent poisoning of catalysts and fouling and
corrosion of heat exchangers and gas turbine blades.
Fortunately, we have gained much experience with commercial
IGCC power plants, and refinery and chemical gasifiers, and
have established that syngas limits can be met with
conservative system design.
Finally, while operation of a CBTL facility can reduce
CO2 emissions relative to more conventional coal-to-
liquids design, integration of capture/sequestration technology
will reduce the GHG footprint to a much greater extent.
Fortunately, high pressure entrained flow gasification lends
itself well to integrated CO2 capture, yet the
actual sequestration of CO2 is not yet commercially
available, and it is vital to validate it for use with the CBTL
technology.
In summary, this country has spent much time and money
developing the kind of gasification and related technologies
that can effectively be used for coal and biomass co-
conversion. Although added R&D and longer-term tests are needed
to better understand how to optimize CBTL, I strongly believe
that it has great potential to improve our energy security
while also being a good steward of the environment.
I thank you for your kind attention.
[The prepared statement of Dr. Ratafia-Brown follows:]
Prepared Statement of Jay Ratafia-Brown, Senior Engineer and
Supervisor, Science Applications International Corporation, McLean, VA
Good Morning Mr. Chairman, Senator Domenici and Members of the
Committee. Thank you for the opportunity to appear this morning to
discuss the technical feasibility of co-converting coal and biomass to
gaseous and liquid fuels via gasification and Fischer-Tropsch synthesis
technologies. My testimony is based on over 30 years of broad
experience conducting technical and environmental assessment and
systems analysis for large-scale energy conversion methods, including
recent project work.
Co-gasification of combined `coal + biomass' feedstock is being
advocated by researchers as a potential means of producing significant
quantities of transportation fuels while yielding very low levels of
pollutant discharges, as well reduced or near-zero release of carbon
dioxide (CO2), a greenhouse gas (GHG) forcing agent. To
achieve these goals both rapidly and cost-effectively, this concept
likely needs to utilize the technological strengths of large-scale,
commercial coal gasification technology, which enables co-conversion of
renewable crop-based biomass feedstock with coal, generation of
suitably ``clean'' syngas at required pressure/temperature conditions,
and the capability to efficiently capture carbon dioxide
(CO2) for sequestration. Since the addition of biomass into
a coal-based conversion system introduces unique technical requirements
and challenges, my goal in this testimony is to discuss the potential
for successfully engineering of such a hybrid energy conversion system.
drivers for `biomass + coal' co-conversion
The primary motivation for converting our substantial domestic coal
and biomass resources to transportation fuels and chemicals is to
displace the use of imported oil and, thereby, help mitigate its high
price and supply security concerns. Inclusion of biomass in this
endeavor also represents a potential means of reducing the
environmental footprint of this transformation on a sustainable basis.
In this regard, ambitious national and international goals, like the
U.S. Biomass Research and Development Act of 2000 and the Biofuel
Directive of the European Union, call for large biomass-based energy
conversion capacity in order to diversify the resource base for
transportation fuels, chemicals, and power/heat generation. The U.S.
Vision recommends that biomass supply 5% of the nation's power, 20% of
its transportation fuels, and 25% of its chemicals by 2030. The EU
Vision (as of March 2007) sets a goal of 10% biofuels use for
transportation by 2020.
Key roadblocks to this resource conversion are associated with: 1)
environmental consequences of greatly increasing coal consumption,
particularly related to amplified release of greenhouse gas emissions
(GHG); 2) small-scale, high specific-cost and relatively poor
performance of available biomass conversion technologies; 3)
availability of sufficient biomass feedstock (locally) for an economic
plant size; and 4) shut-off risk or curtailment of operations if there
is a biomass supply shortage or reduction in supply.
A very promising approach to resolution of most of these roadblocks
is to combine conversion of coal and biomass in a large-scale facility
that incorporates gasification technology to convert solid feedstock to
syngas (primarily H2, CO, CO2, H2O,
and CH4); syngas processing to remove unwanted contaminants
such as sulfur, potassium, and mercury; Fischer-Tropsch (F-T) synthesis
technology to convert syngas to clean liquid fuels (naphtha and
diesel); carbon capture and storage (CCS) technologies technology to
allow efficient and safe sequestration of CO2; and power
generation technology to both supply internal requirements and
electricity for sale. Individual plants would have to be very large to
capture required economies-of-scale: Transportation Sector--25,000 to
50,000 barrels/day; and Chemical Sector--5,000 barrels/day equivalent.
I will refer to this as the coal/biomass-to-liquids (CBTL) concept.
The environmental consequences of this approach, particularly as
related to the net release of CO2, have been investigated by
researchers from the Princeton Environmental Institute.\1\ Their
findings indicate that a plant that combines co-gasification of biomass
(switchgrass) and coal could potentially achieve a near-zero net
CO2 emission rate by exploiting the negative emissions of
storing photosynthetic CO2 in roots and soils. By
comparison, the CO2 emission rate for coal-only F-T liquids
production, with CCS, could be reduced to about the same rate as crude
oil-derived fuels. This approach could also require considerably less
net biomass input to realize near-zero emissions than conventional
biofuels conversion, such as cellulosic ethanol.
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\1\ Williams, R., ``Synthetic Liquid Fuels From Coal + Biomass with
Near-Zero GHG Emissions,'' Princeton Environmental Institute, Princeton
University, January 12, 2005.
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Let me summarize the key drivers for CBTL concept as I see them: 1)
Reduction of imported crude oil; 2) Continued use of our abundant coal
resources in an environmentally acceptable manner; 3) Greater
utilization of our abundant biomass resources in accordance with our
national goals; 4) Efficient and cost-effective utilization of biomass
resources; 5) Coal acts as a ``flywheel'' to keep a facility operating
even if biomass is not sufficiently available; 6) Within a strict
carbon-constrained framework, such as McCain-Lieberman, this approach
should become cost-effective, 7) Use of reliable coal in concert with
more environmentally acceptable renewable feedstock may reduce project
financial risk for large-scale energy conversion plants; and 8)
Gasification-based projects could benefit significantly from the more
positive public attitude displayed towards co-utilization of renewable
feedstock, as well as development of a reliable multi-source fuel
supply network for such projects.
Successful technical and cost-effective implementation of CBTL
particularly depends on adoption of suitable gasification technology,
addressing biomass handling challenges, satisfying syngas ``cleanup''
constraints, and effectively integrating CCS. My intent in the
remainder of this testimony is to focus on the challenges that each
represent and their potential for enabling this concept to function
effectively.
gasification technology capability and experience
First, I want to convey that gasification technology is in
widespread use today. The 2004 World Gasification Survey, sponsored by
DOE, shows that in 2004 existing world gasification capacity had grown
to 45,000 MWth of syngas output at 117 operating plants with a total of
385 gasifiers. Coal (49% of capacity), petroleum products (37%) and
natural gas (9%) currently dominate the gasification market as the
primary feedstocks for production of F-T liquids, chemicals, and power.
Note, however, that biomass gasification only accounts for about 2% of
the total syngas production. Exhibit 1* presents a summary of large-
scale gasification experience.
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* All exhibits have been retained in committee files.
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The gasification technology represents the most critical component
that impacts system design and operation of a CBTL facility. The
desirable design characteristics for co-gasification technology for F-T
liquids applications (using high rank coals) are: large individual
gasifier throughput (>1000 MWth); high temperature (>2,300 F to
eliminate tars/oil contaminants in the syngas); high pressure to
increase syngas throughput and reduce process component sizes; oxygen-
blown (as opposed to air-blown) to eliminate nitrogen as a syngas
diluent; slagging (a consequence of high temperature operation) to
render most of the feedstock ash as a benign byproduct for utilization
purposes; dry feed of biomass since it is difficult to handle as a
slurry, and use of a relatively large particle size to reduce feedstock
preparation.
Fortunately, these design characteristics are generally met with
the widely used entrained-flow gasification technology, which currently
dominates the large-scale gasification market with 85% of the installed
units. (Note that this technology also continues to benefit from a
variety of related R&D efforts sponsored by DOE to further improve
performance and cost, including development of a compact transport-type
gasifier technology.) While these gasifiers are quite flexible with
regard to feedstock characteristics, their high reaction rates demand
very small feedstock input size (e.g., <100 micron or 0.004 inches)
that is easily achievable for friable materials like coal, but more
challenging and energy-consuming for biomass feedstock. Compounding
this important issue is the high pressure injection requirement for the
entrained-flow technology, which may present a challenge to biomass
injection into the gasifier. Also, the chemical make-up of biomass ash
will cause it to behave differently that coal ash, which must be
accounted for in design and operation. Several large-scale
demonstrations of entrained-flow co-gasification of coal and biomass
have already been performed here and in Europe.
Commercial scale co-gasification of biomass with coal has been
demonstrated at the 253 MWe Nuon IGCC power plant in Buggenum, The
Netherlands (using the dry-feed Shell entrained-flow technology), as
well as at Tampa Electric's 250 MWe Polk IGCC power plant (using GE
entrained-flow technology). (The latter was built in the 1990s as part
DOE's Clean Coal Demonstration Program.) The Nuon plant recently tested
biomass content up to 30% by weight (17% of total energy input), which
requires up to 205,000 tons/year of biomass feedstock and coal feed is
about 435,000 tons/year. Besides gasification of demolition wood, tests
were also conducted with chicken litter and sewage sludge. The co-
gasification tests conducted at the Polk plant used up to 1.5% by
weight of woody biomass harvested from a 5-year-old, locally-grown
Eucalyptus grove. Since the plant uses 2,200 tons/day of coal, the
biomass co-gasification basis was 33 tons/day (about 10,000 tons/yr).
Not only did these plants operate normally, but we can generally
conclude that biomass feed size can be on the order of 1 mm (0.04
inches) due to biomass' high reactivity relative to coal. The
importance of this lies in the capability to minimize biomass milling
power consumption and possibly avoid other efficiency-reducing pre-
treatment processes. The Nuon experience has also shown that a
relatively high throughput of biomass is possible in an entrained-flow
unit that is co-gasifying coal. Pilot-scale tests were also tests were
also conducted at the National Energy Technology Laboratory (NETL)/
Morgantown some years ago with coal and up to 35% biomass.
coal + biomas co-gasification challenges
Below, I provide a brief overview on key challenges associated with
oxygen-blown, entrained-flow gasification of coal and biomass.
Oxygen feed to the gasifier--standard cryogenic method of oxygen
production is both costly and energy intensive; however, DOE is well
into development of so-called ion transport membrane (ITM) technology,
which promises significant cost reductions and efficiency gains.
Biomass and coal injection--Feedstock injection into high pressure
gasifiers is challenging. Conventional dry-feed methods employ a series
of complex lock hoppers. Due to the low energy density of biomass, lock
hoppers have two major disadvantages: (1) large amounts of inert gas
are required and must be compressed, and (2) gasification efficiencies
drop due to the dilution of the syngas. Fortunately, DOE's gasification
program has been developing a rotary dry-feed coal pump that, when
fully tested, should allow the feedstock to be ``pushed'' directly into
the gasifier.
Biomass particle size--While entrained-flow gasifiers require very
small coal particle sizes (<0.004 inches), recent commercial `coal +
biomass' tests suggest a much larger size (0.04 inches) is likely
feasible due to the high reactivity of biomass due to its high
O2 and volatiles content
Biomass ash slagging behavior--While the slagging performance of
the biomass ash may be an issue, testing has shown that ``flux''
material (aluminum-silicates) can be added to the gasifier to re-
establish acceptable ash slagging performance.
The bottom-line is that the practical limit of biomass co-
processing with high rank coals (bituminous and subbituminous coals) is
probably associated more with biomass preparation and feed issues and
desired syngas production level, than the capabilities of the
entrained-flow gasification process.
biomass handling challenges
Our work has primarily focused on crop-based biomass, particularly
prairie grass/switchgrass and short rotation woody crops (SRWC), such
as Poplar and Eucalyptus. These are defined as fast-growing,
genetically improved trees and grasses grown under sustainable
conditions for harvest at 1 to 10 years of age. In general, their
biomass heating values [MJ/kg] and particle densities are about half of
that of coal, whereas bulk raw densities [kg/m3] are about
20% of that of coal, resulting in overall biomass energy density [MJ/
m3] approximately 10% of coal (see Exhibit 2). As a
consequence, when co-gasifying raw biomass at a 10% heat input rate
with coal, the volume of coal and biomass can actually be similar;
therefore, biomass requirements with regard to transport, storage and
handling are very high in comparison to its heat contribution.
Biomass either has to be located very close to a conversion
facility and processed immediately, or some form of ``densification''
needs to be implemented to mitigate handling issues. Since this is a
well-recognized issue for biomass, especially for conversion processes
that can consume very large quantities, a number of methods have been
developed, albeit currently at small-scale, that are applicable. These
are pelletization, which is a drying/compression method that increases
energy density of switchgrass pellets by a factor of eight.
Torrefaction is a ``roasting'' treatment that operates within a
temperature range of 200 to 300 C and is carried out under atmospheric
conditions in the absence of oxygen. This process not only increases
the energy density of wood by about 25%, but also greatly reduces the
milling energy consumption to reduce size. Combined torrefaction and
pelletization can increase the energy density of wood by about five
times. Pyrolysis is an option to produce a liquid product (pyrolysis
oil) from biomass, via its thermal decomposition, at temperatures of
450-550 C. Yield efficiency of pyrolysis oil production averages about
70%, and volumetric energy content of pyrolysis oil is 19 68,300 Btu/
gal compared with No. 6 Oil at 144,000 Btu/gal.
syngas ``cleanup'' constraints
The CBTL concept requires strict limits on various contaminants in
the syngas, most of which come from coal, but biomass co-contributes
certain elements and related compounds such as calcium (Ca),
phosphorous (P), chlorine (Cl), sodium (Na) and potassium (K). The
limits are intended to prevent poisoning of the F-T catalysts and
fouling/corrosion of downstream system components, such as heat
exchangers and gas turbine blades. As an example, constraints on alkali
metals (Na + K) are less than 10 part per billion by volume (ppbv) and
halides (HCL + HBr + HF) are also less than 10 ppbv. These and other
limits are controlled via the integration of a group of processes that
sequentially treat the syngas once it exits the gasifier. These include
dry particulate removal, wet syngas scrubbing for fine particulate and
gases, mercury removal, and acid gas (H2S and
CO2) removal. Experience with commercial IGCC power plants,
such as the Polk IGCC plant and the Wabash River plant (another DOE
Clean Coal Technology Program investment), as well as refinery
gasifiers, have established that the CBTL syngas limits can be met with
appropriate system design.
carbon capture and storage challenge
Operation of a CBTL facility will reduce CO2 emissions
relative to a more conventional coal-to-liquids (CTL) design, even
without integration of CCS technology. The extent of the reduction
depends on the relative level of biomass energy input. For example, the
30% (by weight) biomass feed to the Nuon plant that I discussed
previously, resulted in an effective CO2 reduction of about
17% or 220,000 tons/yr (excluding GHG emissions related to biomass
collection and treatment). On the other hand, integration of CCS
technology will reduce the GHG footprint of CBTL to a much greater
extent. However, while CO2 capture technology is
commercially available and well-proven for gasification-type
applications, it increases capital expenditure and operating costs; DOE
is currently developing advanced membrane technologies to lower this
impact. More importantly, the actual sequestration of CO2 is
far from commercially available and acceptable. As stated by DOE, key
challenges are to demonstrate the ability to store CO2 in
underground geologic formations with long-term stability (permanence),
to develop the ability to monitor and verify the fate of
CO2, and to gain public and regulatory acceptance. DOE's
seven Regional Carbon Sequestration Partnerships are engaged in an
effort to develop and validate CCS technology in different geologies
across the Nation. This is vital to sequestration's future and use with
the CBTL technology.
conclusion
Even without considering currently favorable government programs to
encourage investment in CTL and CBTL technology, I've endeavored to
convey that that there are considerable drivers that strongly support
continued development. Importantly, it takes advantage of the
significant investment and progress that the country has made with
gasification and related technologies over the past twenty-five years.
Commercial entrained-flow gasification technology has been proven to be
capable of co-gasifying coal and biomass, which at the minimum would
permit reduced GHG emissions from future CTL facilities. Incorporation
of CCS technology, when sequestration is technically available and
appropriate to regulatory conditions, can have a major impact on the
sustained use of our abundant coal resources and greater use of our
biomass resources. Although, I've reported on some successful tests of
coal and biomass co-gasification, I've also attempted to convey that
R&D is needed to deal with significant challenges related to biomass
handling and feeding issues that are important to plant operability and
cost-effectiveness. Also, longer-term, large-scale tests of the CBTL
concept are required to better understand how a well-integrated design
will perform and function. Overall, I strongly believe this is a
technology that has great potential to improve our energy security
while also being a good steward of the environment.
I will be happy to answer any questions.
The Chairman. I thank you very much. Thank you all for your
good testimony.
Let me start. And we'll do 5-minute rounds here.
I'll start with a question to Mr. Fulkerson. The idea you
presented, which you attributed to Bob Williams at Princeton,
was presented last month when you had your group together, your
research and development group, folks from the National
Laboratories, as I understand it. Could you be a little more
explicit about what is the extent of the capture and
sequestration that would be required as part of this? I mean,
if this combined biocoal effort is adopted, or this technology
is adopted, would there also have to be an attendant capture
and sequestration effort made in order for it to meet the
environmental standards that you think are appropriate?
Mr. Fulkerson. Yeah, of course. As Jay has just pointed
out, the biomass coal gasification process has to be
accompanied by sequestration of all of the CO2 that
is excess in the process. But the interesting point is that the
biomass carbon which is sequestered is a net-negative, and,
therefore, it offsets the carbon that is emitted subsequently
by burning the product fuel, so that the overall well-to-wheel
kind of climate impact can be net-zero. That's----
The Chairman. OK.
Mr. Fulkerson [continuing]. The important point of it.
The Chairman. ``Net-zero,'' meaning that there would be no
requirement for a separate carbon capture and sequestration
effort as part of this. Is that what you mean by ``net-zero''?
Mr. Fulkerson. Yes. What I mean is the overall process,
including burning the product fuel----
The Chairman. Right.
Mr. Fulkerson [continuing]. Produces net-zero carbon
emissions. In other words, most of the of the carbon is
sequestered, but the carbon that is sequestered includes carbon
from biomass, which is a net-negative, since biomass, in being
grown, absorbs CO2 from the air.
The Chairman. Right.
Mr. Fulkerson. So, that's got----
The Chairman. So, you're saying that, by sequestering the
carbon, you then are net-positive, and then, when you burn the
fuel, you use up your net-positive, and you come out----
Mr. Fulkerson. Right.
The Chairman [continuing]. At zero.
Mr. Fulkerson. Right. Right.
The Chairman. OK.
Mr. Fulkerson. I said----
The Chairman. Let me ask Dr. Herzog if you agree with that
analysis, that this would be where you wind up in the process.
Ms. Herzog. Yes, I do agree with the analysis, but let me
make a slight distinction.
The biomass is good. If you just used biomass, you'd be
net-negative. Including the coal, thus, brings you back up. You
could get net-zero, but that means using a lot of biomass in
this system. The question, I think, is, ``Is that the best use
of all this biomass, with the goals in mind that we have, which
is to reduce our oil dependence and reduce our global warming
emissions?'' That's what needs to be assessed properly.
The Chairman. Mr. Fulkerson, you seemed to disagree with
some of that.
Mr. Fulkerson. Dr. Herzog, let me add to what you said.
The beauty of biomass and coal together is that the amount
of biomass that you have to use per unit of product fuel is
much less than you would have to use if you went the cellulosic
ethanol route. That's the interesting trick of this. That's
the, ``Why is that?'' It's because the coal supplies most of
the energy to run the process. That's the reason you get a much
smaller requirement of biomass to come up with this zero-net
carbon emissions----
The Chairman. I'm about to run out of my time here, but let
me just nail down the stage this idea is in. This was presented
to you last month in your R&D group. Are there examples of this
functioning? Are there demonstration projects that are using
this technology? Where are we? I mean, are we looking at doing
this 2 years from now, 5 years from now, 10 years from now, on
a commercial scale?
Mr. Fulkerson. Yes, I would say that Dr. Ratafia-Brown's
testimony gave you where the state-of-the-art is. As I
understand it, there's up to 10 or 15 percent biomass with coal
in gasification in the Netherlands, so these things are coming
along. There is no inherent reason why they shouldn't work,
except the kind of details that Jay pointed out, which are a
lot of details of things have to be ironed out for this. His
testimony provided us closer to the state-of-the-art, as well
as Jim Bartis, here.
The Chairman. OK. All right. Well, I don't want to overstay
my time. Let me go ahead and call on Senator Domenici.
Senator Domenici. Chairman, you're welcome--if he wants
more time, go ahead.
The Chairman. Well, let me just ask one question of Dr.
Ratafia-Brown.
You say in here--I think he's referring to page 5 of your
testimony, where you talk about this plant in Belgium--or in
the Netherlands, excuse me.
Mr. Ratafia-Brown. That's correct.
The Chairman. Yes. Could you tell us what the status of
that is? I mean, if this is such a great technology, and the
Dutch have been doing this for some period of time here, I
guess----
Mr. Ratafia-Brown. Well, the reason that came about,
Senator, is because the Dutch have a mandate for this plant to
reduce their CO2 contribution to the Dutch
inventory, and they placed--I believe it was a 200,000 ton-per-
year reduction of CO2 on this facility. They
fought--therefore, back in 2001, to co-gasify chicken litter
and wood waste and some other biomass, up to, I believe, in
2004, it was 30 percent by weight, which was about 17 percent
on an energy-input basis to the plant. They've successfully
done this. They've had some technical issues, but I think the
overall experience is quite good. Therefore, their
CO2 reduction has come strictly from the co-
gasification of biomass.
The Chairman. You're suggesting that we could do something
similar in our coal plants?
Mr. Ratafia-Brown. We have two plants in this country that
operate very similar to that. It's the Polk Plant in Florida
and the Wabash River Plant in Indiana. They both operate
integrated gasification combined-cycle plants. The Polk Plant
also has tested biomass at their facility very successfully
back in--I think it was----
The Chairman. Very successfully as a way to reduce the
emission?
Mr. Ratafia-Brown. It was just a test to see if they could
process it and reduce emissions, that's correct.
The Chairman. OK. All right, thank you.
Senator Domenici.
Mr. Ratafia-Brown. You're welcome.
Senator Domenici. Mr. Bartis, to follow your middle-of-the-
road--what specific steps would the Congress have to put in
place? If we take those steps, what is the likelihood of
success? Please give us this list, again, now.
Mr. Bartis. Well, the first step is to resolve the
uncertainty associated with what these fuels really cost.
Senator Domenici. All right, so----
Mr. Bartis. We just don't have a handle on that. It's not
very expensive. We could cost-share, with private industry, the
development. But there are no funds allocated to this right
now. But if we could get the front-end engineering design, then
we would know what these plants cost. Truly know.
Now, let me put this in perspective. These plants run
billions of dollars. The detailed engineering package for a
plant like this would be a couple--100 million, $200 million to
get the blueprints. Before you go to that step, you go and get
a front-end engineering design. That costs about $30 million. I
believe that it's possible that, if the Federal Government came
in with a 50-50 cost share, we could get extremely valuable
information on what these plants truly cost. Right now, we're
dealing with very low-level design work primarily done for R&D
purposes, not for investment quality. The second step----
Senator Domenici. There would be no reason for you to think
that this kind of investment would produce the kind of
technology application and reality of----
Mr. Bartis. Well, our view--we've spoken with a large
number of firms--is that without an incentive package, you're
not going to get the participation of the private sector here.
So, unless it's through a broadbased tax or through specific
incentives--and we've looked at these incentives--we're not
going to make progress here. There's just too much uncertainty
on world oil prices.
Senator Domenici. OK. Now, in your opinion, if you did have
the incentives, is the technology apt to produce a feasible
plant----
Mr. Bartis. Yes.
Senator Domenici [continuing]. That will do the job?
Mr. Bartis. Yes. We have options right now for the initial
set of plants for carbon management. There's no reason that any
of these plants should exceed what's typical when we use oil in
refining. So, the first set of plants can certainly come out--
what I'll call carbon-neutral, in the sense that they're no
worse with regard to emissions than the oil that they're going
to displace.
Senator Domenici. All right.
Mr. Bartis. And we have those applications here and now.
And in the future we've got a great chance to go to what Mr.
Fulkerson described as zero emissions, as good as you can get.
Senator Domenici. All right. Now, let me ask--if we did
this, is it possible that the best incentive might be for us to
do this on a plant-by-plant basis to get it started, by saying
we'll take three of them, let's say, or four, and we will say--
we've got this agreement, and the price will come out all
right, because the American Government will buy the stream at a
price that is assured?
Mr. Bartis. We have looked at that option, and our analysis
says that a purchase commitment may not be in the best interest
of the taxpayer, that there----
Senator Domenici. OK.
Mr. Bartis [continuing]. Are better options in which risks
can be shared better. Those options--if you'd like, I can
summarize.
Senator Domenici. Sure.
Mr. Bartis. The most effective option to getting the best
of our firms involved is probably a front-end incentive, such
as a tax credit, which improves the overall investment profile
of such a plant.
Now, the second important incentive is something that
protects the investor, in case oil prices plummet. The larger
that front-end incentive is, the lower that barrier needs.
Finally, we believe that it's very important to look at
cost-sharing. The companies we've talked with also see that as
a favorable approach, some kind of collar so that there's some
kind of recapture of the Federal risk-taking.
We don't at all see loan guarantees as a useful tool,
because they don't attract the right set of players here.
Senator Domenici. OK. Let me just summarize, from my
standpoint, with the two of you, Mr. Bill Fulkerson, speaking
either for yourself or for your mentor, whichever you like, if
that's what he is, and then--if you can speak for him--and
James Bartis. Talking about this subject and wondering where we
have something that will work--now, there may be more things
that will work, so I'm not trying to tell our committee this is
the only one. But you are suggesting there is a known
technology that has had sufficient practice, albeit not with a
large commercial plant, but that there has been sufficient
practice with it that the two of you believe, with proper up-
front incentives that are fair, that we could, indeed, get in
this and come out with a plant or two, whichever we choose--and
we can have a little bit more variety, but if our goal is to
produce a plant that is neutral, in terms of carbon emission,
we could do that, if we want, and get it built, to show the
world that carbon can be used for this purpose. Is that right,
Mr. Fulkerson and Mr. Bartis? Is that what you're telling this
Senate committee?
Mr. Fulkerson. Well, I think what you said if you mean
carbon-neutral as good as petroleum----
Senator Domenici. As----
Mr. Fulkerson [continuing]. Then, absolutely, yes.
Absolutely yes.
Senator Domenici. All right. Let's say it that way for the
record.
Mr. Fulkerson. Okay. If that's what your goal is--if your
goal, however, is to be better than petroleum, because
petroleum is a major emitter of carbon dioxide in the world--
then you have to incentivize, as well, other technologies, such
as the biomass/coal combination. Now, it's not going all that
much further to do that. So, I think that with existing
technologies, or near existing technologies, that you could
accomplish both, and you should. In my testimony, I gave about
six policies that, in concert, I think, would drive us in the
right direction without specify--with picking winners, without
picking technological winners. In other words they're
technology-neutral. This is one of the technologies that would
be incentivized. Whether it's the one that would win, I don't
know, but--anyway.
Senator Domenici. Mr. Bartis.
Mr. Bartis. I endorse that. We have the technology on the
shelf today, and we can make it better than it's ever operated
in the past by putting the right companies in charge. But it's
on the shelf, and we can build it today. We can match the
carbon emissions of conventional petroleum. That's the good
news. We can solve a major national security and economic
problem.
The other critical component is going beyond that and, over
the longer term, building these plants, and to get that done
means we have to demonstrate, at multiple sites, carbon capture
and sequestration. That is not in the current plans of the
Department of Energy. It's critical. In fact, I believe that
maybe two or three of these initial plants, could be used to
generate the carbon dioxide needed for those massive
demonstrations. But it's critical that we move forward there.
Mr. Fulkerson. Jim, let me ask you--you said that we could
do the existing thing today, without sequestration. That--and
be equivalent to petroleum--that's not true. Your gasification
liquids process will produce about twice as much of
CO2 as petroleum. So, to even bring it neutral, you
have to sequester the excess carbon. Isn't that right?
Mr. Bartis. I was thinking of initial plants using it for
enhanced oil recovery operations, or as a demonstration of
these carbon sequestration.
The Chairman. So, that's another way of sequestering it.
Mr. Bartis. Another way of sequestering would be enhanced
oil recovery.
The Chairman. Right.
Senator Bunning.
Senator Bunning. My goodness, where do I start?
Since I have a bill in, I've got to get to the coal-to-
liquids use with biomass to produce a fuel, whether it be a
fuel that is used in trucks and/or diesel fuel. But, even more
importantly, I've been dealing with the Air Force, and they are
so interested in this process as a national security issue,
where we use the same type of process, including biomass, to
produce aviation fuel.
Mr. Fulkerson, is that a distinct possibility, to produce
the same type of diesel and aviation fuel by using biomass and
coal?
Mr. Fulkerson. Absolutely.
Senator Bunning. And, therefore, reducing the footprint.
Mr. Fulkerson. The only difference is the----
Senator Bunning. It's the cost of building the plant.
Mr. Fulkerson. Yes.
Senator Bunning. OK. If we incentivize that and change the
rules--we've got bad rules, as far as purchases by the Air
Force, so we limit it to a 5-year contract, and you have to pay
as you go each year--we've got to change the rules if we're
going to allow the Air Force to use that fuel. So, I want to
get this correctly through my head, because of all the
misinformation that's out there.
The technology now exists to produce, with coal and
biomass, a fuel that will burn as clean as our petroleum-based
fuels, presently. If we use the carbon capture at the plant,
and use it for other purposes, or sell it, or we sequester it,
we have a much better fuel than a petroleum-based fuel.
Anybody?
Mr. Fulkerson. Absolutely. Absolutely.
Senator Bunning. Mr. Brown? Since you're in the business,
and--David, you are also in the business, and you are in the
business, Jim--go ahead.
Mr. Bartis. Allow me to make one caveat here.
Senator Bunning. OK.
Mr. Bartis. All right. The use of biomass and coal is an
extremely low-risk option. However, as Mr. Ratafia-Brown has
mentioned, although there has been experience, it's been very
limited experience----
Senator Bunning. Correct. It's not----
Mr. Bartis [continuing]. Versus.
Senator Bunning [continuing]. Large-scale.
Mr. Bartis. So, there may be----
Mr. Ratafia-Brown. It had been large-scale.
Mr. Bartis. It has been large-scale, but on only specific
types of biomass----
Senator Bunning. OK.
Mr. Bartis [continuing]. I think we all agree there may be
a need to do some large-scale testing before a company would be
willing to put this technology on a multibillion-dollar plant.
There may need to be some tests. I know there are test sites
available, and this could be done----
Senator Bunning. My time's running out. What I want to ask
is that--similar to Senator Domenici--we know we have a big
picture out here. If we don't put coal-to-liquids technology in
the picture, we are limiting our options to synthetic fuels,
whether it be just ethanol, or whether it be soybeans to
diesel, or whatever--we're limiting our options. Therefore,
we're still going to be dependent on Middle East oil or oil
from somewhere. So, why not look at all the options and
incentivize all the options so that we can get all of the
things on the table at once?
Would you agree or disagree? Go ahead, ma'am. Please.
Ms. Herzog. Thank you. I'd like to take a step back and,
again, look at what the goals are. The goals are to reduce oil,
and also, from our perspective, reduce global warming
emissions, and not to pick the winning technology----
Senator Bunning. I don't want to pick them.
Ms. Herzog [continuing]. Which is what you're saying. And
I----
Senator Bunning. No, but I said put them all out.
Ms. Herzog. So, the way--we believe--to do that most
effectively is to set the standard and let the market find the
most promising technologies. Very possibly, it might be what
you're suggesting, but that needs to play on an equal playing
field with all the other opportunities out there.
Senator Bunning. I agree. But we also have to get some kind
of global agreement. The United States can get to zero in
emissions. If we don't get an agreement out of China and India
and other places to lower their emissions, we are not going to
have an effect on global warming anywhere in the world because
China's going to open up 94 coal-fired generation plants this
year, with no restrictions on them.
Ms. Herzog. But----
Senator Bunning. So, we need to have some kind of an
agreement, globally.
Ms. Herzog. I absolutely agree, and we're as concerned
about China and the rest of the world as you are, and also
concerned about U.S. emissions.
Senator Bunning. Thank you very much, panel.
The Chairman. Senator Salazar.
Senator Salazar. Thank you very much, Chairman Bingaman and
Senator Domenici, for holding this very, very important
hearing.
I appreciate your knowing that many of us on this committee
come from States that have a lot of coal, and use a lot of coal
in powering the energy that we use. In my State, 71 percent of
our electricity is generated from coal. We have coal mines and
coal miners throughout the western slope of my State through
the southern end of my State, and I recognize coal has this
abundance that makes it a very attractive place for us to look
at addressing the national security and environmental security
issues of our time.
So, the real debate, it seems to me, here in this
committee, and probably on the Senate floor, will be how is it
that we can move forward and develop the use of our abundant
coal resources in a way that does not do damage to our
environment, in a way that does not compromise our
environmental security?
So, I have a couple of questions. First, to you, Dr.
Herzog. In terms of a hybrid electricity technology for
vehicles, is there a way, through IGCC, and through moving
forward with advanced vehicle technologies, with battery-
powered vehicles that are plugged in at night--is that the kind
of thing that you think has some possibility for us to use some
of our abundant coal resources?
Ms. Herzog. Absolutely. GM is developing plug-in hybrid
electric vehicles. So are other automobile companies. The
exiting thing about plug-in hybrid electric vehicles, which I
said in my testimony and remarks, is that you can use coal
gasification, capture the carbon dioxide, create electricity to
the plug-in hybrid electric vehicle, save much more oil, and
reduce greenhouse gas----
Senator Salazar. Let me ask you, then, this. What is it
that we, as a committee that understands the volume of coal
that we have available here in the United States of America,
can do to further incentivize that goal----
Ms. Herzog. Right.
Senator Salazar [continuing]. To happen sooner than later?
Ms. Herzog. Right. So, as I said just now, I don't believe
in picking technologies. I think this could very possibly be
the winner, but what we need to do is put a cap on our carbon
emissions, headed to where we need to be in the next decades to
come, so a declining cap that will set a market signal on
carbon. In addition, I think standards to help promote--an
incentive to help promote technologies, more general within a
carbon cap, make a lot of sense. For example, a low-carbon fuel
standard, where electricity to plug-in hybrids would qualify.
To have that low-carbon fuel standard starting at a level, in a
few years, and then slowly ramping down over time to make sure
that our transportation sector emissions are heading in the
direction they need to be heading, and not to invest in
technologies today which won't make any sense in 10-20 years.
Senator Salazar. Thank you, Ms. Herzog.
Mr. Fulkerson, I think it was you that testified about the
fact that we already have two IGCC plants that use biomass here
in our country, one in Polk, Florida, and one in Wabash,
Kentucky. Was that your testimony, or another witness?
Mr. Fulkerson. Jay's testimony.
Senator Salazar. That was Jay's testimony. Let me ask you
both. Given two plants that have already been doing IGCC with
biomass that deals with the greenhouse emissions issue, why
isn't this technology being, essentially, deployed, and being
picked up by the commercial market, at this point in time?
Mr. Ratafia-Brown. Well----
Senator Salazar. Jay and Bill, why don't you take a quick--
--
Mr. Ratafia-Brown. Well, we don't currently operate within
a climate change framework. There's no incentive for these
plants to use a crop, that they may have to pay for, to add to
their, you know, already plentiful fuel supplies. Now, in the
State--in the case of the Netherlands, their country did
mandate that that plant----
Senator Salazar. So, for the case of the Florida and
Kentucky plants, they just did it out of being----
Mr. Ratafia-Brown. That was a test----
Senator Salazar [continuing]. Good Samaritans. They just
wanted to go and try it----
Mr. Ratafia-Brown. It was----
Senator Salazar [continuing]. To see how it worked.
Mr. Ratafia-Brown [continuing]. A test to determine whether
that gasifier can handle it, and----
Senator Salazar. The results of those tests, you said, were
positive?
Mr. Ratafia-Brown. Extremely positive.
Senator Salazar. OK. But it was just a test. They're not
currently using it.
Mr. Ratafia-Brown. That's correct. I do----
Senator Salazar. OK.
Mr. Ratafia-Brown. [continuing]. Want to point out one
thing, if I might, with regard to these plants, these CBTL
plants. They not only produce fuels, they do produce
electricity for plug-in hybrids. A 50,000 barrel-per-day plant
will also produce 125 megawatts of electricity for sale to the
grid. So, these----
Senator Salazar. Dr. Herzog, what's----
Mr. Ratafia-Brown. [continuing]. This is a win-win-win.
Senator Salazar [continuing]. What's the problem with
moving forward with projects like the ones that have already
demonstrated what they can do in Kentucky and Florida?
Ms. Herzog. Well, my understanding is, the Polk Plant is a
coal gasification plant that produces electricity. It's been
running for quite some time. If they added biomass, it was
only--I mean, it's not running on biomass now.
Mr. Ratafia-Brown. No, no. That was strictly a test
sponsored by the Department of Energy--again, to test the
viability of it.
Senator Salazar. Well, the tests work. Here's my question
I'm trying to get to. We know the tests work in the
Netherlands, we know they worked in Florida, we know it worked
in Kentucky. The question is, ``How do we make that happen on
more than a test basis, whether it's these two plants or 50
plants, or whatever the number is?''
Mr. Ratafia-Brown. Well, I think that----
Senator Salazar. Dr. Fulkerson----
Mr. Ratafia-Brown [continuing]. Speaks to what Jim was
talking about.
Senator Salazar. Dr. Fulkerson, why don't you respond?
Mr. Fulkerson. You've got to make the economics work. The
problem is that unless there is a carbon tax, or equivalent,
then there's not adequate incentive to build a plant that
sequesters carbon, for example. OK? Without that, you're not
going to have anything happening in the private sector until
you put that regulation in place, which I assume----
Senator Salazar. The carbon limitations--
Mr. Fulkerson [continuing]. That the Congress----
Senator Salazar [continuing]. You think, will drive the
economics to be able to make this more than a test kind of
project in Florida and Kentucky.
Mr. Fulkerson. That----
Senator Salazar. Let me--I've gone over my time by a
minute, and I respect the chairman so much for letting me do
that.
Mr. Fulkerson. That's what you need.
Senator Salazar. So, I yield back, Mr. Chairman.
The Chairman. Thank you very much.
Senator Corker.
Senator Corker. Yes, sir. Again, Mr. Chairman, this has
been an outstanding panel, and thank you for your leadership in
putting it together, along with our ranking member.
I know that one of the components of our biofuels bill
limits the amount of corn to ethanol that's utilized, because
there's concern, I guess, about the food industry and what's
happening there. Yet, what I'm hearing from this panel today is
that by using coal and biomass, we're actually able to take
those same feedstocks, if you will, and cause them to go far
further, putting less pressure on our food industry. Is that
what I'm hearing? Does everybody agree with that?
Mr. Fulkerson. That's what Bob Williams has shown. It's a
very important--very important point. Very important point.
Senator Corker. OK.
I want to share the enthusiasm to plug-ins, by the way, Dr.
Herzog. Let me just--you mentioned, in your written testimony,
how, basically, coal-to-liquid technology uses a tremendous
amount of water. I just wondered how that compared to the
production of corn ethanol or cellulosic ethanol. How does it
compare?
Ms. Herzog. It's a good question. I'm actually not an
expert on the biofuels process, so I'll have to get back to you
on the answer to that.
Senator Corker. Would it be reasonable to assume, though,
that a large amount of water is used in both?
Ms. Herzog. I simply don't know, for the biofuels process.
Senator Corker. Well, it would be interesting for you to
get back to us, or----
Ms. Herzog. Yes.
Senator Corker [continuing]. Someone else, because that was
listed as a strong negative to this, and nobody knows.
Mr. Bartis. The water--this is the water used in coal-to-
liquids. I can----
Senator Corker. That's----
Mr. Bartis. All coal and biomass to liquids, I can----
Senator Corker. Yes.
Mr. Bartis [continuing]. Report on that.
The water use is highly dependent on how you design, and
where you design, your plant. If you design a plant where water
is not abundant, you will put in certain features in that
plant--for example, dry-cooling towers--that cost more, but
that allow you to use much, much less water. So, our estimates
of water use is, it's widely ranging, depending on where you
build the plant. It can be as low as a barrel and a half of
water per barrel of product to as high as seven barrels of
water per barrel of product, depending on what water costs and
its availability.
Senator Corker. OK. As I'm listening to the development of
this technology, I know that in our own biofuels bill we're
depending, in a big way, on cellulosic use. I mean, it's a
technology that is not at commercial use today. Yet, we're
depending upon that to reach these levels that we talked about.
Where would you say we are in the development of coal-to-liquid
technology as it relates to cellulosic technologies? It sounds
to me that we may even be further down the road with this
technology than we are commercially, using cellulosic.
Mr. Bartis. Can I comment on that?
Senator Corker. Yes.
Mr. Bartis. We have looked at both.
Senator Corker. OK.
Mr. Bartis. Right now, I can say that there is not a
doubt--there should be no doubt--that one can take biomass and
put it into a gasifier and make liquids. That is a very, very
low-risk option. We have looked, also, at the concept of taking
cellulosic materials and making alcohols. Right now, we see no
evidence that that option is a very high-risk option. There's a
lot of money being invested in that option by the Government.
It's a very high-risk option. We see no evidence that that
option is going to be less expensive than the Fischer-Tropsch
gasification option for straight biomass. When we add coal,
there's a good chance it may be even less expensive. So, at
this time, we can't say that--we have a near-term option, and
we don't see the long-term option being much less.
Senator Corker. Before you answer, Mr. Fulkerson, let me
just generally ask this question, and you can answer this. I'm
going to run out of time. It seems to me that the way we have
now drafted this bill, we are picking winners and losers. It
seems to me that we might be better serving our country by just
setting standards, as Dr. Herzog has laid out, and many of you,
and letting the market decide. It seems to me that we are
listening to a very viable avenue today. Certainly, I think,
plug-ins is going to be a very, very viable option down the
road. It seems to me that we may be remiss in actually defining
gallonage by certain sources, versus just setting a standard
and letting that gallonage be in the mandate. Would you all
agree or disagree with that?
Mr. Fulkerson. I would certainly agree. I would certainly
agree. In fact, in my testimony, these six policies I talk
about are designed not to be technology-specific. The one
advantage of cellulosic ethanol is that it doesn't require
sequestration. It produces liquids that are carbon-free,
effectively, without sequestration. All the coal and biomass
gasification processes, in order to work as being neutral to
the climate, require sequestration. So, I wouldn't give up on
either one.
Senator Corker. But we could set carbon standards----
Mr. Fulkerson. And that would----
Senator Corker [continuing]. With this, and we could
solve----
Mr. Fulkerson. Just then let the winner take all.
Ms. Herzog. I obviously agree. Just one quick point. On the
biomass co-firing gasification and coal-to-liquids process, we
have one project in the Netherlands, maybe some demo runs have
been done in the United States--it's far from clear to me that
this is viable technology ready to jump out into the
marketplace at this point in time.
The Chairman. Let me just ask a question. I know Senator
Craig is next, and then Senator Murkowski. But just following
up on Senator Corker's point there. In the bill that we
reported out of our committee, we provided--any new plants that
were constructed to provide ethanol from corn, from traditional
feedstocks, would have to be able to demonstrate--that the life
cycle emissions of greenhouse gases were 20 percent less than
in the case of gasoline. It was urged on us, although we didn't
put it in the bill, and we may consider it again on the floor,
that any ethanol produced from advanced biofuels, which was
essentially cellulose-based ethanol, would be at least 50
percent less in emissions--life cycle emissions than
traditional gasoline. Are those the standards that you're
talking about, that if those were in the bill, and applied to
any gas--or any gasoline-equivalent-type fuel, you think that
would be an appropriate way to go?
Ms. Herzog. Yes, we think that's an appropriate standard.
Then super-advanced would be 75 percent below.
The Chairman. OK. All right.
Mr. Fulkerson, did you have a comment on that?
Mr. Fulkerson. Yes. It seems to me that the low-carbon fuel
standard that is being developed in the State of California is
one that should be very carefully considered. What it does is,
it says, look, by 2017, or whatever, the zero--the fraction of
the fuel that you use in your tanks should be 10 percent below
what it is today, and it ratchets down from there. It doesn't
specify a particular technology, it just simply says that the
carbon--the net carbon emissions from that fuel--from the fuel
that's used will be cleaner and cleaner with regard to carbon
emissions----
The Chairman. All right.
Mr. Fulkerson [continuing]. And let whatever technology
produces it----
The Chairman. OK.
Mr. Fulkerson [continuing]. Work.
The Chairman. Very good.
Senator Craig.
Senator Craig. Thank you all very much. This is an issue
that I know a little bit about, but not a lot, and you've added
a great deal to my thought patterns today.
Let me walk you through an interesting scenario that's
happening as we speak. We're debating a bill on the floor of
the U.S. Senate. In that bill is $0.5 billion for timber-
dependent schools and counties. Half a billion a year. OK? In
that bill is also $0.5 billion to fight fires. We spent $2
billion last year fighting fires on our public lands. We've got
$840 million in Interior approps for firefighting, also. So,
we'll spend maybe $1.5 billion fighting fires on our forested
lands. You can run the numbers right now. So, we're going to
spend a couple of billion dollars a year doing something that
we could stop doing if we did something else, but we chose not
do that, as a country.
Here is what we're not doing, if you're interested in
fiber. Biomass. We've got 100 million tons of dead wood on the
floor of our forests today. We're growing 16 million tons a
year that are off limits until Mother Nature takes them away in
the form of a release of carbon into the atmosphere when she
burned 10 million acres last year. Probably the greatest carbon
release in the history of our country occurred last year. But,
because it was natural, it didn't hit anybody's Richter scale
of alarm. But it certainly was carbon.
A healthy forest is a sequestering forest. I'm not sure I
understand this picture very well anymore. We're talking about
switchgrass and farmers and all of that which is available, and
yet, there's 100 million tons laying out there, and 16 million
tons a year grown, and we're subsidizing schools and counties
because we wouldn't let them touch the forests anymore, and now
they're poor. They were once rich. We have tens of thousands of
people out of work who once used to work in our forests.
I'm not suggesting getting back to a green sale program,
I'm talking about going in and thinning and cleaning and going
after the largest quantity of biomass laying out there that
Mother Nature is rapidly converting into carbon and sending it
into the atmosphere again. You're talking about technologies
that, blended with the diversion of $2 billion a year out of
our Treasury that we're currently using to fight fires and
supplement schools into technology--it would seem to make a lot
of sense.
Now, I'm going to suggest you can't get to all of that
wood. Wouldn't be natural to, it wouldn't be environmentally
sound to do so. But it would certainly be environmentally sound
to go after a great deal of it.
What's wrong with that picture?
Yes?
Mr. Fulkerson. There's nothing wrong with that picture. The
residues from agriculture and forests are a great source of
biomass for energy. You can use the gasification process in
order to realize that. So, that's a very good source. There's
nothing wrong with that.
Senator Craig. Doctor.
Mr. Fulkerson. I mean, you don't want to ruin the forests,
but----
Senator Craig. No, no.
Mr. Fulkerson [continuing]. As long as you do it carefully.
Senator Craig. Well, I look across the landscape of my
State today, with thousands of acres dead, bug-killed, can't
touch it.
Mr. Fulkerson. Yes.
Senator Craig. They're not sequestering one ounce of carbon
because they're a dead forest. But a young, viable, diverse
stand forest is rapidly grabbing the carbon and putting it into
the wood.
Yes, Doctor.
Ms. Herzog. One thing I firmly believe is not to comment on
something I don't know very much about, which is forest science
and policy. However, we do have experts in our organization,
and I'd love for them to come in and brief you on this issue in
detail. There are, from what they believe, environmental
impacts from going into forests----
Senator Craig. Sure.
Ms. Herzog [continuing]. And trying to collect all this
waste, biomass material, on the ground. So, we actually have
put together what we believe are decent sustainability criteria
for collecting biomass, which, as I said, I'd love to have our
experts----
Senator Craig. Yes.
Ms. Herzog [continuing]. Come in and brief you.
Senator Craig. No, entry has impact, there's no question
about----
Ms. Herzog. Right.
Senator Craig [continuing]. That. That's a valid thought.
Anyone else wish to comment?
Mr. Ratafia-Brown. Senator, the only thing I'd like to say
is--I'm not a forestry expert, myself, either. This becomes an
economic issue, as far as collection. As I talked, in my
testimony, about energy density of wood products is far less
than something like coal, you pretty much have to try to
increase the density of the material, perhaps on a regional
basis, to make it more available to a larger-scale facility.
Senator Craig. Well, I appreciate that. But I also
appreciate the blending ideas that you're talking about in
these new concepts. Would seem to make a good deal of sense.
Mr. Ratafia-Brown. No, I agree. I think it's a matter of
getting the product to the large-scale----
Senator Craig. Yes.
Mr. Ratafia-Brown [continuing]. Gasification facility. That
is a big issue here. As far as--again, we have a very
distributed----
Senator Craig. Yes.
Mr. Ratafia-Brown [continuing]. Energy source. It's not
like coal, that's very energy-dense. Wood and----
Senator Craig. Right.
Mr. Ratafia-Brown [continuing]. Wood waste is not. You
might want to pelletize it, you might want to do something--
what we call torrefaction----
Senator Craig. Sure.
Mr. Ratafia-Brown [continuing]. To increase the energy
density. But I agree with your comment.
Senator Craig. Thank you.
Did you have a comment, Jim?
Mr. Bartis. We have also looked at this issue, and we
don't--we think small may be beautiful in this case, in that
some of concepts for very large plants that are generally
associated with coal only, make more sense when we get a lot
smaller and look at coal or biomass together. So, this is a----
Senator Craig. Yes.
Mr. Bartis [continuing]. Fantastic opportunity for the
research program to look at whether we can do this at a much,
much smaller scale, comparable to the scale of typical biomass
facilities.
Senator Craig. Yes, David.
Mr. Denton. Yes, I'd just like to add a bit, that biomass
is not biomass, that there are different classes of it, just as
there are different classes of other feedstocks. Wood waste, in
particular, are ones that, because of their nature, may require
some different technologies in gasification than others. I know
when Polk fed eucalyptus, as well as switchgrass, the
switchgrass ran fine. They both gasified fine. The problem was,
wood was, you know, getting involved in some of the check
valves, plugging up things in those----
Senator Craig. It has lignins in it, yes.
Mr. Denton. There are other issues----
Senator Craig. It does create those kinds of problems.
Mr. Denton. So, it will----
Senator Craig. Right.
Mr. Denton [continuing]. Involve some technology
development to probably--but I know there are people looking at
that----
Senator Craig. Yes.
Mr. Denton [continuing]. Right now.
Mr. Ratafia-Brown. David, that was a relatively minor
problem at that facility.
Senator Craig. Yes. Well, they do yield differently. Well,
thank you all very much for that.
One of the problems we're struggling with here--and
certainly the Chairman and I and all of us of this committee
have been involved in it--as we've changed the way we manage
our forests, we have, in a healthy forest policy, attempted to
get in and thin and clean. But there's no value to it. We're
not allowed to place a value on it, nor does little value come
from it. As a result, we subsidize it, we pay for it with your
tax dollars. Therefore, we can't do as much as we ought to be
doing in relation to the general health of our forests. The
opportunity to add value to it, from that standpoint, in these
concepts, seems to be the right dynamic.
But, anyway, thank you all very much for your testimony and
your involvement.
The Chairman. Senator Murkowski.
Senator Murkowski. Thank you, Mr. Chairman. Thank you, to a
very interesting panel this morning. I appreciate all that we
have heard.
I had an opportunity yesterday to sit down with a group of
individuals, primarily from the electric industry, and we were
talking about coal and the technologies, and how we move
forward with the pilot projects, demonstration projects. Of
course, the question that then has to come up is, ``It's great
to be focused on the technology that is coming, and how we're
going to utilize this in the new plants that we build, but what
about the existing facilities across the country?'' I would
like to hear from you this morning whether or not you believe
that we have the technology today to help capture and sequester
from existing plants through our ability to retrofit. If we
don't have the technology, how long until we do have that? What
do we do with these existing facilities out there?
Mr. Denton.
Mr. Denton. Yes. As I mentioned in my testimony, one of the
advantages of industrial gasification--I think this is where
you can maybe get the jumpstart--is that those technologies, by
and large, already require capture of carbon. For example, our
facility in Kingsport, we have to capture the CO2
before it goes forward in our process, any CO2 that
we've formed, primarily due to the shift reaction, where we
actually convert some of the carbon monoxide to carbon dioxide
while forming more hydrogen for our purposes of chemical use.
So, when you do that, you're going to already have carbon
capture, so you've got a nice place in an existing facility
where you have a concentrated stream of CO2 that's
already captured, so it kind of gets you beyond that first step
of two parts of carbon capture and sequestration, the capture
and the sequestration, so you're halfway there. So, I think
that is a good way to get a headstart on----
Senator Murkowski. So, we're there with the capture. Are we
there with the sequestration?
Mr. Denton. Right. On the sequestration, the good thing is
some of the places where, particularly, these industrial plants
are being looked at because they're tied to chemical markets,
which currently exist, for example, a lot of them, along the
Gulf Coast--is your inner region that has, also, a lot of oil
recovery development, so there is the potential to look at
sequestration in enhanced oil recovery applications. The Gulf
Coast also has quite a bit of deep saline aquifer potential, as
well. So, you're located in an area that has some good
sequestration potential.
Senator Murkowski. What if you're not?
Mr. Denton. Well, it depends on where you're located. If
you're not, then you're going to be looking at what other
options you have. If it's coal-based, you may be in a very good
location for enhanced coal-bed methane. So, you have to look at
all the different options that you have in front of you. But, I
think, in most cases, there will be some type of sequestration
option. Then the only issue is the cost penalty to go from the
captured carbon that you already have to sequestration.
Senator Murkowski. Do we need to be doing more here, from
the Federal perspective then, whether it's tax credits or
grants--what should we be doing to make sure that the focus is
not just on the new facilities that may be coming online within
the balance of this next decade, but in retrofitting? Are we
doing enough, from a policy perspective? This goes out to
anybody.
Mr. Denton. I think one of the things that has been talked
about is the--taking some sort of credit--maybe it's a
production tax credit or whatever--to help cover the cost of
that sequestration piece. If you had that in place today, folks
that already have that captured carbon could be doing something
with it and helping advance the technology. So, yes, I think
there is a role for incentives for that.
Senator Murkowski. Anybody else?
Mr. Bartis.
Mr. Bartis. I believe that two things are necessary. First,
and most importantly, is to reduce the uncertainties and pass
legislation that sets up the framework by which carbon dioxide
will be controlled. The sooner we do that, the more we're going
to get new plants properly built, and the more we're going to
have private industry and all of its innovative capabilities
working on the retrofit problem.
Now, with regard to the retrofit problem, that's an
extremely important problem. I presume you're talking about the
huge investment in existing coal-fired power plants. We do not
have technology available today, any means, that allow the
capture of carbon dioxide from those existing plants at
reasonable cost. It hasn't been proven. At any----
Senator Murkowski. How far away----
Mr. Bartis [continuing]. Reasonable cost.
Senator Murkowski. How far away are we from that
technology?
Mr. Bartis. I can't tell you that part. I know it's a topic
of research, and it's an extremely important research topic in
the Department of Energy.
Senator Murkowski. Anybody else?
Mr. Ratafia-Brown.
Mr. Fulkerson. There is a fellow at Carnegie Mellon, Ed
Rubin, that has spent a reasonable amount of his career on
exactly the question that you're asking, and he would be a
really good person to discuss this with. I could certainly put
you in touch----
Senator Murkowski. I'd appreciate that.
Mr. Fulkerson [continuing]. With him. I think he can help.
Senator Murkowski. Great.
Mr. Ratafia-Brown.
Mr. Ratafia-Brown. Well, let me just say, as far as the
technology goes, I agree with Jim, the problem with the capture
from an existing coal-fired power plant is that the
CO2 concentration in the plant flue gases is too
low. It's not nearly as high as it is in the gasification
facility. But there are some ways that one could introduce
biomass. It's already done. You want to introduce biomass, like
wood products, directly into a boiler, or you--or you use a
gasifier prior to the boiler, you gasify the material, and you
feed this gasified material right into a coal-fired boiler, so,
thereby, gaining the benefit of the biomass use, which
effectively reduces your CO2.
The other technologies that are being worked on are
basically using oxygen instead of nitrogen--instead of air, I'm
sorry--as the oxidant for these power plants. If you use
oxygen, you end up with just CO2, and, therefore,
you have a much higher concentration of CO2, which
will much more effectively allow us to sequester--or capture
the CO2 from existing power plant flue gas. There
are a variety of technologies that are being researched through
the Department of Energy for this purposes.
So, there are the means. Again, it's a matter of cost-
effectiveness and providing more funding for that R&D, but it's
doable.
Senator Murkowski. Thank you.
Mr. Chairman, I would suggest that, as we move forward in
these areas--there's been a lot of focus on this new technology
in the demonstration projects, which is very, very important,
but I think we also need to remember as is pointed out, the
incredible infrastructure that is already in place, that
probably has decades of useful life in them. But if we can't
allow for some form of retrofitting, we're not going to be
seeing the reductions in emissions that we would like. So, I'd
like to work with you on that.
The Chairman. No, that's a very good point. I appreciate it
very much.
Senator Tester, go right ahead.
Senator Tester. Thank you, Mr. Chairman. I appreciate you
holding this hearing. I appreciate the panel to be there. I
apologize, I got out of doing the floor thing for a bit to come
ask you guys questions.
This issue is critically important to me and--quite
frankly, because of the coal reserves we have in Montana. I
think there's tremendous opportunity. When I first heard about
the coal-to-liquids, I was really, really enthused. Then, the
issue of CO2 started coming up more and more.
I just wanted to ask--as coal-to-liquid related to coal-
fired electricity, I might add, it wasn't at a zero-based
standpoint. Let's start at the end and work back--if you've got
a gallon of petroleum diesel fuel and you've got a gallon of
diesel created from coal, and it's burnt in the same vehicle,
do they emit the same amount of CO2?
Go ahead Mr. Fulkerson.
Mr. Fulkerson. The coal-derived liquids would vent twice as
much CO2, approximately.
Senator Tester. I'm not talking about the process before,
in the manufacturing of the fuel, I'm talking a gallon to a
gallon burned in the vehicle, we're not doing anything----
Mr. Fulkerson. Oh. Oh, gallon for----
Senator Tester. Gallon-to-gallon.
Mr. Fulkerson. Same amount. Same----
Senator Tester. Same amount, OK. As the process goes--well,
step backward another time. Now we've taken the coal. It's in
gas form. It's my understanding it goes from gas form to liquid
form. Is that where the bulk of the CO2 is
generated? It is.
So, Mr. Denton talked about the Eastman Chemical Company.
You're taking it from coal to gas, and using it in natural gas
form for your processes. How much CO2 is emitted in
that process, compared to coal-fired electrical generation?
Mr. Denton. Well, in our case, it's a lot less, because
keep in mind, we convert a good proportion of the carbon that
comes into the feedstock into actual product.
Senator Tester. OK.
Mr. Denton. We're trying to convert that carbon into
product. We make, as a sidestream, some CO2, but
that is captured by the process.
Senator Tester. That's good.
I want to step over to Mr. Fulkerson again on--I believe
his name is Bob Williams that you're taking the place of. You
did a fine job in your presentation, I might add; he's got
nothing to be ashamed of there. I couldn't crack the part about
biomass negative value and carbon resulting in a negative value
in carbon emissions. In other words, in my head, if I plant a
tree, and that tree gets big, it absorbs a lot of carbon in
that process; I've made a difference in global warming. Now, if
I take that tree and I cut it down and I burn it, I haven't
done anything from the time I started the tree until I burn it.
So, how--and I assume that the process of mixing biomass with
coal includes burning that biomass. How can it be a negative
value?
Mr. Fulkerson. Well, it's negative, just--the fact is that
it takes carbon out of the air to grow the tree or----
Senator Tester. But don't you release it again in the
burning?
Mr. Fulkerson [continuing]. Switchgrass, or whatever,
prairie grass, right?
Senator Tester. Right.
Mr. Fulkerson. OK. Now, you take carbon, and you now
sequester it. You put----
Senator Tester. Yes.
Mr. Fulkerson [continuing]. Put it through the process, and
you sequester it.
Senator Tester. Oh, I see what you mean. You're talking
about at the other end. The----
Mr. Fulkerson. Right.
Senator Tester. OK. So, the question I have is, and I think
you said this, so I think you're going to tell me what I
already know, but I want to make sure--``Do we have the
capability right now to capture carbon on a large-scale basis
with the current technology we have?''
Anybody can answer it.
Mr. Fulkerson. Yes, we do have the capability of doing it.
But we don't have any large-scale----
Senator Tester. Demonstrations.
Mr. Fulkerson [continuing]. And storage of carbon from
present facilities in the United States.
Senator Tester. Gotcha. The----
Go ahead.
Mr. Bartis. We have opportunities to capture carbon from a
few plants. The primary opportunity is to use it in enhanced
oil recovery. There is a good chance--and there doesn't seem to
be any showstoppers available--that we can do geological
storage of carbon dioxide. There's also approaches to store
carbon--well, I guess coal bed--you can store it in coal seams.
So, there's a very low-risk approach, but it's never been
demonstrated.
Senator Tester. OK.
Mr. Bartis. All right? That demonstration is expensive, but
absolutely critical.
Mr. Fulkerson. Senator, there is a demonstration right near
you, in North Dakota, and that's the Great Plains process,
which sequesters--which doesn't sequester, but it separates
out--it sends 160 million cubic feet per day to Saskatchewan to
use for enhanced oil recovery.
Senator Tester. I've gotcha.
Go ahead, Mr. Denton.
Mr. Denton. Yes. In terms of carbon capture and
sequestration, as I mentioned, it is technically feasible.
There is no problem. We've been capturing carbon for two
decades. As Senator Dorgan mentioned that North Dakota
gasification, they are actually putting CO2 in the
ground from enhanced oil recovery. I think the real problem is
beyond that. When you beyond enhanced oil recovery, there are
issues, beyond technical feasibility, that haven't yet been
addressed, and that's stuff like, Who owns the rights, the
property rights, to that? Who takes the ultimate liability?
What are the requirements by EPA of permitting, say, putting
CO2 into a saline aquifer? There's just a whole lot
of other issues around that, that have not been addressed yet,
that are the problems right now, not the technical feasibility.
Senator Tester. So, what you're saying is, we have the
technical feasibility to be reasonably sure--because nothing's
ever 100 percent, besides death and taxes--but reasonably sure
that that CO2 is going to stay in the ground if we
sequester it there?
Go ahead.
Mr. Bartis. We should be optimistic that that will be the
case. That's for one reason--that's the primary reason why RAND
suggests we do something with regard to coal-to-liquids. But,
until we have multiple large-scale demonstrations----
Senator Tester. Gotcha.
Mr. Bartis [continuing]. We're not going to be there.
Senator Tester. OK.
Mr. Bartis. None are planned.
Senator Tester. OK.
I want to talk about water for just a second. I apologize
if these are repetitious questions. I want to talk about water,
and how much water is required to produce a gallon of coal-to-
liquids. Can you give me any idea on how much that would be?
Mr. Bartis. Yes, I don't----
Senator Tester. For, let's say, gallon-to-gallon.
Mr. Bartis. I'll repeat what I said earlier.
Senator Tester. OK.
Mr. Bartis. Gallon to gallon, it depends on what you do
when you design the plants. If you design the plants in an area
that is--that doesn't have lots of--has limited supplies of
water----
Senator Tester. Yes.
Mr. Bartis [continuing]. You're going to put in certain
design features that save water. If you design the plant where
water is abundant, you won't put those features in.
So, our best estimate is, for all--the locations that are
poor in water, probably 2 gallons of water per gallon of fuel.
In areas that are very rich in water, possibly up to 7 gallons
of water per gallon of fuel.
Senator Tester. Does it cost more to--I would assume it
would cost more to build the plant that would be water-
restrictive.
Mr. Bartis. Yes.
Senator Tester. What does that do for competitiveness, as
far as barrel of oil?
Mr. Bartis. I have not looked at those----
Senator Tester. OK.
Ms. Herzog.
Ms. Herzog. Yes, I just wanted to--I agree that, obviously,
you will have a range, and the technology can be done to reduce
water use. Our estimate is, on average, about 5 gallons per----
Senator Tester. OK.
Ms. Herzog [continuing]. Per ton of coal, which completely
fits into that range.
Senator Tester. Yes.
Ms. Herzog. But I'm perhaps a little less optimistic that
the best plants will be built in the right places----
Senator Tester. Yes.
Ms. Herzog [continuing]. As I'm sure you're aware.
Senator Tester. Well, I can tell you that, you know, a lot
of people have died over water over our history, and it's a
critically important piece of survival.
About a month ago, maybe less, with the bill that's going
to be on the floor, there was an amendment offered to require--
it was a mandate for synfuels--coal-to-liquids. I can't
remember what the amount was, but it was fairly significant.
There was some difference of opinion as to whether that's the
right direction to go, whether to require a mandate first, or
to--well, I don't want to put words in your mouth. But what I'm
hearing you folks say--and just tell me if this is correct--if
you were in my position, the first step you would do, from what
I'm hearing, is that you would create a large-scale
demonstration project, maybe two or three of them? Is that what
I'm hearing? Or am I hearing something else?
Go ahead.
Ms. Herzog. I'm sure others will jump in with some----
Senator Tester. Yes.
Ms. Herzog [continuing]. Technical details, but the--it was
21 billion gallons of liquid coal by 2020--
Senator Tester. Right, that was it.
Ms. Herzog. It's approximately 40 medium-sized plants. It
was a requirement to be equivalent to gasoline. The key part is
the standard associated with the plants. The demonstration
plants could make sense, but they have to be doing what we need
them to do, which is actually better than gasoline. They have
to be doing better, in greenhouse gas life cycle emissions,
than gasoline. We would say 20 percent or more.
Senator Tester. Good point.
Further comments on that point?
Mr. Bartis. We have looked at this issue, and our view is
that we--it's important that we go ahead with a few. I wouldn't
call them ``demonstrations,'' but I believe it's very important
that we go ahead with a few, where ``a few'' is up to more
politically astute persons than I. But it's important to get
progress in this area.
The reason we're saying ``a few'' is that we haven't--we're
not certain about all--how carbon is going to be managed, and
we're not certain about the prices of these plants. Now, it's a
little unfair that I'm only talking about coal, so to be--to
put this in proper context, this all--this same recommendation
by RAND would also apply to any incentive that is calling for
large amounts of any unconventional fuel, including ethanol
fuels. We would say it's premature to do that.
Senator Tester. OK. Well, you know, it's unfortunate that a
person doesn't know more about stuff than you do. You know, as
a farmer, I take pride in knowing a lot of stuff about a
little, when it comes to making hay or harvesting crops or
fixing a combine or whatever. I've always approached this coal-
to-liquids from a standpoint that we need to build a
foundation, and that foundation revolves around carbon capture
and carbon sequestration. It's easy to talk about. I mean,
that's pretty straightforward. The question is, ``How do you
get there? How do you have grants that are applicable for
carbon capture and sequestration?'' How do you give tax
credits? How do you get there? How do you get that research
going with the sense of urgency that I truly feel?'' Especially
after being in Glacier Park last weekend and seeing what's
going on there, from a climate standpoint.
Mr. Denton. I think I mentioned earlier, I think the
quickest way still is through some of the industrial
gasification opportunities where you already have carbon
captured. You don't have to do this, all of it, in an
integrated facility. If you're wanting to evaluate carbon
capture and sequestration, go to where you already have carbon
captured in a cheap way to get that sequestration step proven.
If you want to illustrate coal/biomass, you go to where it
makes sense to do that. Then you start putting those pieces
together, and maybe--and I think there is a value to--at some
point, of having a few--as you mentioned--a few of these coal-
to-liquids plants with the right kind of configurations to
evaluate what you want.
Senator Tester. Yes, go ahead.
Mr. Ratafia-Brown. I would just like to say, with regard to
investment tax credits, we run the National Energy Modeling
System, the same one that EIA runs, and what I have found with
advanced technologies is that, when you do provide that
investment tax credit, that incentive, that you can get much
earlier penetration of advanced technologies, at least get them
in to the marketplace, well before they might otherwise because
of that advantage of the lower cost and being able to compete
better.
Senator Tester. OK.
Mr. Fulkerson. You've got to--if you want to solve the
problem, you've got to tax carbon emissions. You've got to put
an incentive there that sets the market. I assume that that's
what all the bills in Congress, and all the debates, are
primarily about now, is----
Senator Tester. Carbon taxes?
Mr. Fulkerson. Yes. Well, carbon----
Senator Tester [continuing]. Make that----
Mr. Fulkerson [continuing]. Tax, cap-and-trade, whatever.
But you've got to put the policies in place that will make
people be inventive about the ways in which to meet it.
Senator Tester. So, what you're saying, until industry gets
to a point where they're between a rock and a hard place,
they're going to coast?
Go ahead. I mean, you deal with them----
Mr. Fulkerson. That's what I would do.
Senator Tester. OK.
Mr. Bartis. I'd like to build upon that statement, though.
I mean, I fully agree that it's very important that we put the
framework out there. But let's also remember that we have a
problem with importing oil from----
Senator Tester. Oh, yes.
Mr. Bartis [continuing]. OPEC. We have looked at carbon
taxes, or cap-and-trade, where--on valuing carbon dioxide,
basically. There is low-hanging fruit out there. The low-
hanging fruit is coal-fired power plants, and any centralized
use of coal, including these coal-to-liquid plants. But if you
put the kind of value on carbon dioxide that motivates capture
from these large facilities, you haven't done anything with
regard to influencing the problem of imported oil. That carbon
tax, a $30 carbon tax, or a $30 cap-and-trade system, that's
only going to raise the price of oil about--gasoline about 30
cents. That's not going to motivate much. It's not going to
motivate much conservation. So, you need to go beyond just
looking--there are two different problems. There's a
CO2 problem, and there's also an energy problem.
Senator Tester. Yes, I gotcha there.
Ms. Herzog. Yes. No, I completely agree that just putting a
cap on the emission state of transportation fuels won't
necessarily drive us to cleaner fuel or vehicle technology.
That's why we believe that you actually also need complementary
policies to make sure that you expand the fuel sources to be
more diverse while meeting certain standards. You can have an
oil-reduction standard, you can have a greenhouse gas standard.
This would be a low-carbon fuel standard, which would ratchet
down over time. This would be greenhouse gas tailpipe emission
standards, which would make our vehicles cleaner, as well.
Senator Tester. Go ahead, Mr. Denton.
Mr. Denton. Yes, in terms of the topic of taxing carbon, I
do want to throw a word of caution here, that, particularly in
our industry, we are in a global industry, and we're seeing
this daily. We're seeing jobs from the United States go
overseas because we are not competing on the energy cost of
living in the United States. If you tax, or you do anything
that puts a cost to just the U.S. industry, what you're going
to see is the actual opposite of what I think you want, that
you're going to see those jobs go overseas to operate
facilities that are not going to do any of this, and put the
emissions into the air. So, we have to be careful about it. I
think, start with incentivizing, getting some of these going,
until you can get the market in place, get some of these other
issues in place, and see a global marketplace that addresses
that issue.
Senator Tester. I understand.
Mr. Ratafia-Brown. Yes, I'd like to go back to Senator
Murkowski's comment about retrofitting. If you put a heavy tax
on carbon, generally what happens is--it's the electricity
sector that takes the brunt of it. They are the most elastic,
in terms of the ability to control. Again, I've run so many
cases of energy bills, looking at different carbon taxes, and
what happens is those existing power plants end up being
retired very quickly, to the detriment of the industry.
Senator Tester. I appreciate all of your comments. I will
tell you that I think the last thing that anybody on this
committee wants to do is increase taxes. But I will also tell
you that there has to be a sense of urgency, that I feel in
this body, but I don't necessarily feel out in the hinterlands
amongst industry. That's not a bad thing about--I'm not
badmouthing industry at all. I'm just saying that the folks
that are doing the carbon capture, I think, have a tremendous
opportunity to make a ton of money by taking that technology,
and refining it, and taking it throughout the world.
I hear what each one of you are saying, and I think they
all have merits. I appreciate the comments from each one of
you. I just want to say this. I appreciate you guys taking the
time and coming up here and talking to us truthfully on your
lifetimes of experiences dealing with coal and coal-to-liquids
and coal-to-gas and the environment. I think we all understand
the tremendous opportunity there is here, and also what a
tremendous challenge it is to try to make this country energy
independent, while satisfying the environmental concerns that
are out there.
So, thank you very much.
The Chairman. Thank you.
Thank you all, again, for coming. This was an excellent
hearing, and we appreciate your good advice.
[Whereupon, at 11:40 a.m., the hearing was adjourned.]
APPENDIX
Responses to Additional Questions
----------
Responses of David Denton to Questions From Senator Bingaman
Question 1. You testified about the relative ease, compared to
IGCC, that industrial gasification facility could get to 90% capture of
feedstock carbon. This would seem to present a real opportunity to make
progress on lifecycle emissions compared to natural gas as a feedstock
if biomass is incorporated in a substantial way. How much opportunity
is there to incorporate biomass into the process?
Answer. Gasification technology is relatively feedstock flexible
and thus certainly has potential for incorporation of biomass as a
feedstock. But this potential is dependent upon the type of biomass and
upon the specific gasification technology that is used. For example,
biomass used in slurry-fed gasifiers must be in a form suitable for use
in the high-pressure slurry pumps used to feed the gasifiers. One must
also keep in mind that biomass feedstocks have only been demonstrated
to date as relatively minor co-feeds in commercial-scale gasifiers.
Feed of significant quantities of biomass to a commercial-scale
gasifier would require a step increase in overall project risk, an
increase that may be difficult to project finance until a few
commercial-scale demonstrations have occurred. For example, it is
highly likely that biomass and coal feedstocks, if co-fed to a
gasifier, would react at different rates (i.e., one of the feedstocks
would react with oxygen faster than the other, resulting in over-
oxidation of one feedstock and under-oxidation of the other), making
control of outlet syngas composition more difficult. Feed of
significant quantities of biomass to commercial-scale gasifiers also
faces other market and risk issues that have not yet been resolved,
such as obtaining long-term (20+ years) assured supply of large
quantities (up to thousands of tons per day) of adequately dried and
stored biomass within a reasonable (50-mile or less) radius of the
gasification facility and at an acceptably low long-term feedstock
price. Industrial gasification projects already face multiple siting
issues--e.g., being close to an inexpensive coal/petcoke feedstock
source, close to markets for the desired end products and to acceptable
outbound logistics, and close to suitable long-term carbon dioxide
sequestration reservoirs. Adding a further requirement to be sited near
suitable biomass feedstock supplies could severely limit the options
for siting such facilities. However, to the extent that selected sites
can accommodate biomass feedstocks, opportunity does exist to pursue
such co-feeds over time as the above-mentioned market and risk issues
are addressed.
Question 2. If you do feed biomass into a coal gasification process
what kind of reductions in lifecycle emissions do you estimate would be
achievable as compared to other fossil fuel feedstocks?
Answer. Lifecycle gasification emissions of any feedstock are
dependent upon the composition of the feedstock and upon the design of
the syngas cleanup process. These variables are somewhat independent,
so it would be difficult to say what, if any, overall lifecycle
emission reductions might occur by co-feeding biomass. To the extent,
however, that any carbon dioxide formed in the process is sequestered,
the overall lifecycle emissions of carbon dioxide to the atmosphere
would be reduced if one includes the extraction of carbon dioxide from
the atmosphere by the growing biomass.
Responses of David Denton to Questions From Senator Sanders
Question 3. The Intergovernmental Panel on Climate Change has
recently issued its Fourth Assessment Report Summary for Policy Makers.
In that Report they concluded that the evidence that global warming is
real and caused by humans is unequivocal. The MIT study, ``The Future
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase
the cost of electricity from coal by 20%, but an aggressive energy
efficiency campaign could be conducted, so that less electricity is
used, bringing our electricity bills down by 20% or more. What do you
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in
the near term and long term?
Answer. Eastman has not yet had occasion to conduct a detailed
calculation of the cost of diesel and synthetic natural gas with CCS.
There have been studies reported by others, such as the DOE, which
reference such cost comparisons. However, the percentage of added cost
for CCS would be expected to be less for products such as diesel and
synthetic natural gas (methane) than for electric power, because the
processes required to produce diesel fuel and methane, just as with
other industrial gasification processes, already incorporate capture of
most of the carbon dioxide formed in the process, whereas capture of
the carbon dioxide would be an added step for production of electric
power. As technologies such as coal-to-liquids and coal-to-methane are
commercialized and deployed, one can reasonably expect the costs to
produce such products to drop over time as the processes are improved
and first-of-a-kind risks are reduced.
Question 4. I join Senator Murkowski in her concern about the need
to retrofit our existing coal fired power plants to address the issue
of carbon capture and storage. Some of the testimony suggested that
adding ``oxyfuel'' to these older plants would be the best path to take
as this burns pure oxygen, instead of outside air, producing a carbon
dioxide-rich exhaust stream, with little or no NOX, so the
CO2 is more concentrated and easier to capture for
sequestration. Do you have any information on the ease/feasibility of
retrofitting older coal plants or other coal-burning industrial
facilities with ``oxyfuel''?
Answer. Eastman has not directly evaluated ``oxyfuel'' combustion
as a retrofit for existing coal-fired power plants. However, one could
reasonably assume that ``oxyfuel'' retrofit of existing boilers could
be problematic because most of these boilers were not designed to be
air-tight. Any in-leakage of air to older boilers would introduce
nitrogen diluent into the system and defeat, to some extent, the
purpose of adding ``oxyfuel'' combustion. So the success of ``oxyfuel''
retrofit of existing boilers could be dependent upon how well the
boilers can be sealed to prevent such in-leakage of air. Also, it is
not at all clear that introduction of pure oxygen to boilers would not
result in substantial increases in NOX emissions from such
boilers (due to higher flame temperatures) without the addition of a
substitute diluent such as recycled carbon dioxide. In addition, one
would still need to remove sulfur and other contaminants from the
exhaust gas prior to sequestration of the carbon dioxide (for most such
applications), and it is unclear what retrofits would be required to
those existing downstream cleanup steps (such as scrubbers) to enable
``oxyfuel'' retrofit of the main boilers. However, the proponents of
``oxyfuel'' combustion are working to try and address all of these
issues.
Responses of David Denton to Questions From Senator Salazar
Question 5. It appears from the written testimony, that liquid
fuels produced from coal combined with biomass can result in lower
greenhouse gas emissions than conventional gasoline. What are the
technology hurdles to overcome in mixing biomass with coal to produce
liquid fuels? Has the combination of biomass and coal been used at any
commercial plant? What is a realistic percentage of greenhouse gas
emissions compared to petroleum that we can expect to achieve?
Answer. See the response to question No. 1 above.
Question 6. Even with the use of biomass, there are still
substantial volumes of CO2 that must be captured and safely
stored. Are there any recommendations this panel has on where to locate
CTL facilities to facilitate the storage of CO2?
Answer. To facilitate the storage of CO2, one must be
near an adequately-sized geologic reservoir suitable for long-term
storage of the CO2. The DOE (Office of Fossil Energy/NETL),
through cooperation with its Regional Carbon Sequestration
Partnerships, has recently developed a Carbon Sequestration Atlas that
identifies a number of suitable geologic reservoirs across the United
States and Canada. Obviously, the most economic CO2 storage
alternatives would involve sequestering the CO2 in
productive applications such as enhanced oil recovery or enhanced coal
bed methane.
Question 7. Can you discuss the water requirements for a CTL plant?
Are there opportunities for reusing/recycling water in the process?
Answer. Eastman has not yet calculated the water requirements for a
CTL plant. Depending on the composition of various water streams, there
may be opportunities to recycle or reuse some of the water streams,
such as in preparation of coal-water slurries to feed to the gasifiers.
However, such recycle or reuse may require treatment of the water
stream to remove specific impurities that might otherwise buildup in
the recycle stream.
Question 8. The auto industry has developed plug-in electric
hybrids, and this committee has heard testimony about all-electric
cars. Can you discuss the advantages and disadvantages of using coal to
produce liquid fuels vs. using coal to generate electricity to charge
batteries for electric cars and hybrids?
Answer. Both alternatives offer opportunities to utilize coal to
reduce our dependence on foreign oil for transportation. Both
alternatives will likely be required to utilize coal to address energy
security. The decision that determines which alternative is preferred
may depend on whether, for a specific site and application, it is more
cost effective to logistically transport liquid fuels or to transmit
electric power from the gasification facility. It also depends on the
ultimate transportation mode--for example, there are no current
electric-powered commercial or military aircraft (except for small
drones). From a greenhouse gas emissions standpoint, the less complex
alternative may be to produce electric power coupled with CCS because
it avoids the added complication of co-feeding biomass to achieve
emissions reductions below that of conventional fuels production and
use. But as mentioned above, both alternatives will be required to
adequately address our overall energy security needs through
utilization of coal.
Responses of David Denton to Questions From Senator Domenici
Question 9. How important is a secure domestic source of feed stock
to the chemical industry in this country?
Answer. If the chemical industry is to survive in this country, it
must have a long-term secure source of low, and relatively stable,
priced feedstocks and energy. Industrial gasification of domestic coal,
petroleum residues (such as petcoke), biomass, and recycled secondary
materials can help address this need. The run-up in energy prices, and
the resultant volatility in energy prices, from natural gas and
petroleum since the year 2000 has contributed to the loss of over
100,000 jobs in the U.S. chemical industry alone (an overall job
reduction of over 10% in that timeframe). Other energy-dependent
industries, such as fertilizers, glass, steel, and forest products,
have also been dramatically impacted. These high-technology and well-
paying jobs are being exported to other countries that have lower and
more stable energy and feedstock costs.
Question 10. The National Energy Technology Laboratory has
indicated it is technologically and economically feasible to produce
22,000 barrels of liquid naphtha (NAP-THA) per day and 27,800 barrels
of diesel product per day from 24,500 tons of Illinois No. 6 coal while
producing 124 mega-watts of electricity to the grid and capturing
32,500 tons of carbon dioxide per day.
Answer. It is certainly technically feasible to gasify coal and co-
produce diesel, naphtha, and electricity while capturing carbon
dioxide. Economic feasibility depends on a number of factors, not the
least of which are the competing price of conventional diesel fuel and
the costs associated with capital project construction. Appropriate
government incentives can be effective at reducing the impact or
uncertainty of these economic variables.
Question 11. Can you give us an estimate of the total domestic
demand for naphtha from the chemical industry in this country?
Answer. According to the DOE's Energy Information Administration,
over 100 million barrels of naphtha were supplied for total U.S.
petrochemical feedstock uses in 2006 (over 300,000 barrels of naphtha
per day).
Question 12. Assuming questions about further reducing carbon
dioxide could be answered, at approximately what price per gallon would
the naphtha have to be produced from a coalto-liquids process for the
Chemical Industry to shift away from foreign natural gas or foreign
LNG?
Answer. The price would have to be sustained at some discounted
level below the projected long-term market price of naphtha and/or the
market-equivalent price for naphtha substitutes such as natural gas or
LNG. It would also have to be at a price sufficient to enable the U.S.
chemical industry to be competitive with global sources for the
naphtha-derived end products. Naphtha prices (for petrochemical
feedstock uses) typically track crude oil prices with about a 5% to 10%
added cost (for example at an oil price of $40 per barrel, naphtha
could be expected to have a market price of around $42 to $44 per
barrel).
Responses of David Denton to Questions From Senator Thomas
Question 13. What specific technology gaps need to be closed by DOE
and private industry working together to reduce the technical and
economic risk of coal-derived fuel plants?
Answer. The most important technology gaps are to demonstrate CTL
technologies using actual U.S. coal-based syngas, to reduce the overall
capital cost of CTL processes (including air separation, gasification,
syngas cleanup, carbon capture, and any syngas-tofuels conversion
technologies), and to improve the overall fuel yields of CTL processes.
Question 14. In addition to financial incentives, in the form of
tax credits, appropriations, and other tools at Congress' disposal,
what regulatory approaches do you believe can be taken to advance the
development of a domestic coal-derived fuel industry? Please address
not only liability issues associated with carbon dioxide sequestration,
but permitting of the actual plants, obstacles to construction of
infrastructure, and other issues that you believe could be addressed
from a regulatory, rather than a financial, standpoint.
Answer. Regulatory incentives could include certification of CTL
fuels, accelerated permitting of CTL plants, long-term liability for
geologic storage of carbon dioxide, and requirements for utilization of
CTL fuels in the transportation sector (civilian, military, and
strategic petroleum reserves).
Question 15. Does the use of a FT coal-derived diesel product have
an improved footprint for nitrous oxide, particulate matter, sulfur
dioxide, volatile organic compounds, and mercury over traditional
sources of diesel? Please quantify the per gallon differences for
criteria pollutant emissions that would result from consumption of a FT
coal-derived diesel product versus traditional, petroleum-derived,
diesel fuel.
Answer. Fischer-Tropsch coal-derived diesel would be ultra-low in
sulfur content and mercury and would bum cleaner than conventional
diesel fuel (lower NOX, PM, etc.). The Department of Defense
has compared emissions of F-T jet fuels versus conventional jet fuels.
Similar improved emission results should be expected from F-T diesel
fuels.
Question 16. China is aggressively pursuing development of a CTL
industry. If the U.S. does not, is it possible that we will be
importing CTL fuels from China in the future?
Answer. That is certainly a possibility, although current Chinese
CTL production is targeted at satisfying their rapidly-growing domestic
market.
Question 17. What implications does this have for U.S. national
security?
Answer. Increasing reliance on foreign sources for our supplies of
petroleum, natural gas (LNG), fuels, chemicals, fertilizers (i.e.,
food), and other industrial products has definite implications for our
overall national security, including our energy security, food
security, job security, and technological/industrial/manufacturing
superiority. Without utilization of our abundant domestic resources,
such as coal via gasification, all of these are at increased risk over
the long-term.
Question 18. We are told that Fischer-Tropes fuels require no
modifications to existing diesel or jet engines, or delivery
infrastructure including pipelines and fuel station pumps. Is that
true?
Answer. Eastman has not evaluated this issue sufficiently to
comment. However, it is known that South Africa has successfully used
F-T coal-derived fuel blends for over half a century to help address
its transportation needs utilizing conventional engines and
infrastructure.
______
Responses of William Fulkerson to Questions From Senator Bingaman
Question 1. The facilities that are commonly talked about here are
very large and use significantly more coal than a comparable coal-fired
power plant. If one were to blend in biomass on the levels you advocate
how much biomass are we talking about for a typical plant? Is it
realistic to assume enough could be produced in the area of the
facility?
Answer. This is a good question. Bob Williams and his colleagues at
Princeton have made detailed calculations for a plant supplied by
switchgrass and Illinois bituminous coal that uses oxygen blown
gasification and captures and stores CO2 derived from both
the switchgrass and the coal (CCS). The size of the plant they
considered would supply 1030 MW of synthetic gasoline and diesel (about
18,000 barrels per day of gasoline equivalent) plus 460 MW of electric
power. These products would be manufactured from 2200 MW [7700 dry
tonnes/day (dt/d)] of coal plus 900 MW (4500 dt/d) of switchgrass. To
grow this much switchgrass would require about 500 square miles of land
assuming a yield of 10 dry tonnes per hectare per year (t/ha/y) and an
annual plant capacity factor of 80%. This would be 15% of the land
within a 33-mile radius of the plant. As you can see building and
operating such a plant would be no small undertaking, but the biomass
growing and gathering effort would appear to be quite manageable.
A key characteristic of this plant is that the net fuel-cycle-wide
greenhouse gas emission rate associated with producing and consuming
the synthetic liquid fuels would be about 27% of the rate for the
petroleum-derived fuels displaced. In addition, the co-product
electricity is produced in a high-efficiency combined cycle power plant
at a carbon emission rate that is only about 10% of that for a new coal
power plant that does not have CCS.
Alternatively, Williams points out that mixed prairie grasses grown
on carbon-deficient soil might be used as the biomass feedstock. In
this case carbon is taken from the atmosphere both to grow the
harvested prairie grass and to build up significant additional carbon
in the soil and roots. (See Tilman, David, et al. Science, 314, 1598-
1600, December 8, 2006). Taking into account this extra sequestration
Williams calculates that the amount of biomass required to reduce to
zero the fuel cycle wide GHG emission rate associated with the
production and consumption of the liquid fuels produced in such a plant
would be about 3400 t/d requiring about 390 sq mi of land to grow. For
such a plant the biomass and coal inputs account for 21% and 79% of
fuel energy input, respectively. The energy and carbon flows for this
system are shown in the attached figure.
Williams' bio-coal system has the flexibility to accommodate a wide
range of cellulosic feedstocks, including crop residues (e.g., corn
stover and wheat straw) and forest product industry residues (e.g.,
logging residues) as well as dedicated energy crops.
The coal gasifier and Fisher-Tropsch synthesis parts of the
technology are fully commercial. The biomass technology is less well
developed. Use of separate gasifiers for biomass and coal at the
conversion plant may ultimately prove to be the least-costly approach;
the needed large-scale biomass gasifiers for this approach are not yet
commercial but could be commercialized by 2015 with a focused
development effort. For the near term, some commercial coal gasifiers
can be co-fired with modest amounts of biomass. In The Netherlands, the
Nuon IGCC power plant at Buggenum has been fired for about a year with
biomass accounting for 11% of the fuel energy input along with coal.
Plans are to increase the percent of energy input from biomass to 20%
during 2008.
The biomass used in these systems will be much more costly than the
coal (on a $ per million btu basis), and that will be good for the
farmer. Nevertheless the calculations carried out by Williams and his
colleagues show that if GHG emissions were valued or taxed at $25 to
$30 per tonne of CO2 equivalent, these zero or near-zero GHG
emitting Fisher-Tropsch liquids could be produced from coal + biomass
with CCS at lower cost than Fischer-Tropsch liquids derived from only
coal with either CO2 vented or with CCS. This remarkable
economic finding arises from the huge credit realized from subsurface
storage of photosynthetic CO2 that offsets the coal-derived
carbon emissions from the plant and from combustion of the fuel
products.
An additional important benefit of this bio-coal fuels scheme is
that more liquid fuel is produced per Btu of biomass than from the
cellulosic ethanol process, for example--in fact, 2-3 times as much.
This is due primarily to the fact that most of the energy to run bio-
coal plant comes from the coal. In the manufacture of cellulosic
ethanol nearly all the energy to produce ethanol comes from the biomass
and hence more biomass energy is required per Btu of fuel product.
Since the limiting factor in the production of liquid fuels from
biomass is the biomass resource, the comparatively high productivity of
the bio-coal process is very important. Additionally less coal energy
is used which reflects back into less mining and associated environment
and safety impacts.
references
Williams, Robert H., Eric D. Larson and Haiming Jin, ``Synthetic
fuels in a world with high oil and carbon prices,'' 8th International
Conference on Greenhouse Gas Control Technologies, Trondheim, Norway,
19-22 June, 2006 and published in the Proceedings of the Conference.
Williams, Robert H. (Princeton University), Stefano Consonni and
Giulia Fiorese (Politecnico di Milano, Milan, Italy), and Eric Larson
(Princeton University), ``Synthetic gasoline and diesel from coal and
mixed prairie grasses for a carbon-constrained world,'' 6th Annual
Conference on Carbon Capture and Sequestration, Pittsburgh, PA, 7-10
May 2007, to be published in the Proceedings of the Conference.
Responses of William Fulkerson to Questions From Senator Sanders
Question 2. The Intergovernmental Panel on Climate Change has
recently issued its Fourth Assessment Report Summary for Policy Makers.
In that Report they concluded that the evidence that global warming is
real and caused by humans is unequivocal. The MIT study, ``The Future
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase
the cost of electricity from coal by 20%, but an aggressive energy
efficiency campaign could be conducted, so that less electricity is
used, bringing our electricity bills down by 20% or more. What do you
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in
the near term and long term?
Answer. Energy efficiency should be the first and foremost strategy
pursued both for managing climate change and for reducing oil
insecurity. I fully agree with the MIT report (MIT, 2007)\1\ on this
point as well as the U.S. Climate Change Technology Strategic Plan and
the IEA Energy Technology Perspectives of 2006. In addition the
National Commission on Energy Policy Study points out the importance of
efficiency in transportation for reducing oil dependence.
---------------------------------------------------------------------------
\1\ Deutch, J., and E.J. Moniz et al., The Future of Coal: Options
for a Carbon-Constrained World, an Interdisciplinary MIT Study, 2007.
---------------------------------------------------------------------------
Regarding synthetic liquid fuels production, consider first a coal
to liquids plant with full CCS (capturing 85-90% of the CO2
not contained in the energy products). With this much CCS, the fuel
cycle-wide GHG emission rate for the production and consumption of
liquid fuel would be about the same as for the crude oil-derived
products displaced. For these plants CO2 capture is
relatively straightforward because most of the coal-derived carbon that
is not contained in the produced synfuels is vented at the conversion
facility as a relatively pure stream of CO2. As a result,
the capture cost is very low--essentially the cost of drying and
compressing CO2 to make it ready for delivery to an
underground storage site. The cost of CO2 transport and
storage would be comparably low if storage were in depleted oil or gas
fields or in deep saline formations. If there were an opportunity to
use the CO2 for enhanced oil recovery (EOR), the incremental
cost for CCS could be negative--i.e., the value of the CO2
for this purpose would often be more than the cost of capturing the
CO2 and delivering it to the EOR site.
(Note: A question that has arisen regarding CO2 EOR is
whether the purchased CO2 actually stays put. It has been
estimated that less than 1% of the CO2 purchased for
CO2 EOR has escaped into the atmosphere (Stevens and Eppink,
2001),\2\ but prior to the Beulah/Weyburn project [CO2
produced at the Beulah ND Great Plains Synfuels Plant and piped 250
miles north for EOR in the Weyburn oil field in Saskatchewan, Canada]
emissions from CO2 EOR projects have not been routinely
monitored. The Beulah/Weyburn project has been intensively monitored by
a broad international scientific consortium, and no CO2
emissions have been detected (IEA GHG R&D Programme, 2005).\3\
Moreover, modeling carried out for this project has estimated that over
the next 5000 years less than 0.2% of the injected CO2 would
escape to the biosphere.
---------------------------------------------------------------------------
\2\ Stevens, S., and J. Eppink, CO2 Utilization for
Enhanced Oil and Gas Production, Gasification Technologies 2001, San
Francisco, 9 October 2001.
\3\ IEA GHG R&D Programme, IEA GHG Weyburn CO2
Monitoring & Storage Project, Petroleum Technology Research Centre of
Canada, 2005.)
---------------------------------------------------------------------------
Recent studies carried out by the National Energy Technology
Laboratory (NETL) and Nexant researchers (Olson and Reed, 2007; Reed
and Olson, 2007)\4\ analyzed a 50,000 barrels per day (2900
MW1) synfuel plant producing a small amount of coproduct
electricity (86 MWe). They found that with CO2
vented such a plant could provide investors with a 20% rate of return
on equity when the oil price is about $60 a barrel. They estimated that
including CO2 capture would increase the capital cost by
only about 2% and reduce the electricity output to 24 MWe.
They estimated that capture and aquifer storage of the CO2
would become cost completive with CO2 venting when the
CO2 emissions value is of the order of $15 per tonne. Such a
plant with CCS would produce liquid fuels with net carbon emission
rates similar to that for the production and use of petroleum based
fuels.
---------------------------------------------------------------------------
\4\ S.C. Olson (Nexant) and M.E. Reed (NETL), ``Impacts of Future
US GHG Regulatory Policies on Large-Scale Coal to Liquids Plants,''
paper presented at the 6th Annual Conference on Carbon Capture and
Sequestration, Pittsburgh, PA, 7-10 May 2007, to be published in the
Proceedings of the Conference.
M.E. Reed (NETL) and S.C. Olson (Nexant), ``Technical, Cost, and
Financial Impacts for Carbon Separation and Compression on Large-Scale
Coal to Liquids Plants,'' presented at the 6th Annual Conference on
Carbon Capture and Sequestration, Pittsburgh, PA, 7-10 May 2007, to be
published in the Proceedings of the Conference.
---------------------------------------------------------------------------
Carbon emissions can be further reduced to zero or near zero by
coprocessing enough biomass with coal (as described in the answer to Q.
1) and sequestering the CO2 produced. The sequestration of
the carbon from the biomass offsets the coal-derived carbon emitted in
the plant and from burning of the fuels produced. However, biomass is a
more expensive feedstock than coal, so the cost of producing Fisher-
Tropsch liquid (FTL) fuels will be greater than for a straight FTL coal
plant until the CO2 emissions value is sufficiently high.
Williams and his colleagues at Princeton estimate that in the range of
$25-30 per tonne of CO2 emissions value the bio-coal plant
could provide synthetic fuels at lower net cost than for synfuels
derived from coal only with CO2 vented or with
CO2 captured and stored (see also the answer to Question No.
1). This emissions value is in the ballpark estimated in the MIT coal
study and many other studies as needed to begin to incentivize CCS from
coal fired power plants. Without controlling emissions from coal fired
power plants around the world mitigating climate change will be much
more difficult, so a climate change policy should value CO2
emissions at least this much.
Question 3. I join Senator Murkowski in her concern about the need
to retrofit our existing coal fired power plants to address the issue
of carbon capture and storage. Some of the testimony suggested that
adding ``oxyfuel'' to these older plants would be the best path to take
as this burns pure oxygen, instead of outside air, producing a carbon
dioxide-rich exhaust stream, with little or no NOX, so the
CO2 is more concentrated and easier to capture for
sequestration. Do you have any information on the ease/feasibility of
retrofitting older coal plants or other coal-burning industrial
facilities with ``oxyfuel''?
Answer. I do not have the information you seek, but I do know an
expert in the field who can probably answer this very interesting
question. He is Ed Rubin of Carnegie Mellon University in Pittsburgh
PA. I sent this information to Senator Markowski already.
In general there are two approaches to reducing emissions of
CO2 from existing coal fired power plants. The first is to
scrub the stack flue gases to absorb the CO2 and sequester
it. The second approach is to fire the power plant boilers with oxygen
and coal to produce relatively pure CO2 flue gas without
nitrogen, and then sequester it. Both of these approaches have been
tried. They are not simple or inexpensive. If one is contemplating a
new coal facility, the IGCC route with CCS will likely be the best
approach depending on coal properties and special circumstances.
The National Energy Technology Laboratory (NETL) has estimated that
flue gas scrubbing will increase in the cost of electricity in the
range of 45 to 70%. Advanced systems may bring this cost penalty down
to about 20%. For the oxyfuel process the cost escalation is estimated
to be 26 to 50% and with advanced systems in the range of 20%. The IGCC
process with CCS would be in the range of 19 to 31% and with advanced
systems in the range of 5-10%. The energy penalty is about 30% for a
pulverized coal plant and 16% for an IGCC plant using current
technologies.
Responses of William Fulkerson to Questions From Senator Salazar
Question 4. It appears from the written testimony, that liquid
fuels produced from coal combined with biomass can result in lower
greenhouse gas emissions than conventional gasoline. What are the
technology hurdles to overcome in mixing biomass with coal to produce
liquid fuels? Has the combination of biomass and coal been used at any
commercial plant? What is a realistic % of greenhouse gas emissions
compared to petroleum that we can expect to achieve.
Answer. One hurdle involves the handling of various biomass
feedstocks. These were addressed by Jay A. Ratafia-Brown of SAIC at the
hearing. Jumping these hurdles will require some development work and
first class engineering, as I understood Jay's comments. My impression
from what Jay said was that there were no real showstoppers, however.
Another hurdle involves biomass gasification. There are two
alternative approaches to cofiring coal and biomass: one involves use
of separate gasifiers to make the synthesis gas from which the liquid
fuels are made, followed by a blending of the synthesis gas streams
from coal and biomass for further processing. Alternatively, coal and a
modest amount of biomass could be gasified in the same gasifier. Only
the latter approach is viable with commercially available coal
gasifiers, and co-gasification is much more difficult for some
commercial coal gasifiers than for others.
The 250 MWe IGCC plant at Buggenum in The Netherlands has been
coprocessing 11% biomass and 89% coal (on an energy basis) for about a
year, and plans are to increase the biomass percentage to 20% during
2008. If that same gasifier fired with 11% biomass were used to make
synthetic liquid fuels instead of electricity, the greenhouse gas (GHG)
emission rate for the liquid fuels would be 20-25% less than the rate
for the crude oil-derived hydrocarbon fuels displaced. This is an
emissions rate that is similar to that from manufacturing corn ethanol.
The co-gasification route uses cellulosic biomass instead of food
biomass, thereby avoiding the corn, meat, and fertilizer price
escalations that have accompanied the rush to ethanol.
The coprocessing of cellulosic biomass with coal in this manner
represents a much quicker route to establishing cellulosic biomass in
the energy market than the cellulosic ethanol route, because, as
remarked by Dan Reicher (former DOE Assistant Secretary for EE/RE):
``Producing cellulosic ethanol is clearly more difficult than we
thought in the 1990s'' (New York Times, 17 April 2007). Moving quickly
to coal/biomass coprocessing would be very helpful in evolving a
logistics infrastructure for cellulosic biomass.
The separate gasifiers approach would make it feasible to increase
the biomass fraction enough to reduce the net GHG emission rate to zero
for liquid fuels. Realizing zero net emissions this way would require
only \1/3\ to \1/2\ as many biomass Btus per Btu of liquid fuels as is
required in making cellulosic ethanol. If there were a concerted
development effort the separate gasifiers approach could likely be
fully commercial by the middle of the next decade. This should in no
way decrease our efforts to convert cellulose to ethanol or other fuels
biochemically. Cellulosic ethanol has the advantage that no CCS is
needed.
Question 5. Even with the use of biomass, there are still
substantial volumes of CO2 that must be captured and safely
stored. Are there any recommendations this panel has on where to locate
CTL facilities to facilitate the storage of CO2?
Answer. Yes, in the biomass/coal plant considered by Williams and
his colleagues some 4.5 to 5 million tonnes of CO2 would
need to be stored each year. For the same amount of fuel produced
changing the relative amounts of coal and biomass inputs doesn't affect
very much the amount of CO2 that would be available for
capture and storage, but adding more biomass makes the net carbon
emissions to the atmosphere much less because the biomass-derived
CO2 stored underground was taken out of the atmosphere in
growing the biomass.
Currently, DOE is conducting 7 regional assessments of
sequestration opportunities. These cover the country. Good
opportunities exist in many places, particularly where deep saline
aquifers are available, and also in many regions where the
CO2 can be used for enhanced oil recovery.
As the MIT study emphasized, several storage projects storing at
least a million tonnes of CO2 annually are needed to
understand better the outlook for aquifer storage in different types of
geological reservoirs and to provide a solid scientific and engineering
basis for the CO2 storage regulatory regime for the longer
term. CTL plants would be good candidate sources for providing the
needed CO2 for some of these early storage projects, because
the CO2 capture cost is low--much less than the cost for
CO2 capture at power plants.
The low CO2 capture cost at CTL plants also makes these
attractive candidates for CO2 enhanced oil recovery
projects.
Siting bio-coal fuel plants requires access to adequate biomass and
coal supplies as well as sequestration capacity. One possible site for
a needed full-scale demonstration of bio-coal fuels production
providing liquid fuels with zero or near-zero net lifecycle carbon
emissions might be in southern Illinois, near the hypothetical site
picked by Bob Williams for his recent study, because all the needed
resources are there.
A full-scale demonstration of a bio-coal fuels plant could be
organized between the government and the private sector in the next 5-
10 years.
Question 6. Can you discuss the water requirements for a CTL plant?
Are there opportunities for reusing/recycling water in the process?
Answer. No, I cannot answer this question, but as I recall, Jim
Bartis from RAND at the hearing suggested about 7 gallons of water per
gallon of fuel is in the right ballpark. Williams agrees with this
rough estimate. Most of the water is for evaporative cooling; a minor
fraction is consumed in the process.
The availability of hydrological water supplies could be a
constraint on the extent of deployment of synfuels technologies,
especially in arid regions of the West. There evaporative cooling water
requirements could be dramatically reduced shifting to dry cooling
towers. Reducing process water requirements would be more challenging.
But even in arid regions of the West there are substantial supplies of
saline water deep underground--fossil water that is not involved in the
hydrological cycle. Williams has estimated that the physical volume of
process water required is comparable to the physical volume of
CO2 that must be stored underground for synfuel plants that
practice CCS. He has suggested investigation of the concept of
recovering saline water and desalinating it for process use, and
injecting for underground storage CO2 plus the salt-rich
residual of the desalination process.
Question 7. The auto industry has developed plug-in electric
hybrids, and this committee has heard testimony about all-electric
cars. Can you discuss the advantages and disadvantages of using coal to
produce liquid fuels vs. using coal to generate electricity to charge
batteries for electric cars and hybrids?
Answer. It depends upon what you mean by plug-in hybrids. The
problem is that we don't have a proper battery for such a vehicle. The
energy density is too low by a factor of 2 to 3, and the battery life
is too short under deep discharge conditions needed to maximize the
usefulness of a plug-in hybrid. Great progress is being made, but
batteries are not there yet. This is what I have been told by Venkat
Shrinivasan of Lawrence Berkeley National Lab.
When a proper battery becomes available using electricity to
augment liquid fuels in transportation is a great idea. If off-peak
power is used which is the logical strategy, the cost of electricity
will be low. Also, because the efficiency of charging a battery is high
as is the efficiency of electric drive electricity can be a very
competitive energy source. Even with the current fraction of fossil
derived electricity, use of the plug-in hybrid will probably reduce
carbon emissions. Michael Kintner-Meyer of Pacific Northwest National
Laboratory has estimated this.
Nevertheless, one still needs fuels to run a hybrid and the bio-
coal fuels process provides a way to produce conventional liquid
transportation fuels with zero or near zero net emissions from the
whole fuel cycle.
My conclusion is that we should work hard on better Li-ion
batteries and bio-coal liquid fuels.
Responses of William Fulkerson to Questions From Senator Thomas
Question 8. You mention that coal and biomass gasification is a
very promising technology that requires additional development,
especially on biomass collection and preparation. What are the
advantages that accompany waiting until this technology is commercial
before imposing limits on the allowable carbon dioxide footprint?
Answer. As I have already noted in my answer to question No. 4, one
variant of the concept (based on co-gasification of modest amounts of
biomass along with coal) can be introduced with current technology,
whereas a system based on use of separate gasifiers needs further
development.
And as I have already noted, getting started via the co-
gasification route would be very helpful in evolving the logistics
infrastructure for cellulosic biomass via learning by doing and in
beginning a transition from food biomass (e.g., corn, soybeans) to
cellulosic biomass in the production of liquid fuels.
I will give you my opinion as to how public policy might be used to
encourage both this early experience and a transition to more advanced
technologies.
As there are already technologies near-at-hand for reducing the
carbon footprint of synfuels production and use, measures promoting
deployment of reduced carbon technologies are needed. But in crafting a
deployment policy, it would be wise to frame the policy so as to drive
us toward mitigating climate change and reducing oil insecurity
simultaneously without the government's attempting to pick
technological winners.
One approach to a policy for technology deployment would be to tax
fuels on the basis of net carbon emissions (on a total fuel cycle
basis). Obviously, such a carbon management policy would create a level
playing field and would avoid the government pick winning problem. With
such a policy, bio-coal fuel would be taxed much less than petroleum
based fuels. A tax would give the consumer the right signals and
industry as well. Most of the tax might be returned to the public to
avoid hardships.
California is trying a very interesting alternative approach. They
will develop regulations requiring a gradual reduction in the carbon
intensity of transportation fuels. This would penalize fuels from
petroleum or coal without co-processing biomass and without
sequestration. It would establish a strong market for low carbon and
carbon neutral fuels such as the bio-coal fuel proposed by Williams (or
cellulosic ethanol for example).
Of course, a technology deployment policy, whatever its form,
should be complemented by measures aimed at bringing to commercial
readiness advanced concepts (e.g., bio-coal systems based on separate
gasfiers for coal and biomass). So two parallel paths are needed in
public policy.
Question 9. In addition to financial incentives, in the form of tax
credits, appropriations, and other tools at Congress' disposal, what
regulatory approaches do you believe can be taken to advance the
development of a domestic coal-derived fuel industry? Please address
not only liability issues associated with carbon dioxide sequestration,
but permitting of the actual plants, obstacles to construction of
infrastructure, and other issues that you believe could be addressed
from a regulatory, rather than a financial, standpoint.
Answer. I am not an expert on this the topic of regulations.
However, in answer to Q 8 a low carbon fuel standard is one regulation
that should be explored carefully, and it is being considered seriously
by California. With time a greater and greater fraction of fuel would
be required to be low or no net carbon emitting fuel on a total fuel
cycle basis. This could be formulated in a way that does not legislate
technologies. Over time it would create a premium for such fuels that
would feedback to creating supply options. Dr. Antonia Herzog of NRDC
also suggested such a fuel standard at the hearing I believe.
On the issue of liability associated with CO2 storage or
transport I assume liability insurance should be required and that
safety of pipelines and sequestration sites should be regulated by the
states or the Federal government. Of course, pressurized CO2
is commonly piped over considerable distances for enhanced oil recovery
and the retention of the CO2 in those deposits appears good.
See my response to question 2.
In my judgment coal synfuels plants should not be built without the
requirement that excess CO2 be captured and stored (CCS),
and the bio-coal fuels process suggested by Williams with CCS is the
best option suggested so far to tame the remaining evils of coal while
optimizing the use of biomass.
In my opinion if we want to reduce oil insecurity and also mitigate
climate change a carefully conceived set of policies are needed some
involving financial sticks and carrots and some involving regulatory
tools. The six policies listed at the end of my testimony might be a
good start, and I copy them here.
First, the greenhouse gas emission externality must be reduced by
putting a cost on emissions by cap and trade or tax or whatever. The
Congress through various pieces of proposed legislation is actively
considering this, and no doubt something will emerge.
Second, a low-carbon fuel standard such as is being developed by
the State of California should be adopted and existing subsidies on low
carbon fuels should be discontinued.
Third, regulations should be adopted to assure that no new coal
synfuels plants are built without carbon capture and storage.
Fourth, an oil security feebate might be enacted to put a floor on
transportation fuel prices. If oil prices crash, say to $30/bbl from
$60, transportation fuel could be taxed and part of the tax rebated to
synfuels plants to help them compete and produce even with low world
oil prices. Part of the tax revenues could be returned to the public.
Fifth, regulations (such as improved CAFE standards) to promote
more efficient use of transportation fuels need to be aggressively
strengthened over time.
Sixth, regulations and R&D to improve coal mine safety, worker
health, and environmental improvement need to be periodically reviewed
and upgraded if necessary.
However, as I mentioned in my testimony it is relatively easy to
make such a list. The hard work comes in sorting out the many options
so policies invented are effective, fair, and politically possible.
That is the difficult task facing this Committee and the Senate in the
whole.
Question 10. What specific technology gaps need to be closed by DOE
and private industry working together to reduce the technical and
economic risk of coal-derived fuel plants?
Answer. The principal gap relates to CO2 storage. The
extent to which CTL and coal in general have substantial futures in a
carbon-constrained world depends critically on the future prospects for
secure CO2 storage.
We are not likely to be able to learn much more than we already
know about this potential by doing more paper studies and small-scale
experiments. Rather, a number of ``megascale'' projects (each storing a
million tonnes of CO2 annually or more)\1\ in a variety of
geological media, with an emphasis on deep saline formations, are
needed as soon as possible both to understand the true practical
potential for secure storage and to help define the regulatory regime
needed for ``gigascale'' CO2 storage (MIT, 2007).
---------------------------------------------------------------------------
\1\ For perspective, the CO2 storage rate for a 50,000
barrels per day CTL plant would be 8 to 9 million tonnes per year.
---------------------------------------------------------------------------
CO2 capture costs are much less for CTL plants than for
coal power plants. The low cost of CO2 capture at CTL plants
makes such plants strong candidates for providing low-cost
CO2 for early megascale storage projects that can be very
helpful in closing the gap. With regard to Williams' bio-coal fuels
idea coal gasification and Fischer-Tropsch technologies are
commercially ready. But there is much less experience with biomass.
Large biomass gasifiers must be commercialized.
Also, as I commented in the answer to Q 4 that development is
needed in the preparation of biomass feedstocks of various sorts for
the oxygen blown gasification step. Jay A. Ratafia-Brown of SAIC
addressed these at the hearing.
Question 11. Does the use of a FT coal-derived diesel product have
an improved footprint for nitrous oxide, particulate matter, sulfur
dioxide, volatile organic compounds, and mercury over traditional
sources of diesel? Please quantify the per gallon differences for
criteria pollutant emissions that would result from consumption of a FT
coal-derived diesel product versus traditional, petroleum-derived,
diesel fuel.
Answer. Emissions of NOX, unburned hydrocarbons, and
particulates from the burning of F-T diesel in compression ignition
engines tend to be lower than from burning petroleum-derived diesel
fuel (Norton et al, 1998).\2\ In addition, the S content of F-T fuels
would be extremely low. This is because sulfur is a FT catalyst poison
so it must be removed upstream of the FT units at the fuel processing
plant.
---------------------------------------------------------------------------
\2\ P. Norton, K. Vertin, B. Bailey, N.N. Clark, D.W. Lyons, S.
Goguen, and J. Eberhardt, ``Emissions from Trucks Using Fischer-Tropsch
Diesel Fuel,'' Society of Automotive Engineers Paper 982526, 1998.
---------------------------------------------------------------------------
For coal-derived F-T liquids mercury would also have to be removed
at the processing plant but it can be removed at very low incremental
cost.
The regulations developed or being developed for Diesel fueled
vehicles including 18-wheelers should apply to FTL as to petroleum-
derived fuels.
Question 12. China is aggressively pursuing development of a CTL
industry. If the U.S. does not, is it possible that we will be
importing CTL fuels from China in the future?
Answer. Sure, it is possible that we will someday import CTL fuels
from China. This is not likely to occur unless petroleum based fuels
are more expensive. What we should be working to prevent is a CTL
industry in China without capture and storage of the excess carbon. A
U.S. low carbon fuel standard would provide an incentive for China to
practice carbon capture and storage and bio-coal fuel production.
Question 13. What implications does this have for U.S. national
security?
Answer. Coal synfuels are being advanced mainly because of energy
supply insecurity concerns associated with dependence on oil imports
and because of the prospect of sustained high oil prices. But whatever
the U.S. does to enhance energy security by promoting CTL must be
carried out in ways that simultaneously mitigate climate change.
Because of the national security risks inherent in GHG emissions-
induced climate change, energy security concerns do not trump climate
change concerns--as pointed out recently by a blue-ribbon panel of
retired US admirals and generals from the Army, Navy, Air Force, and
Marines (CNA, 2007).\3\
---------------------------------------------------------------------------
\3\ CNA Corporation, National Security and the Threat of Climate
Change, Alexandria, Virginia, 2007.
---------------------------------------------------------------------------
______
Responses of James Bartis to Questions From Senator Bingaman
Question 1. You advocate both for carbon capture and gasification
of biomass with coal to meet greenhouse gas emissions targets. Using
both together, you indicate there is a level where the total lifecycle
emissions could theoretically be zero or even negative. Assuming that
is with further technological development, what do you think are
achievable standards today for percentage of carbon captured, biomass
included, and lifecycle emissions?
Answer. For first-of-a-kind CTL plants built in the United States,
80 percent capture of all plant CO2 emissions is an
achievable standard. This level of reduction should result in lifecycle
emissions that are between 10 and 20 percent higher than motor fuels
produced from conventional petroleum. This level of capture is
consistent with the two lowest risk approaches for managing carbon in
initial coal-based commercial plants, namely, co-firing of coal and
biomass and the use of carbon dioxide for enhanced oil recovery. This
emission factor is also appropriate for CTL plants that would capture
carbon dioxide for use in a long-term demonstration of geologic
sequestration.
This percentage reduction is possible without forcing a CTL plant
to incorporate gas turbines that can accept a fairly pure hydrogen
feed. Adding such turbines would allow at least 95 percent removal;
however, it is our judgment that requiring hydrogen turbines would add
considerably to the market uncertainties associated with the future
course of world oil prices and the technical uncertainties associated
with building, operating, and capturing carbon from a first-of-a-kind
plant.
Question 2. You advocate that any facilities that receive federal
incentives should be at least comparable in greenhouse gas emissions to
petroleum-derived fuels. Our recent renewable fuels bill included a
standard requiring fuels have 20% less lifecycle emission than the
fuels they replace. How feasible would a similar standard be for coal-
derived fuels?
Answer. Once initial production and carbon management experience is
obtained, a similar, or even tighter standard, is feasible for fuels
produced from a blend of coal and biomass. Such a standard is not
feasible for the initial round of commercial plants because of the
uncertainties discussed in the response to Question 1 above. Such a
standard is also not feasible for plants that use only coal as a
feedstock. The best that coal-only plants can achieve is parity with
conventional petroleum-based fuels.
This question raises a broader issue regarding implementing energy
policy objectives, namely, the efficacy of emission standards for
first-of-a-kind fuel plants that are subsidized by the government. The
proposed legislation is not intended to obtain early production
experience but rather to promote strategically significant amounts of
production. But for coal-to-liquids, as well as biomass-derived fuels
based on Fischer-Tropsch or cellulosic conversion, what is most needed
is initial commercial production experience. For the case of coal-based
plants, such initial experience should include attaining reasonably
achievable levels of carbon management, as discussed in the response to
Question 1. Setting standards for lifecycle CO2 emissions
may be more appropriate once that initial experience is achieved.
Responses of James Bartis to Questions From Senator Sanders
Question 3. The Intergovernmental Panel on Climate Change has
recently issued its Fourth Assessment Report Summary for Policy Makers.
In that Report they concluded that the evidence that global warming is
real and caused by humans is unequivocal. The MIT study, ``The Future
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase
the cost of electricity from coal by 20%, but an aggressive energy
efficiency campaign could be conducted, so that less electricity is
used, bringing our electricity bills down by 20% or more. What do you
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in
the near term and long term?
Answer. I confine my answer to diesel from coal, since RAND does
not yet have available useful estimates on the costs of diesel from
coal-biomass. Also, our research has not addressed the production of
natural gas from unconventional resources.
As I testified, there are significant uncertainties regarding the
costs of constructing and operating a first-of-a-kind coal-to-liquids
production facility. There are also large uncertainties associated with
the costs of developing and operating a facility for carbon
sequestration. Using available design data, we estimate that the costs
to produce a gallon of diesel from initial coal-to-liquid plants will
be between $1.40 and $1.70 per gallon, assuming no carbon management.
This is a plant gate cost, and should be compared to a refinery gate
price, which for diesel is currently between $2.00 and $2.10 per
gallon. Once the first commercial plants are operating and experience-
based learning begins to take place, costs should drop below $1.40 per
gallon.
With carbon capture and geologic sequestration, we estimate that
the above cost range will increase to $1.60 to $2.10 per gallon. The
broad range of all of our cost estimates reflects the fact that they
are derived from highly conceptual engineering designs intended to
provide only rough estimates of liquid fuel production costs and the
cost uncertainties regarding geologic sequestration. We are also
concerned that the recent large cost increases associated with the
construction of major capital intensive projects are not adequately
reflected in the above estimate. It is for these reasons that we
recommended in our testimony that Congress consider cost-sharing
options that would promote the development of a few site-specific
designs that will provide reliable cost estimates.
For some carbon management options, such as using carbon dioxide in
enhanced oil recovery, the operators of coal-to-liquids plants may be
able to sell their carbon at a price that recovers the extra costs
associated with capturing, compressing and delivering it to the user's
site. In this case, the costs of producing liquid fuels would be close
to, or slightly lower than, the estimated costs without carbon
management.
The above ranges refer to production costs, including a reasonable
return on investment. The actual prices will be based on future
wholesale prices for diesel fuel (which is based on the world oil price
and refining margins) and could be significantly lower or higher.
Question 4. I join Senator Murkowski in her concern about the need
to retrofit our existing coal fired power plants to address the issue
of carbon capture and storage. Some of the testimony suggested that
adding ``oxyfuel'' to these older plants would be the best path to take
as this burns pure oxygen, instead of outside air, producing a carbon
dioxide-rich exhaust stream, with little or no NOX, so the
CO2 is more concentrated and easier to capture for
sequestration. Do you have any information on the ease/feasibility of
retrofitting older coal plants or other coal-burning industrial
facilities with ``oxyfuel''?
Answer. The feasibility of retrofitting older coal plants is an
extremely important issue. Because RAND has not yet had the opportunity
to investigate this problem, I am not able to provide you with an
informed answer.
Responses of James Bartis to Questions From Senator Salazar
Question 5. It appears from the written testimony, that liquid
fuels produced from coal combined with biomass can result in lower
greenhouse gas emissions than conventional gasoline. What are the
technology hurdles to overcome in mixing biomass with coal to produce
liquid fuels? Has the combination of biomass and coal been used at any
commercial plant? What is a realistic percentage of greenhouse gas
emissions compared to petroleum that we can expect to achieve?
Answer. The most efficient and economic gasifiers that are
currently available for use in a Fischer-Tropsch system are entrained-
flow gasifiers. Such gasifiers operate at pressures of about 30
atmospheres (450 pounds per square inch) and require a finely-sized
feed, which is either blown or sprayed into the gasifier. The technical
challenge is to devise the system that grinds, pressurizes, and feeds a
stream of biomass or a combination of biomass and coal into the
gasifier with high reliability and efficiency. This is a fairly minor
technical challenge. It is an engineering problem focusing on
performance and reliability, not a science problem. To establish the
design basis for such a system requires the design, construction, and
operation of one or a few test rigs. These test rigs need to be fairly
large so that they are handling flows close to what would be the case
in a commercial plant. This is because solids are involved and it is
very difficult to predict performance and reliability of solids
handling and processing systems when the size or throughput of the
system undergoes a large increase. Such large-scale testing could be
conducted during the design and construction of a full-scale plant for
co-firing coal and biomass.
Combinations of biomass and coal have been used in commercial
plants in the past, but only at low biomass-to-coal ratios and with a
limited number of biomass types. I believe the highest ratio used in
continuous gasifier operations was at the Nuon IGCC power plant in The
Netherlands, which was mentioned by Mr. Jay Ratafia-Brown in his
testimony on May 24. This plant used a biomass-to-coal ratio (energy
input basis) of about 1 to 5. Whereas much higher ratios, about 1 to 1,
would be needed to bring carbon emissions to well-to-wheels parity with
petroleum-derived fuels, assuming no carbon capture and sequestration.
Additionally, the Nuon plant did not use the types of biomass that are
estimated to be most abundant in the United States.
The relative percent reduction of greenhouse gas emissions that can
be achieved via combined biomass and coal use depends on the fraction
of the feed that is biomass as compared to coal. Consider liquid fuel
production plants without carbon capture and sequestration. At one
extreme, imagine a plant that is fed only biomass. Greenhouse gas
emissions are generated in cultivating, harvesting and transporting
biomass, but these emissions are fairly small, so that using fuel from
a biomass only plant would likely entail lifecycle greenhouse gas
emissions that are less than 10 percent of those from conventional
petroleum-based fuels. As we add coal to the plant, the lifecycle
greenhouse gas emissions increase. At a 50-50 mix, the emissions levels
would be comparable to conventional petroleum, and would increase to
about 2.0 to 2.3 times conventional petroleum for plants using just
coal.
The preceding discussion applies to liquid fuel production plants
without carbon capture and sequestration. With carbon capture and
sequestration, a 50-50 mix of biomass and coal should yield lifecycle
greenhouse gas emissions that are close to zero. As the biomass ratio
increases, the lifecycle emissions would become negative, and as the
coal ratio increases, net emissions would increase until they reached a
maximum that would be very close to that associated with conventional
petroleum.
Question 6. Even with the use of biomass, there are still
substantial volumes of CO2 that must be captured and safely
stored. Are there any recommendations this panel has on where to locate
CTL facilities to facilitate the storage of CO2?
Answer. RAND has not conducted research on the geologic and
technical issues associated with site selection of facilities for the
storage of CO2, and therefore cannot provide an informed
response to the main thrust of this question. We strongly recommend
that the U.S. government take measures as soon as possible that are
required to conduct multiple large-scale demonstrations of geologic
sequestration at various sites across the United States. In addition to
geologic and technical issues, the site selection process should
consider proximity to major coal resources. We also recommend that the
site selection process should promote extensive public participation,
including inputs from state and local governments, industry, and non-
governmental organizations.
Question 7. Can you discuss the water requirements for a CTL plant?
Are there opportunities for reusing/recycling water in the process?
Answer. RAND has conducted research on water consumption and
production in Fischer-Tropsch plants that use natural gas as a
feedstock to produce liquid fuels. Based on this research, we estimate
that at least 1.5 barrels of water would be consumed in a CTL plant for
each barrel of liquid product produced. By consumed, we mean water
either used to make hydrogen or lost through evaporation. We assume
that no once-through cooling water is used. To obtain the minimum water
usage, the plant would need to install dry cooling towers and
incorporate extensive measures to minimize water losses in the power
generation and oxygen production portions of the plant. The net result
of designing such a plant would be an increase in investment costs and
a reduction in the operating efficiency of the plant. As a result, such
a plant would only be built in areas in which water, including suitable
groundwater, was in very limited supply.
In areas in which water is abundant, we anticipate that as much as
10 barrels of water would be consumed in a CTL plant for each barrel of
liquid product produced. Such a plant would likely use less expensive
evaporative cooling towers. The change from dry cooling towers to
evaporative cooling accounts for most of the additional water losses.
The remaining losses are associated with less recycling of process
water.
For most CTL plants, the water consumption will fall between 1.5
and 7 barrels of water per barrel of liquid product produced, with the
actual amount depending on the cost, availability, and quality of local
water supplies.
Question 8. The auto industry has developed plug-in electric
hybrids, and this committee has heard testimony about all-electric
cars. Can you discuss the advantages and disadvantages of using coal to
produce liquid fuels vs. using coal to generate electricity to charge
batteries for electric cars and hybrids?
Answer. With progress in technology, electric vehicles and plug-in
hybrids could be cost effective as alternatives to conventional fuels
and a means of reducing greenhouse gas emissions. At present, however,
the status of battery technology is such that all-electric cars are
expensive and limited in acceleration and range, and therefore have a
very limited market in the United States. Likewise, shortfalls in
current battery technology limit the ability of plug-in hybrids to
offer significant fuel savings at reasonable costs, especially compared
to current and emerging non-plug-in hybrids.
If the battery problems can be overcome, the extent to which
greenhouse gas emissions would be reduced would still depend on the
CO2 emissions associated with producing the electricity used
to charge the batteries. If the electricity is produced from fossil
fuels, these emissions could be mitigated with carbon capture and
sequestration.
Whether and when sufficient progress in battery technology will
occur remains an open question. As such, electric cars and plug-in
hybrids, as well as hydrogen-powered vehicles, are research concepts
that are deserving of federal support. However, it would be imprudent
to delay measures to address global climate change or energy security
based on the prospect that any of the advanced concepts are the
``silver bullet.''
Responses of James Bartis to Questions From Senator Thomas
Question 9. In terms of emissions, your testimony focuses on
greenhouse gases. There are many other substances, however, that
Congress has deemed appropriate to regulate and reduce. They include
mercury, sulfur dioxide, nitrous oxide, particulate matter, and others.
Answer. None received.
Question 10. How do coal-derived fuels perform in these categories
relative to the conventional fuels that they will replace?
Answer. This answer address emissions that would occur at the plant
site at which coal-derived liquids would be produced. The answer to
Question 11 addresses emissions from the use of the fuel.
The front end of an F-T coal-to-liquid fuel production plant is
very similar to power plants that would be based on coal gasification.
The primary difference is that the F-T catalysis reactor is extremely
sensitive to trace amounts of mercury and sulfur, so that extensive
removal of compounds containing these elements will occur before the
synthesis gas is allowed to enter the F-T reactor.
For mercury, we anticipate that commercially available mercury
control systems can capture between 90 and 95 percent of the mercury
that would otherwise enter the F-T reactor. This would reduce net plant
mercury emissions to between 5 and 10 percent of the level that would
result if the same amount of coal were burned in a conventional power
plant.
For sulfur, commercially available removal systems are able to
reduce sulfur concentrations to parts per billion. Net emissions of all
gaseous sulfur compounds to the atmosphere would be negligible, namely,
well under a hundredth of what would be released by a modern power
plant meeting current standards and burning the same amount of coal.
With regard to particulate emissions, these would come from various
sources within a CTL plant. Without recourse to a front-end engineering
design, we are unable to provide a numerical estimate. However, it is
our judgment that, given the performance of commercially available
equipment for controlling emissions, particulate emission levels are
unlikely to be a deciding factor on the ability to site a CTL plant.
The only significant sources of nitrogen oxide emissions are the
gas turbines used to produce power used within the CTL plant and for
sale. The amount of fuel consumed by the gas turbines can vary
significantly based on how the CTL plant is designed. A reasonable
range for a CTL plant is that 70 to 150 MW of gas turbine capacity will
be in operation for each 10,000 barrels per day of liquids production
capacity. Nitrogen oxide emissions from these units should be
comparable to the state of the art for turbines designed for combined-
cycle power plants designed for natural gas or coal.
Question 11. Specifically, does the use of F-T coal-derived diesel
products have an improved footprint for nitrous oxide, particulate
matter, sulfur dioxide, volatile organic compounds, and mercury over
traditional sources of diesel? Please quantify the per gallon
differences for criteria pollutant emissions that would result from
consumption of F-T coal-derived diesel products versus traditional,
petroleum-derived, diesel fuel. China is aggressively pursuing
development of a CTL industry. If the U.S. does not, is it possible
that we will be importing CTL fuels from China in the future? What
implications does this have for U.S. national security?
Answer. Published test data indicate that using F-T-derived diesel
fuel in existing heavy and light duty diesel engines yields reduced
emissions of nitrogen oxides, particulate matter, sulfur oxides, and
volatile organic compounds as compared to ultra-low sulfur diesel fuel
derived from petroleum. Reported reductions are generally in the range
of 15 percent for nitrogen oxides and between 25 to 50 percent for
particulate matter. Somewhat greater levels of nitrogen oxide and
particulate matter reductions are possible in engines modified or
specifically designed for F-T fuel use. While F-T fuel has less than a
tenth of the sulfur of the typical ultra-low sulfur diesel fuel
currently being sold, we do not anticipate a full ten-fold or greater
reduction in sulfur oxide emissions, since other sources of sulfur,
such as lubricating oil, become noticeable contributors at these very
low levels. We are still evaluating the literature results for volatile
organic compounds and carbon monoxide. The results that we have already
seen indicate no significant changes. Vehicular fuel use, including
gasoline and diesel, is not viewed as an important source of mercury
emissions.
Both the national security and economic interests of the United
States would benefit from China's development of a CTL production
capability. By using China's coal resources to produce CTL, China will
need to import less fuel from the Middle East. This should lead to
lower world oil prices and thereby, savings to all oil users, including
American users, and lower export revenues to OPEC members, a number of
whom are governed by regimes that do not support American foreign
policy objectives.
It is highly unlikely that China will export CTL fuels since even a
very large CTL industry in China is unlikely to be able to meet the
shortfall between China's domestic production of crude oil and its
demand for liquid fuels.
Question 12. CTL fuels are the only currently available ``drop in''
replacements for military and civilian aviation fuel. Civilian aircraft
flying in and out of Johannesburg, South Africa have been using CTL
fuels for years. What specific actions do you believe Congress can and
should take to facilitate development of a U.S. CTL industry to assist
the U.S. aviation industry?
Answer. RAND research shows that the benefits of developing a CTL
industry in the United States do not accrue to any specific types of
fuel users, but rather to all fuel users, including military and civil
aviation. This is because the main benefit of producing any
unconventional fuel is that it reduces demand for conventional
petroleum and thereby reduces world oil prices.
Coal-derived liquids have certain performance properties that allow
them to command a premium price in certain markets. In particular,
because CTL fuels are nearly free of sulfur and have a very high cetane
number, CTL fuels will command a premium when used as automotive and
truck fuels. But these two characteristics offer less value when
considering aircraft applications. As such, we believe that commercial
aircraft are not a likely market for CTL fuels produced in the United
States over the foreseeable future.
Our finding is that any federal actions to promote CTL use in
commercial aircraft would not be productive. The critical path for CTL
development is obtaining initial commercial operating experience and
use in automotive applications.
Question 13. Mr. Fulkerson testified that ``If the excess
CO2 produced is sequestered instead of vented then the coal
synfuels process can be equivalent to petroleum in net CO2
emissions.'' Ms. Herzog's testimony seems to dispute this. How do we
reconcile these differences of opinion?
Answer. At RAND, we have conducted extensive research on this
topic. Our analyses show that net CO2 emissions from CTL
plants with sequestration range from slightly less than to slightly
more than petroleum. What drives the differences in our calculations
are assumptions regarding the degree of carbon capture (the last few
percent of removal costs much more than the first 95 percent on a $ per
pound basis), the efficiency of the CTL plant, and the emissions
associated with the refining of conventional petroleum. Additionally,
most CTL plants co-generate electric power. This electric power will
displace a conventional power plant. Assumptions regarding whether the
displaced power would be from an uncontrolled coal-fired power plant or
from a plant using carbon capture and sequestration also influence how
CTL emissions are calculated.
Question 14. In addition to financial incentives, in the form of
tax credits, appropriations, and other tools at Congress' disposal,
what regulatory approaches do you believe can be taken to advance the
development of a domestic coal-derived fuel industry? Please address
not only liability issues associated with carbon dioxide sequestration,
but permitting of the actual plants, obstacles to construction of
infrastructure, and other issues that you believe could be addressed
from a regulatory, rather than a financial, standpoint.
Answer. A great deal of research suggests that the most cost-
effective approach for addressing both energy security and greenhouse
gas reduction is through a broadly applied market-based approach that
stimulates changes in energy production and consumption through
increases in the costs of using petroleum-derived energy and through
increases in the costs of energy uses according to their greenhouse gas
emissions. An example of this approach would be an energy security tax
on all petroleum-derived liquid fuels and a tax on all fossil energy
fuels based on their net greenhouse gas emissions, taking into account
any reductions in emissions from sequestration. This approach would
help to level the playing field among different energy forms based on
their potential energy security and greenhouse gas impacts. Under this
approach, a domestic coal-derived (or coal and biomass-derived) fuel
industry would develop to the extent that such a fuel lifecycle was
economically advantageous over other options, taking into account the
security and greenhouse gas taxes.
Before this or any other approach based on financial incentives can
be effectively applied, however, we believe that the government needs
to support early, but limited commercial operating experience for coal-
based liquids production so that both industry and government are
better prepared to act wisely as further information becomes available
regarding world oil prices, the viability of carbon capture and
sequestration, and the future requirements associated with addressing
energy security and greenhouse gas emissions. The approach we are
recommending is somewhat akin to insurance, or paying for an option to
make a future investment even if it is decided later that the
investment is not needed. For this measured approach, we see a need for
financial incentives, but we see no need, at this time, for special
legislation or regulatory actions to accelerate permitting or to
address obstacles to construction of infrastructure.
I am unable to provide an informed comment on the regulatory issues
associated with siting and operating carbon dioxide sequestration
facilities, since neither I nor others at RAND have conducted
sufficient research on this topic.
Question 15. What specific technology gaps need to be closed by DOE
and private industry working together to reduce the technical and
economic risk of coal-derived fuel plants?
Answer. In my testimony, I listed four important measures that the
federal government can take, in cooperation with industry, to reduce
the uncertainties in the costs and performance of coal-derived fuel
plants. The first of these measures is to cost-share in the development
of a few site-specific front-end engineering designs of commercial
plants based on coal or a combination of coal and biomass. The second
is to foster early commercial experience by firms with the technical,
financial, and management wherewithal to successfully bring a project
to fruition and most importantly to capture and exploit the learning
that will accompany actual operations. The third of these measures is
to conduct multiple demonstrations and, by way of such demonstrations,
develop the regulatory framework required for a commercial
sequestration industry. And the fourth of these measures is to support
research, development, testing and evaluation of concepts for
integrating coal and biomass for the production of liquid fuels. An
early low-risk, high-payoff opportunity in this last area is the
construction and operation of test rigs and/or pilot plants for
evaluating the performance subsystems for co-feeding coal and biomass
into entrained-flow gasifiers.
Question 16. I have been told that coal-derived fuels have a higher
cetane level. Please explain the benefits, environmental and otherwise,
that are to be derived from that fact.
Answer. The cetane number is a measure of how readily diesel fuel
ignites. The higher the cetane number, the sooner a fuel will start to
burn after it is injected into the combustion chamber. Coal-derived
fuels from the Fischer-Tropsch process will generally have a cetane
number from 70 to 80. This is significantly higher than refinery
diesel, which generally ranges from 40 to 55.
In general, fuels with higher cetane numbers make starting a cold
engine easier and reduce hydrocarbon and soot pollutants generated in
the minute or so following a cold start. Higher cetane number fuels
also tend to reduce NOX and particulate emissions, although
the amount of such reductions is dependent on engine design.
Fuels with high cetane numbers are generally lower in aromatics.
Coal-derived fuels based on the Fischer-Tropsch method have extremely
low levels of sulfur and aromatics and these two attributes offer
improved environmental performance with regard to both particulate and
hydrocarbon emissions and should extend the operating life of catalytic
converters used to remove pollutants from diesel exhaust.
Question 17. We are told that Fischer-Tropsch fuels require no
modifications to existing diesel or jet engines, or delivery
infrastructure including pipelines and fuel station pumps. Is that
true?
Answer. This is true, so long as additives are allowed. In general,
the additive package would be similar to that associated with
conventional fuels intended for use in diesel or jet engines. For
unblended (i.e., 100 percent Fischer-Tropsch liquids) coal-derived
fuels, additional additives may be required to assure adequate
lubricity and to protect seals.
______
Responses of Antonia Herzog to Questions From Senator Sanders
Question 1. I am very supportive of your suggestion that we can
better power our vehicles with electricity, whether generated by coal
or renewable electricity like solar and wind, rather than converting
the coal to liquids and using that liquid fuel in our internal
combustion engines, which are much less efficient than electric motors.
You pointed out that plug-in hybrid electric vehicles (PHEVs) powered
by coal-based electricity with CCS are about 10 times better than Coal
To Liquids (CTL) with CCS used in a regular hybrid vehicle when it
comes to CO2 emissions. You also concluded that PHEVs using
coal-electricity with CCS are twice as good as Coal to Liquids with CCS
in terms of oil displaced, that is, I presume the same as the amount of
distance that can be traveled with the same ton of coal. These are
important findings. Can you please share with us the underlying
assumptions for those calculations? Your suggestion that the PHEV will
travel 3.14 miles/kwh, for example, is based on what tests or studies?
Some have suggested that PHEVs can do even better by going 5 or 6
miles/kwh.
Answer. Attached is a spreadsheet with the basic calculations
behind these results.*
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* Information has been retained in committee files.
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As you noted, our conclusion is that a ton of coal used in a power
plant employing carbon capture and storage (CCS) to generate
electricity for a plug in hybrid vehicle will displace more than twice
as much oil and emit one-tenth as much CO2 per mile driven
as using the same coal to make liquid fuels in a plant that uses CCS.
The analysis used the vehicle efficiency assumptions (37.1 miles/
gal, 3.14 miles/kWh) are from the just released EPRI-NRDC Joint
technical Report, Environmental Assessment of Plug-in Hybrid Electric
Vehicles, Volume 1: Nationwide Greenhouse Gas Emissions (1015325), July
2007. See the report for a more detailed discussion of the analysis
(http://www.epri-reports.org/ and http://www.epri-reports.org/
Volume1R2.pdf).
One assumption in our spreadsheet that is not quite consistent with
the EPRI modeling is the assumption that PHEVs operate on electricity
75% of the time. We believe the number is probably closer to 50%.
Question 2. I understand that PHEVs at the efficiency you suggest
would use 10 kwhs to go 31.4 miles or, at 10 cents per kwh, about a
dollar for 31 miles, versus what a gasoline car would pay for 31 miles
of travel, over $3. Is that accurate? If PHEVs are charged at cheaper
night-time rates, what is the cost equivalent per gallon of fuel? I
have heard that it is less than one dollar per gallon. If we consider
that PHEVs will most likely be charged by a mix of fuels that are
cleaner than coal, like natural gas, hydro, and others, what is the
CO2 comparison today, without CCS with a PHEV to a regular
hybrid fueled by CTL fuel without CCS? Do your figures consider the
total life cycle CO2 emissions, that is, do they include
energy costs from transportation, storage, pumping of the liquid fuels
and other energy costs in the CTL numbers?
Answer. The calculation you present is correct. Again I refer you
to the joint NRDC-EPRI study (http://www.epri-reports.org/
Volume1R2.pdf) mentioned in Q1 for a detailed discussion of the full
lifecycle (well-to-wheels) GHG emissions for PHEV for different mix of
fuels (Figure 5-1). There is also NRDC's plug-in hybrid factsheet which
can be found at, http://www.nrdc.org/energy/plugin.pdf.
For PHEVs, per mile global warming emissions are greatly affected
by what is used to charge them. Today's typical pulverized coal plant
(2.5 pounds CO2e/kWh) results in the highest emissions,
about 7.25 lbsCO2e/mi. The average grid (1.3 pounds
CO2e/kWh) is a mix of generation sources mainly coal,
natural gas, nuclear and large hydro resulting in about 5.5
lbsCO2e/mi. Non-emitting renewable electricity sources such
as wind, geothermal, and solar provide the lowest emissions per mile,
about 3.5 lbsCO2e/mi. This analysis assumes all vehicles
travel 12,000 miles per year. On-road efficiency for conventional
vehicles is 24.6 miles per gallon while hybrid drivetrains achieve 37.9
mpg on gasoline. PHEV electrical efficiency is 3.2 mi/kWh and 49% of
the PHEV miles are using stored grid energy. Much of the PHEV charging
occurs during the night (see Figure 4-5).
Question 3. The Intergovernmental Panel on Climate Change has
recently issued its Fourth Assessment Report Summary for Policy Makers.
In that Report they concluded that the evidence that global warming is
real and caused by humans is unequivocal. The MIT study, ``The Future
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase
the cost of electricity from coal by 20%, but an aggressive energy
efficiency campaign could be conducted, so that less electricity is
used, bringing our electricity bills down by 20% or more. What do you
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in
the near term and long term?
Answer. The MIT report estimates the costs of Fischer-Tropsch
liquid fuel and synthetic natural gas from coal with and without CCS,
see p. 156-157, Table A-3.F.2. They estimate that the F-T fuel
production cost is $50/bbl without CCS and $55/bbl with CCS. The
production cost of SNG is estimated to be $6.7/million BTU without CCS
and $7.5/million Btu with CCS. We believe these estimate are on the low
end. Furthermore, an economic study by Jim Dooley of Battelle (Jim
Dooley, Robert Dahowski, Marshall Wise, Casie Davidson ``Coal-to-
Liquids and Advanced Low-Emissions Coal-fired Electricity Generation,''
presentation at NETL conference, May 9, 2007, PNWD-SA-7804) predicts
that in a carbon constrained world CTL would not be a competitive fuel
even with CCS.
Question 4. I join Senator Murkowski in her concern about the need
to retrofit our existing coal fired Power plants to address the issue
of carbon capture and storage. Some of the testimony suggested that
adding ``oxyfuel'' to these older plants would be the best path to take
as this burns pure oxygen, instead of outside air, producing a carbon
dioxide-rich exhaust stream, with little or no NOX, so the
CO2 is more concentrated and easier to capture for
sequestration. Do you have any information on the ease/feasibility of
retrofitting older coal plants or other coal-burning industrial
facilities with ``oxyfuel''?
Answer. Combustion with pure oxygen instead of air eliminates the
nitrogen, avoids production of nitrogen oxides during combustion, and
produces an exhaust gas with a very high CO2 concentration,
making it easy to capture through simple compression and cooling. The
main operating cost of this system comes from the operation of the air
separation unit. Oxy-fuel PC combustion is in early commercial
development but appears to have considerable potential. It is under
active pilot-scale development, and larger projects are under
consideration, with a decision pending by the board of Saskpower at the
end of July whether to proceed with a 300MW unit.
Currently, an oxyfuel retrofit seems to be a more economically
attractive option than a retrofit with post-combustion capture system
(e.g. amine scrubbing). The recent MIT study on the Future of Coal
confirmed this point (p. 148). It is possible, however, that in a
decade or two a more attractive option through post-combustion capture
might exist, although there is no guarantee. It is at least as likely
that oxyfuel will be the retrofit technology of choice, or that there
will be no unanimous choice and that the optimum choice will depend on
the specifics of a particular plant.
The study also stated clearly that ``retrofitting an existing coal-
fired plant originally designed to operate without carbon capture will
require major technical modification'' (p. xiv). Moreover, no such
retrofits have been performed. Constructing a new plant with capture
from the outset makes engineering and economic sense, and we should
minimize our reliance on retrofits as much as possible by designing and
building all new plants with capture.
Responses of Antonia Herzog to Questions From Senator Salazar
Question 5. It appears from the written testimony, that liquid
fuels produced from coal combined with biomass can result in lower
greenhouse gas emissions than conventional gasoline. What are the
technology hurdles to overcome in mixing biomass with coal to produce
liquid fuels? Has the combination of biomass and coal been used at any
commercial plant? What is a realistic percentage of greenhouse gas
emissions compared to petroleum that we can expect to achieve?
Answer. Two key technical hurdles to overcome in cogasifying
biomass with coal are the biomass feedstock handling system, biomass
comes in many shapes and sizes, the moisture content of the biomass,
and impurities mixed in with the biomass. There is only one commercial
scale co-gasification of biomass with coal that is in currently in
operation worldwide. It is 253 MWe Nuon IGCC power plant in Buggenum,
The Netherlands. However, it produces electricity and not Fischer-
Tropsch liquids.
We believe that if we are going to start producing a new type of
transportation fuel to replace petroleum-based fuels then the
production of the new fuel must be consistent with our need to
significantly reduce our global warming emissions starting today and
for the long term. Therefore, the new fuel must produce well-to-wheels
lifecycle greenhouse gas emissions significantly below that of
conventional gasoline or diesel fuels, at least 20 percent lower. It is
technically possible to produce a coal derived liquid fuel with
greenhouse gas emissions at this level or lower. Modeling performed by
Bob Williams from Princeton University indicates that reducing the fuel
cycle-wide GHG emission rate 30% relative to that for the crude oil-
derived hydrocarbon fuels displaced would require that biomass (in this
case switchgrass) accounts for 14% of the fuel input. And achievement
of this emission rate would also require storing underground 85% of the
coal carbon not contained in the products along with 90% of the carbon
in the biomass (R. Williams, ``Synthetic fuels in a world with high oil
and carbon prices'', International Conference on Greenhouse Gas Control
Technologies, Trondheim, Norway, 19-22 June 2006).
Question 6. Even with the use of biomass, there are still
substantial volumes of CO2 that must be captured and safely
stored. Are there any recommendations this panel has on where to locate
CTL facilities to facilitate the storage of CO2?
Answer. This is correct. As a result it would be most cost-
effective to locate a CTL facility as near as possible to a deep
geologic formation into which the CO2 can be permanently disposed such
as a deep saline aquifer.
Question 7. Can you discuss the water requirements for a CTL plant?
Are there opportunities for reusing/recycling water in the process?
Answer. CTL production is expected to require large quantities of
water, 5-7 gallons of water for every gallon of CTL product (see http:/
/www.netl.doe.gov/technologies/oil-gas/publications/AP/
IssuesforFEandWater.pdf).
Water Requirements for Liquefaction Technologies
There are three major requirements for water in a typically
sized 50,000 barrels per steam day (BPSD) liquefaction plant:
Process Water. Process water is water that
is intimately involved in the liquefaction process and
sometimes even plays a part in chemical reactions.
Examples include water in coal gasifiers that reacts
with carbon to form CO and hydrogen and water in water-
gas-shift reactors. Process water may also be used in
scrubbers for the purpose of removing ammonia and
hydrogen chloride from syngas. Some process water is
consumed in the liquefaction process and must be
replaced with additional makeup water. It can also be
lost through evaporation into process gas streams or in
waste slurry streams, such as flue gas desulfurization
sludge or gasifier slag.
Boiler Feed Water. Boiler feed water is
used to produce steam. Much of this water is recovered
as condensate and returned to the boiler, but there is
some loss due to leakage and the occasional need for a
blowdown to purge impurities from the system. Also,
steam may need to be injected at a specific step in the
process, in which case the boiler feed water is
converted to process water.
Cooling Water. Chemical plants, refineries,
power plants, etc., often require cooling of process
streams, and a CTL plant is no different in this
regard. Such cooling is typically accomplished using
circulating water. After absorbing heat, the cooling
water is sent to a cooling tower, where evaporation of
part of the water cools the remaining portion so that
it can be recirculated. Typically, cooling water loss
through evaporation in the tower is the most
significant factor in total overall water consumption.
The amount of water required to operate a coal liquefaction
plant is a function of many variables, including the design of
the liquefaction unit, the type of gasifier used to provide the
syngas or hydrogen, the coal properties, and the average
ambient temperature and humidity. In the 1990s, Bechtel
performed a series of studies for DOE in which they evaluated a
variety of coal liquefaction schemes for indirect liquefaction
(Bechtel 1998) and determined the following water needs:
For eastern coal 7.3 gal of water/gal F-T liquid
For western coal 5.0 gal of water/gal F-T liquid
The above differences in water requirements between eastern
and western coals probably reflect the higher moisture content
of western coal and lower humidity.
One method to reduce water use at a CTL plant would be to use dry
cooling. However, this will make the plants more expensive to build.
Question 8. The auto industry has developed plug-in electric
hybrids, and this committee has heard testimony about all-electric
cars. Can you discuss the advantages and disadvantages of using coal to
produce liquid fuels vs. using coal to generate electricity to charge
batteries for electric cars and hybrids?
Answer. If coal is to be used to replace gasoline, generating
electricity for use in plug-in hybrid vehicles (PHEVs) can be far more
efficient and cleaner than making liquid fuels from coal. In fact, a
ton of coal used to generate electricity used in a PHEV will displace
more than twice as much oil as using the same coal to make liquid
fuels, even using optimistic assumptions about the conversion
efficiency of liquid coal plants. This is assuming production of 84
gallons of liquid fuel per ton of coal, and vehicle efficiency is
assumed to be 37.1 miles/gallon on liquid fuel and 3.14 miles/kWh on
electricity.
The difference in CO2 emissions is even more dramatic.
Liquid coal produced with CCS and used in a hybrid vehicle would still
result in lifecycle greenhouse gas emissions of approximately 330
grams/mile, or ten times as much as the 33 grams/mile that could be
achieve by a PHEV operating on electricity generated in a coal-fired
power plant equipped with CCS. This assumes lifecycle greenhouse gas
emission from liquid coal of 27.3 lbs/gallon and lifecycle greenhouse
gas emissions from an IGCC power plant with CCS of 106 grams/kWh, based
on R. Williams et al., paper presented to GHGT-8 Conference, June 2006.
For more detailed information on plu-in hybrid vehicles emissions
see the NRDC factsheet ``The Next Generation of Hybrid Cars: Plug-in
Hybrids Can Help Reduce Global Warming and Slash Oil'', at http://
www.nrdc.org/energy/plugin.pdf. This factsheet is based upon the just
released EPRI-NRDC Joint technical Report, Environmental Assessment of
Plug-in Hybrid Electric Vehicles, Volume 1: Nationwide Greenhouse Gas
Emissions (1015325), July 2007 (http://www.epri-reports.org/ and http:/
/www.epri-reports.org/Volume1R2.pdf).
Responses of Antonia Herzog to Questions From Senator Thomas
Question 9. If coal-derived fuels are produced so they have a
greenhouse gas profile better than the fuels they displace, would the
NRDC support them?
Answer. The impacts that a large coal gasification program could
have on global warming pollution, conventional air pollution and
environmental damage resulting from the mining, processing and
transportation of the coal are substantial. Before deciding whether to
invest scores, perhaps hundreds of billions of dollars in deploying
this technology, we must have a program to manage our global warming
pollution and other coal related impacts. Otherwise we will not be
developing and deploying an optimal energy system.
One of the primary motivators for the push to use coal gasification
is to produce liquid fuels to reduce our oil dependence. The U.S. can
have a robust and effective program to reduce oil dependence without
rushing into an embrace of liquid coal technologies. A combination of
more efficient cars, trucks and planes, biofuels, and ``smart growth''
transportation options outlined in the report ``Securing America,''
produced by NRDC and the Institute for the Analysis of Global Security,
shows how to cut oil dependence by more than 3 million barrels a day in
10 years, and achieve cuts of more than 11 million barrels a day by
2025.
To reduce our dependence on oil we should follow a simple rule:
start with the measures that will produce the quickest, cleanest and
least expensive reductions; measures that will put us on track to
achieve the reductions in global warming emissions we need to protect
the climate. If we are thoughtful about the actions we take, our
country can pursue an energy path that enhances our security, our
economy, and our environment.
With current coal and oil consumption trends, we are headed for a
doubling of CO2 concentrations by mid-century if we don't
redirect energy investments away from carbon based fuels and toward new
climate friendly energy technologies. We have to accelerate the
progress underway and adopt policies in the next few years to turn the
corner on our global warming emissions, if we are to avoid locking
ourselves and future generations into a dangerously disrupted climate.
Scientists are very concerned that we are very near this threshold now.
Most say we must keep atmosphere concentrations of CO2 below
450 parts per million, which would keep total warming below 2 degrees
Celsius (3.6 degrees Fahrenheit). Beyond this point we risk severe
impacts, including the irreversible collapse of the Greenland Ice Sheet
and dramatic sea level rise. With CO2 concentrations now
rising at a rate of 1.5 to 2 parts per million per year, we will pass
the 450ppm threshold within two or three decades unless we change
course soon.
In the United States, a national program to limit carbon dioxide
emissions must be enacted soon to create the market incentives
necessary to shift investment into the least-polluting energy
technologies on the scale and timetable that is needed. There is
growing agreement between business and policy experts that quantifiable
and enforceable limits on global warming emissions are needed and
inevitable. To ensure the most cost-effective reductions are made,
these limits can then be allocated to major pollution sources and
traded between companies, as is currently the practice with sulfur
emissions that cause acid rain. Further complimentary and targeted
energy efficiency and renewable energy policies are critical to
achieving CO2 limits at the lowest possible cost, but they
are no substitute for explicit caps on emissions.
A coal integrated gasification combined cycle (IGCC) power plant
with carbon capture and disposal can also be part of a sustainable path
that reduces both natural gas demand and global warming emissions in
the electricity sector. Methods to capture CO2 from coal
gasification plants are commercially demonstrated, as is the injection
of CO2 into geologic formations for disposal. On the other
hand, coal gasification to produce a significant amount of liquids for
transportation fuel would not be cost-effective or compatible with the
need to develop a low-CO2 emitting transportation sector.
Question 10. Please explain the difference between the NRDC
lifecycle emissions analysis and that done by the Idaho National
Laboratory, in cooperation with Baard Energy. Please account not only
for carbon dioxide emissions, but criteria pollutants as well.
Does the use of a F-T coal-derived diesel product have an improved
footprint for nitrous oxide, particulate matter, sulfur dioxide,
volatile organic compounds, and mercury over traditional sources of
diesel? Please quantify the per gallon differences for criteria
pollutant emissions that would result from consumption of a F-T coal-
derived diesel product versus traditional, petroleum-derived, diesel
fuel.
Answer. The comparison is between the fuels analysis done by
Argonne National laboratory, home of the GREET model, and the Baard
Energy analysis, which used the same model.
In a new study by the Department of Energy's Center for
Transportation Research and Argonne National Laboratory, researchers
Wang et. al.* found that every gallon equivalent of liquid coal
produces nearly three times more global warming emissions than gasoline
or diesel made from crude oil. The graph below** shows the comparison
between liquid coal produced with low and high efficiency (42%-52%
efficiency) without CCS produces 120-150% more global warming emissions
than gasoline.
---------------------------------------------------------------------------
* Wang et. al. 2007 Life-Cycle Energy and Greenhouse Gas Results of
Fischer-Tropsch Diesel Produced from Natural Gas, Coal, and Biomass,
Michael Wang, May Wu, and Hong Huo, Center for Transportation Research,
Argonne National Laboratory.
** All graphics have been retained in committee files.
---------------------------------------------------------------------------
Even with 85% capture of CO2, CTL emissions are still
15-20% higher than conventional gasoline/diesel. In addition, the Wang
study found that the liquid coal process is hugely energy consumptive
and requires more energy input per mile than conventional crude oil
which is shown in the graph below.
The Baard Energy assumptions were much more aggressive in their
analysis of a F-T plant design. It was tailored to reduce greenhouse
gas emissions by implementing biomass as a feedstock and by selecting
various process configurations and unit operations that allow the
CO2 to be minimized, concentrated, and captured at optimal
locations in the process.
A CTL plant that operates in a conventional fashion, and which is
not optimized, may increase greenhouse gas emissions (especially
carbon) by 2 to 2.5 times. Only about 30% of the incoming carbon is
converted to F-T fuels, which is eventually burned. The remaining 70%
is emitted or vented as CO2 following shift conversion or
combustion of the syngas (and F-T tail gas) in a gas turbine. The Baard
Energy analysis reduced the carbon footprint by about 30% by designing
a plant that:
1. Utilized as much heat integration as is possible to reduce
the parasitic power and to help conserve water use.
2. Used a gasifier that can operate with biomass.
3. Optimized technology choices and methods for separating
the CO2.
Question 11. You testified about a low CO2 emitting
transportation system.
Would the fuels used in that system meet specifications for
military or commercial jet aviation fuel?
Answer. There are bio-based alternative fuels which could meet the
specification for military and commercial jet fuels that are being
actively researched. Virgin Airlines announced back in April that it is
working with Boeing and GE to get a jet powered by biofuels into the
air next year. If all goes well, they could be flying commercially
inside five years, see London Times article below.
Virgin plans to fly 747 on biofuel in 2008
The first commercial aircraft to be powered by biofuel will fly
next year in what could be a significant step towards airlines
reducing their oil consumption and carbon dioxide emissions.
Virgin Atlantic is to announce today that one of its 747 jumbo
jets will be used to demonstrate that biofuels can power an
aircraft. The project, which includes Boeing and General
Electric, the engine-maker, hopes to have the ``green'' jumbo
airborne in 2008.
The airline and its partners are testing up to eight biofuels
to determine which is most effective at altitude. Ethanol,
which is becoming an increasingly popular alternative to petrol
in cars, has been rejected because it does not burn well in
thin-oxygen environments.
The idea of replacing petrol with biofuel in cars is a
significant trend in the car industry. Last year Ford announced
a 1 billion research project to convert more of its
vehicles to these new fuel sources.
However, converting an aircraft to run on biofuel was thought
to be a much longer-term project and the announcement from
Virgin today will surprise those in the industry who have
scorned the idea.
Virgin hopes that biofuel-powered aircraft could be operating
commercially within five years, which could help to cut
significantly the airline industry's carbon dioxide emissions.
At present air travel contributes 2 per cent to 3 per cent of
climate-change gases, but that level is increasing as the
activity expands. The industry is investing in lighter aircraft
and new engines to improve fuel efficiency, but biofuels could
eliminate oil dependence entirely.
Sir Richard Branson, the chairman of Virgin Atlantic, launched
an alternative fuels division last year, pledging the profits
from his airline and trains for the next ten years.
A source close to the biofuel project said: ``Everyone was
saying that flying a plane with alternative energy sources was
a decade away, but it is going much faster than that. The
demonstration by a 747 next year will be a milestone in the
airline industry's attempts to reduce its CO2
emissions and cut its fuel bills.''
Question 12. Would your low CO2 emitting transportation
system provide a single fuel that could reduce the different types in a
military theater from nine to one or two?
Answer. I, unfortunately, do not understand this question. The
transportation system we envision could produce fuels with
CO2 lifecycle emissions that can be as much as 10 times
lower than the conventional fuels they replace. See the EPA alternative
fuels factsheet, http://www.epa.gov/otaq/renewablefuels/420f07035.htm.
Question 13. Your testimony indicates a substantial reliance in the
use of plug-in hybrid vehicles. Do you have any estimates of how long
it would take to build and deploy a fleet of plug-in hybrids to
accomplish this goal?
Answer. We just released a detailed report analyzing the impact of
plug-in hybrid vehicles, see EPRI-NRDC Joint technical Report,
Environmental Assessment of Plug-in Hybrid Electric Vehicles, Volume 1:
Nationwide Greenhouse Gas Emissions (1015325), July 2007 (http://
www.epri-reports.org/ and http://www.epri-reports.org/Volume1R2.pdf).
Also, see the attached NRDC factsheet ``The Next Generation of Hybrid
Cars: Plug-in Hybrids Can Help Reduce Global Warming and Slash Oil''.
Transportation accounts for two-thirds of our oil demand, and this
sector is 97 percent reliant on oil. While there is no silver bullet,
PHEVs can be part of an effective mix of strategies to dramatically cut
our global warming pollution and oil usage in the transportation
sector, including higher fuel efficiency, biofuels, and smart growth.
Raising the fuel efficiency of conventional gasoline vehicles to 40
miles per gallon (mpg) is still the fastest, cheapest way to reduce
transportation sector global warming pollution and oil consumption, and
it's possible to reach this goal in 10 years using existing and
emerging technologies.
Question 14. Has the NRDC produced any estimates of what it would
cost American consumers to purchase these vehicles and the extent to
which they are more or less expensive than existing vehicles?
Answer. NRDC has not specifically done this analysis. A useful
report we have written on the issue of costs is: In the Tank: How Oil
Prices Threaten Automakers' Profits and Jobs. Since the late 1990s,
Detroit's three big U.S. automakers--General Motors Corp., Ford Motor
Company, and DaimlerChrysler--have relied heavily on large, truck-based
sport utility vehicles to drive company profits. But with gasoline
prices now at near-record highs, consumer demand for mid-and full-size
SUVs is sinking fast. What if higher gas prices are here to stay and
the trend away from gas-guzzling vehicles continues? This July 2005
report, a joint effort from NRDC and the Transportation Research
Institute's Office for the Study of Automotive Transportation (OSAT) at
the University of Michigan, says that sales, profits, and American jobs
are at risk if Detroit automakers continue with their current business
strategy in the face of higher oil prices. The report recommends
actions that automakers, government, and investors can take to mitigate
the risks. http://www.nrdc.org/air/transportation/inthetank/
contents.asp.
Question 15. Will we be able to manufacture plug-in hybrid
airplanes, locomotives, trucks or heavy-equipment?
Answer. Airplanes are unlikely. Locomotives already run on
electricity. Trucks and heavy equipment could us hybrid technology,
buses already do.
Question 16. How do you plug in a plug-in-hybrid if you live in
Manhattan and park on the street, or in an apartment in Seattle, or in
a college dorm in Boise? Have you calculated the costs to these cities,
institutions, and private property owners to provide an electrical
socket at every parking space?
Answer. PHEV do not need to be plugged in at every possible
location just as a car today does not need to have the capability of
being fueled wherever it is parked. For a further discussion of PHEV
requirement see, EPRI-NRDC Joint technical Report, Environmental
Assessment of Plug-in Hybrid Electric Vehicles, Volume 1: Nationwide
Greenhouse Gas Emissions (1015325), July 2007 (http://www.epri-
reports.org/ and http://www.epri-reports.org/Volume1R2.pdf).
Question 17. Does the NRDC factor in the origins of the feed-stocks
used to make a particular fuel in whether or not the NRDC supports
them? In other words, do you value domestic fuels over imported fuels,
if all environmental aspects are equal?
Answer. NRDC factors in the origins of the feed-stocks used to make
a particular fuel in determining whether a fuel meets the necessary
standards to protect the environment and public health. With today's
persistently high oil prices, Americans are spending more money than
ever on gasoline. The production and use of gas and diesel in cars,
trucks, and buses also account for 27 percent of U.S. global warming
pollution. Promising new transportation technologies such as plug-in
hybrid electric vehicles (PHEVs) and home grown biofuels could help
Americans spend less money at the pump, and at the same time reduce
global warming pollution and decrease our reliance on oil.
Question 18. China is aggressively pursuing development of a CTL
industry. If the U.S. does not, we may be importing CTL fuels from
China in the future. What impacts do you believe this would have on the
national security of the United States?
Answer. We believe it is highly unlikely that the U.S. will import
CTL fuels from China, especially in a carbon constrained world.
Therefore, U.S. national security will not be impacted.
Question 19. Does the NRDC acknowledge the recent MIT study The
Future of Coal and the premise set forth therein that coal will be an
important energy resource in the near future for the U.S. and that this
same premise is shared by the vast majority of scientists and research
organizations in the U.S.?
Answer. Please see NRDC's response to the MIT, ``The Future of
Coal'' report, ``No Time Like the Present: NRDC's Response to MIT's
`Future of Coal' Report'' at: http://www.nrdc.org/globalWarming/coal/
mit.pdf.
Question 20. Has the NRDC projected energy demands and market
response, such as the development, manufacture of vehicles, and changes
of national infrastructure, necessary to implement their ``smart
growth'' transportation options?
Question 21. Have these options been validated and embraced by the
nation's transportation industry?
Question 22. Has the NRDC considered all of the socio-economic
impacts of this ``smart growth'' proposal?
Question 23. Does the NRDC recommend that U.S. markets not import
foreign vehicles and foreign synthetic fuels which may be more
economical than the ``smart growth'' fleet approach?
Question 24. Does the NRDC recommend that the U.S. government
impose tariffs or import restrictions on other countries that are
headed towards mass production of synthetic fuels?
Question 25. Does the NRDC believe that U.S. engineering and
ingenuity can achieve further improvements of coal-to-liquids
conversion technologies that will reduce greenhouse gases?
Question 26. In your written testimony you say ``with technology
today and on the horizon it is difficult to see how a large coal-to-
liquids program can be compatible with the low CO2-emitting
transportation system we need to design to prevent global warming.''
Question 27. Does this low-CO2-emitting transportation
system exist today, anywhere in the world?
Question 28. When will it be ready to deploy here in the United
States?
Question 29. Please describe this system that the NRDC believes we
need to design.
Answers 20-29. Please see the following NRDC reports for answers to
these above questions.
Driving It Home: Choosing the Right Path for Fueling North
America's Transportation Future. North America faces an energy
crossroads. With the world fast approaching the end of cheap, plentiful
conventional oil, we must choose between developing ever-dirtier
sources of fossil fuels--at great cost to our health and environment--
or setting a course for a more sustainable energy future of clean,
renewable fuels. This June 2007 report explores the full scale of the
damage done by attempts to extract oil from liquid coal, oil shale, and
tar sands; examines the risks for investors of gambling on these dirty
fuel sources; and lays out solutions for guiding us toward a cleaner
fuel future. http://www.nrdc.org/energy/drivingithome/contents.asp.
Biofuels: The Growing Solution to Energy Dependence and Global
Warming. To grapple in a meaningful way with global warming and our
dependency on oil, America will need all of the ingenuity it took to be
the first to send a man to the moon. We need more efficient vehicles.
And we need a clean and renewable alternative to oil. Biofuels--
especially ethanol made from biomass such as switchgrass--can make a
tremendous contribution to ending our dependence on oil, and if
produced and used responsibly can also be a key component of a strategy
to beat back global warming. This index collects NRDC studies, analyses
and other policy materials that answer many of the most pressing
questions about these fuels. http://www.nrdc.org/air/transportation/
biofuels/contents.asp.
In the Tank: How Oil Prices Threaten Automakers' Profits and Jobs.
Since the late 1990s, Detroit's three big U.S. automakers--General
Motors Corp., Ford Motor Company, and DaimlerChrysler--have relied
heavily on large, truck-based sport utility vehicles to drive company
profits. But with gasoline prices now at near-record highs, consumer
demand for mid-and full-size SUVs is sinking fast. What if higher gas
prices are here to stay and the trend away from gas-guzzling vehicles
continues? This July 2005 report, a joint effort from NRDC and the
Transportation Research Institute's Office for the Study of Automotive
Transportation (OSAT) at the University of Michigan, says that sales,
profits, and American jobs are at risk if Detroit automakers continue
with their current business strategy in the face of higher oil prices.
The report recommends actions that automakers, government, and
investors can take to mitigate the risks. http://www.nrdc.org/air/
transportation/inthetank/contents.asp.
______
Responses of Jay Ratafia-Brown to Questions From Senator Bingaman
Question 1. You indicate that although the various technologies to
include biomass in gasification and sequester the carbon have been
demonstrated there is still further development necessary. How can we
best insure that federal incentives push further development of co-
gasification with biomass and not just gasification of coal?
Answer. I would like to first point out that Biomass R&D Technical
Advisory Committee, created by the Biomass Research and Development Act
of 2000 (Act), has established a national vision for bioenergy and bio-
based products. Included in its vision was the setting of a very
challenging goal that biomass will supply 5 percent of the nation's
power, 20 percent of its transportation fuels, and 25 percent of its
chemicals by 2030. This goal is equivalent to 30 percent of current
petroleum consumption and will require more than approximately one
billion dry tons of biomass feedstock annually--a fivefold increase
over the current consumption. This very challenging goal establishes
the overall NATIONAL driver to develop industry incentives. Section 307
of the Act mandated that the Secretary of Agriculture and the Secretary
of Energy establish and carry out the so-called Biomass Research and
Development Initiative (BRDI) under which ``competitively awarded
grants, contracts, and financial assistance are provided to, or entered
into with, eligible entities to carry research on, and development and
demonstration of, biobased fuels and biobased products, and the
methods, practices and technologies, biotechnology, for their
production.'' Section 307(d)(2) specifically identifies gasification
and pyrolysis as thermochemical technologies that may offer the
capabilities ``for converting cellulosic biomass into intermediates
that can be subsequently converted into biobased fuels and biobased
products''--thus bringing these technologies within the purview of the
Act and providing the mechanism by which to provide R&D incentives for
technology development.
To the best of my knowledge, little (if any) effort within the BRDI
focuses on co-gasification of biomass with coal and no funding has been
provided--presumably because of a biomass-only directive. Therefore,
Federal R&D orientation for co-gasification within the BRDI should be
modified or realigned to co-fund combined coal-biomass related
projects. I also believe that specific financial incentives could be
offered to large-scale producers of biomass waste products (e.g.,
farmers and municipalities) and large land-holders to grow/harvest/
process crop-based biomass feedstock to encourage utilization of this
resource. Note that I have not investigated the type and application of
such incentives.
Question 2. You point to the need for significant R&D and
demonstration of co-gasification and sequestration for liquid fuel
production. Do you believe these technologies are not yet ready for
full-scale commercialization? If not, how far off do you think they
are?
Answer. As I broadly discussed in my testimony, successful
technical and cost-effective implementation of the coal-biomass-to-
liquids (CBTL) system (including sequestration) particularly depends on
adoption of suitable gasification technology, addressing biomass
handling challenges, satisfying syngas ``cleanup'' constraints for the
Fischer-Tropsch process, and effectively integrating carbon capture and
storage (CCS) technology. Each area constitutes different levels of
technical status that impacts the commercial-readiness of the overall
system.
Commercial-scale co-gasification of biomass with coal has been
successfully demonstrated at the 253 MWe Nuon IGCC power plant in
Buggenum, The Netherlands (using the dry-feed, oxygen-blown Shell
entrained-flow technology), as well as at Tampa Electric's 250 MWe Polk
IGCC power plant (using slurry-feed, oxygen-blown GE entrained-flow
technology). The latter was built in the 1990s as part DOE's Clean Coal
Demonstration Program. Both of these plants operated normally at the
relative levels of biomass injected (30% by weight for the Nuon plant
and 1.5% by weight for the Polk plant). Therefore, I believe that
existing entrained-flow gasification technology developed over the past
25 years, with consistent DOE support, is effectively ready for large-
scale commercialization using combined coal and biomass feedstock. That
said, R&D associated with advanced oxygen production technology,
advanced gasifier materials, and dry-feed injection systems, currently
being conducted by DOE, can significantly enhance operability,
reliability, and economics of synthesis gas production as feed to the
Fischer-Tropsch technology. Also, advanced gasification designs, such
as the high-temperature/high-pressure `Transport Gasifier' being
developed at DOE's Wilsonville Power System Development Facility, show
the potential to greatly reduce the size and capital cost of future
gasification units.
Experience with commercial IGCC power plants, such as the Polk IGCC
plant and the Wabash River plant (another DOE Clean Coal Technology
Program investment), as well as refinery gasifiers, have established
that the CBTL syngas contaminant limits can be met with appropriate
system contaminant control methods. Thus, syngas treatment is also an
area that is currently ready for CBTL commercialization, but can be
further optimized with added R&D.
While commercial-scale testing of biomass-coal co-gasification has
shown that biomass can be successfully handled and injected into a
high-pressure entrained-flow gasifier, cost-effective transport,
storage and handling of crop-based types of biomass material is not
ready for large-scale commercial co-gasification application. Biomass
either has to be located very close to a conversion facility and
processed immediately, or some form of ``densification'' needs to be
implemented to mitigate handling issues. Since this is a well-
recognized issue for biomass, especially for conversion processes that
can consume very large quantities, a number of densification methods
have been developed that are applicable, but are currently limited to
smaller-scale applications. Technologies, such as pelletization,
torrefaction, and pyrolysis, and suitable logistics strategies need
more R&D, scale-up testing, and integrated demonstration to permit the
effective use of dispersed biomass materials. Therefore, roughly 3 to 5
years of R&D effort is needed to bring about needed improvements and
demonstration.
Integration of CCS technology will reduce the greenhouse gas
footprint of CBTL to a much greater extent than is possible with just
co-gasifying renewable biomass materials. However, while conventional
CO2 capture technology is commercially available and well-
proven for gasification-type applications, it increases capital
expenditure and operating costs. Therefore, DOE is developing advanced
membrane technologies to lower this economic impact. More importantly,
the actual sequestration of CO2 is far from commercially
available and acceptable, albeit years of experience with enhanced oil
recovery (EOR) applications greatly supports this effort. As stated in
my testimony, key challenges are to demonstrate the ability to store
CO2 in underground geologic formations with long-term
stability (permanence), to develop the ability to monitor and verify
the fate of CO2, and to gain public and regulatory
acceptance of this process. DOE's seven Regional Carbon Sequestration
Partnerships are engaged in an effort to develop and validate CCS
technology in different geologies across the Nation. This is vital to
sequestration's future and use with the CBTL technology. DOE's
programmatic goal is to demonstrate a portfolio of safe, cost-effective
CCS technologies at commercial-scale by 2012, making it available for
deployment for CBTL beyond 2012.
In summary, I believe that we are likely 5 to 8 years away from
potential commercial deployment of a large-scale CBTL facility that
fully incorporates CCS capability. However, CBTL could be deployed in
as little as three years with a design that allows for later inclusion
of CCS and biomass feedstock on an as-available basis from both waste
and cop-based sources.
Responses of Jay Ratafia-Brown to Questions From Senator Sanders
Question 3. The Intergovernmental Panel on Climate Change has
recently issued its Fourth Assessment Report Summary for Policy Makers.
In that Report they concluded that the evidence that global warming is
real and caused by humans is unequivocal. The MIT study, ``The Future
of Coal,'' suggested that Carbon Capture and Storage (CCS) may increase
the cost of electricity from coal by 20%, but an aggressive energy
efficiency campaign could be conducted, so that less electricity is
used, bringing our electricity bills down by 20% or more. What do you
see as the cost of liquid fuel (diesel) and gaseous fuel from coal and/
or coal-biomass with CCS versus conventional diesel and natural gas in
the near term and long term?
Answer. Recent economic data isn't available for a proposed CBTL
facility. However, DOE's National Energy Technology Laboratory (NETL)
is currently conducting a project to estimate realistic costs of diesel
fuel produced via alternative coal-biomass co-gasification options. I
recommend that the results of this effort be obtained for the record
when available later in 2007.
Note that a very recent (April 2007) RDS/SAIC/Parsons/Nexant
assessment of a commercial scale coal-to-liquids facility producing
50,000 barrels/day of Fischer-Tropsch liquids (Naphtha and diesel) was
sponsored by DOE (http://www.netl.doe.gov/energy-analyses/pubs/
Baseline%20Technical%20and%20Economic-
%20Assessment%20of%20a%20Commercial %20S.pdf). The facility also
supplies 124 MWe net electricity to the grid and incorporates
CO2 sequestration. Cost of the diesel portion of the F-T
liquids is estimated to range from $1.47 to $2.45/gallon. This
assessment indicates that project viability (based on return-on-
investment or ROI) depends heavily on crude oil prices used to produce
conventional diesel fuel. A reference case, tied to a crude oil price
of $61/bbl, provides a 19.8% ROI, while crude oil prices greater than
$37/bbl would achieve ROIs greater than 10%, and a 15% ROI can be
achieved at crude oil prices greater than $47/bbl. Policy actions were
also shown to significantly impact expected ROIs--Federal loan
guarantees were shown to have the largest ROI impact (increasing the
ROI by more than 11 percentage points from the reference case) due
mostly to an accompanying change in the debt-to-equity ratio assumed to
finance the proposed project. F-T liquids subsidies was shown to
provide a 9 percent increase in ROI based on the existing federal
subsidy for liquid transportation fuels from coal of 50 cents/gallon
($21/barrel), an incentive included in the 2005 Federal Transportation
Bill (H. Res 109-203, Title XI, Section 11113(d)). Note that this
credit is set to expire in 2009, so these credits would have to be
extended in order for such a CTL (or CBTL) project to benefit
accordingly.
Question 4. I join Senator Murkowski in her concern about the need
to retrofit our existing coal fired power plants to address the issue
of carbon capture and storage. Some of the testimony suggested that
adding ``oxyfuel'' to these older plants would be the best path to take
as this burns pure oxygen, instead of outside air, producing a carbon
dioxide-rich exhaust stream, with little or no NOX, so the
CO2 is more concentrated and easier to capture for
sequestration. Do you have any information on the ease/feasibility of
retrofitting older coal plants or other coal-burning industrial
facilities with ``oxyfuel''?
Answer. Retrofitting existing coal-fired power plants to add carbon
capture capability is being carefully investigated by boiler vendors
with support from DOE. The two basic approaches are to integrate: 1)
conventional amine-type scrubbing technology to remove CO2
from the flue gas, and 2) oxygen-fired combustion or oxycombustion
(with flue gas recirculation) to produce flue gas that is mostly
CO2, which avoids the requirement for CO2
scrubbing technology. Both approaches have been shown to be feasible
with no major technical barriers other than the need for 5 to 8 acres
of adjacent land and appropriate sequestration locations. However, both
require considerable capital investments and significantly reduce the
efficiency and output of a power plant.
The basic deficiency of option 1 is that the air used for
combustion contains nearly 80% nitrogen, which results in flue gas that
only contains about 12% CO2 (volume basis)--the nitrogen
dilutes the CO2 and makes it more difficult to capture. The
use of conventional amine scrubbing to capture CO2 from flue
gas and pressurize the CO2 for sequestration can nearly
double the estimated cost of electricity from a conventional power
plant (see ``Engineering Feasibility and Economics of CO2
Capture on an Existing Coal Fired Power Plant, Alstom Power, Inc., DOE
Final Report, June 2001).
In the second option, the use of a high purity oxygen (>95%) can
substantially reduce the amount of nitrogen in the product flue gas.
While the use of pure oxygen would result in extremely high gas
temperatures, which can exceed boiler metal temperature limitations,
CO2 gas recirculation can be used to effectively moderate
the gas temperatures. This approach is appropriate for retrofit
applications of existing pulverized coal units, where the existing heat
transfer surface has been sized for a certain gas flow and temperature
specifications. The previously-sited study indicates that the use of a
commercial cryogenic-type air separation unit with appropriate boiler
modifications would represent the more cost-effective solution for a
retrofit application. Calculated cost-of-electricity values range from
12 to 19% lower than the corresponding values for option 1. Use of
advanced air separation membrane technology, which should become
commercial within several years, will significantly reduce capital
investment and operating cost to further reduce retrofit impact on
plant efficiency and operation (see http://www.netl.doe.gov/
technologies/coalpower/ gasification/gas-sep/index.html).
Responses of Jay Ratafia-Brown to Questions From Senator Salazar:
Question 5. It appears from the written testimony, that liquid
fuels produced from coal combined with biomass can result in lower
greenhouse gas emissions than conventional gasoline. What are the
technology hurdles to overcome in mixing biomass with coal to produce
liquid fuels? Has the combination of biomass and coal been used at any
commercial plant? What is a realistic percentage of greenhouse gas
emissions compared to petroleum that we can expect to achieve?
Answer. TECHNOLOGY HURDLES.--While all types of gasification
technology have been proven to be capable of converting various biomass
feedstock, future biomass gasifiers (for production of liquid fuels)
need to be very large by current biomass gasification standards. This
scale requirement likely limits technologies to circulating fluidized
bed technology and large-scale entrained flow designs used for coal (or
high-throughput transport-type technology currently in development).
Similarly, oxygen-blown, pressurized systems are probably essential,
which gives the edge to the entrained flow technology.
Recent commercial-scale biomass co-gasification experience at the
Polk IGCC (Tampa Electric) and Nuon Buggenum IGCC plants (Nuon Power
Buggenum BV, The Netherlands) has been performed successfully. A key
outcome of this experience shows that biomass feed size, a critical
design and operating parameter for the entrained-flow technology can be
on the order of 1 mm due to biomass' high reactivity relative to coal.
The importance of this lies in the capability to minimize biomass
milling power consumption and possibly avoid other efficiency-reducing
pre-treatment processes like torrefaction. The Nuon experience has also
shown that a relatively high throughput of biomass is possible in an
entrained-flow unit that is co-gasifying coal; up to 30% (by weight)
has been successfully processed. While the slagging performance of the
biomass ash is an issue, testing has shown that flux material can be
added to the gasifier to re-establish acceptable slagging performance.
The bottom-line is that the practical limit of biomass processing is
probably associated more with biomass preparation and feed issues and
desired syngas production level, than the capabilities of the
entrained-flow gasification process and syngas cleanup system.
The best choice for the co-gasification of syngas from biomass and
coal at large-scale involves biomass milling to 1 mm size particles,
compression a by piston or rotary feeder, and subsequent feed via screw
into a high pressure/high temperature entrained-flow gasifier.
Preferably, coal will also be fed dry to maximize efficiency. This
option, as investigated in Europe, shows the lowest amount of unit
operations and has the highest energy conversion efficiency. It has
been calculated that the efficiency from wood with 35% moisture to 40
bar syngas with H2/CO=2 is 81%. Note, however, that this
approach is highly dependent on biomass feed technology that is
untested and unproven for this challenging application. Other, less
challenging design configurations make use of torrefaction to permit
biomass feed directly with coal and coke or flash pyrolysis of the
biomass to produce an oil/char-slurry that can more easily be pumped
into the gasifier under pressure.
Increased plant scale and increasing energy input from biomass
translates into higher biomass consumption and costs due to longer
biomass transport distances from larger growing areas. This sets up a
potential mismatch between the appropriate scale of the pre-treatment
portion of the processing system and the gasification portion.
Therefore, the first configuration issue to be considered is the plant
scale (e.g., 1,200 MWth) and its impact on the biomass capacity
required and the likely dispersion of the biomass resources. Once the
biomass resource capacity is generally determined by plant scale and
relative biomass input need, pre-treatment options can be considered
based on gasification plant design feed requirements, pre-treatment
conversion economies-of-scale, and transport costs for alternative
biomass intermediates. An effective way to deal with the scale
``mismatch'' between pre-treatment and gasification may be achieved by
splitting pre-treatment from gasification: biomass can be pre-treated
in relatively small-scale plants close to the geographical origin of
the biomass and the intermediate biomass feedstock is transported to
the central large-scale plant where it is converted in combination with
coal. The pre-treatment should preferably result in an easy to
transport material with higher energy density. Conventional milling and
pelletization is one possible option. Potentially more attractive is
the use of dedicated pretreatment that also produces a feedstock that
can be used directly and more easily in the large-scale syngas plant.
This is represented by the production of oil/char slurry by fast
pyrolysis or the production of torrefied wood pellets. Oil and slurry
mixtures have a clear advantage over wood chips and straw in transport
bulk density and notable in energy density. For longer distance
collection of biomass, this difference may be a decisive economic
factor. Storage and handling may also be important because of seasonal
variations in production and demand; some storage will always be
required. Apart from the bulk density and the energy consideration, it
is important to note that raw biomass will deteriorate during storage
due to biological degradation process. Char, however, is very stable
and will not biologically degrade. Another important factor is
handling, in which liquids have significant advantages over solids.
To bridge the gap between the existing and proven technology for
coal and the implementation of combined coal-biomass co-gasification,
an R&D strategy is necessary that will focus on four interrelated
areas:
1. Biomass pretreatment & feeding;
2. Gasification & burner design;
3. Ash and slag behavior; and
4. Syngas clean-up.
Biomass Pretreatment & Feeding.--Biomass cannot be handled and fed
similar to coals, as the biomass properties are completely different
(i.e. biomass has a fibrous structure and high compressibility).
Therefore, either biomass has to be pretreated to make it behave
similar to coal or dedicated biomass handling systems have to be
developed. The advantage of pre-treating the biomass to match coal
properties (i.e. by torrefaction), is that it allows short-term
implementation of biomass firing in existing plants. The efficiency can
be improved when a dedicated feeding system for solid biomass is
developed. The primary R&D issue directly related to gasification is
how to feed a variety of biomass materials into the gasifier with
minimum pretreatment and inert gas consumption--DOE has sponsored the
development of the Stamet Posimetric Pump to feed solids directly into
a gasifier at high pressure. Long term tests will be required to move
the technology to full commercial acceptance. While there isn't any
reason to believe that appropriately pre-treated biomass material can't
be handled by this pump, data is required via testing of such material.
The other major R&D priority in this area is to address the important
issue of off-site versus on-site pre-treatment of biomass into
intermediate forms that are both more economical to transport and
store. This needs to consider the environmental impacts of different
methods.
Gasification & Burner Design.--The general objective of R&D on
these topics is to determine the optimum burner design for solid
biomass feeding with coal/coke and the optimum gasification conditions
with respect to biomass particle size (does 1 mm biomass suffice),
maximum efficiency, maximum heat recovery, minimum flux use, minimum
inert gas consumption, complete conversion, production of biosyngas
with desired quality (i.e. low CH4 and no tars).
Ash and Slag Behavior.--In a slagging gasifier the ash and flux are
present as a molten slag that protects the gasifier inner wall against
high temperatures. The slag must have the right properties (e.g. flow
behavior and viscosity) at the temperature in the gasifier. It is
crucial to have a good understanding of the combined slag behavior as
function of the gasification temperature, biomass and coal ash
properties, and selected flux.
Syngas clean-up.--Gas cooling from the gasifier outlet temperature
(1000-1300 C) is normally done by a partial gas quench (to 800 C)
with recycled clean gas or water injection. A gas quench is preferred
considering the higher efficiency and amount of energy that can be
recovered. However, it requires a large gas recycle (typically 1:1 to
the raw gas) resulting in twice as large gas cleaning section (compared
to a system without gas recycle). Therefore, there is a substantial
incentive to develop an innovative hot gas cooler for cooling of the
hot gas with energy recovery and to avoid the recycle. The syngas is
further cooled to the level necessary for the gas cleaning. R&D
activities could focus on the development of a fluidized bed gas cooler
and other innovative designs.
GREENHOUSE GAS EMISSIONS.--A key advantage of co-gasifying biomass
with coal in large-scale gasifiers is the displacement of coal, a high
carbon-content feedstock, with the renewable biomass feedstock that
commensurately reduces carbon discharge (from syngas or liquid fuels
utilization) based on the level of biomass heat input to the gasifier.
Excluding carbon capture, the full level of carbon emissions reduction
associated with the co-gasification of woody biomass depends on
quantity of coal displaced as well as emissions related to harvesting/
transport, drying, and pulverization of this renewable resource. If
waste heat is used as a drying medium, often a likely option, then
harvesting/transport and pulverization represent the largest sources.
Given the high efficiency of large-scale harvesting methods,
pulverization will likely represent the largest source of exogenous
carbon emissions for the woody biomass. Pulverization of waste wood has
been estimated to yield 29 kg CO2/metric ton, based on data
from Denmark. Relative to pulverization yield of CO2, the
transport of biomass is approximately an order of magnitude lower in
value. Therefore, harvesting/transport and pulverization of woody crops
for fuels production will yield about 32 kg CO2/metric ton
biomass supplied, which is less than 2% of the total carbon content of
the wood (per CO2-equivalent) that is effectively recycled.
Relative to fuels refined from crude petroleum, coal-to-liquids
(CTL) production (without integrated CO2 capture) emits 2 to
2.5 times as much CO2 per unit volume of liquid fuel. With
integrated CO2 capture, CTL yields approximately the same
CO2 emissions as petroleum refining. Replacement of a
portion of the coal feedstock with biomass (CBTL) will reduce
CO2 emissions for facilities without or with integrated
CO2 capture capability. For the former, 50 to 60 percent of
the coal input would need to be replaced to yield CO2
emissions equivalent to that of petroleum refining; however, due to the
lower energy content of biomass, about 1.4 tons of biomass would need
to replace each ton of coal to maintain equivalent liquids production
level (about 60% biomass and 40% coal by weight). For a CBTL facility
with integrated CO2 capture, a carbon-neutral facility would
require that coal consumption be reduced by about one-third via
replacement with an energy equivalent quantity of biomass, resulting in
a facility utilizing approximately 60% coal and 40% biomass by weight.
Higher levels of biomass feed will result in a net reduction of
CO2.
Question 6. Even with the use of biomass, there are still
substantial volumes of CO2 that must be captured and safely
stored. Are there any recommendations this panel has on where to locate
CTL facilities to facilitate the storage of CO2?
Answer. I note for the record that key CO2 storage
issues are: 1) Storage period--should be prolonged, preferably hundreds
to thousands of years; 2) Cost of storage (including the cost of
transportation from the source to the storage site)--must be reduced;
3) Risk of release--must be understood and be minimized or eliminated;
4) Environmental impact--must be minimal; and 5) Regulatory/legal
impact--storage method should not violate national or international
laws and regulations.
Storage media currently considered include geologic sinks and the
deep ocean. Geologic storage includes deep saline formations
(subterranean and sub-seabed), depleted oil and gas reservoirs,
enhanced oil recovery, and unminable coal seams. Deep ocean storage
includes direct injection of liquid CO2 into the water
column at intermediate depths (1000-3000 m), or at depths greater than
3000 m, where liquid CO2 becomes heavier than sea water, so
it would drop to the ocean bottom and form a so-called ``CO2
lake.'' In addition, other storage approaches are proposed, such as
enhanced uptake of CO2 by terrestrial and oceanic biota, and
mineral weathering. Captured CO2 can also be utilized as a
raw material for the chemical industry; however, the prospective
quantity of CO2 that can be utilized is a very small
fraction of CO2 emissions from anthropogenic sources.
Combined storage and utilization can be practiced via enhanced oil and
gas recovery schemes.
Since DOE has established an extensive R&D program to fully
investigate all options related to CO2 capture and
sequestration, I recommend that the committee review the DOE program,
its goals, and progress to-date. I fully concur with Mr. James Bartis
of Rand corporation who recommended that the U.S. government take
action as appropriate and as soon as feasible to conduct multiple
large-scale demonstrations of geologic sequestration at various
strategic locations across the United States.
Question 7. Can you discuss the water requirements for a CTL plant?
Are there opportunities for reusing/recycling water in the process?
Answer. I have briefly investigated the issue of CTL water
consumption versus that of a conventional petroleum refinery:
calculations are based on recent DOE/NETL studies for `IGCC with
sequestration' (IGCC/S) and CTL (50,000 Bbl/day facilities). Both
studies used Conoco-Philips gasifiers. The IGCC/S study included an
assessment of water consumption, but the CTL study did not. I have
compared the two based on syngas production and condenser duty. While
most of the water consumption is associated with the water-gas-shift
steam and cooling tower make-up, a small portion of the water
consumption can be considered associated with the net electricity
production of the CTL plant. Based on syngas flow and condenser duty
ratios for these plants, I estimate a water consumption range for the
CTL plant of roughly 6 to 8 Bbl water per Bbl of F-T liquids for a
conventional CTL plant design. [Note that a recent Mitretek [now
Noblis] study indicates that a properly designed CTL plant can reduce
water consumption to 1Bbl/Bbl F-T liquids via use of dry cooling
towers: ``A Techno-Economic Analysis of a Wyoming Located Coal-to-
Liquids (CTL) Plant,'' sponsored by DOE/NETL] This compares with
conventional refinery numbers ranging from 1.85 to 2.6 Bbl water/Bbl of
processed crude. Conventional CTL water consumption apparently needs to
be cut by 55 to 75% to achieve the same water consumption rate as a
conventional refinery. The previously mentioned study shows that this
is doable at a higher capital investment.
Question 8. The auto industry has developed plug-in electric
hybrids, and this committee has heard testimony about all-electric
cars. Can you discuss the advantages and disadvantages of using coal to
produce liquid fuels vs. using coal to generate electricity to charge
batteries for electric cars and hybrids?
Answer. CTL and CBTL plants can produce both liquid fuels and
electricity for sale to the grid. These products are not mutually
exclusive of one another, and the mix of electricity to liquids
production can be adjusted within the framework of the plant design and
modified even after a plant has been built. Therefore, such a facility
has the capability to flexibly serve multiple markets and adjust to
market demand for liquid fuels and electricity.
Responses of Jay Ratafia-Brown to Questions From Senator Thomas
Question 9. We are told that Fischer-Tropsch fuels require no
modifications to existing diesel or jet engines, or delivery
infrastructure including pipelines and fuel station pumps. Is that
true?
Answer. The F-T diesel (FTD) produced by CTL and CBTL is a high-
value fuel that is superior to petroleum-based diesel in a number of
ways, principally the high cetane number, which reduces combustion
noise and smoke, and because it is sulfur, nitrogen and aromatic-free.
Below, I briefly discuss the qualities of FTD versus standard No. 2
diesel fuel (D2).
fuel quality
FTD is much closer to D2 by quality (lubricity, heating value,
viscosity, ignition temperature) than most of the other fuel
substitutes, such as methanol and ethanol, and will require no, or very
insignificant, modifications to equipment currently fueled by
petroleum-based diesel fuel.
Lubricity is especially important for compression-ignition engines
and for gas turbines, as the liquid fuel serves in these devices as a
lubricant for pumping systems. In the case of diesel fuel, the fuel
acts as a lubricant for the finely fitting parts in the diesel fuel
injection system. While all diesel fuel injection systems depend on the
fuel to act as a lubricant, rotary pump-style injection systems seem to
be the most sensitive to fuel lubricity. Lubricity of FTD fuel is in
the range of the lubricity of D2 and its use will not require any
changes in the pumping system or additions of special lubricity agents.
The flash point of liquid fuel, a measure of fuel stability, is the
lowest temperature at which sufficient vapor is given off to form a
momentary flash when a flame is brought near the surface. The flash
point for FTD is almost equal to that of D2. FTD also has viscosity in
the same range as D2.
[Note that an additive package may also be added to the raw FTD in
order to bring the fuel up to specification for sale as diesel fuel to
the end-use consumer. These additives are used to improve performance,
handling, stability and potential contamination and are commonly used
for petroleum-based diesel as well.]
fuel toxicity and odor
FTD fuel is colorless, odorless, and low in toxicity.
Toxicity.--The U.S. DOE Status Report\1\ discusses results of a
comparative study on emissions of the four ``Toxic Air Contaminants''
from diesel exhaust listed in the Clean Air Act (benzene, formaldehyde,
acetaldehyde, and 1,3 butadiene) along with toxic polycyclic aromatic
hydrocarbons, both in the gas phase and bound in particulate matter.
The study showed FTD to have among the lowest emissions of the test
fuels for almost all of the toxic compounds analyzed, and lower
emissions than petroleum diesel for all of them. Tests on mammals given
acute exposures to the FTD fuel itself--oral, skin and eye--also
indicated that the FTD test fuel itself is less toxic than petroleum
diesel.
---------------------------------------------------------------------------
\1\ Status Review Of Doe Evaluation Of Fischer-Tropsch Diesel Fuel
As A Candidate Alternative Fuel Under Section 301(2) Of The Energy
Policy Act Of 1992.
---------------------------------------------------------------------------
Biodegradation.--Laboratory test data submitted by Shell and
Syntroleum for FTD compared to petroleum diesel, and a group of blends
of FTD with petroleum diesel, confirm that FTD will be roughly
comparable in biodegradation to petroleum diesel overall.
Ecotoxicity.--Ecotoxicity data have been submitted by Syntroleum
and by Shell. Tests were done on mysid shrimp, various freshwater fish,
algae, and bacteria. All of these tests showed low toxicities for FTD
by showing that only at high concentrations, if at all, were there
significant mortalities. Overall, available data indicate that FTD
should have considerably lower ecotoxicity than petroleum diesel.
emissions
Information from the California Energy Commission,\2\ where
unmodified diesel engines, fueled with neat FTD fuel (derived from NG),
showed the following average emission reductions per mile compared to
typical California diesel fuel:
---------------------------------------------------------------------------
\2\ Gas-to-Liquid Fuels In Transportation. California Energy
Commission Webpage.
Hydrocarbons--30%
Carbon Monoxide--38%
NOX--8%
Particulates--30%.
Question 10. Can biomass co-feed CTL technology jump-start the
cellulosic biomass fuels industry?
Answer. In my mind, the terminology ``cellulosic biomass fuels
industry'' connotes technology that aims to extract fermentable sugars
from cellulose-based feedstock (e.g., acid hydrolysis enzymatic
hydrolysis) to produce liquid fuels such as ethanol. Compared to this
``sugar-based framework,'' that produces sugar feedstock for
processing, gasification represents an alternative ``thermochemical-
based framework'' that thermally converts the hydrocarbon building
blocks of cellulosic material into synthesis gas (CO and H2)
for further conversion into fuels via the Fischer-Tropsch technology.
Therefore, I don't see the CBTL technology as ``jump-starting'' the
cellulosic biomass fuels industry from the perspective of moving the
sugar-based technology platform forward, except from a competitive
perspective.
That being said, the primary philosophy behind CBTL is to jump-
start the thermochemical-based cellulosic biomass fuels industry, both
rapidly and cost-effectively, by utilizing the technological strengths
of large-scale, commercial coal gasification technology that has been
developed over the past 25 years, as well as the use of coal as the
base feedstock that assures consistent operation. This also relies on
the environmental strengths that `advanced gasification with integrated
carbon capture', key components of CBTL, can bring to the table.
Question 11. In addition to financial incentives, in the form of
tax credits, appropriations, and other tools at Congress' disposal,
what regulatory approaches do you believe can be taken to advance the
development of a domestic coal-derived fuel industry? Please address
not only liability issues associated with carbon dioxide sequestration,
but permitting of the actual plants, obstacles to construction of
infrastructure, and other issues that you believe could be addressed
from a regulatory, rather than a financial, standpoint.
Answer. While financial incentives are the most critical in
reducing business risk to early commercial projects, Siting Risk and
Regulatory and Permitting Uncertainty have been identified in various
large-scale gasification system assessment surveys as critical to
project risk reduction. Significant siting and permitting risk is
associated with the primary conversion facility, feedstock (both coal
and biomass) delivery methods and routes, fuel and CO2
pipelines (assuming sequestration), feedstock storage (coal and
biomass), electricity transmission lines, byproduct storage/handing
facilities (e.g., ash and slag, sulfur containment), and CO2
repository (if needed for sequestration, and which may well be located
in a different locale than the primary plant). Recommended risk
reduction via regulation can implement:
Generic and uniform licensing standards for siting and
permitting facilities in multiple jurisdictions within a
region;
Coordination among Federal agencies, State environmental and
permitting agencies, and state utility rate-setting entities
(PUCs) to facilitate national, regional, and state energy and
environmental regulations and policies.
Federal or state indemnification for facility byproducts
(e.g. slag, hydrogen, liquid fuels, sequestered
CO2).
Siting Risk.--The sheer number and variety of siting issues can
create significant delays in approving and permitting a conversion
facility, continuing to push back market entry. Major acceptability and
siting concerns that have been identified are the cost of electricity
in a community, jobs, availability and proximity of local resources,
fuel diversity, available transmission capacity, potential local and
regional air and water impacts, byproduct/waste disposal concerns,
transmission line and pipeline rights-of-way, the NIMBY effect, and
general negative perceptions of large coal/biomass-consuming plants.
Permitting Risk.--A substantial number and variety of siting issues
for a project can create significant delays in approving and permitting
a plant, which may be a factor in delaying entry into the market. Since
CBTL is not an established energy conversion technology, the permitting
process can be extensive and very complex with regard to environmental
and construction permitting. Federal and state regulators should
develop uniform licensing standards and regulations for CTL/CBTL plants
(including cogeneration), as well as a single, dedicated information
source and database that can assist in the siting and permitting of
plants and procurement of technology and equipment for projects. The
states should also develop Memoranda of Understanding specifying
compatible regional standards to address air shed issues associated
with facility permitting. Regulation could establish a multi-
jurisdictional state/federal-working group to deal with regulatory
implementation issues, in cooperation with the National Association of
Regulatory Utility Commissioners (``NARUC'').
Regulatory Risk.--The regulatory uncertainty associated with future
national environmental standards and the licensing/permitting
requirements in different locations represents important barriers to
technology adoption. Uncertainty regarding future regulation of plant
emissions, especially CO2, makes it is difficult for
stakeholders to accurately assess the economic and financial value of
adopting CTL/CBTL technology (e.g., forward value of emissions
reductions). In addition, the environmental regulations specifically
applicable to gasification-type technology have, so far, been confusing
and differ from that of coal combustion-based plants due to the unique
design characteristics of gasification technology (e.g., use of a
combustion turbine to generate power).
Recent EPA multi-pollutant environmental regulations help reduce
the uncertainty of emissions regulations related to NOX,
SOX, and mercury. In March 2005, EPA issued both the Clean
Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR) that
will permanently cap emissions of sulfur dioxide (SO2) and
nitrogen oxides (NOX) in the eastern United States and DC,
and permanently cap and reduce mercury emissions from coal-fired power
plants. While this does not preclude the adoption of further
legislation that will alter these new rules, they likely identify
minimum emissions reduction standards. On this basis, added appropriate
measures could be regulated to perhaps monetize or otherwise recognize
the future value of emissions allowances, and a definitive set of
accounting standards reflecting the valuation of these credits could
also be developed.
A highly critical factor associated with regulatory risk is the
possibility of future carbon limits. The uncertainty surrounding such
future regulation increases project risk substantially, which can be
relieved via appropriate legislation/regulation to indemnify
CO2 pipelines and storage facilities. As an example, the
sate of Texas passed legislation that establishes ownership of
CO2 captured by DOE's FutureGen clean coal project--the
state will provide indemnification for the CO2 permanently
stored in deep underground formations and also retains the right to
sell CO2 for enhanced oil recovery if not injected. However,
projects that exceed state boundaries may cause problems that could be
dealt with via national legislation and regulation to foster
appropriate regional solutions.
Question 12. What specific technology gaps need to be closed by DOE
and private industry working together to reduce the technical and
economic risk of coal-derived fuel plants?
Answer. With respect to CBTL technology gaps, please see my answer
to question 5. Please note that I fully concur with the testimony of
Mr. James Bartis of Rand Corporation with regard to required steps that
should be taken to reduce risk and quickly move this technology
forward, namely: 1) cost-share in the development of a several site-
specific commercial plants based on coal and/or a combination of coal
and biomass; 2) foster early commercial experience by firms or groups
with the technical, financial, and management capabilities to
successfully carry out large-scale projects of this type and to capture
and exploit the learning that will accompany actual plant operations;
3) conduct multiple demonstrations and, by way of such demonstrations,
develop the regulatory framework required for a commercial
sequestration industry; and 4) increase support of RD&D, testing and
evaluation of advanced concepts and subsystems for integrating coal and
biomass for the production of liquid fuels via gasification and Fisher-
Tropsch technologies.
Question 13. Specifically, what technology gaps or market
limitations would prevent adding large amounts of biomass to a coal
gasifier? At what stage is this research and development?
Answer. The practical limit of biomass processing is probably
associated more with biomass preparation and feed issues and desired
syngas production level, than the capabilities of the entrained-flow
gasification process and syngas cleanup system. As cited in my answer
to question 5, a key technology limitation is associated with high-
throughput, dry feed of coal + biomass into a high temperature/pressure
entrained flow gasifier. DOE has sponsored the development of the
Stamet Posimetric Pump to feed solids directly into a gasifier at high
pressure, which is critical breakthrough if it can reliably handle both
coal and biomass. This pump was originally developed to permit feeding
oil shale into gasifier systems and to provide positive flow control.
The device consists of a single rotating element that is made up of
multiple disks and a hub that are installed inside a stationary
housing. Material entering the pump becomes locked between the discs
and is carried around by their rotation, which means the pump
experiences virtually no wear. The housing is equipped with an abutment
that directs the coal/biomass out of the discharge and makes the pump
self-cleaning. In total, there are over 150 of these units installed at
commercial facilities, but all are used in atmospheric applications. In
recent DOE sponsored tests, it was able to feed coal (lignite,
bituminous, and PRB) to a pressure of 560 psia. The ultimate goal of
the development program is to achieve 1000 psia. Long term tests will
be required to move the technology to full commercial acceptance,
particularly for biomass. While there isn't any reason to believe that
appropriately pre-treated biomass material can't be handled by this
pump, data is required via accelerated testing of such material. Note
also that a piston compressor has been developed in Europe in which
approximately 50 times less inert gas is consumed to feed solids.
Handling and treatment of biomass feedstock for co-gasification
represents perhaps the most significant technical issue from an
operational perspective that would limit biomass feed. While testing
has shown good performance with co-gasification of woody biomass and
coal, transferring the material to the plant and into the gasifier in a
suitable form is critical to performance and overall efficiency. A
complete feed system tailored to the particular biomass fuel must be
used if plant availability (with biomass) is to be maintained.
Significant quantities of biomass will be required to produce a small
portion of the plant's power due to the relatively low energy density
of biomass fuel. Consequently, the supplemental biomass feed system(s)
could be physically almost as large as the feed system for normal solid
fuel such as coal or petroleum coke.
Biomass Transport.--Fuel transport is a major environmental concern
worldwide. Woody biomass and grasses are a dispersed resource that
requires road transport. This has provoked local protest and has proved
a significant, if not the major factor in the failure of at least one
biomass power plant in Europe to obtain planning permission. Even in
cases where additional road transport is under 1% of current heavy-duty
truck traffic, this has been sufficient to provoke protest. Plant
operators with a brand image to protect are particularly sensitive to
such public concern. European experience has shown that feedstock
transport to a large-scale plant is always a contentious area. Even
plants where almost all the local biomass is to arrive via dual
transport methods have been refused planning permission, most of the
objections being on traffic grounds. The difficulties in fuel delivery
should not be underestimated and, therefore, studied closely.
Transport of biomass is expensive due to generally low bulk
densities of biomass fuels and since the cost of biomass fuel is a
critical factor in the economics of co-gasifying, the costs of
transportation (and thus transport distances) are very important
issues. In general biomass heating values [MJ/kg] and particle
densities are about half of that of coal, whereas bulk raw densities
[kg/m3] are about 20% of that of coal, resulting in overall
biomass energy density [MJ/m3] approximately 10% of coal. As
a consequence, when co-gasifying raw biomass at a 10% heat input rate
with coal, the volume of coal and biomass can be similar and therefore
biomass requirements with regard to transport, storage and handling are
very high in comparison to its heat contribution.
Biomass Pretreatment & Feeding.--Biomass cannot be handled and fed
similar to coals, as the biomass properties are completely different
(i.e. biomass has a fibrous structure and high compressibility).
Therefore, either biomass has to be pretreated to make it behave like
coal or dedicated biomass handling systems have to be developed. The
advantage of pre-treating the biomass to match coal properties (i.e. by
torrefaction), is that it allows short-term implementation of biomass
firing in existing plants. The pre-treatment should preferably result
in an easy to transport material with higher energy density.
Conventional milling and pelletization is one possible option.
Potentially more attractive is the use of dedicated pretreatment that
also produces a feedstock that can be used directly and more easily in
the large-scale syngas plant. This is represented by the production of
oil/char slurry by fast pyrolysis or the production of torrefied wood
pellets. Oil and slurry mixtures have a clear advantage over wood chips
and straw in transport bulk density and notable in energy density. For
longer distance collection of biomass, this difference may be a
decisive economic factor. Storage and handling may also be important
because of seasonal variations in production and demand; some storage
will always be required. Apart from the bulk density and the energy
consideration, it is important to note that raw biomass will
deteriorate during storage due to biological degradation process. Char,
however, is very stable and will not biologically degrade. Another
important factor is handling, in which liquids have significant
advantages over solids. This is an area that requires comprehensive R&D
and large-scale demonstration efforts in the U.S. if energy crops are
to be supplied in sufficient quantities to CBTL facilities around the
country. Only small-scale efforts have been supported to-date.
Question 14. What research and demonstration steps are necessary
for wide-scale commercial implementation of carbon capture and
sequestration?
Answer. CO2 Capture.--I would like to point out that DOE
has been conducting a relatively extensive R&D program related to
CO2 capture and sequestration for combustion-based power
systems (e.g., pulverized coal-fired plants that exhaust combustion
flue gas at atmospheric pressure) and gasification-based energy
conversion systems (e.g., Integrated Gasification Combined Cycle power
plants that operate at high pressure). Fortunately for the CBTL
technology, which is gasification-based, CO2 capture is
significantly more cost-effective than for combustion-based capture
systems, even with existing state-of-the-art physical absorption
technology. This is primarily due to high pressure operation with high-
purity oxygen, as well as the capability to increase the CO2
concentration of the synthesis gas to about 40%. Advanced membranes and
other novel separation methods are being developed to minimize the cost
and efficiency losses for both hydrogen and CO2 separation.
These technologies are appropriate for both IGCC and CBTL applications.
The key is to move these capture technologies to the pilot-scale as
soon as possible at existing U.S. IGCC plants, Dakota Gasification
Plant, or pilot gasification facilities like DOE's Wilsonville Power
Systems Development Facility (PSDF).
CO2 Transport and Injection.--Since industry already has
a great deal of experience with long-distance CO2 pipelines
and CO2 injection components, no R&D is required. For
example, Denver City, Texas, is the world's largest CO2 hub,
distributing gas from the 502 mile-long Cortez Pipeline (running from
Colorado to Texas), having a capacity of 1 to 4 billion cubic feet per
day. A cadre of delivery lines carries the gas from Denver City to the
40+ oil fields presently under CO2 flood in Texas' Permian
Basin. The Dakota Gasification Company, located in Beulah, North
Dakota, produces more than 54 billion standard cubic feet of natural
gas annually from lignite coal gasification that exceeds 6 million tons
each year; they capture CO2 from the syngas and send it
through a 205 mile pipeline to EnCana's Weyburn oil field in Canada.
CO2 Sequestration.--Sequestration of CO2 in
geologic formations cannot achieve a significant role in reducing GHG
emissions unless it is fully acceptable to the various stakeholders,
regulators, and above all the general public. For geologic
sequestration to be a viable technology to mitigate climate change, the
risks associated with this activity must be extensively evaluated in
R&D efforts, including ecological, environmental, operational, health
and safety, and economic risks. The major risks associated with the
operation of an underground CO2 storage project are largely
related to leakage from the storage structure and the transport system.
While CO2 is not classified as a toxic material, by
displacing oxygen in high enough concentrations it can cause
asphyxiation and rapid death. Furthermore, in addition to being a
potential health hazard, any leakage of CO2 back into the
atmosphere completely negates the effort expended in sequestering the
CO2. Two types of CO2 releases are possible, slow
leakage through slightly permeable cap rock, and catastrophic releases
due to rupture of a pipeline, failure of a field well, or opening of a
fault. There is also the potential for sequestered CO2 to
leak into non-saline aquifers, which could cause problems with potable
uses of this water. As discussed previously, years of operation with
natural gas pipelines (and CO2 pipelines for enhanced oil
recovery [EOR]) should provide the experience needed for the safe
design and operation of CO2 pipelines. However, there is
always the chance that seismic or building activity could lead to
pipeline rupture. A risk analysis conducted for the Weyburn EOR project
indicated that the most probable path for transmission of
CO2 from one stratum to another or to the biosphere is along
a well bore. Therefore, wells must be carefully drilled and monitored.
If CO2 sequestration is practiced in depleted oil and gas
fields, then the presence of abandoned wells could cause problems.
These wells will need to be effectively plugged and monitored.
Potential health risks from slow leakage are considerably greater if
H2S, SOX or NOX are sequestered along
with CO2. R&D needs to fully investigate and identify those
aspects of geologic sequestration that present probable risks (which
are different for each type of formation), appropriate actions can be
taken prior to the commencement of injection activities to obviate
occurrence of problems.
I strongly recommend the use of Probabilistic Risk Assessment (PRA)
as the preferred methodology for overall evaluation the complex, long
timeframe, process-driven geological storage of CO2. It
takes hundreds of parameters to describe the reservoir, the surrounding
geosphere, the CO2, water and other physical properties and
the injection wells. These parameters and processes interact to make up
a complex series of possible outcomes and impacts. PRA can
statistically quantify the uncertainty associated with the parameters,
describing the processes in deterministic model(s) and can integrate
all possible outcomes (all combinations of parameter perturbations),
including interactions. PRA can be used to focus government/private
resources on the most important parameters and processes and can
effectively guide both the science and regulation. It provides a
statistically rigorous method of ranking geological and anthropogenic
parameters and processes within a systems-oriented CO2
storage model. The PRA methodology can also be used to address health
and safety concerns, and economic performance factors.
I commend DOE's efforts to form a nationwide network of regional
partnerships to help determine the best approaches for capturing and
permanently storing CO2. Seven government/industry Regional
Carbon Sequestration Partnerships are currently determining the most
suitable technologies, regulations, and infrastructure needs for carbon
capture, storage, and sequestration in different areas of the country.
Based on the outcomes of these partnerships, I strongly recommend that
the government rapidly conceive and take appropriate steps to conduct
multiple large-scale demonstrations of geologic sequestration at
various sites across the United States. All steps necessary must be
taken to guarantee adequate monitoring, mitigation, and verification
(MM&V) aimed at providing an accurate accounting of stored
CO2 and a high level of confidence that the CO2
will remain sequestered permanently. Appropriate representation from
watchdog environmental groups need to be included in the oversight of
these projects to assure objectivity and to gain widespread public
acceptance.
Question 15. Does the use of a FT coal-derived diesel product have
an improved footprint for nitrous oxide, particulate matter, sulfur
dioxide, volatile organic compounds, and mercury over traditional
sources of diesel? Please quantify the per gallon differences for
criteria pollutant emissions that would result from consumption of a FT
coal-derived diesel product versus traditional, petroleum-derived,
diesel fuel.
Answer. Please see my answer to Question 9.
Question 16. China is aggressively pursuing development of a CTL
industry. If the U.S. does not, is it possible that we will be
importing CTL fuels from China in the future?
What implications does this have for U.S. national security?
Answer. I am of the strong opinion that our own actions relative to
CTL and CBTL deployment are what count most with regard to our energy
security and national security. Secondarily, and accounting for
comparable environmental considerations, we should strongly encourage
and work with the Chinese to help them develop their own indigenous
fuel resources. This will relieve pressure on petroleum consumption
around the world and be highly positive for consumers in all countries,
while reducing purchases of crude oil from areas of the world that do
pose real energy and security threats to the U.S. Considering China's
significant growth and voracious appetite for fuels, it seems highly
unlikely that they will be selling their domestically-produced fuel
products, except perhaps to much closer neighboring countries. If our
country takes appropriate and timely steps to utilize our own natural
resources wisely, then we can become more secure and confident about a
promising future with adequate energy supply. Let's not leave it to the
next generation to satisfy these critical responsibilities.