[House Hearing, 110 Congress]
[From the U.S. Government Publishing Office]
SPINNING STRAW INTO BLACK GOLD: ENHANCED OIL RECOVERY USING CARBON
SUBCOMMITTEE ON ENERGY AND
COMMITTEE ON NATURAL RESOURCES
U.S. HOUSE OF REPRESENTATIVES
ONE HUNDRED TENTH CONGRESS
Thursday, June 12, 2008
Serial No. 110-75
Printed for the use of the Committee on Natural Resources
Available via the World Wide Web: http://www.gpoaccess.gov/congress/
Committee address: http://resourcescommittee.house.gov
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COMMITTEE ON NATURAL RESOURCES
NICK J. RAHALL, II, West Virginia, Chairman
DON YOUNG, Alaska, Ranking Republican Member
Dale E. Kildee, Michigan Jim Saxton, New Jersey
Eni F.H. Faleomavaega, American Elton Gallegly, California
Samoa John J. Duncan, Jr., Tennessee
Neil Abercrombie, Hawaii Wayne T. Gilchrest, Maryland
Solomon P. Ortiz, Texas Chris Cannon, Utah
Frank Pallone, Jr., New Jersey Thomas G. Tancredo, Colorado
Donna M. Christensen, Virgin Jeff Flake, Arizona
Islands Stevan Pearce, New Mexico
Grace F. Napolitano, California Henry E. Brown, Jr., South
Rush D. Holt, New Jersey Carolina
Raul M. Grijalva, Arizona Luis G. Fortuno, Puerto Rico
Madeleine Z. Bordallo, Guam Cathy McMorris Rodgers, Washington
Jim Costa, California Louie Gohmert, Texas
Dan Boren, Oklahoma Tom Cole, Oklahoma
John P. Sarbanes, Maryland Rob Bishop, Utah
George Miller, California Bill Shuster, Pennsylvania
Edward J. Markey, Massachusetts Bill Sali, Idaho
Peter A. DeFazio, Oregon Doug Lamborn, Colorado
Maurice D. Hinchey, New York Mary Fallin, Oklahoma
Patrick J. Kennedy, Rhode Island Adrian Smith, Nebraska
Ron Kind, Wisconsin Robert J. Wittman, Virginia
Lois Capps, California Steve Scalise, Louisiana
Jay Inslee, Washington
Mark Udall, Colorado
Joe Baca, California
Hilda L. Solis, California
Stephanie Herseth Sandlin, South
Heath Shuler, North Carolina
James H. Zoia, Chief of Staff
Rick Healy, Chief Counsel
Christopher N. Fluhr, Republican Staff Director
Lisa Pittman, Republican Chief Counsel
SUBCOMMITTEE ON ENERGY AND MINERAL RESOURCES
JIM COSTA, California, Chairman
STEVAN PEARCE, New Mexico, Ranking Republican Member
Eni F.H. Faleomavaega, American Louie Gohmert, Texas
Samoa Bill Shuster, Pennsylvania
Solomon P. Ortiz, Texas Bill Sali, Idaho
Rush D. Holt, New Jersey Adrian Smith, Nebraska
Dan Boren, Oklahoma Steve Scalise, Louisiana
Maurice D. Hinchey, New York Don Young, Alaska, ex officio
Patrick J. Kennedy, Rhode Island
Hilda L. Solis, California
Nick J. Rahall II, West Virginia,
Hearing held on Thursday, June 12, 2008.......................... 1
Statement of Members:
Costa, Hon. Jim, a Representative in Congress from the State
of California.............................................. 1
Prepared statement of.................................... 3
Pearce, Hon. Stevan, a Representative in Congress from the
State of New Mexico........................................ 4
Prepared statement of.................................... 6
Statement of Witnesses:
Demchuk, Mark, Team Lead Weyburn, EnCana Corporation,
Calgary, Alberta, Canada................................... 51
Prepared statement of.................................... 53
Response to questions submitted for the record........... 58
Duncan, Dr. Ian, Associate Director, Earth and Environmental
Systems, Bureau of Economic Geology, University of Texas at
Prepared statement of.................................... 49
Evans, Ronald T., Senior Vice President of Reservoir
Engineering, Denbury Resources, Incorporated............... 25
Prepared statement of.................................... 27
Response to questions submitted for the record........... 32
Klara, Scott M., National Energy Technology Laboratory, U.S.
Department of Energy....................................... 13
Prepared statement of.................................... 14
Response to questions submitted for the record........... 18
Kunkel, Dr. Gregory P., Vice President, Environmental
Affairs, Tenaska, Inc...................................... 40
Prepared statement of.................................... 42
Response to questions submitted for the record........... 47
Roby, William, Vice President, Worldwide Engineering and
Technical Services, Occidental Oil and Gas Corporation..... 34
Prepared statement of.................................... 36
Response to questions submitted for the record........... 39
Spisak, Timothy, Division Chief, Fluid Minerals, Bureau of
Land Management, U.S. Department of the Interior........... 8
Prepared statement of.................................... 9
Additional materials supplied:
Peridas, George, Ph.D., Science Fellow, Climate Center,
Natural Resources Defense Council, Statement submitted for
the record................................................. 69
OVERSIGHT HEARING ON SPINNING STRAW INTO BLACK GOLD: ENHANCED OIL
RECOVERY USING CARBON DIOXIDE.
Thursday, June 12, 2008
U.S. House of Representatives
Subcommittee on Energy and Mineral Resources
Committee on Natural Resources
The Subcommittee met, pursuant to call, at 10:08 a.m. in
Room 1334, Longworth House Office Building, Hon. Jim Costa
[Chairman of the Subcommittee] presiding.
Present: Representatives Costa, Pearce, Holt, Sali, Smith,
STATEMENT OF THE HONORABLE JIM COSTA, A REPRESENTATIVE IN
CONGRESS FROM THE STATE OF CALIFORNIA
Mr. Costa. The oversight hearing of the Subcommittee on
Energy and Mineral Resources will come to order. The
Subcommittee is meeting today to hear testimony on enhanced oil
recovery using carbon capture and sequestration. There has been
a lot of discussion about this over the last several years, and
there is proposed legislation that deals with the issue.
It is appropriate and fitting, therefore, that the
Subcommittee take an opportunity to have the various witnesses
give us their take on the potential as it relates to a host of
options in terms of the management toolbox for carbon
sequestration for oil and gas recovery, as to the potential as
it relates to carbon capture and sequestration.
I have to do a few preliminaries before I and the Ranking
Member get into our opening statements. They are the following.
Under Rule 4(g), the Chairman and the Ranking Minority
Member may make opening statements, which I guess we will do.
If any Members have any other statements, we are interested in
them, and they will be included in the record under unanimous
Additionally, under Committee Rule 4(h), additional
material for the record should be submitted by Members or the
witnesses within 10 days after the hearing. We ask you to
really comply with that, and to help our staff, both the
Majority and Minority staff.
We would appreciate witnesses' cooperation in any written
submission of questions to the witnesses, either in the first
or second panel, if in fact questions are submitted by Members,
that you respond in a timely fashion in writing within the 10
Now, having settled all that, let me begin in terms of an
opening statement for all of you here who are present.
We are meeting today obviously to look at what are the
current state-of-the-art practices, and what is the potential
as it relates to enhanced oil recovery using carbon dioxide.
This is one of those energy issues where I think there is
agreement on both sides of the aisle, that there are not only
current activities taking place, but activities that can be
Not only can this technology help increase our domestic
production of oil, but in fact it is already doing an
impressive job in many fields throughout the country. And at
the same time, the carbon dioxide that otherwise would go out
into the atmosphere is being placed where it doesn't have an
impact on our air quality.
In my own district, there is a focal point for enhanced oil
recovery that really has been taking place for decades. First,
for those of you who are not aware of the district that I
represent, it goes from Fresno in the north all the way down to
Bakersfield in the south. And some of the earliest oil fields
in California were developed in the Kern County region.
Since 1961, we have begun a significant effort in taking
some of the older fields that were first developed at the turn
of the 20th century, some 50, 60 years prior, and in the early
sixties we began looking at innovative ways that we could
enhance the recovery, and therefore the production, of those
It first began with steam injection, taking the steam and
impacting the viscosity of the thicker crude that was contained
in the strata, and using the steam to loosen up that very heavy
crude, and getting, in a more cost-effective fashion, the
ability to recover that oil. As a result of that effort, that
steam recovery, now for over four decades, we have had over
270,000 barrels of oil per day come through many of the older
fields in California because of enhanced recovery.
But projects like steam obviously don't use carbon dioxide.
And we see an opportunity here to use a new technology that has
taken place in a number of areas.
In the last two years there are over 21 new carbon dioxide
EOR projects in the United States. I think that is good news
for all sorts of reasons. Twenty-one new carbon dioxide EOR
projects in the United States.
All told, carbon dioxide EOR produces today in the United
States 250,000 barrels of oil each day, which equates to
roughly 5 percent of the U.S. oil production. And the potential
for additional application, I think, is even greater.
The Department of Energy has estimated that there are over
80 billion barrels of oil in the United States that is amenable
to carbon dioxide-enhanced oil recovery, using current
technology. Advances in EOR technology, that number could
double, it is believed by some to be as much as 160 billion
barrels of domestic oil production.
Many of these resources exist in fields that are already in
operation, where there is infrastructure, not only including
the wells, but including the pipelines and the roads. The
infrastructure that is necessary to make carbon dioxide
enhancement recovery work. These resources I think are
important to evaluate, and to assess in terms of how we can
expand that exploration.
While discussing the benefit to domestic energy supply, we
also need to be mindful of the benefit to the environment,
because I think it is equally as important. This great example
of taking something that is often thought of as a waste
product--i.e., carbon dioxide--and using it beneficially I
think bodes well for all of us. If we take carbon dioxide from
human activities and make sure that it stays underground, we
can get some benefits as it impacts the climate.
The International Energy Agency has said that carbon
capture and sequestration is critical to reducing carbon
dioxide. Enhanced oil recovery can help capture and sequester a
lot of carbon dioxide, up to 13 billion tons by some estimates.
Still, the National Petroleum Council has recently put it,
``Enhanced oil recovery using carbon dioxide has the potential
to play a key role in the early commercialization of carbon
capture and sequestration; and as such, will provide an
important technology bridge to the extensive application of
I agree with that sentiment, and I believe that the future
of carbon dioxide-enhanced oil recovery is a bright one, just
as back in the sixties the use of steam injection into some of
the older fields in Kern County allowed us to take that thick,
heavier crude and reduce its viscosity to a point where we
could enhance the recovery of those fields.
I look forward to the testimony from our witnesses. And I,
at this time, would like to yield to the gentleman from New
Mexico, the Ranking Member of the Subcommittee, Mr. Pearce.
[The prepared statement of Mr. Costa follows:]
Statement of The Honorable Jim Costa, Chairman,
Subcommittee on Energy and Mineral Resources
In these times of record oil and gas prices, there is near
unanimous bipartisan agreement that one of the goals we need to focus
on is providing timely relief for American consumers--consumers who are
spending higher and higher percentages of their incomes to fill their
gas tanks and cool their homes. However, each party has very different
ideas about the best ways to accomplish that goal.
I do not believe that either party has a monopoly on good sense
when it comes to this issue. Both have ideas that are valid, and that
need to be explored. As someone who feels that we need to come together
to find common solutions to our energy problems, it is particularly
encouraging to be able to find a subject that has so much appeal to
both sides of the aisle. Carbon dioxide enhanced oil recovery is a win-
win: it has energy supply benefits and it has environmental benefits.
Done right, it has the ability to significantly increase the amount of
oil we produce domestically, while also acting as a bridge to the
large-scale sequestration of carbon dioxide underground, which the
International Energy Association has said is essential for reigning in
future carbon dioxide emissions.
Enhanced oil recovery (EOR) has a long and lustrous history in my
part of California. The oldest operating enhanced oil recovery field in
the United States is in Kern County, and after four decades is still
injecting steam to produce over 33,000 barrels of oil per day.
Traditional oil production only recovers about one-third of the oil
originally in the ground, leaving a huge resource base that we would be
foolish to ignore. And since those first days in Kern County, steam and
carbon dioxide have helped to flush out billions of barrels of
additional oil from California to Texas, from the Rockies to the Gulf
While production from steam EOR has been declining in recent years,
carbon dioxide EOR has been growing, to the point where it now produces
nearly 250,000 barrels of oil per day, nearly 5% of total United States
oil production. And there is plenty left to go after, too. The
Department of Energy has estimated that with current technology, there
are over 80 billion barrels of oil in existing fields that could be
obtained with carbon dioxide enhanced oil recovery, and with
technological advances, that number could double.
Let me say that again: there are over 80 billion barrels of oil in
existing fields that could be obtained with carbon dioxide enhanced oil
recovery. That is 8 times the amount of oil estimated to be contained
in the Alaska National Wildlife Refuge.
But the problem for EOR, ironically, is a lack of carbon dioxide.
While there are billion of tons of CO2 coming out of our
power plants each year, we simply do not have the infrastructure in
place to capture and direct it to oil fields. Instead, we drill for
natural sources of carbon dioxide stored underground, or, to a lesser
extent, we capture the carbon dioxide coming off natural gas plants,
fertilizer plants, or other small industrial facilities, and then
transport it over 3,500 miles of pipeline to get it where it is needed.
This is, however, just a small fraction of what we would need to fully
unlock the potential of EOR.
There are other environmental benefits to carbon dioxide EOR
besides the reduced emissions to the atmosphere. By focusing on those
fields that have already been in production, we get to take advantage
of existing infrastructure, like wells, pipelines, and roads, as well
as ease the pressure to start drilling in new areas.
Enhanced oil recovery will not be the solution to our carbon
dioxide emission problem--estimates are that we could store roughly 13
billion tons of carbon dioxide through EOR, but that is not nearly
enough. Still, it provides a very strong incentive for power plants to
capture and sell their carbon dioxide, and for pipeline operators to
build the connections necessary to get the carbon dioxide from the
plant to the field. Our ability to reduce emissions in the future may
depend on us taking both of these steps, so to the extent that EOR can
help get us to do those faster, we are far better off.
As the National Petroleum Council's recent report titled ``Facing
the Hard Truths about Energy'', noted, ``enhanced oil recovery using
carbon dioxide has the potential to play a key role in the early
commercialization of CCS [carbon capture and sequestration] and, as
such, will provide an important technology bridge to more extensive
I wholeheartedly agree, and I look forward to the testimony from
STATEMENT OF THE HONORABLE STEVAN PEARCE, A REPRESENTATIVE IN
CONGRESS FROM THE STATE OF NEW MEXICO
Mr. Pearce. Thank you, Mr. Chairman. I appreciate your
holding this hearing today. We are meeting at a time when gas
prices are an unprecedented $4.05 a gallon. They are
significantly higher in places like California and the District
Every day Americans are paying a record portion of their
income in energy costs. But when you go to the poorest states,
like New Mexico--we are about 47th on the per capita income--we
pay a significantly greater percentage of our incomes for
gasoline, and so we are very acutely aware of the escalating
price of energy.
Today's hearing is going to focus on carbon sequestration
for enhanced oil recovery. It is going to give us the chance to
examine some of the important issues that face companies
producing oil, and some of America's oldest oilfields, at the
same time talking about the domestic challenges that we are
going to face in producing the fuel that moves America and
powers our economy. So we have kind of a two-pronged
Carbon capture and sequestration on a commercial scale is
still an unproven technology. The process of separating and
capturing carbon during the production of energy remains cost-
prohibitive under current law.
As we are going to hear today, implementation of the
capture program on a coal power plant may consume nearly 25
percent of the power generated by that plant. Those costs have
to be calculated. The initial investment on that particular
plant will increase the cost by nearly 50 percent during the
construction, from $2 billion to $3 billion. These costs for
energy production will be passed along to the consumers who
purchase electricity generated in these facilities.
Enhanced oil recovery is a technically challenged and
costly process. I suspect I am the only Member of Congress who
actually ran a business that was engaged in reclaiming old
oilfields. My wife and I ran a fishing and rental tool company.
We did repairs on these aging wells in Lee County, New Mexico,
across the border in Texas, and now then we are watching with
interest as CO2 is being used to extend the life of
those wells. But we are also very familiar with the
technological challenges that come with that.
The process is not suited for all oilfields. You cannot go
into just any oilfield and start injecting carbon dioxide. The
process simply has to have the right formation to work, and it
will not work across the spectrum of oilfields in America. It
is important to note that enhanced oil recovery is no
replacement for new oilfield development.
While the EOR can extend the life of a field by 10, 20, or
even 30 years, America's oil producers need access to new
developments and new reserves to ensure that America has the
resources to keep our economy moving forward. We have the
resources here in America, but many of them are locked up, like
the Outer Continental Shelf, ANWR, or simply banned from
development, like oil shale in Colorado and Utah.
This hearing will highlight that while EOR can help America
keep producing oil, it does produce, it does need new oil, and
it is not, the enhanced oil recovery is not a solution to our
There is concern that this hearing may be the start of a
process that would move legislation banning the mining of
CO2 from natural sources. That would be very
misguided. Since mined CO2 is never released into
the atmosphere, such a step would only increase costs for
companies engaged in the EOR, while having no impact on
reducing atmospheric CO2 concentrations.
I would hope that going forward, we can give the companies
engaged in the process the confidence that they are not going
to see their investments disrupted by misguided and misdirected
legislation. We have already seen that in close detail on the
conversion of corn to ethanol; we have seen the tremendous
pressure on our water resources, now greater acres than ever
are being plowed up in our rain forests. And finally, the
conversion of food to fuel is causing hunger throughout the
Finally, Mr. Chairman, while this hearing touches on the
issue of domestic energy, it is not about actually producing
new domestic energy. At a time when Americans are facing record
energy costs, this committee has the responsibility to take
steps to address how to increase domestic oil production and
I would ask you, Mr. Chairman, to hold a hearing next week,
where we are working together. We invite witnesses and talk
about the specific steps we could take to increase domestic
energy production, reduce our dependence on foreign oil, reduce
gasoline costs for our constituents, and more importantly, help
America get our economy moving forward.
I hope you will consider my request. And I yield back,
looking forward to the testimony that we hear from our
[The prepared statement of Mr. Pearce follows:]
Statement of The Honorable Steve Pearce, Ranking Member,
Subcommittee on Energy and Mineral Resources
Mr. Chairman, thank you for holding this hearing today. This
Committee is meeting at a time when Americans are facing record and
rising gasoline costs. Yesterday, the national average for gasoline
surpassed $4.05 a gallon, and is significantly higher in states like
California and here in the District of Columbia.
Everyday Americans are paying record portions of their income in
energy costs. This burden is carried by poor and working citizens, like
my constituents in New Mexico, at 47th in per capita income, who pay
America's highest percentage of their income for energy costs.
Today's hearing will focus on Carbon Sequestration for Enhanced Oil
This hearing will give us a chance to examine some of the important
issues face companies producing oil on some of America's oldest oil
fields. At the same time, talking about the domestic challenges they
face in producing the fuel that moves America and powers our economy.
Carbon capture and sequestration on the commercial scale remains an
unproven technology. The process of separating and capturing carbon
during the production of energy remains cost prohibitive under current
law. As we are going to hear today, implementation of a capture program
on a coal power plant may consume nearly 25 percent of the power
generated by that plant. The initial investment will increase the costs
nearly 50%, from $2 Billion to $3 Billion, for the construction of the
plant. These costs for energy production will be passed along to the
consumers who purchase electricity generated in these facilities.
ENHANCED OIL RECOVERY (EOR)
Enhanced oil recovery is a technically challenging and costly
process. I am probably one on the only Members of Congress who has
personal experience working in these older oil fields. My wife and I
operated a fishing business which worked to repair wells in older oil
fields, like those using to EOR. Near my home in Lea County, New
Mexico, and across the border in Texas, this process is being used to
extend the life of some of America's oldest oil fields.
However, this process is not suited to all of America's oil fields
and simply because the process works in Texas and New Mexico doesn't
mean that it will work in every oil field in America. It is important
to conduct EOR that you have the right underground formation.
It is also important to note that Enhanced Oil Recovery is no
replacement for new oil field development. While EOR can extend the
life of a field by 10, 20, maybe 30 years, America's oil producers need
access to new development and new reserves to ensure that America has
the resources to keep our economy moving forward.
We have the resources here in America but many of them are locked
up, like the OCS and ANWR or simply banned from development like the
oil shale of Colorado and Utah. This hearing will highlight that while
EOR can help America keep producing oil, it does need new oil, and is
not a solution to our energy crisis.
There is concern that this hearing may be the start of a process to
move legislation banning the mining of CO2 from natural
sources misguided. Since mined CO2 is never released into
the atmosphere such a step would only increase costs for companies
engaged in EOR while having no impact on reducing atmospheric
CO2 concentrations. I would hope that going forward we could
give the companies engaging in this process the confidence that they
are not going to see their investments disrupted by misguided and
misdirected legislation. We have seen this happen with the development
of Ethanol, where we believed that we could grow our way to energy
independence, instead we are facing water shortages, worldwide
deforestation and growing hunger from rising food costs.
Finally, Mr. Chairman while this hearing touches on the issue of
domestic energy; it is not about actually producing new sources
domestic energy. At a time when Americans are facing record energy
costs this committee has the responsibility to take steps to address
how to increase domestic oil production and reduce costs.
I would ask you Mr. Chairman to work with me to hold a fair hearing
next week where working together we invite witnesses and talk about the
specific steps we could take to increase domestic energy production,
reduce our dependence on foreign oil, reduce gasoline costs for our
constituents, and more importantly help America get our economy moving
Mr. Costa. Thank you very much, gentleman from New Mexico.
Always willing to consider any requests and good ideas. I do
believe, in fact, that there are multiple management tools in
our energy toolbox to deal with our issue. And certainly our
oil and gas production domestically, in terms of ensuring that
we are as effective as we possibly can, is one of the issues
that I support.
We have increased application for permits to drill by 361
percent, beginning at the end of the Clinton Administration and
throughout the Bush Administration. Today there are over 28,000
active application of permits to drill, and the energy
companies that have bid on those application of permits to
drill that have been approved through the Minerals Management
Service are active on over 18,000, which means that there are
over 10,000 that are currently not being utilized.
But I believe that we need to examine all efforts. I was in
the Gulf of Mexico several months ago, and there is tremendous
activity taking place out there, as we all know, and the recent
bids that have taken place. We have had record bids at that, on
when they become available, for those companies that are
participating in them. And that really reflects, I think, in
part the desire on energy companies in our country to maximize
our efforts for both onshore, as well as offshore,
opportunities for oil and gas.
And while I can tell you, because I know a little bit about
my schedule next week, that we can't do that next week, it is a
subject of something that I have been entertaining, because we
do have an energy crisis in this country. I agree with you on
that point. And it is not going to go away.
And nor do I believe that there are any silver bullets,
whether it is corn or anything of the list of menus that people
have that have good ideas, and they are good ideas. But there
is no one sole source of solutions. It is, in my view, a
combination of solutions that are involved, short-term and
long-term efforts. And if we are going to be successful, it is
going to have to be done in a bipartisan way, in my opinion.
So, to appropriately respond to your comments, and I hope I
did, I think it is important that we get into the meat of this
morning's hearing, which is part of this larger conversation.
Let me say for those of you, we have been told that the
schedule is as follows: that we are going to have votes around
11:00. And so my desire is to have our first panel testify;
have a round of questions to the first panel. I am not sure we
are going to be able to do this, but I would like to then get
to the second panel, and at least get the second panel to be
able to all make their opening statements before we have to go
and vote. I don't know how many votes we are going to have.
Four votes usually, for those of you who aren't familiar
with our drill across the street, usually involves about 40
minutes, or 30 to 40 minutes. So some time after 11:00 there
will be a 30- to 40-minute break when we are forced, not
forced, but when we are required to fulfill our other
obligations, which is to vote on behalf of our constituencies.
So with that understood, we will begin with our first
Mr. Timothy Spisak. Did I pronounce it right?
Mr. Spisak. Spisak, yes.
Mr. Costa. Spisak, is the Chief of Fluid Minerals Division
of the Bureau of Land Management. And Mr. Scott Klara is also
with us today, and we are looking forward to your testimony.
I think you understand the drill. You have those lights in
front of you. It is five-minute timing. The green light means
that you have four minutes, and then when the yellow light goes
on you are on your last minute. And we do try to stay within
the timeframe of the five minutes allowed for your oral
testimony. Obviously, if you have more lengthy testimony, that
is submitted for the record.
So let us begin, Mr. Spisak, with your testimony, please.
STATEMENT OF TIMOTHY SPISAK, CHIEF, FLUID MINERALS DIVISION,
BUREAU OF LAND MANAGEMENT
Mr. Spisak. Mr. Chairman, members of the Subcommittee,
thank you for the opportunity to be here today to discuss
enhanced oil recovery using carbon dioxide on public land.
As you mentioned, my name is Tim Spisak, Fluid Minerals
Division Chief for the Bureau of Land Management, and I oversee
the BLM's oil and gas program.
My testimony today will address ongoing enhanced oil
recovery efforts and future plans for large-scale carbon
sequestration projects on public lands. Enhanced oil recovery,
or EOR, is a process used to recover more oil than can be
obtained by natural pressure, through the injection of fuel or
gas, such as CO2, into an oil reservoir to force
more to the surface.
CO2 is a leasable commodity for which BLM
collects royalties, and can be a byproduct of oil and gas
production on public lands. The decision to undertake
CO2 EOR is largely that of industry, and is
generally guided by financial considerations which balance
infrastructure needs and the cost of CO2 against the
anticipated return to determine whether the investment is
Within the BLM's regulated authority to administer oil and
gas leases, EOR is generally approved as part of a secondary
unit agreement and sundry notices, in order to ensure that the
company is moving forward in accordance with regulation and
Geological storage of carbon dioxide involves injection of
CO2 into a subsurface rock unit, and displacement of
the fluid or formation water that occupied the pore space. This
principle operates in all types of potential geological storage
formations, such as oil and gas fields, coalbeds, and deep
saline water-bearing formations.
Most of the potential CO2 storage capacity in
the U.S. is in these deep saline formations. The BLM
anticipates taking a leading role, working with other agencies,
to evaluate and develop where appropriate long-term carbon
The BLM is currently working with partners on demonstration
projects, including a deep saline sequestration project in
Utah, and an enhanced coalbed methane project in Mexico.
The BLM existing administrative and regulatory structure
will help facilitate future carbon sequestration projects, and
potentially leasing. We expect these continuing efforts to lead
to a robust, coordinated regulatory framework.
The BLM's experience in administering a large-scale mineral
leasing program, issuing rights-of-way on public land, and
other programmatic and land-management expertise will
facilitate this effort. As called for by the Energy
Independence and Security Act, Section 714, the BLM is working
in coordination with USGS, DOE, EPA, and others, to complete a
report to Congress by December 2008, outlining a recommended
framework for geologic sequestration on public lands.
As long-term sequestration efforts advance, a number of
issues will need to be addressed. These issues include the
economics of geologic sequestration of man-made CO2,
the feasibility and logistics of long-term geologic containment
of CO2, the ownership of formation pore space on
split-estate lands, the liability and safety issues related to
potential release of CO2 stored underground, or
potential saltwater intrusion into freshwater aquifers, and the
degree of public acceptance of the construction and operation
of nearby CO2 sequestration facilities.
As the nation's largest Federal land manager, the BLM
recognizes its responsibilities to the country, and the
opportunity to play a key role in EOR and carbon capture and
sequestration. I look forward to providing you the results of
our efforts in December, and would be happy to answer any of
[The prepared statement of Mr. Spisak follows:]
Statement of Tim Spisak, Division Chief, Fluid Minerals,
Bureau of Land Management, U.S. Department of the Interior
Mr. Chairman and Members of the Subcommittee, thank you for the
opportunity to be here today to discuss enhanced oil recovery using
carbon dioxide on public lands. I am Tim Spisak, Division Chief for
Fluid Minerals for the Bureau of Land Management (BLM), and I oversee
the BLM's Oil and Gas program. My testimony today will address on-going
enhanced oil recovery efforts and progress to date and future plans for
large-scale carbon sequestration projects on public lands.
BLM-managed public lands and minerals continue to play an important
role in meeting the Nation's energy needs. Increases in energy prices
are affecting the Nation as a whole. The BLM is looking to continue to
facilitate the development of oil and gas resources on the public lands
in addition to providing for alternative and renewable forms of energy
in an environmentally-sound way.
As the Nation's largest land manager, the BLM is entrusted with the
multiple-use management of 258 million acres of land, and administers
700 million acres of sub-surface mineral estate of which the surface
owners are Federal agencies, states, or private entities. Of the 1.2
billion acres inventoried by the U.S. Geological Survey (USGS) in its
National Oil and Gas Assessment, 279 million acres are under Federal
management. The recently released Energy Policy and Conservation Act
(EPCA) Phase III Report found that these resources translate into 30.5
billion barrels of undeveloped oil and 5.3 billion barrels of proven
reserves. These areas currently under lease are the most likely for
enhanced oil recovery in the short term.
In 2007, nearly 3,500 new oil and gas leases were issued and
approximately 500 of the more than 5,340 wells spud on over 4.6 million
acres of leased Federal land were for oil production. We are diligent
in executing our responsibilities to make these resources available in
an environmentally-sound manner. Within the framework of a transparent
public process, we carefully consider any potential effects to habitat,
groundwater, air and other resources; mitigate impacts through best
management practices, stipulations and conditions of approval; and
balance development with other uses across the landscape. It is our
role, with the appropriate environmental protections in place, to
provide the tools needed to allow oil production from leased resources,
to facilitate the pioneering of new technology, and to ensure a fair
return to the American taxpayer from the development of resources from
Escalating oil prices affect not only interest in domestic
production, but also the viability of industry to pursue unconventional
and renewable fuels through advanced technologies and processes. New
technologies may allow industry to effectively recover resources that
were once determined to be too expensive to pursue. Continuing to
support and advance these efforts, in part, is essential to addressing
the energy issues we now face.
Enhanced Oil Recovery
Enhanced oil recovery (EOR) is a process used to recover more oil
than can be obtained by natural pressure, through the injection of
fluid or gas into an oil reservoir to force more oil to the surface.
Carbon dioxide injection is one type of EOR. This process is often
undertaken in the later stages of an oil and gas operation, but may be
done at an earlier stage. The decision to undertake enhanced oil
recovery is largely that of industry, and is generally guided by
financial considerations. Industry balances infrastructure and the cost
of carbon dioxide (or other medium) against the anticipated return to
determine whether the investment is justified. Within the BLM's
regulatory authority to administer oil and gas leases, EOR is generally
incorporated into a ``sundry notice'' in order to ensure that the
company is moving forward in accordance with the appropriate rules,
regulations, and policies. An example of currently operating carbon
dioxide EOR on Federal lands is the Salt Creek Field, a relatively
shallow field in Wyoming that was developed in the early 1900's. In
more recent times, it has become cost effective for industry to re-
develop this field using modern technology and extract resources left
behind after earlier efforts. Following substantial reconstruction of
existing infrastructure, carbon dioxide injection EOR has been
employed, effectively doubling production. In the process, 150 million
cubic feet of carbon dioxide is injected per day that would otherwise
have been vented to the atmosphere.
In addition to its use in enhancing oil recovery, carbon dioxide is
a leasable commodity under the Mineral Leasing Act of 1920. The BLM
currently collects revenues in the form of royalties derived from the
sale of carbon dioxide produced in connection with oil and gas
production on public lands. In 2007, the sale of carbon dioxide
generated over $23 million in royalty revenue in the states of
Colorado, New Mexico, and Wyoming.
EOR's use of carbon injection will continue to yield valuable data
and information that facilitates future efforts to effectively capture
and sequester carbon dioxide in geologic formations found on public
lands. A critical issue for evaluation of storage capacity is the
integrity and effectiveness of these formations for sealing carbon
dioxide underground, thereby preventing its release into the
atmosphere. Current EOR efforts will enhance our understanding of these
types of critical scientific and geologic issues. We expect that new
information on this technology and the issues it presents will continue
to be generated from activities on the public lands that we manage. As
such, we anticipate the need for BLM to play an important role in
collaborating with other Federal agencies, states, the private sector,
and the public as we move forward in addressing legal and policy issues
that arise during development.
Carbon Capture and Sequestration (CCS)
The current atmospheric carbon dioxide concentration is
approximately 380 parts per million volume and rising at a rate of
approximately 2 parts per million volume annually, according to the
most recent information from the Intergovernmental Panel on Climate
Change (IPCC). The 2005 IPCC Special Report on Carbon Dioxide Capture
and Storage concluded that in emissions reductions scenarios striving
to stabilize global atmospheric carbon dioxide concentrations at
targets ranging from 450 to 750 parts per million volume, the global
storage capacity of geologic formations may be able to accommodate most
of the captured carbon dioxide. However, it is not known how much of
this carbon dioxide storage capacity would be economically feasible
(assuming some price on carbon). Also, geologic storage capacity may
vary widely on a regional and National scale. A more refined
understanding of geologic storage capacity is needed to address these
The challenges of addressing carbon dioxide accumulation in the
atmosphere are significant. Fossil fuel usage, a major source of carbon
dioxide emissions to the atmosphere, will continue for the foreseeable
future in both industrialized and developing nations. Therefore, a
variety of strategies are being investigated to reduce emissions and
remove carbon dioxide from the atmosphere. Such strategies include the
facilitated sequestration of carbon for the capture and storage of
carbon dioxide through terrestrial sequestration using soils and trees,
or by injection into geologic formations.
Geological storage of carbon dioxide in porous and permeable rocks
involves injection of carbon dioxide into a subsurface rock unit and
displacement of the fluid or formation water that initially occupied
the pore space. This principle operates in all types of potential
geological storage formations such as oil and gas fields, deep saline
water-bearing formations, or coal beds. Most of the potential carbon
dioxide storage capacity in the U.S. is in deep saline formations.
The BLM anticipates taking a leadership role, in collaboration with
other agencies, in evaluating and developing, where appropriate, long-
term carbon sequestration efforts. The BLM's existing administrative
and regulatory framework will help facilitate future carbon
sequestration demonstration projects and potentially, leasing, and
ultimately inform a robust, coordinated regulatory regime. In addition
to experience in administering a large-scale mineral leasing program,
we have the realty expertise and an existing framework for issuing
rights-of-way on public land that could serve future needs for carbon
dioxide pipelines across public lands. Other programmatic and land
management expertise, such as the BLM's experience in evaluation of
potential environmental impacts of projects, will facilitate this
effort. Other agencies, such as USGS, DOE, and EPA will also play an
important role in recommending geologic criteria that could be
incorporated into a set of ``best practices'' for geologic site
selection. The BLM looks forward to working closely with the USGS, DOE,
EPA, the National laboratories, other Federal agencies, academia,
industry and the public to develop geologic and technical criteria that
could be used in future site selection.
At this early stage in the development of carbon dioxide storage
technologies, especially in the absence of large-scale demonstration
projects of more than 1 million tons of carbon dioxide per year, many
unknown factors may impact the development of best practices. We look
forward to working together to resolve outstanding legal and policy
questions as we continue to learn more about the technologies and
geologic information necessary in moving forward with a carbon
sequestration program. We understand that the Environmental Protection
Agency (EPA) plans to propose regulations for issuing Safe Drinking
Water Act permits for geologic sequestration of carbon dioxide. BLM
will provide input as appropriate in the rulemaking process.
Current CCS Demonstration Projects--The BLM is working with the
Department of Energy (DOE) on regional partnerships that promote CCS
demonstration projects. In promoting CCS efforts on public lands, the
BLM is currently active in two demonstration projects: a deep saline
sequestration project in Farnham Dome, Utah, and an enhanced coalbed
methane project in San Juan Basin, New Mexico.
The Farnham Dome project involves the reinjection and
storage over a four year period of carbon dioxide produced on state and
Federal lands with site monitoring for an additional 5 years. As a cost
incentive for the demonstration project, the BLM has agreed to defer
royalty payments on carbon dioxide produced from the Federal mineral
estate (90 percent of the project area) until after the demonstration
project when the carbon dioxide may be produced for commercial gain.
The San Juan Basin project will demonstrate the
feasibility of carbon dioxide coalbed sequestration while determining
the potential for enhanced recovery of coalbed methane by injecting
75,000 tons of carbon dioxide into the formation over a one-year
We look forward to evaluating the results of these projects and to
using these results to explore additional demonstration projects on
public lands. If appropriate, we will begin looking at the costs and
benefits of moving forward to develop a program for public lands. As
the largest Federal land manager, the BLM will continue to support
these demonstration projects, as well as other demonstration project
opportunities that may be identified involving resources managed by the
Energy Independence and Security Act
The BLM is currently implementing the carbon capture and storage
provisions of the Energy Independence and Security Act (EISA) [Public
Law 110-140]. Section 713 of EISA directs the BLM to maintain records
on, and an inventory of, the quantity of carbon dioxide stored within
Federal mineral leaseholds. The BLM is reviewing its current data
collection structures and methods, including commercially available
data, and will determine how this new data collection requirement can
be incorporated into existing systems. The BLM is coordinating with the
Minerals Management Service on changes that may be required to the Oil
and Gas Operations Report that is used to collect production and
injection data on Federal mineral estate.
Section 714 of the EISA directs the Secretary of the Interior to
submit a report to Congress by December 2008 containing a recommended
framework for geological sequestration on public lands. In coordination
with the Environmental Protection Agency, the Department of Energy,
USGS, and other appropriate agencies, the BLM is examining criteria for
identifying candidate geological sequestration sites in several
specific types of geological settings. Additionally, the BLM will
consider the EPA proposed regulations for carbon capture and
sequestration when available to ensure that all of the BLM's
recommendations are in compliance with the Safe Drinking Water Act and
regulations under that Act. The BLM will be considering a regulatory
framework for the leasing of public lands for the long-term geological
sequestration of carbon dioxide, while providing for public review and
protecting the quality of natural and cultural resources.
As the BLM advances long-term carbon sequestration efforts, several
issues need to be addressed. Federal leasehold or Federal mineral
estate liability issues related to the release of carbon dioxide stored
underground will need to be studied and evaluated. Relevant experiences
from enhanced oil recovery using carbon dioxide on public lands will
assist us in examining this issue. In addition to scientific and
geologic issues, legal and regulatory issues remain, specific to carbon
dioxide sequestration on land in cases in which title to mineral
resources is held by the United States, but title to the surface estate
In preparing our report to Congress under EISA, the BLM will
examine existing statutes, regulations, proposed regulations, and case
law, and recommend whether additional legislation may be necessary to
ensure that public land management and leasing laws are sufficient to
accommodate the long-term geological sequestration of carbon dioxide on
In the meantime, the BLM plans to participate and expand its
involvement in carbon dioxide research, development and demonstration
projects. We will also continue to permit enhanced oil recovery
operations on public land; analyze the data we are beginning to collect
under Section 713 of EISA; examine the adequacy of existing regulations
and proposed regulations; and move forward on other recommendations
that will be developed over the next six months.
Addressing the challenges of reducing atmospheric carbon dioxide
and understanding the effects of global climate change are complex
issues with many interrelated components. Geologic sequestration of
carbon dioxide is one of several mechanisms being investigated by the
scientific community. While promising, a number of unknowns remain.
Existing demonstration projects have studied injection of
carbon dioxide of geologic origin rather than atmospheric carbon
dioxide. The economics of capturing and sequestering carbon dioxide
from other sources are not well understood.
Significant technological, scientific, and logistical
challenges remain in geologic carbon sequestration, such as the ability
to evaluate formations for containment capabilities over long periods
of time, measured in hundreds or thousands of years. However, large
scale demonstration projects such as those described earlier in my
testimony will begin to address these challenges.
Complex questions on access, compensation, and ownership
of formation pore space on split-estate lands have not yet been
Abandoned wells in proximity to injection sites often are
not able to contain pressure increases associated with carbon dioxide
injection, and can require substantial re-engineering.
Liability and safety questions in the event of carbon
dioxide leakage or salt water intrusion into fresh water aquifers are
unresolved, although research jointly sponsored by EPA and DOE is
underway to assess these issues.
The degree of public acceptance of the construction and
operation of nearby carbon dioxide sequestration facilities is unknown.
The assessment activities required by the BLM in EISA should
ultimately increase the information base upon which decision makers
will rely as they deal with these issues. In addition to addressing the
challenges presented by carbon dioxide, this commodity presents certain
opportunities for future knowledge and use. The BLM stands ready to
assist Congress as it examines these challenges and opportunities.
The BLM will continue to support our Nation's energy needs and
facilitate the pioneering of new technology and processes. As the
Nation's largest Federal land manager, the BLM recognizes its
responsibilities to the country and the opportunity to play a key role
in enhanced oil recovery and carbon capture and sequestration. I look
forward to providing you with the results of our efforts this December.
I would be happy to answer your questions.
Mr. Costa. Thank you very much, Mr. Spisak. And you stayed
within the five minutes. We usually give gold stars for that.
Our next witness, and I misspoke earlier, is Mr. Scott
Klara with an L, not Kara, and I apologize for my misspeak,
Director of the Strategic Center for Coal with the National
Energy Technology Laboratory, which is a part of the Department
So Mr. Klara, please begin your testimony.
STATEMENT OF SCOTT KLARA, DIRECTOR, STRATEGIC CENTER FOR COAL,
NATIONAL ENERGY TECHNOLOGY LABORATORY
Mr. Klara. Thank you, Mr. Chairman and members of the
Subcommittee. It is a pleasure to be here.
I appreciate the opportunity to provide testimony on the
U.S. Department of Energy's research efforts in enhanced oil
recovery using carbon dioxide; and in particular, its relevance
to carbon sequestration.
Throughout my brief remarks, I will refer to carbon dioxide
as CO2, and enhanced oil recovery as EOR.
Mr. Costa. That works for us.
Mr. Klara. Although much of the nation's original onshore
oil resource reserves have been produced, the Nation is still
home to a large resource of oil. Large volumes of oil remain
stranded in the reservoir. In fact, as much as 70 percent of
the oil in the reservoir remains stranded due to technical and
economic hurdles associated with primary extraction methods.
Extraction of a significant fraction of the stranded oil is
possible through the advances of technology related to
Fossil fuel combustion and fossil fuel power plants in
particular are a major source of CO2 emissions of
potent greenhouse gas. In fact, fossil fuel power generation
accounts for more than one-third of the U.S. anthropogenic
greenhouse gas emissions, and CO2 in particular
accounts for 80 percent of all U.S. greenhouse gas emissions.
There is some good news. And that good news is that
technologies are under development that can potentially provide
significant reductions in CO2 emissions from fossil-
fueled power plants.
Now, what if we were to try to tie these two challenges
together: Increasing domestic oil recovery and reducing
CO2 emissions from fossil-fueled power plants? This
coupling becomes possible by the topic of this hearing, which
is linking the capture of carbon CO2 from sources
like power plants, and using this CO2 for EOR.
The Department has recognized the importance of
CO2 EOR for more than 40 years. Since the 1970s,
DOE-funded projects have been developing concepts to improve
the effectiveness and applicability of CO2 EOR.
Current EOR research has begun to focus now on the carbon
storage aspect of the process. In parallel with these
developments, the Department also conducts research on future
energy conversion technologies that will minimize
CO2 emissions by developing cost-effective
approaches for efficiently capturing CO2 from
fossil-fueled power plants, and safely and permanently storing
these in underground formations.
Several key areas that make up this research program are
sub-elements like gasification, advanced turbines, fuel cells,
carbon capture, and sequestration. My written testimony has
more detail about those program areas.
I would like to now briefly elaborate a bit more on one key
research program, the carbon sequestration program.
Carbon sequestration developments are addressing the key
challenges that confront the widescale deployment of capture-
and-storage technology through research on several areas: Cost-
effective capture technologies, monitoring, mitigation and
verification technologies to ensure permanent storage,
permitting issues, liability issues, public outreach, and
Relative to EOR, the program is focusing on technologies
for monitoring, mitigation, and verification that will validate
permanent CO2 storage and EOR applications, and
provide the necessary tools and best-practice protocols for
using EOR as a carbon storage option. The Department's
sequestration program was recently recognized by the EIA
greenhouse gas group as the world's most ambitious program
dedicated to the advancement of carbon-capture and storage
My written testimony provides many facts, data, and
references that highlight the potential of CO2 EOR
and its relationship to CO2 storage. CO2
EOR represents an early opportunity for helping to realize
carbon-capture and sequestration technologies. Developing the
technology base to support a widespread expansion of
CO2 EOR could substantially increase existing United
States oil reserves and oil production.
The Department's developmental efforts are providing the
elements necessary to help enable this expansion by advancing
carbon-capture and storage technologies to increase the supply
of carbon dioxide, and optimizing EOR technologies for carbon
This completes my statement, and I look forward to
additional discussion. Thank you.
[The prepared statement of Mr. Klara follows:]
Statement of Scott M. Klara, National Energy Technology Laboratory,
U.S. Department of Energy
Thank you, Mr. Chairman and members of the Subcommittee. I
appreciate this opportunity to provide testimony on the U.S. Department
of Energy's (DOE's) research efforts in enhanced oil recovery (EOR)
using carbon dioxide (CO2) and its relevance to carbon
The economic prosperity of the United States over the past century
has been built upon an abundance of fossil fuels in North America. The
United States' fossil fuel resources represent a tremendous national
asset. Making full use of this domestic asset in a responsible manner
enables the country to fulfill its energy requirements, minimize
detrimental environmental impacts, and positively contribute to
The Nation is home to a large resource of oil. Although much of the
Nation's original onshore petroleum reserves have been produced, large
volumes of crude oil remain stranded in place after current production
operations are completed because their extraction using current
technology is both technically difficult and uneconomic. As much as 70%
of the oil in a given reservoir remains stranded in place after current
production operations are completed due to technological and economic
hurdles. The total volume of this stranded oil 1 is
estimated by Advanced Resources International (ARI), of Washington, DC,
to exceed 390 billion barrels, though DOE and the U.S. Geological
Survey (USGS) have not yet validated the ARI estimates. Of this total,
ARI estimates that roughly 200 billion barrels are relatively
accessible at depths to 5,000 feet below the surface. Extraction can be
aided technically and made more economic through the use of
CO2 for EOR. To put these numbers in context, according to
the Energy Information Administration (EIA), we have produced about 195
billion barrels of our petroleum resources over the past 120 years and
currently have proven reserves 2 of roughly 21 billion
barrels. Proven reserves are those quantities of petroleum, which, by
analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be commercially recoverable, from a given date
forward, from known reservoirs and under defined economic conditions,
operating methods, and government regulations. If probabilistic methods
are used, there should be at least a 90% probability that the
quantities actually recovered will equal or exceed the estimate.
Stranded oil is not currently included in proven reserves. Stranded oil
is a resource that could add substantially to reserves when technology
becomes available and economic conditions allow. It is equal to the
total reserves in place, minus the proven reserves.
\1\ Assessing Technical and Economic Recovery of Oil Resources in
Residual Oil Zones, ARI, February 2006, www.adv-res.com/pdf/
\2\ U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves,
2006 Annual Report, DOE/EIA-0216(2007), November 2007, www.eia.doe.gov/
There is also scientific consensus that increased levels of
greenhouse gases in the atmosphere, primarily CO2, methane,
nitrous oxide, and chlorofluorocarbons, are linked to climate change.
Globally, about 75-80% of total greenhouse gas emissions are
CO2. In this connection, fossil fuel combustion, in general,
and fossil-fuel power plants, in particular, have been identified as a
major source of anthropogenic greenhouse gas emissions, particularly
CO2, into the atmosphere. Slowing the growth of
anthropogenic greenhouse gas emissions has become an important concern.
Both of these challenges--extending the supply of domestic fuels
(primarily oil) and reducing emissions of CO2 from fossil-
fueled power plants (primarily those fired with coal)--can be addressed
simultaneously through the use of captured CO2 for achieving
EOR. Currently, most EOR projects rely on the availability of cheap
sources of naturally occurring CO2. If research into
reducing the cost of CO2 capture from power plants proves
successful, anthropogenic sources of CO2 may become readily
available for EOR projects. The Intergovernmental Panel on Climate
Change has estimated a worldwide technical capacity for CO2
storage in EOR applications at 61 to 123 billion tonnes of
CO2. Estimates by ARI, which DOE has not yet fully
evaluated, have shown that the technical limit for CO2
storage associated with EOR is 20 billion tons. Of that quantity, ARI
estimates up to 12 billion tons could be economically stored, if EOR
technology continues to advance and the cost of carbon capture
technology is significantly reduced. If these potentials can begin to
be realized, incremental oil produced via EOR using CO2
flooding could help offset the costs of CO2 capture, and the
prospect of relatively low-cost supplies of captured CO2 in
widespread areas of the country could, in turn, provide the impetus for
a national re-evaluation of the EOR potential in many mature fields.
The proximity of sources of captured CO2 to oil reserves
amenable to EOR is an important consideration, because transportation
of CO2 over long distances is expensive and can affect the
economics of EOR. The use of EOR for carbon sequestration will also
involve permitting issues, liability issues, monitoring and
verification technologies to ensure permanent storage, and public
In summary, while conventional EOR is a commercial process,
CO2 capture from coal power systems is not yet commercial at
the large scale required for deployment in power plants. Continued
evolution of EOR and transformational advances in development and
deployment of CO2 capture from coal power could help realize
this synergy between the coal/power industry and the oil industry.
The Department has recognized the importance of CO2 EOR
for more than forty years. As early as the 1970s, DOE-funded projects
were assessing the fluid properties of CO2 to establish its
applicability in EOR. A special focus was given to developing
correlations that helped the oil industry utilize these properties to
improve EOR performance in commercial projects. Technological advances
included the use of horizontal wells for improved reservoir contact,
four-dimensional seismic to monitor the behavior of CO2
floods, automated field-monitoring systems for detecting problems, and
the injection of increasingly larger volumes of CO2 to
increase recovery rates. This DOE-funded research has helped to
significantly advance industrial EOR operations, most of which
currently use CO2 from natural reservoirs, but the research
focus is now on the carbon sequestration aspect of EOR, a developing
application, rather than the mature oil production side of EOR.
Coupled with these advances in CO2 EOR, the Office of
Fossil Energy's Clean Coal Research & Development (R&D) Program
provides for the development of new cost- and environmentally-effective
approaches to coal use. The major focus of the program is developing
future plant configurations that minimize CO2 emissions by
developing cost-effective approaches for efficiently capturing
CO2 from coal-fired plants, and safely and permanently
sequestering the captured CO2 in underground reservoirs. The
key technology areas that make up the Clean Coal R&D Program are
discussed in the following paragraphs.
Gasification is a pathway to convert coal or other carbon-
containing feedstocks into synthesis gas. This synthesis gas, in turn,
can be used as a fuel to generate electricity or steam, or as a basic
raw material to produce hydrogen, high-value chemicals, and liquid
transportation fuels. The Advanced Integrated Gasification Combined
Cycle Program is developing advanced gasification technologies to meet
the most stringent environmental regulations and facilitate the
efficient capture of CO2 for subsequent sequestration.
Gasification plants are very amenable to CO2 capture because
they can be designed to produce a high-pressure stream of
CO2 that is easier to capture, compared to conventional
power plant technologies. Advances in the current state-of-the-art, as
well as the development of novel approaches, could provide the
technical pathways enabling gasification to meet the demands of future
energy markets, while minimizing greenhouse gas emissions.
The Advanced Turbine Program consists of a portfolio of laboratory
and field R&D focused on performance-improvement technologies with
great potential for increasing efficiency and reducing emissions and
costs in coal-based applications. The Program focuses on the combustion
of pure hydrogen fuels in large-scale turbines greater than 100-
megawatt size range, and it has also worked on the development of less
costly approaches for compressing large volumes of CO2.
Since advanced turbines will be fuel-flexible, capable of operating on
hydrogen or syngas, they will make possible electric power generation
in gasification applications configured to capture CO2.
Fuel Cells hold great potential to provide substantial improvements
to the efficiency and emission reductions of future power plants. Fuel
cell emissions per unit of electric power produced are well below
current and proposed environmental limits for commercial power sources.
Their modular nature permits use in central or distributed generation
with equal ease. Rapid response to emergent energy needs is enhanced by
the modularity and fuel flexibility of fuel cells. The ultimate goal of
the program is the development of low-cost, megawatt-scale fuel cell
power systems that will produce affordable, efficient, and clean
electric power both as stand-alone sources, or when they are
incorporated into integrated coal gasification combined-cycle systems
equipped with CO2 capture and sequestration.
Carbon sequestration developments are addressing the key challenges
that confront the wide-scale deployment of capture and storage
technologies through research on cost-effective capture technologies;
monitoring, mitigation, and verification technologies to ensure
permanent storage; permitting issues; liability issues; public
outreach; and infrastructure needs. For example, relative to capture
costs, today's commercially available capture and storage technologies
will add around 80% to the cost of electricity for a new pulverized
coal plant, and around 35% to the cost of electricity for a new
advanced gasification-based plant. 3 The Carbon
Sequestration Program is aggressively pursuing developments to reduce
these costs to less than a 10% increase in the cost of electricity for
new gasification-based energy plants, and is developing a goal for
pulverized-coal energy plants. Relative to EOR, the program is focusing
on technologies for monitoring, mitigation, and verification that will
validate permanent CO2 storage in these applications, and
provide the necessary best practices protocols for using EOR as a
carbon storage option.
\3\ 3 Cost and Performance Baseline for Fossil Energy Plants,
Volume 1: Bituminous Coal and Natural Gas to Electricity, U.S.
Department of Energy/National Energy Technology Laboratory, DOE/NETL-
2007/1281, Final Report, May 2007.
EOR and Sequestration Potential
Many EOR processes incorporating thermal, chemical, microbial, and
a variety of miscible gas-injection methods have been employed in the
United States. Among these, CO2EOR is likely the most
promising technology. Because CO2 is miscible with crude oil
under certain conditions, it can be injected into previously drained
oil reservoirs and used to sweep a portion of the remaining oil from
the reservoir, thereby helping to overcome the physical forces that
trap the residual oil. While not all of the relatively easily
accessible stranded oil is susceptible for recovery by CO2-
EOR, a large proportion could be recovered if a source of low-cost
CO2 and advanced CO2-EOR technologies are
developed and deployed.
A series of CO2-EOR assessments conducted by ARI have
projected that, if current high oil prices are sustained over the long-
term, if low-cost captured CO2 from power plants is
available, and if there continue to be improvements in CO2-
EOR technology, 89 billion barrels of incremental oil--more than four
times the current U.S. proved reserves--may be economic to produce. It
was also noted in this study that widespread use of improved
CO2-EOR technologies and modified processes that emphasize
using increased volumes of CO2 in each reservoir could
result in three times as much CO2 being used, and five times
more oil being recovered. These changes could result in significant
recovery of this incremental oil. Since oil companies take many factors
and risks into consideration when determining which investments to
make, it is unlikely that all of the additional 89 billion barrels of
domestic oil would be produced, due to the complexities of corporate
investment decisions. DOE has not yet fully evaluated these projections
and their relevance to DOE activities.
ARI estimates that within just the large fields in North Dakota's
portion of the Williston Basin, as much as 390 million barrels of
incremental oil could have a cost of production less than the current
price of oil, though DOE and USGS have not yet verified these
estimates. In addition, the feasibility of converting the large
unconventional in-place resource within the Bakken Shale of North
Dakota into economic reserves has been examined by USGS. Their recent
study estimates that nearly 4 billion barrels of (undiscovered) oil are
technically recoverable from the Bakken Shale formation 4.
Additionally, a 2006 study by the North Dakota Geological Survey, which
DOE and USGS have not yet verified, suggested that by using next
generation CO2-EOR technology, as much as 400 billion
barrels, or more, of oil resource may be in-place 5. If
injection of CO2 into this fractured shale could mobilize
even a minor portion of this larger estimate, the Williston Basin's
contribution to the Nation's oil supply would be significantly
\4\ USGS, Assessment of Undiscovered Oil Resources in the Devonian-
Mississippian Bakken Formation, Williston Basin Province, Montana and
North Dakota, April 2008.
\5\ Bakken Formation Reserve Estimates, Julie LeFever and Lynn
Helms, North Dakota Geological Survey, 2006.
In addition, while the main focus of CO2-EOR is on
maximizing the amount of oil produced rather than the amount of
CO2 injected, its sequestration potential is still
significant, though much less than the sequestration potential of
saline formations in the United States. Estimates by ARI, which DOE is
evaluating, have shown that the technical limit for CO2
storage associated with EOR is 20 billion tonnes. Of that quantity, up
to 12 billion tonnes could be economically stored if EOR technology
continues to advance, and assuming that the cost of CO2 is
less than $30-$38/ton delivered, which would require significant
advances in carbon capture technology. To put this into context, total
anthropogenic emissions of CO2 in the United States is
around 6 billion tonnes per year, with around 2 billion tonnes per year
of this CO2 from coal-fired power plants.
CO2-EOR represents an early major opportunity for
helping to realize carbon capture and sequestration technologies. The
use of CO2-EOR projects could help power generation
companies to take advantage of the oil industry's expertise with
CO2 handling and injection, and help accelerate the
implementation of other underground CO2 sequestration
options in coalbeds, depleted oil/gas reservoirs, and deep saline
formations. Developing the technology base needed to support a
widespread expansion of CO2-EOR could substantially increase
existing United States' oil reserves and production. The Department's
development efforts are providing the elements needed to help enable
this expansion by advancing capture technologies to increase the supply
of CO2 and optimize EOR technologies for carbon
Mr. Chairman, and members of the Subcommittee, this completes my
statement. I would be happy to take any questions you may have.
Response to questions submitted for the record by Scott M. Klara,
National Energy Technology Laboratory, U.S. Department of Energy
1. Mr. Klara, last year the Department of Energy released a study on
America's Unconventional Fuels that recommended an aggressive
program for productively using industrial carbon dioxide
emissions for EOR. What would such a program entail, how does
it fit into the Department's existing carbon dioxide capture
program, and what would it cost?
Response 1. The Department of Energy's (DOE) program for geologic
storage of carbon dioxide focuses on saline formations because they
have by far the largest capacity for carbon storage of any type of
domestic geologic formation. While EOR represents a good low-hanging
fruit for carbon sequestration, only saline formations have capacity on
the scale that would be needed to sequester the carbon emissions from
domestic coal power generation. Base EOR technology--using carbon
dioxide to increase oil production--is commercially available and
widely deployed, and the industry has both the financial incentives and
resources to advance the technology on its own. The DOE program is
focusing on EOR sequestration technologies where the private sector
lacks incentive: monitoring, mitigation, and verification that will
validate permanent CO2 storage in these applications, and
best practices protocols for using EOR as a carbon storage option.
While EOR-related CO2 research is not a specific line item
within DOE's Sequestration Program, based on the 2009 President's
Budget Request it is estimated that approximately $7 to $9 million will
be provided for EOR-related activities within the Sequestration
Program, primarily through field testing activities. In addition, many
of the technologies DOE is developing for geologic carbon storage in
saline and other non-EOR formations are also applicable to EOR. The
2009 President's Budget Request provides $149 million for the
Sequestration Program of which approximately $134 million is for
geologic storage and $15 million is for capture R&D activities.
2. Mr. Klara, what has the Department's budget for Enhanced Oil
Recovery research been for each of the past 5 years?
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
.eps*Includes broad-based Reservoir Efficiency Processes laboratory
studies in addition to CO2-EOR field tests. In addition,
many of the technologies DOE is developing for geologic carbon storage
in saline and other non-EOR formations are also applicable to EOR.
3. Mr. Klara, what type of research is the Department into, Enhanced
Gas Recovery or Enhanced Coal Bed Methane recovery?
Response 3. DOE is currently pursuing unconventional gas technology
research and development (R&D) with mandatory funds provided by the
Energy Policy Act of 2005, Subtitle J, Section 999, which NETL manages
and implements. The 2009 Budget proposes to repeal the mandatory oil
and gas R&D program because the industry has the financial incentives
and resources to develop new ways to extract oil and gas from the
ground more cheaply and safely. Coalbed methane recovery is one small
aspect of that program; however, nearly all current work in Section 999
is related to technologies focused on enhancing recovery of natural gas
from fractured shales.
4. Mr. Klara, has the Department of Energy carried out the Enhanced
Oil Recovery demonstration program mandated by Section 354 of
the Energy Policy Act of 2005? Could you provide us with an
update on the progress of that program?
Response 4. The DOE carbon sequestration program's EOR activities
focus on EOR sequestration technologies where the private sector lacks
incentive: monitoring, mitigation, and verification that will validate
permanent CO2 storage in these applications, and best
practices protocols for using EOR as a carbon storage option.
Consistent with Section 354(c)(2)(B), the Department issued a
solicitation on February 1, 2006, for Enhanced Oil Recovery (EOR) field
tests. The solicitation closed on May 5, 2006. Project selection was
made on July 21, 2006, and a news release announcing the selection was
published on the National Energy Technology Laboratory's website on
September 6, 2006. One award was made to the University of Alabama.
Status of the project initiated under the program: Following the
completion of a detailed reservoir characterization effort, the
University of Alabama initiated studies to establish the feasibility of
using carbon dioxide (CO2) for EOR in the heterogeneous
Citronelle field in Alabama. That feasibility has been confirmed and
pilot flood design efforts are almost concluded. Concurrently with the
determination of feasibility, the University's industry partner,
Denbury Resources, initiated field work to refurbish wellbores and
facilities in preparation for a 5-spot pilot CO2 flood. The
pilot design is scheduled for completion in July 2008 and will be
submitted for NETL review prior to the initiation of field
CO2-EOR pilot operations. The pilot is anticipated to start
around November 2008. If the pilot is successful, Denbury Resources
plans to extend their existing CO2 flooding operations near
Jackson Dome, Mississippi, to the Citronelle Field.
5. Mr. Klara, your testimony mentions injecting carbon dioxide into
fractured shale formations in North Dakota--do we know whether
or not those formations can effectively store carbon dioxide
Response 5. The primary geologic storage options that are being
considered for carbon sequestration are saline formations, oil/gas
formations, and unmineable coal seams. Geologic storage capacity
estimates generally include only these options. As research continues
to unfold, several geologic storage options related to basalt
formations and shale formations may emerge as potential storage
candidates. These storage options are beginning to be investigated as
potential options for safely and permanently storing carbon dioxide,
and conclusive results verifying their effectiveness are still several
Mr. Costa. Thank you very much, Mr. Klara, for your
Let me begin the questioning. The Department of Energy
released a study, I guess, recently on America's unconventional
fuels that recommend investigation of assessment of potential
fiscal incentives to encourage the investment of CO2
for EOR projects.
Is the Department doing this since they released the
report? And are there any results that you can speak of?
Mr. Klara. Yes. The Department is still studying those
efforts, and studying those issues. And several reports have
been released, or are in preparation, relative to looking at
the potential for CO2 EOR throughout the United
States, and through numerous basins that are called geologic
basins. And I would be happy to give you a status on those
after the hearing.
Mr. Costa. All right. Several times in your testimony you
talked about various studies that were being done with Advanced
Resources International. When do you expect those evaluations
to be finished?
Mr. Klara. We have several of those that are already
developed and finished, and we would anticipate most of those
being done over the course of the next, say, nine months to a
Mr. Costa. And how about in the year of enhanced gas
recovery, or the enhanced coalbed for methane recovery? Is
there any research being done in those two areas?
Mr. Klara. Yes. The majority of that research right now is
being done in the carbon-capture and storage area, where we are
looking at the use of carbon dioxide in coalbeds, for example,
to enhance gas recovery of coalbed methane.
Mr. Costa. And where is the Department of Energy in
carrying out the enhanced oil recovery demonstration program
that was mandated in the previous legislation that was noted,
Section 354 Energy Policy Act of 2005?
Mr. Klara. I would have to get back to you on that, sir.
Mr. Costa. Please do.
Mr. Spisak, does the BLM see carbon-dioxide enhancement oil
recovery as a significant component of our future production
for Federal lands? And if so, what percentage, or how would you
describe its role in the future?
Mr. Spisak. I think there is significant potential there.
There are a number of depleted oilfields, or partially depleted
oilfields on Federal lands, that might be candidates for carbon
sequestration. But as was mentioned earlier, each case would
need to be evaluated separately. And I think we are ready to
assist in that.
As you are aware----
Mr. Costa. Has the Bureau of Land Management begun
undertaking that assessment?
Mr. Spisak. We primarily provide access to others to
develop, and that is our expertise, if you will. We have
regulations in place that we believe can deal with, dealing
with rights-of-way for CO2 pipelines, and the
planning side. But our regulations primarily allow us to
authorize CO2 injection for enhanced oil recovery
Mr. Costa. OK. But let me ask it to you in a different way,
I guess, and that will be a subject, I guess, of the next
panel. But has industry that has participated in these fields,
have they come to you folks indicating that there is a stronger
interest, given the current energy crisis that we are facing,
and the cost of fuel, to pursue these older fields?
Mr. Spisak. We are starting to see that, through our sundry
notices, where companies will ask that a well be shut in for
potential CO2 conversion at a later date.
Mr. Costa. One of the concerns that has been raised, even
though I believe this is kind of a win-win situation, that the
carbon sequestration, that possibly the carbon dioxide might
leak out of old well bores. Does the BLM, are they attempting
to get a handle on this, on location and status of abandoned
wells on public lands?
Mr. Spisak. Well, part of Section 349 of the Energy Policy
Act required us to inventory orphaned and idled wells, and
prioritize those lists. And we have actually started that
process. And so we have a better idea of the numbers of those
types of wells that we have in our inventory.
Mr. Costa. My final question to you, Mr. Spisak. In 2006
the Department of Interior concluded that the royalty relief
for oil produced from industrial carbon dioxide was not
warranted. Why was that?
Mr. Spisak. Well, we have existing regulations that allow
us, on a case-by-case basis, to allow royalty reductions to
help promote that type of activity. And we felt like we could
always open up that issue in the future, if necessary.
Mr. Costa. Are companies telling you that there are any
complications under the existing mineral leasing laws and
regulations that would create more difficulty if they convert
to a current EOR project on Federal lands?
Mr. Spisak. We haven't been hearing anything along those
lines at this point.
Mr. Costa. My time has expired, so I will now defer to the
gentleman from New Mexico, Mr. Pearce.
Mr. Pearce. Thank you, Mr. Chairman.
Mr. Spisak, you heard the Chairman say that there are
10,000 APDs that are not being utilized. I am looking at a
chart that shows in 2001, we had protests filed on 17 percent
of the parcels which are offered for development. That number
has increased to 58 percent today, 81 percent in the Rocky
Do you find that, do you see that in real life, that we are
actually finding protests, maybe three to four times higher?
And would that be a reason that we are not producing in some
Mr. Spisak. Well, protests are typically at the lease-
issuance or offering stage. The number of APDs and the number
that are actually acted upon need to take into consideration
that APDs now, with the updated onshore order, there is two
years' period of time for the companies to be able to use them,
which could be extended to another two years. And a lot of it
depends on various timing restrictions that are in place. And
so that the companies have to work that into account, as well
as rig availability, which is, with the big run-up, companies
are scrambling to get rigs either built and crews to be able to
utilize the APDs that are in the pipeline.
Mr. Pearce. OK. You have a lot of----
Mr. Costa. If the gentleman would yield, and I won't count
it against you. But on the number I used, and I will be happy
to double-check it, but those 28,000 application of permits to
drill have been approved, so they are not under protest.
Mr. Pearce. Thanks. Now, we were talking about the carbon
sequestration and the use in the EOR, like the infrastructure
already exists, Mr. Spisak. Is that accurate, that we would use
the same infrastructure to move carbon dioxide?
Let me hold up a map. I am visualizing the problem almost
the same as our natural gas movements. In other words, we have
to move carbon dioxide from where it was produced, somewhere.
And so I am wondering that front chart there--yes, this
chart here--I am wondering if we are going to see a system of
pipelines like that to carry carbon dioxide to the fields, and
then carry the enhanced oil back out.
Mr. Spisak. As mentioned in my testimony, the issue of
infrastructures such as pipelines, right now the pipeline
network is to deliver natural gas away. And those aren't
necessarily going to be the pipelines that could deliver
Mr. Pearce. Right. So what kind of a permitting process are
we talking about? If, I mean, we have to take carbon from
everywhere in the country, take it in, gather it up, and then
send it to some processing plant, and then back out to the
oilfields? What sort of permitting problems do we face, just
getting those pipelines to convey the CO2?
Mr. Spisak. Well, as is anything when the level of activity
is, as it increases, we have a certain workload, workforce that
is able to process----
Mr. Pearce. To get this done in the next 10 years. Could
you get the permitting done with the current workload?
Mr. Spisak. We are pretty full up as it stands now.
Mr. Pearce. OK. So what I am saying is that it is not like
they are available.
Mr. Spisak. Correct.
Mr. Pearce. Mr. Klara, I noted in page 4 of your testimony
you talk about DOE as significantly advanced, enhanced oil
recovery. Can you tell me the contributions that DOE has made
Mr. Klara. Yes. A few examples----
Mr. Pearce. Just very brief, because we need to move on to
Mr. Klara. Yes. A few examples. For example, CO2
bypasses a key issue that limits the effectiveness of
CO2. And there has been a lot of research done, and
additives to carbon dioxide.
Mr. Pearce. Can you move the mic a little bit closer?
Mr. Klara. There has been a lot of research done with
additives to carbon dioxide and other additives in the
reservoir to get a more effective flood-front of carbon
In addition, there has been a lot of work on things like
reservoir management strategies and using new well techniques,
like horizontal wells.
Mr. Pearce. These are DOE-sponsored events, not companies
that are using their own resources. These are DOE advancements?
Mr. Klara. DOE certainly has been a part of many of those
Mr. Pearce. That wasn't quite my question, but I will move
You mention on page 2 that the global warming is
significantly linked to carbons, CO2, methane,
nitrous oxide, everything else in the environment. What is your
professional opinion on why the polar icecap tripled in size
this last winter? Why did we have the coldest winter on record
in most of the northern hemisphere? Why did we have ice in
Vietnam when I was there? In 1971, 1972, and 1973 I didn't find
ice anywhere; and yet we had ice for almost 30 days in Vietnam.
The carbon has decreased in our atmosphere. Exactly what is
your professional opinion on this sudden reversal in our
Mr. Klara. Well, sir, I am not a climate-change expert, so
I am going to----
Mr. Pearce. OK. You put it in your testimony. So when you
start using words that you can't--I mean, there are questions
that are raised significant on this very point. So when you use
statements like that in your testimony, it gives the appearance
that you are experienced, and you can give data about that. And
I think it is a very significant question. If you would get
somebody in your agency to answer that question, I would
Mr. Klara. OK, we will do that.
Mr. Pearce. OK, thanks. I see my time has gone, Mr.
Chairman. If we do two rounds, I have another series.
Mr. Costa. All right. The gentleman from New Jersey is
next, Mr. Holt.
Mr. Holt. Thank you, Mr. Chairman. And thank you for
setting up this hearing.
Let me ask, what are the major areas of research? I am
trying to get a sense of the scale of the investment that is
necessary for research into all aspects of using public lands
for sequestration of the carbon. You have to look at the
leakage, how extensive is it to study that; you have to look at
the feasibility of transportation of the carbon dioxide, and so
Has someone mapped out a long-term research, or short-term
even, research plan? I suppose Mr. Klara would be the best
person to start with, but I welcome comments from Mr. Spisak,
Mr. Klara. We have a program within the Department of
Energy, our Fossil Fuel Research Program, that is dedicated to
developing the technologies to try to make that happen. And we
have numerous goals and issues throughout our program over the
course of up through 2020 and 2025, for example, that will
hopefully set the stage for commercial availability of emerging
Relative to enhanced oil recovery and using CO2,
I think there are several key issues. First, you need mature
fields, and the United States happens to have that happening
automatically. Second, you need cheap sources of carbon
dioxide. And relative to human activities and anthropogenic
CO2, you need cheap sources of anthropogenic
CO2. So a significant portion of the research
program is looking at reducing the cost of CO2
capture from energy facilities like power plants, looking at
developing best practices and protocols for carbon storage and
underground formations, to ensure it is permanent and safe. And
those are some of the key aspects of the research program.
Mr. Holt. And as this is mapped out, I mean, would it all
be done by the Energy Technology Laboratory? Or is this, I am
trying to get a sense of the scale of the investment that is
necessary, public and private, to determine whether this is
going to be a reality.
Mr. Klara. In Fiscal Year 2008, the research budget for the
coal program, for example, is in the neighborhood of $500
million. And most of what we do in the coal program is
dedicated toward future energy power-plant configurations to
deal with the CO2 issue.
And we believe that, I believe that sustained investment is
required for us to----
Mr. Holt. You are saying most of the $500 million goes into
studying sequestration of the carbon?
Mr. Klara. No, no, no. Don't----
Mr. Holt. That is what I am asking about, for the
sequestration of the carbon.
Mr. Klara. Right. Our carbon sequestration program alone is
in the neighborhood of $120 million for Fiscal Year 2008. And
what I meant by the comment of linking it to the entire
research program was that whether you are looking at
gasification of fuel cells, advanced turbines, all of those
development efforts have in mind future plants that have to do
with the CO2 issue. So there is aspects within all
of those program elements that are concerned about future
configurations that deal with CO2 capture.
Mr. Holt. Does BLM have a research program?
Mr. Spisak. No, I wouldn't characterize what we do as
research. It is more land management access, working through
how they would implement such research on the ground.
Mr. Holt. OK. Mr. Spisak, if there were more extensive use
of carbon for enhanced oil recovery, what would be the
environmental effects that you have identified, other than
pipelines? To the extent that pipelines would have
Mr. Spisak. Injecting the fluid into the ground, like other
fluids, water is a fairly I would say routine matter when it
comes to enhanced oil recovery with CO2 injection.
CO2, when it does mix with water, can have some
corrosive aspects. But I wouldn't expect that those types of
environmental concerns are any more dangerous than the types of
things we deal with every day.
Mr. Holt. And quickly, Mr. Klara, if it can be answered
quickly, how does one study leakage of carbon dioxide from coal
seams or oil, depleted, or partially depleted oil areas? How do
you study that, actually?
Mr. Klara. The key there is to develop the suite of
monitoring technologies that will allow you to look at the
migration of carbon dioxide in the underground strata, at the
surface, as well as even aerially. So there are some aerial
technologies, plane flyover technologies, for example, that can
look for leakage.
So the key there is a whole portfolio of imaging
technologies that is applied to a carbon storage location that
will allow you to essentially look at nearly all of the carbon
dioxide, and know where it is at given period of time.
Mr. Costa. The gentleman's time has expired. Thank you.
The gentlemen from Louisiana, Mr. Scalise.
Mr. Scalise. Thank you, Mr. Chairman.
Mr. Spisak, how often do companies file an application for
a permit to drill, but never, in fact, develop that, or drill?
Mr. Spisak. I don't have a specific answer, but to say, but
we find that over a four- or five-year period, about 75 percent
of the APDs that are filed are eventually drilled. This is
based on a study of looking at APDs back in 2004/2005.
Mr. Scalise. Over a five-year period roughly, then.
Mr. Spisak. Right.
Mr. Scalise. What would be a reason that someone would file
the application, get the permit, but the not drill?
Mr. Spisak. One example might be they might drill a well;
they might find that the downhole was different than they were
expecting, and some of the other APDs in the pipeline that they
had approved may not be appropriate for that development.
It could be that there is time constraints on seasonal
restrictions for winter or deer cabin, or whatever it might be,
closes the window down that they are able to drill the wells
that they are needing, and so they have to push them off in
Another may be that they have a certain amount of rig
availability to deal with the APDs that they have, and they are
not able to get enough rigs or rig crews in there to drill the
APDs that they have.
Mr. Scalise. I don't have any more questions. That is all I
Mr. Costa. OK. All right. I am going to use the discretion
of the Chair at this time. We have had one round of questions,
and I will ask the Committee members to submit any written
questions, if you have any additional questions, and move on to
our second panel.
Thank you very much, gentlemen, for your testimony and your
prompt response on the answers. And as we are waiting for the
other witnesses to come forward for the second panel, we will
try to get through their testimony as best we can, hopefully
before the votes are called, at which point we will have to
recess and go to the Floor. And that will take about 40
minutes. That will be a break for all of you here in the
audience and all of you participating. And then we will come
back and resume the hearing where we left off.
So thank you, gentlemen. And I will take this time, as our
second panel is coming forward. The lady that is standing up is
Holly Wagenet. You can acknowledge, wave to everyone, Holly.
This is her last hearing as a part of the Committee. She has
applied to law school, and she is going to go there, and I
suspect she will do well, as she does in every other effort. We
want to thank you for all the nice work you have done on behalf
of the Subcommittee. And Holly Wagenet is being replaced by the
lady next to her, Marcie Cooperman. Raise your hand, Marcie. So
we want to make sure she is part of our able staff, to do a
good job. And we thank them for their hard work, and wish you
the very best, Holly. Yes.
Mr. Costa. She told me not to do that yesterday, so what
can I say?
Anyway, we have five witnesses here. And let us begin first
with Mr. Tracy Evans, in our second panel. He is the Senior
Vice President of the Reservoir Engineering with Denbury
Resources, Inc. Mr. Evans.
STATEMENT OF TRACY EVANS, SENIOR VICE PRESIDENT OF RESERVOIR
ENGINEERING, DENBURY RESOURCES, INC.
Mr. Evans. Thank you, Chairman Costa, Ranking Member
Pearce, and members of the Subcommittee for the opportunity to
share our views on enhanced oil recovery utilizing carbon
dioxide, or CO2 EOR.
Denbury's primary focus is enhance oil recovery utilizing
CO2, and we believe it can play an important role in
meeting America's future energy needs, and helping to reduce
As Denbury's Senior Vice President, I oversee all reservoir
engineering, land, property acquisitions, and purchases of
anthropogenic or manmade CO2 volumes.
We are currently the largest oil producer in the State of
Mississippi, and one of the largest injectors of CO2
in terms of volume in the United States. Since 1999, we have
produced over 20 million barrels of oil from CO2
flooding from 10 active EOR projects in Mississippi and
Currently we utilize 550 million cubic feet, approximately
32,000-plus tons, of new CO2 each day to produce
about 24,000 gross barrels of oil per day. All this
CO2 comes from a natural deposit that we currently
own. Although large, this supply is enough that it could supply
us with up to 800 million cubic feet of additional
CO2, and the discussions to acquire additional
volumes, as well.
It is important to note that we plan to purchase this
anthropogenic CO2. Thus, unlike the straw freely
provided by the king in the tale by the Brothers Grimm,
CO2 is not free; and in fact, its price typically
varies proportionately with the price of oil.
Also, unlike spinning straw into gold, CO2
generally must be transported significant distances from
natural or anthropogenic sources to oilfields, and injected to
produce incremental volumes over 20 to 30 years.
We currently operate three pipelines in operation,
distributing CO2 from our natural source at
Jacksonville, Mississippi, to our oilfields with a combined
length of around 350 miles. Our biggest single project during
2008 and 2009 will be the construction of a $750 million, 314-
mile, 24-inch pipeline to transport CO2 from
southern Louisiana to southeast Texas. The primary purpose of
this pipeline is to capture anthropogenic volumes of
The potential construction of gasification plants with the
numerous additions to deplete oilfields along this route make
this region attractive to additional CO2 EOR. Thus,
CO2 EOR is a long-term capital-intensive endeavor.
Nonetheless, we believe it has enormous potential in the near
term to help address the urgent, often conflicting goals of
increased energy security and lower greenhouse gas emissions.
At the present time, CO2 injections for the
purposes of CO2 EOR total approximately 2 billion
cubic feet per day; and generally in three regions of the
country: West Texas, Mississippi, and Wyoming. All other oil-
producing regions of the country could and would benefit from
CO2 EOR. Unfortunately, these areas do not have
sufficient CO2 supplies.
We estimate that if enough CO2 were available in
all producing regions of the country, we could inject upwards
of five to six times the current amount of CO2 being
injected. To put this in perspective, this additional
CO2 volume is equivalent to approximately 40 typical
gasification projects that would produce around 200 million
cubic feet per day per project. Thus, if such projects can get
off the ground, the potential for additional oil production
using CO2 EOR is significant.
I will now briefly address two obstacles to increasing EOR
production and carbon sequestration: The cost of capture and
transportation, and the lack of clear tax rules applicable to
pipelines carrying anthropogenic CO2.
Perhaps the single-largest obstacle developing carbon-
capture, transportation, and sequestration beyond the limited
number of projects currently in operation is the significant
costs involved. The cost of capture stems from the variations
in the quantity and the quality of CO2 produced by
hydrocarbon combustion or gasification, or other industrial
processes, as well as the cost of purchase and power of the
compressors necessary to pressure up the gas sufficiently to
enter a pipeline in order to get it to a sequestration site.
Transportation costs are also significant. Insulation costs
for CO2 pipelines have increased in recent years
from about $30,000 per inch-mile for Denbury's free-state
pipeline to an estimated $100,000 per inch-mile for the planned
green pipeline in southern Louisiana, primarily due to rising
steel prices, rising energy prices, and construction costs,
effectively doubling our CO2 transportation rate.
Without some means of reducing the cost of CCS infrastructure,
development will likely remain stagnant.
Certain committees and Members of Congress have already
taken steps to address cost issues, and to remove obstacles to
infrastructure development. For example, one year ago the
Senate Finance Committee approved a clarification of the tax
treatment of income from pipelines for transporting
A substantial portion of CO2, natural gas, or
products pipelines in the U.S. are owned and operated by
publicly traded partnerships, whose reduced costs of capital
lowers the costs of development and transportation of natural
resources. However, due to the current uncertainty of the Tax
Code, much of the existing CO2 pipeline capacity
cannot be used, and new capacity may not get built to transport
anthropogenic CO2 from emission sites.
The Senate Finance Committee approved language to remove
this uncertainty. This Congress ultimately failed to include it
on the Energy Independence and Security Act.
To conclude, the U.S. economy will continue to require
massive amounts of energy well into the future. CO2
can and should play an important role, helping to reduce
dependence on imports. We can increase substantial volumes of
domestic oil. And CO2 EOR is also the only currently
active on-the-ground of CO2 injection and
sequestration. And I look forward to answering any questions
you may have.
[The prepared statement of Mr. Evans follows:]
Statement of Ronald T. Evans, Denbury Resources, Inc.
Denbury Resources, Inc., (``Denbury'') appreciates this opportunity
to share with Members of the House Subcommittee on Energy and Mineral
Resources its experience with enhanced oil recovery using carbon
dioxide or ``CO2 EOR.'' CO2 EOR presents
significant opportunities to reduce the nation's dependence on foreign
energy sources while simultaneously helping to reduce industrial
emissions. With the right policies in place, many billions of barrels
of oil are accessible on the Gulf Coast and around the United States
and millions of tons of CO2 can be sequestered through
CO2 EOR. However, some impediments exists--primarily tax and
economic--to capturing and transporting CO2 on a broader
scale in order to inject it and produce these significant volumes of
As Senior Vice President, Reservoir Engineering, for Denbury, I
oversee all reservoir engineering, land functions and acquisition
activities; am responsible for securing and contracting sources of
anthropogenic CO2; and coordinate our government relations.
Denbury is currently the largest oil producer in the State of
Mississippi and one of the largest injectors of carbon dioxide in terms
of volume in the United States. Denbury's primary business focus is
enhanced oil recovery utilizing CO2. At the present time we
operate ten (10) active CO2 enhanced oil projects, nine in
the State of Mississippi and one in the State of Louisiana.
Denbury also owns the largest natural deposit of CO2
east of the Mississippi River, called Jackson Dome in central
Mississippi, which we extract and transport through approximately 350
miles of dedicated CO2 pipelines for use in EOR. Denbury is
currently in the process of designing or constructing an additional 375
miles of CO2 pipelines in order to expand our operations
into additional fields throughout the Gulf Coast of the United States.
The Subcommittee may also be interested to know that Denbury is working
with the federal Department of Energy and various research universities
on several Phase II and Phase III demonstration projects in the
Regional Carbon Sequestration Partnership Program. Finally, while our
business model focuses primarily on the transportation and
sequestration aspects of carbon capture and sequestration (``CCS''), we
are also very familiar with the capture component both in terms of (1)
the compression demands of transportation and sequestration and (2) our
enhanced oil operations, which capture and recycle large volumes of
CO2 in order to recover additional volumes of oil. Given
this background, Denbury is pleased to share with you its expertise in
CO2 EOR and its views on policy implications for the
nation's energy security and efforts to reduce industrial emissions.
A thorough understanding of both (1) the physical processes by
which CO2 is obtained, transported and injected for purposes
of EOR, and (2) the economics that underlie existing and future EOR-
related use of CO2 is essential to any consideration of
potential policy issues. The costs associated with capturing and
transporting CO2, whether in the context of EOR or
otherwise, are significant and varying and--perhaps the single largest
obstacle to developing carbon capture and transportation infrastructure
beyond the limited, discrete projects currently in operation. From
Denbury's perspective, it is critical that any contemplated state or
federal legislation or regulation not increase these costs and impede
private sector development of the infrastructure necessary to meet the
demands of our energy hungry and potentially carbon-constrained world.
I. Capture / Compression
The starting point for any CO2 EOR project is to produce
or capture the CO2. Denbury currently obtains all of its
CO2 from its natural deposit at Jackson Dome. Certain
existing and some evolving technologies allow CO2 emitted
from various manufacturing processes to be captured. The combustion or
gasification of hydrocarbon-based fuels such as coal, petcoke or other
hydrocarbons produces particularly large volumes of CO2 at
varying levels of quality and purity. As new capture-inclusive projects
are constructed, Denbury plans to acquire thousands of metric tons of
CO2 each day for use in EOR.
Aside from the threshold questions of how to properly classify
CO2 and whether and to what extent to restrict emissions,
from Denbury's perspective, the capture of CO2 presents no
significant policy issues. Rather, the capture component presents a
significant economic issue: First, existing capture technology is
expensive. The byproduct of hydrocarbon combustion or gasification is a
stream of gases and other impurities that contains various quantities
of CO2. In order for CO2 to be usable in EOR it
must be injected in a relatively pure form. Similarly, CO2
injected into deep saline reservoirs must be in a relatively pure form
to maximize the storage space available to be filled with
CO2. Thus, a significant component of the capture cost is
the cost to separate and purify the CO2 to be injected. The
lower the percentage of CO2 in the stream of gases, and the
greater the amount of impurities in the stream, the greater the cost of
capture. Second, most technologies capture the CO2 at a
lower pressure than is required to either enter a typical
CO2 pipeline or to inject into a deep saline reservoir or
EOR project. The costs of the compressors and the power necessary to
drive them are significant--approximately $7.50/ton of the estimated
$20/ton total cost 1 for CO2 that is transported
moderate distances. Therefore, the compression costs associated with
CO2 capture are slightly more than one-third (33%) of the
total CCS cost for the least expensive sources of anthropogenic (man-
made) CO2. Additional compression costs are incurred to
maintain pressure in pipelines and again when CO2 is
pressured up to a sufficient level for EOR reservoir injection. In
summary, without some means of reducing the cost of captured
anthropogenic CO2 significantly, infrastructure development
will likely remain stagnant.
\1\ Total costs of CCS varies substantially by source of
CO2--to upwards of $70/ton--and even across proposed
gasification projects because of variances in each process. This figure
represents an estimate of the lowest-cost industrial-sourced
To address this issue, last year the Finance Committee approved a
tax credit for the capture and sequestration of CO2 of
$10.00/ton in connection with EOR and $20/ton for non-EOR projects for
up to 75,000,000 tons sequestered. From Denbury's perspective, this
would be sufficient to incentivize construction of additional pipelines
from emission sites to geologic sequestration sites in connection with
EOR activities. Unfortunately, this provision was not included in the
energy legislation ultimately signed into law in December. We hope that
Congress will address the issue of CCS costs in 2008, especially those
associated with capture and compression, and note that proposed
projects from gasification through to sequestration have the potential
to create hundreds and perhaps thousands of jobs across the country.
The most economical way to transport CO2 is through
pipelines at pressures in excess of 1100 psi so that the CO2
is transported as a supercritical fluid (dense phase). At pressures in
excess of 1100 psi and temperatures common for CO2
pipelines, CO2 is a supercritical fluid which means that the
CO2 has properties of both a liquid and a gas. Larger
volumes of CO2 can be transported through CO2
pipelines in this dense phase than can be transported as a gas. Given
the pressure requirements to maintain CO2 in the dense
phase, CO2 pipelines are generally operated at pressures
greater than 2,000 psi. This pressure is well in excess of the average
operating pressure of a natural gas pipeline, though the material used
to manufacture both types is the same.
At the present time there exist over 3,500 miles of dedicated
CO2 pipelines, most of which have been transporting
CO2 for over 20 years--and some for over 30 years. (see
Attachment No. 1) However, this is just a fraction of the pipeline
network that exists for oil and natural gas and covers very limited
geographic areas. The vast majority of CO2 pipelines
transport natural CO2 from natural underground
CO2 production sources that are owned and operated by the
CO2 pipeline owner--generally for use in enhanced recovery
projects also owned and operated by the CO2 pipeline owner.
In cases where the owner of the CO2 pipeline has
CO2 production volumes in excess of its own EOR
requirements, the excess CO2 volumes are sold to EOR
operators in other projects or to industrial gas suppliers. This
limited number of regional CO2 shippers and consumers stands
in marked contrast to the numerous and geographically widespread
producers and consumers of oil and natural gas products. As with the
development of the extensive network of natural gas, oil and
hydrocarbon products pipelines, CO2 pipelines should also be
given room to grow by state and federal regulatory authorities
The construction and installation of CO2 pipelines is a
capital intensive effort, the costs of which have increased in recent
years for a variety of reasons, including rising steel prices,
construction costs and energy prices. By way of example, Denbury's 93
mile, 20 inch Freestate pipeline (see Attachment No. 2) completed in
2006 cost approximately $30,000 per inch-mile, resulting in an
effective transportation rate of approximately $3.50/ton at full
capacity. The initial 37 mile segment of Denbury's 24 inch Delta
pipeline was completed in 2007 at a cost of approximately $55,000 per
inch-mile. We estimate that our planned 314 mile, 24 inch Green
Pipeline that will run from Donaldsonville, Louisiana to Hastings field
in southeast Texas will cost approximately, $100,000 per inch-mile
resulting in an effective transportation rate of approximately $7/ton
at full capacity. While the length (pumping stations to maintain
adequate pressure add an additional $1 to $2 per ton to transportation
costs), route obstacles and type of terrain all added to the estimated
cost of the Green pipeline, the fact remains that such endeavors, even
under the best of circumstances are extremely costly and take years of
Today, a substantial portion of all CO2, natural gas,
oil and products pipelines in the U.S. are owned and operated by
companies that are organized as Publicly Traded Partnerships commonly
referred to as Master Limited Partnerships (``MLPs''), which through
their lower cost of capital have been an important financing source for
building these assets. Section 7704 of the tax code permits MLPs to be
taxed so that income and tax liabilities are passed through to the
partners, even though the MLPs are large public entities, provided 90
percent or more of the MLP's gross income is derived from certain
qualifying activities. These activities include exploration,
development, processing and transportation of natural resources,
including pipelines transporting gas, oil, or products thereof (see
Sec. 7704(d)(1)(E)). While this provision covers the processing and
pipelining of ``natural'' CO2, it is unclear whether it
covers anthropogenic CO2. Because of this uncertainty, much
of the existing CO2 pipeline capacity (that owned by MLPs)
cannot currently be used to transport anthropogenic CO2 from
emissions sites--at least not without significantly higher tax costs
than other pipeline assets in the industry.
Last year, as part of its energy tax package, the Senate Finance
Committee adopted a modification to include industrial source
CO2 in the definition of qualifying income (see Sec. 817 of
the Energy Enhancement and Investment Act of 2007, June 19, 2007).
However, Congress ultimately failed to include that package of
provisions in the Energy Independence and Security Act of 2007 (P.L.
110-140). Without this modification of the tax code, a substantial
portion of the pipeline industry will most likely not contribute
capital to the construction of the CO2 pipeline
infrastructure necessary to facilitate CCS through transportation of
anthropogenic CO2. We strongly urge Members of the Energy
and Mineral Resources Subcommittee to work with their colleagues on the
Ways and Means Committee and their counterparts in the Senate to
accomplish this important clarification.
IV. CO2 EOR--Injection / Sequestration
Approximately half of the oil that has ever been discovered will
remain in the reservoir following primary and secondary production
operations. In the proper environment, enhanced oil recovery utilizing
CO2 has the ability to recover up to an additional 25% of
the original oil in place or half of the remaining oil in place
following primary and secondary operations. Enhanced oil recovery
utilizing CO2 requires multiple injection wells throughout a
unitized field or reservoir. CO2 injection wells are
permitted and approved by each State's division or department of
Underground Injection Control utilizing the standards and policies
issued by the EPA. CO2 injection wells utilized in tertiary
oil recovery (a.k.a. EOR) are permitted and approved as Class II
Injection wells. Such wells have been in existence for over 30 years.
We believe existing laws and regulations provide sufficient protection
of the fresh water and ground water reservoirs from the injection of
CO2 in EOR operations or, for that matter, in deep saline
At the present time, CO2 injections for the purposes of
CO2 EOR total approximately 2 billion cubic feet per day
(Bcf/d) in three regions of the country, West Texas, Mississippi and
Wyoming. Several other oil producing regions of the country could and
would benefit from CO2 EOR. Unfortunately, these other areas
do not have naturally occurring CO2 supplies. We estimate
that if naturally occurring CO2 were available in all oil
producing regions in the country, CO2 EOR could inject
upwards of five or six times the current amount of CO2 being
injected. To put this in perspective, this additional CO2
volume is equivalent to approximately 40 typical gasification projects
(200 MMcf/d per project).
The amount of CO2 injected in CO2 EOR
projects varies by oil producing area and project design. Although each
project is different, the range of CO2 injected to produce a
barrel of oil is four to twelve thousand cubic feet (Mcf). In order to
produce oil through CO2 EOR, the injected CO2
must physically contact the oil remaining in the reservoir. Oil
remaining in the reservoir after secondary recovery operations cannot
be recovered or produced unless the oil is physically altered.
CO2 dissolves into the oil causing the oil to swell, the
viscosity to reduce and the surface tension (force holding the oil to
the rock) to reduce, allowing the oil to become mobile. Due to
reservoir heterogeneities and existing well spacing some oil is not
contacted and thus these characteristics of each CO2 EOR
project are the limiting factor to recovering a greater percentage of
the remaining oil. Further, CO2 EOR, while applicable to a
fairly wide range of reservoirs and oil gravities, is not applicable to
all. Generally, in order to keep the CO2 in the dense phase,
a reservoir pressure in excess of 1,100 psi must be achieved, thus
CO2 EOR is generally conducted in reservoirs below 3,000
feet. In our opinion, CO2 EOR is the most efficient tertiary
recovery technology available today for reservoirs in which
CO2 EOR is applicable.
At the present time Denbury is injecting approximately 550 million
cubic feet per day (MMcf/d) of CO2 into its current
CO2 EOR projects and is planning on initiating injections
into three additional CO2 EOR projects in the near future
which will increase our total injections to approximately 800 MMcf/d.
Denbury has allocated essentially 100% of its proven CO2
reserves to current and future projects that we own or have the option
to purchase. Therefore we have been negotiating and contracting for
anthropogenic volumes of CO2 from proposed gasification
projects and other existing anthropogenic CO2 sources. We
have signed three CO2 purchase contracts to date totaling
almost 800 MMcf/d of anthropogenic CO2. These contracted
volumes of anthropogenic CO2, and others in negotiation, are
necessary for Denbury to expand its CO2 EOR operations to
additional fields. These contracts also contain CO2 pricing
provisions that are tied to the price of oil, so as oil prices
increase, the price paid for the anthropogenic CO2
increases. These contracted CO2 prices may or may not be
sufficient to cover the CO2 capture and compression costs
depending on several variables including (existing and future) capture
and compression costs, the price of oil, the CO2 source, and
the distance from the source to the CO2 EOR project.
The U.S. economy will continue to require massive amounts of energy
well into the future. We believe the country needs to use all of its
resources to meet this demand. Given current environmental conditions,
there is also a desire to sequester significant volumes of
CO2 from industrial sources. CO2 EOR's ability to
address both of these realities make it uniquely well-suited to play an
important role in America's energy and environmental future. For this
to happen, the federal government should help address the significant
costs of capturing and transporting CO2 as discussed above.
The most important step Congress can take at present is to amend
Section 7704(d)(1)(E) of the tax code to make clear that transportation
of anthropogenic CO2 is included. This will allow a
significant number of industry participants to lead the way in
developing the infrastructure necessary for a carbon constrained,
energy dependent world. By providing necessary mechanisms to foster
CO2 EOR (whether on federal or privately owned land), and
allowing states to continue to oversee its development, the U.S. can
realize significant increases in domestic oil production and benefit
from reduced industrial emissions.
Just as we believe the country needs to draw upon all of its vast
resources to meet our energy requirements, we recognize that many
different avenues must be explored and researched to exponentially
reduce emissions. The EOR industry's experience with using
CO2 and its knowledge of oil reservoir geology should
greatly facilitate the commencement of significant CO2
sequestration today versus some distant time in the future. The
substantial body of knowledge and expertise with CO2 EOR
that exists is why we believe it will be the primary method of
sequestering CO2 in the near term, while research is
completed on additional technologies and geological formations.
CO2 EOR is not the sole answer to America's energy or
environmental challenges. However, it can be a key part of solving this
Attachment No. 1
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Attachment No. 2
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Response to questions submitted for the record by Tracy Evans,
Senior Vice President of Reservoir Engineering, Denbury Resources Inc.
Questions & Responses
1. Mr. Evans, if the government enacted that fix to the pipeline tax
code that you mention, how much investment do you think that
would bring in from the private sector?
It is difficult to quantify with any certainty how much private
sector investment would result from clarification of Section 7704 of
the tax code with respect to anthropogenic carbon dioxide
(CO2). Denbury's expertise lies in tertiary oil recovery
methods, and pipeline construction investment decisions depend on
multiple factors in addition to tax policy. Nonetheless, such
clarification would remove what is essentially a significant regulatory
hurdle or disincentive to transporting man-made CO2 volumes
from emissions sites to enhanced oil recovery or saline injection sites
via dedicated pipelines, the most efficient mode of transporting
CO2. Insofar as a major portion of oil, natural gas and
CO2 pipelines are owned and operated by publicly traded
limited partnerships, Denbury Resources believes that removing this
obstacle would have a substantial impact:
Our review of the Oil and Gas Journal's 2007 Pipeline
Construction Report (published by Penwell) indicates that 10,500 miles
of pipeline projects were proposed or planned (primarily to transport
oil and natural gas products) as of its publication in November 2007.
Of that amount, 78% or 8,100+ miles are being proposed or planned by
publicly traded partnerships.
Our review of the Pipeline Journal's most recent annual
ranking of the top pipeline owners and operators in the United States,
indicates that publicly traded partnerships account for 66%+ of the top
20 liquid pipelines operators ranked by number of miles operated.
(November 2007; data based on 2006 miles; Oildom Publishing Co.) These
top 20 owners based on miles of liquid pipelines operated account for
66%+ of the total number, (91,120 miles of 138,037 miles), of liquid
pipelines in the U.S. If so-called legacy pipelines owned by major oil
and gas companies are removed, the percentage owned and operated by
publicly traded partnerships increases to 96%+.
Looking at the top 20 gas pipeline operators, which
account for approximately 75% of all gas pipelines (234,275 miles of
312,586 miles) in the U.S., the percentage owned and operated by
publicly traded partnerships is 43%+.
From the above, it is very evident that publicly traded
partnerships own or operate a substantial portion of pipelines
operating in the U.S. today and are constructing or planning to
construct the vast majority of new pipelines. It is hard to envision
how the enormous pipeline network required to effectively transport
CO2 for storage--via enhanced oil recovery, injection into
saline aquifers, or otherwise--could be built without the resources,
expertise and full participation of publicly traded partnerships. Such
companies can hardly be expected to undertake the substantial effort
and investment required to build CO2 pipelines while
uncertain of the tax treatment of any eventual income derived from the
transportation of anthropogenic CO2. CO2 pipeline
owner/operator Kinder Morgan has also called attention to this issue.
(See testimony of Vice President Charles E. Fox before the Senate
Commerce Committee's Subcommittee on Science, Technology, and
Innovation, November 7, 2007.)
Further, due to their tax structure which results in lower costs of
capital, publicly traded partnerships have historically been willing to
accept lower rates of return on investment than public companies that
are corporate entities. Thus, if publicly traded partnerships
participate in the construction and ownership of CO2
pipelines, the total cost of capturing, transporting and sequestering
man-made CO2 will be lower than would otherwise be the case.
If Congress is determined to increase domestic production through
CO2 enhanced oil recovery (EOR) and to store CO2
to reduce emissions, it should encourage the involvement of this key
segment of the private sector by removing this uncertainty.
2. Mr. Evans, what federal and state EOR incentives is your company
currently taking advantage of?
Section 43 of the Internal Revenue Code provides a 15% tax credit
for capital investments made in CO2 EOR projects. However,
the credit is indexed to crude oil prices, which are now well above the
maximum level at which the tax credit applies. Thus, Denbury utilizes
some Section 43 EOR tax credits earned in prior years when crude oil
prices were lower to offset federal taxes in the current year, but new
Section 43 credits are no longer available
At the present time, Mississippi, Louisiana and Texas (areas where
Denbury operates) all provide for reduced severance taxes on oil
produced as a result of enhanced oil recovery utilizing CO2.
While each state varies in the amount of severance taxes levied,
Mississippi and Texas each grant a 50% reduction in the amount of
severance taxes paid on oil produced through CO2 EOR.
Louisiana is different in that it grants a severance tax holiday (0%)
until project payout is reached. In January 2008, Texas enacted a new
regulation that grants an additional 50% (total of 75%) severance tax
reduction for oil produced using man-made CO2 in EOR
3. Mr. Evans, your testimony mentions the tax credit for
CO2-EOR that was almost enacted last year and says
it would be enough to incentivize pipeline construction--would
it also be enough to incentivize capture as well?
The tax credit approved by the Senate Finance Committee last year
was for carbon capture and sequestration (CCS), not for CO2
EOR. The point of the credit is not to subsidize pipeline construction,
but to defray the high costs noted in my testimony of separating,
capturing and pressurizing anthropogenic CO2. If capture
costs--the most significant factor in total CCS costs--can be
sufficiently reduced, the existing CO2 pipeline backbone
could be significantly expanded in connection with EOR activities in a
cost-effective manner. At current market prices for crude oil, a tax
credit for the capture and sequestration of CO2 of
approximately $10.00 per ton would lower total CCS costs sufficiently
to encourage the capture of significant volumes of CO2 from
the lowest cost emissions sources (i.e. +/-$20/ton for ammonia and coal
gasification.). A reliable supply of man-made CO2 at a
reasonable price, in turn, would encourage EOR end users to undertake
the substantial investment required for construction of additional
pipelines from emission sites to geologic sequestration sites. Thus,
credits incentivizing capture would help create and match the
CO2 supply with EOR demand, from which the pipelines to link
the two would follow. These pipelines could ultimately be used to
transport and sequester additional volumes of CO2 after the
cessation of EOR operations.
As I testified at the hearing, Denbury builds and owns pipelines to
transport CO2 for use in its EOR operations. Denbury does
not capture CO2 from industrial sources, although it has
entered into agreements to purchase CO2 from projects that
plan to capture it. So far, these projects--and many others that
envision capturing CO2 emissions--have not started
construction. The proposed tax credit could help advance many of these
projects, namely those with the lowest estimated costs of capture, by
addressing a major cost component. A larger credit may help advance
additional projects--those with slightly higher capture costs.
Senators Kent Conrad and Orrin Hatch recently introduced
legislation (S. 3208) that contains a new version of the tax credit.
The credit as structured in this bill would range from $15-$30 per ton
of CO2 captured and sequestered and would be effective for
ten years. Denbury supports these modifications and urges members of
the Subcommittee to work with their colleagues to pass companion
legislation in the House of Representatives.
4. Mr. Evans, what sort of production levels do you think we could see
from CO2-EOR over the next 10 or 20 years? Could we
reach 1 million barrels per day? What would it take to make
those sort of production levels a reality?
Assuming access to sufficient supplies of CO2 at
reasonable prices in all oil producing regions of the country, I
believe the United States could eventually reach production from
CO2 EOR of up to 2 million barrels per day. It is difficult
to estimate a time frame since that depends on many variables (rates of
construction, labor costs, materials costs, etc.), but +/-20 years is
reasonable. I arrive at this estimate as follows:
The maximum rate of oil production the United States can expect
from CO2 EOR depends on many factors, primarily the
availability of CO2 at reasonable costs. CO2 EOR
is applicable to all oil producing regions of the country but not to
all oil producing reservoirs in each region. As discussed at the
hearing, the success of CO2 EOR in a given reservoir depends
on multiple factors such as reservoir depth, gravity of the oil, purity
of CO2 stream, reservoir temperature, reservoir pressure,
reservoir heterogeneity and other factors.
Denbury has successfully utilized CO2 EOR in one oil
producing region of the country with the only known naturally occurring
significant source of CO2 east of the Mississippi River.
When comparing our CO2 EOR volumes (an estimated 24,000
gross barrels of oil per day) to the current daily total volume of oil
production in the State of Mississippi (based on U.S. Energy
Information Administration estimates for January 2008), CO2
EOR is in excess of 42% of Mississippi's total production. With
Denbury's future additional projects, CO2 EOR will
eventually exceed 50% of total production in Mississippi.
The Permian Basin of West Texas has the greatest number of existing
CO2 EOR projects--more than any other oil producing basin in
the country. It is estimated that total current oil production from
CO2 EOR projects there is approximately 200,000 gross
barrels per day while total daily production from all forms of oil
production in the basin is approximately 678,000 barrels per day
according to IHS, Inc., which maintains an industry production
database. Thus, approximately 30% of the oil production from the
Permian Basin is being produced through CO2 EOR.
Applying the overall level of success with CO2 EOR in
these two regions--30% to 50% of total production--to current U.S. oil
production, which averages approximately 5 million barrels per day (a
reasonable, useful analogy based on what we know of other oil-producing
regions), would yield 1.5 million to 2.5 million barrels per day. Since
it is unlikely that man-made CO2 will be delivered to all
producing oil basins at the same time, I believe it's appropriate to
reduce these figures by 20%. Thus, my estimate of potential additional
oil production from CO2 EOR is 1.2 million to 2.0 million
barrels per day.
As stated at the outset, this estimate assumes access to sufficient
supplies of CO2 at reasonable prices in all oil producing
regions of the country. Reliable access to such supplies is what would
it take to make these sort of production levels a reality. My answers
to questions 1 and 3 above describe policies that, if adopted by
Congress, would facilitate this.
Mr. Costa. Thank you very much, Mr. Evans.
Our next witness is Mr. William Roby, Vice President of
Worldwide Engineering and Technical Services for Occidental Oil
and Gas Companies.
Mr. Roby, please.
STATEMENT OF WILLIAM ROBY, VICE PRESIDENT, WORLDWIDE
ENGINEERING AND TECHNICAL SERVICES, OCCIDENTAL OIL AND GAS
Mr. Roby. Thank you, Chairman Costa.
Mr. Costa. The five-minute rule applies to all of you, just
like the previous panel.
Mr. Roby. Thank you. Thank you, Chairman Costa, members of
the Energy and Mineral Resources Subcommittee, and other
My name is William Roby. I am Vice President of Worldwide
Engineering and Technical Services for Occidental Oil and Gas
I greatly appreciate the opportunity to speak today
regarding both Occidental's use of carbon dioxide to enhance
the recovery of oil and associated gas in the United States,
and some of the emerging policy issues related to enhanced oil
These issues are of great importance to the nation,
particularly as demand grows, and we seek ways to increase
domestic production of oil and natural gas in this country,
while reducing the concentration of CO2 in the
By way of background, Occidental Oil and Gas Corporation is
a Los Angeles-based oil and gas exploration and production
company, with operations in the United States, the Middle East,
North Africa, and Latin America. Sixty-three percent of
Occidental's 2007 production occurred in the United States, and
75 percent of our proven reserves are located in the United
Enhanced oil recovery techniques have substantial economic
and environmental benefits, and can significantly increase oil
recovery. As a result, oil that would have been left in place
is producible, and contributes directly to our domestic supply.
Its use is being good stewards of our country's precious energy
In addition, CO2 EOR is a viable method for
reducing greenhouse gases by reusing and storing CO2
underground from industrial and power-generation facilities.
CO2 has been used for over 30 years in the
Permian Basin in West Texas, and New Mexico to enhance oil
recovery. Since that time, Occidental has become the largest
user of CO2 injection for EOR in the world. And
CO2 flooding is our most commonly used EOR
Through CO2 flooding, the fields Occidental
operates in the Permian Basin will produce over 1 billion
barrels of oil more than would have been produced without this
technology. Our experience shows that CO2 flooding
has increased the ultimate oil recovery by an average of nearly
We now operate over 8,700 wells in 28 CO2 EOR
projects in Texas and New Mexico. We have nearly 3,700
CO2 injection wells that support 5,000 producing
wells, and we inject approximately 1.4 billion cubic feet of
CO2 each day, or 500 billion cubic feet per year, in
the Permian Basin alone.
However, using CO2 to enhance oil recovery is
technically challenging and costly. Some oil formations are not
amenable to CO2 injection, and all depend on
geologic structure, permeability, and homogeneity of the
formation. Additionally, oil production response sometimes
takes many months to occur. We estimate that using
CO2 to enhance oil recovery increases the cost per
barrel of oil by more than 50 percent over typical secondary
Notwithstanding the cost, we believe using CO2
to increase oil recovery is an extremely important technology
for meeting our national energy needs, and Occidental
encouraged Congress to develop policies and incentives to
increase its use. National policies and incentives to promote
CO2 injections could significantly increase proven
oil reserves. Increasing domestic reserves has additional
benefits, including extending the life of aging reservoirs,
increasing tax and royalty revenues for the public, increasing
employment opportunities to operate the fields, and providing
greater domestic supplies of energy.
The committee specifically asked for suggestions on how to
foster further use, and remove impediments to the expansion of
CO2 enhanced oil technology. Since CO2
EOR is a costly business proposition, these projects require
robust, long-term economics to incentivize producers to
undertake the risks. We have the following suggestions.
Number one, investment incentives. We suggest you consider
providing incentives such as investment credits, and
accelerating depreciation of the project's capital cost,
including infrastructure required to transport and inject
Number two, royalty rates. We suggest that the government
consider providing declining royalty rates on Federal leases
where CO2 EOR is used.
Number three, legal issues. Legal areas that warrant
clarification include, one, confirming subsurface pore space as
part of the mineral state; number two, predictable and defined
rights and obligations relating to subsurface pore space
ownership; and number three, the ability and easy modification
of historic field unit agreements to accommodate EOR
operations, including potential unitization raised by
sequestration of CO2.
And last, clear expectations regarding the disposition of
EOR wells and fields, including oilfield CO2
However, we believe the current regulatory provisions and
Permian regimes for conventional CO2 EOR operations
work very well, and provide thorough oversight by the
regulators and opportunity for public input.
And I want to discuss the role CO2 EOR
technology can play on controlling greenhouse gas emissions. In
particular, one of the benefits of injecting CO2 for
enhanced oil recovery is the ability to store significant
volumes of CO2 in the reservoir, both during and
after oil and gas production. In typical EOR operation,
approximately one-third to one-half of the CO2
initially injected becomes trapped in the reservoir. The rest
is recycled from producing wells as a valuable commodity, and
As I mentioned earlier, Occidental currently injects
approximately 500 billion cubic feet of CO2 per
year. To put this in context, each year the amount of
CO2 that Occidental injects is equivalent to the
emissions of 10 150-megawatt coal-fired power plants.
We have 30 years of history using naturally occurring
CO2 from underground reservoirs. However, we just as
easily could use CO2 captured from emissions of
electrical utilities, refineries, and other large sources if it
were available at competitive prices.
We believe the key challenge to using manmade
CO2 and EOR operations are the costs to capture
carbon dioxide from industrial-power generation sources, and
the cost of building the infrastructure to transport the
CO2 to a field, and to compress it to the required
pressure for injection into the reservoir.
Occidental believes that industrial CO2 for
natural recovery provides technical information, and
demonstrates results for long-term CO2
sequestration. In fact, this technology is a great way, is a
gateway to future large-scale carbon sequestration; and the
industry's 30-year history of using CO2 provides the
evidence it can be managed safely.
Mr. Costa. Mr. Roby, we appreciate your testimony, and you
have done a good job.
Mr. Roby. Yes, that is my last comment. Thank you very
Mr. Costa. Thank you.
[The prepared statement of Mr. Roby follows:]
Statement of William Roby, Vice President of Worldwide Engineering and
Technical Services, Occidental Oil and Gas Corporation
Chairman Costa, members of the Energy and Mineral Resources
Subcommittee and other guests, my name is William Roby. I am Vice
President of Worldwide Engineering and Technical Services of Occidental
Oil and Gas Corporation. I greatly appreciate the opportunity to speak
today regarding both Occidental's use of carbon dioxide to enhance the
recovery of oil and associated gas in the United States and some of the
emerging policy issues related to enhanced oil recovery. These issues
are of great importance to the Nation, particularly as demand grows and
we seek ways to increase domestic production of oil and natural gas in
this country while reducing the concentration of carbon dioxide in the
By way of background, Occidental Oil and Gas Corporation is a Los
Angeles-based oil and gas exploration and production company with
operations in the United States, the Middle East, North Africa and
Latin America. Sixty-three percent of Occidental's 2007 production
occurred in the United States, primarily in the states of California,
Texas, New Mexico, and Kansas. Seventy-five percent of our proven
reserves are located in the United States.
Before I discuss Occidental's experience with enhanced oil recovery
using carbon dioxide or CO2, I want to briefly explain what
I mean when I use the term ``enhanced oil recovery.'' Enhanced oil
recovery, or EOR, is a generic term for techniques that increase the
amount of oil extracted from a reservoir beyond primary and secondary
recovery methods. Primary recovery refers to production where the
hydrocarbons in the reservoir flow into the well due to the natural
pressure in the reservoir. Secondary recovery refers to production
where the hydrocarbons flow into the well because pressure in the
reservoir is increased by injecting fluids, such as water or
hydrocarbon gas, typically already found in the reservoir. Lastly,
enhanced oil recovery refers to production from injecting materials not
normally found in the reservoir such as steam, CO2 in large
quantities, or other chemicals. These techniques are designed to
increase reservoir pressure, reduce the oil's viscosity or alter oil's
properties that cause it to be trapped in small pore spaces in the
rock, thus improving oil's ability to flow through the reservoir and
Enhanced oil recovery techniques have substantial economic and
environmental benefits. They can increase production from an oil
reservoir by an additional 10% to 50% of the oil originally contained
in the reservoir. As a result, oil that traditionally would have been
left in place contributes directly to our domestic supply. Recovering
more oil from existing fields with EOR uses far fewer resources than
simply abandoning older fields and installing new infrastructure, such
as roads, pipelines and equipment, for primary production in new
locations. In addition to these benefits from all EOR techniques, EOR
using carbon dioxide flooding is a commercially viable method for
reducing greenhouse gas emissions by reusing and storing CO2
underground that would otherwise be emitted from industrial or power
generation facilities to the atmosphere.
Carbon dioxide has been used for over thirty years in the Permian
Basin in West Texas and New Mexico to enhance oil recovery. Since that
time, Occidental has become the largest user of CO2
injection for EOR in the world, and CO2 flooding is our most
commonly used EOR technique in the Permian Basin. By using this
technique, along with other new technologies, we have been able to
substantially increase the productivity and lengthen the life of
existing oil fields. Through the use of CO2 flooding and
other EOR techniques, the fields that Occidental operates in the
Permian Basin will produce over one billion barrels of oil more than
would have been produced without this technology. Our experience has
been that CO2 flooding has increased the ultimate oil
recovery from the fields where we employ it by an average of nearly 25
percent. We now operate approximately 8,700 wells in 28 EOR projects in
Texas and New Mexico utilizing CO2 to increase oil
production. We have nearly 3,700 CO2 injection wells that
support 5,000 production wells, and we inject approximately 1.4 billion
cubic feet of CO2 each day or 500 billion cubic feet per
year in the Permian Basin alone.
Using CO2 to enhance the recovery of oil is technically
challenging and costly. Some oil formations are not amenable to carbon
dioxide injection, depending on the geologic structure, permeability
and homogeneity of the formation. For those fields where CO2
injection is feasible, such as in the Permian Basin, we incur costs
both to purchase or produce CO2 and to acquire, operate and
maintain the necessary above-ground processing equipment. Projects are
capital intensive because they require extensive infrastructure to
transport, compress, capture and recycle CO2; operating
costs, such as for additional electricity needs, are also high; and oil
production response sometimes takes many months to occur. These costs
add significantly to our total cost to produce a barrel of oil. We
estimate that using CO2 enhanced recovery at our Permian
Basin operations increases the cost of recovering a barrel of oil by
more than 50% over typical primary and secondary recovery operations.
Notwithstanding the cost, based on our experience in the Permian
Basin, we believe the use of carbon dioxide to increase oil recovery is
an extremely important technology for meeting our national energy
needs, and Occidental encourages Congress to develop policies and
incentives for increasing the use of this technology. Enhanced oil
recovery using CO2 has helped increase supplies from some of
the Nation's most prolific fields. National policies and incentives to
promote the use of carbon dioxide injection could significantly
increase proven reserves of oil and gas in the United States.
Increasing domestic reserves has many additional benefits, including
extending the life and recoverable reserves of aging reservoirs,
increasing tax and royalty revenues for the public, increasing
employment opportunities to operate the fields, and providing greater
domestic supplies of energy, all of which could, perhaps, reduce or
forestall speculative exploration in undeveloped areas.
The Committee has specifically asked for suggestions on how to
foster further use of carbon dioxide enhanced oil recovery technology
and to strengthen our domestic oil supply by removing impediments to
the expansion of this technology. Since CO2 EOR is a costly
business proposition, these projects require robust long-term economics
to incentivize the producers to undertake the risk. We have the
following suggestions on ways to foster further use of this technology:
1. Investment incentives:--we suggest you consider providing
incentives such as investment credits, and accelerated depreciation of
the project's capital cost, including infrastructure required to
transport and inject carbon dioxide.
2. Royalty rates--we suggest that the government consider
providing declining royalty rates on federal leases where
CO2 EOR is used.
3. Legal issues--legal areas that warrant clarification include:
1) confirming subsurface pore-space as part of the mineral estate, 2)
predictable and defined rights and obligations relating to subsurface
pore-space ownership, 3) the ability to easily modify historic field
unit agreements to accommodate EOR operations, including potential
unitization issues raised by the sequestration of CO2, and
4) clear expectations regarding the disposition and abandonment of EOR
wells and fields, including oilfield carbon dioxide sequestration
sites. However, we believe the current regulatory provisions and
permitting regimes for conventional CO2 EOR operations work
very well and provide thorough oversight by the regulators and
opportunity for public input.
In addition to these recommendations, I now want to discuss the
role that CO2 EOR technology can play in controlling
greenhouse gas emissions. In particular, one of the benefits of
injecting carbon dioxide for enhanced oil recovery is the ability to
store significant volumes of carbon dioxide in the reservoir both
during and after oil and gas production. In typical EOR operations,
approximately one third to one-half of the carbon dioxide initially
injected becomes trapped in the reservoir. The rest is recycled from
oil producing wells as a valuable commodity and reinjected.
CO2 is not vented to the atmosphere. Additional trapping of
carbon dioxide occurs with each subsequent injection cycle so that,
eventually, nearly all of the initial CO2 volume becomes
stored in the formation and more CO2 must be procured to
maintain oil production rates. As I mentioned earlier, Occidental
currently injects approximately 500 billion cubic feet of
CO2 per year. Of this 300 billion cubic feet is recycled
CO2 from producing wells, and the other 200 billion cubic
feet--approximately 40% of the injected CO2--is newly
supplied to the floods to make-up for the quantity stored through the
CO2 flooding process. To put this in context, each year the
amount of CO2 that Occidental injects is equivalent to the
emissions from ten 150-megawatt coal-fired power plants.
Occidental has 30 plus years of history using naturally occurring
carbon dioxide, which we produce from underground reservoirs or buy
from other producers as a commodity. However, we could just as easily
use carbon dioxide captured from emissions of electric utilities,
refineries and other large sources--if it were available at competitive
prices in the Permian Basin or at other fields suitable for
CO2 flooding. We believe the key challenges to using man-
made carbon dioxide in EOR operations are the cost of the technology to
capture carbon dioxide from industrial and power generation sources and
the cost of building the infrastructure to transport the carbon dioxide
to an injection site and compress it to a higher pressure that allows
it to be injected into an oil reservoir for enhanced recovery.
Additional incentives and policies would be useful to expedite
building carbon dioxide pipelines and to offset the cost of adding
equipment to capture and compress emissions containing carbon dioxide.
Also, since natural CO2 supplies are not available near most
oil fields that are amenable to CO2 flooding, consideration
should be given to developing policies and incentives that encourage
locating new industrial operations and power generation with large
carbon dioxide emissions near such oil and gas reservoirs. The
utilization of these man-made CO2 sources would enable more
widespread application of CO2 EOR to increase domestic oil
Many organizations are now looking at the underground storage of
carbon dioxide, which is also known as geological storage or
sequestration, as an approach to controlling greenhouse gas emissions.
Occidental sees mutual benefit from the use of carbon dioxide for
enhanced oil recovery and the storage of carbon dioxide as a way to
control greenhouse gas emissions. The 2005 special report sponsored by
the Intergovernmental Panel on Climate Change on carbon dioxide capture
and storage strongly endorsed the idea and said that EOR technology can
provide a substantial technical head start on proving the concept of
geologic storage of carbon dioxide at commercial scale. Occidental
Occidental also believes that industry experience using
CO2 for enhanced oil recovery provides technical information
and demonstrated results for long-term CO2 sequestration. In
fact, this technology we are using is the gateway to future large scale
carbon sequestration operations. The industry's 30-year history of
using CO2 for EOR provides evidence that CO2 can
be managed safely and should allay concerns about long-term storage of
CO2 in oil and gas reservoirs as well as other geologic
Occidental believes that, while storing man-made carbon dioxide in
oil and gas reservoirs and other underground formations is not the only
option for reducing greenhouse gas emissions, it is an important,
commercially viable option that can be rapidly implemented to
accomplish this objective, particularly because it carries with it the
substantial additional benefit of increasing domestic oil and gas
Thank you for the opportunity to speak today and share Occidental's
experience using carbon dioxide to enhance and increase oil and gas
production in the United States, as well as our ideas for creating
policies and incentives to increase its use and expedite development of
a national infrastructure to capture, transport, inject, recycle and
store underground carbon dioxide that has traditionally been emitted to
Response to questions submitted for the record by William Roby, Vice
President--Worldwide Engineering and Technical Services, Occidental Oil
& Gas Corporation
1. Question: Mr. Roby, there are a lot of questions with regard to
carbon sequestration. What has the safety record been like in
your operations? And do you have any problems with pipeline
Response: The safety and environmental record at our
CO2-EOR operations has been consistently good. As I
indicated in my testimony our operations have been in existence for
approximately 30 years and Occidental acquired the assets in 2000.
During the time of our operation we have had no safety problems related
to the use of CO2 or its transportation. With regard to
pipeline leakage, we have typical oil and gas pipelines in the fields
in addition to the necessary CO2 pipelines. Our pipeline
system is subject to the normal maintenance issues associated with such
systems but we have had no safety problems with the handling or
transportation of CO2. Because the CO2 pipelines
do not carry volatile substances, they pose much less of a safety and
environmental risk than typical oil and gas pipelines.
2. Question: Mr. Roby, what federal and state EOR incentives is your
company taking advantage of?
Response: Section 43 of the Internal Revenue Code has a provision
for Enhanced Oil Recovery Credit which allows a 15% credit on the cost
of CO2 (including the transportation to the site) for
qualified enhanced oil recovery projects where first injection
commenced after 1990. If a company takes the credit, it then loses the
deduction for the cost so it nets out to approximately a 10% credit. We
were able to take advantage of this provision for several years,
however, the credit phased out when the cost of oil went above the
inflation-adjusted cap (now approximately $46 per barrel) in 2005.
Therefore, we have not been able to use this credit since 2005.
Occidental is actively performing CO2-EOR only in the
states of Texas and New Mexico and each state treats EOR projects
differently from a tax standpoint. In New Mexico, EOR incentives are
available to producers only under certain circumstances. Qualifying
projects can get relief of 50% of the state severance tax rate, which
is 3.75%, so the net benefit to a producer would be 1.875%. However,
this incentive phases out when the price of oil goes above $28 per
barrel, which it did in 2003. Our North Hobbs Unit began production
after 2003 and consequently, we have not received any state incentives
for our New Mexico EOR operations.
In Texas, incentives are also allowed in certain circumstances.
Producers may take advantage of a 50% oil severance tax reduction on
EOR projects approved by the state. The severance tax rate is 4.6% so
the net tax reduction is 2.3% of the market value of oil produced using
CO2 injection. Occidental is currently taking advantage of
this tax provision in Texas.
3. Question: Mr. Roby, how much natural gas is produced during
CO2-EOR operations and what happens to it?
Response: While the primary target of our CO2-EOR is
oil, in some cases, we do encounter ``associated'' natural gas. The
amount of natural gas produced varies from field to field and from well
to well and is not easy to quantify in the abstract. Generally, the
natural gas is captured and sent to a processing plant where the
CO2 and other compounds are removed; then the natural gas is
put into a pipeline and sold. In our operations, we use the recovered
CO2 again in EOR operations.
4. Question: Mr. Roby, what sort of production levels could we see
from CO2-EOR over the next 10 to 20 years? Could we
reach 1 million barrels a day? What would it take to make those
sorts of production levels a reality?
Response: Currently, the U.S. produces about 200,000 barrels of oil
per day (BOPD) using CO2-EOR with about 180,000 of those
barrels being produced in the Permian Basin of Texas and New Mexico. As
I indicated in my testimony, fields respond differently to
CO2-EOR and some fields are simply not responsive to
CO2 or geologically amenable to the application of
CO2-EOR technology. In order to substantially increase the
recovery of oil using CO2-EOR, it will be necessary to
ascertain whether a particular field is amenable to CO2-EOR,
find sources of CO2 and then build the infrastructure to get
the CO2 to the fields. Ultimate production levels will, of
course, depend upon the costs of each project and the price of oil. It
is certainly possible that production could reach 1mm barrels per day
given adequate CO2 and investment in infrastructure;
however, this level of production is unlikely in the foreseeable future
absent some governmental incentives. Using the current U.S. production
as an analog, our industry has grown production 200,000 BOPD over the
past 20 years. This suggests that CO2 induced production
could be in the 300,000 to 400,000 BOPD range over the next 10-20 years
unless unusual investment incentives are undertaken.
Mr. Costa. I want to be fair to all the witnesses in terms
of the timing, and you exceeded your time. But we do appreciate
Our next witness is Mr. Greg Kunkel. You are Vice President
of Environmental Affairs in Tenaska, Inc., is that correct?
Mr. Kunkel. That is correct.
Mr. Costa. Wonderful. Please begin your testimony.
STATEMENT OF GREG KUNKEL, VICE PRESIDENT, ENVIRONMENTAL
AFFAIRS, TENASKA, INC.
Mr. Kunkel. Thank you, Chairman Costa, Ranking Member
Pearce, and members of the Subcommittee.
My name is Dr. Greg Kunkel, Vice President of Environmental
Affairs at Tenaska. And I am pleased to be here to share our
views on enhanced oil recovery.
Tenaska is one of the nation's top developers of large,
efficient power-generation facilities. In fact, the Natural
Resource Defense Council ranks Tenaska as having the lowest
carbon footprint of any of our peers, with less than half of
the national average emission rate of greenhouse gases.
Tenaska's record demonstrates that significant greenhouse
gas emission reductions can be accomplished in the power sector
using low-carbon fuels, like natural gas, and advanced
Today, however, I am here to talk about achieving even
more, and not with natural gas, but with coal, with the help of
the oil industry, and potentially with your help.
Over the last several years, high and volatile natural gas
prices have stimulated a growing demand for baseload electric
generation resources, like coal and nuclear, with lower and
less volatile fuel costs, and 24-hour-per-day operation.
Because market conditions were obvious to everyone, many
coal-fired facilities were proposed, and many advanced to some
stage of development. Some have been, or are being, built, but
many more have been postponed or canceled due to uncertainty
about future legislative caps on greenhouse gas emissions,
among other things.
Tenaska has concluded that baseload generation using coal
is still very necessary to avoid soaring electricity prices in
the future. But the control of greenhouse gas emissions in the
most cost-effective manner should be a part of any future coal
We believe that enhanced oil recovery has an important role
to play in achieving cost-effective emission control for early
adopters of carbon emission control technology.
Currently, Tenaska has an early development of commercial-
scale coal-fired baseload power facilities that is unlike any
currently in operation. Tenaska's objection has been to find
ways to develop the baseload resources that the market for
In enhanced oil recovery, we see a way to do that and
provide carbon dioxide as a commodity in an existing market, in
which the end use also accomplishes geologic storage.
The Tenaska Trailblazer Energy Center, located near
Sweetwater, Texas, in the Permian Basin, where the best EOR
opportunities exist, is designed to capture up to 90 percent of
its potential carbon dioxide emissions, and deliver that
CO2 via pipeline for use in enhanced oil recovery.
Trailblazer will utilize super-critical pulverized coal
technology, and we are considering adding carbon dioxide-
capture technologies, among others.
While Tenaska is fully focused on developing Trailblazer,
and it could be in operation as early as 2014, it is important
to recognize that we have developed this project in
anticipation of Federal climate change legislation that offset
the significant capital and operating costs of carbon-capture
Without a carbon regulatory regime to ensure that avoidance
of greenhouse gas emissions has a monetary value, it appears
that revenues from enhanced oil recovery carbon dioxide sales
will be insufficient to cover all carbon-capture costs.
However, if carbon emissions are regulated, projected
compliance cost savings and other regulatory effects, combined
with EOR revenues, would provide the needed economic incentives
to build Trailblazer.
Perhaps the most important thing Congress could do to
facilitate the development of Trailblazer or other similar CCS
projects is to provide industry with regulatory certainty,
particularly a regulatory framework within which a market can
develop that values greenhouse gas emission reductions.
In the past, Congress has employed a number of effective
policies to help overcome barriers to entry and encourage new
energy technologies. Tenaska generally supports those
mechanisms that provide the greatest degree of certainty; we do
a lot of financing. We prefer investment tax credits and
accelerated depreciation to Federal grants or loan guarantees,
primarily because of predictability.
Should the House decide to pursue a cap-and-trade
mechanism, some of the potential areas where the specifics of
climate change legislation could affect the project are
allowance allocations, use of auction proceeds, mobilization of
equipment manufacturers and others in the industry, necessary
regulation, and electricity pricing.
In summary, proven technology is available today to capture
greenhouse gases from coal-fired power plants, and the value of
carbon dioxide-enhanced oil recovery makes that technology
cost-effective if we also value a reduction in greenhouse gas
As previously acknowledged, Trailblazer was conceived and
has been designed in anticipation of Federal climate change
legislation. In the absence of such legislation, Trailblazer
faces costs and risks that likely cannot be offset by revenues
For the benefit of demonstrating carbon capture and storage
at commercial scale, Congress may elect to support a few
carbon-capture projects, and we would hope that cost-effective
projects associated with EOR will be given some consideration
in that event.
Thank you again for your interest in this subject. I would
be pleased to respond to any questions at the right time.
[The prepared statement of Mr. Kunkel follows:]
Statement of Gregory P. Kunkel, Ph.D., Vice President of
Environmental Affairs, Tenaska, Inc.
Thank you Chairman Costa, Ranking Member Pearce and Members of the
My name is Dr. Greg Kunkel. I am Vice President of Environmental
Affairs for Tenaska, Inc., and I am pleased to be here to share our
views on opportunities for enhanced oil recovery using carbon dioxide
captured from a power plant. I believe Tenaska can provide important
insight to Congress on this matter because of an electric generation
project Tenaska has in early development: a commercial-scale, coal-
fired, baseload power facility that, unlike any currently in operation
anywhere, would capture up to 90 percent of its potential carbon
dioxide (CO2) emissions and deliver that CO2 for
use in enhanced oil recovery operations and geologic storage.
Tenaska is a privately held company that builds, owns and operates
power plants, among other business activities detailed at the end of
this testimony. Congress and developers of power plants share some
common interests concerning climate change legislation. You and I both
want to know what it will cost to eliminate greenhouse gas emissions
from power generation through carbon capture and storage technologies.
If the answer to this was well known, then climate change legislation
could be crafted that would pose less risk to the economy. From the
perspective of the electric industry, technological risks for the first
commercial carbon capture and storage facility are compounded by the
fact that federal greenhouse gas cap-and-trade or other governing
regulatory structures do not yet exist, and it is unclear whether state
or regional regulatory structures will prevail over the long term.
International obligations have not been finalized. Whereas industry
looks to Congress for a structured market with rules, Congress
reasonably looks to industry for at least a preliminary estimate of the
Academics, policy makers and even the leadership of the G8
countries seem to agree that the country, and the world, needs a number
of large-scale carbon capture and storage projects that will resolve
critical technical and economic feasibility issues. Tenaska believes
that enhanced oil recovery (EOR) can contribute to advancement of such
a project by simultaneously providing for geologic storage of
CO2 and a significant economic benefit that could help to
pay for early deployment of carbon capture technology. Whatever the
costs for carbon capture and storage will be, and I do not have a final
answer for you on that, I do know that net costs will be less if we can
make economic use of the CO2. The testimony that follows
describes how Tenaska became interested in EOR, the development status
of our project, and some thoughts on what Congress can do to advance
commercial deployment of baseload generation with carbon capture and
Challenge: Building Baseload Generation in an Uncertain Regulatory
Tenaska is one of the nation's top developers of large, efficient
power generation facilities. The Natural Resources Defense Council
ranks Tenaska as having the lowest carbon footprint of any of our
peers--less than half of the national average emission rate of
greenhouse gases. As developers, rather than researchers or inventors,
Tenaska's focus is on projects that can be accomplished with available,
reliable, cost-competitive equipment and for which development
investments can be made with a reasonable assurance of success.
Over the last several years, market conditions for development of
generation facilities have included high and volatile natural gas
prices, oversupply of natural gas generation capacity in much of the
country, financial failures of merchant generators, regional growth in
renewable energy resources, and growing demand for ``baseload''
resources, like coal and nuclear, with lower and less volatile fuel
costs and 24-hour-per-day operation. Many coal-fired facilities
advanced to some stage of development, some have been or are being
built, but many more have been postponed or canceled due to various
combinations of escalating costs, environmental opposition, utility
owner and commission concerns about long-term investment in coal, and
uncertainty about future environmental and climate change-related
Tenaska's objective has been to find ways to develop the baseload
resources that the market for electricity requires. We were reticent to
invest in solid fuel projects without addressing the climate change
issue, so a question before us was how to reduce greenhouse gas
emissions in the design of projects today. To accomplish this, we
needed to assure ourselves that carbon capture technologies were ready
for a utility-scale project; a secure home was available for captured
CO2; and the economics and long-term financing arrangements
for such projects would work.
New Coal Plants with Carbon Capture: Enhanced Oil Recovery as a
In enhanced oil recovery (EOR), Tenaska saw an attractive market
for CO2 in which geologic storage is accomplished under an
existing, federal regulatory structure. Interviews with oil producers
with EOR expertise suggested a considerable appetite for additional
supply. However, the current opportunities to meet this demand are
geographically limited, and significant barriers exist to new EOR
development. Pipelines for transporting CO2 are specialized,
high-pressure pipelines with relatively high construction costs, so the
distance between the source and the injection sites is critically
Tenaska embarked on feasibility studies to evaluate whether a coal-
fired generation facility with carbon capture capability could be
economically developed in or near the Permian Basin, where a robust EOR
market exists. We focused on coal sourced from the Powder River Basin
that would be delivered by rail. We reviewed greenfield and brownfield
pulverized coal as well as integrated gasification combined cycle
(IGCC) generation technologies, but ultimately selected supercritical
pulverized coal with amine CO2 capture technology for
Some of the well-known advantages of IGCC technology with respect
to CO2 capture efficiency are to some degree offset by
reduced efficiency of combustion turbines at the altitude of West Texas
sites. Supercritical pulverized coal technology enjoyed a relative
advantage in our analysis with respect to equipment availability, cost
certainty, reliability, industry experience, competitive procurement
and development costs. Amine-based CO2 absorber/stripper
systems have been in operation on smaller scales and represent the more
mature technology available for utility carbon capture applications.
Tenaska continues to evaluate alternative technologies, including
In October, 2007, Tenaska committed funding for engineering, site
development, and permitting of a supercritical pulverized coal facility
with carbon capture to serve the Electric Reliability Council of Texas
(ERCOT) and Permian Basin EOR markets. The ERCOT power market provides
good opportunities for a facility of the sort we are proposing. It has
a need for baseload power and the ERCOT transmission system is located
in suitable proximity to the Permian Basin, where good EOR
opportunities exist. In addition, it is a market with which Tenaska is
very familiar. We have developed approximately 3,500 MW of generation
capacity in ERCOT, and our power marketing group is headquartered
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Tenaska's Trailblazer Energy Center
On February 19, 2008, Tenaska publicly announced the Trailblazer
Energy Center, a 765 MW gross output and 600 MW net output
supercritical pulverized coal electric generation facility with the
capability to capture and deliver to the EOR markets 90 percent of
CO2 produced in the boiler. On the same day, we closed the
site property transaction, an air permit application was filed with the
Texas Commission on Environmental Quality, and a transmission
interconnect request was filed with ERCOT.
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Tenaska is fully focused on the development of Trailblazer. Our
schedule calls for completion of studies to support engineering,
procurement and construction contracting as well as issuance of key
environmental permits by the first quarter of 2009. Financial closing
and initiation of construction may be as early as the fourth quarter of
2009. Construction requires about four and half years, so commercial
operation could be as early as 2014. Currently, we are performing
technical and economic analyses of competing carbon capture
technologies and vendor offerings; transmission studies are underway;
water resource studies are in process; and intensive permitting and
site development work is ongoing.
Merits of Trailblazer include the following:
600 MW of needed baseload generation capacity to the
ERCOT electric transmission grid.
Addition of baseload power reduces marginal power prices
to the benefit of consumers across the system.
Coal-fired capacity helps insulate Texas electric
customers against natural gas price volatility.
Enhanced Oil Recovery and Carbon Sequestration
Availability of CO2 renders a greater fraction
of the original oil in place recoverable, thereby adding to recoverable
Actual production of oil is increased. If the historical
Permian Basin EOR response is used as a guide, this could mean more
than 34,000 incremental barrels of oil per day associated with
Trailblazer's 300 million cubic feet per day of CO2.
Recapture and re-injection of CO2 produced with
the oil can provide a high percentage of permanent geologic storage of
Provide 1,500 to 2,000 jobs over a lengthy construction
Create more than 100 permanent and well-paying jobs.
Stimulate the local economy with construction spending
over $2 billion and a total project cost over $3 billion
Enable $1 billion incremental Permian Basin oil production
Reduce the rate of decline of U.S. production and
dependence on imported oil.
Post-combustion capture, if successfully demonstrated on
this scale, could have a wider application. Indeed, our investigation
indicates that retrofitting existing coal stations with CO2
capture technology may have about the same cost as the addition of this
equipment to a new facility. According to the Intergovernmental Panel
on Climate Change (IPCC), there are about 5,000 large power plants
worldwide with combined emissions of over 10 billion tons of
CO2 per year.
Higher levels of sulfur dioxide (SO2) removal will likely
be needed, pushing criteria pollutant emissions control to a new level.
An opportunity is presented for recapture of flue gas
water that may enable gains in water use efficiency.
Trailblazer may also utilize air cooling or hybrid cooling
systems that further decrease water requirements.
Expanded production of oil from existing fields has less
impact than development of new fields.
Commercial Challenges Facing Trailblazer
For Trailblazer to become a commercial enterprise, there are
significant challenges to overcome. Many of the more substantive
challenges relate directly to the carbon capture and storage component.
The costs of carbon capture using existing technology scaled to
utility-sized application are daunting. The capital investment in
carbon capture could add as much as a $1 billion to a $2 billion power
plant, when financing and other ``soft'' or indirect costs are
included. There are ongoing operating costs as well. At Trailblazer,
the equivalent of 200 MWs of electricity and steam may be consumed in
the CO2 capture and compression process that otherwise would
be delivered to the ERCOT power grid.
There are other, less direct ``early-adopter'' costs associated
with introducing new technology that will affect Trailblazer. New
technologies carry inherent risk. Until the first commercial plant is
built and operated, and the risks have been quantified, each
participant in the development, construction, and financing process
will place a risk premium on their participation to cover unknown but
real contingencies. Once there is a suitable track record for
commercial utility-scale carbon capture technology, associated risks
can be assumed by those most capable of mitigating them and the risk
premium will be reduced.
Since announcing Trailblazer in February, my colleagues and I have
been busy explaining the project to local and regional stakeholders and
policymakers and also to staff and Members of Congress here in
Washington. The response has been generally very supportive, even among
groups and individuals long opposed to new additions of coal-fired
generation capacity. To maintain that support, we recognize that
continued engagement will be needed throughout the development process,
and we have much yet to do.
Impact of Federal Polices on Trailblazer
Perhaps the most important thing Congress could do to facilitate
the development of Trailblazer or similar carbon capture and storage
projects, is to provide regulatory certainty, and in particular, a
regulatory framework within which a market can develop that values
greenhouse gas emission reductions. Without regulatory certainty and
recognition of the value of emission reductions, developers are
confronted with making multibillion dollar decisions in a policy
vacuum. No developer can operate effectively while having to speculate
on regulatory outcomes, especially outcomes so fundamental to the
success of the enterprise.
Accordingly, we have developed Trailblazer in anticipation of
federal climate change legislation that would support, through placing
a price on greenhouse gas emissions and other means, the significant
capital and operating costs of carbon capture technology. Without
climate legislation, it appears that revenues from enhanced oil
recovery CO2 sales will be insufficient to cover all carbon
capture costs. With proposed climate legislation, projected compliance
cost savings and other effects of climate change legislation, combined
with EOR revenues, would provide the needed economic incentives to
build and operate Trailblazer.
Some of the potential areas where climate change legislation could
affect the project are:
Allowance allocation. Most cap-and-trade legislative
proposals include some free allocation of emission allowances for new
sources, and may include bonus allowances for generation units with
carbon capture and storage.
Auction proceeds. Cap-and-trade proposals may produce
governmental revenue by auctioning greenhouse gas emission allowances
to regulated entities. Auction proceeds may be directed to construction
of early carbon capture and storage projects or performance payments
for demonstrated sequestration.
Industry mobilization. Utility equipment manufacturers,
financial institutions and service providers would be encouraged to
bring forward competitive new offerings to address the risks and
opportunities of a large new market. To some degree, this is occurring
in advance of legislation, but is clearly a result of the industry's
sense that climate change legislation is inevitable within the next
couple of years. An interesting byproduct of our investigation of
capture technologies is that there does not appear to be an
insurmountable cost penalty for retrofit applications. This implies a
potential to apply similar technology to much of the nation's existing
Regulatory framework. Climate change legislation will
likely provide for further regulatory development to provide for the
establishment of greenhouse gas registries, industrial emission
monitoring rules, permitting, monitoring and verification of greenhouse
gas sequestration sites; and address long term liability for geologic
storage sites. Sequestration achieved through EOR needs to be
specifically recognized in such regulations. Development of the
regulatory framework is critically important.
Increased electricity price. Almost any kind of climate
change legislation will associate a cost with emissions of greenhouse
gases such as CO2. Because of compliance costs of
uncontrolled generation facilities, higher market electricity prices
can be expected.
In the past, Congress has employed a number of effective policies
to help overcome barriers to entry and encourage new energy
technologies. We support those mechanisms that provide the greatest
degree of certainty with respect to their application and that have
clearly established guidelines. We prefer investment tax credits more
than federal grants or loan guarantees primarily because the
predictability of receiving tax policy benefits is greater and more
controllable than the possibility of being awarded a grant or loan
guarantee by a federal agency. Such accounting practices as an
accelerated depreciation standard applied to the carbon capture
component of Trailblazer would facilitate faster recovery of investment
capital, and would provide a material incentive that we and our
financing counterparties could evaluate with a higher degree of
certainty. Absolving early sequestration projects from CO2
liability would similarly facilitate more enthusiastic participation by
the financial community.
Should the House decide to pursue a cap-and-trade mechanism similar
to what has been contemplated in the Senate, we would advocate for an
economy-wide approach. We would support bonus provisions for early
adopters, and for EOR to be eligible for the same level of benefits as
other CO2 sequestration mechanisms. We would prefer that
natural gas be regulated upstream from the emission source, to
encompass a greater number of emitters while regulating fewer sources,
and to avoid cost-recovery issues for entities holding long-term power
Tenaska confronts many significant challenges in its effort to take
the Trailblazer project from concept to reality. Trailblazer has been
designed in anticipation of federal climate change legislation. In the
absence of such legislation, Trailblazer faces costs and risks that
likely cannot be offset by revenues from power generation and marketing
CO2 for enhanced oil recovery. Trailblazer can wait until
federal legislation is enacted or Congress can act in other ways to
support such a project now.
Thank you again for your interest and for the opportunity to
provide some details on this exciting project. I would be pleased to
respond to any questions you may have.
Tenaska is an energy company that develops, constructs and operates
non-utility electric generation and cogeneration facilities that it
owns in partnership with other companies. The company also markets
natural gas, electric power and biofuels and provides energy risk
management services. In addition, Tenaska is involved in asset
acquisition and management, fuel supply, natural gas transportation
systems and electric transmission development. Tenaska was founded in
1987, and is a privately held company with headquarters in Omaha,
Nebraska, and regional offices in Texas, Colorado, and Alberta, Canada.
The company currently has more than 600 employees; 2007 gross operating
revenues were $11.6 billion.
Tenaska has considerable experience as a developer of electric
power generation, having built more than 9,000 megawatts of highly
efficient, state-of-the-art power generation facilities associated with
more than $10 billion in total financial transactions.
Response to questions submitted for the record by Greg Kunkel, Ph.D.,
Vice President, Environmental Affairs, Tenaska, Inc.
1. Dr. Kunkel, if your project requires a cap-and-trade system to
become economic, and you're getting revenues from selling the
carbon dioxide for EOR, does that mean that a cap-and-trade
system by itself wouldn't get companies to capture carbon
dioxide unless there was an enhanced oil recovery option?
Response: EOR should make carbon capture economic sooner than it
would be otherwise. Any of the proposed cap-and-trade systems would
have the benefit of providing a price signal that companies could use,
among other factors, to guide investment decisions related to carbon
dioxide capture facilities. Economic analyses of various cap-and-trade
proposals suggest that those price signals, particularly the implied
operating cost related to emitting each ton of carbon dioxide or other
greenhouse gas, would likely be below the level that would justify
carbon capture in the early years of cap-and-trade system
implementation. As the emissions allowed under the cap are reduced over
time, then we expect that emissions allowance pricing would eventually
justify carbon capture, based also on our current understanding of
carbon capture capital and operating costs. By 2050, when emissions
reductions of 50 to 80 percent may be required, it is clear that carbon
capture must be and would be widely implemented for generation
facilities that utilize fossil fuels.
EOR revenue has the effect of rendering carbon capture economic at
the earliest possible date. By effectively making the cost of emissions
reductions lower, EOR can reduce the costs of any cap-and-trade
In addition to the price signal provided by any cap-and-trade
system, auction of emission allowances would also provide revenues that
could be directed toward early emission reduction actions, like carbon
capture. A cap-and-trade system can also be designed to provide bonus
allowances for carbon capture. From Tenaska's perspective, such
incentives are most effective when the economic benefit is very clear,
such as a defined payment for each ton sequestered, so that any benefit
is deemed credible by investors and lenders.
Another important consideration is the general state of capture
technology. Current pilot testing and demonstration projects for new
technologies and full scale design and construction of the first
utility scale projects will reduce uncertainty in our cost estimates,
demonstrate the limits of performance of alternative capture
technologies, and pave the way for lower cost capture facilities in the
2. Dr. Kunkel, what percentage of carbon dioxide do you estimate you
will capture at your plant?
Response: Tenaska's ongoing review of carbon capture technologies
for post-combustion applications indicates that we will be able to
design a facility to achieve 85 to 90 percent capture of carbon
dioxide. We intend to capture this percentage from the entire flue gas
stream, not just a side stream as proposed in various pilot projects.
I would like to thank the Subcommittee Members and Staff for their
interest in Tenaska's Trailblazer Project and the potential for carbon
capture from power facilities to support enhanced domestic production
Mr. Costa. Thank you, Dr. Kunkel, for your very good
Our next witness is Dr. Ian Duncan, Associate Director from
the Earth and Environmental Systems, Bureau of Economy Geology
for the University of Texas at Austin. Is that correct?
Mr. Duncan. The Bureau of Economic Geology.
Mr. Costa. At the University of Texas.
Mr. Duncan. At the University of Texas at Austin. Yes, sir.
Mr. Costa. I understand you have a good school down there.
Mr. Duncan. That is the rumor.
Mr. Costa. We are glad to have you here. Please begin your
STATEMENT OF IAN DUNCAN, ASSOCIATE DIRECTOR, EARTH AND
ENVIRONMENTAL SYSTEMS, BUREAU OF ECONOMIC GEOLOGY, THE
UNIVERSITY OF TEXAS AT AUSTIN
Mr. Duncan. I appreciate the opportunity to testify. I
would first say that the Chairman has stolen most of my thunder
and made most of my points, but I will try to add a few things
to his remarks.
Mr. Costa. Good points are always worth underlining,
especially when you agree with the Chairman.
Mr. Duncan. CO2-enhanced oil recovery can impact
atmospheric CO2 levels in a significant way.
Currently, in the Permian Basin on Texas, 30 million tons a
year of CO2 are being injected into depleted
oilfields. Approximately 15 percent of this is coming from
industrial sources currently. I believe that 99 percent, give
or take half a percent, of that CO2 actually ends up
in long-term storage in the subsurface.
We have over 35 years of history of CO2
injection in the Permian Basin. And this really makes this a
real interesting laboratory to look at the effects of
CO2 in the subsurface. Several people have mentioned
leakage. Our biggest hope for understanding leakage is to look
at these longstanding floods in the Permian Basin. And it is
unfortunate that, apart from the small project that the Bureau
has running, there is very little study of this at the moment.
Government can encourage early entry capture projects. As
Tracy Evans said, this is going to be critical to get
CO2-enhanced oil recovery going based on
anthropogenic CO2. In fact, what we need to do is
transition from business-as-usual CO2 EOR to what I
would call next-generation CO2 EOR.
Business as usual is mostly using natural CO2
uses technologies that minimize CO2 usage for
historical reasons, has limited monitoring, and mostly takes
place in 80 percent of the Permian Basin of Texas, and results
in about 15 percent, give or take, additional oil recovery.
Next-generation enhanced oil recovery could be based mostly
on anthropogenic CO2, if we can get the capture,
should maximize CO2 usage using new technologies,
some of which are on the horizon, but need further research; we
will have sequestration-grade monitoring, or MMV; we will have
higher-percentage oil recoveries, and will spread out across
the country to multiple states in multiple sedimentary basins.
CO2-enhanced oil recovery can play a major role
in paying for the infrastructure that can be later used for
sequestration on a large scale in brine reservoirs.
We at the Bureau have estimated that 3.8 billion barrels of
oil are available outside the Permian Basin in Texas that could
be gained through CO2-enhanced oil recovery. We also
need more trained personnel if we are going to ramp up. We need
more graduate student research, more DOE grant funding, to
train the personnel that we need to do this.
A lot of the people in this industry are my age, and are
going to be retiring over the next five to 10 years. Personnel
is a major issue. I think we also need an aggressive research
program to help increase oil recovery as this next generation
approaches, and lower risk.
Thank you, Mr. Chairman.
[The prepared statement of Mr. Duncan follows:]
Statement of Ian Duncan, PhD, Associate Director,
Bureau of Economic Geology, University of Texas at Austin
My name is Ian Duncan. I have a PhD in Geological Sciences and I am
an Associate Director of the Bureau of Economic Geology (BEG) at the
University of Texas at Austin. The BEG is engaged in a wide range of
applied research in a broad range of energy related and environmental
issues including CO2 sequestration. The BEG's Gulf Coast
Science Center (GCCC) part of my group is an industry-academic
collaboration that has been working on geologic CO2 storage
including CO2 EOR since 1988. The GCCC currently has
significant field tests underway, one Scurry County Texas (Kinder
Morgan's SACROC CO2-EOR field) and two in Mississippi
(Denbury resources Cranfield CO2-EOR sit). These field tests
seek to how effectively CO2 injected for EOR is retained in
the subsurface, and how we can best predict and document this retention
through modeling and monitoring. These studies are funded by about $50
million in Department of Energy funds (over 10 years). For the past
nearly four years I have been doing research on the role that
CO2 Enhanced Oil Recovery (CO2-EOR) can play in
mitigating greenhouse gases in the atmosphere and in increasing
domestic oil production in the US.
The key points that I would like to make are:
(1) In the near term CO2-EOR can make a significant
contribution to mitigating increases in CO2 emissions into
the atmosphere by putting significant quantities of anthropogenic or
man-made CO2 (CO2-A) into permanent storage in
depleted oil reservoirs
(2) Government should encourage ``early-entry'' capture at power
plants and other industrial sources of CO2 emissions to
supply CO2-A for CO2-EOR projects in conjunction
with sequestration. It is critical that these projects be allowed
qualify for whatever carbon credits or offsets arise out of federal
(3) Government should provide a policy/regulatory environment that
encourages CO2 EOR operators to change business as usual by:
a) utilizing CO2-A when made available at a reasonable cost
from capture at power plants and other industrial sources; b) creating
and implementing monitoring, verification and mitigation (MMV) plans to
provide assurance of permanent sequestration; and c) conduct life cycle
analyses of their projects to measure CO2 avoided.
(4) CO2-EOR can provide the financial capacity and
rationale for developing a CO2 capture, compression and
transportation infrastructure across a significant portion of the U.S.
that can later be used for large scale CO2 sequestration in
deep brine reservoirs.
(5) In the Texas Gulf Coast alone, BEG staff have estimated that
an additional 3.8 billion barrels of oil recovery could be achieved
through CO2-EOR. This is almost twice the entire annual
domestic oil production of the U.S. at this time.
(6) Industry and University experience related to CO2-
EOR in the U.S. has provided most of the knowledge, expertise and human
capacity that will enable CO2 sequestration to be
implemented. Creating funding for CO2-EOR related research
in the Department of Energy's budget could have a significant positive
effect on knowledge creation, technological innovation and technology
transfer related to CO2 sequestration. Such funding would
also help produce young engineers and geologists trained in
CO2 injection related technologies and help alleviate a
shortage that is critical now and will grow more so in the near future.
(7) An aggressive research program including pilot projects would
help improve the performance of current EOR activity and enable the
development of new more effective approaches that could increase oil
recovery, reduce the geological and technical risks, and enhance
sequestration rates incidental to CO2-EOR.
CO2 sequestration will involve the capture anthropogenic
CO2 (typically from electric power plants) followed by deep
subsurface injection into oil and gas reservoirs, deep unmineable coal
beds or deep brine reservoirs. Approximately 80% of the CO2
injection in the world takes place in the Permian Basin of Texas and
New Mexico, making the region the largest commercial market for
CO2. Texas corporations and technical workers have a unique
experience base and outstanding safety record, in pipeline transport
and subsurface injection of CO2. Since the early 1970s,
CO2 has been injected into many Permian Basin oil reservoirs
to enhance production. Injected CO2 is dominantly produced
from natural accumulations and pipelined to the Permian Basin. In
addition, on the order of 10% is now derived from other sources such as
gas processing plants where the CO2 would otherwise have
been released to the atmosphere. Currently roughly 30 million metric
tons (MMt) of CO2 are injected annually in the Permian Basin
in operations that are closed-cycle. In other words, CO2
that is produced from the oil reservoirs in association with the
recovered oil is recycled (re-injected into the reservoir for
Many individual operations in the Permian Basin are at the scale of
CO2 production associated with coal burning power plants.
CO2-flooding for enhanced oil recovery (EOR) has been active
at SACROC in Scurry County since 1972. Kinder Morgan the current
operators at SACROC currently inject 13.5 MMt CO2/yr and
withdraw/recycle 7 MMt CO2/yr, for a net storage of 6.5
MMt CO2/yr. For comparison, a 500 MW pulverized coal power
plant produces roughly 3-4 MMt CO2/yr. This magnitude of
annual CO2 storage at SACROC is over six times the rate of
Statoil's Sleipner project offshore Norway.
The Gulf Coast has a large potential for CO2 enhanced
oil recovery (EOR) outside of the traditional area of CO2
EOR in the Permian Basin. Using the miscibility screening criteria BEG
staff have inventoried 767 oil reservoirs where miscible CO2
EOR could be applied for an additional 3.8 billion barrels of oil
recovery. By way of comparison, annual oil production in USA is about
1.86 billion barrels. This incremental production target is attractive
because of value in terms of wellhead value, tax revenue, and economic
activity. This EOR activity would lead to the use of large amounts of
CO2, however, it is small in the context of the projected 55
to 70 billion tons of CO2 emissions for the Gulf Coast over
the next 50 years. Deep brine reservoirs in the Gulf Coast have been
estimated by BEG staff to have a sequestration capacity about 4 times
this value (that is over 200 billion tons of CO2).
EOR results in storage of CO2 dissolved in residual oil,
dissolved in brine, and trapped as an immobile supercritical phase.
Experience in Permian basin EOR projects is that 30 to over 60% of the
injected CO2 is retained in the reservoir during the first
pass through the reservoir. Ultimately through recycling 99.. However,
the volume retained as a by-product of EOR is small relative to total
point source emissions. The large synergy between EOR and reducing
carbon emissions is that EOR would enable the construction of an
infrastructure linking sources to reservoirs. Very large volumes of
brine reservoirs can then be accessed beneath oil production, a concept
that we describe as stacked storage. Existence of an infrastructure
would reduce the cost of storage of Gulf Coast power plant, refinery,
and chemical plant emissions for the next 50 years or more.
The Gulf Coast of the USA is a region of high CO2
emissions that overlie thick, extensive, and well known subsurface
geologic formations. Path forward toward developing an economically
viable system for capture and storage include: (1) development of a
climate favoring construction of gasifiers using coal, lignite, petcoke
and/or biomass as sources (IGCC electric power plants for example), (2)
construction of a pipeline backbone to transport CO2
regionally, (3) a market for CO2 for EOR in areas beyond the
traditional area of use in the Permian Basin, and (4) development of
stacked storage, using deeper brine-bearing formations beneath
Sequestration credits may play a significant role in future
CO2 EOR based on anthropogenic CO2. The criteria
to qualify projects for CO2 credits are likely to evolve as
the industry matures. A recent Texas law creating a tax credit for
CO2 EOR using anthropogenic CO2 requires projects
to establish a reasonable expectation that they can meet a performance
standard of 99% retention for 1,000 years. To meet this standard,
operators will likely have to: characterize the seal for their
reservoir and demonstrate that it is compatible with this standard;
design and implement an appropriate monitoring program and complete a
CO2 life cycle analysis to verify the amount of
Up until now, CO2 purchase has been the largest cost
component of a CO2-EOR flood. As a result engineers and
geologists in companies and the Universities have developed and refined
technologies and approaches to minimize CO2 usage in
CO2-EOR projects. We may be entering a new regime in which
CO2 injection gains credits that changes the fundamental
economics. Under these circumstances new or previously little used
approaches to CO2 EOR projects such as vertical floods and
CO2 alternating with CO2 foam may become viable.
Such approaches offer great opportunities for increasing the total oil
recovery and maximizing CO2 storage. However research in
combination with full scale field test are almost certainly necessary
to convince companies of the viability of these and other ``game
Although this testimony has focused on the Gulf Coast and Permian
basin of Texas, significant CO2-EOR potential also exists in
a number of other states including Louisiana, New Mexico, Oklahoma,
Wyoming, Illinois, Michigan, California, Kansas, Mississippi, North
Dakota and others. In the context of economic growth, global oil demand
and atmospheric mitigation of CO2, a ``first step''
mechanism is required to sequester large volumes of CO2 in a
manner that later allows pure CO2 storage to initially
``piggyback'' via the commercial leverage of the oil recovered.
In summary I would leave you with the following points:
CO2-EOR can play a key role in developing the
infrastructure and the technical understanding to enable large scale
CO2 sequestration in brine reservoirs.
CO2-EOR combined with carbon capture from
power plants and other stationary sources can have a significant
positive impact on domestic oil production.
Mr. Costa. Thank you, Professor Duncan. And I look forward
to getting back to you with some questions.
Our last witness with this panel is Mr. Mark Demchuk, is
that right? Demchuk?
Mr. Demchuk. Yes, it is.
Mr. Costa. And you are the Team Leader with Weyburn of
EnCana Oil and Gas Partnership.
Mr. Demchuk. Yes.
Mr. Costa. Did I get that all right?
Mr. Demchuk. It is pretty close. Thank you, Mr. Chairman.
Mr. Costa. You may begin your testimony.
STATEMENT OF MARK DEMCHUK, TEAM LEAD, WEYBURN, ENCANA OIL AND
Mr. Demchuk. My name is Mark Demchuk, and as you said, I am
EnCana Corporation's Team Lead for our Weyburn CO2-
enhanced oil recovery project.
EnCana is a North American industry leader in
unconventional natural gas and integrated oil development. We
have significant operations in the United States, including two
refineries that we have in partnership with Conoco Phillips,
one in Illinois and one in Texas.
In 2007 our U.S. natural gas production from operations in
Wyoming, Colorado, and Texas totaled 1.3 billion cubic feet per
day. The Weyburn project is located in Saskatchewan, Canada,
and is a technology-driven business that is both Canada's
largest carbon dioxide-enhanced oil recovery project, as well
as the world's largest CO2 geological storage
I am currently responsible for all aspects of the Weyburn
business, including strategy, business development, technology,
drilling, operations, and stakeholder relations.
Last year at a hearing here in May, one of my colleagues
from EnCana also testified on the Weyburn project in front of
the Subcommittee on Energy and Mineral Resources, and the
Subcommittee on National Parks, Forests, and Public Lands. The
hearing was titled ``Geological and Terrestrial Sequestration
of CO2.'' So my testimony here today is very similar
to what she provided last year.
The geological storage of CO2 in oil zones
offers a novel win-win approach to mitigating emissions, while
enhancing production for mature oilfields. In Weyburn,
CO2 has been injected one mile underground for the
primary purpose of enhanced oil recovery since 2000, making
valuable use of a byproduct that would have otherwise been
emitted to the atmosphere from Dakota Gasification Company's
coal gasification facility located in Beulah, North Dakota.
Discovered 50 years ago, we now expect the economic
producing life of the Weyburn oilfield to be extended up to an
additional 30 years, through the use of CO2-enhanced
oil recovery. We currently produce over 28,000 barrels per day,
and the field is projected to store around 30 million metric
tons of CO2 over the life of the project. This
equates to taking about 6.7 million cars off the road for one
At present, we inject about 125 million cubic feet a day of
CO2 from Dakota Gas, and that has resulted in over
10 million tons of CO2 storage since the project
started in 2000.
The Weyburn oilfield has also served as the highly coveted
commercial-scale laboratory for the International Energy
Agency's Greenhouse Gas Weyburn-Midale CO2
Monitoring and Storage Project. The first phase of this multi-
party international research project, run under the auspices of
the IEA, concluded in 2004 that storage of CO2 in an
oilfield is viable and safe over the long term.
Through extensive geological, geophysical, and
hydrogeological work, as well as computer modeling, it
concluded that after 5,000 years, 99.8 percent of the
CO2 injected into the Weyburn field would remain
Mr. Chairman, EnCana is proud of the Weyburn project. The
project did not happen overnight. It took years of technical
analysis, substantial capital investment, a viable
CO2 supply, as well as lengthy, complicated
negotiations with our partners, CO2 supplier, and
governments. We believe that there are opportunities to conduct
similar enhanced oil recovery and storage projects in other
areas, and that deep geologic formations can be successfully
used to store CO2.
I must caution, however, that any project must be closely
monitored, and there must be a sound scientific basis
established to assure that the geologic formation being used is
adequate to store CO2. That is why we continue to
work closely with governments, researchers, and industry on the
final phase of the IEA project to enable transfer of knowledge
and technology gained in Weyburn to a more widespread
The IEA project is providing a good foundation for
development of solid policy, regulations, and operating
practices for future CO2 storage.
I thank you for allowing me to come and testify today, and
I would be glad to answer any questions you may have.
[The prepared statement of Mr. Demchuk follows:]
Statement of Mark Demchuk, Team Lead Weyburn,
EnCana Corporation, Calgary, Alberta, Canada
My name is Mark Demchuk. I am Team Lead of the Weyburn Unit for
EnCana Corporation. EnCana is a dynamic North American leader in the
production of oil and gas. I am currently responsible for all aspects
of the Weyburn Operation managing a staff of over 100 employees and
contractors split between our Weyburn field site and in the Calgary
I am here today at the invitation of the Chairman to discuss
EnCana's experience with carbon dioxide(CO2) enhanced oil
recovery and the International Energy Agency's world-class research
project at Weyburn centered on the geological storage of
The Weyburn oilfield, operated by EnCana, is demonstrating that oil
production can be increased in an environmentally responsible manner
through underground injection of CO2. CO2 has
been injected into this oilfield since 2000, making valuable use of a
by-product that would have otherwise been emitted from Dakota
Gasification Company's (DGC) coal gasification facility located in the
northern United States. The field is projected to store 30 million
tonnes of CO2 over the EOR life, equal to taking about 6.7
million cars off the road for one year. I will discuss in more depth
how EOR is prolonging the life of the Weyburn oilfield, while at the
same time contributing to reducing CO2 emissions.
The Weyburn oilfield has also served as the highly coveted,
commercial-scale laboratory for the International Energy Agency (IEA)
Green House Gas Weyburn-Midale CO2 Monitoring and Storage
Project. This multi-party, international research project, run under
the auspices of the IEA, is investigating the viability of long term
storage of CO2 in an oil reservoir and will provide a good
foundation for the development of solid policy, regulations and
operating practices for future CO2 storage associated with
EOR. The results of the first phase of the IEA project will be covered
as well as the key elements of the final phase, which was launched in
EnCana Corporation--An Overview
Headquartered in Calgary, Alberta, Canada, EnCana is a leading oil
and gas producer in North America, where the company's primary focus is
on the development of resource plays. EnCana's portfolio of long-life
resource plays includes four key resource plays in the U.S. that
produce natural gas. In Canada, five key resource plays produce natural
gas and five focus on oil, one of which is the Weyburn property.
In 2007, EnCana produced 3.6 billion cubic feet of natural gas per
day from approximately 45,000 wells across North America, in addition
to more than 134,000 barrels of oil and natural gas liquids per day.
EnCana's U.S. natural gas production averaged 1.3 billion cubic feet
per day in 2007.
On May 11, 2008, EnCana Corporation's Board of Directors
unanimously approved a proposal to split EnCana into two highly focused
energy companies--one a natural gas company with an outstanding
portfolio of early life, North American, natural gas resource plays and
the other a fully integrated oil company with industry-leading in-situ
oilsands properties and top-performing refineries, as well as an
underlying foundation of reliable oil and gas resource plays. This
transaction, which is expected to be completed in early 2009, is
designed to create two highly sustainable, independent entities, each
with an ability to pursue and achieve greater success by employing
operational strategies best suited to its unique assets and business
EnCana strives to increase the net asset value of the company for
shareholders, make efficient use of resources and minimize its
environmental footprint. The company's success is determined not only
through its bottom line but also through its behaviour. Weyburn is an
example of that commitment
Weyburn Oilfield--Enhanced Oil Recovery
Located in the southeast corner of the province of Saskatchewan in
Western Canada, Weyburn is a 180-square-kilometer (70-square-mile) oil
field discovered in 1954. It is part of the large Williston sedimentary
basin, which straddles Canada and the U.S. Production is 25- to 34-
degree API medium gravity sour crude. The reservoir is a Mississippian-
aged Midale Marly zone, a low permeability chalky dolomite overlying
the Midale Vuggy zone, a highly fractured and permeable limestone.
Water-flooding to increase oil recovery was initiated in 1964 and
significant field development, including the extensive use of
horizontal wells, was begun in 1991. In September 2000, the first phase
of a CO2 enhanced oil recovery scheme was initiated. The EOR
project is to be expanded in phases to a total of 92 patterns over the
next 15 years. The CO2 is a purchased byproduct from DGC's
synthetic fuel plant in Beulah, North Dakota. If this CO2
had not been used for EOR and stored, it would continue to have been
emitted into the atmosphere. It is transported through a 200 mile
pipeline to Weyburn then injected into the reservoir, one mile
underground. The CO2 is 95% pure and Weyburn's current take
is 6600 tonnes/day (equivalent to 125 mmscfd).
Discovered 50 years ago, we now expect the economic producing life
of the Weyburn oil field to be extended up to an additional 30 years
through the use of CO2 enhanced oil recovery It currently
produces over 28,000 bbls/d of light crude oil, the highest production
level in 30 years. Without EOR, it is estimated that current production
would have declined to 12,000-13,000 bbls/d leaving a huge resource
untapped. The environmental benefits are also significant as
CO2 storage contributes to mitigating emissions. The Weyburn
project has stored approximately 10 million tonnes of CO2 to
date and over the lifetime of the EOR project, it is projected that an
additional 20 million tonnes of CO2 will be sequestered.
IEA Green House Gas Weyburn CO2 Monitoring & Storage
The IEA Green House Gas Weyburn CO2 Monitoring & Storage
Project is a significant CO2 monitoring and storage research
and development effort that was run in parallel with the commercial
Weyburn EOR project during 2000-2004. Phase 1 of this project was
designed to contribute significantly to the understanding of greenhouse
gas management, specifically the technical feasibility and long term
fate/security of CO2 storage in geological formations.
Initiated in 2000 by the Saskatchewan Ministry of Energy and Mines
(now Saskatchewan Industry and Resources), the federal Department of
Natural Resources, and PanCanadian Energy Corporation (now EnCana), the
first $40 million phase of this multi-disciplinary project has been
endorsed by the IEA GHG Research and Development Programme. It was
managed by the Petroleum Technology Research Centre (PTRC) of
This project constitutes the largest, full-scale, in-the-field
scientific study ever conducted in the world involving carbon dioxide
storage. Weyburn has become the international flagship project on GHG
geological storage research, routinely receiving senior level business
and government visitors, as well as media, from around the globe.
The collaborative Phase One research was funded by 15 public and
private sector institutions. In addition to the two previously
mentioned government departments, other government partners included
the United States Department of Energy (US DOE), the European Union,
and the province of Alberta through the Alberta Energy Research
Institute. Industry sponsors included EnCana, BP plc, ChevronTexaco
Corp., DGC, Engineering Advancement Association of Japan, Nexen Inc.,
SaskPower, TransAlta Corporation and Total SA of France. The project
also involved 24 research and consulting organizations in Canada,
Europe and the United States.
The overall objective of Phase 1 of the project was to predict and
verify the ability of an oil reservoir to securely store and
economically contain CO2. The scope of work focused on
understanding the mechanisms of CO2 distribution and
containment within the reservoir into which the CO2 is
injected and the degree to which the CO2 can be permanently
Phase 1 results 1
Completed in 2004, Phase 1 concluded that CO2 can be
securely stored underground in an oil reservoir such as Weyburn.
Through extensive geological, geophysical and hydrogeological work, as
well as initially simplistic deterministic and stochastic
(probabilistic) performance assessment modeling, the work concluded
that after 5000 years, 99.8% of the CO2 injected into the
Weyburn field would remain trapped underground.
A key feature of the project was the pre-injection baseline
monitoring that was done prior to CO2 injection at the
field. While there are already commercial applications of
CO2 EOR in the United States, the Weyburn oilfield and the
IEA GHG project are unique, due to the comprehensive knowledge of pre-
injection reservoir conditions as a result of an extensive historical
database of geological and engineering information. This has proven
critical to following the movement of CO2 in the Weyburn
reservoir over the four years of the Phase 1 project and to the present
Excellent monitoring techniques were demonstrated through the
project; the movement of the CO2 was predicted, monitored
and verified by a variety of different methods. The greatest success
was encountered with four-dimensional time lapse seismic surveys, which
can reliably detect relatively small volumes of CO2
underground. Geochemical fluid sampling also gave good insights into
the movement of CO2 within the reservoir and could detect
any CO2 breakthrough at wells.
IEA Green House Gas Weyburn-Midale CO2 Monitoring & Storage
Phase 1 of the IEA project has provided a good foundation for the
development of solid policy, regulations and operating practices for
future CO2 storage/EOR projects; however, there is more work
to be done. The Phase 1 final report identified a number of important
gaps and recommended a follow-up ``Final Phase'' to build a technical
Best Practices Manual that outlines geological storage site selection
protocols, injection strategies, effective technologies for tracking
CO2 through various geosciences technologies, completing and
abandoning wellbores, and rigorous risk assessment strategies. Several
gaps were identified at the end of the first phase of the project that
will be addressed in the final phase project: understanding of the
aging of wellbores over decades and centuries following abandonment, a
credible peer-reviewed risk assessment approach, and a suite of cost-
effective long-term measurement and verification protocols to track
CO2 movement underground. It was clear during the initial
planning of the final phase project that information and advice could
be provided to regulators for the development of advanced regulations
based on incremental improvements of existing oil and gas regulations.
Further, measurement, monitoring and verification (MMV) protocols would
be identified during the project that would be valuable for crediting
protocols. Governments and industry alike would derive benefits from
completing the research at Weyburn through widespread knowledge and
technology transfer. Demonstration of the integrity of geological
storage at Weyburn would help to ensure public confidence in this
greenhouse gas mitigation strategy through a proactive public
communications and outreach program within the final phase project. The
final phase of the project also includes the Apache Midale
CO2-EOR operation that began CO2 injection in
late 2006. We foresee a future where Weyburn has paved the way and
future projects will not need to expend nearly as much research and
monitoring resources to be assured of safe geological storage.
Next steps: Technical
Extensive investment and effort have been expended to get to the
current level of understanding of geological storage at Weyburn but
additional work is still necessary to develop cost-effective protocols
to enable efficient site selection, design, operation, risk assessment
and monitoring of future projects.
The key gaps identified in Phase I and the measures being taken in
the Final Phase to address them and achieve win-win solutions include:
(i) Drafting of firm protocols for storage site selection.
(ii) Final selection of the most effective underground
monitoring methods for CO2 movements.
(iii) Identifying the most effective reservoir methods for
maximizing storage capacity and oil recovery.
(iv) Finalizing the development of the most cost-effective and
credible risk assessment methods and risk mitigation techniques
to ensure the integrity of the storage medium.
Next steps: Non-technical
Advancement of the technical aspects of CO2 storage is a
necessary but insufficient requirement for the management of geological
storage of CO2 on a large scale. A successful CO2
geologic storage ``industry'' must encompass a suite of technologies
linked by a network of institutions, financial systems and regulations,
along with public outreach activities, that are able to achieve broad
public understanding and acceptance. Additional work is necessary in
the following areas.
For CO2 storage to flourish, a predictable, science-
based regulatory regime needs to be in place. Fortunately, regulations
governing the injection of acid gases with a CO2 component
and other industrial applications are already in place. A complementary
regulatory framework for long term storage applications with respect to
safety and reliability may be required.
The experience from current provincial regulations on issues such
as emergency planning and protection, health and safety, and drilling
and well completion standards, as well as the fact the oil has been
kept in the geological structure for many years should prove very
helpful to future CO2 storage regulatory efforts.
Finally, a transparent registry system should be created, with
well-defined measurement protocols and verification requirements, to
ensure proper accounting for greenhouse gas reductions created by
geological storage and recognition of offset credits.
Geological Storage of CO2 is increasingly recognized as
a pragmatic way to address CO2 emissions. An effective
public outreach and consultation process could be helpful to ensure
public understanding and acceptance of geological storage as a viable
means of CO2 sequestration. The technology needs to be
communicated to the public in the context of GHG mitigation options,
with clear explanations regarding why it is safe and viable over the
Current Status--Final Phase
The initial technical research package was approved by the sponsors
in November 2006 along with a first year budget of $2.9 million
(Canadian). Several research agreements are in place with research
activities underway2. A number of agreements are pending execution. The
technical research program is being expanded in a carefully managed and
stage-gated process to ensure that results are directly applicable to
the needs of a comprehensive Best Practices Manual, regulatory and
policy advice and public outreach activities. Final phase project
activities are integrated by four theme leaders in: geological
characterization, wellbore assessment, geophysical and geochemical
CO2 tracking, and risk assessment. Semi-annual coordination
meetings are held with all researchers and sponsors to ensure
dissemination of information and research prioritization on a
continuous basis. International interest in this research project
remains strong with new industry sponsorship coming from Apache Canada,
Saudi Aramco, OMV Austria and Schlumberger. Sponsorship from the public
sector remains strong from U.S. Department of Energy (NETL), and the
Governments of Canada, Saskatchewan and Alberta. The project continues
to be endorsed by the IEA Greenhouse Gas R&D Programme, with further
endorsement coming from the Carbon Sequestration Leadership Forum since
It is EnCana's hope that the experience at Weyburn will enable the
start-up of a significant number of commercial-scale EOR-based
CO2 geological storage projects, a win-win scenario for the
economy and the environment. These projects would provide substantial
environmental benefits by enabling the geological storage of
significant quantities of CO2 that would otherwise be
emitted to the atmosphere. Ramping up development of CO2-
based EOR projects would also increase oil recovery and hence improve
energy security. Conventional methods in North America may only recover
approximately 30% of oil in place, leaving a tremendous resource in the
ground for EOR.
Although EnCana's activities have focused on EOR-based operations
and not on other storage alternatives such as deep saline aquifers or
coal bed methane, many of the operating practices so developed would be
applicable to these other storage alternatives. Furthermore, the
operating practices developed for Weyburn's geological environment
would also be transferable to other sites with different geological
characteristics. EOR projects currently represent the storage
alternative that is the closest to being economic and with the right
policy and regulatory framework, market signals and economic
conditions, a number of projects could realistically be initiated.
Finally, Weyburn, particularly the IEA GHG Project, demonstrates
the power of collaboration and partnerships between governments,
researchers and industry to unlock value through technology. The
research was valuable to EnCana as it helped the company to better
understand its oil field and to innovate (e.g. CO2
monitoring by four-dimensional seismic survey). It provided the
opportunity for a Canadian research centre to develop expertise and
potentially become a world leader in CO2 geological storage
monitoring and assessment. Finally, it has enabled government to
advance their innovation, technology and sustainability agendas.
1. Wilson M. and Monea M., IEA GHG Weyburn CO2
monitoring & storage project--Summary report 2000-2004, 7th
International Conference on Greenhouse Gas Control Technologies,
Vancouver, Canada, Sept. 5-9, 2004.
2. Knudsen, R. and Preston, C.K., Update of the IEA GHG Weyburn-
Midale CO2 Monitoring and Storage Project--Final Phase, 7th
Annual Conference on Carbon Capture and Sequestration, Pittsburgh, PA,
USA, May 5-8, 2008.
1 ADVISORY ON FUTURE-ORIENTED INFORMATION: In the
interest of providing EnCana Corporation (``EnCana'' or the
``Company'') shareholders and potential investors with information
regarding the Company and its subsidiaries and the proposed transaction
to form GasCo and IOCo and management's assessment of the Company's
future plans and operations, certain statements or information in this
document contain ``forward-looking statements'' within the meaning of
the United States Private Securities Litigation Reform Act of 1995 or
``forward-looking information'' within the meaning of applicable
Canadian securities legislation. Forward-looking statements or
information in this document include, but are not limited to,
statements with respect to: the future production potential and
ultimate recoveries from the Weyburn project; the amount of
CO2 which may be injected at Weyburn; the projected quantity
of incremental production resulting from CO2 injection and
projections for geologic storage of CO2 at Weyburn and the
potential efficacy of CO2 sequestration on climate change;
the ability of the Company to realize the long-term opportunity to
undertake large-scale carbon capture and storage; the proposed
transaction to form GasCo and IOCo and expected future attributes of
each of GasCo and IOCo following such transaction; and the anticipated
benefits of the transaction.
You are cautioned not to place undue reliance on forward-looking
information, as there can be no assurance that the plans, intentions or
expectations upon which it is based will occur. By its nature, forward-
looking information involves numerous assumptions, known and unknown
risks and uncertainties, both general and specific, that contribute to
the possibility that the predictions, forecasts, projections and other
forward-looking statements will not occur. Although the Company
believes that the expectations represented by such forward-looking
statements are reasonable, there can be no assurance that such
expectations will prove to be correct. Some of the risks and other
factors which could cause results to differ materially from those
expressed in the forward-looking statements contained in these
responses include, but are not limited to: volatility of and
assumptions regarding crude oil and natural gas prices, assumptions
based upon the Company's current guidance, fluctuations in currency and
interest rates, product supply and demand, market competition, risks
inherent in the Company's North American and foreign oil and gas and
midstream operations, risks inherent in the Company's marketing
operations, including credit risks, imprecision of reserves estimates
and estimates of recoverable quantities of oil, bitumen, natural gas
and liquids from resource plays and other sources not currently
classified as proved reserves, the ability of the Company and
ConocoPhillips to successfully manage and operate the North American
integrated heavy oil business and the ability of the parties to obtain
necessary regulatory approvals, refining and marketing margins,
potential disruption or unexpected technical difficulties in developing
new products and manufacturing processes, potential failure of new
products to achieve acceptance in the market, unexpected cost increases
or technical difficulties in constructing or modifying manufacturing or
refining facilities, unexpected difficulties in manufacturing,
transporting or refining synthetic crude oil, risks associated with
technology and the application thereof to the business of GasCo and
IOCo; the Company's ability to replace and expand oil and gas reserves,
the Company's ability to either generate sufficient cash flow from
operations to meet its current and future obligations or obtain
external sources of debt and equity capital, general economic and
business conditions, the Company's ability to enter into or renew
leases, the timing and costs of well and pipeline construction, the
Company's ability to make capital investments and the amounts of
capital investments, imprecision in estimating the timing, costs and
levels of production and drilling, the results of exploration and
development drilling, imprecision in estimates of future production
capacity, the Company's ability to secure adequate product
transportation, uncertainty in the amounts and timing of royalty
payments, imprecision in estimates of product sales, changes in
royalty, tax, environmental and other laws or regulations or the
interpretations of such laws or regulations, political and economic
conditions in the countries in which the Company operates, the risk of
war, hostilities, civil insurrection and instability affecting
countries in which the Company operates and terrorist threats, risks
associated with existing and potential future lawsuits and regulatory
actions brought against the Company, and such other risks and
uncertainties described from time to time in the Company's reports and
filings with the Canadian securities authorities and the United States
Securities and Exchange Commission. Accordingly, the Company cautions
that events or circumstances could cause actual results to differ
materially from those predicted. Statements relating to ``reserves'' or
``resources'' or ``resource potential'' are deemed to be forward-
looking statements, as they involve the implied assessment, based on
certain estimates and assumptions that the resources and reserves and
resource potential described exist in the quantities predicted or
estimated, and can be profitably produced in the future. You are
cautioned that the foregoing list of important factors is not
exhaustive. You are further cautioned not to place undue reliance on
forward-looking statements contained in these responses, which are made
as of the date hereof, and, except as required by law, the Company
undertakes no obligation to update publicly or revise any forward-
looking information, whether as a result of new information, future
events or otherwise. The forward-looking statements contained in these
responses are expressly qualified by this cautionary statement.
Response to questions submitted for the record by Mark Demchuk,
Team Lead, Weyburn Unit
Mr. Demchuk, when the firm protocols for storage site selection are
drafted, will those be just for fields where enhanced oil
recovery is taking place, or will they be broadly applicable?
We (EnCana) believe that the protocols will be most relevant to
enhanced oil recovery applications. However, there will likely be some
relevance to other storage technologies, but how applicable remains to
Mr. Costa. Thank you very much, Mr. Demchuk. For those of
you who are focused on when we may have to recess, we are told
votes will be between 11:15 and 11:30. So I suspect they will
be any time here in the next 10 minutes. We will try and see
how far we can go on the Q and A round prior to that. We
usually have 15 minutes-plus when the first roll call is
So let us begin. Mr. Demchuk, you mentioned that the
extensive pre-injection baseline monitoring and time-lapse
seismic studies at Weyburn, and Weyburn obviously is a model
that we are all looking at. Will it be necessary to include
those at other EOR sites? And are there other methods for
monitoring the carbon dioxide that may not be as costly or take
Mr. Demchuk. Well, certainly we have enjoyed and used with
great success 3-D seismic, and now 4-D seismic technology to,
first of all, baseline the reservoir conditions, and then map
and track the movement of CO2 within the reservoir
since we started injecting.
Just to distinguish the difference between 3-D and 4-D
seismic, 4-D really means time-stamped. So you take a three-
dimensional seismic picture, and you are able to time-stamp it
and follow the movement of CO2 within the reservoir.
Mr. Costa. So as you apply that 4-D in future efforts, does
it make them less costly?
Mr. Demchuk. No, price doesn't really change. We spend
about $2 million a year redoing the same seismic shoot to track
the movements of the CO2 within the reservoir.
Mr. Costa. At the end of the day, does the Weyburn project
end up storing more carbon dioxide per barrel of oil than
produced in other enhanced oil recovery projects?
Mr. Demchuk. Well, I can't really say that we are going to
store more CO2 per barrel of oil produced. We do
anticipate that at the end of the useful life of the EOR
project, we will continue to be able to store CO2 as
a straight-up CO2 storage project.
Mr. Costa. Mr. Duncan, short of putting a price on carbon,
are there specific actions you think the government should take
to really kick-start this storage effort for industrial carbon
dioxide through EOR?
Mr. Duncan. Well, I think solving the cost discrepancy that
Tracy Evans referred to, I think the other thing that we can do
is an active research program.
The understanding that we have of CO2 EOR in the
Permian Basin doesn't help us a lot once we move outside the
Permian Basin, because the geological characteristics of the
oil reservoirs are quite different. So we are going to have to
have different approaches if we want to maximize oil recovery.
Mr. Costa. One size doesn't fit all.
Mr. Duncan. Exactly.
Mr. Costa. Have you had a chance to look at any of the cap-
and-trade proposals that have been kind of percolating around
Mr. Duncan. To tell you the truth, cap-and-trade proposals
make my head hurt.
Mr. Costa. I am glad I am not the only one.
Mr. Duncan. So I try to avoid that activity.
Mr. Costa. All right, all right. What is your take on
whether or not this issue is, as carbon dioxide is defined, as
a waste or a commodity?
Mr. Duncan. It is an issue that I don't find terribly
exciting. I think the important thing is that we clear the way
to increasing CO2 EOR. I don't find those kind of
legal nitpickings particularly exciting.
I think if there is clear legislation on the Federal level,
that it will clear away any uncertainties related to
terminology and semantics.
Mr. Costa. This question is for everyone on the panel, and
you will have to be brief because my time is going.
The Department of Interior recently concluded tax policies
and grants focused on research and development. Some of you
indicated in your testimony that in terms of enhanced oil
recovery, it would be more effective in terms of royalty
relief. Do you agree with that? And can anyone tell me what you
think the current price of carbon dioxide is, and how closely
that is related to the price of oil?
Mr. Roby, let us begin with yourself.
Mr. Roby. We have various pricing for CO2 based
on the long-term contracts that we have had. Some do slide with
the price of oil. So yes, the price of CO2 is a
function of oil price.
Mr. Costa. And in terms of royalty relief for produced oil?
Mr. Roby. Would you repeat the question, Chairman?
Mr. Costa. The conclusion that tax policies and grants, and
I think you said it in your statement, you would rather have
royalty relief than grants. Is that correct?
Mr. Roby. Right, right. As you know, CO2
projects are a long-term project. The price of oil is certainly
an uncertainty. We would like to be able to put as much
certainty in there as we could. Royalty relief we think would
Mr. Costa. Yes. Quickly, since everything is local, you
have a plant in my area that you are developing, Occidental is,
for enhanced oil recovery. Could you tell us more about that
Mr. Roby. Well, we are in negotiations, and there is
ongoing discussions for a plant out there. It is just in the
discussion stage; things are being negotiated and talked about.
There has been a public release by the parties involved in it.
We are talking to other companies, as well, so that is just
one of several that we are just in the talk----
Mr. Costa. I will get additional information from you later
on. My time has expired, and therefore so has everybody else's.
But we will get to a second round here, because we have I think
a lot of questions.
The gentleman from New Mexico, the Ranking Member, Mr.
Mr. Pearce. Thank you, Mr. Chairman.
Mr. Costa. And after, I think, when you complete your
questions, we will probably have to go and vote. I assume the
roll call has started?
OK. Go ahead, Mr. Pearce.
Mr. Pearce. Mr. Roby, on the whole idea of using
CO2 as sequestration, is this an activity that a
startup firm could be involved in? In other words, I am trying
to get an idea of the magnitude of experience necessary. So
could we just say a power company built a plant, and then start
pumping CO2 down in the ground right there where it
Give me just a brief answer about that.
Mr. Roby. As you know, it is very complex. It is very
costly. Injecting CO2 in the ground takes huge
And so to answer your question, I would say no, it is not
for a small startup company. It takes a company with a long-
term perspective. It is costly, and, you know, with it being
costly, it does take experts to understand the implications of
where the CO2 is going, the correct monitoring, and
the correct processing.
Mr. Pearce. We will have the staff hold the chart up here.
What I am saying here is there is some field there, looks like
in west Texas, eastern New Mexico, where I live and we made,
our business was there. So I am seeing a curve, the green
curves show the amount of oil that comes. But I am seeing
constant, constant redrilling and then in-in-filling of the
field to create that high peak of oil that we get.
But then we see that the oil that is retrieved against the
decline out here. Where we put the red graph on, that is where
you begin to inject and do more in-filling. And so the only way
we are able to extend the life of that field is through this
enhanced oil recovery. But that enhanced oil recovery is,
percentage-wise, still a very kind of small portion of the
total field. Is that a correct----
Mr. Roby. That is correct. In fact, that appears to be for
the entire Permian Basin. And that is right. It looks like we
have all water flood primary and secondary recovery there.
And the CO2 recovery, though it is extremely
valuable to extend the reserves, it is, just makes a small
percentage. We talked about today 15 percent recovery. So most
of the recovery is going to be from primary and secondary.
This is, it is not a silver bullet. It is helpful, but it
will not solve all the problems that we have with energy.
Mr. Pearce. Now, I have heard speculation that there is
currently legislation that is being drafted to just shut off
the natural sources of CO2. What effects would that
have on this field, and employment, the output, if we had
legislation that just stopped the natural-occurring sources of
Mr. Roby. It would be devastating. In short, CO2
production is significant in the Permian Basin. There is quite
a bit looking in other parts of the country. If we shut down
using natural-occurring CO2, as talked about with
the immature capturing CO2 from industrial
locations, and without the infrastructure, we would shut down a
tremendous amount of oil production in the United States. And
unemployment would be significant in your home state, as well
as west Texas.
Mr. Pearce. Mr. Demchuk, your observations on the same
Mr. Demchuk. Well, from a production perspective, I didn't
bring it, but I have a very similar chart that shows the
production of the Weyburn field, which is 50 years old. And, as
Mr. Roby described, the bulk of our production will have come
from primary production and water flood, and we are simply
extending the life of the field and increasing our production
in the neighborhood of about----
Mr. Pearce. So if we lost the source of naturally occurring
CO2 and mandated only carbon sequestration sources.
Mr. Demchuk. Well, actually, for us it would make no
difference, because we use manmade CO2 from a coal
Mr. Pearce. And even in your U.S. operation--you have U.S.
Mr. Demchuk. Not on the EOR side of the business. Our U.S.
operations are primarily gas production.
Mr. Pearce. Mr. Duncan, do you have any idea about how long
it would be before we really are able to seriously harvest
CO2 in the United States for enhanced oil recovery?
Just a number of years. Just a guess is fine.
Mr. Duncan. Well, I can give you more than a guess. If you
started a project now, probably five to seven years to build
capture plans. And I asked some people in Kinder Morgan how
long they thought it would take to bring in, and they said four
to seven years, so that is sort of consistent.
Mr. Pearce. OK. Mr. Chairman, I see my time has elapsed. I
have more questions. We will wait until the second round, and I
know we have to go. Thanks.
Mr. Costa. Thank you very much, Mr. Pearce. I would advise
those on the second panel and those in the audience, we will be
gone for at least half an hour. So my best guess is that we
will begin probably some time after 12:10, 12:15. So if you
have an opportunity, want to get a cup of coffee or use the
facilities, or whatever.
But I know there is interest by the gentleman from New
Mexico and myself, and we will have a second round of
questions. And so we will see you in about half an hour. Thank
The Subcommittee is now in recess.
Mr. Costa. All right. I think we have our panel back. It
took a little longer than we had anticipated. I apologize for
that. But we are going to try to get in another round here with
the members that are here, and we will bring this to a close.
I think we ended with the gentleman from New Mexico, Mr.
Pearce's questioning, and so I will start off here on the
Mr. Evans, what are you doing that is feasible offshore? We
know that production rates have declined, especially on the
shallower wells offshore of the Gulf. So could this technique
be used there?
Mr. Evans. Mr. Chairman, Denbury is currently not doing
anything offshore, but there is no technical reasons why you
can't do CO2 EOR offshore. It becomes more of an
economic issue of taking the CO2 offshore. And
generally in the offshore environment, the costs just go up to
do the same thing that you are doing onshore.
But there is no technical reason why you can't do
CO2 EOR offshore.
Mr. Costa. You talked about, and Mr. Pearce pointed out the
issue with the pipelines, and we understand that access is
important, if there was a change in the tax code that would
provide incentives, do you think there would be much investment
in the private sector to deal with the pipeline, the
Mr. Evans. I think there would be a great deal of interest
in building more pipelines for CO2. Most of your
pipeline operators, what they want to really have assurance of
is that there is going to be throughput through that pipeline.
So not only would it encourage investment, but it would
also lower the total cost of, delivery cost of anthropogenic or
manmade CO2, as well.
Mr. Costa. You also mentioned, I guess, in your comments
about the tax credit for the CO2 EOR that was almost
enacted last year. Do you think that is enough to incentify the
construction for pipelines?
Mr. Evans. Well, the tax credit actually is for the capture
of the CO2, not necessarily the pipelines. The issue
that we see is, as Denbury is, the actual oil and gas companies
can build or pay for, in terms of CO2 costs, most of
the pipeline infrastructure. And we can only cover a portion of
the capture costs, depending on which source it is coming from.
Obviously the lowest capture cost we believe is future
gasification projects. And as you go up from there, then we can
only cover a lesser and lesser amount.
Mr. Costa. OK. Mr. Roby, and I guess maybe Mr. Evans, do
either of your companies have plans for converting your fields
to storage at the end of the EOR operations? And what would be
the legal or regulatory or financial impediments if you did so?
Let me start with Mr. Roby.
Mr. Roby. As far as plans, we don't have plans at this
point in time. However, we do recognize that after we inject
quite a bit of CO2 in these fields, that the
CO2 will stay there. So the natural process does
We also recognize that CO2 is quite a commodity.
And if we can take that CO2 in a field that has used
it, and we depleted the oil resource from that field, we would
then take it to another field.
So since we have invested tremendous millions of dollars
for the CO2, we are going to try to have that
contacting as much oil as possible.
Mr. Costa. Well, with that statement made, where do you see
this EOR effort going in the next 10 or 20 years from
Mr. Roby. We are excited about CO2 flooding, as
we have been in the past. We want to continue to grow it. We
want to continue to put CO2 flooding in the Permian
As you know, we have looked at other areas of the country,
and we are currently investigating that. We hope that it will
grow into other regions beyond the Permian Basin. And in the
fields that have not been taking CO2 we are
continually growing that, and we plan to continue to do so.
Mr. Costa. Mr. Evans?
Mr. Evans. We don't currently have that necessarily in our
business model. We are going to also continue to expand. We are
planning now with the three contracts to take anthropogenic
volumes of CO2, so we are going to sequester through
EOR. But taking those fields beyond the EOR, we have not put
that in our business model.
We are aware that a lot of our oilfields are sitting right
in amongst saline reservoirs, as well, and so we are cognizant
of that. And we fully expect our pipelines, once EOR is over,
to be able to be utilized for the transportation of manmade for
The second part of your question was the impediments. I
think the biggest impediment right now is determining legally
who owns the pore space.
Mr. Costa. Who owns the----
Mr. Evans. The pore space, where the CO2 will be
captured. There is no clarity on that issue yet. I know several
states have been working on that, and right now they are not
necessarily in agreement, either. So that is probably the
biggest impediment. Access to land, and then who owns that pore
Mr. Costa. Dr. Kunkel, you mentioned you effectively need a
cap-and-trade system to make your project economic. Is there a
price for carbon dioxide that would make it economic? Or would
you say there is another way of partnering with oil producers?
Mr. Kunkel. Well, a price for carbon dioxide is necessary.
You know, the exact price also depends on a lot of other
varying commodity prices, such as electricity market prices in
Texas, coal price, and so on.
But if there was a market price of CO2 emission
reduction of $20 to $25, it would start to look very good for
Mr. Costa. OK, my time has expired. The gentleman from New
Mexico, Mr. Pearce.
Oh, I am sorry.
Mr. Sali. Mr. Chairman, you missed me on the first round.
Mr. Costa. No, I know, and I am going to do my mea culpas
Mr. Sali. How would you like to handle that? I can take 10
minutes on the second round, or I can go now and take up my
Mr. Costa. Why don't we alternate, Mr. Scalise? I am sorry,
Mr. Sali. You want me to go now? I am sorry.
Mr. Costa. Yes.
Mr. Sali. OK. Mr. Roby, you mentioned in your testimony I
think that Occidental has been involved in enhanced oil
recovery for 30 years. In addition to carbon dioxide injection,
what other types of enhanced oil recovery has your company been
Mr. Roby. We were active in steam flooding in the United
States, and also in the Mid-East. We are currently putting in
those first large commercial steam flood in the Mid-East; it is
a very large project in Oman.
We are also looking at chemical flooding in the domestic
arena, both in Texas and California, as well as we are looking
in Latin America and in the Mid-East. So we are actually active
in EOR projects in the three areas that we operate, which is
Mid-East, North Africa, Latin America, and the United States.
Mr. Sali. Now, with respect to the total enhanced oil
recovery efforts that your company is involved in, what
percentage of that is from carbon dioxide injection? Just
Mr. Roby. A third. It is about--no, that is too high. It is
about 20 percent for CO2.
Mr. Sali. Is it fair to say that you anticipate this will
be a growing area? Or other types of enhanced oil recovery
would grow with that? Or what do you see for the future?
Mr. Roby. We see it as growth. Will it grow on a percentage
basis on CO2? I am unsure about that, because we
want to grow in other areas where we are not putting in
I will tell you that we are looking at putting in
CO2 floods in other continents, as well. But we do
believe ultimate production will grow through CO2.
Mr. Sali. As we look, I am reminded of the chart that was
shown a little earlier. It looks like in the Permian Basin,
there is a declining amount of recovery that is going to come
from that basin, total recovery.
Mr. Roby. Right. Yes, sir.
Mr. Sali. When we talk about enhanced oil recovery using
CO2 injection, what percentage of the total crude
oil needs for the United States will that produce?
Mr. Roby. Well, let me quantify. CO2 production
in the Permian Basin is in the tune of about 200,000 barrels a
day. And I believe your question is what percent of that is the
total domestic production?
Mr. Sali. I am actually looking at the feasibility of
carbon dioxide injection and the recovery that we will get from
that, not just from your company, but other companies. Do you
have any kind of a guess about what percentage of our energy
needs going forward we can rely on from this?
Mr. Roby. In opening comments by the Chairman, it was said
that there is no silver bullet. I agree with that completely.
This will help. I believe that we can, you can hope to get
in the tune of 15 percent to 20 percent recovery from
CO2. There is, by no means every reservoir is
capable of producing CO2. I do believe that there is
many reservoirs in the Gulf of Mexico that aren't floodable by
CO2, just due to gravity override. The permeability
and the precocity is such that the testing that has been done
in some areas shows that CO2 will actually rise to
the top, so in fact it was not a very good formation for
producing CO2, or for using CO2 to
So as a result of that, I think it is a little helpful, but
in the tune of--and this is an educated estimate--a small
percent, let us say 10 percent, in that tune.
Mr. Sali. You think that we could have as much as 10
percent of the total production for the United States----
Mr. Roby. Oh, no. Oh, no, not in total. What I mean is that
if you look at floodable areas, you could potentially recover
10 percent. But if you look at that in the, in total of
floodable fields, it is a smaller percent than that. Because
again, there is many fields that you can't put CO2
in; it is just not amenable to this process.
Mr. Sali. Here is what I am trying to get at. If we are
going to look forward and meet the energy needs of this
country, to what extent can we rely on CO2
injection? To what extent are we going to have to rely on new
production exploration to give us new production in areas where
we aren't today? How does this fit in that puzzle?
Mr. Roby. We are going to have to have new primary
production and water flood production. There is no question
about that. CO2 will help, but again, it is not
going to be the savior. It is going to help.
Quantification, we have 200,000 in today. You could double
that, say 400,000, wildly. That is still just 10 percent of
total production in the United States. But clearly below what
our consumption is.
Mr. Sali. Thank you. Thank you, Mr. Chairman.
Mr. Costa. I thank the gentleman from Idaho. And again, I
was not intentioned to avoid your time there.
Mr. Sali. That is fine.
Mr. Costa. I try to be fair.
Mr. Sali. All right.
Mr. Costa. Mr. Evans, what kind of plants are you getting
your industrial carbon dioxide from?
Mr. Evans. We plan to get it from three basic plants. One
is a coal-to-liquids plant, one is a pepcoke-to-ammonia plant,
and the other is more than likely going to be pepcoke to a
combination of ammonia and methiodal.
Mr. Costa. How much more expensive is the natural gas than
the carbon dioxide pipeline?
Mr. Evans. How much is the manmade CO2, or
Mr. Costa. How much more expensive is natural gas?
Mr. Evans. Well, natural gas is about $12 per NCF. You
know, manmade CO2 is probably going to be in the
neighborhood of, you know, depending on negotiations, somewhere
between a dollar and two dollars.
Are you talking about natural CO2?
Mr. Costa. Yes. I am sorry, I don't think I was clear on my
question. I am talking about the price of the pipeline.
Mr. Evans. Oh, the price of the pipeline? Oh. On a per-inch
mile, generally the prices won't be that much different on the
pipelines. The big difference between pipelines is we have a
heavier grade of steel, because we generally operate
CO2 at 2200 psi or greater, where a natural gas
pipeline would be 1200.
So what you would see is a slightly higher price for the
actual pipe, but the construction would be closer than that. My
best estimate would be probably in the neighborhood of 15
percent to 20 percent more.
Mr. Costa. OK. Dr. Kunkel, are you working closely with the
Department of Energy on attempting to, with the new plan, I
think we had a description in your submitted testimony, in
terms of funding for the captured portion of the plant you
Mr. Kunkel. We have submitted information about our project
in response to the recent information request that they have
about various carbon-capture and gasification types of
projects. And so they have our information; they know of our
interests, and we are aware of their interests. They have a
process going forward which may take some time.
Mr. Costa. Will you still build your plant if you don't
have the capture piece?
Mr. Kunkel. We do not intend to build a plant without the
capture piece. We see it as, you know, part and parcel of this
Mr. Costa. All right. Professor, you clearly have been in
the field for a number of years. Where do you see this all
going in terms of the potential? I mean, we are trying to
combine challenges here that we have with CO2
levels, we are trying to obviously enhance our oil and gas
recovery. We are in an energy crisis. I think a number of us
have made the comment that there is no silver bullet. I think
that is true, there is no silver bullet.
I guess the policy debate we are having here in Washington
is what is the proper mix between additional domestic sources,
both onshore and offshore, enhancing our older fields, and
dealing with other alternative forms of energy.
Where do you, in terms of your focus, where do you stand
down there at Texas University?
Mr. Duncan. In terms of my personal focus, I agree with Mr.
Roby about the fact that CO2 EOR is not going to
have a huge impact on domestic oil production. It can have a
very meaningful impact, but it is not going to turn the ship
However, it can have a meaningful, a really meaningful
impact in terms of CO2 sequestration. It can play a
significant role. It can also play a very significant role in
developing the infrastructure that can later be used for brine
Mr. Costa. The infrastructure part I get. But in terms of
the significant role of the capture, how do you describe a
significant impact? I mean, what in your mind constitutes, I
guess, a significant impact?
Mr. Duncan. Well, I think a significant impact would be if
you look at the Princeton people's wedge idea of tackling the
CO2 problem, if you could capture 10 percent of the
CO2, or 20 percent say in the Gulf Coast and the
other oil-producing areas as susceptible for CO2
EOR, I think that would be a big chunk of a U.S. contribution
toward a carbon-constrained world.
Mr. Costa. And then that technology would be applicable in
other parts of the world.
Mr. Duncan. Exactly, yes. As a matter of fact, if
CO2 sequestration is going to occur anywhere in the
world, it is basically going to take place with technology
developed in the U.S., in the Gulf Coast, in Texas. And it is
going to require expertise from those people who have been
doing CO2 injections for the past 35 years or so.
Mr. Costa. And we have the expertise here.
Mr. Duncan. We have the expertise. We have the knowledge,
we have the understanding. We need more of it, but we have a
lot of it.
Mr. Costa. All right. My time has expired. The gentleman
from New Mexico, Mr. Pearce.
Mr. Pearce. Thank you, Mr. Chairman. Mr. Roby, how much
would the price of gas go up, gasoline at the pump go up if we
were to shut off naturally occurring sources of CO2
today? And I worry about that. I listened with extreme concern
as Maxine Waters described the process where the government
might take over and run the oil companies. And so I really have
great fears about what the intent of the majority is.
So what would be the cost? What would happen to the price
of gasoline, in your estimation?
Mr. Roby. Well, Occidental is not in the refining and
marketing business, so we have no, so we don't have an arm of
However, you mentioned in my estimation. I just know that
the price is a function of supply and demand of the base
product, and the supply of crude would go down. As I mentioned
early in my remarks, I believe not using naturally occurring
CO2 would be devastating. And we could easily pull
out 200,000 barrels a day from the Permian Basin, and potential
growth beyond this.
So all I can tell you is directionally, it would go up. And
I think it would certainly not be good for the energy of this
Mr. Pearce. You have heard Mr. Evans's optimistic view
about the investment that would be attracted by the, toward the
building of pipelines. Do you anticipate that the building of
any carbon dioxide-transmitting pipelines might be met with
protests and with litigation?
Yesterday I think one of the Circuit Courts handed down a
decision that a refinery can't be built, so again we have made
another decision not to build refineries in this country
yesterday. Do you think there would be any objections by groups
that don't want these pipelines built?
Mr. Roby. There will always--yes.
Mr. Pearce. Yes. And how far along would you think that we,
to get a series of pipelines across the country that would feed
all of the, all of the fields that are hospitable to
CO2 injection, would you take a guess at how long it
would take to get all that infrastructure through the courts
and through the processes?
Mr. Roby. It would be enormous. It has taken us decades to
get to where we are today with natural gas. Permitting process
is taking longer today than it was a decade ago.
I would venture to speculate that we are looking at 20-ish
Mr. Pearce. Twenty years. Mr. Evans, would that dampen down
the enthusiasm, all these people lined up to build these
pipelines? Do you think they will keep their money on the
docket for 20 years while they are waiting for the process?
Mr. Roby. Well, I think, of course, we will----
Mr. Pearce. I am asking Mr. Evans. Excuse me.
Mr. Evans. Well, I think in order to build, you know,
500,000 miles in infrastructure, you say that would take 20
years. Individual pipelines in all producing regions, we don't
see a lot of protests. We have not seen----
Mr. Pearce. OK, but we are talking about building
infrastructure across the entire country. And we are talking
about significantly affecting the CO2 that is
available. And so yes, I know your situation is just from
Sweetwater to the field.
Mr. Evans. Right.
Mr. Pearce. But I am asking a generalized question.
Mr. Evans. Well, yes. People will invest in these pipelines
as long as they are assured that they are going to be able to
get put in.
Mr. Pearce. Yes, they are not going to leave their money
sitting on the table.
Mr. Evans. Well, it won't be sitting on the table. It took
almost 50 years to build the infrastructure we have today, but
that is built out as you build volume.
So yes, we will face protests. We may or may not need
eminent domain. But those kind of things can all be addressed.
Mr. Pearce. And by the way, we just had a hearing here a
couple weeks ago where people are protesting the corridors; we
set up corridors in the 2005 Energy Policy Act to convey
different forms of energy. And the protests are occurring that
will probably stop that entire project. So I am just trying to
keep our feet on the ground here, as we look with enthusiasm.
Mr. Evans, let us say that we do withdraw the naturally
occurring sources of CO2, and we see, say, a five-
time increase in the price of carbon, would your company still
do a CO2 injection with a five-time increase?
Mr. Evans. Well, five times increase from where our
Mr. Pearce. An increase in the cost.
Mr. Evans. Well, we probably would, because our
CO2 cost right now is very, very low. So five times
our cost, we could still do it.
I don't think people in the Permian Basin and Rocky
Mountains probably could accept that kind of increase.
Mr. Pearce. Your project is based on Mr. Kunkel's building
of his project, and his project is dependent on legislation.
The European countries are finding that cap-and-trade is just
too expensive. I think that might be what caused Mr. Duncan's
head to hurt about it, that the European countries are backing
away from it.
What are you going to do in your project if Mr. Kunkel
doesn't build his? Are you still going to go ahead with your
project to put CO2 in the ground?
Mr. Evans. Well, our primary focus is not power.
Unfortunately, their costs are very, very high, especially for
power not generated by gasification.
Mr. Pearce. That is not my question. My question is, are
you going to keep on the project if Mr. Kunkel doesn't build
his project? Are you going to stay on your project?
Mr. Evans. Well, not if I was only tied to his project.
Mr. Pearce. But that is my question. You are so tied to it
that you will not, is that my understanding?
Mr. Evans. No, sir. Actually, Denbury and Tenaska are not
tied together at all. In fact, we are not working on that
project with them.
If that was a similar project in our area of the country,
and that was our only choice of CO2, no, that would,
his price of CO2 would not be economical for us to
Mr. Pearce. All right, Mr. Chairman. I have a lot to think
about, I think. Thanks. I appreciate it.
Mr. Costa. Thank you for your good questions, as always.
Members of the panel, thank you for your patience. I am sorry
that we had to have a break.
Mr. Pearce. Wait, I am going to have unanimous consent to--
Mr. Costa. OK. And obviously this is an issue that has a
great deal of interest, and your testimony is focused on that.
And we will continue to work with you as we try to chart a
course that can continue this effort that I think has a lot of
potential benefit to our country's energy needs.
Mr. Pearce. OK. We have a report from the Department of
Energy about enhanced oil recovery. I would like unanimous
consent to submit that.
Mr. Costa. Without objection.
Mr. Pearce. And additionally, an editorial from yesterday's
Investor's Business Daily, American Energy Production. I am
requesting unanimous consent to submit that for the record.
Mr. Costa. Without objection.
[NOTE: The article submitted for the record has been
retained in the Committee's official files.]
Mr. Costa. Anyway, once again, I thank the members of the
Committee. Thanks to the staff. And I apologize for the way the
hearing got elongated today. But your expertise and your
information is very valuable, as we look at the policy
considerations that we have to consider as we pursue hopefully
that bipartisan energy policy that I think is in the best
interest for all of America, given the energy crisis we are
This hearing is now adjourned.
[Whereupon, at 1:04 p.m., the Subcommittee was adjourned.]
[Additional material submitted for the record follows:]
[A statement submitted for the record by George Peridas,
Ph.D., Science Fellow, Climate Center, Natural Resources
Defense Council, follows:]
Statement of George Peridas, Ph.D., Science Fellow,
Climate Center, Natural Resources Defense Council
We thank the House Natural Resources Committee, Subcommittee on
Energy and Mineral Resources for the opportunity to submit written
testimony for its June 12th, 2008 oversight hearing on ``Spinning Straw
Into Black Gold: Enhanced Oil Recovery Using Carbon Dioxide''. 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 D.C., San Francisco, Los Angeles, Chicago and Beijing.
The Subcommittee's examination of the topic of Enhanced Oil
Recovery using Carbon Dioxide (CO2-EOR) is extremely
topical. The United States are faced with two related challenges that
demand prompt action: energy independence and climate change.
First, we must ensure that our nation can meet its energy needs
securely, affordably and efficiently, without being subject to world
energy price shocks or relying on unstable regions for its fuel
Second, as the developed world's largest greenhouse gas emitter--
and until very recently the world's largest emitter 1--we
must also take prompt action to reduce these emissions substantially in
order to avoid the worst effects of climate change on this country and
the rest of the planet, as well as the significant costs associated
with it, which will be significant for many regions of the country.
\1\ Estimates indicate that China surpassed the U.S. in emissions
CO2-EOR offers an opportunity to take positive action on
both challenges by making use of an untapped domestic oil resource
without the worst impacts of other production methods or proposals,
while permanently sequestering CO2 from anthropogenic
sources underground. To put the opportunity in perspective, a recently
updated survey of the CO2-EOR potential in the United States
prepared for the U.S. Department of Energy estimates that as much as 48
billion barrels of ``stranded oil'' from existing fields--more than
double the approximately 22 billion barrels of proven U.S. reserves--
would be economical to produce at recent years' high oil prices.
2 At $100/barrel, that amounts to $4.8 trillion tied to
domestic oil reserves that would create a multi-decade market for more
than 11.5 billion tons of CO2, almost all of which will need
to come from industrial sources that otherwise would be emitted to the
\2\ ``Storing CO2 with Enhanced Oil Recovery'', DOE/
NETL-402/1312/02-07-08, February 2008.
In our view, the urgent challenges of our national and global
dependence on oil and escalating global warming pollution both demand
rapid investment in efficiency and cleaner sources of energy. NRDC also
believes that carbon capture and geologic storage from coal-fired power
plants and other large industrial sources will be necessary to achieve
the deep emission reductions that will be needed. We believe that
CO2-EOR, implemented with the appropriate measures to ensure
long-term geologic sequestration, provides a very significant
opportunity to advance carbon capture and storage, reduce industrial
emissions and to sustain domestic oil projection without drilling in
environmentally sensitive areas.
Our oil addiction
In his 2006 State of the Union address, President Bush famously
admitted that America is addicted to oil. Indeed, the U.S. consumes oil
at an astonishing rate of roughly 21 million barrels/day or a quarter
of the oil produced globally, 70% of which is used in the
transportation sector. According to the DOE-EIA Annual Energy Outlook,
we import twice as much oil as we produce domestically, meaning that a
staggering two-thirds of our oil is imported. Domestic oil production
has been dropping steadily since the 1970s as the figure below shows,
and the nation's dependence on imported oil is project to increase
steadily according to the EIA. Depending so heavily on an imported
resource so crucial to the economy is without question unwise--and the
policy decisions that will affect whether this will be the case are
being made today.
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Until recently, the nation had grown complacent about oil use.
The price of oil remained under $20/barrel in nominal terms for much of
the 1990s, creating an illusion of an inexpensive commodity. Since 2002
however, oil prices have been climbing ever upwards, surging to almost
$140/barrel in June 2008. It is clear that the era of cheap oil--and
cheap fossil fuels more generally for that matter--is over in all
likelihood. With strong demand in the developed world and an ever-
increasing pressure coming from the developing countries, a world of
high or rising oil prices is a distinct possibility and one predicted
by several analysts.
The economic impacts of the recent surges are being felt worst of
all by the poorest families and communities. Yet high prices have not
slowed us down. Even in the context of sustained high oil prices in the
last five years, fuel use trends remain largely unchanged, and our
transportation fuel demand continues to rise relentlessly. Only now is
evidence emerging that consumers are turning to more fuel-efficient
vehicles and away from ``gas-guzzlers'', an effect that is making
automakers resort to plant closures and shift their fleet to the kind
of vehicle that ought to have been the obvious choice and the correct
business decision long ago.
It does not take an expert to work out that our current path is
unwise from an economic point of view, from a national security point
of view, or from an environmental point of view.
A changing climate
Alongside surging oil prices and demand, the planet's climate is
changing fast. Greenhouse gas emissions from the use of fossil fuels,
mainly CO2, are having a profound effect on our planet,
presenting us with one of the most significant environmental and social
challenges of the century.
In its most recent Assessment Report last year, the
Intergovernmental Panel on Climate Change, an independent scientific
body, issued the loudest warning to date, calling the warming in the
climate system ``unequivocal'' and calling for serious emission
reductions if we are to avoid truly dangerous greenhouse gas
concentrations. Failure to pursue significant reductions in greenhouse
gas emissions very soon will make the job much harder in the future--
both the job of stabilizing atmospheric pollution concentrations and
the job of avoiding the worst impacts of climate chaos.
A growing body of scientific research indicates that we face
extreme dangers to human health, economic well-being, and the
ecosystems on which we depend if global average temperatures are
allowed to increase by more than 2 degrees Fahrenheit from today's
levels. We have good prospects of staying below this temperature
increase if atmospheric concentrations of CO2 and other
global warming gases are kept from exceeding 450 ppm (parts per
million) CO2-equivalent and then rapidly reduced. To make
this possible requires immediate steps to reduce global emissions over
the next several decades, including action to halt U.S. emissions
growth within the next few years and then cut emissions by
approximately 80% by mid-century. This goal is ambitious, but
achievable. It can be done through an annual rate of emissions
reductions that ramps up to about a 4% reduction per year. Fortunately,
a wide variety of tools is available today to achieve those
reductions--but we will need all the tools at our disposal. One such
tool is Carbon Capture & Sequestration (CCS).
Carbon capture & sequestration (CCS)
Given the world's and the nation's dependence on fossil fuels, it
is essential to have in place a technology and a strategy to reduce
greenhouse gas emissions from large industrial facilities that burn
these fuels, even though their complete phase-out through energy
efficiency improvements and a transition to renewable fuel sources
might be technically and theoretically possible. Using all available
tools is a wise and necessary hedging strategy in the face of the steep
emission cuts that are needed. Projections differ as to the exact
portion of reductions that will be delivered by different technologies,
but from a strategic point of view, CCS provides a much needed answer
for fossil fuel use--which is inevitable.
Coal by itself, the most carbon-intensive of fossil fuels presents
the biggest climate challenge. Since the dawn of the industrial age,
human use of coal has released about 150 billion metric tons of carbon
into the atmosphere--about half the total carbon emissions due to
fossil fuel use in human history. Another 4 trillion metric tons of
carbon are contained in the remaining global coal resources. That is a
carbon pool nearly seven times greater than the amount in our pre-
industrial atmosphere. Using that coal without capturing and disposing
of its carbon means a climate catastrophe. And the die is being cast
for that catastrophe today, not decades from now. According to the
International Energy Agency, over 1800 GW of new coal plants will be
built between now and 2030, a capacity equivalent to 3000 large coal
plants, or an average of ten new coal plants every month for the next
quarter century. This new capacity amounts to 1.5 times the total of
all the coal plants operating in the world today.
Continuing with the use of coal without capturing and sequestering
is fundamentally incompatible with climate stabilization. NRDC believes
that CCS technology is available to us today to begin deployment.
Research on CCS has been ongoing for many years now, with major
international conferences taking place since the early 1990s. Since
then, knowledge on the subject has greatly expanded, to the extent that
the Intergovernmental Panel on Climate Change (``IPCC'') issued a
special report on CCS in 2005. An extensive Massachusetts Institute of
Technology (``MIT'') study on the Future of Coal in 2007 also examined
CCS in depth. There is a substantial body of evidence, knowledge, and
peer-reviewed literature on CCS.
In many ways, CCS is not new. There are three elements to
successful geologic sequestration of carbon dioxide: capture,
transportation, and sequestration. All three of these elements have
been demonstrated and operated in commercial, large scale
The first element of CCS is the initial capture of the carbon
dioxide emissions. ``Pre-combustion capture'' is applied to conversion
processes that gasify coal, petroleum coke, or other feedstocks (such
as biomass) rather than combusting them in air. In the oxygen-blown
gasification process, the feedstock is heated under pressure with a
mixture of pure oxygen, producing an energy-rich gas stream consisting
mostly of hydrogen and carbon monoxide. Coal gasification is widely
used in industrial processes around the world, such as in ammonia and
fertilizer production. Hundreds of such industrial gasifiers are in
operation today. In power generation applications as practiced today
this ``syngas'' stream is cleaned of some impurities and then burned in
a combustion turbine to make electricity in a process known as
Integrated Gasification Combined Cycle (``IGCC''). Commercially
demonstrated systems for pre-combustion capture from the coal
gasification process involve treating the syngas to form a mixture of
hydrogen and CO2, and then separating the CO2
primarily through the use of solvents. These same techniques are used
in industrial plants to separate CO2 from natural gas and to
make chemicals such as ammonia out of gasified coal. However, because
CO2 can be released to the air in unlimited amounts under
today's laws, except in niche applications, even plants that separate
CO2 do not capture it; rather, they release it to the
atmosphere. Notable exceptions include the Dakota Gasification Company
plant in Beulah, North Dakota, which captures and pipelines more than
one million tons of CO2 per year from its lignite
gasification plant to an oil field in Saskatchewan (the Weyburn project
described below), and ExxonMobil's Shute Creek natural gas processing
plant in Wyoming, which strips CO2 from sour gas and
pipelines several million tons per year to oil fields in Colorado and
Wyoming. The principal obstacle for broad application of pre-combustion
capture to new power plants (and the main reason behind limited
deployment of IGCC with carbon capture) is not technical, it is
economic: under today's laws it is cheaper to release CO2 to
the air than capture it. Other capture technologies, including post-
combustion and oxyfuel combustion are currently at the bench and/or
pilot demonstration stage. The cost of CO2 capture is by far
the most expensive element in the CCS chain of operations, estimated to
be in the region of 75% of total costs, depending on the geological
setting and the distance of transport.
The second element of CCS is the transportation of captured carbon
dioxide to the injection site, if needed. As we describe further below,
CO2 pipelines today operate as a mature market technology.
The third element of CCS is the sequestration of the carbon dioxide
in geological formations. Injection of carbon dioxide has been
successfully demonstrated on a large scale, not least in the context of
CO2-EOR projects, some of which like Seminole, SACROC and
Wasson are injecting annual amounts of CO2 well above the
quantity that a 500MW coal plant would produce. There is also
considerable scientific knowledge regarding the mechanisms for trapping
carbon dioxide in sedimentary geological formations. For example,
residual trapping limits carbon dioxide mobility through capillary
forces. Solubility trapping occurs when injected carbon dioxide
dissolves in fluids within the geological formation. Stratigraphic
trapping occurs when overlying impermeable rock formations prevent
upward movement of carbon dioxide from underlying reservoirs.
Mineralization trapping occurs when injected carbon dioxide forms
carbonate minerals and essential becomes part of the solid rock into
which it was injected. Both the Intergovernmental Panel on Climate
Change (``IPCC'') and the interdisciplinary team from the Massachusetts
Institute of Technology (``MIT'') concluded that such sequestration
methods in appropriately selected and operated geologic reservoirs are
likely to trap over 99% of injected carbon dioxide over 1,000 years.
This conclusion is based on existing project performance and a number
of natural and industrial analogs. Nature itself has stored
hydrocarbons and CO2 for millions to hundreds of millions of
years, and humans have successfully stored natural gas and other fluids
There are several commercial and research projects that inject
carbon dioxide in sedimentary geological formations for permanent
sequestration. For example, the Sleipner project in Norway has been
operating since 1996 and injects about 1 million tons of CO2
annually into a deep saline formation in the North Sea. BP's In Salah
project, operating in Algeria since 2004, injects a similar amount of
CO2 stripped from natural gas back into the water leg of the
natural gas field. The Weyburn project receives CO2 captured
and transported from North Dakota to Saskatchewan and has been
operating since 2000 and injects 1-2 million tons of CO2
annually. All three of these projects include monitoring programs. The
results of that monitoring indicate that the CO2 is
remaining sequestered in the formations and that there is no reason to
expect any CO2 leakage from these projects. These projects
just mentioned give me a great deal of confidence that CO2
can remain permanently sequestered in geological reservoirs.
All components of CCS therefore--capture, transportation and
injection--have been demonstrated at commercial scale in a number of
industrial applications. We believe that the barriers to CCS are not
technological, but rather economic and regulatory. We are joined by
leaders of major industrial corporations such as NRG Energy and BP, who
have stated their case as follows:
``We're Carboholics. Make Us Stop. We are not running out of
time; we have run out of time. We need to move as quickly as
possible toward implementing the low-emissions ways of
combusting coal that are under development or, in the case of
``coal gasification'' technology, are ready for commercial
[David Crane, CEO of NRG Energy; Washington Post, October 14, 2007]
``CCS cannot succeed as a commercially successful emission
abatement technology without the policy or regulatory
frameworks that would allow commercial entities to invest in
it. New technology cannot be `pushed' into industrial-scale
deployment, a market is necessary to `pull' it. Deploying CCS
at scale is not as much a question of technology availability
but of economic viability. CCS is available today to play a
significant role in reducing greenhouse gas emissions and
addressing climate change''.
[Robert Malone, Chairman and President, BP America; Written Testimony
Submitted to the Select Committee on Energy Independence and Global
Warming U.S. House of Representatives, September 21, 2007]
The reason that no large integrated power sector CCS project exists
today is purely economic: it is simply cheaper to vent the
CO2 under today's laws instead capturing it, compressing it,
transporting it to a suitable reservoir and sequestering it. However,
this is not an indication of the state of readiness of the technology.
The USDOE is also leading a national research program on CCS. Although
we applaud the efforts of the dedicated and talented individuals
involved in this program, the resources and funding available are not
in line with the deployment timescale needed for CCS to reduce
emissions meaningfully. Without an economy-wide cap-and-trade scheme
that prices carbon emissions, and without targeted and reliably funded
(such as auction revenues, as opposed to the notoriously unreliable
appropriations) incentives to bring down the costs of CCS in the
initial years when the carbon price is too low and volatile to spur
investment, CCS is destined to linger in the background as it has done
until now. We are convinced, however that, under such a policy
framework, hundreds of MWs of power sector CCS would be deployed in the
early years. The DOE's targets and timelines should not be seen as
representative of the technology, or its program as the gateway to CCS.
Addressing energy independence and climate change
Weaning ourselves off foreign oil, while at the same time
addressing climate change, is achievable if we make the right choices.
In a world of climbing prices, increased dependence on imports,
geopolitical instability and rising emissions, the obvious focus should
be the more efficient use of energy and oil, and its replacement to the
extent possible with cleaner, sustainable alternatives.
Solutions abound: more efficient vehicles, expanded use of public
transport, smart city planning, low carbon fuels such as sustainably
grown biofuels, plug-in-hybrid vehicles powered by low carbon
electricity are all options that are available to us today. Our first
priority should be to substitute oil by improving end-use efficiency,
and by sustainable, low-carbon alternatives as fast as possible. These
resources are cleaner, and the diversity that they will provide is our
most powerful weapon against oil profiteers domestically and abroad. On
the topic of domestic production, we should fully exploit the fields we
have already explored and developed. America's existing oil fields hold
billions of barrels of oil that we know are there and can be produced
at reliable costs with no added environmental damage. CO2-
EOR is key to tapping this resource.
In order for these solutions to deliver on their potential,
concerted policy efforts will be needed--and this will take decisive
action, political vision and leadership. Now is the time to make the
right choices on how to fuel our future growth, and to move in an
efficient, low-carbon direction.
The false promises of drilling and unconventional fuels
In the face of high oil prices and energy security concerns, a
number of proposals have been put on the table that would allegedly
come to the rescue. These include drilling in environmentally sensitive
or protected areas such as the Arctic National Wildlife Refuge (ANWR)
or on the Outer Continental Shelf (OCS), or resorting to unconventional
oil sources such as tar sands and oil shale.
Drilling in ANWR and on the OCS has been restricted in order to
protect a few of the remaining special places in America from the
industrialization that accompanies energy exploitation, and because an
expansion of drilling in these areas will do precious little to benefit
Americans--the U.S. can meet its energy needs without opening these
areas to drilling and accompanying industrial activities. Both of these
premises remain true today, even though unrelated forces have resulted
in an increase in prices at the gas pump. It remains true that complete
exploitation of these areas would not reduce America's transportation
fuel bill. Efforts to expand drilling in those areas amount to nothing
more than attempts by special interests to stockpile and secure market
share. However, there are a combination of actions that can provide
real and long-lasting relief while protecting these special places as
part of the bargain.
The Arctic National Wildlife Refuge, a pristine area located in
northeast Alaska, is the nation's second largest national wildlife
refuge, comprising 19 million acres. It is home to nearly 200 wildlife
species. Because of its abundant and diverse wildlife, the refuge is
often likened to Africa's Serengeti. Scientists consider the coastal
plain, which has been proposed for drilling, to be the biological heart
of the entire refuge, containing caribou, polar bears, grizzly bears,
wolves, and various migratory birds, several of which are protected by
international treaties or agreements. The refuge was created in 1960 by
Congress to specifically protect the region's wildlife.
In addition to the wilderness value of the refuge, drilling there
will do nothing to relieve prices at the pump for a number of reasons,
which are aptly summarized in a recent report by Majority staff of this
Committee 3, drawing on official departmental statistics and
\3\ ``The Truth About America's Energy: Big Oil Stockpiles Supplies
and Pockets Profits''; A Special Report by the House Committee on
Natural Resources Majority Staff, June 2008.
It is not clear exactly how much oil could be extracted.
It may be possible that up to 11 billion barrels of crude oil is in
place. However, the amount of this oil that can actually be recovered
due to technological and economic reasons is significantly less. In a
recent study, the DOE's Energy Information Administration estimated
that the cumulative additional oil production from ANWR could be as low
as 1.9 billion barrels, with an upper estimate of 4.3 billion barrels.
\4\ ``Analysis of Crude Oil Production in the Arctic National
Wildlife Refuge''. Energy Information Administration Office of
Integrated Analysis and Forecasting U.S. Department of Energy; May 2008
A vast acreage is open and available for leasing in
Alaska outside ANWR. However, companies have leased only a fraction of
this land and produced very little or no oil. 5
\5\ Approximately 91 million acres are currently open to leasing in
the Arctic region of Alaska onshore and offshore. Oil and gas companies
have leased only 11.8 million of these. Within the National Petroleum
Reserve in Alaska, around 3 million acres out of 22.6 have been leased.
No oil has been produced those lands and industry has drilled only 25
exploratory wells there since 2000.
It will take a decade before oil can be produced from
ANWR, and another decade before oil production reaches its peak.
The total production from ANWR would pale in comparison
with total U.S. demand, and also in comparison to the production
potential from CO2-EOR from depleted fields.
Pretty much the same realities apply to drilling on the OCS.
Drilling in these areas poses unacceptable environmental risks of oil
spills, air and water pollution, seismic impacts on marine mammals and
onshore damage. Drilling is not necessary, given that estimates by the
Minerals Management Service (MMS) show that 60% of the untapped
economically recoverable oil and 80% of the untapped economically
recoverable oil and/or natural gas on the OCS are located in areas that
are currently open for leasing to industry.
Perhaps most importantly, feeding our addiction does nothing to
decrease our dependence on oil. Moreover, oil prices are set by global
markets. There is absolutely no evidence to show that increased
domestic production will result in more than a few cents worth of lower
prices at the pump--in fact although between 1999 and 2007, the number
of drilling permits issued for development of public lands has more
than tripled, oil and gasoline prices have risen to today's levels
regardless. We also cannot hide the fact that the local and cumulative
impacts from the expansion in leases and permits has also been
significant. Many leases are located in areas where the carrying
capacity for development has been, or is very close to being exceeded,
and in most areas development is taking place without an overall
development plan or in a phased manner. Nor is the characterization of
no-go areas accurate. In some regions such as California, despite the
absence of ``new'' drilling for some years now, there a substantial
ongoing legacy program. All in all, recent years have been
characterized by a fury of domestic drilling under permissive federal
regulators, with plenty of unused leases still available in reserve.
Despite this activity, prices have soared and the share of imports has
The only sound and possible way to decrease prices and ensure a
secure energy supply for the nation is to move away from the paradigm
of meeting uncontrolled demand growth, use oil more efficiently and to
replace it with other, low-carbon fuels. We just cannot drill our way
out of our oil dependence. Attempts to mislead the public into
believing that the protection of sensitive areas from drilling is
responsible for today's ills are irresponsible and not in the interest
of the American people, who will ultimately be the judges of the
policies that come out of Congress. Increasing fuel efficiency
standards for new vehicles to 40 miles per gallon would save more than
ten times the likely yield of oil from ANWR. It is short-sighted and
unwise to think of degrading an irreplaceable refuge to get a few cents
of relief from higher gas prices, rather than encouraging Detroit to
make more efficient cars and employing Americans in clean energy jobs.
Fortunately we moved a step closer to the right path this past year
when Congress required automakers to build cars and light trucks that
average at least 35 mpg by 2020. By raising the fuel-efficiency bar
even higher, we will be well on our way to beating the addiction. The
public has realized that, and automakers are feeling the impacts: only
recently General Motors announced that it is closing four plants that
produce sport utility vehicles and pickup trucks in North America,
prompted by soaring gas prices and slumping sales in the area. At the
same time, GM plans a new emphasis on compact cars and is reviewing the
future of the giant ``Hummer''.
Unconventional fuels are no exception. In the name of energy
independence and lowering gas prices, proponents would have us believe
that producing transportation fuels from tar sands, oil shale and coal
are a sensible solution. These resources can be accessed domestically
in the U.S. or in friendly Canada just across the border. The
technologies to convert these unconventional resources into fuels had
seen very limited application for years due to their high cost and
market risk, but current high oil prices are spurring a flurry of
development. Tempting though these resources might seem, they carry a
host of economic and environmental problems, and unsurprisingly are not
the answer to our oil addiction either.
Whether it is scouring the earth for the tar-like substance mixed
with sands excavated from under the Boreal forests of Alberta, Canada,
mining shale under the U.S. Rockies, or stripping coal from the
mountains of the American West and Appalachia to manufacture synthetic
liquid fuel, these unconventional sources constitute a heavy
environmental burden to communities and ecosystems--both local and
Fuel production from these sources is extremely energy intensive,
and the production process emits a far higher amount of greenhouse gas
emissions than conventional oil production--often whole multiples of
that amount. In a carbon-constrained world, these fuels will have to
shoulder the additional cost of their high carbon content, and will not
fare well either under cap-and-trade regimes or low carbon fuel
standards that are now being legislated in a number of states and
Canadian provinces and will likely be Federal policy in the U.S. soon.
Producing fuel from tar sands, oil shale, and liquid coal is not only
environmentally risky, but also a risky business proposition. In the
near future, the United States is likely to join Europe and Japan in
adopting mandatory limits on global warming pollution. Businesses
developing these highly polluting fuels will likely find they are poor
investments in a global market that increasingly values clean, low-
carbon energy technologies. Moreover, taxpayers are being asked to
share the bill for these risky deals through government subsidies and
entitlements. Taxpayers and investors alike should be wary of putting
their dollars into risky ventures involving carbon-intensive fuels.
Extraction of all three resources also comes at enormous cost to our
water, air, forests, wetlands, and wildlife and places serious burdens
on community infrastructure and public health.
Destroying wildlife habitat to extract those costly resources at a
significant expense to the climate is also not the way to wean
ourselves off oil. Some have characterized tapping into these resources
as ``scraping the bottom of the barrel'', which aptly describes how
little those resources would do to reduce oil consumption domestically,
or affect the price we pay for oil. Supply concerns are unlikely to be
eased by the growing clout of the world's oil cartel, the Organization
of Petroleum Exporting Countries (OPEC). OPEC countries hold over 75%
of the world's oil reserves according to current estimates. EIA
estimates that members of OPEC earned $673 billion in net oil export
revenues in 2007, a 10% increase from 2006, with Saudi Arabia earning
the largest share of these earnings at $194 billion or 29% of total
revenues. This immense market power enables the organization to control
world oil prices effectively, leaving limited or no scope for the U.S.,
which holds a meager 3% of global oil supply, to ease price pressures
through additional production.
Could CO2-EOR offer a better alternative to uncontrolled
drilling in wild places and dirty fuels, alongside conservation
policies and clean, sustainable fuels?
Enhanced oil recovery as an untapped domestic fuel source and
Stranded oil is oil that is left in the reservoir after primary and
secondary recovery techniques. Enhanced oil recovery through
CO2 flooding can reduce the amount of stranded oil
significantly. Of the original oil in place (OOIP), 5-40% is usually
recovered in the primary production phase. An additional 10-20% of oil
in place is produced by secondary recovery that uses water flooding.
Various miscible agents, among them CO2, have been used for
enhanced, or tertiary, oil recovery with an incremental recovery of 7-
23% (averaging around 13.2%) of the original oil in place. The exact
number is highly reservoir specific.
The use of CO2 for EOR began in the U.S. in the early
1960s. Inexpensive industrial CO2 sources, such as natural
gas processing plants, were initially used, although to sustain the
expansion this was quickly supplemented and eventually overshadowed by
naturally occurring CO2 discovered in Colorado, New Mexico
and Mississippi. Today, there are around one hundred registered
CO2 floods worldwide, almost 90% of which are in the U.S.
and Canada. Some 35 million tons of CO2 annually are
injected in mature oil reservoirs. These floods are primarily in the
Permian Basin of Texas and New Mexico, but also in the Bighorn Basin of
Wyoming, the Rangeley Field of Colorado and the Mississippi Salt Basin.
In North Dakota CO2 from the Great Plains Synfuels project
is captured and transported across the border to Canada, and injected
into the Weyburn and Midale fields in Saskatchewan. CO2
pipelines today operate as a mature market technology and are the most
common method for transporting CO2. The first long-distance
CO2 pipeline came into operation in the early 1970s. In the
United States, over 3,000 miles of pipeline transports more than 40
million tons CO2 per year for use in CO2-EOR.
The growth of CO2-EOR as a technique has been contained
for a number of reasons. The primary reason is the relative scarcity of
high-volume sources of pure CO2 that is needed for EOR
operations. This in turn has put a premium on the cost of
CO2 to operate the floods, which can add up to half the
total costs of a CO2-EOR project. The cost of capturing
anthropogenic CO2 and using finite supplies of
CO2 that is being produced from natural domes (in much the
same way as oil and gas) has thus kept projects in check. Another
reason relates to lead times: it can take two years or more for the
production to respond to the CO2 being injected, delaying
revenues, increasing risks and making financing less favorable.
Moreover, different fields' response to CO2 flooding can be
highly variable, making successful operation a site-specific affair.
Rising oil prices however, have now made CO2-EOR economics
look far more attractive. CO2 supply for EOR is more choked
than ever, and companies are pursuing aggressive business models to
expand their operations using anthropogenic CO2.
The Department of Energy (DOE) has collaborated with Advanced
Resources International (ARI) to produce estimates of the volumes of
oil that could be produced and the CO2 that can be stored
through CO2-EOR in the U.S. The latest iteration of the
study 6, issued in February 2008, builds on the previously
issued ``Basin Studies'' and makes the case for a very significant
domestic CO2-EOR potential. Specifically, it evaluates the
total stranded oil at roughly 400 billion barrels, 85 billion of which
is ``technically recoverable'' using state-of-the-art CO2-
EOR techniques, with 45 billion being ``economically recoverable'' at
an oil price of $70. At current levels, the economically and
technically recoverable estimates represent approximately 5-10 full
years worth of our oil consumption. The base case for the economically
feasible market demand for CO2 estimates are approximately
7.5 billion tons of CO2 in the lower 48 states, and 9.3
billion tons of CO2 in the whole of the U.S.--this is well
in excess of the nation's annual CO2 emissions of
approximately 6 billion tons of CO2. This is a significant
sequestration potential. Even today's injection levels of approximately
35 million tons per year amount to the emission from five large coal
power plants which, although would not solve our CO2 problem
still represents a significant quantity.
\6\ ``Storing CO2 with Enhanced Oil Recovery'', DOE/
NETL-402/1312/02-07-08, February 2008.
Easing the CO2 supply and cost constraints would enable
the much larger cited potential to be tapped. The International
Resources Group recently conducted an analysis of the proposed
Lieberman-Warner conducted for NRDC, using an improved and extended
version of the U.S. national MARKAL model (US-NM50) originally
developed by the Environmental Protection Agency's Office of Research
and Development. The reference point for the analysis is a business-as-
usual (BAU) scenario calibrated to the Department of Energy's 2008
Annual Energy Outlook. The results demonstrate the power of
CO2-EOR combined with efficiency: oil imports drop to 35% of
total oil supply in the middle years of the period under study due to
both lower demand and through CCS using CO2-EOR that greatly
expands domestic production from existing fields. Oil imports rise
again between 2035 and 2050 as the EOR resource begins to deplete,
although they remain under 60% of total oil supply, as compared to more
than 80% by 2050 in the BAU case. The figure below illustrates the
analysis results--the two scenarios correspond to different mixes of
renewable and CCS power generation:
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
CO2-EOR in our view therefore has a substantial
immediate- to long-term role to play in both increasing domestic oil
production in a responsible way, and in sequestering CO2.
Although global and national CO2 storage capacity estimates
in deep saline formations dwarf those in depleted oil and gas fields,
it will be several years before EOR capacity is depleted in the U.S. In
this interim period, the added revenues from oil production can help
offset the costs of capturing CO2 from industrial sources
and the costs of expanding the pipeline network for CO2.
Key questions and recommendations
We conclude by answering some of the key questions around
CO2-EOR as a domestic source of oil and a CO2
Why pursue further drilling when we should be breaking our dependence
Breaking the dependence on foreign oil--and oil in general--should
be the first priority as this testimony has argued. However, America
will continue to depend to some extent on oil for some years to come.
Sourcing this oil domestically is advantageous over importing it. Oil
produced from CO2-EOR in already drilled, mature fields is
far preferable to oil that would be produced from ecologically
sensitive areas of the country. Existing wells and pads can be used,
reducing the need for further disruptions. The CO2 pipeline
network for EOR can provide the backbone for a national sequestration
pipeline network. Moreover, an expansion in the CO2-EOR
business can have more direct beneficial effects to local and state
economies and workforces, as operators are almost entirely small- to
medium-size independent producers as opposed to the majors.
What about the CO2 emissions from the produced oil?
The oil produced from CO2-EOR will emit CO2
when refined and combusted. The key factor in determining whether these
emissions are additional, however, is to look at overall oil demand. If
the quantity of oil produced through CO2-EOR is substantial
enough to reduce prices and induce an increase in national consumption,
then the emissions are additional. In practice, however,
CO2-EOR oil would be limited in quantity would simply be
displacing imported oil without resulting in additional emissions.
Regarding the suggested notion of ``green oil'', which has been
suggested to capture the fact that oil from CO2-EOR might
have resulted in the sequestration of anthropogenic CO2, we
feel that it is simpler and more appropriate to account for the reduced
emissions at the source of the CO2, whether this is a power
plant, refinery, ethanol plant or other facility that would be
regulated under climate legislation.
How is business-as-usual CO2-EOR different to CCS?
CO2-EOR is not tantamount to CCS. In the former, the
objective of the process is to maximize oil yields using the least
amount of CO2, which has to be bought in as a resource,
often at some expense. The objective of sequestration on the other hand
is to maximize the amount of CO2 stored in the geological
formation, and to ensure permanence of storage. However, the extensive
body of technical expertise gained from CO2-EOR practices is
directly related to CCS. Conventional injection techniques used in EOR
in combination with a few simple additions can ensure permanent storage
and provide the assurances needed for a CO2-EOR project to
qualify as sequestration.
Specifically, these steps would be:
A more extensive geological site characterization that
establishes the containment characteristics and mechanisms present in
Proven monitoring and verification systems capable of
tracking the evolution of CO2 in the subsurface and either
verify containment or provide triggers for remedial action.
Mitigation or remediation actions to ensure that
CO2 remains contained underground without endangering
underground sources of drinking water or being released to the
Appropriate accounting provisions.
All of these steps and techniques can be performed today by
research and commercial entities alike at a small fraction of the cost
of capturing the CO2.
A geological site characterization assesses the ability of a
reservoir to retain CO2 for long periods of time, or
indefinitely for all intents and purposes. It assesses the capacity and
injectivity of the reservoir, the effectiveness of the trapping
mechanisms, the integrity of the caprock, as well as other risk
factors. The presence of oil in reservoirs is itself evidence that they
have the ability to trap fluids over long periods. However, a more
careful study of the specific reservoir characteristics is needed to
pick secure, non-leaky reservoirs with the desirable injection and
retaining characteristics. Geologists and the oil industry have the
necessary tools at the disposal to perform this evaluation at a modest
cost, especially in fields that have been drilled and operated for
years. The impact of existing wells at the proposed site, as well as
their construction standards, should be evaluated as an integral part
of the site characterization.
A robust program for monitoring CO2 in the subsurface is
an integral component of sequestration. Such a program, typically
referred to as Monitoring, Measuring, and Valuation (``MMV''), has the
role of tracking the evolution of CO2 in the subsurface and
either verifying containment or providing triggers for remedial action,
while serving as a continuous source of data feedback for the reservoir
models that should be used to predict CO2 behavior. A number
of monitoring techniques and tools are readily available. Selection of
the appropriate ones and specifics of their use is very site- and
medium-specific, and should follow directly from the information that
the site characterization study would reveal. The monitoring regime
should also include methods to detect potential leakage from wells,
which are the more likely conduits for migration as opposed to
geological pathways in well-selected reservoirs. This is particularly
important in areas of high drilling and well density.
In addition to monitoring, mitigation and remediation procedures
need to be studied and specified prior to injection to ensure that
CO2 will remain contained underground without endangering
underground sources of drinking water or being released to the
atmosphere. That said, experience and research indicate that the risk
of such leaks are minimal in properly selected and operated reservoirs.
We are not aware of any cases or studies in the history of
CO2-EOR that point towards groundwater contamination or
other adverse impacts.
Should the use of naturally sourced CO2 in EOR be
discontinued or CO2-EOR regulated differently?
It is somewhat paradoxical that in a world that desperately needs
to reduce its CO2 emissions, we are producing CO2
from geological formations in order to re-inject it. The reasons, or
course, are economic. We do not believe that the use of naturally
sourced CO2 should be discontinued. With the right
incentives for capturing anthropogenic CO2 in place, we
believe that future growth in CO2-EOR will be done primarily
on the back of anthropogenic CO2. As this becomes widely
available and economical, the use of naturally sourced CO2
can and should be phased out.
We also do not believe that it is necessary to alter the EPA's or
the states' Class II Underground Injection Control (UIC) requirements
for the purposes of business-as-usual EOR. If CO2-EOR is to
qualify as sequestration, however, we do believe that additional
provisions are required--as we outline below.
Cap-and-trade: the most far-reaching measure that will not only
reduce our greenhouse gas emissions but also reduce our dependence on
foreign oil, is an economy-wide cap-and-trade scheme, such as that
proposed by the Lieberman-Warner legislative proposal that was recently
debated in the Senate. Recognizing that the initial price of
CO2 is likely to be too low and/or too unstable to stimulate
sufficient investment in CCS, the bill included a set of targeted
incentives for carbon sequestration. As the MARKAL analysis described
earlier in this testimony shows, the bill would provide a significant
boost to CO2-EOR by making significant supplies of
CO2 available at affordable prices, greatly reducing oil
Tax treatment for anthropogenic CO2 pipelines: pipelines
that carry natural CO2 currently qualify for favorable tax
treatment as master limited partnerships. It is not yet clear whether
pipelines carrying anthropogenic CO2 would qualify. The tax
code should be modified explicitly to extend at least as favorable a
treatment, and preferably favorable, to the pipelines carrying
Requirements for conversion of EOR to CCS: we believe that
appropriately modified CO2-EOR projects should be allowed to
earn carbon allowances under a cap-and-trade scheme. EPA should be
required to write the relevant accounting protocols for sequestration
facilities. In addition, we propose the inclusion of conversion
provisions or a new injection class under the EPA's UIC program that
will clearly outline how a CO2-EOR project can be converted
to and classified as a CCS project. The characterization, monitoring
and remediation/mitigation considerations discussed above, together
with the accounting protocol, provide a basis for the conversion.
Subsurface property rights: states have different laws for mineral
and pore-space rights (which usually belong to the surface owner). With
very few exceptions, such as Wyoming that recently passed a clarifying
law, conflicts are resolved through case law, with the mineral estate
usually being dominant over the surface estate. Sequestration could
results in conflicts between occupying the pore space with
CO2 and minerals that might be present in the same
reservoirs, all between many different owners. We urge that states
clarify these properly issues, and that the relevant Federal agencies
clarify provisions for lands under their jurisdiction.
We would like to thank the Subcommittee again for the opportunity
to submit written testimony, and stand ready to assist in any way