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SPINNING STRAW INTO BLACK 

GOLD: ENHANCED OIL RECOVERY USING CARBON DIOXIDE 

OVERSIGHT HEARING 

BEFORE THE

SUBCOMMITTEE ON ENERGY AND 

MINERAL RESOURCES 

OF THE

COMMITTEE ON NATURAL RESOURCES 

U.S. HOUSE OF REPRESENTATIVES 

ONE HUNDRED TENTH CONGRESS 

SECOND SESSION 

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/index.html 

or 

Committee address: http://resourcescommittee.house.gov 

(II) 

COMMITTEE ON NATURAL RESOURCES 

NICK J. RAHALL, II, West Virginia, Chairman 

DON YOUNG, Alaska, Ranking Republican Member 

Dale E. Kildee, Michigan 

Eni F.H. Faleomavaega, American Samoa 

Neil Abercrombie, Hawaii 

Solomon P. Ortiz, Texas 

Frank Pallone, Jr., New Jersey 

Donna M. Christensen, Virgin Islands 

Grace F. Napolitano, California 

Rush D. Holt, New Jersey 

Rau ́l M. Grijalva, Arizona 

Madeleine Z. Bordallo, Guam 

Jim Costa, California 

Dan Boren, Oklahoma 

John P. Sarbanes, Maryland 

George Miller, California 

Edward J. Markey, Massachusetts 

Peter A. DeFazio, Oregon 

Maurice D. Hinchey, New York 

Patrick J. Kennedy, Rhode Island 

Ron Kind, Wisconsin 

Lois Capps, California 

Jay Inslee, Washington 

Mark Udall, Colorado 

Joe Baca, California 

Hilda L. Solis, California 

Stephanie Herseth Sandlin, South Dakota 

Heath Shuler, North Carolina 

Jim Saxton, New Jersey 

Elton Gallegly, California 

John J. Duncan, Jr., Tennessee 

Wayne T. Gilchrest, Maryland 

Chris Cannon, Utah 

Thomas G. Tancredo, Colorado 

Jeff Flake, Arizona 

Stevan Pearce, New Mexico 

Henry E. Brown, Jr., South Carolina 

Luis G. Fortun ̃ o, Puerto Rico 

Cathy McMorris Rodgers, Washington 

Louie Gohmert, Texas 

Tom Cole, Oklahoma 

Rob Bishop, Utah 

Bill Shuster, Pennsylvania 

Bill Sali, Idaho 

Doug Lamborn, Colorado 

Mary Fallin, Oklahoma 

Adrian Smith, Nebraska 

Robert J. Wittman, Virginia 

Steve Scalise, Louisiana 

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 Samoa 

Solomon P. Ortiz, Texas 

Rush D. Holt, New Jersey 

Dan Boren, Oklahoma 

Maurice D. Hinchey, New York 

Patrick J. Kennedy, Rhode Island 

Hilda L. Solis, California 

Nick J. Rahall II, West Virginia, ex officio 

Louie Gohmert, Texas 

Bill Shuster, Pennsylvania 

Bill Sali, Idaho 

Adrian Smith, Nebraska 

Steve Scalise, Louisiana 

Don Young, Alaska, ex officio 

(III) 

CONTENTS 

Page 

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 Austin .................... 48 

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 

(1) 

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 

Washington, D.C. 

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, and 

Scalise. 

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 consent. 

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 

2 

panel, if in fact questions are submitted by Members, that you respond in a timely fashion in writing within the 10 days. 

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 built on. 

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 older fields. 

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 

3 

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 carbon sequestration.’’ 

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 Coast. 

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 

4 

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 

carbon sequestration.’’ 

I wholeheartedly agree, and I look forward to the testimony from our witnesses. 

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 of Columbia. 

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 consideration. 

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 inVerDate Aug 31 2005 15:45 Mar 17, 2009 Jkt 000000 PO 00000 Frm 00008 Fmt 6633 Sfmt 6602 L:\DOCS\42879.TXT Hresour1 PsN: KATHY
5 

crease 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 energy crisis. 

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 world. 

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 reduce costs. 

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. 

6 

I hope you will consider my request. And I yield back, looking 

forward to the testimony that we hear from our witnesses today. 

[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 Recovery. 

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 

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. 

AMERICAN RESOURCES 

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. 

LEGISLATION 

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. 

HEARING 

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 

7 

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 forward. 

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. 

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 

8 

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 panel. 

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 justified. 

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 policy. 

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 sequestration efforts. 

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. 

9 

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 your questions. 

[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 

Introduction 

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 multipleuse 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 

10 

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 public 

lands. 

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 knowledge gaps. 

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 

11 

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 period. 

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 BLM. 

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. 

12 

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. 

Future Efforts 

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 is not. 

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 public lands. 

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. 

Conclusion 

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 resolved. 

• 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. 

13 

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 of Energy. 

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 CO2 EOR. 

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 costeffective approaches for efficiently capturing CO2 from fossil-fueled 

14 

power plants, and safely and permanently storing these in underground formations. 

Several key areas that make up this research program are subelements 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 infrastructure needs. 

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 technologies. 

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 sequestration co-benefits. 

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 sequestration. 

Introduction 

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 national 

security. 

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 

15 

1 Assessing Technical and Economic Recovery of Oil Resources in Residual Oil Zones, ARI, 

February 2006, www.adv-res.com/pdf/ROZlPhaselIIlDocument.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/oillgas/naturallgas/datalpublications/ 

crudeloillnaturallgaslreserves/cr.html. 

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. 

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 outreach. 

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. 

Technology Developments 

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 recovVerDate Aug 31 2005 15:45 Mar 17, 2009 Jkt 000000 PO 00000 Frm 00019 Fmt 6633 Sfmt 6621 L:\DOCS\42879.TXT Hresour1 PsN: KATHY
16 

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. 

ery 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 combinedcycle 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. 

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, 

17 

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. 

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 expanded. 

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. 

Conclusion 

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 sequestration 

co-benefits. 

Mr. Chairman, and members of the Subcommittee, this completes my statement. 

I would be happy to take any questions you may have. 

18 

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? 

Response 2. 

*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 


42879.007.eps
19 

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 without leaking? 

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 years away. 

Mr. COSTA. Thank you very much, Mr. Klara, for your testimony. 

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 year. 

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. 

20 

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 only. 

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. 

21 

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 Mountains alone. 

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 areas? 

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 CO2 to—— 

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. 

22 

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 on this? 

Mr. KLARA. Yes. A few examples—— 

Mr. PEARCE. Just very brief, because we need to move on to another question. 

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 dioxide. 

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 advancements. 

Mr. PEARCE. That wasn’t quite my question, but I will move on. 

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 climate? 

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 appreciate that. 

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 forth. 

23 

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, also. 

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 technologies. 

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 environmental effects. 

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. 

24 

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 time. 

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 have. 

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 

25 

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. 

[Applause.] 

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 greenhouse emissions. 

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 Louisiana. 

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. 

26 

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 CO2. 

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 anthropogenic CO2. 

27 

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 domestic oil. 

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 

28 

1Total 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 CO2. 

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 onethird (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. 

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. 

II. Transportation 

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 

29 

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 careful planning. 

III. Taxation 

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 reservoirs. 

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 

30 

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. 

V. Conclusion 

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 complex puzzle. 

31 

Attachment No. 1 

Attachment No. 2 


42879.001.eps 42879.002.eps
32 

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 

33 

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 applications. 

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 

34 

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 CORPORATION 

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 

guests. 

My name is William Roby. I am Vice President of Worldwide Engineering and Technical Services for 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 CO2 in the atmosphere. 

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 States. 

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 resources. 

35 

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 technique. 

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 25 percent. 

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 recovery operations. 

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 CO2. 

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 agreeVerDate Aug 31 2005 15:45 Mar 17, 2009 Jkt 000000 PO 00000 Frm 00039 Fmt 6633 Sfmt 6602 L:\DOCS\42879.TXT Hresour1 PsN: KATHY
36 

ments 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 sequestration sites. 

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 reinjected. 

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 industrialpower 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 much. 

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 atmosphere. 

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 

37 

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 improve extraction. 

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 

38 

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 onehalf 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 supplies. 

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 concurs. 

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 conVerDate Aug 31 2005 15:45 Mar 17, 2009 Jkt 000000 PO 00000 Frm 00042 Fmt 6633 Sfmt 6621 L:\DOCS\42879.TXT Hresour1 PsN: KATHY
39 

cerns about long-term storage of CO2 in oil and gas reservoirs as well as other geologic formations. 

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 production. 

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 

the atmosphere. 

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 leaks? 

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. 

40 

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 your testimony. 

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 combined-cycle 

technology. 

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 coalfired 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. 

41 

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 development. 

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 commercialscale 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 electricity requires. 

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 technology. 

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 emissions. 

42 

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 from EOR. 

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 Subcommittee. 

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-andtrade 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 costs. 

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 storage. 

Challenge: Building Baseload Generation in an Uncertain Regulatory 

Environment 

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, costcompetitive 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 

43 

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 requirements. 

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 

Business Opportunity 

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 important. 

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 further work. 

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 ammonia-based systems. 

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 there. 

44 

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. 

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; 


42879.003.eps 42879.004.eps
45 

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. 

Æ Addition of baseload power reduces marginal power prices to the benefit of 

consumers across the system. 

Æ Coal-fired capacity helps insulate Texas electric customers against natural 

gas price volatility. 

• Enhanced Oil Recovery and Carbon Sequestration 

Æ Availability of CO2 renders a greater fraction of the original oil in place recoverable, thereby adding to recoverable reserves. 

Æ 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. 

Æ Recapture and re-injection of CO2 produced with the oil can provide a high 

percentage of permanent geologic storage of the gas. 

• Economic Impact 

Æ Provide 1,500 to 2,000 jobs over a lengthy construction period. 

Æ Create more than 100 permanent and well-paying jobs. 

Æ Stimulate the local economy with construction spending over $2 billion and 

a total project cost over $3 billion 

Æ Enable $1 billion incremental Permian Basin oil production annually. 

Æ Reduce the rate of decline of U.S. production and dependence on imported oil. 

• Environment 

Æ 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. 

Æ Higher levels of sulfur dioxide (SO2) removal will likely be needed, pushing 

criteria pollutant emissions control to a new level. 

Æ An opportunity is presented for recapture of flue gas water that may enable 

gains in water use efficiency. 

Æ Trailblazer may also utilize air cooling or hybrid cooling systems that further 

decrease water requirements. 

Æ 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. 

46 

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 fossil fleet. 

• 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 delivery contracts. 

47 

Conclusion 

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. 

About Tenaska 

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 program. 

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 future. 

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 

48 

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 of oil. 

Mr. COSTA. Thank you, Dr. Kunkel, for your very good testimony. 

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 testimony. 

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 moniVerDate Aug 31 2005 15:45 Mar 17, 2009 Jkt 000000 PO 00000 Frm 00052 Fmt 6633 Sfmt 6602 L:\DOCS\42879.TXT Hresour1 PsN: KATHY
49 

toring, 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 legislation. 

(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 

50 

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 additional recovery). 

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 hydrocarbon reservoirs. 

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 

51 

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 CO2 avoided. 

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 changing’’ technologies. 

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 GAS PARTNERSHIP 

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 project. 

52 

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 year. 

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 trapped underground. 

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 industrial implementation. 

53 

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 head office. 

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 

CO2. 

Introduction 

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 WeyburnMidale 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 

2007. 

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 plans. 

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 

54 

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 Project—Phase I 

Project description 

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 Saskatchewan. 

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 sequestered. 

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. 

55 

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 day. 

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 Project— 

Final Phase 

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. 

56 

Regulatory Issues 

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. 

Public outreach 

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 long-term. 

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 2004. 

Conclusion 

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 geoVerDate Aug 31 2005 15:45 Mar 17, 2009 Jkt 000000 PO 00000 Frm 00060 Fmt 6633 Sfmt 6621 L:\DOCS\42879.TXT Hresour1 PsN: KATHY
57 

logical storage monitoring and assessment. Finally, it has enabled government to 

advance their innovation, technology and sustainability agendas. 

References 

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. Forwardlooking 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 

58 

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? 

Response: 

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 be seen. 

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 required. 

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 as long? 

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? 

59 

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-andtrade proposals that have been kind of percolating around here? 

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 longterm 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 longterm project. The price of oil is certainly an uncertainty. We would 

60 

like to be able to put as much certainty in there as we could. Royalty relief we think would be helpful. 

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 project? 

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. 

Pearce. 

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 is? 

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 economic analysis. 

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 

61 

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 CO2? 

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 issue. 

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 gasification facility. 

Mr. PEARCE. And even in your U.S. operation—you have U.S. operations? 

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 you. 

The Subcommittee is now in recess. 

62 

[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 second 

round. 

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 transmission capacity? 

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 store CO2. 

63 

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 Occidental’s 

perspective? 

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 Basin. 

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 storage. 

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 space. 

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 us. 

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 

right now. 

64 

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 first 

round. 

Mr. COSTA. Why don’t we alternate, Mr. Scalise? I am sorry, Mr. 

Sali. 

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 using? 

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 approximately. 

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 CO2 floods. 

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. 

65 

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 produce. 

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 natural gas? 

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? 

66 

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 described? 

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 project. 

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 around. 

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 sequestration. 

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 

67 

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 that. 

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 country. 

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 years. 

68 

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 current—— 

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. 

69 

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 continue. 

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. 

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 facing. 

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, 

70 

1 Estimates indicate that China surpassed the U.S. in emissions in 2007. 

2 ‘‘Storing CO2 with Enhanced Oil Recovery’’, DOE/NETL-402/1312/02-07-08, February 2008. 

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 supplies. 

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. 

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 atmosphere. 

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. 

71 

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 emisVerDate Aug 31 2005 15:45 Mar 17, 2009 Jkt 000000 PO 00000 Frm 00075 Fmt 6633 Sfmt 6621 L:\DOCS\42879.TXT Hresour1 PsN: KATHY

42879.005.eps
72 

sions 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 midcentury. 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 phaseout 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 peerreviewed 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 

installations. 

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 

73 

fields in Colorado and Wyoming. The principal obstacle for broad application of precombustion 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 underground. 

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 deployment.’’ 

[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. 

74 

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-andtrade 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 

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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. 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 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. 

in a recent report by Majority staff of this Committee 3, drawing on official departmental statistics and reports: 

• 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

• 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

• 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 risen. 

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 

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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 

global. 

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 CO2 sink 

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 

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6 ‘‘Storing CO2 with Enhanced Oil Recovery’’, DOE/NETL-402/1312/02-07-08, February 2008. 

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. 

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: 

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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 abatement technology. 

Why pursue further drilling when we should be breaking our dependence on oil? 

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 


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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 potential reservoirs. 

• 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 atmosphere. 

• 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 businessas-usual EOR. If CO2-EOR is to qualify as sequestration, however, we do believe 

that additional provisions are required—as we outline below. 

Recommendations 

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 

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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 imports. 

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 anthropogenic CO2. 

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 porespace 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 possible. 

Æ