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CARBON SEQUESTRATION: 

RISKS, OPPORTUNITIES, 

AND PROTECTION OF 

DRINKING WATER 

HEARING 

BEFORE THE

SUBCOMMITTEE ON ENVIRONMENT AND 

HAZARDOUS MATERIALS 

OF THE

COMMITTEE ON ENERGY AND 

COMMERCE 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED TENTH CONGRESS 

SECOND SESSION 

JULY 24, 2008 

Serial No. 110–141 

( 

Printed for the use of the Committee on Energy and Commerce 

energycommerce.house.gov 

COMMITTEE ON ENERGY AND COMMERCE 

JOHN D. DINGELL, Michigan, Chairman 

HENRY A. WAXMAN, California 

EDWARD J. MARKEY, Massachusetts 

RICK BOUCHER, Virginia 

EDOLPHUS TOWNS, New York 

FRANK PALLONE, JR., New Jersey 

BART GORDON, Tennessee 

BOBBY L. RUSH, Illinois 

ANNA G. ESHOO, California 

BART STUPAK, Michigan 

ELIOT L. ENGEL, New York 

ALBERT R. WYNN, Maryland 

GENE GREEN, Texas 

DIANA DEGETTE, Colorado 

Vice Chairman 

LOIS CAPPS, California 

MIKE DOYLE, Pennsylvania 

JANE HARMAN, California 

TOM ALLEN, Maine 

JAN SCHAKOWSKY, Illinois 

HILDA L. SOLIS, California 

CHARLES A. GONZALEZ, Texas 

JAY INSLEE, Washington 

TAMMY BALDWIN, Wisconsin 

MIKE ROSS, Arkansas 

DARLENE HOOLEY, Oregon 

ANTHONY D. WEINER, New York 

JIM MATHESON, Utah 

G.K. BUTTERFIELD, North Carolina 

CHARLIE MELANCON, Louisiana 

JOHN BARROW, Georgia 

BARON P. HILL, Indiana 

JOE BARTON, Texas 

Ranking Member 

RALPH M. HALL, Texas 

FRED UPTON, Michigan 

CLIFF STEARNS, Florida 

NATHAN DEAL, Georgia 

ED WHITFIELD, Kentucky 

BARBARA CUBIN, Wyoming 

JOHN SHIMKUS, Illinois 

HEATHER WILSON, New Mexico 

JOHN B. SHADEGG, Arizona 

CHARLES W. ‘‘CHIP’’ PICKERING, 

Mississippi 

VITO FOSSELLA, New York 

ROY BLUNT, Missouri 

STEVE BUYER, Indiana 

GEORGE RADANOVICH, California 

JOSEPH R. PITTS, Pennsylvania 

MARY BONO, California 

GREG WALDEN, Oregon 

LEE TERRY, Nebraska 

MIKE FERGUSON, New Jersey 

MIKE ROGERS, Michigan 

SUE WILKINS MYRICK, North Carolina 

JOHN SULLIVAN, Oklahoma 

TIM MURPHY, Pennsylvania 

MICHAEL C. BURGESS, Texas 

MARSHA BLACKBURN, Tennessee 

PROFESSIONAL STAFF

DENNIS B. FITZGIBBONS, Chief of Staff 

GREGG A. ROTHSCHILD, Chief Counsel 

SHARON E. DAVIS, Chief Clerk 

DAVID CAVICKE, Minority Staff Director 

(II) 

(III) 

SUBCOMMITTEE ON ENVIRONMENT AND HAZARDOUS MATERIALS

ALBERT R. WYNN, Maryland, Chairman 

FRANK PALLONE, JR., New Jersey 

BART STUPAK, Michigan 

LOIS CAPPS, California 

TOM ALLEN, Maine 

HILDA L. SOLIS, California 

Vice Chairman 

TAMMY BALDWIN, Wisconsin 

G.K. BUTTERFIELD, North Carolina 

JOHN BARROW, Georgia 

BARON P. HILL, Indiana 

DIANA DEGETTE, Colorado 

ANTHONY D. WEINER, New York 

HENRY A. WAXMAN, California 

GENE GREEN, Texas 

JAN SCHAKOWSKY, Illinois 

JOHN D. DINGELL, Michigan (ex officio) 

JOHN B. SHADEGG, Arizona 

Ranking Member 

CLIFF STEARNS, Florida 

NATHAN DEAL, Georgia 

JOHN SHIMKUS, Illinois 

HEATHER WILSON, New Mexico 

VITO FOSELLA, New York 

GEORGE RADANOVICH, California 

JOSEPH R. PITTS, Pennsylvania 

LEE TERRY, Nebraska 

MIKE ROGERS, Michigan 

JOHN SULLIVAN, Oklahoma 

TIM MURPHY, Pennsylvania 

JOE BARTON, Texas (ex officio) 

PROFESSIONAL STAFF

RICHARD FRANDSEN, Chief Counsel 

CAROLINE AHEARN, Counsel 

RACHEL BLESHMAN, Legislative Clerk 

GERALD COURI, Minority Counsel 

(V) 

C O N T E N T S 

Page 

Hon. Gene Green, a Representative in Congress from the State of Texas, 

opening statement ................................................................................................ 1 

Hon. John B. Shadegg, a Representative in Congress from the State of Arizona, opening statement ...................................................................................... 3 

Hon. Tammy Baldwin, a Representative in Congress from the State of Wisconsin, opening statement ................................................................................... 5 

Hon. Tim Murphy, a Representative in Congress from the State of Pennsylvania, opening statement .................................................................................... 6 

Hon. Doris Matsui, a Representative in Congress from the State of California, 

opening statement ................................................................................................ 7 

Hon. Joe Barton, a Representative in Congress from the State of Texas, 

opening statement ................................................................................................ 8 

Hon. John D. Dingell, a Representative in Congress from the State of Michigan, prepared statement ...................................................................................... 23 

WITNESSES

Benjamin Grumbles, Assistant Administrator, Office of Water, U.S. Environmental Protection Agency .................................................................................... 10 

Prepared statement .......................................................................................... 12 

Answers to submitted questions ...................................................................... 159 

Robert C. Burruss, Research Geologist, Energy Resources Team, U.S. Geological Survey, National Center ................................................................................ 23 

Prepared statement .......................................................................................... 25 

Answers to submitted questions ...................................................................... 163 

Scott M. Klara, Director, Strategic Center for Coal, U.S. Department of Energy ........................................................................................................................ 29

Prepared statement .......................................................................................... 32 

Answers to submitted questions ...................................................................... 164 

Lawrence Bengal, Director, Arkansas Oil and Gas Commission ......................... 60 

Prepared statement .......................................................................................... 62 

Answers to submitted questions ...................................................................... 173 

Don Broussard, Water Operations Manager, Lafayette Utilities Services ......... 67 

Prepared statement .......................................................................................... 69 

Answers to submitted questions ...................................................................... 174 

Ian Duncan, Associate Director, Earth and Environmental Systems, Bureau 

of Economic Geology ............................................................................................ 84 

Prepared statement .......................................................................................... 85 

Submitted questions 1 ......................................................................................

Scott Anderson, Senior Policy Advisor, Climate and Air Program, Environmental Defense Fund ........................................................................................... 91 

Prepared statement .......................................................................................... 92 

Answers to submitted questions ...................................................................... 175 

Ben Yamagata, Executive Director, Coal Utilization Research Council ............. 96 

Prepared statement .......................................................................................... 98 

Answers to submitted questions ...................................................................... 176 

SUBMITTED MATERIAL

Interstate Oil and Gas Compact Commission, report of September 25, 2007, 

submitted by Mr. Bengal ..................................................................................... 110 

1 Mr. Duncan did not answer submitted questions for the record. 

(1) 

CARBON SEQUESTRATION: RISKS, OPPORTUNITIES, AND PROTECTION OF DRINKING 

WATER 

THURSDAY, JULY 24, 2008 

HOUSE OF REPRESENTATIVES, 

SUBCOMMITTEE ON ENVIRONMENT AND HAZARDOUS

MATERIALS, 

COMMITTEE ON ENERGY AND COMMERCE, 

Washington, DC. 

The subcommittee met, pursuant to call, at 10:05 a.m., in Room 

2322 of the Rayburn House Office Building, Hon. Gene Green 

(chairman) presiding. 

Members present: Representatives Green, Solis, Baldwin, 

Butterfield, Barrow, Hill, Schakowsky, Matsui, Dingell (ex officio), 

Shadegg, Radanovich, Pitts, Terry, Murphy, and Barton (ex officio). 

Staff present: Caroline Ahearn, Ben Hengst, Andrew Wallace, 

Chris Treanor, Rachel Bleshman, Katherine Brittain, Michelle 

Byrne, Alex Haurek, David McCarthy, Jerry Couri, Amanda 

Mertens Campbell, Andrea Spring, and Garrett Golding. 

OPENING STATEMENT OF HON. GENE GREEN, A 

REPRESENTATIVE IN CONGRESS FROM THE STATE OF TEXAS 

Mr. GREEN. I call this meeting to order, and today we have a 

hearing entitled ‘‘Carbon Sequestration: Risks, Opportunities and 

Protection of Drinking Water.’’ For purposes of making opening 

statements, the Chair and the ranking members of the subcommittee and the full committee will each be recognized for 5 

minutes. All other members of the subcommittee will be recognized 

for 3 minutes. Those members may waive the right to make an 

opening statement and when first recognized to question witnesses, 

instead add 3 minutes to their time for questions. Without objections, all members have five legislative days to submit their opening statement. And I will recognize myself for my opening statement. 

Now, first I want to state that I am glad to be here in the first 

hearing of the subcommittee in my capacity as Chair. I intend the 

subcommittee be active and engaged with its jurisdiction and operate in a conclusive fashion for the benefit of all its members. 

Former Chairman Al Wynn is a good friend and did an excellent 

job and I am grateful to vice chair Hilda Solis of California, for her 

active role on the subcommittee. I am also looking forward to working with our ranking member, Mr. Shadegg of Arizona, and all our 

members. And I will welcome the ranking member. 

2 

Today’s hearing is timely, given the recent released EPA proposal for regulating carbon sequestration. EPA’s proposal seeks to 

provide regulatory certainty for potential sequestration projects 

which would be an important foundation for any future climate 

change legislation. 

Our subcommittee intends to work diligently on the oversight of 

this rulemaking and examine whether EPA requires additional authority to regulate underground carbon sequestration. 

Carbon capture and sequestration is known as CCS. It is one of 

the most important possible solutions for climate change. Without 

sequestration, coal fire power plants could go from being a low cost 

option to a high cost option if Congress regulates greenhouse gas 

emissions. Electricity, heating, and manufacturing costs could rise 

economy wide, at least, in the short and medium term. 

Cost models for climate change legislation are highly dependent 

on the development of future technologies which are inherently difficult to predict. Several models do tell us, however, that one of the 

largest variables for the impact of cost—energy cost, is the availability of CCS. EPA’s analysis of the recent Lieberman-Werner bill 

indicates that CCS could account for 30 percent of the CO2 reductions by 2015, which would involve injecting many gigatons of CO2

underground. If CCS were unavailable, these reductions would 

have to come from elsewhere and, likely, at a higher cost. CCS has 

two major components, capture and sequestration. To date much of 

the attention has been on capture. Last week our Energy and Air 

Quality Subcommittee held a hearing on the important legislation 

introduced by Chairman Boucher to move capture technology into 

the commercial phase. We are holding our hearing to inform Congress of the geological opportunities to sequester carbon and potential risk of underground injection of CO2 on a massive scale. 

Unlike capture, carbon injection technology is well established 

and has been used for enhanced oil recovery for over 30 years. The 

Permian Basin in west Texas is home to the majority of carbon dioxide injection and the majority of the carbon dioxide injection in 

the entire world. This is good news for addressing climate change 

and producing more domestic energy. 

Carbon sequestration differs from enhanced oil recovery in two 

ways. The volumes of CO2 for sequestration are much larger and 

long-term storage must make sure that CO2 does not come back up. 

Large scale CO2 sequestration could have a number of unintended 

consequences underground, if done improperly. The injected CO2

will contain pollutants such as sulfur or mercury from power plant 

emissions, or it could cause heavy metals underground to leach into 

ground water. If injected near fault lines, the pressure could cause 

seismic activity, which could allow CO2 to escape. CO2 would push 

saline aquifiers into fresh water occupiers, harming drinking water 

and otherwise alter ground water. The EPA’s proposed sequestration rule creates a new class of regulated well for the underwater 

injection control, the UIC program, which operates under the Safe 

Water Drinking Act. The Act provides minimum standards for protecting underground sources of drinking water and our committee 

needs to know whether that authority is sufficient to address the 

leaks of CO2 back in the atmosphere or other risks. 

3 

The proposed rule also set a 50-year default time period for operators to monitor and provides financial assurance for correcting action for carbon sequestration projects. There are no similar limits 

on existing wells for hazardous waste of enhanced oil recovery. 

EPA appears to be balancing the importance of CCS technology for 

climate change against the potential long-term risk of large scale 

CO2 sequestration. The committee will pay close attention and ensure this balance is correct, and we do not unduly start shifting 

risk from the atmosphere to underground sources of drinking 

water. 

The Department of Energy’s National Energy Technology Lab 

and the U.S. Geological Survey are assessing our Nation’s capacity 

for carbon sequestration. Breakthroughs in capture technology will 

be of little use unless we sequester the CO2. For economic reasons, 

we know a lot about oil and gas formations, but they are estimated 

to be, only, about four percent of the total capacity. We know less 

about the deep saline aquifiers that are the biggest potential for sequestration. 

Some of our witness who will be displaying maps of our current 

assessments and describing the status of their efforts, in particular 

we are interested in the status of the USGS effort to rank potential 

sequestration sites for capacity and risk. 

With that, I yield back my time and again I recognize our ranking Member, Mr. Shadegg of Arizona, and good to be working with 

you. 

OPENING STATEMENT OF HON. JOHN B. SHADEGG, A REPRESENTATIVE IN CONGRESS FROM THE STATE OF ARIZONA 

Mr. SHADEGG. Thank you, Mr. Chairman, and I am pleased to be 

here. I apologize for my slightly tardy arrival and I look forward 

to working with you. I want to congratulate you in your new capacity. I think we can do a lot of good and I am encouraged to see the 

subcommittee re-engaging in its work. 

I cannot imagine a more important time for us to cooperate on 

the issues before this subcommittee as America is clearly energy 

challenged, at the moment, and we face a number of grave issues, 

including the question of global warming and greenhouse gases and 

their effect on our environment. With your permission, Mr. Chairman, and the unanimous consent of the committee, I will put my 

written statement into the record and just make a few comments. 

I want to thank you for holding this hearing. I think it is extremely important. As you know, we are looking at carbon capture 

and sequestration and as we move toward a carbon constrained 

world, it is pretty clear that that may be a part of the technology 

that we move forward with in this country. Coal makes up a substantial part of the energy production in this country today. In 

2007 coal fueled almost half or 48.7 percent of the electricity generated in the United States. If we are to continue to rely on our 

vast quantities of coal, then indeed CCS technology appears likely 

to be a part of the equation. 

However, coming from a State like mine, of Arizona, where 

water, literally, is life and death, and where we often joke that 

whiskey is for drinking and water is for fighting, it is of grave concern to me that we examine the process by which we capture and 

4 

sequester carbon and if we are to do it in the earth, in caverns located underground, the environmental impacts of doing so. I believe it would be a grave error for us to move forward with technologies that trade one environmental problem, the impact of carbon on our air and on our overall environment with another environmental problem and that would be the impact of carbon capture 

and sequestration on our water supply. 

So I think this is an extremely important hearing. I note that a 

number of States are already moving forward to restrict new carbon producing coal fired power plants because of lack of the ability 

to capture and sequester the carbon produced and that makes it 

very important that we move forward with this technology and that 

we learn of the environmental impacts of what is being proposed, 

so I look forward to the hearing testimony today. I will put my full 

statement into the record and I am anxious to work with you, Mr. 

Chairman, as we go forward. 

[The prepared statement of Mr. Shadegg follows:] 

STATEMENT OF HON. JOHN SHADEGG

Thank you Mr. Chairman. I’d like to start by welcoming you to your new capacity 

on the Subcommittee. I look forward to working with you. 

Today’s hearing is focused on the sequestration of carbon dioxide as it relates to 

drinking water. This issue is part of a much broader picture. The United States’ demand for energy is expected to rise by 19% by 2030. In 2007, coal fueled almost 

half of electricity generated in the United States. As we move towards a carbon-constrained world, many believe carbon capture and sequestration (CSS) technologies 

should be part of the equation, to not only continue to meet our current demand 

but to also meet our future demand with American made coal. 

A large part of deploying CCS technologies is tackling the cost of both the capture 

technology and the transportation of the carbon dioxide to storage sites. However, 

at issue today, is the sequestering of the carbon dioxide and what potential this 

process may have on drinking water. 

Last Tuesday, EPA issued a proposed rule on carbon sequestration under the Safe 

Drinking Water Act’s Underground Injection Control program. As we will hear from 

our witnesses today, this program seems appropriate given EPA’s past experience. 

However, I have two major concerns. 

First, a large-scale project has not been demonstrated in the United States. A 

more realistic understanding of the entire CCS process seems necessary before we 

create a full-scale regulatory regime. For example, we understand that sequestered 

carbon may be very mobile in various geological sites. However, we do not understand how a large plume of carbon dioxide may move through these geological sites 

or where the displaced liquids will go. And this is particularly important to my 

home state of Arizona where we have carbon storage potential but also a large 

water supply from underground aquifers most likely to be affected by carbon sequestration. In fact, Arizona has two sole source aquifers - the Upper Santa Cruz and 

Avra Basin Aquifer and the Bisbee-Naco Aquifer that may be particularly at risk. 

We must be careful not to trade one environmental concern - carbon dioxide emissions - with another - contaminated drinking water. 

Secondly, I am seriously concerned that liability has not been addressed by the 

EPA proposed rule. It is important for businesses to fully understand all the rules 

of operation- not to only understand half of the rulebook. While I understand the 

complexity of determining liability issues, I do not think that the nation is served 

well by Washington bureaucrats ignoring the issue. Planning to address the issue 

at a later date is inappropriate. Businesses in America face enough uncertainty with 

regulation. We should not arbitrarily expose them to liability issues. Carbon emissions are already impacting the business decisions of today’s energy providers and 

it is important the Federal government provide certainty in their regulations to aid 

future business decisions before creating a massive regulatory regime. I look forward to addressing these and other issues in our question and answer period. 

Thank you. 

5 

Mr. GREEN. Thank you, Mr. Shadegg. Next opening statement is 

Congresswoman Baldwin, Wisconsin. 

OPENING STATEMENT OF HON. TAMMY BALDWIN, A REPRESENTATIVE IN CONGRESS FROM THE STATE OF WISCONSIN 

Ms. BALDWIN. Thank you, Mr. Chairman, and let me join my colleagues in congratulating you on your new role on this subcommittee. I look forward to working with you and moving forward 

on many important environmental matters that this subcommittee 

will examine. You are beginning your chairmanship on a very 

strong note with today’s hearing focused on carbon sequestration. 

Deployment of carbon capture and sequestration technology is 

critical if we are going to drastically remove greenhouse gas emissions from the atmosphere, and doing so is critical because, as we 

know, climate change is real and it poses serious threats to our 

economy, our environment and our national security. Certainly as 

we move forward with legislation to address climate change, we 

must ensure that the various technologies we deploy are safe and 

effective. 

We already know that we have the ability to capture and even 

inject carbon dioxide into the ground. In Wisconsin we have a very 

exciting, first of its kind in the United States, carbon capture pilot 

project at a coal fired power plant. It has the potential to capture 

90 percent of the CO2 it emits from one percent of the flue gas 

being captured. Unfortunately, though, it is a catch and release 

program, at this point, as the ability to have large-scale sequestration is not yet available nationwide and may never be available in 

a State like Wisconsin due to our State’s geologic formations. As future pilot projects come online that do have sequestration capabilities, proper regulations must be in place to ensure the safety of the 

American people and our drinking supply. 

I commend the EPA for taking the first step in laying out proposed regulations that would govern the underground injection of 

carbon dioxide and I hope to learn more about how the administration feels large-scale sequestration can become viable. 

And among the issues that I hope our witnesses will touch upon 

today are, what are the liability issues associated with sequestration? In other words, who will be held responsible if there is a significant leak affecting our water supply? What are the standards 

that must be set to ensure the safety of the injection wells? For instance, how do we protect these wells from corroding and are there 

monitors that can be placed on the wells to alert us if something 

is going awry? And, finally, if different carbon capture technology 

is used, is it possible that carbon dioxide composition would be different, and if so, does this present an issue in terms of sequestration capability? 

Mr. Chairman, I apologize that I will have to leave the hearing 

early this morning, for other commitments. However, I am hopeful 

that some of these questions will be addressed through the course 

of your discussions today, and I thank you and yield back the balance of my time. 

Mr. GREEN. Thank you, and members have the right, if we don’t 

get to your questions, you can submit them and I think that is 

6 

great. Our next opening statement is Congressman Murphy from 

Pennsylvania. 

OPENING STATEMENT OF HON. TIM MURPHY, A REPRESENTATIVE IN CONGRESS FROM THE STATE OF PENNSYLVANIA 

Mr. MURPHY. Thank you, Mr. Chairman. It is good to see you at 

the helm here, and I am excited that you would choose such an important topic as carbon sequestration because it is so vital in the 

interest of our Nation such as our family security, our job security, 

our economic security and our National security as we are facing 

the challenge of our generation, that is energy. This Congress has 

debated a lot, not necessarily as much as I would like to see on 

issues involving energy when it comes to oil. But coal and the 

issues with coal are often times pushed aside, so it is vitally important we deal with this issue and start to deal with it today. 

Our energy demands in this country are going to double by about 

the year 2050. That means, right now, the 400 coal-fired power 

plants, many of them with inadequate scrubbers and no scrubbers, 

need to be rebuilt in ways that eliminate pollution. We are also 

going to need to about double that—the number of coal-fired power 

plants, and that means that if we are going to meet those demands 

by 2050, we are going to have to have a ribbon cutting ceremony 

for new coal-fired power plants starting year 2010, every two and 

a half weeks. We have not even started building, in fact, some contracts have been cancelled, much of that because we are trying to 

deal with the issue of carbon sequestration, an issue we have to 

deal with. 

Now, we only have two options for eliminating the emissions in 

coal-fired power plants. One is to close the plant, you have zero 

emissions—zero energy and the USA loses so much of its electricity 

it cannot only—cannot sustain growth, it cannot keep the manufacturing sector up and light our homes, our farms and our factories. 

The second thing is to solve this issue of carbon sequestration. 

I am pleased that in southwestern Pennsylvania where we have 

one of the National Energy Technology Labs, they have been doing 

some pretty remarkable work on dealing with the carbon sequestration issue. It is one that we have to make sure as a Congress 

and as a Nation, we fund this so we can solve this problem. While 

we have 250 to 300 years worth of coal, we have far more energy 

than the Saudi’s may have in oil and we ought to be using American energy, and American know-how, and American energy to 

solve America’s energy problems. 

We are going to need to continue to develop these technologies, 

to map out systems and ensure that anything we do is safe and 

sustainable. So whether we are looking at injecting CO2 into rock 

or into the ground sites, we have to make sure that we also negate 

any risk involved with that to the environment too. We don’t just 

want to—we don’t want to just postpone environmental problems, 

we want to solve them. 

Other issues, of course, are not just carbon sequestration, but actual carbon transformation. We are using other plant life, et cetera, 

we can convert to carbon, back into oxygen and other elements, as 

well. Well, with all that, this is a vitally important meeting and vitally important hearing because this is a critical component in our 

7 

Nation’s—solving our Nation’s energy problems. I look forward to 

hearing the testimony today, along these lines. Thank you, Mr. 

Chairman. I yield back. 

Mr. GREEN. Thank you. Our next opening statement is our—and 

welcome to the committee for a good friend, Congresswoman Matsui. 

OPENING STATEMENT OF HON. DORIS MATSUI, A REPRESENTATIVE IN CONGRESS FROM THE STATE OF CALIFORNIA 

Ms. MATSUI. Thank you, Mr. Chairman. I would like to join my 

other colleagues in welcoming you to this new post and we look forward to working with you, and thank you for calling this important 

hearing. And I would like to also thank today’s panelists for joining 

us and discussing the important issue of carbon capture and storage. I look forward to hearing all of your expert opinions. 

Carbon capture and storage is a subject that has been getting a 

lot of attention lately, as we look to ways of dealing with the urgent matter of climate change. Only two weeks ago we heard in the 

Energy and Air Quality Subcommittee about prospects for conducting research and demonstration projects in carbon capture and 

storage. Then, as now, my first concern is public safety. The evidence is clear. We must take actions to seriously address the issue 

of climate change. It will be a massive undertaking. 

To tackle this enormous challenge, we must have all available resources at our disposal. Carbon capture storage is likely to be one 

component to a comprehensive approach to addressing this problem 

along with many others, such as energy efficiency, solar, biomass 

and wind. But our constituents need to be confident that we can 

use any new technology safely and effectively and carbon capture 

remains to be fully tested. 

My home State of California already has many environmental 

risk factors, from contaminated ground water to active geologic 

faults. So we must ensure that any new technologies we use do not 

adversely affect the health of our population. While we must embrace new technologies, we cannot do so at the expense of clean 

water, clean air or our constituent’s safety. 

As a mother and now a grandmother, I am constantly reminded 

of the importance of leaving a safe, livable and stable planet for future generations. That is why, now, we must address climate 

change, but we must also consider, carefully, how to proceed wisely 

and with the appropriate safeguards. I look forward to learning 

more about the ways we can ensure that carbon capture storage is 

used safely. Mr. Chairman, I thank you for your leadership and 

your commitment to these issues. And I yield back the balance of 

my time. 

Mr. GREEN. Thank the gentlewoman. Congressman Terry. 

Mr. TERRY. I will waive opening statement at this time. I appreciate that. 

Mr. GREEN. Congressman Hill. 

Mr. HILL. I will pass on an opening statement, Mr. Chairman, 

other than to say congratulations for ascending to the helm here. 

We all know that you are going to do a good job. 

Mr. GREEN. Thank you. Congressman Barrow. 

8 

Mr. BARROW. I thank the Chair and I want to add my congratulations to my beatification as the Chairman of this subcommittee. 

I am looking forward to working with you. This is an incredibly important subject to my part of the country where the utility customers rely, to a much greater extent than we would like to, on 

sources of energy that emit a great deal of carbon into the atmosphere. So this is very important to us, so in the interest of time 

and getting to the panel, I am going to waive any further opening 

statement, but Mr. Chairman, thank you for your leadership in 

calling this hearing and I look forward to working with you on this 

issue. Thank you very much. 

Mr. GREEN. Congressman Radanovich, do you have an opening 

statement? 

Mr. RADANOVICH. No, I will pass. 

Mr. GREEN. Okay, thank you. That concludes our opening statements and we will turn to our first panel. Again, I want to welcome, not only our first panel, but our second panel today on this 

very important issue. Of course, coming from Texas where we have 

an interest in carbon sequestration already, and producing in more 

hydrocarbons, we have some working experience with it. But I 

would like to welcome the Honorable Benjamin Grumbles, the Assistant Administrator of the U.S. EPA Office for Water; Mr. Scott 

Klara, the Director of the Strategic Center for Coal and the Department of Energy’s National Energy Technology Lab that Mr. Murphy mentioned and also Dr. Robert Burruss, Research Geologist for 

the Energy Resources Team at the U.S. Geological Survey. I welcome each of you and each of you will give 5-minute statements. 

We will start with you, Mr. Grumbles. 

Mr. GRUMBLES. Thank you, Mr. Chairman. I am Ben Grumbles, 

Assistant Administrator for Water at the U.S. EPA. 

Mr. GREEN. Mr. Grumbles, if you could hold just a minute. Ranking member. 

Mr. BARTON. Is it—am I in time for an opening statement? 

Mr. GREEN. If you would like to give one. 

Mr. BARTON. Very quickly. 

Mr. GREEN. Okay. 

OPENING STATEMENT OF HON. JOE BARTON, A 

REPRESENTATIVE IN CONGRESS FROM THE STATE OF TEXAS 

Mr. BARTON. You want to hear the first part of it Mr. Chairman. 

I want to congratulate you for taking this gavel of the Environment 

and Hazardous Material Subcommittee. For once, I have to say 

your sides got it right. You actually know a lot about this subject. 

Your district has a huge number of petrol-chemical facilities. Nobody has worked harder to protect the environment during your 

time in the Congress, than you have. And on a personal level, you 

are a fair and reasonable person and very approachable. And, you 

know, we were very pleased to have Mr. Wynn, when he was here 

in your position, but you are a worthy successor and I am absolutely certain that this subcommittee and the full committee is 

going to be better because of your leadership. So it is really good 

to see you in the Chair. I appreciate that a lot. 

9 

This hearing is an important hearing, Mr. Chairman. Many 

members of the full committee have joined the subcommittee 

Chairman, Mr. Rick Boucher, of the Energy and Air Quality Subcommittee, myself included, in sponsoring bills—a bill to develop 

the technology for carbon capture, carbon conversion and storage. 

Ultimately we want to see this concept become an option in the energy mix for the United States of America, but first we have got 

to understand all the facts of the issue. 

In resolving one environmental issue, we need to make sure that 

we are not starting another. The EPA has begun to explore what 

underground injection of carbon dioxide or CO2 might mean for underground sources of drinking water. I want to commend Assistant 

Administrator Grumbles for getting out ahead on this issue. Let us 

understand these issues as soon as possible so that as the project 

developers design their systems that make whatever scientific parameters are necessary to protect our drinking water supplies, how 

liability is addressed under CERCLA and RCRA, however, is very 

muddy water indeed. EPA’s proposed rule from last week does not 

address any of the liability issues surrounding CO2 sequestration 

and underground sources of drinking water. Without an understanding of the liability framework, it is extremely difficult for 

members and their constituents to make an informed decision on 

the proposed rule. 

We also need to better understand the varieties of geologic formations, how they compare as suitable hosts for underground injection. If the best formations are not close to power plants capturing 

the CO2, that raises a huge logistics issue. 

I think that the issues already identified in Mr. Grumbles office 

and others with regard to injecting CO2 into the ground should 

cause us to take another look at carbon dioxide conversion technology, converting CO2 into a solid substance such as sodium bicarbonate or what most people would call baking soda is already underway at an experimental site in my district, down in Texas. 

Large-scale application of this process would yield more baking 

soda than we probably need, but there are other applications too, 

and it is dramatically easier to store than the gassiest form of CO2. In short, Mr. Chairman, we have got a lot to learn in this area, 

and I am happy that our witnesses today are going to begin the 

process of educating us. I want to welcome them all, especially Mr. 

Grumbles, who has served so professionally in a particularly difficult job at EPA. I look forward to today’s testimony. Thank you 

again for your courtesy in allowing me to give an opening statement on my tardy arrival. With that I yield back. 

Mr. GREEN. Thank you Mr. Barton, and I appreciate your friendship for a number of years, and I always joked that sometimes 

when Congressman Barton and I talk we don’t have to have an interpreter to understand our language. If we could ask your forbearance, our Chairman is on the way, and having learned a long time 

ago that that is why our office has been across the hall from Chairman Dingell for almost a decade now, even though we could move 

to a larger one, it is so convenient to make sure I can talk to the 

Chair, and— 

Mr. BARTON. We have got an oversight hearing on long-term 

healthcare and that is where he and I both were. 

10 

Mr. GREEN. And I am also on that committee and I have an interest in it, if I could ask unanimous consent for the Chair to give 

his opening statement when he arrives and that way we can start 

with our witnesses, if our witnesses don’t mind being interrupted. 

Mr. GRUMBLES. Not at all. 

Mr. GREEN. Mr. Grumbles, again, welcome. 

STATEMENT OF BENJAMIN GRUMBLES, ASSISTANT ADMINISTRATOR, OFFICE OF WATER, U.S. ENVIRONMENTAL PROTECTION AGENCY 

Mr. GRUMBLES. Thank you, Mr. Chairman. I am Ben Grumbles, 

Assistant Administrator for Water at U.S. EPA, and it is an honor 

to be the first witness to congratulate you on your new post. I know 

that we share the same goal and that is accelerating environmental 

progress while maintaining our country’s economic competitiveness 

and energy security, and it is a delight to be able to discuss with 

committee members the subject of geologic sequestration, and in 

particular the first ever rule that we have just proposed that Administrator Johnson signed on July 15 that would provide a National framework for safe and effective geologic sequestration and 

help make significant strides towards mitigating greenhouse emissions. 

Mr. Chairman, what I would like to do in the brief amount of 

time in the terms of the opening statement, is to emphasize, first 

of all with respect to climate change and efforts within the EPA 

and the administration that we are committed to taking timely and 

aggressive actions to confront the serious challenge of global climate change by harnessing the power of advanced climate change 

mitigation technologies such as carbon capture and geologic sequestration. We are entering a new age of clean energy where we can 

both be good stewards of the earth and good stewards of the American economy. The Intergovernmental Panel on Climate Change 

has estimated that CCS, the process of capture, transport and storage of CO2 has significant potential and can reduce domestic CO2

emissions to the atmosphere from 15 percent to 55 percent over the 

next century. U.S. EPA is excited about advancing that effort and 

the Office of Water, in close collaboration, with the Air Office and 

the Research Office work together so that the Administrator would 

be in a position to propose this rule that he signed on July 15. 

Mr. Chairman, geologic sequestration is not the silver bullet, but 

it may be an ace in the hole, and it is important for us to continue 

to have this dialogue with our State and local partners and with 

Congress on this National framework for regulatory consistency, 

and site specific flexibility to ensure that carbon dioxide is injected 

safely for long-term storage. 

This is also a part of the Office of Water’s climate change strategy that we have published in draft form and are anticipating finalizing in the fall. The highlights of the rule, the extensive rule 

that we proposed, Mr. Chairman, are that we are creating a new 

Class VI under the Safe Drinking Water Act’s UIC program, Underground Injection Control Program. Our experiences are based on 

35 years of experience under the existing UIC program, including 

the Class II. As you Mr. Chairman know, in your State, there has 

been significant activity, particularly under Class II for enhanced 

11 

oil recovery. The lessons we learned from that are invaluable as we 

move forward to finalize this rule in late 2010 or perhaps early 

2011. 

Our rule would require that geologic sequestration wells are appropriately located, constructed, tested and monitored. Siting requirements would include provisions for ensuring the site is thoroughly evaluated to ensure CO2 will not migrate to the surface. 

Construction requirements would include provisions that wells be 

constructed with corrosion resistant materials to prevent the well 

from corroding over time. There are also provisions included for 

periodic review of the area around the injection well to allow for 

adjustments as the fluid moves underground. 

Mr. Chairman, a central, fundamental part of the rule that we 

are proposing is monitoring, continued monitoring and testing, both 

for scientific integrity and also public acceptability to reduce the 

potential for any risks from the carbon—geologic sequestration. We 

have also included proposed requirements for financial responsibility to assure the funds would be available for well plugging, site 

care, closure and emergency and remedial response. 

We believe we have developed a framework that will ensure safe 

injection in the present and safe storage in the future. Mr. Chairman, we have a 120 day public comment period that will probably 

begin tomorrow when the rule appears in the Federal Register. 

During that time, I want to assure you that we will be continuing 

our robust collaboration with our State and local partners, with the 

scientific community, with other Federal agencies such as DOE and 

USGS—with everyone to continue to move forward in a positive 

way that does continue to protect underground sources of drinking 

water while also making significant steps towards mitigating 

greenhouse gas emissions. 

Mr. Chairman, I look forward to the testimony of our colleagues, 

particularly Federal partners and also our State and local partners 

who have been working closely with us on this proposal, and I 

would be happy to answer questions as they arise. 

[The prepared statement of Mr. Grumbles follows:] 

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Mr. GREEN. Thank you, and now by unanimous consent, I would 

like to recognize our Chair of the Full Committee for an opening 

statement. 

Mr. DINGELL. Mr. Chairman, I will not accept your kindness, but 

it makes me, nonetheless, grateful. Mr. Chairman, I ask unanimous acceptance my statement be included in the record and I take 

this opportunity to congratulate you on holding this very important 

hearing which is your first as the Chairman of the Subcommittee 

on Environment and Hazardous Materials, and I look forward to 

this being the beginning of a long and successful career in this capacity, as you grow in your service to the people of Texas and the 

United States. Thank you, Mr. Chairman. 

[The prepared statement of Mr. Dingell follows:] 

STATEMENT OF HON. JOHN D. DINGELL

July 24, 2008 

Mr. Chairman, thank you, and I commend you for calling this important hearing, 

your first as Chairman of the Subcommittee on Environment and Hazardous Materials, to focus on the myriad of issues involved in sequestration of huge volumes of 

CO2 in deep underground formations. I congratulate you on your new chairmanship 

and look forward to a close working relationship as the Subcommittee tackles very 

important public health and environmental issues. 

We have distinguished witnesses before the subcommittee today, who can inform 

us as to the availability of storage sites in the U.S., the capacity of such sites, and 

the regulatory framework necessary to protect underground sources of drinking 

water. 

Water is critical to growth and economic development in many areas of the country, and will become even more so in future years. In pursuing the goal of carbon 

capture and storage, a system must be in place that protects the quality of drinking 

water sources and assures the public that this is a safe way to proceed. 

Approximately one week ago EPA released proposed regulations under the Safe 

Drinking Water Act designed to achieve these goals. I look forward to EPA’s testimony and the views of our other witnesses on the adequacy of the proposed regulations and any gaps that remain to be addressed. I thank them for their presence, 

and I thank you, Mr. Chairman, for your vigor and your diligence in addressing 

these questions. 

Mr. GREEN. Thank you. Dr. Burruss. 

STATEMENT OF ROBERT C. BURRUSS, RESEARCH GEOLOGIST, 

ENERGY RESOURCES TEAM, U.S. GEOLOGICAL SURVEY, NATIONAL CENTER 

Mr. BURRUSS. Thank you Mr. Chairman and members of subcommittee for the opportunity to testify today about geologic sequestration of carbon dioxide. My name is Robert Burruss. I am a 

research geologist with the U.S. Geological Survey. This morning 

I will review some basic principles of geological storage of CO2 and 

also assessment methods. I will discuss risks associated with large 

scale storage projects and give you an overview of USGS activities. 

Geological storage of CO2 in oil and gas traps, saline formations 

and coal beds involves injection of liquid CO2 at depths greater 

than about 3,000 feet, displacing the original fluids. In the subsurface, buoyant CO2 rises until it is retained beneath a seal. If the 

seal forms a trap, it will accumulate like crude oil and natural gas 

accumulate in nature. This is called physical trapping. CO2 also 

dissolves in formation, but only to a limited extent, causing solubility trapping. The solution is a weak acid that can precipitate 

new minerals, causing mineral trapping. However, the acid may 

24 

dissolve minerals mobilizing natural, but potentially hazardous 

trace metals and residual organic matter into the formation water. 

CO2 is also highly soluble in crude oil, creating another type of solubility trapping and the drive for enhanced oil recovery. Large volumes of CO2 remain trapped in the reservoir as additional oil is recovered. The value of that additional oil can offset the costs of carbon capture and sequestration. 

USGS develops robust methodologies for consistent assessments 

of National and international resources of oil, gas and coal. As the 

Nation’s lead agency for assessment of ground water resources, 

USGS provides critical expertise to evaluate saline formations. 

Consistent assessment of geologic commodities must distinguish 

well characterized potential reserves from much larger volumes of 

poorly characterized resource. Because oil and gas traps occur within saline formations and because they are the best characterized 

part of the larger formation, they are both—traps and saline formations are related geologically and are analogous to a potential reserve to trap and a resource the saline formation. 

However, evaluation of storage volumes must include properties 

of the overlying seal because the seal is the critical factor affecting 

the risks of CO2 leakage. Evaluation of risks of storage is dependant on the size of full-scale projects and the total volume of CO2

stored as sequestration is fully deployed. For example, a 1,000 

megawatt coal-fired power plant emits about 8 million tons of CO2

per year. Over 50 years the total volume of CO2 stored will be 

equivalent to about 4 billion barrels of oil. The number of traps of 

this size is limited and poorly matched to the location of large CO2

sources. Multiple projects will displace progressively larger volumes 

of water each year, potentially disturbing natural ground water 

flow systems and displacing saline water into near surface environments. 

Also affecting risk is the fact that the surface area above storage 

and saline formations may be as much as 20 times larger than the 

area for equivalent storage above traps. This is due to the fact that 

a much smaller fraction of the pore space is occupied by CO2 stored 

in saline formations than in physical traps. The larger surface area 

increases the effort necessary to characterize risks of leakage and 

to monitor the site during the lifetime of a project. 

Previous USGS studies, collaboration with DOE and State agencies, for example in the Frio Brine experiments, and USGS participation in EPA stakeholder meetings for its current rule making activity, provide new information for us to build a robust assessment 

methodology. The Energy Independence and Security Act authorizes USGS to develop a methodology and conduct a National assessment in cooperation with DOE, EPA and State agencies. Recently, USGS received funding specifically to develop the methodology. That work is proceeding. At completion, an independent nonUSGS panel will be convened for external peer review of our methodology. 

To conclude, USGS is using basic principles of sequestration and 

resource assessment to build a consistent methodology for CO2

storage that incorporates risks associated with sequestration at the 

regional or basin scale. We look forward to collaborating with our 

colleagues in other Federal and State agencies on an assessment 

25 

methodology for CO2 storage. Thank you for the opportunity to 

present this testimony. I will be happy to answer any questions. 

[The prepared statement of Mr. Burruss follows:] 

STATEMENT OF DR. ROBERT C. BURRUSS

Mr. Chairman and Members of the Subcommittee, thank you for the opportunity 

to present testimony on geological sequestration of carbon dioxide (CO2), addressing 

opportunities, risks, and protection of drinking water resources within the United 

States. My remarks will briefly discuss some of the basic principles of geological CO2

sequestration, provide an overview of current U.S. Geological Survey (USGS) activities on these topics, and address some of the fundamental principles of assessment 

of geological commodities that underlie USGS methods, including the types of uncertainties that can affect estimates of storage volume at the regional scale. 

INTRODUCTION

The magnitude of addressing reductions in greenhouse gas emissions necessary to 

impact global climate change is significant because fossil fuel use, the major source 

of CO2 emissions to the atmosphere, will continue for some time in both industrialized and developing nations. Geologic sequestration of CO2 captured from large industrial sources of emissions is one of a number of technologies for carbon management that could be deployed to stabilize the concentration of CO2 in the atmosphere. 

Although geologic sequestration is the topic of this hearing, geologic CO2 sequestration alone cannot achieve the goal of stabilizing the atmospheric CO2 concentration 

at a level that will have a meaningful impact on climate change. The magnitude 

of reductions needed may be on the order of 70 percent or more (IPCC, 2005), requiring all methods of carbon management in addition to geologic sequestration. 

These other methods include terrestrial sequestration, increased use of renewable 

biological sources, electricity generation by solar and wind systems, geothermal and 

nuclear power, increased efficiency in transportation as well as electric power generation, transmission, and end use. 

Over the last nine years the USGS has engaged in several studies to evaluate geological and geochemical factors that improve our understanding of processes occurring during geologic storage of CO2, the potential risks associated with storage of 

large volumes of CO2, and some potential environmental impacts of geologic sequestration. 

The USGS also collaborates with DOE on sequestration projects such as, the 

DOE-lead Geo-SEQ program, a consortium of National Laboratories working on 

monitoring technologies and simulation codes for carbon storage; the DOE-sponsored 

Frio Brine project in Texas; and review of the efforts by DOE to develop several 

large scale field projects throughout the United States. 

More recently, Section 711of the Energy Independence and Security Act (P.L. 110- 

140), enacted into law in December 2007, authorized the Secretary of the Interior, 

acting through the Director of the USGS, to develop an assessment methodology and 

conduct a national assessment of geological storage capacity in collaboration with 

the Secretary of Energy, the Administrator of EPA, and the State geological surveys. 

USGS will collaborate with DOE to incorporate the results of the assessment into 

future revisions of the DOE ′′Carbon Sequestration Atlas of the United States and 

Canada′′. The cumulative advances from these earlier USGS studies and DOE-funded activities provide a basis for developing a methodology to assess the national capacity to store CO2 and understand the potential impacts of large-scale deployment 

of geologic sequestration. 

Subsequent to enactment of P.L. 110-140, the USGS received from Congress funding to initiate a new activity to develop the methodology to conduct a national assessment of carbon dioxide storage capacity in oil and gas reservoirs and saline formations. The USGS has also recently updated its website to promote the dissemination of information and research relevant to this new activity: http://energy.er.usgs.gov/health—environment/co2—sequestration/, and has assembled a 

project team to begin development of the methodology. The USGS will consult and 

collaborate with other organizations, as appropriate, including state geological surveys, the Department of Energy, the Environmental Protection Agency, other bureaus within the Department, and other stakeholders. This will help ensure, to the 

maximum extent possible, an efficient, effective, and coordinated effort. As with all 

USGS energy resource assessment methodologies, an independent non-USGS panel, 

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holder organizations, will be convened to provide a technical review of the methodology. The full methodology is expected to be released by spring 2009. 

BASIC PRINCIPLES OF GEOLOGIC SEQUESTRATION OF CARBON DIOXIDE

Geologic storage involves injection of liquid CO2 into a subsurface rock unit and 

displacement of the fluid that initially occupied the pore space. This principle operates in all types of potential geological storage formations such as oil and gas traps, 

deep saline formations, coal beds, and other rock types. 

At the pressures and temperatures that exist at depths in the Earth greater than 

about 3,000 feet, carbon dioxide is a supercritical fluid with density that ranges 

from 500 to about 700 kg/m3 at the greatest depths considered for storage, about 

12,000 feet below the land surface. Because the density of CO2 is only 50 to 70 percent of the saline formation water, the CO2 will be buoyant and rise vertically until 

it is retained beneath an impermeable barrier, commonly called a seal. If the structure of the seal forms a trap with both vertical and horizontal barriers (closure), 

CO2 will accumulate in the same manner that other natural buoyant fluids, like 

crude oil and natural gas, accumulate by displacing formation water from the geologic trap. This process is commonly referred to as physical trapping. Physical trapping of CO2 involves two factors critical for evaluation of storage risks: the integrity 

of the seal and the total volume of water displaced by injected CO2. The volume of 

displaced saline water relative to the volume of CO2 injected must be understood 

to fully evaluate the potential for leakage, including the potential for contamination 

of drinking water. 

Some of the injected CO2 will dissolve in the subsurface formation water, a process known as solubility trapping. The solubility of CO2 is relatively low, however, 

reaching a maximum of about 5 percent of the weight of pure water, and generally 

less, 2 to 3 percent of the weight of saline water. This means that for complete solubility trapping, each ton of injected CO2 must contact at least 20 tons of formation 

water, possibly much more. 

Another consideration is that dissolved CO2 forms a weak acid, carbonic acid, 

which can react with other components dissolved in formation water. Carbonic acid 

can also react with minerals in the geologic storage formation, either dissolving 

them, or precipitating new minerals, a process known as mineral trapping. The 

acidified formation water may dissolve coatings on mineral grains, releasing trace 

metals and residual organic components to the formation water and to the supercritical CO2, raising the possibility of mobilizing potentially hazardous, naturally occurring materials. This process increases the potential for saline water that is displaced 

from a geologic storage formation to contaminate shallower, potable water supplies 

if the displaced water can migrate to shallower depths. 

If residual oil is present in a storage formation, CO2 will dissolve in the oil as 

another type of solubility trapping. However, CO2 is much more soluble in residual 

oil than in water. In fact, at pressures equivalent to depths of about 5000 feet in 

the subsurface, CO2 is completely soluble in oil (also known as completely miscible). 

This fact, together with the physical effects caused by dissolution of CO2 in oil, including the volume of oil swelling and the viscosity dropping, provides the primary 

mechanism for enhanced oil recovery (EOR) using CO2. When the oil is produced 

from a well, the CO2 dissolved in the oil is separated from the oil, recycled and reinjected to recover additional oil. In the overall process, some injected CO2 remains 

in the geologic formation, equivalent to about 1 ton of CO2 stored for every 2 additional barrels of oil recovered. At current prices for crude oil, this additional recovery is clearly a valuable ′′by-product′′ of potential CO2 storage in depleted oil fields. 

GEOLOGICAL RESERVES, RESOURCES, AND THE ROLE OF THE USGS IN CAPACITY

ASSESSMENT

An assessment of the geological capacity to store CO2 must be based on fundamental principles that are analogous with any assessment of a finite geological commodity such as petroleum or coal. Within the total possible volume of storage, we 

must be able to distinguish potential geologic CO2 reserves from resources (Bachu 

and others, 2007). The resource is the quantity that, based on geological principles 

and available knowledge, may exist within some portion of the Earth. The reserve 

is that portion of the resource for which we have more information and thus greater 

certainty with which we can define a volume that can be evaluated with enough detail to assign a value to the commodity. For clarification, use of the term ′′reserve′′ 

in this testimony is broader and distinct from the term ′′proved reserves′′ which connotes economic evaluation of a known quantity of resource. The current and most 

precise definitions of the terms reserve and resource as they pertain to oil and gas 

accumulations are provided in a 2007 joint publication of the Society of Petroleum 

27 

Engineers, the American Association of Petroleum Geologists, the World Petroleum 

Congress, and the Society of Petroleum Evaluation Engineers (SPE, 2007). In the 

SPE terminology, the USGS assessment will focus on ′′contingent resources′′, a term 

indicating that additional economic factors must be evaluated before a value can be 

assigned, thereby shifting the volume of contingent resource to a reserve. In common usage ′′probable reserves′′ is synonymous with ′′contingent resources′′. 

The USGS has a long history of conducting national and international assessments of natural resources. Given that geologic storage space for CO2 in the subsurface is a finite geological commodity, USGS scientists have the necessary geological expertise to build a robust methodology for assessing geological CO2 storage capacity. This expertise stems in part from many years of experience in conducting 

impartial, scientifically robust oil, gas, and coal assessments where a critical issue 

is the distinction between reserve and resource described previously. 

Equally important in developing an assessment methodology is the significant expertise of the USGS in assessment of ground-water resources. The unique knowledge within the USGS of regional ground-water aquifer systems enables the USGS 

to develop methods to assess potential storage in saline water-bearing geologic formations. Although very large storage capacities can be calculated for saline formations, incorporation of geological and hydrological risk factors that affect these capacities is a challenging and difficult scientific task. These factors are essential to 

defining the portion of the total geologic CO2 storage resource that is actually technically feasible to utilize and may ultimately meet the economic definitions of a reserve. 

CONCEPTUAL FRAMEWORK FOR STORAGE ASSESSMENT

USGS methods for assessment of geological resources focus on evaluations at the 

regional or basin scale where we can define geologically consistent assessment units 

(AU). The application of a consistent methodology across these scales will facilitate 

aggregation of results from all assessment units, providing an overview of the national endowment of storage capacity. For CO2 storage, the description of the AU 

should include information from two types of geological formations, the storage unit 

and the overlying regional seal. The most commonly described formation types for 

geological storage of CO2 are depleted oil and gas fields, saline formations, and 

unmineable coal beds. For each storage type, a sealing formation must accompany 

the storage formation to prevent the buoyant leakage of CO2 from the storage formation to shallower levels or to the atmosphere. The geological properties of the 

sealing formation provide a basis for evaluating the geological risk of CO2 leakage 

from the storage formation that could cause contamination of shallower aquifers for 

potable water supplies or limit the effectiveness of sequestration if stored CO2 can 

return to the atmosphere. The geological risk factors at the scale of the AU are distinct in scale from risks specific to individual CO2 storage sites, where additional 

factors such as the integrity of existing well bores and cement must be taken into 

consideration. 

Although CO2 storage in known oil and gas traps and saline formations are commonly considered as distinctly different types of storage, in most cases they are geologically linked. The physical traps of oil and gas fields occur within almost every 

saline formation under consideration for CO2 storage. Using the distinction between 

reserve and resource described earlier, the physical traps that have retained buoyant oil and gas for hundreds of thousands to hundreds of millions of years are the 

best characterized part of the saline formation in which we understand the integrity 

of the seal and the injectivity of the formation. These areas are typically the most 

well characterized settings for CO2 storage, and in this context can be considered 

analogous to a reserve and the larger area of saline formation adjacent to the trap 

can be considered the resource. 

We can make conservative estimates of storage volume based on the amount of 

oil and gas recovered from the trap. That initial conservative estimate of storage 

volume can increase through additional recovery of residual petroleum with enhanced oil recovery. Ultimately, it may be possible to fill the trap to the maximum 

capacity defined by the spill point of the trap. When a trap is filled to maximum 

capacity, if the saline formation extending beyond the trap is adequately characterized, then injection could continue and storage would ′′spill′′ into the larger volume 

of the saline formation. Alternatively, storage could be initiated in an adjacent trap 

in the same assessment unit or in a different assessment unit. This concept of conservative definition of an initial, well-characterized volume of a geological commodity (in this case, storage volume) that can grow over time as the geologic setting 

of the commodity continues to be evaluated is another way to describe the fundaVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00033 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
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mental definitions of reserve, resource, and reserve growth that will be implemented 

in the USGS assessment methodology. 

Although the geological relationships between the storage properties of the physical traps of depleted oil and gas fields and the properties of the larger potential 

storage volumes within the saline formation of the same assessment unit are clear, 

developing geologically sound mathematical methods to estimate the storage volume 

of saline formations is difficult for several reasons. First, the number of direct measurements of the properties of the storage unit and overlying seal may be very limited. A saline formation may have only one well penetration or no penetrations at 

all within a 100 square mile area. Even if there is one or even several penetrations 

of the formation, the amount of information available for characterization of the 

injectivity of the formation or the integrity of the seal may be limited. The limited 

data availability will not preclude estimates of storage volume, but it will result in 

large ranges of uncertainties in the estimated storage volumes. The largest uncertainties caused by sparse data may be in the uncertainties in risk parameters such 

as potential for leakage and/or the injectivity of the formation. 

Risk parameters can be incorporated into numerical assessments of geological 

commodities such as storage volume in two distinctly different ways. Values can be 

assigned to risks on a standardized scale, the values for all risks totaled, and then 

the calculated volumes can be ranked by total risk. A more rigorous method is to 

assign a probability to each independent risk factor, and then multiply these factors 

to arrive at the overall ′′riskiness′′ of the storage volume. That overall risk factor 

is then used to reduce the calculated volume of potential storage. This method results in probabilistic ranges of storage volumes that can be compared between assessment units within a single basin or between basins and regions. This approach 

is analogous to the process underlying USGS assessments of oil and gas resources 

that we describe as ′′fully risked′′ and is the method we will incorporate in the 

USGS methodology for assessment of CO2 storage capacity. 

Another aspect of CO2 storage in saline formations that impacts our evaluation 

of risk factors is the scale of storage projects and the volumes of CO2 that must be 

injected into storage formations as geological sequestration is fully deployed. The 

CO2 emitted by a single, 1000 megawatt coal-fired electrical generating station is 

roughly 8 million tons per year. If that CO2 is captured and injected into the subsurface, it will displace about 84 million barrels of formation water. Over the lifetime of a single full-scale storage project of this size, for example, for 50 years, the 

total volume of CO2 injected into the subsurface, and the volume of water displaced, 

will be equivalent in volume to about 4.1 billion barrels of oil. This volume corresponds to a ‘giant’ oil field, according to terminology used in describing oil field 

sizes. There are physical traps of this size in the United States, but the number 

is limited. The geospatial mismatch between size of storage needed for sequestration 

projects and the location of large sources of CO2 has been addressed in a USGS report published in 2006 (Brennan and Burruss, 2006). If geologic sequestration is deployed to the extent that the Nation is storing about 500 million tons of CO2 per 

year, equivalent to emissions from 50 to 60 coal-fired power plants of 1000 megawatt size, then we must recognize that the storage process will displace about 0.6 

km3 or 172 billion gallons of formation water each year. Such large movements of 

saline formation water have the potential to disturb regional ground-water flow systems, possibly displacing saline formation water laterally or vertically to near-surface environments where it could contaminate shallower drinking water supplies or 

impact ecosystems. 

The size of storage projects also impacts our concepts for evaluating risks of CO2

storage. Estimates of the total area of a geological storage site will determine the 

area that must be characterized geologically and hydrologically prior to injection, 

monitored during injection, and then continually monitored for sometime into the 

future once the injection phase of the project ends and long-term storage begins. 

However, for the same volume of total storage, there is an important difference between storage in physical traps and storage in saline formations. 

In a physical trap with lateral barriers to flow, injected CO2 will fill a thickness 

of the formation up to a maximum defined by the spill point of the trap. Within 

that interval, CO2 can occupy up to 50 or 60 percent of the pore volume of the formation. In contrast, the CO2 injected into saline formations will rise vertically to 

the base of the sealing formation and spread laterally. Models of this process and 

experience at the Sleipner project in the North Sea show that the total fraction of 

pore space occupied by injected CO2 is small, on the order of 2 to 5 percent, although in some geologically heterogeneous formations this fraction could increase to 

10 to 20 percent. This difference between high efficiency of storage in traps and low 

efficiency in saline formations means that for the same quantity of CO2 stored, the 

surface area above a storage site in a saline formation that corresponds to the spaVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00034 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
29 

tial extent of injected CO2 in the subsurface will be at least 2 times larger to as 

much as 20 times larger than the area above equivalent storage in a physical trap. 

The larger surface area above storage sites in saline formations will increase the 

effort necessary to characterize risks of storage and to monitor the site during the 

lifetime of a sequestration project. 

The focus of USGS evaluations of risks of geologic sequestration is at the regional 

or basin scale where the total volume of storage from deployment of multiple, fullscale projects may have the greatest impact on movement of formation water and 

injected CO2. Evaluation of these risks is dependent on knowledge of the geology 

and hydrology of the regional assessment unit. This analysis of risks is different 

from the risks evaluated in the proposed EPA rules on geologic sequestration where 

the emphasis is on evaluation and mitigation of the risks at the scale of individual 

storage projects. USGS does not evaluate individual projects. However, the regional 

scale risks may impact individual projects. USGS collaboration with EPA on risk 

issues ranges from informal discussions about subsurface fluid flow and area of review with the Underground Injection Control Program, to USGS participation in the 

public stakeholder meetings that EPA held as part of the current rulemaking process. We look forward to closer collaboration with EPA as development of our methodology proceeds and during assessment of storage capacity. 

CONCLUDING REMARKS

In this statement, I have summarized some of the basic aspects of geological CO2

sequestration and described some of the fundamental concepts underlying resource 

assessments that the USGS is employing to develop a probabilistic methodology for 

assessment of CO2 storage capacity in both the physical traps of depleted oil and 

gas fields and in saline formations. In addition, I have discussed some of the concepts of geological risk that must be incorporated into the assessment methodology. 

The present USGS work addresses the activity authorized under Section 711 of the 

Energy Independence and Security Act (P.L. 110-140) to develop an assessment 

methodology that can be applied consistently across the Nation. As noted above, the 

methodology development is being conducted in coordination with a number of organizations to maximize the usefulness of the assessment to a variety of partners and 

stakeholders, including the Department of Energy, the Environmental Protection 

Agency, other Agencies within the Department of the Interior, and State Geological 

Surveys. 

Thank you for the opportunity to present this testimony. I will be happy to answer any questions you may have. 

References: 

Bachu, S., Bonijoly, D., Bradshaw, J., Burruss, R., Holloway, S., Christensen, 

N.P., Mathiassen, O.M., 2007, CO2 storage capacity estimation: Methodology and 

gaps, International Journal of Greenhouse Gas Control, v. p. 430-443. 

Brennan, S. T., and Burruss, R. C., 2006, Specific Storage Volumes: A useful tool 

for CO2 storage capacity assessment, Natural Resources Research, v. 15, pp. 165 

-182, DOI: 10.1007/s11053-006-9019-0. 

Intergovernmental Panel on Climate Change (IPCC), 2005, IPCC Special Report 

on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the 

Intergovernmental Panel on Climate Change [Metz, B., O. Davidson, H. C. de 

Coninck, M. Loos, and L. A. Meyer (eds.)], Cambridge University Press, Cambridge, 

United Kingdom and New York, NY, USA, 442 pp. 

Society of Petroleum Engineers (SPE), American Association of Petroleum Geologists (AAPG), World Petroleum Congress (WPC), and Society of Petroleum Evaluation Engineers (SPEE), 2007, Petroleum Resources Management System, 49 p., 

http://www.spe.org/spe-app/spe/industry/reserves/prms.htm, downloaded July 2, 

2008. 

Mr. GREEN. Thank you. Mr. Klara. 

STATEMENT OF SCOTT M. KLARA, DIRECTOR, STRATEGIC 

CENTER FOR COAL, U.S. DEPARTMENT OF ENERGY 

Mr. KLARA. Thank you Mr. Chairman and members of the subcommittee, and I appreciate this opportunity to discuss, today, the 

Department of Energy’s research program on carbon sequestration. 

My testimony today will, primarily, focus on sequestration capacity estimates. You will see some charts being shown on some background work that we have done that is included in your package, 

30 

but I would be happy to engage any other sequestration topics, as 

well, during the question and answer session. 

DOE has taken a leadership role in advancing the development 

of sequestration technologies. Essentially, we are responsible for 

overseeing the development of the technology base. Through the 

carbon sequestration program, DOE is developing both the core and 

supporting technologies through which carbon sequestration could 

become an effective and economically viable option for reducing 

CO2 emissions. 

A key component to the program are the regional carbon sequestration partnerships. We are funding a network of seven partnerships to help develop the technology, infrastructure, and best practices protocols for implementing CO2 sequestration in different regional settings throughout the Country. The seven partnerships 

that form this network currently include more than 350 unique organizations, universities, private companies, spanning 42 States, 

three Indian nations and four Canadian provinces. Collectively, the 

partnerships represent more than 95 percent of coal-fired CO2

emissions, industrial CO2 emissions, total land mass, as well as essentially all the geologic sequestration sites that have potential for 

storage. 

Relative to the protection of drinking water, a key interest of this 

hearing, a key goal for the sequestration program is the development of technologies that will ensure safe practices. The program 

is addressing the key challenges that would ensure the safe, longterm permanent storage of CO2, including the development of monitoring, mitigation and verification technologies to track the fate of 

the injected CO2. The ultimate success of sequestration will hinge, 

in part, on the ability to measure the amount of CO2 stored at a 

particular site, the ability to confirm that the stored CO2 is not 

harming the local ecosystems and the ability to effectively mitigate 

any impacts associated with this storage. The program is developing the technologies and best practices to resolve these issues. 

Relative to another key interest for this hearing, the sequestration program is working to ensure that adequate storage capacity 

is available for sequestration. Since 2003 we have been leading the 

regional carbon sequestration partnerships to estimate CO2 storage 

estimates in different geologies throughout the United States and 

Canada. Some of those charts you see shown on the side views. 

The first version of the carbon sequestration atlas was released 

in 2006. I show a copy in my hand. The goal of the atlas was to 

provide the first coordinated assessment of sequestration storage 

potential across the majority of the United States and portions of 

Canada, along with the methodologies used. The atlas focused on 

three types of geologic storage, oil and gas, unmineable coal seams 

and saline. The atlas relied on a team of geologic experts and scientists from across the country, including the United States Geologic Survey and representatives from nearly every State Geologic 

Survey. The atlas utilized an extensive set of databases maintained 

by the regional partnerships, USGS, EPA and EIA. 

DOE maintains and analyzes all capacity information used to develop the atlas through a web based geographic system we call 

NATCARB, the National Carbon Explorer. NATCARB is publicly 

available on the web, is the world’s first CO2 source/sink database 

31 

that provides graphical interface to analyze regions of the country 

for CO2 sources and geologic storage locations. NATCARB can be 

viewed as a portal that accesses databases maintained by others, 

for example, the regional partnerships, USGS, EPA, Department of 

Transportation and EIA. Therefore, NATCARB has immediate access to the latest updates on information relative to CO2 sources/ 

sinks and other properties. 

Today, I have discussed the atlas from 2006, primarily. The 

atlas, however, is not a static document, but will be regularly updated as more data and insight are gained. The next updated 

version is due for release in November 2008. I present a draft copy 

here. The drawings you see shown represent information from the 

newer version of the atlas. 

So, in conclusion, DOE’s responsible for developing technology 

base. I have gone over most of our efforts today, relative to sequestration capacity estimates because it was of interest to the committee, and just note that these capacities estimates, along with 

the atlas and NATCARB are going to be critically important contributions to the Department’s program and future updates and enhancements will help pave the way for wide-scale deployment of sequestration technologies. This ends my verbal remarks, thank you. 

[The prepared statement of Mr. Klara follows:] 

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Mr. GREEN. Thank you, and again, thank the first panel. We will 

proceed with our questions. And I will recognize myself. Mr. Grumbles, in his docket the EPA compiled a survey of indemnification 

programs used in other areas. In its rule making, the EPA analyzed liability under Safe Drinking Water Act of Superfund, but I 

am concerned about looking at indemnification without a complete 

picture of the liabilities. For the committee’s benefit, can EPA compile a survey of all the potential legal sources, regarding liabilities 

for carbon sequestration projects, including the State and common 

law liability? 

Mr. GRUMBLES. Mr. Chairman, I know we share your interests 

and concerns about potential liabilities and accountability of the 

owners and operators. We would be happy to work with you, work 

with the committee as we move forward on the rule making and 

get public comments. I know one of the areas—one of the priorities 

for us is to gain a greater understanding of the potential pros and 

cons of different types of liability programs. We make very clear, 

Mr. Chairman, and it is important to restate it here, that in this 

proposed rule making, the real focus is the technical requirements. 

It doesn’t—it is not meant to address liabilities under other statutes or some of the other aspects— questions raised with carbon 

capture and sequestration. It is focused on the UIC program and 

Safe Drinking Water Act, but we would be happy to work with you 

and all your colleagues on the committee to compile information. 

Mr. GREEN. Okay, thank you. EPA regulations currently define 

an underground source of drinking water as an aquifer less than 

10,000 milligrams per liter of totally dissolved solids. The saline 

aquifiers considered for sequestration are higher than that level 

and thus are not currently considered the source of the drinking 

water. However, in many parts of the country, you are suffering 

from water shortages. And does the EPA proposal consider the possibility that some of these saline aquifers that we see on the DOE 

maps may be sources of drinking water in the future when purification technology continues to improve? 

Mr. GRUMBLES. Yes it does, Mr. Chairman. I know you and Congressman Shadegg are also—and others are very interested in the 

potential for reclamation and reuse of ground water as well as surface water, so what we are explicitly doing is calling for public comment on the different standards that we have on the definition of 

underground sources of drinking water from freshwater to saline to 

brackish to brine, because we think it is important. We also know 

and have been working with, and are aware that municipal water 

authorities and others want to make sure that future sources of 

drinking water are not, in some way, endangered by this important 

carbon sequestration effort. 

Mr. GREEN. The EPA rule making states that some injection activities may cross State boundary issues that are beyond the scope 

of this rule making. What are these issues and how will these 

issues be resolved if EPA does not intend to provide for these crossboundary situations, because— 

Mr. GRUMBLES. Well I—Mr. Chairman, I think that is one of the 

subjects that has come up in several of our workshops and I know 

that we are going to continue to review that, as the public comments come in on the proposed rule making. We recognize there is 

42 

a unique role for the U.S. EPA when it comes to trans-boundary 

issues, so that is one that I think we also benefit by close coordination with the committee and others on interstate and trans-boundary issues. 

Mr. GREEN. And on our second panel, we can address some of 

that with the interstate compact commission. Does the EPA have 

adequate staff resources to manage a large increase in the UIC 

permitting due to sequestration, and what are their resources needed in this area? 

Mr. GRUMBLES. Well, Mr. Chairman, we—as part of the President’s budget request, we did request an increase to take into account the growing potential and promise of carbon sequestration. 

We have adequate staff and resources to get the rule proposed. We 

do believe this is a growth area, a great opportunity for the agency, 

but right now, we feel we have adequate staff and support. We also 

are sharing as much and benefiting from the Air Office and the Research and Development Office. We also know that the States have 

significant questions about resource responsibilities and impacts, 

you know, in implementing the rule that we proposed from last 

week. 

Mr. GREEN. My next question of both Mr. Burruss and Mr. 

Klara, some of the testimony today indicates that the sequestration 

combined with enhanced oil recovery could produce 3.8 billion barrels of oil, just on the Texas Gulf Coast. As part of that sequestration assessment will DOE or USGS be able to provide estimates of 

potential recovery reserves from enhanced oil recovery? Is that possible? 

Mr. KLARA. Absolutely, and, in fact, it is being looked at. The 

atlas and the information I present here today does not show enhanced oil recovery potential, but the Department has done some 

recent reports, trying to look just at that and especially in a carbon 

constrained world, where you might have the need to put a lot of 

CO2 underground, and the potential looks pretty large. 

Mr. GREEN. And my last question is, I know your surveys include 

storage capacity offshore, underground formations. Which agency is 

responsible for permitting any sequestration wells that would be 

offshore? 

Mr. KLARA. That might be a better question for Mr. Grumbles, 

but I can say that in the EPA regulations, they do go, I think, 3 

miles offshore and then beyond that it becomes more questionable, 

but I think that might be a good question to. 

Mr. GREEN. Okay. 

Mr. GRUMBLES. I would just say that our interpretation is consistent with Mr. Klara’s that the UIC program, under the Safe 

Drinking Water Act, for sub-seabed sequestration projects in State 

waters, out 3 miles or in some cases 9 miles—the proposed Class 

VI rule would apply to those. We also have responsibilities under 

the Marine Protection Research Sanctuaries Act, which could also 

apply to carbon sequestration, geologic sequestration, sub-seabed 

injection projects in ocean waters and our general counsel’s office 

and our office are looking at that subject too. But, definitely, the— 

in State waters, this Safe Drinking Water Act rule would apply to 

those. 

Mr. GREEN. Okay. Thank you. Mr. Shadegg, questions? 

43 

Mr. SHADEGG. Thank you, Mr. Chairman. Let me begin by saying 

that I think we are operating in kind of a public atmosphere where 

the American people recognize that we had a recent experience 

with a congressionally approved practice that turned out to have 

unintended consequences. 

Specifically, I am thinking about MTBE. We all thought we were 

helping the environment by using MTBE to oxygenate gasoline, 

and for a few years were very pleased with what we had done and 

then we discovered, oh my gosh, we were doing damage to our 

water supply, and we had to reverse all of those policies. And I 

think that is the kind of framework over which the American people will view whatever we do at this point. 

I would like to begin, Dr. Burruss, by asking you, I guess two 

questions. One, to the extent that we are not sequestering carbon 

right now, but we are in fact using it in enhanced oil recovery, are 

we looking at and studying potential environmental damage done 

by that at the present time and evaluating it as a real life lab for 

whether or not there are potential environmental consequences for 

water supplies or for that matter, any other damage to the environment? And, if so, where are we looking at it and what volume of 

data do we have at this point? 

Mr. BURRUSS. Congressman, we certainly have not conducted any 

studies specific to enhanced oil recovery projects for the environment over those fields. However, we do believe that it is an important—those enhanced recovery projects are important laboratories 

for doing—for learning more about the safety of storage and other 

potential environmental risks. I believe some of the partnerships 

may be working on some aspects of that. But, in general, I think 

we have not taken as much advantage as we could of the lessons 

from enhanced oil recovery. 

Mr. SHADEGG. Mr. Klara or Mr. Grumbles, would you like to 

comment on that? 

Mr. KLARA. Well, I guess I will make—the first comment is that, 

certainly, from a technology based standpoint, we are looking at 

nearly any risk you can imagine, and the path forward is to be able 

to quantify and assess those risks and come up with a risk assessment methodology that you can have a very high degree of confidence will result in safe practices. 

And I think, coupled with that, with the EPA’s experience with 

the underground injection code, and the fact putting regulations in 

place that have had some tried and true practice to show that 

things are safe if you follow certain requirements. I think coupling 

these risk assessment approaches we will be coming out with best 

practices and coupling that with the—for example, the Class VI 

guidelines that have just been proposed and modifications, perhaps, to those that, obviously, we need to make sure it is safe, but 

we believe that, from a technology standpoint, it has got to be driven with this technology risk-assessment approach. 

Mr. SHADEGG. Mr. Grumbles, before I go to you, to let you comment on that question, I want to go back to you, Mr. Klara, and 

kind of burrow down a little bit. Would you agree with Dr. Burruss 

that while you are developing these methodologies, we have not yet 

implemented them to look at the impact of CO2 when it hasn’t been 

injected to enhance oil production in current sites? We are not 

44 

doing that. He says he doesn’t think we are taking as much advantage of the opportunity to do that, as we should. I take it, you 

agree with that? 

Mr. KLARA. Well, I think there is, maybe, two parts to that question. The first is, past practices relative to putting CO2 in the 

ground for enhanced oil recovery, I believe have shown themselves 

to be safe, relative to the EPA guidelines. 

Now, if you talk about putting CO2 underground for 10,000 to 

100,000 year storage, now that is a different question. And along 

those lines of questions, I would agree, completely, with your assessment that we need field projects. 

And so, for example, within the DOE program we have 25 geologic field projects underway right now putting holes in the ground 

with small amounts of CO2 to assess just that, and then we are 

leading up to much larger injection projects. And so, for example, 

we have best science practices right now that we are ready to publish, but we are waiting until best practices can be proven through 

many of these field tests. 

Mr. SHADEGG. It is going to be important to me, before I vote, 

to do something like this, which is very important to be able to say 

to the American public, yeah, we made a mistake with MTBE, but 

we have done a better job of vetting this before we started to do 

it, so—and I am assuming, and maybe I am wrong, that looking at 

the fact that we have already done it with enhanced oil recovery, 

not for the intention of storing it, but the interaction between CO2

and these, you know, kind of geological formations where we have 

been putting it is something we should be studying and looking at 

to see, well, does it escape? Can we adequately study where it is? 

And, when it does escape, does it do damage? Mr. Grumbles, did 

you want to comment on that question? 

Mr. GRUMBLES. I just wanted to say a couple things, very quickly. And, one, I agree with everything the witnesses have said. Congressman, we do have quite a bit of experience, this country does, 

on the injection of CO2 underground, and it is through the regulated programs, Class II, UIC regs that EPA and the States have 

carried out 35 million tons a year are injected for enhanced oil or 

gas recovery and we agree that it seems successful and it is a very 

promising approach. 

This rule that we just proposed focuses on long-term storage at 

very large volumes of CO2, different from the enhanced oil recovery 

and we think it is really important to get the public comment on 

the technologies and the extensive monitoring and the literature 

review that will continue to ensure that there is no endangerment 

to underground sources of drinking water, current or future. 

Mr. SHADEGG. Or to other aspects of the environment? 

Mr. GRUMBLES. That is correct, other aspects of the environment. 

Mr. SHADEGG. My time is expired. Let me just quickly comment. 

I am concerned about the fact that the rule does not look at the 

liability issue and I am hopeful that the EPA will, in fact, look at 

liability under CERCLA and RCRA, as a part of informing us, because liability is something we have got to be concerned about on 

behalf of the American taxpayer. 

Mr. GRUMBLES. And I would just say that what it does lay out, 

consistent with the 35 years of our regulatory program for other 

45 

classes under the Safe Drinking Water Act, it does insist upon responsibility of the owner and operator for proper site characterization for injection, for care of the site, for extensive monitoring, and 

for fixing the problem, if there is a problem. 

The issue that is one that the rule does not address, and that I 

think everyone is interested in and having a robust discussion with 

policy makers and scientists is, on other types of liability, longerterm liability after the site has been closed, there is no more monitoring by the owner or operator, there are other environmental 

laws or statutes involved that—that is what the rule doesn’t get 

into, but it definitely does hold owners and operators accountable 

with enforcement provisions to ensure that they remediate, if there 

is a problem. 

Mr. SHADEGG. Thank you. 

Mr. GREEN. Ms. Matsui? 

Ms. MATSUI. Fifty percent of California’s population is dependent 

on groundwater. It is really California’s gold, and we are entering 

an era where we are really being affected by climate change already, so I am looking at all of this and I realize that there is some 

demonstration projects reoccurring in California regarding carbon 

sequestration. One of them is called Rosetta Resources, and I am 

interested in this because it is likely a first step in trying to determine—this is for you Mr. Klara—the safety and effectiveness of 

carbon sequestration in certain geological formations and it will 

only inject a small amount of carbon in comparison to the millions 

of tons that would need to be stored if this technology is to have 

a significant impact on the climate. 

I am interested in whether the trial of this kind can legitimately 

assess the safety concerns we have, including pressurizing faults, 

releasing potentially harmful minerals, changing subterranean ecosystems and acidifying or polluting our groundwater. If such smallscale tests will not be an accurate portrait of the volumes and pressures necessary, what plans are in place to safely scale up these 

tests to generate a more accurate portrayal? 

Mr. KLARA. The first step in the process is to do these smaller 

injection tests like you had indicated with the one in California. 

From there, we certainly agree that you want to go to a larger 

scale, and, at least within the Department’s program, we have several approaches we are taking on that and one is to go forward 

with seven large scale tests, one in each of the regional partnerships throughout the country of at least a million tons or more. 

We also have Clean Coal Power Initiative, and other activities 

that are trying to encourage us to do some larger scale tests. In addition to that, what we do too, is we look at what we call analogs, 

which was alluded to before, meaning that there has been a lot of 

work done for injecting CO2 underground for enhanced oil recovery. 

There has been work done for storing natural gas and natural gas 

storage. And the science community is studying these, day in, day 

out to get the best handle of all the risk possibilities in a future 

where we would be injecting these large volumes. 

Ms. MATSUI. Mr. Grumbles, this Rosetta Project is already delayed, partly because of regulatory hurdles, and how is the EPA 

working with State agencies like the California Division of Oil, Gas 

and Geothermal Resources to assure our constituents that all carVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00051 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
46 

bon capture and storage projects are safe and adequately overseen? 

And, also, will these pilot projects be permitted under the current 

regulations, or be subject to the draft rule being proposed and discussed today? 

Mr. GRUMBLES. Thank you Congresswoman. First, the EPA entered into a memorandum of understanding with the Interstate Oil 

and Gas Compact Commission several years ago to work closely 

with them on areas of mutual interest to ensure environmental 

protection as it relates to oil and gas activities and carbon sequestration has been a part of that. And we have been working closely 

with all of the States that are a part of that effort, and they have 

a specific role with us, in the development of this rule and in reviewing the rule before we finalize it. 

More specifically, one of the questions has come up that we do 

discuss in the preamble to the rule that was proposed and signed 

by the administrator on the 15th is the relationship between the 

Class V experimental well permits and this new Class VI, which 

is the extensive rule. And we describe, in the preamble, that pilot 

projects may continue to be carried out under that Class V experimental well permit as long as they are focused on research and are 

not of a commercial scale. 

What we are learning is that adaptive management means, as 

we move forward to finalize this regulation with enforcement responsibilities to ensure drinking water, underground sources, are 

not endangered. We know that more and more pilot projects, in coordination with DOE and with States, are going to continue. They 

need to continue because they will help inform us about what the 

final contents of the regulation will be. 

So we are going to be working closely with all of the States who 

are involved in this, which is an increasing number. It is very clear 

that States are showing leadership and strong interest in this geologic sequestration effort, too, and we are going to be working with 

them as we move to finalize the rule. 

Ms. MATSUI. Okay, thank you Mr. Grumbles. My time is up. 

Mr. GREEN. Mr. Terry? 

Mr. TERRY. Thank you. I don’t have as piercing of questions as 

my colleagues do, I am just curious, Mr. Grumbles, what are the 

known safety and health risks of CO2 to drinking water? Have we 

already determined that? 

Mr. GRUMBLES. We have a good idea as to the potential risks, 

and the key for us is that with proper siting and well construction 

specifications, and extensive monitoring the risks are not great, but 

the key depends on the siting and the following through on the 

nine or ten categories of extensive requirements that we are proposing in the Class VI rule. 

What are the risks? One of the risks would be that as you are 

injecting the CO2—while CO2 is not a toxic substance, the risks are 

that at such volumes and high pressures, you could be pushing salt 

or other naturally occurring substances into an underground source 

of drinking water. That is one risk. 

Another would relate to the CO2, when it combines with water, 

can create a carbonic acid that can be corrosive, which can erode 

well—the infrastructure of the wells and that could lead to a leak. 

47 

So for us, we wanted to lay out a National framework that has 

very specific, technical requirements to address those various risks. 

We also recognize, Congressman, that over time the potential risks 

are likely to decrease, as long as the proper siting has occurred and 

the proper construction of the well and the proper carrying out and 

operation of the well. 

It is important to underscore to everyone that our regulatory 

framework envisions that these deep injections would be occurring 

at least half a mile or more deep and that there would be multiple 

barriers of containment. 

Mr. TERRY. Is that beneath most ground water? 

Mr. GRUMBLES. That would probably be the case. We are going 

to take comments in the rule making process as to, you know, what 

instances might justify it being above some ground water supplies, 

if there were extra layers of protection and confining rock formations, but it is very deep injection, under very specific geologic conditions. 

Mr. TERRY. All right, once again, I am just trying to get my mind 

around what the specific health hazards to humans are from CO2. 

Mr. GRUMBLES. Well, another could be that, you know, there 

could be chronic or acute health risks, breathing or risks to vegetation that could occur. So we are investing an enormous amount of 

effort in this drinking water—underground injection control regulation to make sure that the CO2 would be properly sited and injected and would stay put and would be extensively monitored to 

try to prevent any type of risks, whether it is to ground water or 

other risks that might occur, but the focus of the rule is on using 

our Safe Drinking Water Act authorities. 

Mr. TERRY. As I understand about CO2, the greatest risk is as 

a greenhouse gas, not necessarily a health hazard specifically to 

humans, so if we can keep it underground, and it doesn’t leach into 

the air, have we solved our CO2 emissions issue? 

Mr. GRUMBLES. Well we recognize that there is a need for a 

broad portfolio of technologies and strategies to successfully mitigate greenhouse gas emissions such as CO2. Carbon capture and 

sequestration is not a silver bullet, but it has significant promise 

and— 

Mr. TERRY. That ace in the hole, I think you said. 

Mr. GRUMBLES. Well we—the Air Office, the EPA Research Office 

in very close coordination with the Department of Energy and, 

yeah, USGS and others, and internationally we are, just like DOE, 

we are traveling and learning from what other countries are doing 

in long term storage sequestration, underground of carbon dioxide, 

and it remains to us a very promising but unproven technology 

that we want to encourage carefully. 

Mr. TERRY. And you were discussing with Ms. Matsui the pilot 

program and what popped into my mind is, I don’t know of too 

many 10,000 year pilot programs. What do you perceive as the 

timeframe it would take to do a proper study of CO2 sequestration 

so we can assure Mr. Shadegg’s and my constituents that we aren’t 

making an MTBE mistake? 

Mr. GRUMBLES. Well, you know, I am going to also ask other witnesses, particularly Mr. Klara, to discuss the pilot projects because 

they have really been taking the lead on the various pilots. 

48 

What we have done, is we have recognized as these 30, or more, 

pilot projects move forward, there needs to be a management 

framework, so we proposed an experimental well permit for these 

research related projects to gather information. Very small scale 

compared to potential commercialization projects that our new rule 

would be addressing. And in terms of the time frames, we, you 

know, the information we have on them is—it is important to gather whatever information we can over a short period of time, in 

terms of the research projects. 

Our financial responsibility provisions, under the Underground 

Injection Control Program typically are for 30 years for financial 

responsibility through site closure. And in our proposed rule we are 

saying, well let us start with a 50 year period, but let us make sure 

that it is not written in stone and that that can be adjusted, significantly, but I would defer to Mr. Klara on the scope of the research 

and pilot projects and the time frame needed for those. 

Mr. TERRY. You are up. 

Mr. KLARA. An obvious key is that we have to use the best risk 

assessment methodologies possible because, as you indicate, we 

can’t be here 10,000 years from now and know what is going to 

happen. In addition to that, what we are doing too is looking at the 

mechanisms that trap the CO2, and so for example, we are finding 

all kinds of interesting things that, literally, in a short period of 

time, years after you inject it, maybe 50 percent of the carbon dioxide is automatically locked up by many physical factors and we are 

looking at maybe accelerating those locking mechanisms, as well, 

as a way to, you know, permanently insure that it will be down 

there, but right now there definitely will be some CO2 that would 

be amenable for leakage and through these field tests we are applying the best risk assessment methodologies we have at our disposal to take a look at 1,000, 10,000 years from now and try to 

make some indication and probabilities relative to the potential for 

leakage from those formations. 

Mr. TERRY. Okay, I am just curious if there is, kind of, a time 

frame where we think we can move safely by taking it from a pilot 

project to, actually, encouraging or even mandating sequestration 

technology on any new coal plants. 

Mr. GRUMBLES. Nothing in this rule from the U.S. EPA is mandating geologic sequestration. Let us be very clear about that. 

What we are doing is laying out the framework for the technical 

specifications and environmental safeguards. 

We also think the key phrase here for Federal Environmental 

Regulation of this is adaptive management, so we have been striving in the proposed rule making to ensure that as the State regulators and as the EPA and the scientists involved in this learn 

more about it, we can adapt specific plans. 

A key part of it, Congressman, is post-site closure, stewardship 

and responsibility and that is another subject that is going to need 

some more discussion, public and Congressional, and in the agency 

experts and extensive monitoring throughout the whole duration of 

the project and ongoing responsibility to remediate if there is a 

problem that were to occur, even after the site is closed. 

Mr. GREEN. I would also like—and maybe in response to Congressman Hill’s questions, you can talk about the expected life of 

49 

CO2 within a formation, and I don’t know if we are talking about 

10,000 years, but that might be something that—but, Congressman 

Hill. 

Mr. HILL. Thank you Mr. Chairman and panel members for 

being here. As a matter of fact, that was going to be one of my 

questions that the Chairman just asked, so why don’t we just start 

off with that? 

Mr. BURRUSS. We know from nature that there are many large 

natural CO2 accumulations that have existed for millions of years, 

that the CO2 has not all leaked out to the surface and the other 

important piece of information that we base all our understanding 

of how CO2 will be stored in the subsurface really comes from our 

experience with producing oil and gas because they are buoyant 

fluids, just as CO2 is a buoyant fluid in the subsurface. So that 

what we know about the processes that have retained oil and gas 

in the subsurface for many millions of years also apply to the retention of CO2 in the subsurface. 

Clearly, we have to have monitoring protocols and a number of 

issues we have to evaluate, but the fundamental principles of trapping and retention really come from what we know about oil and 

gas, and so I—from a geologists point of view, I think if we do it 

right, it is going to stay there for hundreds of thousand and millions of years. 

Mr. HILL. What about in the event of an earthquake or something, would that change the reality? 

Mr. BURRUSS. Clearly there is some risk that in an earthquake— 

a faulting event at the storage site could release CO2, there is no 

question that that could happen, but even one question I pose to 

my colleagues in California who work on CO2 sequestration and oil 

and gas resources is, you know, how many oil fields do we know 

leak during earthquake events in historic periods in California? We 

don’t see that happen, so if we are careful we believe we can do 

this right. 

Mr. HILL. Okay. I am trying to get my arms around how far 

along we are as it relates to sequestration. I had an environmental 

group in my office yesterday that it says it is not being done, 

shouldn’t be done. I have been working with a company in southern 

Indiana, where I represent, that wants to change coal to gas and 

then sell the carbon to an oil company in Texas to sequester and 

to extract that oil. Mr. Grumbles, you indicated that there are, 

presently, 35 million tons now being sequestered. Is that on an annual basis? How far along are we? 

Mr. GRUMBLES. That is an excellent question and the first thing 

I would say is not sequestered, but injected underground for enhanced oil recovery under the Class II Safe Drinking Water Act 

Underground Injection Control Program. 

Then the question is, aside from that more focused use of CO2, 

injecting it underground to enhance oil and gas recovery, what 

about long-term storage? You know the sequestration where you 

are mitigating greenhouse gas emissions by putting the CO2 underground, and on that respect it has not—I know of—there are two 

sites in the U.S. where it is actually occurring. One in Texas and 

one in Michigan and about 30 or so sites that Mr. Klara and the 

Department of Energy can engage and describe in greater detail. 

50 

Internationally, there are some pilot projects and some larger 

scale, close to commercial-scale carbon sequestration projects, but 

as the Intergovernmental Panel on Climate Change said, I—you 

know, it is a very promising but unproven technology in terms of 

large-scale commercial, you know commercial size projects for— 

Mr. HILL. But there are some commercial places in the United 

States and around the world that are sequestering and using it. 

Mr. GRUMBLES. I would defer to them on the—in terms of the difference between commercial scale and larger than a pilot project. 

Mr. KLARA. Right now, worldwide, there are three projects that 

could be viewed as commercial scale operations going to continue 

for as long as they need to continue for those operations, and 

viewed as being sequestration. 

In the United States, all projects to date have really been pilot 

projects, just studying the concept, studying the phenomenon, relative to sequestration and when you indicate, well when is it ready, 

there is some subjectivity to that. But I will give you my comments 

on it, in that right now I don’t think it would be difficult to go 

around the world with some of the best oil companies and say, can 

we find 10 sites that would be good for sequestration? And hence, 

that is why there are some commercial operations already in place, 

worldwide. 

But if sequestration is truly going to have the potential impact 

it would likely need to have as a climate mitigator—CO2 mitigator, 

we would need hundreds to thousands of deployments. So what we 

are doing from a technology development standpoint within the Department is saying, well, yeah, there are some projects, right now, 

around the world you can use all this oil and gas expertise from 

large companies and make it happen. 

What we are doing is slowly trying to work the technology base 

in best practices to the point where we can then say, yes, it can 

be done at hundreds of sites, and so it, definitely, is an option that 

we should consider on a wide-scale deployment. And, right now, we 

have a timeline toward the year 2020 with a lot of metrics—technology metrics, in that, it would say that if all is successful, by that 

time, we feel that we will have a set of best practices, set of regulations like the stuff that are merging out of EPA, that would probably be the time frame where you can say, well wide-scale deployment of this probably can, now, occur in both the United States 

and the world. 

Mr. HILL. Okay, let me clarify some things that have been said 

so that I understand, exactly, what you are talking about on sequestration. You mention, Mr. Grumbles, that presently we are 

using the carbon to extract oil in some places in the United States, 

and about 35 million tons have been sequestered as a result of that 

technology being used to extract oil. Is that—are you saying sequestration is— 

Mr. GRUMBLES. Sequestered, in my mind, is a good word for 

long-term storage. And this is—it is being used instead, as a tool, 

to help enhance the oil recovery. It is really not being sequestered. 

Mr. HILL. Okay. I don’t know how much time I have Mr.—oh I 

see I have got the green light still. Mr. Grumbles, you indicated 

that—or in your testimony, you said that 15 percent to 55 percent 

51 

reduction over a certain number of years. Could you clarify what 

you were talking about there? 

Mr. GRUMBLES. I can say that that was the findings and conclusions of the Intergovernmental Panel on Climate Change. It wasn’t 

EPA but, I mean, we wouldn’t disagree with that assessment. The 

statistic is being used to try to give policy makers a sense for the 

potential for carbon capture and sequestration to be used as a tool 

to mitigate greenhouse gas emissions. 

Mr. HILL. Okay, so that 15 to 55 percent reduction, you are talking about reductions in the atmosphere? 

Mr. GRUMBLES. That is correct. 

Mr. HILL. Okay. Mr. Burruss, you talked about that the seal is 

the critical feature in making sure that we trap this carbon, could 

you expand upon that, somewhat? 

Mr. BURRUSS. Yes, Congressman. Mr. Grumbles mentioned barriers and other things. Basically, the seal is a geologic formation 

that we commonly refer to as shale, in some cases and an evaporite 

or carbonate, but a rock that is impermeable to flow of fluids so 

that fluids do not go from some deeper level up to shallower levels 

through that barrier. In the hydrology community we refer to those 

as aquatards or aquacludes that prevent flow across that rock unit. 

And so, in what we envision as a storage unit or assessment unit 

is the actual geologic unit in which the CO2 is injected and then 

the overlying rock that is—that prevents any vertical flow of the 

stored CO2 or of formation water that is displaced by that CO2. Mr. HILL. Okay, I see my time has expired, but I do have one 

last question. And Mr. Klara, you talked about the seven regional 

partnerships that you want to put in place, correct? 

Mr. KLARA. Yes, they are in place. 

Mr. HILL. Does that replace the FutureGen project? 

Mr. KLARA. No, it does not. FutureGen or any other large project 

would be complimentary to that. And probably, a distinct difference 

would be with the partnerships. They are focused, primarily, on the 

storage aspects and not the capture aspects at a power plant, and 

a thing like FutureGen or the Clean Coal Power Initiative, what 

that brings is the integration of capture at a power plant with the 

storage site. 

Mr. HILL. Okay. Thank you, Mr. Chairman. 

Mr. GREEN. Thank you, this gentleman’s time expired. Mr. 

Radanovich. 

Mr. RADANOVICH. Thank you Mr. Chairman, and thank you for 

this hearing. I represent the area in California, along with Ms. 

Matsui, that long strip in the central valley, and she is right. In 

California it is all about water. I am interested, Mr. Klara, in the 

depth of that saline water and is it as brackish as ocean water, and 

how much is there there? 

Mr. KLARA. The determination, right now, on that is from an 

EPA ruling and you may have heard this 10,000 parts per million 

to total dissolved solids, but just— 

Mr. RADANOVICH. I heard 10 grams per liter. 

Mr. KLARA. Well, 10,000 parts per million, yeah. And so right 

now that is the requirement that we use to analyze whether you 

should even attempt to look at that saline formation as a possible 

sequestration option. We have the ability to, certainly, change that 

52 

parameter and do a reassessment, as appropriate, but right now we 

are using that as the guideline to say, what are potential targets 

of saline formations, based on that ruling to say that that water 

is very, very brackish, more brackish than sea water, typically. 

And, so those are the target formations under consideration right 

now. 

Mr. RADANOVICH. And a sense of how many acre, feet or gallons 

that area represents? Any care to guess? 

Mr. KLARA. Huge, massive. 

Mr. RADANOVICH. Huge. 

Mr. KLARA. Yeah, for example, with sequestration, it is likely 

and it depends on how the shares made throughout the world, in 

terms of mitigation reductions, but we could be looking at several 

great lakes worth of volume of carbon dioxide. It is miniscule, compared to the volume of saline water that is underground at these 

levels. 

Mr. RADANOVICH. Can you tell me how deep that layer is? 

Mr. KLARA. It varies throughout the country, but typically these 

will be greater than 5,000 feet deep, so half a mile-ish or more, 

deeper. And, in some cases, several miles, so these are very, very 

deep formations. 

Mr. RADANOVICH. Okay, all right, and perhaps someone, I am not 

sure who can answer this question, but it seems to me that you are 

talking more about it in terms of groundwater, freshwater, groundwater pollution. This sounds like it is more of a—the potential hazard would be a displacement issue so that either the brackish saline water would be injected into the freshwater systems or, in the 

cases of oil, that oil itself would be—or CO2 would be injected into 

freshwater. Is that a pretty fair assessment that possible problems 

would be contaminations of those three things? 

Mr. GRUMBLES. I would say one of the risks is that the CO2, not 

as a toxic contaminant, but in large volumes with great amounts 

of pressure, could be pushing, displacing other substances such as 

salts or other contaminants, or naturally occurring substances into 

the underground sources of drinking water. It is also very important for us to ensure that the CO2 stream, that is injected, is as 

pure as possible. 

I think you are right, Congressman, that is one of the risks that 

we see to—although I would say it is a low risk—if the siting and 

the monitoring and technical specifications are met that are in our 

proposed rule. The risks are displacement of other fluids that 

would, ultimately—or could get into a potential or current sources 

of drinking water. 

Mr. RADANOVICH. Mr. Grumbles, you had mentioned a little earlier that, you know, we are talking 10,000 years or that is appears 

that the potential hazard diminishes over time because, I guess, 

nature underground adjusts itself. Is that what you—to the high 

pressure and it stabilizes over the long-term, or at least that is 

what you are experiencing or seeing? 

Mr. GRUMBLES. That is what our observations are. I would defer 

to others for more scientific explanation, but I think that is the 

case. If after a certain period of time the plume has stabilized, then 

the chances are good that the risks would continue to decrease of 

it further mobilizing because of chemical or natural processes. 

53 

Mr. RADANOVICH. Do we have any evidence that sequestered carbon, at those depths are leaking, venting out somewhere now? I 

mean, does that occur in nature that—there are massive amounts 

that are locked up, I know, but is there a place on earth where, 

you know, it comes out of a volcano or something like that? 

Mr. BURRUSS. Congressman, yes, there are many places in the 

world where there are natural CO2 vents, commonly associated 

with volcanic activity or geothermal activity. In sedimentary basins, it is more common that the CO2 is actually trapped, just like 

natural gas, I mean the naturally occurring CO2, so we know that 

process happens and would prevent leaks. But there are, in fact, 

places in the world where naturally leaking CO2 is a hazard to 

human health or ecosystems or, certainly, alters ecosystems, so we 

are learning from that information, as well. I mean the issue of 

natural analogs of, not only storage, but also of risks associated 

with leakage is coming from the geologic community. 

Mr. RADANOVICH. In California, there is not a lot of coal out 

there and we depend, primarily, on natural gas for the generation 

of energy. If that potential shows in California, does that mean we 

can become a clean coal burning State? Does that mean that there 

is a pipe in the ground for every coal burning, electric-generation 

plant, or does that mean we are victim to the CO2 pollution of Nebraska or Arizona or Texas? 

Mr. KLARA. Well, I think that sequestration, unfortunately, is 

often thought of as a coal-based issue, but all fossil fuels, including 

natural gas, release significant quantities of carbon dioxide so my 

guess would be that in a carbon constrained future, that places like 

California would be very interested in doing something with CO2

emissions from sources like natural gas. 

Mr. RADANOVICH. Okay, it kind of broadens the energy sources 

that we have in order to generate electricity and such, right? 

Mr. KLARA. Right. 

Mr. RADANOVICH. Okay, very good. I appreciate this panel. It is 

a very fascinating subject. Thank you very much. 

Mr. GREEN. Thank you. Our next questioner is Congresswoman 

Solis, I am going to ask you would take the Chair just for a few 

minutes. 

Ms. SOLIS [presiding]. Thank you and I apologize, also, for coming in late and missing your testimony, but I do have some concerns, as well. And I think some of my colleagues on our side of 

the aisle, especially coming from California, the issues of keeping 

our water tables clean, as possible, and the amount of time and effort that the EPA has already put into keeping our water safe for 

drinking water. But my concern is the limitations. 

I mean, the technology is clearly, we are looking at, but also the 

limitations that that might have, and my concern is while carbon 

dioxide may not be harmful in the atmosphere, as much as Mr. 

Grumbles has stated, when it does come in contact with water, it 

can become very corrosive and if there are other elements that are 

found in that sequestration, such as lead or arsenic, that can become very problematic. And I would like to hear a little bit about, 

you know, your response to that, Mr. Grumbles. 

And I have some particular questions because in California we 

also have a very, I think, important issue going on there where we 

54 

are going through a drought. We are very concerned about preserving our water and we are looking at various storage facilities 

there, and because we are such a volatile area in California, with 

respect to earthquakes and I know that Mr. Klara might be able 

to speak about this, that there is preparation, also, for the big one, 

and we have had presentations before other committees to talk 

about what our preparation would be and what that would mean 

if there were a 7.9 earthquake and if I look at your map here, for 

California along the San Andreas fault, a potential for sequestration is pretty much along the fault line so I have concerns about 

that. 

So, I will start with you, Mr. Grumbles, actually. 

Mr. GRUMBLES. Thank you Congresswoman. A couple of points I 

would make are responses to those very legitimate, valid questions 

and concerns. One is, it is very important to us to insure that the 

CO2 stream is as pure as possible, and so we have, in this proposed 

rule that the administrator just signed, we have defined it to exclude hazardous wastes for purposes of this carbon sequestration 

injection program, and we are also working with the Air Office as 

they continue to pursue technologies and issues associated with 

carbon capture in the Department of Energy. 

It is very important, also, to emphasize the upfront, critical component of site characterization. That is the very first piece of the 

new regulatory framework we are proposing, and that is to put an 

extensive effort into proper characterization of the risks of a geologic setting and the area of review for potential movement of the 

plume. And so places that might be subject to earthquakes or volcanos or other—might have other various fractures are questionable and would require extensive analysis and modeling, because 

the key for us is safe and effective injection and containment of the 

CO2. 

Ms. SOLIS. If I can, Mr. Grumbles, I know that existing rules, 

right now, which apply to Class I wells and the injection of hazardous wastes in Class II wells enhance oil and recovery, appear 

to have owners and operators as remaining liable in perpetuity, but 

unlike this new proposed rule, we are placing a 50 year limit on 

that. And I wonder, then, who bears a financial responsibility after 

those 50 years? 

Mr. GRUMBLES. We are seeking comment on 50 years. I wouldn’t 

say it is a 50 year limit. It is a suggested time frame and the way 

it would work, Congresswoman, is that after a 50 year period of 

monitoring the site, and this is after the actual injection of the 

CO2, it is for a 50 year period after the injection—continue to monitor the site. 

It would also say that if continued, further monitoring is going 

to cease by the owner or operator, the owner or operator would 

have the burden to demonstrate to the director, to the regulator 

whether it is the State regulator or the EPA Federal regulator, 

that there would be no further movement or endangerment of that 

plume. The director would, then, be able to adjust that 50 year period, could make it longer, so it can change in various ways. It is 

meant for us to start the dialogue and the discussions and you get 

the public comments on what is a timeframe that owners and operators can get a sense for some upfront certainty as to where the 

55 

technical requirements are going to go and what their responsibilities will be. 

Ms. SOLIS. I realize that some members on the panel have already asked about longevity, what happens after 100 hundred 

years, and what have you. I am very concerned about, again, contaminants that would have a corrosive effect on, even, the lining 

of these particular contained areas. And if there is movement how 

do you project that 10 years after, you know 60 years, that there 

is movement and that there is a leakage. And, then also with respect to your jurisdiction, if something does then expose itself to 

our atmosphere you clearly don’t have any jurisdiction there. 

Mr. GRUMBLES. In our proposal, we are suggesting that there be 

continuous monitoring and testing for movement of the plume. Not 

just upfront predictions of where it might go, which would be—all 

of that would be, you know, the adequacy of the site characterization and the area of review—risk characterization will all—those 

are all going to be critical as to whether or not a permit would be 

issued, in the first place. But even after it does, our proposed regulations lay out, what I believe is, an extensive array of requirements for continuous updating, in terms of the response and monitoring to follow the plume and take corrective action if, for some 

reason, there was a leakage along the way. You mentioned 

corrosivity. That is an area of concern for us too, Congresswoman, 

and we think it is important to make sure that there are no leaks 

or spills or movement of the CO2 once it is injected. 

Ms. SOLIS. My time is up, but I will hand over some other questions to you and the other panelists. 

Mr. GRUMBLES. Thank you. 

Ms. SOLIS. With that, I would like to recognize Mr. Pitts from 

Pennsylvania. 

Mr. PITTS. Thank you, Madam Chair. Mr. Grumbles, you mentioned the 35 million tons of CO2 injected annually for enhanced 

oil recovery and that that is done under your authority with the 

Underground Injection Control Program. I am trying to understand 

the magnitude of this. If you could translate that into a corresponding volume, 35 million tons, what kind of a volume are we 

talking about? 

Mr. GRUMBLES. Well, I don’t think I can. I can turn to staff. I 

will also be able to turn to the other panelists, either on this panel 

or on the second panel who can translate that into a volume. One 

thing that I wanted to emphasize, Congressman, is that 35 million 

tons is a huge number compared to the amount of CO2 that has 

been injected for purposes of carbon sequestration, to date. We are 

still all experimenting with that and as Mr. Klara has pointed out, 

the long-term capture and long-term storage of CO2 is very small 

compared to that 35 million tons. 

Mr. PITTS. Mr. Klara, can you clarify? 

Mr. KLARA. Yeah. A large power plant would put out around 8 

million tons per year of carbon dioxide, compared to the 35 million 

that we are injecting for all of enhanced oil recovery. And just to 

give you a sense of the volume, 1 million tons of that 35 million 

would take up the volume of about the Empire State building. So 

it is about 35 Empire State buildings that are being put underground, relative to volumetric standpoint for enhanced oil recovery. 

56 

Mr. PITTS. Okay, and Mr. Grumbles or Klara, what is the source 

of that CO2? 

Mr. KLARA. The majority of that CO2 is natural CO2 taken from 

existing CO2 reservoirs, at select locations throughout the United 

States and so the majority of that is natural CO2 that is taken up 

from underground. 

Mr. PITTS. How would you compare the purity of that CO2 with 

what we would expect to derive from a coal-fired plant—power 

plant using carbon capture technology? 

Mr. KLARA. Well, certainly, there are some CO2 requirements for 

pipeline flow relative to corrosivity and issues that impact pipeline 

integrity. And the carbon dioxide capture from a power plant, we 

believe, would be at least that pure, relative for sequestration purposes. Now, as pointed out earlier, there are some trace components that we are studying, as well, to see if there is any impact 

of those. Right now those trace components are not issues relative 

to pollution or relative to hazardous emittance, but underground 

we are trying to be careful and study the chemistry and the physics 

of the flow just to be darn well sure that there is no impact from 

those trace components. 

Mr. PITTS. Now, Mr. Grumbles, you mentioned several sites that 

you have selected for this. How did you choose those sites and what 

were the criteria you used in choosing them? 

Mr. GRUMBLES. I don’t believe we chose the sites. We have been 

in a supportive role with Department of Energy and with others. 

What we have done, is we have laid out our suggestions on a management framework for safe and effective carbon sequestration. 

Mr. KLARA. Yeah, what we have done is, primarily through our 

regional carbon sequestration partnerships, is for years they have 

been evaluating potential sequestration locations as evidenced by 

some of the pictures you see on the posters and on the screen. And 

what we have done is develop understanding and characterizing 

where these storage locations were for several years and then when 

we started to get to the point of putting some small-scale projects 

on the ground, we picked some of the better, more likely locations 

that could be amenable to large-scale sequestration. And, so in a 

nutshell, that is how we selected. 

Now along with that selection process, we have been following, 

even more extensively because it is a research project, than the 

guidelines proposed by EPA, so these have been, truly, science 

projects where we are throwing a lot of science, relative to risk and 

care, at these projects to ensure that we completely understand everything that is going on underground. 

Mr. PITTS. Now, you mentioned 35 million tons of CO2 injected, 

annually. How many years have you been doing this? 

Mr. GRUMBLES. Since the Class II UIC program, which has been 

about 35 years. 

Mr. PITTS. And you put this down with great pressure. What 

kind of pressure are you talking about? 

Mr. GRUMBLES. Go ahead. 

Mr. BURRUSS. Congressman, the pressure that—it is injected—at 

the surface, that pressure may be on the order of 2,000 PSIs, it is 

the pipeline pressure, but the—in the subsurface, it is the pressure 

that naturally occurs in the earth, in the oil and gas fields in which 

57 

it is injected, so it may be, you know, on the order of, you know, 

5,000 pounds per square inch, or less or more, depending on the 

depth. But it is, basically, at the natural pressure. It doesn’t raise 

the pressure, and if it does, those pressures are carefully monitored. 

Mr. PITTS. So you are putting it down into voids, or are you pressuring it into— 

Mr. BURRUSS. No, you have to—just to explain, enhanced oil recovery, in some respects is a large recirculation system. CO2 and 

water are injected, oil and water and CO2 come back. The oil is 

taken out, the CO2 is collected and the CO2 and the water are reinjected, so that process continues to circulate. 

There is, basically, because oil and water were removed prior to 

CO2 injection, there is no new volume that is necessary during 

EOR, in general. However, a lot of that is—essentially all the CO2

that is injected stays in the formation unless it is removed by either venting or putting it back into a pipeline. 

So, to come back to your question about 35 million tons a year, 

there are individual fields in west Texas that already have 50 million tons stored in them because injection has been going on for 30 

years. So we have to keep in mind, there are some pretty large volumes in the ground that we put there. 

Mr. PITTS. My time is up, thank you. 

Mr. GREEN. Ms. Schakowsky? 

Ms. SCHAKOWSKY. Thank you, Mr. Chairman. First let me apologize to the panel. There are other hearings going on, and so we are 

running back and forth here. Mr. Klara, is the 3 year carbon sequestration project in Decatur with Archer Daniels Midland, with 

ADM, one of the 30 you are talking about? 

Mr. KLARA. Yes, in fact, that one would be in addition. The 25 

geologic tests are small-scale tests, relative to several thousand 

tons of carbon dioxide. But Decatur is a large project with a million 

tons. 

Ms. SCHAKOWSKY. Okay, I am sorry and 3 years meaning, is that 

the entire project or you are just going to monitor it for 3 years, 

or how does that work? You fill up in 3 years? 

Mr. KLARA. Yeah, the length of the project is somewhat scientifically arbitrary, in that we want to make sure that we put a large 

enough volume underground that it is representative of what a 

large power plant might involve. And then what we do is once we 

get that volume underground, which in this case would be, roughly, 

a 3 year-ish period, we then monitor it for many years to understand the fate and the flow of the CO2, our modeling, et cetera, et 

cetera, just to make sure that we really understand exactly where 

the CO2 is going and what is happening. 

Ms. SCHAKOWSKY. Now I know CO2 is CO2, but is there a difference in the technology if it is an ethanol plant, if it is a power 

plant, if it is an oil site—recovery site, or anything? 

Mr. KLARA. Yeah, it is likely that there will be no difference. 

There may be some cases where, for example, CO2 derived from 

maybe a power plant might have some trace components that an 

ethanol CO2 would not have. Thus far we have not found those 

trace components to be of any consequence, but we are still studyVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00063 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
58 

ing those, but in general we do not envision it being different from 

any of those sources. 

Ms. SCHAKOWSKY. And so what is going to happen to the CO2

once it is injected? Eventually, does it get capped or— 

Mr. KLARA. Well, certainly you are not going to pick a formation 

unless you are sure that it has a lot of cap layers that would prevent the CO2 from migrating, so that is a key factor to determine 

where you put the CO2. In an example that you are presenting, 

those studies have been done to show that that is a very amenable 

formation that is capped. What we know, also, is after you inject 

CO2 that with time, much of the CO2 gets locked up by natural 

processes. 

Ms. SCHAKOWSKY. What does that mean? 

Mr. KLARA. What it means, for example, is it will get absorbed 

in the water. For example, it will turn into carbonate rock from 

mineral reactions and some capillary forces will stop some of the 

CO2 from migrating. 

Ms. SCHAKOWSKY. Mr. Terry was asking about the water. When 

you say it is absorbed in the water are we talking about aquifers? 

Mr. KLARA. Well, these are salt formations—salt water. And salt 

water of such an extent that EPA has determined that, at least 

right now with technologies, they would never be considered for 

drinking water purposes. And so those are the target formations. 

It is a salt-briny water. 

Ms. SCHAKOWSKY. How is this similar or different from the 

FutureGen project that we have been considering? 

Mr. KLARA. We have several components in the program to demonstrate and prove the technologies. Relative to our partnerships 

and the case you point to in your State, that is looking at the storage side, primarily. But also there is the capture from a power 

plant side that we want to link with the storage, and so efforts like 

FutureGen and the Clean Coal Power Initiative are what bring 

that integration together. So there is all the storage issues where 

we are putting CO2 in the ground and then there is the integration 

with power facilities and that is where a FutureGen or a Clean 

Coal Power Initiative would come into play. 

Ms. SCHAKOWSKY. So what is the status of that project? And by 

the way, Dr. Burruss, if you want to add to this, because I am sure 

you are involved, and then the benefits. 

Mr. KLARA. The status of which? 

Ms. SCHAKOWSKY. The project, the ADM project. 

Mr. KLARA. Well the status of the ADM project is that we are 

under cooperative agreement. All the, you know, government paperwork is in place. The funding is in place and right now they are 

doing an assessment of the area, starting to buy the facilities. So, 

for example, CO2 compressor, et cetera, and with the schedule 

being, I think, injection in calendar year 2009. 

Ms. SCHAKOWSKY. So that is when we actually begin to—what do 

you have to, dig the hole, basically? 

Mr. KLARA. Well, yeah, exactly. So, right now, for example you 

have to drill wells. You have to get piping at the surface to transport the CO2. You have to get a compressor so there is all these 

equipment purchases and equipment designs that have to be done. 

Plus reservoir modeling to make sure that we got a handle of the 

59 

best place to inject, et cetera. And that, typically, right now will 

take us, probably, the rest of this calendar year. 

Ms. SCHAKOWSKY. All right. 

Mr. KLARA. Before we would begin injection at that project. 

Ms. SCHAKOWSKY. Okay, thank you. I am just about out of time. 

I thank you. 

Mr. GREEN. Congressman Butterfield. Questions? 

Mr. BUTTERFIELD. Thank you very much, Mr. Chairman. Thank 

you for recognizing me. You look mighty good in that chair and I 

look forward to working with you as we go on. 

Mr. GREEN. I want to thank everybody, I appreciate it, so thanks 

for your comments. 

Mr. BUTTERFIELD. Thank you. One of the worst things is to come 

into a subcommittee hearing late and start asking questions not 

knowing whether the questions have been previously asked. And so 

I have some written questions that I would like to go through and 

hopefully they have not been asked before I get here, but Mr. 

Grumbles thank you very much for coming back to the committee. 

I recall when you were here before and it’s good to see you here 

again. 

Mr. Grumbles, I wanted to ask you about gaps, or potential gaps 

in the EPA’s authority to regulate injection activities for carbon sequestration. Is there a gap in EPA’s authority to regulate releases 

of CO2 coming up from an injection well or a sequestration project 

back to the atmosphere. Do you perceive any gaps? 

Mr. GRUMBLES. Well, what I know is that as we proposed the 

rule, we wanted to make very clear that the rule does not include 

items outside the scope of the Safe Drinking Water Act authority, 

so as we proposed the rule and the administrator signed it on the 

15th, in the discussions accompanying the rule, we point out a few 

things, Congressman, that get to the gap question. 

One of them is that we recognize that a very important part of 

the public discussion is risks that might occur beyond, just, risks 

to underground sources of drinking water, so potential releases to 

the air or the environment, in some way, really don’t come within 

the regulatory program or authorities under the Safe Drinking 

Water Act. However, we do point out, Congressman, that we do 

have the authority to include air surface, or subsurface monitoring 

for purposes of gauging whether or not the CO2 plume is moving 

in some way or shape or form where it shouldn’t be. So there is 

going to be some discretion for the director to require some monitoring that could include air surface—air monitoring. 

We also point out that the regulations and the Safe Drinking 

Water Act do not include or contemplate transfer of liability or indemnification programs. So we point that out as an area for discussion for policy makers. And also in the context of financial responsibility, the focus of our programs, which is technically under the 

Resource Conservation and Recovery Act that we have been using, 

Congressman, for the history of the underground injection control 

program, is to include financial responsibility provisions relating to 

those various classes of injection. 

For this proposed new class, this Class VI, for long-term storage, 

deep injection underground of CO2, we do include some financial 

responsibility requirements, but we raise the question for public 

60 

discussion about—what about longer term financial responsibility 

after the site is closed and, you know, also relates to other types 

of risks, so those are some of the areas that we think it is important for Congress and for the public to comment on. 

Mr. BUTTERFIELD. Let me read to you a quote from the proposed 

rule. I believe it comes from page 28, according to staff. The quote 

is, ‘‘However, regulating such surface atmosphere releases of CO2

are outside the scope of this proposal, and SDWA authority.’’ Is 

that an accurate quote from the rule? 

Mr. GRUMBLES. Yes, that is, and that is an accurate view of the 

legal authorities, but it is also, as I mentioned, it is important to 

us and it is included in the text of the rule that there—that the 

director has the authority to require monitoring for potential releases to the air—surface releases if it is in some way connected 

to a potential risk of underground source—underground drinking 

water supplies. So there is extensive monitoring required but it is 

a fair statement and it is certainly something that we would stand 

by as pointing out an area for further discussion with Congress and 

other policy makers. 

Mr. BUTTERFIELD. All right, thank you. I yield back. 

Mr. GREEN. Thank you. This concludes our first panel, and again 

thank you for being here and appreciate the information, and again 

each committee member has a right to submit questions and we 

will submit them in the future. Our next panel, if we can change 

as quick as we could, I would like to welcome our witnesses and 

while you are coming up, I will introduce you. Lawrence Bengal, 

Director of the Arkansas Oil and Gas Commission on behalf of the 

Interstate Oil and Gas Compact Commission; Don Broussard, 

Water Operations Manager for Lafayette Louisiana Utilities; Ian 

Duncan, Associate Director of the Texas Bureau of Economic Geology with the University of Texas; Scott Anderson, Senior Policy Advisor for the Environmental Defense Fund in Austin, Texas; and 

Ben Yamagata, the Executive Director of Coal Utilization Research 

Council and a partner at Van Ness and Feldman. One of our scheduled witnesses, Professor Sally Benson, was unable to attend due 

to family circumstance, but she also is a recognized expert in the 

field. And, again, to our second panel, welcome and I would like to 

recognize each of you for 5 minutes and highlighting your prepared 

testimony, starting with Mr. Bengal. Again, thank you for your patience this morning. 

STATEMENT OF LAWRENCE BENGAL, DIRECTOR, ARKANSAS 

OIL AND GAS COMMISSION 

Mr. BENGAL. Good morning, Mr. Chairman and Ranking Members, members of the subcommittee. My name is Lawrence Bengal. 

I am the Director of the Arkansas Oil and Gas Commission and I 

am appearing here today in my capacity as Chairman of the Interstate Oil and Gas Compact Commission Task Force on Carbon Capture and Geologic Storage Task Force. I will share with the committee the experience and conclusions of the Task Force with regard to the geologic storage of CO2. I hope my testimony will demonstrate to the committee that 

States have a crucial and important role to play in the regulation 

of this most promising technology, the geologic storage of CO2. 

61 

States have a keen interest in managing the good sites that occur 

within that State. Funded through the National Energy Technology 

Laboratory, the task force has been engaged since 2003 in efforts 

relating to the regulation of geologic storage of CO2. Although it may not be widely recognized, States are the primary 

regulators of oil and natural gas production and related activities 

including natural gas storage, acid gas injection and the injection 

of carbon dioxide, or CO2 for enhanced oil recovery. Regulating the 

geologic storage of CO2 is akin to regulating oil and gas production. 

States, therefore, possess much of the knowledge base that will be 

required to regulate CO2 geologic storage. 

Additionally, one of those important functions of the State in regulating oil and natural gas development is the protection of water 

resources. In most cases States are already the on-the-ground administrators of the EPA’s Underground Injection Control (UIC) program, under State primacy jurisdiction granted by the EPA. With 

the advent of the model laws and regulations created by the Task 

Force, and released earlier this year, States have now begun to develop laws and regulations governing geologic storage of CO2. At 

least 12 States have begun or are well along in this process. 

This State-based regulatory system incorporates, as the oil and 

natural gas regulatory regime now does, EPA requirements under 

the UIC program as expanded to include the storage of CO2. Additionally, Department of Transportation’s Pipelines and Hazardous 

Material Safety Administration will play a critical role in ensuring 

CO2 pipeline safety, which is also administered through State partnerships. The result will be a combined State and Federal regulatory system in the 2010 to 2011 timeframe that will provide a 

flexible, responsive, safe, environmentally sound and nationally 

consistent regulatory framework for geologic storage of CO2. It 

should be more than adequate to get the first projects planned and 

safely off of the ground. If a need for additional Federal regulatory 

authority manifests itself, it can be addressed at that time. 

Let me now turn to the diagram which illustrates the cradle to 

grave regulatory model, which the Task Force has recommended to 

States. As you can see, there are three phases. This will give you 

a quick idea of the breadth of the regulatory structure proposed by 

the Task Force, which is covered in more detail in my written testimony. I would note that only within the project area indicated by 

the green box does it appear that EPA has regulatory authority 

under the Safe Drinking Water Act. Areas not covered by EPA authority, however, can be addressed by State regulatory authorities. 

Let me close by emphasizing that public support for geologic storage of CO2, as a strategy for mitigating the impact of global climate 

change, will be crucial. Key to this support will be public understanding of the 30-year long history of CO2 transportation, handling and use (including use to increase domestic oil production). 

In this context, CO2 should not be classified as a hazardous substance or pollutant under existing regulatory frameworks. Given 

the complexities of credits, ownership and usage of CO2, a new regulatory paradigm is needed based on resource management, rather 

than waste disposal. 

As such, it will be vitally important to include the public in every 

step of the regulatory development process, State and Federal. 

62 

State open meeting laws will ensure public notice and participation 

in the State process both at the legislative and regulation development stages. 

Thank you for the opportunity to appear here today. If I can provide any additional information, please do not hesitate to ask. I 

would also ask that a copy of the full IOGCC Task Force Report 

be included in the record today. Thank you. 

[The prepared statement of Mr. Bengal follows:] 

TESTIMONY OF LAWRENCE E. BENGAL

Summary 

Mr. Bengal will testify in his role as Chairman of the Task Force on Carbon Capture and Geologic Storage of the Interstate Oil and Gas Compact Commission 

(IOGCC). (The IOGCC is the nation’s oldest interstate compact.) He will explain 

why it will be necessary for states to play a major role in the regulation of the storage of carbon dioxide (CO2) in geological formations and what states are actively 

doing to prepare themselves for this important role. Mr. Bengal will testify that it 

is very likely that states will be the on-the-ground-regulators of geological carbon 

storage. Mr. Bengal in his testimony will make clear why states are well-suited experientially for this role by virtue of their technical expertise regulating oil and natural gas development and ancillary activities, including natural gas storage, acid 

gas injection and CO2 enhanced oil recovery. Mr. Bengal will also explain how 

states, in most instances, are the administrators of the U.S. Environmental Protection Agency Underground Injection Control (UIC) Program. He will close by emphasizing the importance of public support of carbon storage as a strategy for mitigating the impact of global climate change. Key to this support will be public understanding the long history of CO2 transportation, handling and use (including use to 

increase domestic oil production). Mr. Bengal will suggest that given the complexities of credits, ownership and usage of CO2 that a new regulatory paradigm will 

be useful, one that is based on resource management rather than waste disposal. 

Testimony 

Good morning. My name is Lawrence Bengal. I am the Director of the Arkansas 

Oil and Gas Commission and I’m appearing today in my capacity as Chairman of 

the Interstate Oil and Gas Compact Commission’s Task Force on Carbon Capture 

and Geologic Storage (CCGS). In the 5 years the Task Force has been in existence, 

its membership has been drawn from IOGCC member state and provincial oil and 

gas agencies, U.S. Department of Energy sponsored Regional Carbon Sequestration 

Partnerships, the Association of American State Geologists and industry. The Task 

Force has also had representatives from the U.S. Environmental Protection Agency 

(EPA), the U.S. Bureau of Land Management (BLM) and the environmental group 

Environmental Defense attending as observers. 

The member states of the Interstate Oil and Gas Compact Commission (IOGCC) 

produce more than 99% of the oil and natural gas produced onshore in the United 

States. Formed by Governors in 1935, the IOGCC is a congressionally ratified interstate compact. The organization, the nation’s leading advocate for conservation and 

wise development of domestic petroleum resources, includes 30 member states, 8 associate states, and 6 international affiliate provinces. The mission of the IOGCC is 

two-fold: to conserve our nation’s oil and gas resources and to protect human health 

and the environment during the production process. Our current chairman is Governor Sarah Palin of Alaska. 

The purpose of my testimony today is to share with the Committee the experience 

and conclusions of IOGCC’s CCGS Task Force with regard to the geologic storage 

of carbon dioxide (CO2). As this committee today explores the topic ′′Carbon Sequestration: Risks, Opportunities, and Protection of Drinking Water′′ I hope my testimony will demonstrate to the committee that states have a crucial and important 

role to play in the regulation of this most promising technology: the geologic storage 

of CO2. 

Let me begin by noting what may not be completely understood by everyone. In 

the United States, states are the primary regulators of oil and natural gas production and related activities including natural gas storage, acid gas injection and the 

injection of carbon dioxide (CO2) for enhanced oil recovery (EOR). As that which 

must be regulated in the geologic storage of CO2 is extremely similar to that which 

must be regulated in oil and gas production, states thus possess much of the knowledge base and skill sets that will be required of the on-the-ground regulator of CO2

63 

geologic storage. Additionally, one of the most important functions of the state in 

regulating oil and natural gas development and related activities is to ensure that 

in the construction and operation of the wells and ancillary facilities that the state’s 

water resources are protected, including of course, groundwater. Additionally, states 

are already in most cases the ′′on-the-ground′′ implementers of the Underground Injection Control (UIC) Program of the U.S. Environmental Protection Agency (EPA) 

under primacy jurisdiction granted to states by the EPA. 

It is also important to note that much of the state authority to regulate oil and 

natural gas production and related activities comes from the state’s conservation 

code, which in most cases is based on the IOGCC Model Conservation Code. This 

means practically that the state codes are very similar to one another and that a 

company moving from one jurisdiction to another encounters far more legal and regulatory similarities than dissimilarities. 

With the advent of the model laws and regulations created by the IOGCC Task 

Force and released by the IOGCC earlier this year, states now have a resource to 

begin to develop laws and regulations governing the regulation of carbon geologic 

storage. At present over 7 states are already well along in this process, having 

adopted or in the process of adopting such frameworks. This state-based regulatory 

system will incorporate, as the oil and natural gas regulatory regime does now, EPA 

requirements under the UIC program as expanded to include the storage of CO2

along the lines announced by EPA last week. The Department of Transportation’s 

Pipelines and Hazardous Materials Safety Administration (PHMSA) will also play 

a critical role in ensuring CO2 pipeline safety. (The states also administer the 

PHMSA program as a federal-state partnership.) The result will be a combined state 

and federal regulatory system in the 2010-2011 timeframe that will provide a sound 

and nationally consistent regulatory framework for the geologic storage of CO2 in 

the United States. 

Let me now turn to a more detailed review of the Task Force history and its recommendations. 

Funded by the U.S. Department of Energy (DOE) and its National Energy Technology Laboratory (NETL), the Task Force has been engaged since 2003 in a twophase effort relating to the regulation of the geologic storage of carbon. In Phase 

I, the Task Force undertook a thorough review of the technology of geologic storage 

and in Phase II developed a model statute and model rules and regulations for the 

states and provinces to administer regulatory oversight of geologic storage of carbon 

dioxide (CO2). 

A major conclusion of the Task Force in Phase I was that the geologic storage of 

CO2, in addition to conservation, is among the most immediate and viable strategies 

available for mitigating the release of CO2 into the atmosphere. It was readily apparent to the Task Force that carbon storage was also not something entirely new 

and mysterious - but the technological outgrowth of four analogues. These four analogues, in the opinion of the Task Force, provide the technological and regulatory 

basis for storage of CO2 in geologic media: 1) naturally occurring CO2 contained in 

geologic reservoirs, including natural gas reservoirs; 2) the large number of projects 

where CO2 has been injected into underground formations for Enhanced Oil Recovery (EOR) operations; 3) storage of natural gas in geologic reservoirs; and 4) injection of acid gas (a combination of H2S and CO2), into underground formations, with 

its long history of safe operations. 

It was the opinion of the Task Force that given the jurisdiction, experience, and 

expertise of the states and provinces in the regulation of oil and natural gas production as well in regulating the analogues identified above, the states and provinces 

would not only be well able to regulate, but would be the most logical and experienced on-the-ground regulators of CO2 geologic storage. Additionally and importantly, the oil and natural gas producing states and provinces are strategically and 

geologically well-situated for the geologic storage of CO2. Regulations already exist 

in most oil and natural gas producing states and provinces covering many of the 

same issues that will need to be addressed in the regulation of CO2 geologic storage, 

and consequently serve as adaptable frameworks. 

Given these Phase I conclusions, the Task Force, in Phase II, began work and in 

September of 2007 produced, for the first time, a clear and comprehensive model 

legal and regulatory regime for the geologic storage of CO2. Utilizing these model 

regulatory frameworks, states and provinces, and indeed other nations, have the 

basic building blocks to begin immediately the process of developing and enacting 

legislation and promulgating rules and regulations enabling CO2 geologic storage 

projects. Wyoming, Washington, Kansas, California, New Mexico, North Dakota, 

and Texas are, among other states, in various stages of developing such a legal and 

regulatory framework. Wyoming passed legislation this year relying heavily on the 

IOGCC model. 

64 

I anticipate that by 2010 there will be at least 7-15 states, encompassing much 

of the country best suited for carbon geologic storage, with legal and regulatory systems in place for the regulation of geologic storage of CO2. The recently proposed 

EPA carbon storage regulations under the Safe Drinking Water Act and its implementing UIC program should also be in place by 2011. 

Let me now briefly address how the IOGCC anticipates that the EPA’s CO2 geologic storage regulations will interface with the regulatory systems being developed 

by the states. Given the incorporation of UIC-like regulatory requirements into the 

proposed IOGCC model regulatory frameworks, there is every reason to anticipate 

that the IOGCC and EPA frameworks will fit like hand in glove. This is largely because of the role that states play in the administration of UIC programs under EPA 

state primacy authority. 

As we’ve heard this morning, the EPA has been in the process of developing regulations for geologic sequestration under the Safe Drinking Water Act. Draft regulations were announced last week. The IOGCC at the invitation of EPA had two representatives, Berry ′′Nick′′ Tew of Alabama and myself, actively participating in the 

process as state co-regulators. States with primacy already play an integral role in 

administering the UIC program and under future rules governing geologic storage, 

are likely to do so again. Having representatives from states involved in the process 

helps insure compatibility between the state and federal components of geologic 

storage regulatory oversight. 

What is clear to me, especially given my involvement with the current EPA 

workgroup, is that the state regulatory system for carbon storage proposed by the 

IOGCC Task Force will in all likelihood work seamlessly with the regulations likely 

to emerge out of the EPA regulatory development process. 

It is now appropriate to supply a little more detail about the legal and regulatory 

system which the IOGCC Task Force has proposed for the geologic storage of CO2

and how, precisely, the proposed EPA regulatory system for CO2 storage would likely fit into this system. This diagram will be helpful: 

The diagram represents the ′′cradle to grave′′ regulatory model which the Task 

Force has recommended to states. There are three phases. 

1. LICENSING INCLUDING AMALGAMATION OF STORAGE RIGHTS

The first phase is the licensing phase which includes the critical requirement that 

the project operator control the storage rights. 

The Task Force concluded that as a part of the initial licensing of a storage 

project that the operator of the project must control the reservoir and associated 

pore space to be used for CO2 storage. The operator would need to acquire these 

rights from the owners or assume those rights by means of eminent domain, unitization or some other vehicle that either exists in a state or would be created by the 

state uniquely for this purpose. This step is necessary because in the U.S., the right 

to use reservoirs and associated pore space is considered a private property right 

and must be acquired from the owner. It was the conclusion of a Task Force legal 

subgroup that in most U.S. states, for non EOR-related storage, the owner of these 

rights would likely be the owner of the surface estate. It may be prudent, however, 

depending upon the specific property right ownership framework in a given state, 

for an operator to also control the relevant subsurface mineral rights. 


46862.101
65 

Additionally, as part of the initial licensing of a project the operator would be required to submit for State Regulatory Authority (SRA) approval, detailed engineering and geological data along with a CO2 injection plan that includes a description 

of mechanisms of geologic confinement that would prevent horizontal or vertical migration of CO2 beyond the proposed storage reservoir. The operator would also be 

required to submit for approval by the SRA a public health and safety and emergency response plan, worker safety plan, corrosion monitoring and prevention plan 

and a facility and storage reservoir leak detection and monitoring plan. 

The rules also include requirements for an operational bond that would be sufficient to cover all operational aspects of the storage facility excluding wells which 

would be separately bonded. 

Site licensing and amalgamation of storage rights is generally believed to be outside the scope of the current UIC Program, and given that regulatory involvement 

with property rights is a state issue, this phase is best addressed at the state level. 

In addition, given the likely competition for acceptable storage sites, it is in a state’s 

interest to manage these sites to maximize storage capacity and resolve any operator conflicts over the right to use storage resources, thereby maximizing the state’s 

best economic interest in providing storage sites for that state’s generators. 

2. THE STORAGE AND CLOSURE PHASE

In this second phase we are talking about the phase, following initial licensing, 

when the storage project is developed, operated, and closed. This includes a short 

time period following plugging of the wells during which time the project is monitored to ensure stability of the injected CO2. During the storage component of this phase the model rules specify the procedures for permitting and operating the project injection wells to safeguard life, 

health, property and the environment. The operator would be required to post individual well bonds sufficient to cover well plugging and abandonment, CO2 injection 

and/or subsurface observation well remediation. The rules also specify design standards to ensure that injection wells are constructed to prevent the migration of CO2

into other than the intended injection zone. Provisions in the rules also ensure that 

all project operational standards and plans submitted during the licensing phase 

would be adhered to and that the project and wells are operated in accordance with 

all required operating parameters and procedures. Quarterly and annual reports 

would be required throughout the operational life of the project. The rules also ensure that the wells are properly plugged and the site restored. The individual well 

bonds, maintained during the operational phase of the project would be released as 

the wells are plugged. 

The closure component of this phase is defined as that period of time when the 

plugging of the injection wells has been completed and continuing for a defined period of time (10 years unless otherwise designated by the State Regulatory Authority) after injection activities cease and the injections wells are plugged. During this 

closure period, the operator of the storage site would be responsible for providing 

the required data to ensure the injected CO2 has not migrated beyond the project 

boundaries and the injected CO2 plume has been stabilized. During this time the 

operator is required to maintain an overall project operational bond. 

This phase is primarily where the EPA’s proposed carbon storage rules will supplement state rules so as to ensure the operation and plugging of the wells are protective of the groundwater resources under the UIC Program. 

3. LONG-TERM ′′CARE TAKER′′ PHASE (LONG-TERM MONITORING AND LIABILITY) 

This last phase is the Long Term or Post-Closure Period and is characterized as 

that period of time when the operator of the project is no longer the responsible 

party and the long-term ′′care taker′′ role is assumed by a government entity or government-administered entity. The major issue faced by the Task Force was how to 

deal with long-term monitoring and liability issues. The formula settled upon by the 

Task Force is the following: 

At the conclusion of the Closure Period, the operational bond would be released 

and the regulatory liability for ensuring that the site remains a secure storage site 

would transfer to a trust fund administered by the state. During the Post-Closure 

Period, the financial resources necessary for the state or a state-contracted entity 

to engage in future monitoring, verification, and remediation activities would be provided by this state-administered trust fund. 

The Task Force concluded that such a state-administered trust fund would be the 

most effective and responsive ′′care-taker′′ to provide the necessary oversight during 

the Post-Closure Period. The trust fund would be funded by an injection fee assessed to the site operator and calculated on a per-ton basis. 

66 

In summary, the EPA Regulations under the SDWA and the UIC Program will 

primarily deal with the Storage and Closure Phase as illustrated by the green box 

in the diagram, for it is only in the project areas within that box that EPA has authority under the SDWA. In addition to EPA’s mandate to protect drinking water 

under the SDWA, the IOGCC regulations cover other public health and safety issues 

that need to be a part of a comprehensive regulatory framework. As previously stated, almost all of the well operational standards proposed in the IOGCC model regulations are already UIC requirements of one form or another. 

What I anticipate is that the proposed EPA regulations, whatever they end up 

being, will yield a set of uniform national standards, which superimposed on whatever state regulations may be in place will result in national consistency of application so as to ensure that drinking water resources are protected. Again as previously 

stated, given most states (those with primacy) already administer the existing UIC 

program, they will continue to do so, conforming their state regulations as they pertain to the geologic storage of carbon to the minimum standard set by the new EPA 

regulations. 

Unless the EPA regulations end up being unnecessarily proscriptive and onerous, 

the systems should work together perfectly and as I’ve already stated, ′′seamlessly′′. Certainly this is the hope and current full expectation of the IOGCC. 

I will note that with regard to federal lands (surface and/or mineral interests), 

that federal regulations emanating out of the BLM will undoubtedly be necessary. 

However, what emanates out of BLM would in all likelihood be more akin to what 

the states have done with regard to state and private lands rather than an overarching and broader national regulatory scheme. 

Additionally, our model regulatory system does not address the regulatory issues 

involving CO2 emissions trading and accreditation for the purpose of securing carbon credits. The Task Force concluded that the issue of CO2 emissions trading and 

accreditation would likely best be addressed in the marketplace and/or at the federal government level and was beyond the scope of the Task Force’s mandate. In 

any event, the Task Force strongly believes that development of any future CO2

emissions trading and accreditation regulatory frameworks should utilize the experiences of the states. 

As concerns long term ′′care taker′′ liability, what the Task Force has proposed 

will have to be addressed by each state and province as they develop their own 

framework. It remains to be seen if states will agree with the Task Force or propose 

something new. There may indeed be a need for a federal role here at some point 

in the future but it is suggested that federal action in this area await a clear need 

manifesting itself in the years ahead. 

Additionally and very importantly, states and provinces are likely to continue to 

regard CO2 geologic storage reservoirs as a valuable resource that should be managed using resource management frameworks, therefore avoiding the treatment of 

CO2 storage as waste disposal. In this context, the Task Force believes that CO2

should not be classified as a hazardous substance or pollutant under existing regulatory frameworks. Given the complexities of credits, ownership and usage of CO2, 

a new regulatory paradigm is needed based on resource management rather that 

waste disposal. The Task Force strongly believes that treatment of CO2 as a waste 

under waste management regulatory frameworks will diminish significantly the potential of carbon storage technology to meaningfully mitigate the impact of CO2

emissions on the global climate. The energy consuming public and the industry 

which produces that energy share a common goal in coming up with a workable solution. 

Let me close by noting the obvious -- that public support for carbon storage as 

a strategy for mitigating the impact of global climate change will be crucial. It will 

be important to educate the public about this technology including CO2’s long history of being transported, handled, and used in a variety of applications. As such 

it will also be vitally important to include the public in every step of the regulatory 

development process, state and federal. State open meeting laws will ensure public 

notice and participation in the state process at both the legislative and regulation 

development stages. 

Thank you for the opportunity to appear here today. If I can provide any additional information, please do not hesitate to ask. I would also ask that a copy of 

the full IOGCC Task Force Report be included in the record today. 

Mr. GREEN. If you would submit that, I appreciate it—with your 

testimony. We have a series of votes in about 10 minutes. It will 

probably last the better part of 30 to 35 minutes, so if each of you 

67 

could summarize your testimony and we will be back for the questions as possible. Mr. Broussard, again, welcome. 

STATEMENT OF DON BROUSSARD, WATER OPERATIONS 

MANAGER, LAFAYETTE UTILITIES SERVICES 

Mr. BROUSSARD. Good morning. My name is Don Broussard, and 

I am the Water Operations Manager for the Lafayette Utilities System in Lafayette Louisiana. Lafayette Utilities System is an electric utility, a drinking water utility, a waste water utility and a 

telecommunications wholesaler. We serve a retail and wholesale 

population of approximately 170,000 people. Now, it is important to 

know that part of our electric generation does come from coal-fired 

electric generation units. I am appearing here today on behalf of 

the American Water Works Association, AWWA. AWWA is the 

world’s oldest and largest association dedicated to safe water. Our 

utility members serve safe and affordable drinking water to more 

than 80 percent of the American people. We appreciate the opportunity to provide our views on geologic carbon sequestration this 

morning. Our overarching concern regarding geologic carbon sequestration is the potential contamination of underground sources 

of drinking water and the potential for other unintended and possibly harmful consequences. Water chemistry in an underground 

setting is complex and AWWA has several technical concerns regarding the potential for carbon sequestration to contaminate the 

USDWs. 

Preventing degradation of water should not just be limited to 

contaminates with established maximum contaminate levels, but 

should also include other constituents whose presence may either 

make ground water more difficult to treat or impact the beneficial 

uses of that groundwater. Several references on geologic carbon sequestration discuss changes in the carbonate cycle, resulting in 

lower ph conditions and the release of iron, manganese, arsenic 

and possibly other inorganics into groundwater surrounding the injection zone. We need appropriate subsurface monitoring technologies identified and developed to prevent or respond to potential 

contamination of USDWs by these inorganic compounds. 

The construction of the injection wells is a critical issue to 

AWWA, both in terms of the materials used and the depth of injection. Since the injection wells will be encased in cement, the longterm integrity of the cements that will be used during construction 

will need to be extensively tested under real-world conditions. 

It is important to note that as the injection wells are constructed, 

they will be penetrating existing underground sources of drinking 

water and essentially be permanently living in the underground 

source of drinking water. 

I might mention that one term that I have not heard mentioned 

today is a sole-source aquifer, where we have a drinking water 

source that has been designated as a sole-source aquifer it is impractical for a water utility to identify another source of groundwater or source of drinking water. So I just ask for particular consideration for those sole-source aquifers. 

Another area of concern is often the lack of good records of abandoned wells that tapped the very same strata used for carbon dioxide sequestration. There is a presumption that even States with oil 

68 

and gas or mining operations have excellent up-to-date reports and 

have maps indicating abandoned wells and mines. That may not be 

the case. 

Many States with extractive industries do have maps and surveys, but they are not sufficiently precise for geologic sequestration. 

Studies have shown that injected carbon dioxide has been pretty 

good at finding these abandoned wells and these wells allow for the 

transmission of carbon dioxide out of the confined aquifer into potential USDWs, and then eventually to the surface. 

AWWA would like to see the issue of long-term liability resolved. 

EPA’s proposed geologic carbon sequestration rule cannot address 

financial responsibility of the sequestration site after the formal period of post-injection site care has ended. We call on Congress to 

develop legislation that will address the issue of who has to assume 

financial responsibility of the site after the site closure requirements have been fulfilled. 

Research on the geologic sequestration of carbon dioxide should 

take a holistic approach, encompassing a review of potential impacts on the current and future underground sources of drinking 

water. AWWA recommends that commercial scale carbon sequestration not be deployed until the results of current large-scale Department of Energy pilot projects have been received and reviewed. 

By waiting for these results, both the EPA and the Department of 

Energy will be better able to fully understand the effects of carbon 

sequestration on underground sources of drinking water. Then any 

necessary modifications can be made to the regs and sequestration 

technology before companies invest in processes that may have severe and potentially unintended consequences. 

We are concerned that the results of current research and pilot 

projects may not be available until after EPA’s regulation on geologic carbon sequestration have already been finalized. 

In conclusion, AWWA is concerned that the proposed large-scale 

sequestration of carbon dioxide and underground aquifers may 

have significant impacts on the public, the environment and drinking water utilities. We are aware of the impacts that climate 

change will have on the water utilities across the country and recognize that something needs to be done to address climate change. 

We also recognize the need to have energy and that all fuel types, 

including coal, are essential. However, AWWA urges caution in 

moving forward with this technology. Thank you for your time and 

I would be happy to respond to any questions you might have. 

[The prepared statement of Mr. Broussard follows:] 

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Mr. GREEN. Dr. Duncan. 

STATEMENT OF IAN DUNCAN, ASSOCIATE DIRECTOR, EARTH 

AND ENVIRONMENTAL SYSTEMS, BUREAU OF ECONOMIC 

GEOLOGY 

Mr. DUNCAN. Thank you Mr. Chairman. My name is Ian Duncan. 

I have a Ph.D. in geological sciences and I am the Associate Director of the Bureau of Economic Geology at the University of Texas, 

which is the second largest research institute at the University. I 

also believe—I normally don’t make statements like this because it 

is too much of a Texas thing, but I believe the University of Texas 

has the largest group of researchers working in geological sequestration in the country. 

Based on all the available information to me, I believe that largescale CO2 sequestration in deep brine reservoirs can be done safely 

and effectively and without endangering the country’s drinking 

water resources. My basis for saying this is, in part, on the 35 

years of experience that we have in Texas in the Permian Basin 

of injection of CO2. Also, on the natural occurrences of CO2, where 

we can show that naturally generated carbon dioxide has been contained by seals, the same kind of seals that we would propose to 

use for sequestration on the time scale of millions of years. 

Based on my review of the recent EPA draft regulation documents, I commend the EPA for the quality and comprehensiveness 

of their draft. I think they have done excellent work in trying to 

include stakeholder input into this. I think it is an excellent start 

and I will look forward to having further input on their development of the rule. 

I do have a concern that the EPA does not have a legislative 

mandate to require, encourage or even suggest that operators 

choose the most optimal—by optimal I mean lowest risk leakage 

site available. And myself and my co-author J.P. Nicot have written a paper suggesting a mechanism by which this might occur, 

and this is detailed in my written testimony. 

It is critical that EPA be given sufficient resources to develop, 

implement and enforce the regulations, also that State agencies be. 

This is a new kind of process that is involved in carbon sequestration. It is going to require well-trained technical people to enforce 

it. I believe that performance standard based approaches to regulating CO2’s sequestration offer considerable advantages over prescriptive approaches. They are flexible and they can do what we 

call learn-as-you-go, in other words the first big projects that come 

in, we are going to learn from them and we need regulations that 

can adapt from them. Again, my written testimony details some aspects of the performance standard approach and gives an example 

with respect to seals. 

In the near term, CO2 enhanced oil recovery combined with appropriate monitoring mitigation and verification can make a significant contribution to putting man-made CO2 into permanent storage 

and depleted oil reservoirs. And it may have been a little confusing 

in some of the previous testimony where it was, perhaps, suggested 

that CO2 involved in enhanced oil recovery is just there to recover 

the oil. 

85 

I refer to my written testimony again, but in the Sacroc oil field 

in Scurry County, Texas, Kinder Morgan is currently injecting 30.5 

million tons of CO2 a year. Seven million tons of that is being recycled, stripped out of the oil and re-injected, and 6 and a half million 

tons is being permanently stored as near as we can tell. That 

makes it, by far, the largest sequestration project, and I use that 

term loosely, not specifically because it is not being monitored. It 

is not anthrogetic, but it shows the potential. 

I also agree with the members of the committee who suggested 

we have not taken enough advantage of the CO2 enhanced oil recovery as a resource to learn from. The Bureau of Economic Geology has one small project going at Sacroc trying to detect any leakage and so far we haven’t found it, but I think it would be a good 

use of resources to put more money into research related to CO2

enhanced oil recovery and also to use it as a natural laboratory. 

Now, I want to make a self-serving statement. The Congress 

should appropriate funds to support University research in CO2 sequestration, outside the partnership program and also in CO2 enhanced oil recovery. Congress cut the funds for studying oil and gas 

research and the reason I suggest you should do this is that when 

I go to carbon sequestration conferences, I discover I am one of the 

youngest people there and I am, like, 58. We have a crisis in having the people power to be able to do this. Thank you. 

[The prepared statement of Mr. Duncan follows:] 

STATEMENT OF IAN DUNCAN

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 University of Texas has arguably the largest group of researchers 

in the country focused on CO2 sequestration in deep brine reservoirs. The BEG is 

engaged in research in a broad range of energy related and environmental issues 

including CO2 sequestration. The BEG’s Gulf Coast Carbon Center (GCCC) is an industry-academic-NGO collaboration working on geologic CO2 sequestration including 

Enhanced Oil Recovery CO2 EOR. 

The GCCC’s Frio Pilot Injection Project, led by the BEG’s Dr Susan Hovorka and 

funded by the DOE’s National Energy Technology Laboratory, was the first highly 

instrumented CO2 injection experiments in the world. The Frio Brine Pilot Injection 

project (conducted 2004 to 2007) was: 

•A first-of-a-kind field investigations into the viability injecting CO2 into a brinefilled sandstone reservoir for long term geologic storage or sequestration; and 

•A carefully monitored, small-volume (1,600 tons), short-duration experiments 

using injection of CO2 into high-permeability brine-bearing sandstone to test the effectiveness of computer modeling and various monitoring techniques. 

The Frio Brine Pilot project was designed to begin to develop the understanding 

necessary to begun large scale CO2 injection. No evidence has been found of CO2

leaking or behaving in any way not predicted by pre-injection computer simulations. 

Extensive monitoring has not detected any evidence of leakage of the geologic reservoir. The Frio Pilot Injection has shown that relatively low-cost, off-the-shelf, monitoring techniques can provide cost effective monitoring of CO2 injections for sequestration. This project has also confirmed the utility of computer simulations to accurately model the fate of CO2 injected into subsurface brine reservoirs. 

The GCCC currently has a significant field-test of CO2 sequestration in brine reservoirs underway in Mississippi (Denbury resources Cranfield CO2-EOR site). This 

field test seeks to show the effectiveness of CO2 sequestration, and how we can best 

predict and document the long term retention of CO2 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

sequestration in deep brine reservoirs and associated with CO2 enhanced oil recovery (CO2-EOR) can play in mitigating greenhouse gases in the atmosphere and in 

86 

increasing domestic oil production in the US. Recently I have been working on developing a regulatory framework for CO2 sequestration in brine based on performance standards rather than prescriptive standards (command and control). 

The key points that I would like to make are: 

(1) Based on all the available information I believe that large scale CO2 sequestration in deep brine reservoirs can be done safely and effectively without endangering 

the nation’s underground sources of drinking water (USDW). 

(2) Based on my review of the recent EPA draft regulatory documents, I commend 

the EPA for its quality and comprehensiveness. I compliment the EPA staff on their 

efforts to foster broad stakeholder input into their process. 

(3) I will not be making specific comments on the details of the EPA draft as I 

do not want to preempt the mechanism for stakeholder comment that the EPA has 

in place. 

(4) I have a concern that the EPA does not have any legislative mandate to require, encourage or even suggest that operators choose the most optimal (lowest risk 

of leakage) sites available. 

(5) It is critical that EPA be given sufficient resources (including trained professional staff engineers and scientists) to fully develop, implement, and enforce regulations for carbon sequestration. 

(6) Performance standard based approaches to regulating CO2 sequestration offer 

considerable advantages over prescriptive approaches. 

(7) In the near term, CO2-EOR combined with appropriate monitoring, mitigation, 

and verification, (MMV) can make a significant contribution to mitigating increases 

in CO2 emissions by putting man-made CO2 (CO2-A) into permanent storage in depleted oil reservoirs. 

(8) Congress should appropriate funds for the DOE to support university research 

into CO2 sequestration associated with CO2 EOR and for individual investigator research outside of the Sequestration Partnership program. Such funding would help 

produce young engineers and geologists trained in CO2 related technologies and alleviate a shortage that is critical now and will grow more so in the near future. 

DEVELOPING A SEQUESTRATION CAPABILITY IN THE US 

CO2 sequestration will involve the capture of 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 today 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 injection 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 Oil Field in Scurry County since 1972. 

Kinder Morgan the current operator at SACROC currently injects 13.5 MMt CO2/ 

yr and withdraws/recycles 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 EOR outside of the traditional area 

of CO2 EOR in the Permian Basin. Using 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 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). 

87 

EOR results in storage of CO2 dissolved in residual oil, dissolved in brine, and 

trapped as an immobile supercritical phase. Experience in mature Permian basin 

CO2-EOR projects is that 30 to over 60% of the injected CO2 is retained in the reservoir over a year of injection (starting at 100% retention for the initial phase of 

the project). Due to recycling (capture and reinjection of CO2 produced with the oil), 

it is likely that appropriate MMV techniques would demonstrate that in most instances 99% +/- .05% of the CO2 used is ultimately sequestered in the oil field. 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. The path forward toward 

developing an economically viable system for capture and storage includes: (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 

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 will change 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 will almost certainly be 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, Montana 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 EOR operations in a manner 

that later allows pure CO2 storage to initially ‘piggyback’ via the commercial leverage of the oil recovered. 

CO2-EOR can create an effective bridge to CO2 sequestration in brines, by providing the financial capacity and rationale for developing a CO2 capture, compression and transportation infrastructure across a significant portion of the US that 

can later be used for large scale CO2 sequestration in deep brine reservoirs. To facilitate this happening, Congress should provide a policy/regulatory environment 

that encourages CO2-EOR operators to change business as usual by: a) utilizing 

CO2-A when available at reasonable cost from capture at power plants; b) creating 

and implementing MMV plans to provide assurance of permanent sequestration; 

and c) conduct life cycle analyses of their projects to measure CO2 avoided. 

CREATING A NEW REGULATORY FRAMEWORK FOR CO2 SEQUESTRATION 

The two key aims of a regulatory framework for CO2 injection should be: to ensure 

public health and safety; and to prevent environmental damage, particularly damage to drinking water resources. Additional issues that should be addressed by the 

regulatory process include: 

88 

•The concerns of local government and local residents. Any negative environmental consequences of geologic sequestration are likely to impact the local community •Providing a mechanism for stakeholders and the general public to have effective 

input into the both the permitting process and the integrity of subsequent regulatory oversight. •Supporting confidence of the market place for CO2 sequestration credits by assuring transparency. •Assuring adequacy of long term monitoring, mitigation and remediation efforts. 

(A) ENCOURAGING OPTIMAL SITE SELECTION THROUGH CREATING A GENERAL

PERMITTING PROCESS FOR SEQUESTRATION

An aim should be to require the selection of sites that have low risk of leakage. 

The Carbon Capture Project, an industry based research collaboration, has suggested that the first key to lowering the risks associated with CO2 sequestration 

projects is ′′careful site selection′′. The long term risk of leakage of brine sequestration projects is very much dependant on site selection. Permitting is by its very nature a binary (yes or no) decision. Currently the EPA has no legislative mandate 

to encourage selection of the best sequestration targets. 

One approach to encouraging companies to select the sites that are least likely 

to leak based on best available scientific knowledge is to implement the General 

Permit model of Nicot and Duncan 2008. In this paper we suggest that States, with 

guidance from Federal agencies (U.S. Geological Survey, U.S. EPA), should be responsible for developing regional evaluations of geology and engineering properties 

of potential brine reservoirs for CO2 sequestration. Such studies could include regional static reservoir models, numerical models of the evolution of CO2 plumes, and 

regional risk assessments. State and Federal governments should be proactive in 

starting regional studies with stakeholder (general public, local governments, operators, CO2 generators) input that would rank areas according to criteria developed 

from such broad input. Rankings based on a systematic approach to risk assessment 

could be established with the help of decision-support tools specifically developed for 

this purpose. These ′′risked-based′′ or ′′risk-informed′′ approaches have already been 

used for other performance-based permitting systems developed by the U.S. EPA. 

The EPA has a long history of ranking sites with some degree of success. The 

DRASTIC program and Risk Based Corrective Action are two examples. Similar 

schemes could be used for carbon-storage sites. 

As the permitting system evolves, it will be important to build in market-based 

incentives to encourage innovation and to reward sound stewardship. Such incentives could include streamlined permitting, extension of existing permits to encompass multiple injection projects into the same brine reservoir, and waiving of some 

requirements on the basis of an exemplary track record. Innovative permitting can 

lower overall cost of sequestration, at the same time encouraging technical innovation and improved performance. 

A hierarchical approach to permitting could be developed. The first level, the general permit phase, would be based on regional assessments of specific brine reservoirs. A State agency responsible for the permitting process of geologic sequestration carries out regional-scale assessments for suitable target regions on the basis 

of sophisticated modeling and extended data sets. A national agency, such as U.S. 

EPA, could also be involved when UIC oversight responsibility has not been delegated to the State. National/Federal agencies could also help in or be required to 

providing consistency across lower-level entities (states, provinces, etc). Counties, 

metropolitan areas, and subregional agencies could carry out a subregional-scale assessment. The results will then be used by the designated State or Federal agency 

to create general permits for specific regions for individual and/or groups of brine 

reservoirs. Individual operators apply for permits (as in the case of deep injection 

wells). 

For early-entry projects it likely will not be possible to implement the hierarchical 

approach without unnecessarily delaying initiation of geologic sequestration. For 

large scale implementation of sequestration EPA should be given a legislative mandate that enables it to regulate sequestration in a regional context rather than on 

a well by well or even project by project basis. 

(B) PERFORMANCE STANDARD BASED APPROACHES TO REGULATION

To have a significant impact on decreasing the rate of increase of atmospheric 

CO2 levels, geologic sequestration in deep brine reservoirs will have to occur on a 

very large scale. The scale of individual injection projects is likely to be as large as 

or larger than any previously permitted under the UIC program. In addition CO2

89 

is more buoyant (though less hazardous) than other fluids regulated by the UIC 

process. Performance standard based approaches are the best able to adapt to evolving understanding of the technologies involved. Additionally, a performance-based 

framework will increase the quantity and quality of information available to the 

public and other stakeholders. 

The regulatory landscape can be viewed as a continuum between prescriptive and 

performance- based regulation. Prescriptive regulation is based on prescribed actions. In contrast, performance-based regulation sets goals for outcomes. The specific 

means to achieve the outcome is left up to the regulated entities. Perhaps inevitably 

particular regulatory frameworks have become associated with particular political 

parties or even philosophical movements within political parties. 

New Zealand’s Building Act of 1991 was the first to fully implement a performance-based regulatory regime across a whole industrial sector. This legislation represented a specific philosophy based on faith in market forces and minimal governmental interference to maximize efficiency. Part of these reforms allowed private 

certifiers to monitor compliance with desired performance goals. Unfortunately within a decade New Zealand newspapers were investigating what became known as the 

‘‘leaky building crisis’’, caused by a pervasive failure of the regulatory approach. 

Over 18,000 houses were affected; many were determined to be uninhabitable. 

The record of an official inquiry in 2002 into the crisis identified a number of 

problems including imprecise specification of performance standards as well as systemic deficiencies in accountability and enforcement. New Zealand’s response to the 

leaky building crisis was the 2004 Building Act which created: increased accountability; introduced tighter specification of performance standards; stronger monitoring of inspection practices; and increased rigor for licensing of certifiers. 

Based on review of the New Zealand experience the following recommendations 

can be made to strengthen performance standard based approaches to regulating 

CO2 Sequestration: 

Create performance standards that are as clear and specific as possible 

Justice Breyer has noted that often performance standards are hard to enforce 

due to the difficulty of developing appropriate tests for adequacy of performance. 

Performance standards should be expressed in a quantitative form wherever possible. Clearly performance metrics that are expressed in well calibrated shades of 

grey (probabilistic) are to be preferred over binary black/white (or yes/no) measures. 

Create hybrid regulatory frameworks that combine traditional specification based 

approaches (where this makes sense) with performance based approaches. 

Some situations call for a ′′hybrid approach′′ that combines performance standards 

with prescriptive regulations. One approach is to add provisions for alternative compliance mechanisms. Such provisions can enables allow firms to ‘opt-out’ of prescriptive standards if they can get a comparable level of performance in other ways. 

Develop clear and effective reporting requirements 

If the required effort to implement the standards is unclear then this can increase 

the cost of compliance compared to prescriptive regulations. Where possible, for each 

permitted project, specific metrics should be developed for each performance standard. These metrics, once agreed on should become part of the permit. 

Create strong professional accountability of regulatory staff and third party certifiers. 

As was found in the ′′leaky buildings crisis′′ in New Zealand, performance based 

regulatory frameworks function as intended only if there is effective enforcement. 

Strong codes of practice for regulatory professionals and third party certifiers that 

encourage exercise of sound professional judgment should be required by Congress. 

Maximize transparency by increasing information available to the public 

Regulation determines levels of environmental quality through public processes. 

Increasing the amount and quality of information available to the public will improve the transparency of the regulatory process. Non-Government Organizations 

(NGOs) can play a very useful role in acting as surrogates for the local community 

in monitoring projects. 

Create an environment that encourages proactive compliance by regulated entities 

Incentives to reward sound stewardship could include ′′fast track′′ permitting; extension of permits to multiple injection projects in the same brine reservoir; and 

waiving of some requirements on the basis of an exemplary track record. 

Develop accountability through performance audits 

Strategies should include: (1) self audits by regulated entities themselves particularly when the self reporting is done by well trained, certified professionals; (2) independent audits by third party, certified professionals; (3) audits by a regulatory 

agency; and (4) review of audit results by independent oversight boards composed 

of experts in the field. 

90 

Build in ′′learn-as-you-go′′ into the regulatory framework as an ongoing adaptive 

approach to process improvement by systematically both tracking learning on multiple levels and achieving consensus on the key lessons learned. 

The Carbon Capture Leadership Forum has suggested that a ‘learn-as-you-go’ 

strategy will be essential to implement sequestration in a timely manner. The ultimate expression of ′′learn-as-you-go′′ is a regulatory framework that accommodates 

adaptive evolution of the permitting process itself. 

Proactively integrate computer modeling into the regulatory process to maintain 

both flexibility and accountability 

The results of computer simulations will likely play a key role in both preparing 

and evaluating permit applications for large scale CO2 injection projects. 

(C) CAN PERFORMANCE STANDARDS BE DEVELOPED FOR REGULATING CO2

SEQUESTRATION IN DEEP BRINE RESERVOIRS? 

Performance standards are objectives that the regulatory agency (representing the 

interests of society in general) place on regulated entities. 

The FutureGen Alliance’s Request for Proposals (RFP) for injection sites established a prescriptive standard for seals. The Alliance had specific requirements for 

an acceptable primary seal, stating that the seal ′′must have sufficient thickness 

(greater than 20 feet [6 meters])′′. Requiring a minimum thickness for a seal is an 

arbitrary prescription. A useful performance standard for an adequate seal is: 

Performance standard 1. The operator must demonstrate that the reservoir has a 

top seal and other elements of a natural and engineered containment system with 

petrophysical and geological properties consistent with protection of underground 

sources of drinking water (USDW) from contamination from injected CO2, pollutants 

mobilized by the CO2 injection, and/or water high in total dissolved solids (TDS) set 

in motion by pressures induced by the injection. 

Such a standard could be supported by more technical sub-standards such as: 

Performance Standard 1a. An acceptable seal must have either a measured capillary entry pressure higher than the predicted maximum pressure at the base of the 

seal or a combination of permeability and thickness such that the seal effects a sufficient barrier to the flow of CO2 under the conditions of the specific project such that 

the retention performance standard is assured. It is acceptable to document the effectiveness of the seal by analogy with the equivalent sealing unit elsewhere retaining natural gas or oil, assuming that enough information is known about each seal 

to consider them equivalent (in their permeability and capillary entry properties). 

Whether or not performance standard based regulations are integrated into the 

EPA’s approach to regulating CO2 sequestration, I believe that the EPA will need 

significant additions to their professional staff to enable effective regulation. Regulating CO2 sequestration will involve a wide range of scientific and engineering 

issues such as: geochemical interaction of rock, gas and brine; the geomechanical effects of high injection pressures; and evaluation of computer simulations of multiphase flow. All of these issues require well trained professionals to evaluate. Congress should make sure that the EPA has sufficient staff and resources to develop 

and enforce their regulatory framework for CO2 sequestration. 

EVALUATING THE RISKS ASSOCIATED WITH GEOLOGICAL CO2 SEQUESTRATION 

Based on the available information from over 35 years of CO2 injection into geologic reservoirs in the Permian basin of Texas and on scientific knowledge from natural CO2 reservoirs, I believe that large scale CO2 sequestration can be done safely 

and effectively without endangering the nation’s underground sources of drinking 

water (USDW). Although safety and health issues are always of paramount concern, 

the excellent safety and health record of the CO2 industry in the Permian Basin of 

West Texas, and the absence of known negative impact on USDW suggest that these 

issues are not a major component of the business risk faced by a putative carbon 

sequestration industry. Having said this, it is very unfortunate that very little research funding is available to study and assess the wealth of potential information 

available from studying the results of the long term CO2 injections in the Permian 

Basin by CO2 EOR operators. Apart from a small DOE funded research project 

through the Southwest carbon Sequestration Partnership and led by the BEG, only 

very limited research is being done in this crucial area. I recommend that Congress 

should appropriate funds for the DOE to support university research into CO2 sequestration associated with CO2 EOR particularly in the Permian basin which has 

the longest history of CO2 injection in the world. 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 

91 

rates incidental to CO2-EOR. Such funding would also help produce young engineers 

and geologists trained in CO2 related technologies and alleviate a shortage that is 

critical now and will grow more so in the near future. 

It has recently been suggested that an effective system of regulation for geologic 

sequestration should share the long-term risks of sequestration between the public 

and private entities. I prefer to place the emphasis not on the government sharing 

the long term risk but rather on reducing risk of leakage by creating a regulatory 

framework that: (1) provides a mechanism to assure optimal site selection (2) minimizes risk by requiring adequate site characterization; (3) assures early detection 

of any leakage by insisting on deep monitoring; and (4) requires preventive action 

to lower the chance of leakage leading to adverse outcomes. Government resources 

should be deployed early in the project life cycle, focused on optimizing selection and 

evaluation of sites. Providing careful oversight of risk assessments and then requiring early and vigorous implementation of preventative action will be more valuable 

than reserving resources to remediate problems that could have been prevented. 

In conclusion I am confident that we have the technical understanding, the scientific knowledge and the experience to implement CO2 sequestration on a large 

scale in such a way that the nation’s drinking water resources are effectively protected. 

Mr. GREEN. Time. You are over time. I appreciate your comment 

on the appropriations—Mr. Anderson? 

STATEMENT OF SCOTT ANDERSON, SENIOR POLICY ADVISOR, 

CLIMATE AND AIR PROGRAM, ENVIRONMENTAL DEFENSE 

FUND 

Mr. ANDERSON. Scott Anderson with Environmental Defense 

Fund, thanks for letting me be here. At the outset I would like 

[microphone cuts out]—thank you—thus joining the lower cost 

methods of addressing climate change. We do not know what the 

next decades hold in terms of coal demand. Whether its share of 

the market will be up or be down, but we are convinced that coal 

will be around for a long time, that CCS is an essential technology 

and that as a technological matter, if not a commercial matter, that 

this technology is ready to begin deployment now in carefully selected and carefully managed sites. In fact, there are already special situations where CCS is beginning to be deployed, but in general deployment of CCS is held back by two main factors, a lack 

of inadequate price signal from the market and uncertainty about 

the regulatory framework. We believe it is within our grasp to 

solve both of these problems. 

I would like to cover several things this morning. My main focus 

will be to suggest what regulatory elements are needed to manage 

the risks of geologic sequestration, particularly risks relating to 

drinking water, and to offer a preliminary assessment of the EPA 

rules. I would also like to comment, briefly, unless I run out of time 

on regional capacity assessments and offer a few observations on 

the liability issue. 

As to the elements of inadequate regulatory system, we believe 

it should be reasonably flexible to account for different geologic environments and evolving understanding of particular sites, that it 

should be adaptive in the sense that requirement should become 

more sophisticated as knowledge improves and that it should tend 

to be performance based, although some aspects of the rules ought 

to be more prescriptive than others. 

But being flexible and adaptive and performance based is not 

enough. It is also essential that regulations stay focused on assurVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00097 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
92 

ing that underground sources of drinking water are protected and 

this cannot be compromised. This focus includes rigorous standards 

relating to site characterization and selection, operations, adjustments to site characterization modeling and operations—I meant to 

say, based on experience, rigorous closure procedures, and very rigorous—this is the whole ball game—very rigorous standards for 

post-closure determinations that projects do not and will not endanger USDWs. 

Turning to the proposed rules, we are happy to say that our preliminary assessment is positive. In particular, we support the new 

Class VI idea. We support the broad approach to finding the area 

of review. We, generally, support the extensive level of information 

that is being required of permit applicants. And this is a key one, 

we are glad to see that the agency is avoiding using the simple passage of time in order to conclude that there are no problems. That 

is an insufficient standard. 

[The prepared statement of Mr. Anderson follows:] 

STATEMENT OF SCOTT ANDERSON

We appreciate the opportunity to speak to you today as the Committee examines 

the regulatory framework necessary for carbon sequestration, particularly measures 

that need to be taken to protect underground sources of drinking water. We also 

appreciate the opportunity to make a few comments regarding capacity assessments 

for the sequestration of carbon dioxide in geological formations. Climate change is 

the most important environmental issue of our generation and successful development and deployment of geologic sequestration is a critical path for accommodating 

coal, the world’s most abundant but carbon-intensive fossil fuel, to a carbon-constrained future. 

Environmental Defense Fund (EDF) is a national non-profit organization representing more than 500,000 members. Since 1967, we have linked science, economics and law to create innovative, equitable and cost-effective solutions to urgent environmental problems. My personal background includes more than 20 years representing independent oil and gas producers in Texas, and so I have some appreciation for many of the issues and concerns related to the underground storage of carbon dioxide. 

The House is doing important work to address the threat of climate change. The 

single most important thing the House can do to further the geologic sequestration 

of CO2 is to take action on cap and trade legislation, since such legislation would 

create a market value and a market mechanism for avoiding carbon dioxide emissions. Given the right incentives, we believe that the market will be far more effective and efficient in discovering necessary technologies of all types, including carbon 

capture and storage (CCS), than any suite of government mandates or subsidies, 

however well intentioned. 

Also vital is your interest in determining what regulatory measures are needed 

for geologic sequestration to satisfy the goals of the Safe Drinking Water Act. Without a sound regulatory framework, geologic sequestration of carbon dioxide could fail 

to live up to its promise and in fact lead to additional environmental problems. CO2

sequestration cannot be done everywhere and projects must be properly managed 

in order to be safe and effective. For good reason, public acceptance of CCS will happen only if the public is confident that rigorous and credible regulatory oversight 

is in place. Fortunately, developing sound regulations for geologic sequestration appears to be within our grasp and the country is making excellent progress toward 

achieving this goal. 

The fact that Environmental Defense Fund supports the deployment of CCS does 

not mean that we are champions of coal. We are pleased that people are increasingly recognizing that energy efficiency and renewables should play a leading role 

in energy and climate policy. As indicated by McKinsey and Company’s U.S. Greenhouse Gas Abatement Mapping Initiative, there are many efficiency and renewable 

energy strategies that are cost-effective and can be pursued even before CCS is a 

fully developed, commercial enterprise. CCS is an important part of the solution, but 

it is only a part. 

93 

Although we are not champions of coal at EDF, we are realists. Market forces dictate that coal will continue to be used for electricity production for the foreseeable 

future regardless of whether its share of the market goes up or down. Therefore the 

nation and the world need technologies that enable coal to be used in a manner that 

avoids significant greenhouse gas emissions. According to an IEA study released in 

2006, CCS could rank, by 2050, second only to energy efficiency as a greenhouse 

gas control measure. The Intergovernmental Panel on Climate Change (IPCC) 

projects that CCS could, by 2100, contribute 15 to 55% of the greenhouse gas reductions needed to avert catastrophic climate change. 

I would like to cover several things this morning. My main focus will be to suggest 

what regulatory elements are needed in order to manage the risks of geologic sequestration, particularly risks that are relevant to the protection of groundwater. I 

will offer a preliminary assessment of the proposed rules released last week by EPA. 

I also will comment briefly on progress being made in assessing the nation’s geologic 

capacity for CO2 sequestration. Finally, I will offer a few observations on liability 

issues since there is a relationship between an effective regulatory program and the 

broader legal context in which such regulation takes place. 

REGULATORY CONSIDERATIONS - MEASURES NEEDED TO PROTECT UNDERGROUND

SOURCES OF DRINKING WATER

Geologic sequestration of carbon dioxide is feasible under the right conditions. It 

has been successfully demonstrated in a number of field projects, including several 

large projects. The IPCC Special Report on Carbon Capture and Storage concluded 

in 2005 that the fraction of CO2 retained in ′′appropriately selected and managed 

geological reservoirs′′ is likely to exceed 99% over 1000 years. The IPCC also concluded that the local health, safety and environmental risks of CCS are comparable 

to the risk of current activities such as natural gas storage, enhanced oil recovery 

and deep underground storage of acid gas if there is ′′appropriate site selection 

based on available subsurface information, a monitoring programme to detect problems, a regulatory system and the appropriate use of remediation methods to stop 

or control CO2 releases if they arise.′′ 

While there is little doubt that geologic sequestration is feasible, and little doubt 

that successful projects are technically achievable today, knowledge and understanding are expected to increase dramatically as the technology begins to be deployed on a large scale. Current projects are highly customized. Neither government 

nor industry have yet developed standard protocols for fundamental aspects of the 

process such as site characterization and monitoring. In fact, due to geologic variability both between and within sites, project design will always need to be site-specific to a significant degree. Still, the IPCC Special Report projects that increasing 

knowledge and experience will ′′reduce uncertainties′′ and ′′facilitate decision-making.′′ 

In other words, we know enough to get started but we can expect to experience 

a lot of ′′learning by doing.′′ 

What are the implications of this for the regulatory system? We believe at least 

four recommendations are in order to account for the fact that increasing knowledge 

and experience will facilitate rational decision-making in different ways over time: 

•Lean toward a performance-based system. ′′Performance-based′′ regulations and 

′′command-and-control′′ regulations do co-exist -- they are two poles on a continuum; 

•Be reasonably flexible. Different projects will present different risks and uncertainties, and the uncertainty presented by a single project will tend to decline over 

time; 

•Require projects to employ an iterative process, informed by monitoring results 

and perhaps even by experience gained from other projects, in order to reduce uncertainty and drive improvements in site characterization, site suitability assessment, models, model inputs, field operations, the monitoring plan itself, and the remediation plan; 

•Write ′′adaptive′′ rules. Look for language that automatically accommodates 

evolving best practices. Also structure rules to make use of evolving knowledge at 

each particular site. Be willing to amend rules when needed to protect the environment, giving due regard to the fact that it generally is in the public interest for the 

regulatory framework to give the regulated community the certainty needed to make 

investment decisions. 

These general recommendations are important, but it is not enough for rules to 

be flexible, adaptive and performance-based. It is essential that rules be grounded 

in a thorough, scientific understanding of the risks involved and that rules assure 

that the risks will be managed properly. In order to accomplish this, some aspects 

of the rules (e.g. site characterization and site selection requirements) will need to 

94 

be more prescriptive than others and the regulatory program must always remain 

focused on assuring that underground sources of drinking water are not endangered. 

How should this focus on protecting underground sources of drinking water be 

maintained? Regulations governing the geologic sequestration of carbon dioxide 

must include clear and rigorous standards relating to: 

•Site characterization and selection (including modeling, capacity estimates for 

long-term retention, and risk assessment) 

•Operations (including well construction and maintenance, injection practices, purity of the injection stream, monitoring, reservoir pressure management, reporting 

requirements, and preventive action and/or corrective action as necessary) 

•Periodic adjustments over the life of the project regarding any of the above elements if appropriate based on project experience 

•Closure procedures 

•A post-closure determination that the project does not and will not endanger 

USDWs 

EPA’S PROPOSED RULES FOR GEOLOGIC SEQUESTRATION

How well do the proposed rules that EPA released on July 15 meet these criteria? 

EDF is still in the preliminary stage of evaluating the proposal, but it is clear that 

the rules have much to say about each of the regulatory elements just mentioned. 

The Agency appears to have thoroughly reviewed most of the issues involved and 

attempted to craft a set of rules that is both protective of the environment and not 

unduly burdensome for industry. EDF will undoubtedly develop many recommendations for adjustments during the public comment period, including recommendations 

of fundamental importance, but overall we are pleased at this stage with what we 

have seen. 

Although we are still at an early stage of assessing the proposal, we can offer the 

Committee some specific comments at this time. For convenience, I will divide our 

observations into positive comments and not-so-positive comments. First the positive: 

1.We believe that the proposal to create a new Class VI category for long-term 

geologic sequestration of carbon dioxide is a good idea. Creating a separate category 

is justified by the differences between long-term sequestration and other injection 

operations - differences that relate to scale, duration, and pressure regimes, and 

perhaps by other differences as well. Section 146.81(a). 

2.Because of the differences just mentioned, we believe that EPA is right to propose to maintain different regulations for Class II wells used for enhanced oil recovery projects. If such wells begin to be used for the purpose of long-term sequestration, Class VI regulations would generally apply at that time. See section 146.81(c). 

3.The proposal defines the Area of Review (AOR) to include the entire area that 

may be impacted by the injection activity, rather than defining the AOR according 

to a fixed radius around injection wells as is sometimes done in the Underground 

Injection Control (UIC) program. This is a good and important proposal because of 

the potentially large areal extent of sequestration projects and the risks that may 

be present due to elevated pressure. Section 146.81(d). 

4.Although some adjustments are probably in order, the scope of information that 

the proposed rule would require as part of a Class VI permit application appears 

to be generally reasonable. Section 146.82. 

5.Similarly, although some adjustments are probably in order, the proposed minimum criteria for siting appear to be generally reasonable. The criteria have much 

in common with both established (UIC) principles and with specific recommendations made by stakeholder groups such as the Interstate Oil and Gas Compact Commission and the Ground Water Protection Council. Section 146.83. 

6.While once again some adjustments are probably in order, another positive and 

important provision is the proposal to require a testing and monitoring plan to 

verify that the sequestration project is operating as permitted and is not endangering USDWs. Section 146.90. 

7.The proposed rule properly avoids relying on the simple absence of known problems over a given amount of time following cessation of injection as the basis for 

determining that USDWs are not being endangered. Section 146.93. 

8.The proposed rule includes emergency and remedial response requirements that 

are clear and rigorous. If an operator obtains evidence that the injected carbon dioxide steam and associated pressure front may endanger a USDW, the operator must 

immediately cease injection, take all steps reasonably necessary to characterize any 

release, notify the permitting agency within 24 hours, and follow previously approved plans to address movement of injection or formation fluids. Section 146.94. 

95 

We offer the following preliminary comments regarding aspects of the proposed 

rules that may merit adjustment: 

1.Although the proposal defines the Area of Review as the region that may be impacted by the injection activity, the proposed methodology for determining this region may not focus adequately on the potential effects of elevated pressure and displaced brine, as distinct from effects of the carbon dioxide itself. Section 146.81(d). 

2.The proposal should take a more sophisticated approach to regulating injection 

pressure. Injection pressure limitations need to take account of the possibility that 

under certain conditions faults that would otherwise be nontransmissive can become 

transmissive even if injection pressures are kept below the level necessary to create 

new fractures or propagate existing fractures. No single across-the-board pressure 

limit, including the proposed requirement that injection pressure not exceed 90 percent of fracture pressure, is adequate for this purpose. See section 146.88(a). 

3.Although the proposal properly avoids using the simple absence of known problems over a given amount of time as the basis for determining that USDWs are not 

being endangered following the cessation of injection, the requirement that the carbon dioxide plume and pressure front be ′′stabilized′′ in order to make this finding 

is probably not appropriate as a general standard. The World Resources Institute 

is in the process of completing a set of Guidelines that may prove helpful on this 

important issue. See section 146.93(b). 

GEOLOGIC STORAGE CAPACITY ASSESSMENTS

EDF commends the Department of Energy’s Regional Sequestration Partnership 

Program for developing the Carbon Sequestration Atlas of the U.S. and Canada. 

And we look forward to the more detailed assessments of long-term storage capacity 

contemplated by the USGS. It is important, however, to understand the purposes 

for which such studies are and are not useful. Regional assessments can provide 

general information about where appropriate sequestration sites may be located. 

They can provide regional capacity estimates that are either more or less accurate 

depending on the type of analysis that is undertaken. Regional assessments cannot, 

however, confirm that a particular site is or is not suitable for a sequestration 

project. Determining the suitability of a site necessarily requires extensive data collection and geologic characterization specific to the location under consideration. 

LIABILITY RULES AND THE REGULATION OF GEOLOGIC SEQUESTRATION

A number of people appear to take it as a forgone conclusion that ′′liability relief′′ 

is necessary in order for a geologic sequestration industry to develop. Those holding 

this view are rarely specific about the ′′liability relief′′ they have in mind. EDF is 

not convinced that any ′′liability relief′′ is needed for the carbon dioxide sequestration industry in the long run, although we are open to exploring the possibility of 

special rules and institutions for early projects (e.g., liability limits for individual 

companies in carefully defined situations coupled with an industry-funded risk pool 

to cover damages in excess of such limits). 

We would offer the following observations on the subject of ′′liability relief′′: •Privatizing benefits while socializing risks is a good way to incentivize inefficient 

and even dangerous behavior. •Current liability rules grounded in common law and statutes serve an important 

purpose - encouraging people to act as their fellow citizens and policymakers expect 

them to act. •There is no special ′′liability relief′′ for the enhanced oil recovery business or the 

underground injection of hazardous waste business. Natural gas storage is not subject to UIC regulations, but natural gas storage operators are not shielded from liability as a general matter. Yet all three of these businesses inject material into geologic formations and appear to have little trouble attracting investment in the marketplace. •If liability rules incentivizing good behavior were absent, regulators might perceive a need to adopt rules that were more detailed and prescriptive than would otherwise be the case. •Those who advocate modification of liability rules for carbon sequestration ought 

to be clear about what liabilities they would like to see addressed. Do they mean 

to include liability for contract violations, fraudulent acts, or conversion of other 

people’s property? Do they mean to include liability for intentionally inflicted harms 

or gross negligence? Do they mean to include all types of damages or just certain 

types of damages? 

•It is one thing to transfer the risk of liability for a well-executed sequestration 

project, and something else entirely to relieve an operator who has created a project 

that presents significant risks. In order to distinguish between these situations and 

96 

maintain incentives for workmanlike behavior, we believe that the nature and perhaps the existence of any liability modification should depend on whether a project 

demonstrates following closure that there is a high degree of certainty that USDWs 

are not and will not be endangered. •A useful way to think about possible modifications of liability rules applying to 

geologic sequestration activities would be to ask what novel risks are presented by 

this activity, the extent to which these risks can be handled in the current marketplace (e.g., insurance, investors shouldering risk in expectation of a higher return), 

and the extent to which it might be possible and desirable to create new private 

sector mechanisms (e.g., industry risk pools, new forms of insurance) to address any 

real problems with capital formation. •In the event it is found that investment in geologic sequestration is unreasonably 

hampered by risk management issues, the solution should be tailored to fit the problem and to the extent possible the solution should make use of market mechanisms 

and risk-sharing within the industry. 

CONCLUSION

In a carbon-constrained world where market forces are harnessed to make sure 

that society’s carbon footprint is reduced in an economically rational fashion, Environmental Defense Fund foresees a dramatically increased role for renewable energy 

and for energy efficiency. At the same time, since any complete transition away 

from fossil fuels is likely to take a very long time, we foresee a long-term need to 

deal with CO2 emissions from coal-based facilities. The sooner we begin to deploy 

CCS technology on a large scale the better. We applaud you for working on measures to make this a reality. 

Mr. GREEN. Thank you. Mr. Yamagata. 

STATEMENT OF BEN YAMAGATA, EXECUTIVE DIRECTOR, COAL 

UTILIZATION RESEARCH COUNCIL 

Mr. YAMAGATA. Mr. Chairman, I will—even though I am an attorney. First let me associate myself, point number one, with comments that Congressman Murphy made earlier about the need for 

coal, the importance of coal, the challenges to coal today, but also 

the fact that we need coal. To the extent that that is the case and 

while there are questions about CO2 which is one of the reasons 

why we are not building coal plants generally, there is a dash to 

gas and in that context. FERC has already implied or suggests that 

we are going to experience rather significant increases in the cost 

of electricity. That is, sort of a perspective, point number one. 

Point number two is that technology is really important to meeting the Nation’s climate goals. Let me give you a factoid, if I may. 

A massive study, just completed by the International Energy Agency identified technologies necessary to meet a global reduction in 

greenhouse gas emissions of 50 percent below current levels by 

2050. CCS, carbon capture and storage, technologies were associated with 20 percent of the total reductions required. The point 

here is, if CCS cannot be made to work here in the United States 

and India and in China, it is not coal that will be in jeopardy, it 

will be the whole issue of trying to meet goals with respect to climate change. 

Point number three, CCS should pose no risk to groundwater so 

long as geologic storage is properly managed. This is the point that 

other panelists have made this morning. The Intergovernmental 

Panel on Climate Change concluded that 99 percent of the CO2

stored in ‘‘appropriately selected and managed geological reservoirs’’ will remain permanently stored in those reservoirs for over 

a thousand years or more. 

97 

Point four, we see four major barriers to the successful deployment of CCS technologies. First, is that all of the pieces needed for 

capture and storage of CCS are in existence. Most of these pieces 

have been used in the petrol-chemical industry for years, but we 

have never assembled these pieces, integrated them together at a 

commercial scale for use in power generation. So, in point, we have 

no experience here, not in the United States, not world-wide. All 

of the pieces need to be put together. 

The second barrier is that related to—and the subject of most of 

the conversation this morning—we have very limited experience 

with storing large volumes of CO2. The good news is, it looks like 

we have, in the North American continent, very huge reservoirs 

that might be capable of taking the CO2 that is available or that 

is emitted today. 

The third barrier is cost. For a power production facility, the addition of CCS systems, using currently available technology, could 

double the cost of electricity when compared to a basic pulverized, 

coal power plant that could be constructed today without CCS. To 

address these first three barriers, cost, integration and know-how 

with respect to storage, CURC has proposed a program that has a 

cost in excess of $50 billion over an 18 year period to focus our efforts on CCS research development and demonstration, but also, 

and importantly, to start the process of ‘‘putting steel in the 

ground’’. So with available technology, things that we know how to 

do today, we should start capturing and storing CCS and get some 

of that experience learned by doing. 

The fourth barrier, as defined in this whole session today, is the 

absence of a defined regulatory structure to govern the sequestration of CO2. The EPA’s proposed rule for underground injection 

control has been that discussion today, and addressing part of the 

issues with respect to sequestration. This is a proper rule where 

EPA has aligned itself. That is the limit of their responsibility as 

provided under the Safe Drinking Water Act, but there are really 

other regulatory structures that need to be dealt with, some of 

which have been alluded to today, compression issues, purity of 

CO2, the transport of the CO2, questions about ownership of the 

pore space, and of course, long-term liability of CO2 ownership. 

None of these have been addressed. We call upon the Congress and 

the Executive branch to address these particular issues, which are 

very important. 

And, finally, let me say that with respect to early adopters, people who are thinking about and willing to take on the projects of 

CCS today, some clarity needs to be given in the terms of long-term 

liability. Our proposal is that with respect to a limited number of 

these projects, Congress or State governments must take on the responsibility of transferring, or taking the transfer, of this long-term 

liability once the projects have been operated and successfully 

closed in. 

Mr. Chairman, I thank you for the time you have given me and 

I look forward to your questions. 

[The prepared statement of Mr. Yamagata follows:] 

98 

STATEMENT OF BEN YAMAGATA

REALIZING THE POTENTIAL OF CARBON CAPTURE AND STORAGE TECHNOLOGY

INTRODUCTION

The Coal Utilization Research Council (CURC) is an association of coal stakeholders which has the primary purpose of fostering programs of technology research, 

development, demonstration, and deployment of technologies to enable the continued economic and energy security benefits that derive from coal use, in a manner 

that is consistent with the nation’s environmental policies and goals. CURC members include major U.S. coal companies, coal-using electric utilities, manufacturers 

of power plants and power plant environmental control systems, major universities 

with engineering programs related to coal technologies, and major coal-related associations or institutes including the National Mining Association, Edison Electric Institute, the National Rural Electric Cooperative Association, and the Electric Power 

Research Institute (a list of members is attached). Our major focus is on coal-based 

power production, because that sector consumes over 90% of U.S. coal production, 

but our members are also involved in technologies that convert coal to substitute 

natural gas, chemical feedstocks and liquid transportation fuels. In recent years 

CURC’s highest priority has been the research, development, demonstration and deployment of carbon capture and storage (CCS) technologies. 

This written statement focuses upon the need for coal in supplying reliable, lowcost, environmentally acceptable, energy to American consumers and the need to 

successfully address concerns about global warming impacts associated with the use 

of coal. 

ADEQUACY AND COSTS OF ELECTRICITY CAPACITY IN THE U.S. 

The U.S. power sector is showing signs of serious stress. In reports issued in May 

and June of this year, the Federal Energy Regulatory Commission (FERC) pointed 

to increasing use of relatively costly natural gas and declining electric capacity reserve margins. FERC has predicted 60-120% increases in wholesale electricity prices 

this summer compared to last summer.1 These reports followed last winter’s report 

by the North American Electric Reliability Corporation (NERC) that reliability of 

electricity supply in the U.S. had declined, and would fall below industry standards 

of acceptable reserves on both U.S. coasts by 2009.2

Attempts to construct coal-fueled power generation have been met, in many instances, with opposition by non-governmental entities and deepening concerns over 

costs and CO2 impacts by government entities. During 2007, over 30 proposed coalbased power plants were postponed or cancelled. Proposed plants were stopped by 

Public Utility Commission objections to escalating costs (or potential future costs related to CO2 emissions), or by environmental permitting agency objections to CO2

emissions, even in the absence of CO2 regulatory requirements. The general response has been to propose the construction of natural gas-based power plants that 

are less costly to construct, easier and quicker to obtain necessary government permits, and emit about one-half the CO2 of a coal-based power plant. But these generating plants will use a fuel that currently costs more than five times as much as 

coal. The DOE/Energy Information Administration predicts electricity price increases of 15% by the end of 2009, but utilities in a number of states have already 

registered rate increase requests of 20-30%, and most of these have cited escalating 

fuel prices.3

The economic challenge of climate change mitigation must somehow be accommodated in this already highly volatile marketplace. 

CCS TECHNOLOGY IS CRITICAL TO MEETING THE NATION’S CLIMATE GOALS

The CO2 emissions from coal (about 33% of U.S. manmade CO2 emissions) and 

natural gas-based power (natural gas-based electricity also contributes to the U.S. 

total CO2 emissions - about 6% of the total) constitute a large percentage of overall 

CO2 emissions even while these fossil fuels contribute, by far, the largest percentage 

of available electric capacity to the Nation’s power grid. Those CO2 emissions can 

be reduced by improving generation efficiency, or by improving end-use efficiency, 

but a major reduction will require the widespread adoption of carbon capture and 

storage (CCS) technology. CCS technology involves two steps: separation and compression of CO2 at the power plant, and transport and storage of CO2.4

The significance of CCS technology to achieving climate goals was demonstrated 

in a massive study published this year by the International Energy Agency (IEA), 

an arm of the (spell out acronym)OECD. The study, Energy Technology PerspecVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00104 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
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tives: 2008, identified technologies necessary to meet a global reduction in greenhouse gas emissions of 50% below current levels by 2050. CCS technologies were 

associated with 20% of the total reduction required, and the IEA stated that, ′′There 

is an urgent need for the full-scale demonstration of coal plants with CCS.′′ In EPA’s 

analysis of S.2191, the Lieberman-Warner climate bill (as initially introduced), that 

Agency determined that CCS was critical to controlling overall compliance costs. 

More recently, Senator Bingaman emphasized the need to pursue CCS technology 

and stated, ′′We need to invest in this technology agenda immediately, even before 

the implementation of a cap-and-trade system, so we can figure out right away if 

our caps are based on technically viable options ..′′ 

In other words, if CCS cannot be made to work, it is not coal use that is in jeopardy, it is the climate goals that many (including many in Congress) are seeking 

to achieve. 

CCS RISKS TO GROUNDWATER

On July 15, EPA proposed rules to regulate CO2 storage through the Underground Injection Control (UIC) program. The major potential impacts of CCS on underground sources of drinking water (USDW) were identified as: leaching of metals 

and mobilization of other contaminants by CO2 or dilute carbonic acid formed from 

CO2, and contamination of drinking water by pollutants in the CO2 injectant stream 

(the CO2 itself is not a problem). In other words, if these impacts were to occur they 

would most likely be the result of an improperly managed geologic storage facility 

in which CO2 leaked from its designed containment area and reached an USDW. 

Both the rules recently proposed by the US EPA and model State regulations developed by the Interstate Oil and Gas Compact Commission (IOGCC) include provisions for selecting storage sites which have a high probability of retaining injected 

CO2. These proposed programs also include requirements for periodic or continuous 

monitoring of conditions underground to detect and mitigate unexpected leaks before the CO2 would ever reach valued USDW resources. 

It should be noted that the Intergovernmental Panel on Climate Change (IPCC) 

has concluded that, ′′Observations from engineered and natural analogues as well 

as models suggest that the fraction [of stored CO2] retained in appropriately selected and managed geological reservoirs is very likely to exceed 99% over 100 years 

and is likely to exceed 99% over 1,000 years.′′ Experts from around the globe agree 

that once properly stored, the likelihood of any significant leakage of CO2 is miniscule. 

MAJOR BARRIERS TO CCS DEPLOYMENT

CURC believes that there are four major barriers to deployment of CCS technologies. •The first is that the needed capture technology, which exists and has been used 

in the petrochemical industry, has never been deployed on a commercial scale with 

power generation. Integrating these CCS systems, which can consume 15-30% of the 

energy used at a power plant, with the basic power plant system is challenging. •The second barrier is that we have very limited experience with storing large volumes of CO2. The four largest commercial scale projects in the world, taken together, are approximately the storage rate required for 85% capture on one large 

coal-fired power plant. EPA confirms what the Department of Energy and others 

have reported, that there are vast potential resources within the North American 

continent to store as much as 3,900 billion tons of CO2; current annual CO2 emissions for all U.S. sources are approximately 6 billion tons so there is potentially 

hundreds of years of storage capacity available. •The third barrier is high cost. The four CO2 storage projects cited above are all 

non-power applications in which the separation of CO2 from other gases is part of 

the basic process of energy production or conversion, and creates very little additional cost. For power production, the addition of a CCS system, using currently 

available technology, can double the cost of electricity generation, compared to a 

basic pulverized coal power plant that could be constructed today without CCS. •The fourth barrier is the absence of a regulatory framework governing storage 

of CO2. Regarding this last barrier, two potential regulatory frameworks have received attention. The first is the aforementioned EPA proposed rule on UIC. That rule is focused almost entirely on potential impacts on USDW, as it must be since it draws 

its authority from the Safe Drinking Water Act. The second is a set of model legislation and model implementing regulations developed by the Interstate Oil and Gas 

Compact Commission (IOGCC). The IOGCC package is much broader in scope than 

the EPA proposed rules because it includes its own enabling legislation specifically 

100 

tailored for CO2 storage systems. The IOGCC proposed rules draw from two decades 

of state regulatory and industry experience with compression, transport, and injection of (primarily natural) CO2 for enhanced oil recovery. 

RECOMMENDATIONS TO OVERCOME BARRIERS TO CCS DEPLOYMENT

CURC believes that two actions are needed over the next couple of decades to 

overcome the four principal barriers to CCS deployment that are identified above. 

The first action is that we must act now to provide financial incentives that result 

in immediate deployment of a limited number of CCS-equipped power plants or synfuel facilities equipped with currently available CCS. Without hands-on experience 

integrating CCS technology with power plant technology, and the associated experience with large-scale CO2 storage systems in multiple geological formations, technology will not reach a full-deployment capability. Industry, regulators and the public need this early experience to validate our ability to address CO2. In addition, 

early CCS projects - undertaken now - will assist in realizing cost reductions via 

this ′′learn by doing′′ effort. 

We need to recognize that CCS deployment will be a ′′crawl, walk, run′′ process, 

rather than one in which we begin by ′′running.′′ This technology maturation process 

- first crawl, then walk, and finally, run -- has several important implications for 

policy makers. One immediate policy implication is that government financial incentives should not be predicated or conditioned on achieving high fractions of CO2 capture, like 85% or 90% capture. Such a significant percentage requirement is tantamount to running when we do not yet know how to crawl. It is true that we need 

experience with large-scale storage, but that can be better accomplished with a requirement for a significant annual storage tonnage, such as one million tons per 

year of CO2 storage. 

Another policy implication is that we need a flexible interim set of rules for CO2

storage for those willing to be the ′′first adopters′′ of CCS projects. It needs to be 

emphasized that the proposed EPA rules only cover one aspect of the needed legal 

framework, that is, the injection of CO2 into underground storage reservoirs. In addition, these rules will apply well into the future and for vast tonnages of stored 

CO2 and given this importance and longevity the actual adoption of these rules may 

be years away. For those early adopters of CCS projects that are coupled to coalbased energy conversion projects wishing to go forward now, we need an interim approach that addresses both EPA’s concerns as well as broader legal and regulatory 

uncertainties that are outside EPA’s legislative authority. CURC is very mindful of 

the absolute need to protect the public and USDW, that will be achieved presumably 

through the adoption of some form of the proposed EPA regulations for CO2 injection as well as state or federal adoption of ′′how to′′ procedures as reflected, in part, 

by such model legislation and regulations as developed by the IOGCC. Again this 

process to be accomplished correctly may require years to complete. And, it should 

be emphasized that it is far preferable ′′to get it done right than to get it done 

quick.′′ 

The CURC proposes an interim program that is predicated upon an assurance to 

′′first adopters′′ that the long-term liability of stored CO2 would be transferred to 

and accepted by government. Initially, a CCS project would be responsible for the 

storage of CO2 during operation of the project and for a period of time (e.g. ten 

years) after cessation of project activities during which the owner or operator would 

remain responsible for monitoring and verification post-storage shutdown. Without 

such assurances through some form of interim program, it is difficult to foresee how 

any initial CCS project, not knowing the ′′rules of the road′′ can proceed. 

This Committee is urged to become actively involved in the consideration of such 

an interim program as a necessary step to avoid the delays that will confront the 

early demonstration and deployment of commercial-scale CCS projects that will otherwise await the installation of a regulatory and liability structure. 

A final policy implication is that these pioneering CCS projects will not finish the 

job. These near-term activities have the potential to greatly accelerate full deployment of CCS technology. However, in order for this technology to be affordable, both 

in the U.S. and for the high growth coal nations of China and India, we must redouble our commitment to RD&D. This includes research on more efficient coal-based 

power systems (which emit less CO2 even without CCS systems), as well as research 

on lower cost power systems equipped with CCS. Little progress will be registered 

in mitigation of CO2 emissions from coal if we fail to develop CCS technologies that 

are affordable for all major coal using nations. But the larger message here is that 

it will take time to complete this needed RD&D. If we press for immediate emission 

reductions from the power sector, we are likely to see utilities abandon coal for natural gas, an action which will meet their early emission compliance needs. However, 

101 

the reliable and affordable CCS technology which is ultimately needed for both coal 

and gas will not receive priority attention under this scenario, and will therefore 

not be available when it is needed. For more information on this longer term RD&D 

effort I would refer readers to the CURC-EPRI Roadmap. 

All told, CURC estimates that the two technology development programs presented here, the immediate deployment program and the longer term RD&D effort, 

will cost well over $50 billion, spread over two decades. If we are to be successful 

Congress must join with industry to jointly provide sufficient time, focus and money 

to develop and apply those technologies that will allow us to be successful. A sustained partnership of great magnitude will be required. 

CONCLUSIONS

The following general conclusions can be drawn from the above discussion: 

•The U.S. power sector, beginning now, will exhibit sharp increases in prices, 

compared to previous years. Electricity reliability will deteriorate over the next few 

years, with a higher probability for blackouts during peak demand periods, beginning in some regions in 2009. 

•Coal provides one-half the electric power generated in the U.S. and one-third of 

the nation’s CO2 emissions. Coal is essential for meeting U.S. power demand, and 

CCS technology is essential for coal to meet its environmental responsibilities. CCS 

is also needed for natural gas generating technologies, which contribute a significant 

portion of U.S. power generation. 

•Storage of CO2 presents two types of risk to underground supplies of ground 

water: potential contamination by metals and other compounds already in the 

ground, but mobilized by CO2 injection or weak acids created by CO2 injection and 

migrating to the USDW reservoir; and contamination by trace materials injected 

along with the CO2. Both of these risks would only manifest if the CO2 storage 

structure were improperly chosen or maintained. Both EPA and the IOGCC have 

formulated regulations that, if adopted and implemented, would negate that eventuality. The IPCC has concluded that a properly sited CO2 storage project will have 

an extremely low probability of releasing CO2 into rock strata where contamination 

of ground water could occur. 

•CCS is an emerging technology that must overcome significant barriers before it 

will be available for broad deployment to mitigate CO2 emissions from the power 

sector. However, CURC and others have identified those barriers and CURC has 

proposed a reasoned plan to overcome them. The plan includes immediate deployment of a small number of power plants with existing CCS technology now, and a 

longer term RD&D effort to produce a sharp reduction in the cost of CCS. CURC 

believes that a nurturing regulatory environment and financial assistance will be 

needed to ready CCS technology for broad commercial deployment. 1 2008 Summer Market and Reliability Assessment, Item No.: A-3, Federal Energy Regulatory Commission, May 15, 2008; and Increasing Costs in Electric Markets, Item No.: A-3, FERC, June 19, 2008. 22007 Long-Term Reliability Assessment: 2007-2016, North American Electric Reliability Corporation, October 2007. 3Short Term Energy Outlook, July 2008, USDOE Energy Information Administration. Price Jolt: Electricity bills going up, up, up, USA Today, June 20, 2008. 4CCS, in this statement, can refer to both the storage of CO2 into deep geologic 

formations as well as the use of CO2 in the recovery of crude oil referred to as enhanced oil recovery (EOR). Also references to CCS, in the context of possible government incentives, can also include CO2 captured from coal to liquid fuels, chemicals, 

industrial feedstocks or substitute natural gas. 5Finding the Path Forward on Climate Legislation, speech to NDN, Sen. Jeff 

Bingaman, July 9, 2008. 6EPA press release and Notice of Proposed Rulemaking are available at: http:// 

yosemite.epa.gov/opa/admpress.nsf/bd4379a92ceceeac8525735900400c27/ 

d35b72dfe481043b85257487005e47cd!OpenDocument. 7Carbon Dioxide Capture and Storage, IPCC, 2005. 

8Moreover, for over 15 years, acid gases (including CO2 and much more hazardous 

hydrogen sulfide) have been injected into saline geologic formations in western Canada. The Alberta Research Council and Energy & Utilities Board report that, ′′By 

the end of 2003, approximately 2.5 Mt CO2 and 2.0 Mt H2S have been successfully 

injected into deep hydrocarbon reservoirs and saline aquifers in western Canada. . 

No safety incidents have been reported in the 15 years since the first operation ..′′ 

These injection and storage operations are smaller than those needed for electric 

power plants and the Canadian report cited the need for assessing long-term containment and large-scale operations. From: Overview of Acid-Gas Injection OperVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00107 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
102 

ations in Western Canada, Bachu (Alberta Energy and Utilities Board) and Gunter 

(Alberta Research Council), Proceedings of the 7th International Conference on 

GHG Control Technologies, IEA GHG Programme, 2005. 9These projects include: Sleipner, which captures 1 million tonnes per year of CO2

from natural gas production in the North Sea; Weyburn, which captures 1.7 million 

tonnes per year from substitute natural gas production from coal in North Dakota; 

In Salah, which captures 1 million tonnes per year from natural gas production in 

Algeria; and Snohvit, which captures 0.7 million tonnes per year from natural gas 

production in the Barents Sea. 10Storage of Carbon Dioxide in Geologic Structures - A Legal and Regulatory 

Guide for States and Provinces, IOGCC, September 25, 2007. 11It is not intended to assert that the adoption and successful pursuit of these two 

programs will thereby be sufficient to insure the continued long-term use of our Nation’s coal resources nor the widespread commercial use of these technologies. Adoption of these programs will best insure that CCS technologies will have been developed and initially deployed, widespread commercial use may require additional programs or assistance. 12CURC - EPRI Roadmap for Advanced Coal Technologies, www.coal.org. 

Mr. GREEN. Thank you. I think I will try and get my questions 

out of the way and as soon as I finish mine we have a—just heard 

the 10 minute bell and if members want to go to—and we will reconvene as soon as the votes are finished. 

Mr. Duncan, again, welcome to Washington. Your testimony cited 

that 80 percent of the world’s underground injection of CO2 occurs 

in the Permian Basin in west Texas to enhance domestic oil production. In what way is our experience with enhanced oil production, or EOR benefit sequestration efforts to reduce greenhouse 

gasses—emissions? And I know you said in your testimony that 

there is no monitoring now, if there are releases from that, but we 

have a lot— 

Mr. DUNCAN. Let me correct that. There is monitoring for safety 

purposes, but not in terms of broad field leakage. So we monitor 

around the wells. We monitor the pipelines and so on. I think the 

first basic experience is handling CO2, transporting CO2, pipelining 

CO2 and the CO2 pipeline industry has the best safety record of 

any pipeline in the Country. Their safety record is better than natural gas, so we have been able to demonstrate that you can 

produce CO2 and pipeline it over large distances safely and effectively. 

Mr. GREEN. We do have some CO2 pipelines that are in functioning now. 

Mr. DUNCAN. Yes. There is a large network of CO2 pipelines that 

bring natural CO2, largely from Colorado, down into west Texas. 

They also separate CO2 in Texas from natural gas production and 

pipeline that out to the oil fields. 

Mr. GREEN. Okay. 

Mr. DUNCAN. So I think in terms of the technology for injecting 

CO2, monitoring CO2 in the subsurface, this is all being developed 

by the oil industry, in relationship to CO2 enhanced oil recovery. 

Mr. GREEN. EPA estimates that domestic oil recovery equals only 

about four percent of the total domestic capacity for sequestration, 

which sounds small, but that seems— that is still 90 gigatons of 

CO2. Can you give us a ballpark estimate on how long it would 

take us to fill up the bulk of that capacity under an aggressive and 

a conservative outlook for CCS? 

103 

Mr. DUNCAN. I can give you some numbers for Texas. The Bureau of Economic Geology has estimated, fairly conservatively I 

think, that there is 3.8 billion barrels of oil could be recovered in 

Texas, outside of the Permian Basin. That is in the Gulf Coast and 

east Texas, through use of CO2. We have also estimated that somewhere between five and six billion tons of CO2 could be sequestered 

as part of this EOR. To give you some idea of the magnitude of 

that, station resources in the Gulf Coast will produce, over the next 

50 years, probably about 60 billion tons. So it is not going to take 

care of all the CO2, but it will help us develop a pipeline infrastructure compression that can be later used for injecting into brines. 

We have also estimated there is over 200 billion tons of capacity 

in the Deep Brine’s along the Gulf Coast and in east Texas. 

Mr. GREEN. Okay. I appreciate your testimony. It is helpful. One 

of the questions that came from some of the committee members 

at the first panel and I guess for this panel is, in the ground now, 

the experience in west Texas particularly, CO2—and if often times 

after a decade or two, it merges with whatever rock formations is 

there, particularly if there is a coal seam, and very deep. Is that 

generally what you understand, or with your experience? 

Mr. DUNCAN. I think we are just starting to develop an understanding of what is happening with CO2 and enhanced oil recovery. 

There hasn’t been a lot of interest in the past. As long as the oil 

flowed, people didn’t worry, about what was going on. We believe 

that, probably, most of the oil, at least I believe, that most of the 

CO2 that doesn’t come out is actually dissolved in oil that is just 

still trapped down there, and the rest of it is either dissolved in 

brine that is in association with the oil or trapped in pore spaces 

within the brine. 

Mr. GREEN. Okay. Thank you. Mr. Yamagata, is it possible to 

rank the major carbon capture methods, in terms of the levels of 

contamination, or do they perform all about the same and what 

contaminates are present in what contamination. I know sulfur, 

and maybe other things. 

Mr. YAMAGATA. Well, the importance of technology development, 

Mr. Chairman, is that we are going to get the emission levels of 

criteria pollutants, as well as CO2, down to miniscule levels, in 

some cases, almost non-detectable. In the context of your first part 

of your question, however, and that is the type of platforms that 

we are trying to develop or that are already developed for the capture of CO2 and that is in the context of really thinking about combustion based systems that produce Bauer—or, as you have heard 

before, gasification based systems that also produce electric power 

and other things as well. 

In those two instances, the goal here is to capture at least 90 

percent of the CO2, at a cost that is no greater than, say, 20 percent of what the costs are today without CO2 capture. Those are 

goals, of course. Technology development will flow out of whether 

or not we are successful there. The other important point here, 

however, is that we need to start doing things now. If we can’t do 

90 percent now, economically, let us start doing something, just 

learning by doing and letting that, in itself, bring down costs and 

give us a better understanding of what we need to do next. 

104 

Mr. GREEN. Thank you, and my time is expired. And, again, the 

committee will stand in recess until the finishing of the final vote 

and it will be our ranking member’s turn. 

[Recess.] 

Mr. DUNCAN. There are some studies going on, but I don’t think 

we are getting the kind of information that we could get out of that 

and some of the other projects—long-term sequestration projects in 

the Permian Basin. 

Mr. SHADEGG. I am curious, the carbon dioxide that was used 

there, and is currently sequestered, came from where? Was it taken 

from the earth and other locations and brought? 

Mr. DUNCAN. The CO2, in general, from the Permian Basin, 90 

percent of it comes from natural sources of CO2, mostly up in Colorado. And about 10 percent, at the moment comes from gas separation plants. That is where we are producing natural gas that it has 

too much CO2 in it so they separate it out using that, and that gets 

counted as anthropogenic or man-made CO2 because it is man’s activity that is producing it. The Sacroc Project, historically, began 

with 100 percent of that CO2 from the gas separation plant and I 

think, at the moment, about 20 percent of it is coming from that 

source. 

Mr. SHADEGG. If the CO2 is taken from the gas separation process, had that CO2 not been used for enhanced oil recovery, would 

it have just gone into the environment? 

Mr. DUNCAN. That is correct. 

Mr. SHADEGG. I find some irony that my friends that were deeply 

worried about the impact of CO2 on the environment, who don’t 

really like oil, have been benefiting by the fact that the oil industry 

has been sequestering a whole lot of CO2, apparently for the last 

35 years, and apparently benefiting—if in fact, carbon dioxide is 

damaging the environment and causing enhanced global warming, 

we have been fighting it for 35 years without knowing it. 

Mr. DUNCAN. Correct. 

Mr. SHADEGG. You mentioned that Congress had cut funds for 

the study of enhanced oil recovery and, therefore, cut funds, kind 

of I would suggest perhaps, unwittingly for the study of carbon dioxide sequestration. Is that correct? 

Mr. DUNCAN. Yes, I think that is correct. The oil and gas part 

of the Department of Energy was cut and much of that money went 

to fund graduate student research, faculty research. In other 

words, it was training the next generation of petroleum engineers 

with expertise in CO2. And a considerable proportion of that was 

actually related to CO2 enhanced oil recovery. 

Mr. SHADEGG. How much of the CO2 that is put back in, in the 

EOR process, is sequestered? 

Mr. DUNCAN. Ultimately, all of it is. In other words, it is a recycling process, so it cycles through and every time you cycle through 

it, more of it gets trapped. And how much gets trapped per cycle 

depends on the actual geology of the individual field and the way 

they are doing the injection, but ultimately it will all be— 

Mr. SHADEGG. My next question is for Mr. Broussard, and it goes 

to the issue of water quality. Do any of you—but before I go there, 

do any of you want to comment on the series of questions we just 

had. Sometimes I see people fidget and know they have a gem of 

105 

knowledge they want to put across and I am anxious to hear it because you are teaching me a lot and I appreciate it. Mr. Anderson. 

Mr. ANDERSON. Two comments, first, Environmental Defense 

Fund agrees that there is a happy win-win situation between CO2

sequestration and enhanced oil recovery. The second comment, although I am really reluctant to disagree on technical matters with 

Ian Duncan, I think it is important to say that business as usual 

EOR, even if, in fact, it has sequestered 99 or 100 percent of the 

CO2, we don’t know that for a fact. 

Mr. SHADEGG. Well that was his whole point about, we aren’t 

studying this. I mean, it could be leaking out somewhere else. It 

could be doing other things. 

Mr. ANDERSON. It is also important to do some additional geologic characterization between the time you do the EOR project and 

the time you do sequestration because the EOR operations could 

have damaged the reservoir. You need to make sure that didn’t 

happen. 

Mr. SHADEGG. Mr. Yamagata. 

Mr. YAMAGATA. Mr. Shadegg, just another point here. I made reference, in my comments, to the need to do integration between 

power generation and capture. And one way to speed that process 

along, to address the greenhouse gas issues, is to do the power generation with the capture, with the EOR application versus trying 

to put CO2 into deep saline formations, and you could just move 

that thing along quicker. 

Mr. SHADEGG. If I understand what you are saying, right now we 

don’t have a place where we can, even experimentally, sequester 

substantial quantities of CO2, but we could be capturing CO2 in the 

industrial process and using it in EOR processes, creating the demand and creating the entire cycle and study how it works. 

Mr. YAMAGATA. We do have places, but part of the difficulty here 

is just the risk, and lack of understanding, at this point, of putting 

large quantities of CO2 into these deep saline formations. So if we 

want to move the process along, capturing the CO2 from power generation or from using coal for liquids or subsic gas or anything like 

that, you capture that CO2 and use it for EOR purposes. We are 

still doing half of the equation here and getting more experience as 

a result of that. 

Mr. SHADEGG. Learning from the process? 

Mr. YAMAGATA. Right. 

Mr. SHADEGG. Mr. Broussard, mine is kind of a comment, but I 

would be happy to have you respond to it. And that is, in your testimony you stressed the importance of studying the impact of carbon sequestration on water supplies because that is what you guys 

are about, and you noted that some of that is being done or proposed to be done by EPA. Several of the witnesses, today, have 

made it very clear that they have a very strong scientific belief that 

this can be done without damage to the environment and without 

damage to water supplies. If I have a question, it is, is AWWA 

doing its own independent studies of that issue? Or, alternatively, 

would you consider it, because I am a little—I would feel more 

comfortable if somebody other than EPA were, kind of, checking 

EPA’s work, so that EPA wasn’t the only source of telling us, ‘‘yes, 

this is safe.’’ And maybe that involves AWWA getting a grant from 

106 

the government so that, you know, we have two people looking at 

it, not necessarily from the same perspective, one of whose primary 

interest is ensuring safe drinking water. 

Mr. BROUSSARD. Appreciate the question. There is some independent research going on, outside of the work that the EPA is 

doing and is proposing to do and while I don’t have a comprehensive list today, I would be glad to provide some resources to indicate what research is already being done. 

One of the main concerns that we have—and I just wanted to express it, I didn’t really say it, this out rightly, in the testimony, but 

the main concern is that the injection site will go through the underground source of drinking water, if one of those sites is selected 

because of the geology and other consideration. And the fact it penetrates is an area where there could be some contamination or 

water quality issues. 

Mr. SHADEGG. Yeah, I have seen them. There is a graph we have 

that shows how it happens and it goes through the recovery of the 

drinking water. The Chairman has indulged me. I am way over my 

time. I want to thank all of the witnesses on this panel and on the 

previous one. It has been a tremendous education for me. 

Mr. GREEN. Well, one, I—the questions you ask and the responses because we are all learning and, you know, our committee 

is responsible for the Safe Drinking Water Act and that is our concern and I just want to follow up. When they go through—because 

there are parts of my area, in the Gulf Coast, that we are always 

going to have—you are going to go through water. You are going 

to go through our water table. Is there a way you can do it and 

still get to those salt domes that we have all along the Gulf Coast? 

Mr. BROUSSARD. I guess, if I had my preference, I would just ask 

that there would be strong considerations made to not permit a 

Class VI well in an underground source, especially if there is a 

sole-source designation. That is the main concern that I would 

have. As far as your question, I don’t know if there is another way 

around it, other than avoiding the source of drinking water. 

Mr. GREEN. And I agree with the sole-source and I appreciate 

your testimony on that because we don’t want to contaminate that, 

but we do have—and, you know forgive me, I was a lawyer in my 

earlier life like Mr. Yamagata and was a business major and ran 

a business, but the way I understand what we do now with energy 

is that they, typically, if there is a resource there, whether it is oil 

or natural gas, they pretty well know, generally, the pool and 

where it is at, and are we using that information now to be able 

to put—I mean, maybe we didn’t care about what happened to the 

carbon once it went in and, you know, pushed out the oil or gas, 

but because we may want to use it for sequestration and we could 

use some of the same studies that maybe that they are doing to get 

that resource out to also make sure that one is not contaminating 

any ground water, which we also have the concern with the production of oil and natural gas too. We don’t want to have that, so Dr. 

Duncan is that something that we could expand on that—and, also, 

I know that our regulatory agency from Arkansas, because in 

Texas we have our Railroad Commission that does, mostly, our oil 

and gas work. Don’t ask me why it is Railroad Commission, but in 

1877 we kept that. But is that something that the regulator for the 

107 

State in permitting could also take advantage of the information 

that is provided to you, as a regulator of your natural gas wells, 

particularly, in Arkansas? 

Mr. BENGAL. Yes, it was the Railroad Commission in Arkansas 

at one time, too, but we changed—— 

Mr. GREEN. We haven’t gotten around to changing. 

Mr. BENGAL [continuing]. Our name. I know you tried, but to answer your question yes, that is taken into account. I might add two 

things. One, under the U.S. EPA UIC program, States that have 

primacy basically implement the UIC requirements for the EPA in 

that State. A State is perfectly able under that primacy agreement 

with the U.S. EPA, to enact more stringent regulations in that particular State if it desires to do so. It is not limited to just what the 

EPA says, so that if a State has a concern about a particular area 

of faulting or seismic activity or there is any other issue of concern 

to the State, it can actually enact more stringent regulations than 

the EPA regulations. And with respect to another question earlier 

concerning business models, there are companies right now who 

are, basically, scouring the countryside, rounding up sources of CO2

for Enhanced Oil Recovery (EOR) use. There is a real shortage of 

CO2 for EOR use. 

Mr. GREEN. Well, if you would listen to most of us, you would 

say we have no shortage of—— 

Mr. BENGAL. That is carbon. 

Mr. GREEN. Or CO2. Let me follow up, Mr. Bengal, with the EPA 

proposed rule which set a minimum standard for State carbon sequestration permits. And it is my understanding the EPA has contacted States to hold off on issuing your own rules until the EPA 

is finished. Do you believe that State regulators could implement 

both, like you said the UIC, but also add additional requirements 

onto it? Is that part of what the EPA is allowing, to carry that tradition forward on this? 

Mr. BENGAL. Yes, that is part of the current UIC program, and 

when a State would apply for primacy under the new Class VI program, I assume that the same thing would apply in that a State 

could actually make those requirements more stringent. The parts 

of the EPA rule that don’t cover initial siting, like ownership issues 

and long-term liability, could actually be handled under State authorities that exist now. 

Mr. GREEN. Okay. Are you aware of any private property lawsuits in States that are involving sequestration? 

Mr. BENGAL. There are none that I am aware of. Now there have 

been several issues dealing with subsurface trespass relative to 

EOR, but since sequestration is not actively taking place, there has 

not been an issue with regard to that. The IOGCC did a legal analysis of the ownership of pore space as part of our report. I would 

just add, too, that even though you see the map of many large 

areas where sequestration could occur, there is an ownership component that will have to come into play. Not every location where 

you could theoretically do sequestration, will you actually be able 

to do it by the time you take into account cities, towns, Federal 

lands, things like that. And when you get down to having to own 

the exact place where you will store, there will be a real competition for the good sites within States. And this is where State auVerDate Nov 24 2008 15:10 Feb 25, 2009 Jkt 037690 PO 00000 Frm 00113 Fmt 6633 Sfmt 6633 C:\DOCUMENTS AND SETTINGS\CWELLS1\110-141 SCOM1 PsN: JIMC
108 

thorities will have to come in to resolve those conflicts such as 

when a site is being leased by two companies, which company gets 

to operate that site? It is up to the States to maximize the storage 

space use, or you could end up wasting that storage space and not 

being able to store as much CO2 as you could if you took care of 

it properly. 

Mr. GREEN. Mr. Anderson, let me ask one last question, and I 

know before your current position at Environmental Defense Fund 

you represented independent oil and gas producers, is action to address climate change compatible with leveraging the market economies of the enhanced oil recovery to drive the innovation in sequestration that would broaden to sequestration and deep saline 

aquifers? Do we have enough of that—is there enough push on the 

climate change to be able to drive the technology and have that 

twofer, that win-win? 

Mr. ANDERSON. I think you are asking if we need complementary 

measures to accelerate the technology, in addition to a policy of, 

say cap and trade. Is that— 

Mr. GREEN. Sure. 

Mr. ANDERSON. Is that the question? 

Mr. GREEN. Yeah. 

Mr. ANDERSON. Yes. I think—well it depends on when you think 

that CCS needs to begin playing a major role as opposed to a transitional role. There are a lot of things that are less expensive than 

CCS that we can do to help mitigate climate change. And, therefore, those are more likely to be the things that are adopted on a 

large scale early on. On the other hand, as Ben would be quick to 

say, we know we are going to need CCS as soon as possible, and 

therefore there is probably very good reason to have complementary policies to help incentivize the technology and accelerate its 

development. As far as the degree to which our knowledge in EOR 

can be translated to saline aquifers I think to a very great degree, 

it can. The big uncertainty is for the brine formations, which I 

think are more case specific than generally understood. The basic 

big question mark for whether you can do sequestration in a brine 

formation is—really has to do with the question of whether you 

know enough in advance about the seal quality and the lateral extensiveness of the seal. And since you don’t have a lot of development that has already taken place, like you do in an oil reservoir, 

that is a really big question and the only way to answer that question is to either do tests or to just start your project and see how 

it goes. 

Mr. GREEN. Well, and I know we have tests from the first panel’s 

testimony. Any other comments? 

Mr. BROUSSARD. If I may, Mr. Chairman, one of the issues that 

was brought up earlier by Mr. Bengal was—and I think maybe you 

brought it up earlier, was about the boundary issue between a 

State—the Chicot Aquifer is my sole-source aquifer and it does 

exist, partly, in Texas and mostly in Louisiana, so if you have a 

State primacy agency in Texas that rules on a Class VI well and 

it affects something of Louisiana, you have an interstate commerce 

or some other complicating issues. I just wanted to bring that up. 

109 

Mr. GREEN. Yeah, that is a concern I have with, you know—because traditionally, if the States do have some regular authority 

working with EPA on the others. 

Mr. BENGAL. That is pretty much handled in oil and gas. There 

are oil fields, now, that cross State boundaries, waterfloods across 

State boundaries and the States handle that. What we do with 

Louisiana now is to handle it with MOUs between the States, 

interstate agreements that allow regulation on both sides of the 

border. So, that exists in the oil and gas industry now. 

Mr. GREEN. And, again, from your testimony, EPA is going to 

continue that relationship that they have with the States being 

able to have some authority in there. 

Mr. BENGAL. There would be nothing in the rules that would preclude a State from entering into arrangements with adjoining 

States to address cross-State boundary issues. 

Mr. GREEN. Mr. Shadegg, I actually had two rounds so. 

Mr. SHADEGG. Be my guest, I am fine. 

Mr. GREEN. Being no other questions, one thank you for your 

time this morning and appreciate it. That concludes the statements 

of the second panel, and I want to remind members you may submit additional questions for the record to be answered by relevant 

witnesses. The questions should be submitted to committee clerk in 

electronic form within 10 days and the clerk will notify your offices 

of procedure. Without objection this committee is adjourned. And 

again thank you for being here. 

[Whereupon, at 2:00 p.m., the subcommittee was adjourned.] 

[Material submitted for inclusion in the record follows:] 

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ROBERT C. BURRUSS, RESPONSE TO QUESTION FROM MR. SHADEGG

1.Dr. Burruss, in your testimony you outline a very rigorous geologic 

storage assessment framework which takes into account not only the 

unique geology of depleted oil and gas fields, saline formations, and 

unmineable coal beds and their respective, unique sealing formations, but 

also the assessment of ground-water resources. All of this data will be assigned a risk factor. Once all of the numbers are crunched and all of the 

scientific data checked and double-checked, how safe can we expect carbon 

sequestration to be? 

Geologic carbon sequestration is known to be very safe in certain environments 

and under certain conditions. Over the last 30 years in the United States, large volumes of carbon dioxide have been routinely injected into oil reservoirs to enhance 

production of oil. Although most of the injected CO2 is co-produced with the oil, separated and re-injected for additional oil recovery, some CO2 remains in the reservoir 

and is therefore sequestered. We know that geological formations, such as oil and 

gas reservoirs, that have an overlying seal formation (caprock) are safe for carbon 

sequestration because they have held oil and gas for millions of years. It is true, 

though, that during the lifetime of oil or gas reservoirs, they have been penetrated 

by well bores that could be sources of leakage. The drilling history of individual sequestration sites must be reviewed carefully to ensure that all previously drilled 

wells are properly plugged to prevent leakage of CO2 or brine to the surface or to 

shallow drinking water supplies. Other potential storage sites such as deep saline 

formations (saline aquifers) are much less characterized than depleted oil and gas 

reservoirs. Such sites will require extensive characterization prior to deployment of 

geologic sequestration to ensure that the CO2 is fully contained within the formation. 

In part, discussions of the safety of geologic sequestration of CO2 depend on what 

is meant by ′′safe,′′ whether the process is safe in terms of leakage to the surface, 

safe from contamination of drinking water, or in terms of any of the technologies 

for transporting and pumping high pressure carbon dioxide into the ground. The 

technology exists to safely pressurize, transport, and inject carbon dioxide into the 

ground because we have been doing this as part of enhanced oil recovery for over 

30 years. However, the volumes of CO2 that must be injected for geologic sequestration to be an effective technology for mitigation of climate change are large, and 

there are fundamental questions of science that must be addressed before the safety 

of geologic sequestration can be fully understood. For example, we must understand 

the extent to which fluids and pressure variations are dispersed throughout a saline 

formation over decades as large volumes of CO2 are injected. 

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LAWRENCE E. BENGAL, RESPONSE TO QUESTIONS FROM MR. SHADEGG

1.Should we rush forward with adopting a carbon cap-and-trade scheme 

and begin sequestration on a massive scale before all the states and the Environmental Protection Agency (EPA) have a chance to complete the regulatory framework governing sequestration? 

Mr. Bengal: It is my view that until legislation is passed that either sets a cap 

on the amount of carbon emitted into the atmosphere (cap-and-trade legislation) or 

imposes a tax on carbon that’s emitted into the atmosphere (carbon tax), that there 

will be little impetus for the robust development of carbon sequestration projects in 

the United States. Should there be interest on the part of developers in moving forward with one or more large projects before the passage of any such legislation, 

there would be nothing to prevent that from occurring if a willing state used either 

existing regulatory frameworks (state and EPA) or frameworks such as many states 

are developing. Wyoming, Kansas and Washington are close to having complete 

frameworks in place and legislatures in North Dakota, Montana, New Mexico, 

Texas, West Virginia, California, Michigan and Oklahoma are expected to take up 

legislation in 2009. Legislation limiting the emission of carbon into the atmosphere 

(either cap-and-trade legislation or a carbon tax) will only help facilitate the implementation of storage projects and it should not be necessary to postpone adoption 

of such measures awaiting the completion of regulatory development by the states 

or the EPA. Cap and trade or carbon tax legislation will not mandate CO2 storage, 

which is only one method to reduce emissions, on the contrary having a known 

emission standard in-place will only help industry move forward to address the unresolved issues. Issues that are not yet addressed, such as long term liability, could 

be dealt with by states using existing state authorities providing there was a willingness on the part of the state to do so. 

2.You say that 7 states have either adopted or are in the process of adopting regulations governing carbon geologic storage. Have these states addressed the liability issues associated with CO2 storage? Have they adopted 

the state trust fund mechanism you describe? 

Mr. Bengal: To my knowledge none of the states that have adopted the state trust 

fund mechanism as proposed and set forth in the IOGCC model. We understand, 

however, that some states could very shortly enact legislation providing for such a 

state trust fund mechanism. In the meantime, the states that have adopted legislation have taken different positions on the liability issue to the extent they have even 

addressed the issue. 

3.Do you think the Post-Closure trust fund mechanism is adequate to address all the liability issues associated with sequestration? Especially for 

early projects, who may be storing CO2 at previously untested volumes, do 

there need to be additional liability protections to enable the private sector to more 

forward on projects? 

Mr. Bengal: There are two primary types of liability that will need to be addressed One of these is concerned with the operational or caretaker functions of the 

project in its post-closure phase. The second is concerned with claims for personal 

injury or property damage that might result from leakage of stored CO2 in the postclosure phase. 

The state trust fund was designed to address the first of these two types of liability, pertaining to the operational or caretaker functions of the project which deal 

with the long term monitoring programs, verification methods and remediation of 

any mechanical or geologic leaks which could impact public health and safety. The 

state trust fund mechanism was not designed to address personal or property damage claims arising during the post-closure phase of the project. This type of liability 

would have to be addressed either legislatively or through the purchase of commercial insurance, potentially by the trust fund. 

Uncertainty about liability is a stumbling block for early projects. Any protections 

or clarifications that could be provided to industry by government to reduce their 

uncertainty about liability exposure will greatly enhance the development of early 

projects. 

4.I find your description of CO2 storage as a resource management problem 

rather than a waste disposal one fascinating. Could you discuss this in more detail? 

Is it because of the market potential of CO2 in EOR and other uses? 

Mr. Bengal: The Task Force concluded that the commodity vs. pollutant or waste 

debate was unproductive and decided that a ′′resource management′′ approach made 

much more sense. Waste regulatory frameworks deal with point source emissions 

and the local area impacts of those emissions. This type of regulatory framework 

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would only complicate the management of CO2 emissions. CO2 released into the atmosphere as a consequence of the combustion of fossil fuels is of concern primarily 

for its global impact (climate change) and not its local impact. Not every source of 

CO2 emission will need to be regulated in order to have a significant impact on overall emission reduction. 

A key conclusion reached by the Task Force was that nothing is gained by viewing 

CO2 as a pollutant or waste. In fact it was reasoned that such a designation only 

exacerbated the regulatory complexity of CO2 storage which unlike wastes include: 

ownership and management of the pore space, maximization of storage capacity, potential use of the CO2 for enhanced oil recovery (EOR), long term liability, issues 

of environmental protection, and issues of pipeline access. CO2 as a resource rests 

in part on viewing CO2 as a byproduct of the public’s demand for energy, a resource, 

produced through combustion of fossil fuels, another resource. In addition, given 

CO2 is a consequence of the public’s use of a resource to produce energy resources 

it is logical that yet another public resource, underground storage reservoirs, be 

used to store that byproduct. Viewed in this context regulating CO2 under a resource management framework allows the state to manage a variety of resources 

in a comprehensive manner for the benefit of its citizens. 

Put another way, to view the regulation of storage of CO2 under a waste disposal 

framework (as a pollutant or waste) sidesteps the public role in both the creation 

of CO2 and the mitigation of its release into the atmosphere and places the burden 

solely on industry to rid itself of ′′waste′′ from which an ′′innocent′′ public must be ′′protected′′. Such an approach lacking citizen buy-in with respect to the public’s responsibility for the problem as well as the solution could well doom geological storage to failure and diminish significantly the potential of geologic carbon storage to 

meaningfully mitigate the impact of CO2 emissions on the global climate. 

A resource management framework, as proposed by the Task Force, allows for the 

integration of these issues into a unified regulatory framework that facilitates a 

′′public sector-private sector partnership′′ to address the long-term liability, given 

that the release of CO2 into the atmosphere is at least partially a societal problem 

and that the mitigation of that release is likewise at least partially a societal responsibility. In this way the state is able to use and manage underground storage 

space as a valuable state asset to the benefit of its citizens. 

In response to the last part of the question, although CO2 used in EOR projects 

is a commodity and was an important component in determining to propose a resource management framework, it was not the sole driver. There were many other 

factors and considerations, as enumerated above. 

DON BROUSSARD, RESPONSE TO QUESTION FROM MR. SHADEGG

1.Mr. Broussard, you rightly express concern about the safety and cleanliness of our drinking water. I certainly would not advise any legislation 

or authorize any programs that would leave a great risk of polluting our 

underground sources of drinking water. What I gather from your testimony, however, is that you advise and accept the idea of gradual, measured studies and carbon sequestration pilot project that would monitor the 

safety of these underground drinking water sources? 

While the UIC program has a long history, the injection of CO2 into the ground 

is a process that is not well understood. This substance is different from substances 

currently regulated under the UIC, and the behavior of the compound under severe 

pressures and temperatures is not well known. AWWA believes that gradual, measured studies and pilot projects must be conducted before carbon sequestration is embraced as a feasible technology to combat climate change. The Department of Energy’s Phase III Regional Carbon Sequestration Partnership projects should provide 

some of this information, and we look forward to reviewing the data when it becomes available. However, the results of these large-scale projects are several years 

off and there is currently limited research available, with the exception of the 

Sleipner project on what happens in the subsurface between groundwater, carbon 

dioxide and the surrounding rock strata in large-scale geologic sequestration activities. Also, AWWA strongly recommends that EPA and DOE perform both modeling 

(theoretical) and observational research to better understand the carbon sequestration process and the effects of CO2 injection on saline aquifers and the subsurface 

geology. 

AWWA believes that the results of the DOE research are crucial to the development of a comprehensive regulation that protects water resources from the potential 

unintended consequences of geologic carbon sequestration. In particular, AWWA believes that research on the potential pathways for contamination of USDWs has not 

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yet been completed. As a result, we are concerned that the appropriate subsurface 

monitoring methods and technologies have not been adequately identified or developed. AWWA believes that more detailed research is needed to identify the specific 

requirements for subsurface monitoring that can protect USDWs from contamination due to geologic carbon sequestration. 

It is important to note that unintended consequences from geologic sequestration 

might not manifest themselves for decades or even centuries. This is another reason 

to move cautiously forward and provide for extensive review of the pilot projects before proceeding with careful site selection and robust mitigation plans/resources for 

commercial scale projects. Having observed significant unintended consequences recently with both MTBE and biofuels, we believe that more information needs to be 

obtained regarding how CO2 performs in large-scale projects. We also need the 

chance to observe these pilot projects for any unintended consequences before we 

move ahead with commercial deployment of this technology. 

While we recognize that drinking water utilities will be affected by climate 

change, this does not mean that we should rush to embrace a technology before results from large-scale pilot projects are available. Taking careful, deliberate steps 

in the development of CCS technology will ensure we have a very clear understanding of the potential impacts. 

The proposed scale of carbon sequestration is unprecedented compared with traditional enhanced oil and gas recovery, increasing the potential for unintended consequences. As such, AWWA recommends that DOE and EPA include the drinking 

water utilities that are directly impacted by the carbon sequestration pilot projects 

as stakeholders. Potentially impacted utilities must be involved in the development 

of appropriate aquifer monitoring programs for the pilot programs to appropriately 

ensure that the water resources are not adversely affected. This will allow the utilities to gain first hand experience regarding how the sequestration process will be 

implemented. 

In summary, AWWA does believe that much more research and large-scale pilot 

projects - with potentially effected drinking water systems as partners - is required 

before geosequestration of carbon dioxide becomes a widely used technology. 

A. SCOTT ANDERSON, RESPONSE TO QUESTIONS FROM MR. SHADEGG

1.You say that the market is ′′far more effective and efficient . than any 

suite of government mandates or subsidies.′′ Isn’t a cap-and-trade scheme 

itself just a massive government mandate? 

Response:I should have said that markets are far more efficient at allocating resources than government mandates or subsidies. Certainly the ′′cap′′ portion of capand-trade counts as a mandate. Cap-and-trade considered as a whole, however, goes 

well beyond setting a cap on greenhouse gas emissions, and does so by incorporating 

market forces. By providing for a market in emissions allowances, a cap-and-trade 

system will enable the private sector to determine the most efficient pattern of emission reductions, thus reducing overall compliance costs compared to an approach 

that simply mandated all sources to reduce emissions by a prescribed amount. 

2.You say that you’re unconvinced that liability relief is necessary. You 

cite models based on current operations, such as enhanced oil recovery or 

hazardous waste injection. Doesn’t the unique nature of CO2 - it’s viscosity, 

buoyancy and corrosivity - make its storage an inherently different case? 

Response:No. Enhanced oil recovery operations annually have been injecting tens 

of millions of tons of CO2 since the 1970s, and the carbonic acid that forms when 

CO2 mixes with water is not nearly as corrosive as some of the substances that are 

injected in hazardous waste injection wells. Neither is CO2 explosive -- as is the case 

with natural gas that storage facility operators store (usually quite safely) in geologic formations near or beneath populated areas. What is unique about the geologic 

sequestration of CO2, compared to these other underground injection operations, is 

that it will involve larger volumes and that the reservoir storage pressures will tend 

to be higher. It is not clear at this point whether these differences, or other considerations, will lead to problems with capital formation that might justify a modification of liability rules. 

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