This comment letter response contains two parts:   

(1) The original submittal from the commenter.

(2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA‐assigned comment code; and an

individual response. These are described and explained below.  

• The data base contains Comment text from the letters submitted by commenters.  

Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues.  However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and

appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID.  Additionally, one or more Comment Codes (i.e., unique topic area ID) was

assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).  

• Following decisions on the final rule requirements, Individual responses were drafted

by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments.  Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter.  As a result of this process, there is

repetition in the response text.  The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.   

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.  

Responses on each topic area are compiled and are also available in the rulemaking docket.
EPA-HQ-OW-2008-0390-0115

Document ID: EPA-HQ-OW-2008-0390-115

Last Name: LaPlaca

First Name: Nancy

Title: 

Organization: Bardwell Consulting

City: 

State: 

Zip Code: 

Phone Number: 

Fax Number: 

Country Code: 

Email Address: 

Current Category Code: 260

Comment: Did Dick Cheney design this website? It's really hard to use.

DO YOU THINK YOU COULD ADD A BUTTON THAT SAYS "SUBMIT COMMENTS" ??

Here are the problems with underground injection of CO2: - it's risky: who will

bear the risk of leakage? - CO2 is heavier than air and displaces air - couple

incidents in Africa (one in Cameroon) in late 1980's where large "cloud" of CO2

was released and suffocated 1800 people and 1100 head of cattle. - liquid CO2 is

very corrosive - injecting CO2 can induce seismic activity

[SEE PDF FOR ATTACHMENT 1. IN THE MATTER OF XCEL ENERGY’S PROPOSED INTEGRATED

GASIFICATION COMBINED CYCLE (IGCC) PLANT IN BRUSH CO COLORADO Docket No.

07F-088E. COMPLAINANTS’ MOTION REQUESTING LEAVE TO REPLY; AND REPLY TO PUBLIC

SERVICE COMPANY OF COLORADO’S REPLY TO COMPLAINTS’ RESPONSE TO XCEL’S MOTION TO

DISMISS]

[SEE PDF FOR ATTACHMENT 2. IN THE MATTER OF XCEL ENERGY’S PROPOSED INTEGRATED

GASIFICATION COMBINED CYCLE (IGCC) PLANT IN BRUSH CO COLORADO Docket No.

07F-088E. COMPLAINANTS RESPONSE TO PUBLIC SERVICE COMPANY OF COLORADO’S MOTION

TO DISMISS]

[ATTACHMENT 3 IS NOT YET AVAILABLE.]

[SEE PDF FOR ATTACHMENT 4. Leakage and Seepage of CO2 from Geologic Carbon

Sequestration Sites: CO2 Migration into Surface Water by Curtis M. Oldenburg and

Jennifer L. Lewicki]

[ATTACHMENT 5 IS NOT YET AVAILABLE.]

[SEE PDF FOR ATTACHMENT 6. BEFORE THE FLORIDA PUBLIC SERVICE COMMISSION DOCKET

NO. 07@8 -El FLORIDA POWER & LIGHT COMPANY IN RE: FLORIDA POWER & LIGHT

COMPANY'S PETITION TO DETERMINE NEED FOR FPL GLADES POWER PARK UNITS 1 AND 2

ELECTRICAL POWER PLANT]

[ATTACHMENT 7 IS NOT YET AVAILABLE.]

Page 1
BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF COLORADO

* * * * *

______

IN THE MATTER OF XCEL )

ENERGY’S PROPOSED )

INTEGRATED GASIFICATION ) Docket No. 07F-088E

COMBINED CYCLE (IGCC) )

PLANT IN BRUSH CO )

COLORADO )

______

COMPLAINANTS’ MOTION REQUESTING LEAVE TO REPLY; AND

REPLY TO PUBLIC SERVICE COMPANY OF COLORADO’S REPLY TO 

COMPLAINTS’ RESPONSE TO XCEL’S MOTION TO DISMISS

________________________________________________________________________

This Docket before the Colorado Public Utilities Commission (“PUC”) involves 

plans by Public Service Company of Colorado (“PSCo” or “Xcel”) to hire a vendor for an 

Integrated Gasification and Combined Cycle coal plant (“IGCC” or “gasified coal 

plant.”) in Colorado. The following summarizes what has occurred to date:

· March 21, 2007—Complaint filed by Nancy LaPlaca and Leslie Glustrom

· March 28, 2007—The PUC considers the complaint, sets a hearing date of May

31, 2007

· April 12, 2007—Xcel files a Motion to Dismiss the Complaint

· May 3, 2007—Complainants file a Response to the Motion to Dismiss

· May 10, 2007—Xcel files a Reply to the Complainants’ Response.

Complainants hereby request leave to file a reply to Xcel’s May 10th Reply, and 

incorporate this reply and our initial Response to Xcel’s Motion to Dismiss.
2

COMPLAINANTS ARE NOT “POISONING THE WELL” BUT MERELY 

REQUESTING THAT ALL CURRENTLY AVAILABLE INFORMATION BE 

CAREFULLY CONSIDERED BY XCEL AND THE COMMISSION

Xcel states in its Reply that Complainants are attempting to “poison the well” 

against IGCC. Complainants only wish to bring to the attention of the Commission the 

serious issues concerning the cost and technical feasibility of IGCC and Carbon Capture 

and Storage (CCS). Xcel also states that this docket is not the place for a “quasilegislative investigation into the relative merits of one or more technologies.”1

Complainants disagree. Colorado Revised Statute 40-2-123 states repeatedly that the 

gasified coal technology “may” have significant benefits. See C.R.S. 40-2-123 Section 1. 

Complainants urge Xcel to look carefully at existing information and adjudicated 

proceedings for gasified coal plants that have already occurred in other states. 

On May 2, 2007, Delaware Public Service Commission staff recommended a

wind/natural gas combination for electrical generation rather than an IGCC plant.2The 

wind/gas combo was chosen after careful evaluation using Delaware’s Integrated 

Resource Plan. (See Attachment A.)

Also, just this week, Standard & Poor’s (S&P) issued a warning to investors in a 

report on the financial risk that climate change poses to financial markets, investors and 

industries. S&P utility analyst Swami Venkatraman stated that “[t]he risk is immediate 

and clear, in the sense that the [coal-to-gas] technology is unproven and it’s not clear how 

1

See Xcel’s Reply to Complainants’ Response to Public Service Company of Colorado’s Motion to 

Dismiss dated May 10, 2007, p. 2. 

2 PSC Staff Review and Recommendations on Generation Bid Proposals, Docket No. 06-241, Prepared for 

the Delaware Public Service Commission, May 2, 2007. The Delaware PSC staff, like the Administrative 

Law Judges in Minnesota, recommended no on the IGCC proposal, but for different reasons. In Delaware, 

the 3 bids – IGCC, natural gas and wind – were evaluated in light of its Integrated Resource Plan, as well as 

overwhelming public support for the wind project. See Attachment A. 
3

well they would run three years from today.” He also stated that gasification developers 

are likely to have trouble even getting firm construction prices from builders.3

Complainants believe that Carbon Capture and Storage (CCS) is not presently—and 

may never—be available at the level needed to manage carbon dioxide (“CO2”) 

emissions from coal plants—gasified or pulverized. To pursue coal gasification before all 

the technical, economic, legal, regulatory and public acceptance issues related to CCS 

have been addressed is not prudent.

XCEL’S ASSERTION THAT THE MESABA DECISION DOES NOT 

APPLY TO THIS CASE IS CONTRARY TO ITS OWN STATEMENTS SINCE 

XCEL’S MESABA BRIEFS ARE RELEVANT TO THE INSTANT CASE; AND 

XCEL CLEARLY INTENDS TO BUILD AN IGCC PLANT IN COLORADO

Xcel’s Assertion That Mesaba Does Not Apply is Contrary to its Own Statements

Xcel briefed many IGCC issues thoroughly in the course of the Mesaba docket, 

and its submissions are extremely relevant here. Xcel argues that although it opposed the 

Purchase Power Agreement (PPA) in the Mesaba case, it did not question the IGCC 

technology. Complainants disagree, and note that many of the issues that have been 

raised in the analysis of the proposed IGCC plant and the PPA in Minnesota will also 

apply in Colorado. 

Key issues related to IGCC and CCS are summarized on page 2 from Xcel 

Energy’s Initial Brief in the Mesaba docket, dated January 5, 2007, which is Attachment

2 to Complainant’s May 3, 2007 response:

3

Investors Warned Against Coal-to-Gas Power Plants, by Jeff Montgomery, The News Journal, May 16, 

2007. The same article reports that Mr. John M. Byrne, who directs the University of Delaware’s Center 

for Energy and Environmental Policy, said the insurance industry has already come to the same conclusion 

as the S&P report. Attachment B. 
4

· Fuel costs for the IGCC plant are unknown and unknowable due to lack of 

fuel supply arrangements, and so do not provide a hedged, predictable price;

· The Mesaba PPA on the IGCC technology is not a least cost resource and its 

cost is not reasonable for ratepayers;

· The Mesaba PPA for the IGCC plant shifts significant financial and 

operational risks to customers; 

· The Mesaba PPA for the IGCC plant does not include the $1 billion plus 

equipment costs associated with carbon capture and storage.

For these reasons and several others, Xcel can predict that IGCC/CCS is not likely

to be seen as a prudent investment in Colorado, and complainants feel that Xcel already 

knows or should know that its investment in this technology is neither prudent nor in the 

public’s interest. .

Xcel Clearly Intends to Build an IGCC Plant in Colorado

Dozens of newspaper articles have been posted in Minnesota, Colorado and 

national news outlets touting Xcel’s proposed IGCC plant. Complainants find Xcel’s 

argument that it is merely considering building an IGCC plant disingenuous at best. If 

Xcel was truly in the fact-gathering stage of determining whether or not to build the 

IGCC plant, it would welcome, rather than discourage, the type of scrutiny Complainants 

wish to encourage.

Arguing semantics, rather than taking a serious look at this costly and unproven 

technology, is not prudent, not in the public’s interest, and violates the spirit of C.R.S. 

40-2-123. C.R.S. 40-2-123 does not unequivocally state the benefits of IGCC, but 
5

merely posits that the technology may have certain benefits. It is in all our best interests 

– Xcel’s, ratepayers, Complainants, shareholders, and the Commission, to determine 

whether these alleged benefits exist, at the earliest possible time. 

In short, Xcel wants to play both sides of the argument – promoting IGCC in 

Colorado where it can pass through the costs of the plant, fuel, carbon capture, 

transportation and storage, increased coal and coal transportation costs; and railing 

against IGCC in Minnesota, where it cannot make a profit on building the IGCC plant. 

COMPLAINANTS ASSERTIONS THAT CONGRESS MAY IMPOSE A 

CARBON TAX; SUBMISSION OF THE EPA STUDY ON IGCC; AND MR. 

STEPHEN JENKINS’ TESTIMONY 

ARE RELEVANT TO THE INSTANT CASE SINCE THEY ADDRESS 

THE MERITS OF THE IGCC TECHNOLOGY

As Xcel knows well, financing IGCC technology is a critical hurdle, and without 

federal loan guarantees, grants and other benefits, the IGCC technology risk would not be 

likely to be borne by private investors. Carbon taxes will also add to the cost of the plant, 

and in its 2003 Least Cost Plan (LCP), Xcel acknowledged the possible future imposition 

of a carbon tax. Just how large that carbon penalty will be, however, will seriously affect 

the financial viability of the plant.4 Although carbon taxes are not included in Colorado’s 

IGCC statute, C.R.S. 40-2-123 (2), the reality of carbon taxes is closer since the U.S. 

Supreme Court’s ruling in Massachusetts v. EPA, decided April 2007. (Slip Opinion, 

No. 05-1120, argued November 29, 2006, decided April 2, 2007.) Similarly, the July

2006 EPA study on IGCC that Complainants included as Attachment 3 in Complainants 

May 3, 2007 Response; as well as Mr. Jenkins’ testimony on the value and drawbacks of 

4 A carbon tax could be as low as Xcel asserts – around $8/ton – or as high as the current price in Europe, 

which is closer to $25/ton. 
6

IGCC are relevant and serve to increase the Commission and Xcel’s information about 

IGCC, resulting in a more prudent decision. 

In short, Complainants believe that the seriousness of climate change and the public 

interest concerns inherent in funding a new technology warrant moving forward with this 

complaint. Attached please find documents that detail the seriousness of climate change 

and CO2 levels in Colorado.

Coal is the most carbon-intensive of all fossil fuels, and is responsible for 44% of 

all CO2 emissions in the State of Colorado.5 We are currently in the midst of a planetary

warming crisis that, if unchecked, is likely to seriously change the habitability of the 

planet. The need to change course and reduce carbon dioxide (CO2) emissions is urgent. 

The Intergovernmental Panel on Climate Change (“IPCC”) has just released a series of 

updated reports that indicate:

· The planet is threatened by runaway climate change, and the main greenhouse gas 

is CO2; approximately 40% of all CO2 is from coal-fired electrical generation;

· “System inertia,” due to the long lived nature of CO2 in the atmosphere and 

various feedback cycles, means that in addition to the 1.4 degrees Fahrenheit 

warming so far, there is 1 degree Fahrenheit in warming already in the pipeline 

due to existing green house gases. Adding more carbon dioxide will increase this 

warming even further. 

5

State’s CO2 Output Jumps, Environmental Group Says, by Todd Hartman, Rocky Mountain News, April 

14, 2007. The article states that 2004 data shows that the bulk of CO2 emissions – 44% -- are linked to 

electricity generation, while transportation accounts for 31%, and industry 13%. Colorado’s CO2 output 

jumped 39% from 1990 to 2004, increasing an average of 2% per year. Attachment C. 
7

· The U.S. has produced over three times more CO2 from fossil fuels than any

other country, raising a serious moral and potentially legal burden for our 

children; and

· In order to start stabilizing the climate, we must start stabilizing CO2 and other 

greenhouse gas levels in the atmosphere.

6

The attached graphic (Attachment E) from the September 2004 issue of National 

Geographic shows that atmospheric CO2 levels are higher than they have been in the last 

400,000 years; and that CO2 levels track very closely with planetary temperature. In 

short, CO2 levels are the best “temperature gauge” we have for the planet7, 

8 Although 

no one knows exactly how hot the planet will get, there is no question that the planet will 

be warming substantially as we move through this century. Complainants feel that time 

is of the essence since the consequences of climate change are extremely serious. For 

example, researchers have found the Arctic sea ice is melting 30 years faster than 

anticipated.9

C.R.S. 40-2-123 exempts Xcel from the Commission’s competitive bidding 

process for its proposed IGCC plant, but does not provide Xcel with an unlimited 

checkbook to make imprudent expenditures pursuing coal gasification. Given what Xcel 

6 Global Warming: Connecting the Dots from Causes to Solutions, by Dr. James Hansen, February 26, 

2007. Presentation before the National Press Club and American University, Washington, D.C. Dr. Hansen 

is perhaps the most preeminent climate change scientist in the United States. The first page of this 

presentation is included as Attachment D. 

7 National Geographic, September 2004, p. 65; data from Nature June 3, 1999; data back 650,000 years in 

Science, November 25, 2005, Attachment E; Intergovernmental Panel on Climate Change, Third 

Assessment Report, Synthesis Report page 34, graphic of Variations of the Earth’s Surface Temperature: 

years 1000 to 2100. (Attachment F) 

8

Intergovernmental Panel on Climate Change, Third Assessment Report, Synthesis Report page 34, 

graphic of Variations of the Earth’s Surface Temperature: years 1000 to 2100, Attachment F. 

9

Study: Arctic Ice shrinking quickly, by Eric Schmidt, Boulder Daily Camera, May 1, 2007. The article 

states that researchers at the National Center for Atmospheric Research and the University of Colorado’s 

National Snow and Ice data center. The models simulated ice loss at 2.5% per decade from 1953 to 2006, 

but data show that the rate of ice melt at 7.8 percent per decade. Attachment G. 
8

knows or should know now, it can be projected that a coal gasification plant will not be 

found to be a prudent investment. Thus, Xcel should not expect to recover costs for 

imprudent expenditures on coal gasification from ratepayers. There are overwhelming 

technical, economic, regulatory and public acceptance hurdles to clear before Carbon 

Capture and “Storage” (“CCS”) will be available - if ever- on a scale that would be 

needed to manage the CO2 emissions from IGCC plants.10 Moreover, there is strong 

support for investing in truly carbon free forms of electricity. In fact, a New York 

Times/CBS News poll of 1,025 adults in late April 2007 found that 87% of those polled 

support developing renewable resources such as solar and wind.11 (See Attachment H). 

In short, Complainants feel that the Commission’s constitutional and statutory

obligation to act in the public’s best interest and to ensure ratepayer funds are spent in the 

most prudent manner possible, require that Xcel’s Motion to Dismiss be denied. 

Respectfully submitted this 17th Day of May, 2007

_____________________________

Nancy LaPlaca

4801 W. Yale Ave.

Denver CO 80219

nancylaplaca@yahoo.com

303-588-3937

_____________________________

Leslie Glustrom

4492 Burr Place

Boulder, CO 80303

lglustrom@gmail.com

303-245-8637

10 Please see Attachments 3 and 4 from Complainants Response to Xcel’s Motion to Dismiss, dated May 3, 

2007 and Attachment B to this filing. The 2006 EPA report on IGCC and a more recent report, titled The 

Future of Coal by the Massachusetts Institute of Technology, dated February 2007, detail the many issues 

that need to be solved for the successful implementation of carbon capture and sequestration. 

11 That Nagging Warming Thing: Poll Shows Most Americans See Environmental Threat, Want Action,

Rocky Mountain News, p. News 27, May 12, 2007. 
9

CERTIFICATE OF SERVICE

I hereby certify that on May 17, 2007, the original and five copies of the foregoing 

COMPLAINANTS’ MOTION REQUESTING LEAVE TO REPLY AND

REPLY TO PUBLIC SERVICE COMPANY OF COLORADO’S REPLY 

REGARDING THE MOTION TO DISMISS IN 07F-088E

was served by hand delivery on:

Doug Dean, Director

Colorado Public Utilities Commission

1580 Logan, OL2

Denver, CO 80203

And have hand-delivered, mailed or e-mailed copies to the following:

Ms. Paula M. Connelly, Esq. Christopher M. Irby, Esq.

Xcel Energy Services. Assistant Attorney General

1225 17th St. Ste. 900 1525 Sherman St., 7th Floor

Denver, CO 80202 Denver CO 80203

paula.connelly@xcelenergy.com Chris.irby@state.co.us

Mr. Dale Hutchins Chere Mitchell

Colorado Office of the Attorney General chere.mitchell@dora.state.co.us

(Office of Consumer Counsel)

1525 Sherman St., Floor 5 Dudley Spiller, Esq.

Denver, CO 80203-1714 Olivia Lucas, Esq.

dale.hutchins@state.co.us Ryley, Carlock & Applewhite

1999 Broadway, Suite 1800

Stephen W. Southwick, Esq. Denver CO 80202

First Assistant Attorney General dspiller@rcalaw.com

Office of the Attorney General olucas@rcalaw.com

1525 Sherman St., 7th Floor

Denver CO 80203

Stephen.southwick@state.co.us

P.B. Schechter

Rate/Financial Analyst

Office of Consumer Counsel

1560 Broadway, Suite 200

Denver CO 80202

Pb.schechter@dora.state.co.us

____________________________________

Nancy LaPlaca

____________________________________

Leslie Glustrom
BEFORE THE PUBLIC UTILITIES COMMISSION

OF THE STATE OF COLORADO

* * * * *

______

IN THE MATTER OF XCEL )

ENERGY’S PROPOSED )

INTEGRATED GASIFICATION ) Docket No. 07F-088E

COMBINED CYCLE (IGCC) )

PLANT IN BRUSH CO )

COLORADO )

______

COMPLAINANTS RESPONSE TO 

PUBLIC SERVICE COMPANY OF COLORADO’S MOTION TO DISMISS

________________________________________________________________________

Nancy LaPlaca and Leslie Glustrom filed a formal complaint with the Commission on 

March 21, 2007 regarding plans by Public Service Company of Colorado (“PSCo” or “Xcel”) to 

hire a vendor for an Integrated Gasification and Combined Cycle coal plant (“IGCC” or “gasified 

coal plant.”) in Colorado. The Colorado Public Utilities Commission (“PUC” or “Commission”) 

heard the complaint on March 28, 2007, and followed staff’s recommendation to request a 

response from PSCo and the present docket was created. Complainants filed an amended 

complaint that asked Xcel to prepare a report on IGCC plants in other states, as well as activities 

surrounding Concentrating Solar Power (CSP), a clean energy source. At the March 28, 2007 

hearing before the Commission, staff set a formal hearing date of May 31, 2007. PSCo then filed 

a Motion to Dismiss on April 12, 2007. Complainants hereby respond to the Motion to Dismiss.
2

TABLE OF CONTENTS

INTRODUCTION ........................................................................................................................ 3

ARGUMENT................................................................................................................................. 4

I. COMPLAINANTS HAVE STATED A CLAIM UNDER BOTH.................................. 4

C.R.S 40-6-108(1)(a) AND C.R.C.P. RULE 12(b).................................................................. 4

II. THE REQUIREMENTS OF C.R.S. 40-2-123(2).............................................................. 5

DO NOT SUPPORT DISMISSAL.......................................................................................... 5

III. XCEL’S ACTIVITIES IN SEEKING FEDERAL FUNDING UNDER THE 

CLEAN COAL POWER INITIATIVE, AND SPECIAL BONDING TREATMENT FOR 

THE IGCC PLANT IN COLORADO HOUSE BILL 07-1150 CONTRAVENE XCEL’S 

CLAIM THAT IT IS MERELY CONSIDERING WHETHER TO FILE AN 

APPLICATION ........................................................................................................................ 8

IV. THE COMMISSION’S LEGISLATIVE MANDATE AND RULES, WHICH 

REQUIRE THAT ITS DECISIONS ARE PRUDENT, DEMAND THAT THE 

COMMISSION ENSURE THAT XCEL IS FOLLOWING THE MANDATE OF C.R.S. 

40-2-123(2)..................................................................................................................................... 9

The Environmental Protection Agency’s July 2006 Study on IGCC................................. 11

Testimony of Mr. Stephen D. Jenkins, IGCC Expert.......................................................... 11

House Resolution 2069 Recently Introduced That Would Impose Carbon Tax............... 12

Xcel Has Submitted Recent Testimony on Many of These Issues in the Mesaba Docket 13

Investing in Coal-Fired Generation Electrical Generation May Not Be Prudent............ 13

Reducing Carbon Dioxide Emissions and Green House Gases is a Goal of C.R.S. 40-2-

123(2)........................................................................................................................................ 14

Reducing Regulated Pollutants Such as Mercury is a Goal of C.R.S. 40-2-123(2)........... 14

Promoting Technologies Such as Concentrating Solar Power (CSP) is a Goal of C.R.S. 

40-2-123(2)............................................................................................................................... 15

CERTIFICATE OF SERVICE ................................................................................................. 17
3

INTRODUCTION

Complainants filed this complaint in this docket to ensure that Xcel follows the dictates 

of C.R.S. 40-2-123(2), and that a vigorous and open debate takes place about the proposed 

gasified coal plant before ratepayer funds are expended. It is our goal in filing this complaint to

begin an open, public debate.

1

Complainants believe that there is ample evidence available on the costs, emissions 

profile, performance, carbon dioxide (CO2) capture capability, CO2 transportation, CO2 storage, 

CO2 sequestration, fuel and fuel transportation and other issues concerning IGCC to indicate that 

pursuing an IGCC project further at this point in time would be imprudent. During the past year 

and a half, Xcel has been a participant in Minnesota Public Utilities Commission (PUC) Docket 

No. E-6472/M-05-1993 (Attachment 1). In the Minnesota docket, Xcel was opposed to the 

IGCC plant. (A copy of Xcel’s January 2007 brief opposing the Minnesota plant is included 

here as Attachment 2.) While the legal framework in Minnesota differs from that in Colorado, 

many of the economic and technical concerns about IGCC that Xcel has pointed out in 

Minnesota will also pertain to any plant proposed for Colorado. 

Complainants will establish that:

I. They have stated a claim per the requirements of C.R.S. 40-6-108, and the complaint 

must also be allowed to stand under C.R.C.P. Rule 12(b); 

II. The requirements of C.R.S. 40-2-123(2) do not support dismissal; 

1 Complainants are concerned that in the 2003 Least Cost Plan, a number of rules were not followed, including Rule 

3610(b), requiring that any generation facilities over 250 MW are put out for bid, so that Xcel was exempted from 

the thorough and public process of competitive bidding. See 4 CCR 723-3, Rules 3600 et seq. A goal of this 

complaint is to avoid a similar situation from arising with respect to a proposed coal gasification plant. 
4

III. Xcel’s activities in seeking federal funding under the Clean Coal Power Initiative, 

and special bonding treatment for IGCC in Colorado House Bill 07-1150 contravene 

Xcel’s claim that it is merely considering whether to file an application; and

IV. The Commission’s legislative mandate and rules, which require that its decisions are 

prudent, demand that the Commission ensure that Xcel is following C.R.S. 40-2-

123(2) and giving careful consideration to available information before signing a 

contract with a potential vendor for an IGCC plant.

2

ARGUMENT

I. COMPLAINANTS HAVE STATED A CLAIM UNDER BOTH

C.R.S 40-6-108(1)(a) AND C.R.C.P. RULE 12(b)

Xcel asserts that complainants have failed to state a claim per the requirements of C.R.S. 

40-6-108(1)(a), which states:

“(1)(a) Complaint may be made by the commission on its own motion or by any 

corporation, person, chamber of commerce, or board of trade, or by any civic, 

commercial, mercantile, traffic, agricultural, or manufacturing association or 

organization, or by any body politic or municipal corporation by petition or 

complaint in writing, setting forth any act or thing done or omitted to be done by 

any public utility, including any rule, regulation, or charge heretofore established 

or fixed by or for any public utility, in violation, or claimed to be in violation, of 

any provision of law or of any order or rule of the commission.” (emphasis 

added)

Complainants acknowledge that building an IGCC plant is a complex process that 

requires enormous expenditure of time and resources. Complainants believe that, per 40-6-

108(1)(a), Xcel’s activities to select a vendor constitute “any act or thing done or omitted to be 

done by any public utility, including any rule, regulation, or charge...in violation [,] of any 

2

4 CCR 723-3, Rule 3613(d)(I)(B), states “To support a Commission decision to disallow investments or expenses 

associated with new resources on the grounds that the utility’s actions were not consistent with a commission 

approved plan, an intervener must present evidence to overcome the utility's prima facie evidence that its actions 

were consistent with Commission decisions approving or modifying components of the plan. Alternatively, an 

intervener may present evidence that, due to changed circumstances timely known to the utility or that should have 

been known to a prudent person, the utility's actions were not proper.”
5

provision of law or of any order or rule of the commission.” (emphasis added) Complainants 

believe that Xcel’s activities in moving forward with the IGCC violate the letter and purpose of 

C.R.S. 40-2-123. 

Colorado Rule of Civil Procedure 12(b)(5) and (6) set out the standard for dismissing an 

insufficient claim. A motion to dismiss for failure to state a claim upon which relief can be 

granted serves as a test of the formal sufficiency of a plaintiff's complaint. Dorman v. Petrol 

Aspen, 914 P.2d 909, 911 (Colo.1996). The chief function of a complaint is to give a defendant 

notice of the transaction or occurrence that is the subject of a plaintiff's lawsuit. Rosenthal v. 

Dean Witter Reynolds, Inc., 908 P.2d 1095, 1100 (Colo.1995). A C.R.C.P. 12(b)(5) motion to 

dismiss is looked upon with disfavor, and a complaint should not be dismissed unless it appears 

beyond a doubt that a plaintiff can prove no set of facts in support of her claim which would 

entitle her to relief. Id.; Dunlap v. Colo. Springs Cablevision, Inc., 829 P.2d 1286, 1291 

(Colo.1992). A complaint should not be dismissed for failure to state a claim so long as the 

plaintiff is entitled to some relief upon any theory of the law. Rosenthal, 908 P.2d at 1099;

Dunlap, 829 P.2d at 1290. When reviewing a motion to dismiss under C.R.C.P. 12(b)(5), all 

averments of material fact must be accepted as true, and all of the allegations in the complaint 

must be viewed in the light most favorable to the plaintiff. Dorman, 914 P.2d at 911.

II. THE REQUIREMENTS OF C.R.S. 40-2-123(2) 

DO NOT SUPPORT DISMISSAL

Colorado Revised Statute 40-2-123(2) includes a long list of requirements, including the 

requirement that the facility not exceed 350 MW, unless there is a Commission determination 

that a larger size is necessary to obtain specified benefits. Xcel has stated in a number of 

newspaper stories, including the March 1, 2007, Rocky Mountain News article by Gargi 
6

Chakrabarty attached to the initial complaint, titled Xcel’s Plans for Clean-Coal Plant May Grow 

that it is considering building a 600 MW facility. Xcel should not be proceeding with a 600 MW 

facility until there has been a Commission determination that a facility larger than 350 MW is 

needed..

3 Xcel has essentially started the process of obtaining the necessary licenses and 

meeting the obligations of C.R.S. 40-2-123(2); Since ratepayers will be paying for the plant as 

well as for many of Xcel’s preliminary activities in preparation of the plant, complainants see no 

reason why Xcel should carry on these activities in secret. 

Xcel has relied heavily on the “encouragement” expressed by the State Legislature in the 

enactment of House Bill 06-1281 regarding IGCC plants. First, Xcel’s reliance on this 

legislation is rather disingenuous as Xcel played a large role in the development of this 

legislation. More importantly, it is incumbent upon Xcel to conduct an independent and careful 

analysis of the information that is already available. Complainants contend that there is more 

than enough information that Xcel “knows or should know” at this point in time to question the 

prudence of any further expenditures on a coal gasification plant.4

3 C.R.S. 40-2-123(2)(b) (I): “IGCC Project” means an IGCC facility that:

(B) Does not exceed three hundred fifty megawatts nameplate capacity; except that it may exceed this 

capacity if the Commission determines that a larger size is necessary to obtain the benefits of federal cost-sharing, 

financial grants or tax benefits, or other financial opportunities or arrangements benefiting the project, including 

opportunities to jointly develop the project with other electric utilities.

4

See 4 CCR 723-3, Rules 3600 et seq, the Least Cost Planning rules; and 4 CCR 723-3, Rule 3102(b). Rule 

3102(b)(IX) states that “[a]n application for certificate of public convenience and necessity to construct and to 

operate facilities or an extension of a facility pursuant to § 40-5-101, C.R.S., shall include... a report of prudent 

avoidance measures considered and justification for the measures selected to be implemented.” (emphasis added)

4 CCR 723-3, Rule 3613, Commission Review and Approval of Least-Cost Resource Plans, states:

In a proceeding concerning the utility's request to recover the investments or expenses associated with new 

resources: ...

(B) To support a Commission decision to disallow investments or expenses associated with new resources 

on the grounds that the utility’s actions were not consistent with a Commission approved plan, an intervener must 

present evidence to overcome the utility's prima facie evidence that its actions were consistent with Commission 

decisions approving or modifying components of the plan. Alternatively, an intervener may present evidence that, 

due to changed circumstances timely known to the utility or that should have been known to a prudent person, the 

utility's actions were not proper. (emphasis added)
7

Xcel cannot escape the intent of the Least Cost Planning rules in prudently reviewing 

generating facilities by sleight-of-hand avoidance. 4 CCR 723-3 Rule 3613(B) states that “an 

intervener may present evidence that, due to changed circumstances timely known to the utility

or that should have been known to a prudent person, the utility's actions were not proper.” This 

rule speaks directly to “changed circumstances” such as those we are currently experiencing, 

where construction costs are rising rapidly, the cost of renewable resources have decreased 

dramatically, and carbon taxes are on the horizon. Indeed, the U.S. Supreme Court’s recent 

decision in Massachusetts et al v. Environmental Protection Agency et al, Case 05-1120, decided 

on April 2, 2007, 5determined that carbon dioxide is a greenhouse gas that fits the definition of 

“air pollutant” under the Clean Air Act. See 42 U.S.C. Section 7521 (a)(1). 

And finally, in testimony Xcel filed during the Mesaba IGCC plant proceedings this past 

year, Xcel argued persuasively that it should not be forced to buy power from an IGCC plant. 

Xcel Energy’s Initial Brief dated January 5, 2007 Attachment 2, stated that:

· while the $2.156 billion ($3,593/kW) estimated Capacity Price of Mesaba may not be 

exact, it is an “appropriate proxy for assessing the overall costs of the project to Xcel and 

Minnesota ratepayers.”

· There is a “shortage of rail delivery capacity in the area which makes future coal delivery 

prices unstable.” 

· There is “insufficient information to determine that Mesaba Unit 1 would significantly 

reduce emissions over traditional technologies for the designated emissions”; and

· There are significant operational risks shifted to Xcel and its ratepayers.6

5 The opinion can be found at: http://www.supremecourtus.gov/opinions/06pdf/05-1120.pdf

6

State of Minnesota, Office of Administrative Hearings for the Public Utilities Commission, In the Matter of a 

Petition by Excelsior Energy Inc. For Approval of a Power Purchase Agreement Under Minn. Stat. Section 
8

Before proceeding further with potential vendors, Xcel should conduct a careful analysis 

of the information that is already available on IGCC plants, including information about the 

feasibility of Carbon Capture and Storage (“CCS”).7 Complainants contend that ample existing 

evidence raises questions about whether this investment would be prudent or beneficial. 

III. XCEL’S ACTIVITIES IN SEEKING FEDERAL FUNDING UNDER THE CLEAN 

COAL POWER INITIATIVE, AND SPECIAL BONDING TREATMENT FOR THE 

IGCC PLANT IN COLORADO HOUSE BILL 07-1150 CONTRAVENE XCEL’S CLAIM 

THAT IT IS MERELY CONSIDERING WHETHER TO FILE AN APPLICATION

Xcel states in its Motion to Dismiss that it is only considering whether or not it will apply

for a Certificate of Public Convenience and Necessity (CPCN), and thus does not need to provide 

the Commission with any information about the plant until it files the CPCN application. 

Complainants feel that this response is evasive, and that Xcel’s public statements as well as 

actions demonstrate Xcel’s intent to build a plant. 

Xcel’s Managing Director of Environmental Policy Frank Prager states in the March 1, 

2007 Rocky Mountain News article, that Xcel has already spent $3.5 million on preliminary

development, and is reviewing two vendor finalists. A further demonstration of Xcel’s 

determination to build the plant is found in its efforts to obtain $130 million in federal funding 

for the plant under the U.S. Department of Energy’s Clean Coal Power Initiative, also discussed 

in the article.8

The legislative declaration of HB 06-1281, quoted in Xcel’s Motion to Dismiss, states 

that IGCC technology “may” have significant environmental benefits over traditional coal-fired 

216B.1694, Determination of Least Cost Technology, and Establishment of a Clean Energy Technology Minimum 

Under Minn. Stat. Section 216B.1693, Xcel Energy Initial Brief, dated January 5, 2007, pp. 24, 27-29, 32 and 34.

7 Final Report, Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle and 

Pulverized Coal Technologies, July 2006, EPA-430/R-06/006, excerpts included here as Attachment 3.

8 March 1, 2007, Rocky Mountain News article by Gargi Chakrabarty attached to the initial complaint, titled Xcel’s 

Plans for Clean-Coal Plant May Grow. 
9

generation, and “may” generate electricity with greater thermal efficiency, less water and 

reduced emissions. The purpose of HB 06-1281 is to flesh out these critical questions that must 

be answered -- not to give Xcel carte blanche spending on a new technology before it has been 

proven to be in the public’s best interests. Complainants feel it would be in the best interests of 

the citizens of Colorado, the Commission, Xcel and all other affected parties to start reviewing 

the many studies about IGCC in a public forum before Xcel proceeds any further with plans for a 

coal gasification plant.

In addition, Xcel sought special financing arrangements under Colorado House Bill 07-

1150, which includes the IGCC plant identified in C.R.S. 40-2-123(2) as deserving of treatment 

as a “clean energy” resource, similar to that obtained for solar, wind and geothermal.9Including 

the IGCC plant as a “clean energy” resource in a bill that establishes a Clean Energy 

Development Authority responsible for granting bonds and other financial incentives further 

demonstrates Xcel’s commitment to building the IGCC plant.

IV. THE COMMISSION’S LEGISLATIVE MANDATE AND RULES, WHICH 

REQUIRE THAT ITS DECISIONS ARE PRUDENT, DEMAND THAT THE 

COMMISSION ENSURE THAT XCEL IS FOLLOWING THE MANDATE OF C.R.S. 

40-2-123(2)

The Commission’s Decisions Must be Prudent and in the Public’s Best Interest

Under Commission rules governing Commission Review and Approval of Least-Cost 

Resources, the Commission provides a review on the merits; a basis for its decision; sufficient 

evidence demonstrating why it approved or denied the utility’s plan; and the prudency of its 

decision. 10

9 Curiously, HB07-1150 exempts biomass if it is produced from fossil fuels, but includes IGCC, which is made from 

gasified coal, a fossil fuel.

10 See 4 CCR 723-3, Rules 3601 and 3613.
10

The long list of requirements under C.R.S. 40-2-123(2) demonstrate the need for the 

Commission to similarly determine whether or not an IGCC plant is in the public’s best interest

and the prudency of any investments in such a plant. See C.R.S. 40-2-123(2)(e)(1). During the 

2006 legislative session, Xcel was an integral part in writing HB 06-1281, which was codified as 

C.R.S. 40-2-123(2). The statute states:

“(c ) a public utility may apply under this subsection (2) to the Commission for a 

Certificate of Public Convenience and Necessity, and for cost recovery for one 

IGCC project. The utility’s application shall demonstrate why the utility should 

be granted a waiver of the Commission’s rules requiring competitive resource 

acquisition.”

Pursuant to C.R.S. 40-2-123(2), Xcel’s proposed IGCC plant has been exempted from the 

least-cost bidding process. In, The Overview and Purpose of the Least Cost Plan (LCP) states: 

“This process is intended to result in least-cost resource portfolios, taking into 

consideration projected system needs, reliability of proposed resources, expected 

generation loading characteristics, and various risk factors. The rules are intended 

to be neutral with respect to fuel type or resource technology.”

The LCP process is intended to result in least-cost resource portfolios. The LCP rules 

exist to protect the public’s interest, ensure that utilities obtain a fair return on investment and 

determine “various risk factors.” While an IGCC plant may be excluded from the Least Cost 

Planning process, the Commission’s role in protecting the public from undue risk and evaluating 

multi-billion dollar investment is implicit in its constitutional charter and throughout the rules 

governing its conduct.11 The Commission is charged with protecting the public’s interest in 

determining whether or not new generation facilities are needed. The Commission’s role in 

determining whether or not to issue Xcel a license for an IGCC power plant will have 

consequences for today’s ratepayers, and for our children and grandchildren. 

C.R.S. 40-2-123(2)(d)(III) states that Xcel provide information concerning 

11 See Article XXV of the Colorado Constitution, and C.R.S. sections 40-2-123, 40-2-102, 40-3-111 and 40-4-101. 
11

“the capture and sequestration of a portion of the project’s carbon dioxide 

emissions and the proposed level of carbon dioxide to be captured and 

sequestered from the IGCC project.”

The Environmental Protection Agency’s July 2006 Study on IGCC

These serious issues deserve scrutiny by the Commission and public. A number of 

reports have been issued, including a July 2006 study by the Environmental Protection Agency

(EPA) titled Final Report, Environmental Footprints and Costs of Coal-Based Integrated 

Gasification Combined Cycle and Pulverized Coal Technologies, July 2006, EPA-430/R-06/006, 

included here as Attachment 3. Page ES-6 of that report states that capturing 90% of the CO2 

from IGCC plants would increase the cost the total cost of electricity 38%, increase capital costs 

47%, and reduce efficiency 14%. 

Testimony of Mr. Stephen D. Jenkins, IGCC Expert

Mr. Stephen D. Jenkins testified before the Colorado PUC on February 12, 2007. Mr. 

Jenkins has worked in the industry for 30 years, and managed one of only two IGCC plants 

currently operating in the U.S., the Polk Power Station in Tampa, Florida. In direct testimony 

before the Florida Public Service Commission dated January 29, 2007, Mr. Jenkins stated that:

· The biggest IGCC plant to date is 260 net MW (p. 7);

· Proving coal gasification at the 600 MW scale will take another 6-8 years (p. 8); 

· Reliability is a serious issue – in its 9th year, Polk has 82% reliability; other plants 

availability was 60-78%. (p. 9);

· Operating a gasifier is significantly more complicated when integrated with other 

processes to produce electricity (p. 11); 
12

· IGCC takes several days for a cold start (p. 16); and could require 60 startups/shut downs per year, as opposed to pulverized coal plants, which require 2-3 start 

ups/shut downs per year (p. 17);

· Plant reliability affects emissions, and during start-ups, plants use more coal and 

therefore emit more pollution (p. 22); 

· Thus, emission rates could increase an average of 38% due to start-up/shut down 

events (p. 23); 

· The CO2 capture/removal system uses significant amounts of energy due to the 

high-pressure steam; (p. 25);

· To date, no U.S. company has experience with capture and sequestration (p. 28);

· No IGCC plant has a planned efficiency over 38% (p. 30); and 

· The emissions profile for super critical pulverized coal (SCPC) and IGCC are 

similar for primary pollutants (p. 31).

Mr. Jenkins testimony is included as Attachment 4.

House Resolution 2069 Recently Introduced That Would Impose Carbon Tax

The U.S. Congress has started to discuss imposing a carbon tax on fossil fuels. U.S. 

Representative Pete Stark of California recently introduced a bill to impose a carbon tax of $10 

per ton of carbon content on coal, petroleum and other fossil fuels, and the tax is scheduled to 

increase $10 per year until an 80% reduction from 1990 levels of carbon dioxide emissions have 

been realized.12 Since coal-fired electrical generation accounts for 40% of all CO2 emissions, 

12 Congressman Stark's Save Our Climate Act, H.R.2069 
13

and is the most carbon-intensive of all fossil fuels, the cost of adding a carbon tax to coal-fired 

power would significantly increase the total cost of electricity.

Xcel Has Submitted Recent Testimony on Many of These Issues in the Mesaba Docket

Many of these issues have been vetted in Minnesota, where a decision was released on 

April 12, 2007. The findings in that case are relevant here. Two Administrative Law Judges 

(“ALJs”) rejected Excelsior Energy’s petition for a Purchase Power Agreement (PPA) for a 600 

MW IGCC plant located near Taconite, MN, hereafter referred to as the “Minnesota IGCC” 

plant. In that docket, the ALJs reviewed information about the proposed IGCC plant’s cost, 

emissions profile and underlying technology, and recommended that a PPA was not in the public 

interest for a number of factors, including the Minnesota IGCC plant’s “unreasonable cost,” and 

the “likelihood that its cost will increase, not decrease, over time.” The ALJs also determined 

that because the plant did not significantly reduce either nitrogen oxides or mercury, it did not 

qualify as a “Clean Energy Technology” under Minn. Stat. Section 216B.1693(c) (see 

Attachment 1).

13

Investing in Coal-Fired Generation Electrical Generation May Not Be Prudent

As noted in Attachments 1 and 2, coal supplies and prices can no longer be assured and 

any investment in a coal-based technology has to give very serious consideration to the very real 

constraints on coal supply and transportation and the implications for future prices as well as 

functioning of coal-based power plants. There was substantial information regarding these 

constraints that came to light in Xcel’s electric and gas rate case last year (Docket 06S-234EG) 

13 MPUC Docket No. E-6472/M-05-1993, In the Matter of the Petition of Excelsior Energy Inc. for Approval of a 

Power Purchase Agreement Under Minn. Statute 261B.1694, Determination of Least Cost Technology, and 

Establishment of a Clean Energy Technology Minimum Under Minn. Statute 216B.1693, dated April 12, 2007, pp. 

55-56.
14

and these are issues that should receive careful analysis and public review before any further 

investments are made in a coal based technology. 

Reducing Carbon Dioxide Emissions and Green House Gases is a Goal of C.R.S. 40-2-

123(2)

The Legislative Declaration of HB 06-1281 and C.R.S. 40-2-123 (2) is that an IGCC 

plant could lead to “decreased emissions of greenhouse gases such as carbon dioxide.” In order 

to have significant reductions in greenhouse gases (“GHGs”), a coal gasification plant would 

have to be combined with provisions for carbon management such as Carbon Capture and 

Storage (“CCS”). There are many excellent reports on CCS, including the attached July 2006 

EPA report, included here as Attachment 3. IGCC without carbon capture and storage will 

significantly increase, rather than reduce carbon emissions. Even with CCS, IGCC plants will 

still lead to increases in emissions of carbon dioxide, while what is required to address climate 

change is very significant reductions in emissions of greenhouse gases.

In addition, the reduced efficiency and parasitic load from the equipment that will capture 

the CO2 significantly reduces the plant’s thermal efficiency, thus requiring more coal be 

burned.14

Reducing Regulated Pollutants Such as Mercury is a Goal of C.R.S. 40-2-123(2)

Both Xcel Energy’s Initial Brief in the Mesaba case,15 and the ALJ’s decision in the 

Mesaba IGCC decision16 stated that IGCC technology will not reduce mercury.

14 EPA, Final Report, Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle 

and Pulverized Coal Technologies, July 2006, EPA-430/R-06/006, page ES-6, included here as Attachment 3.

15 Xcel Energy Initial Brief, dated January 5, 2007, p. 32.

16 MPUC Docket No. E-6472/M-05-1993, In the Matter of the Petition of Excelsior Energy Inc. for Approval of a 

Power Purchase Agreement Under Minn. Statute 261B.1694, Determination of Least Cost Technology, and 

Establishment of a Clean Energy Technology Minimum Under Minn. Statute 216B.1693, dated April 12, 2007, pp. 

55-56.
15

Promoting Technologies Such as Concentrating Solar Power (CSP) is a Goal of C.R.S. 40-

2-123(2)

C.R.S. 40-2-123(1) states: 

that “the [C]omission shall give the fullest possible consideration to the costeffective implementation of new clean energy...in its consideration of generation 

acquisitions...bearing in mind the beneficial contributions...to Colorado’s energy

security, economic prosperity, environmental protection, and insulation from fuel 

price increases.” 

The Colorado PUC held a pubic information session on Concentrating Solar Power (CSP) 

in March 2007, with Mr. Mark Mehos from the National Renewable Energy Lab in Golden.17

CSP has zero fuel cost and zero chance of fuel cost increases, emits practically zero pollutants, 

and does not include the risks, liabilities and unknowns of carbon capture and storage. In 

addition, increased use of renewable energy will drive down the cost. CSP can be either used as 

a stand alone form of centralized energy generation or it can be used to displace fossil fuels.

Many Colorado legislators have expressed an interest in promoting CSP. Attached is a 

letter from over 30 state Representatives voicing support for CSP.18

If we transform our electric grid to one that runs on renewable energy and then move to 

electric and plug-in hybrid vehicles, we can also make major reductions in our carbon dioxide 

emissions from vehicles, thus increasing the value of CSP for all of Colorado.

CONCLUSION

Complainants respectfully request the Commission to .

1. Open a docket to review IGCC and CCS and prepare a report for public review; and 

17 The key points, included in Attachment 5, are that the CSP potential is enormous, the technology can be made 

dispatchable with either thermal storage or through hybridization with fossil fuel plants. 

18 See Attachment 6, letter dated April 27, 2007, from Colorado Representative Judy Solano et al. 
16

2. Continue to seek ways to promote the deployment of Concentrating Solar Power in 

Colorado per the request of Colorado’s legislators.19)

Dated May 3, 2007.

Respectfully submitted,

_____________________________

Nancy LaPlaca

4801 W. Yale Ave.

Denver CO 80219

nancylaplaca@yahoo.com

303-588-3937

______________________________

Leslie Glustrom

4492 Burr Place

Boulder, CO 80303

lglustrom@gmail.com

303-245-8637

19 Generation resources under 30 MW are exempt from the PUC’s Least Cost Plan resources. 
17

CERTIFICATE OF SERVICE

I hereby certify that on May 3, 2007, the original and seven copies of the foregoing 

RESPONSE TO XCEL’S MOTION TO DISMISS IN 07F-088E

was served by hand delivery on:

Doug Dean, Director

Colorado Public Utilities Commission

1580 Logan, OL2

Denver, CO 80203

And have hand-delivered, mailed or e-mailed copies to the following:

Ms. Paula M. Connelly, Esq. Christopher M. Irby, Esq.

Xcel Energy Services. Assistant Attorney General

1225 17th St. Ste. 900 1525 Sherman St., 7th Floor

Denver, CO 80202 Denver CO 80203

paula.connelly@xcelenergy.com Chris.irby@state.co.us

Mr. Dale Hutchins Chere Mitchell

Colorado Office of the Attorney General chere.mitchell@dora.state.co.us

(Office of Consumer Counsel)

1525 Sherman St., Floor 5 Dudley Spiller, Esq.

Denver, CO 80203-1714 Olivia Lucas, Esq.

dale.hutchins@state.co.us Ryley, Carlock & Applewhite

1999 Broadway, Suite 1800

Stephen W. Southwick, Esq. Denver CO 80202

First Assistant Attorney General dspiller@rcalaw.com

Office of the Attorney General olucas@rcalaw.com

1525 Sherman St., 7th Floor

Denver CO 80203

Stephen.southwick@state.co.us

P.B. Schechter

Rate/Financial Analyst

Office of Consumer Counsel

1560 Broadway, Suite 200

Denver CO 80202

Pb.schechter@dora.state.co.us

____________________________________

Nancy LaPlaca

____________________________________

Leslie Glustrom
This document is not available in Regulations.gov since it 

contains copyrighted material that may not be reproduced 

without consent of the copyright holder. 

Contact the EPA Docket Center, Public Reading Room to view 

or receive a copy of this document. Requests for copies may be 

made as follows: 

In person/writing: 

Environmental Protection Agency, Docket Center 

1301 Constitution Ave NW, 2822T, Room 3334 

Washington, DC. 20004 

Telephone: 

202-566-1744 

Fax: 

202-566- 9744 

Email: 

docket-customerservice@epa.gov
LBNL-57768

Leakage and Seepage of CO2 from Geologic

Carbon Sequestration Sites:

CO2 Migration into Surface Water

Curtis M. Oldenburg

Jennifer L. Lewicki

Earth Sciences Division

Ernest Orlando Lawrence Berkeley National Laboratory

Berkeley, CA 94720

June 17, 2005

This work was supported in part by a Cooperative Research and Development Agreement (CRADA) between BP

Corporation North America, as part of the CO2 Capture Project (CCP) of the Joint Industry Program (JIP), and the

U.S. Department of Energy through the National Energy Technologies Laboratory (NETL), and by the Ernest

Lawrence Berkeley National Laboratory, managed for the U.S. Department of Energy under Contract No. DEAC03-76SF00098.
CO2 Seepage into Surface Water

DRAFT 2 Rev. 1.2

DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither

the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or

implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any

information, apparatus, product, or process disclosed, or represents that its use would not infringe privately held

rights. Reference herein to any specific commercial product, process, or service by trade name, trademark,

manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring

by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not

necessarily state or reflect those of the United States Government or any agency thereof.
CO2 Seepage into Surface Water

DRAFT 3 Rev. 1.2

TABLE OF CONTENTS

List of Tables ..................................................................................................................................5

List of Figures.................................................................................................................................5

Abstract...........................................................................................................................................7

1. Introduction...............................................................................................................................9

2. Definitions and Environment.................................................................................................10

2.1. Terminology.......................................................................................................................10

2.2. Environment of Interest .....................................................................................................12

3. Natural CO2 and CH4 Fluxes.................................................................................................13

3.1. Introduction........................................................................................................................13

3.2. Groundwater ......................................................................................................................13

3.3. Wetlands ............................................................................................................................14

3.4. Rivers .................................................................................................................................15

3.5. Lakes and Reservoirs .........................................................................................................15

3.6. Marine Environments ........................................................................................................16

4. CO2 Leakage and Bubble Flow..............................................................................................17

4.1. Bubble Formation Fundamentals.......................................................................................17

4.2. Steady-State Bubble Rise in Surface Water ......................................................................19

4.3. Bubble and Channel Flow..................................................................................................19

4.4. Steady-State Bubble Rise in Porous Media .......................................................................20

4.5. Transport by Bubble Flow and Diffusion in Surface Water..............................................24

4.6. Transport of Dissolved CO2 in Surface Water...................................................................28

4.7. Effects of Pressure, Temperature, and Salinity on Ebullition............................................28

5. Summary and Discussion .......................................................................................................29

5.1. Summary ............................................................................................................................29

5.2. Discussion..........................................................................................................................30

6. Recommendations for Future Research ...............................................................................31

6.1. CO2 Flow and Transport in Water .....................................................................................31

Acknowledgments ........................................................................................................................32

Nomenclature ...............................................................................................................................33

References.....................................................................................................................................34

Figures...........................................................................................................................................39
CO2 Seepage into Surface Water

DRAFT 4 Rev. 1.2

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CO2 Seepage into Surface Water

DRAFT 5 Rev. 1.2

LIST OF TABLES

Table 2.1. Definitions of terms used in this report. ......................................................................11

Table 2.2. Factors favoring ebullition and dispersion. .................................................................12

Table 4.1. Fluid properties for the analysis of bubble flow in porous media. ..............................23

Table 4.2. Porous media properties and results for bubble flow in porous media........................24

Table 4.3. Henry’s law coefficients (Ki) for different Pz values...................................................27

Table 4.4. Precentage of flux by bullition for CO2 and CH4. .......................................................27

LIST OF FIGURES

Figure 2.1. Schematic of transitions at the interface between porous media and surface water. .39

Figure 2.2. Schematic of flow regimes in porous media. .............................................................40

Figure 2.3. Schematic of surface-water environments .................................................................41

Figure 2.4. Phase diagram for CO2 showing typical P-T path with depth in the earth.................42

Figure 4.1. Half-section of a spherical bubble showing forces. ...................................................43

Figure 4.2. Bubble rise velocity as a function of bubble radius. ..................................................44

Figure 4.3. Force balance on single CO2 bubble. .........................................................................45

Figure 4.4. Log10 ub for three different coarse porous media as a function of particle size. ........46

Figure 4.5. Schematic of domain and variables for ebullition vs. dispersive mass transport.......47

Figure 4.6. Solubility of CO2 in water and various brines as a function of depth........................48
CO2 Seepage into Surface Water

DRAFT 6 Rev. 1.2

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CO2 Seepage into Surface Water

DRAFT 7 Rev. 1.2

ABSTRACT

Geologic carbon sequestration is the capture of anthropogenic carbon dioxide (CO2) and its

storage in deep geologic formations. One of the concerns of geologic carbon sequestration is

that injected CO2 may leak out of the intended storage formation, migrate to the near-surface

environment, and seep out of the ground or into surface water. In this research, we investigate

the process of CO2 leakage and seepage into saturated sediments and overlying surface water

bodies such as rivers, lakes, wetlands, and continental shelf marine environments. Natural CO2

and CH4 fluxes are well studied and provide insight into the expected transport mechanisms and

fate of seepage fluxes of similar magnitude. Also, natural CO2 and CH4 fluxes are pervasive in

surface water environments at levels that may mask low-level carbon sequestration leakage and

seepage. Extreme examples are the well known volcanic lakes in Cameroon where lake water

supersaturated with respect to CO2 overturned and degassed with lethal effects. Standard bubble

formation and hydrostatics are applicable to CO2 bubbles in surface water. Bubble-rise velocity

in surface water is a function of bubble size and reaches a maximum of approximately 30 cm s-1

at a bubble radius of 0.7 mm. Bubble rise in saturated porous media below surface water is

affected by surface tension and buoyancy forces, along with the solid matrix pore structure. For

medium and fine grain sizes, surface tension forces dominate and gas transport tends to occur as

channel flow rather than bubble flow. For coarse porous media such as gravels and coarse sand,

buoyancy dominates and the maximum bubble rise velocity is predicted to be approximately 18

cm s-1. Liquid CO2 bubbles rise slower in water than gaseous CO2 bubbles due to the smaller

density contrast. A comparison of ebullition (i.e., bubble formation) and resulting bubble flow

versus dispersive gas transport for CO2 and CH4 at three different seepage rates reveals that

ebullition and bubble flow will be the dominant form of gas transport in surface water for all but

the smallest seepage fluxes or shallowest water bodies. The solubility of the gas species in water

plays a fundamental role in whether ebullition occurs. We used a solubility model to examine

CO2 solubility in waters with varying salinity as a function of depth below a 200 m-deep surface

water body. In this system, liquid CO2 is stable between the deep regions where supercritical

CO2 is stable and the shallow regions where gaseous CO2 is stable. The transition from liquid to

gaseous CO2 is associated with a large change in density, with corresponding large change in

bubble buoyancy. The solubility of CO2 is lower in high-salinity waters such as might be

encountered in the deep subsurface. Therefore, as CO2 migrates upward through the deep

subsurface, it will likely encounter less saline water with increasing capacity to dissolve CO2

potentially preventing ebullition, depending on the CO2 leakage flux. However, as CO2

continues to move upward through shallower depths, CO2 solubility in water decreases strongly

leading to greater likelihood of ebullition and bubble flow in surface water. In the case of deep

density-stratified lakes in which ebullition is suppressed, enhanced mixing and man-made

degassing schemes can alleviate the buildup of CO2 and related risk of dangerous rapid

discharges. Future research efforts are needed to increase understanding of CO2 leakage and

seepage in surface water and saturated porous media. For example, we recommend experiments

and field tests of CO2 migration in saturated systems to formulate bubble-driven waterdisplacement models and relative permeability functions that can be used in simulation models.
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DRAFT 8 Rev. 1.2

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CO2 Seepage into Surface Water

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1. INTRODUCTION

Geologic carbon sequestration is the capture of anthropogenic CO2 and its storage in deep

underground formations such as depleted oil and gas reservoirs and deep brine-filled formations.

The anthropogenic CO2 that would otherwise be emitted into the atmosphere will typically be

separated from industrial and power-plant flue gases. The purpose of geologic carbon

sequestration is to reduce net atmospheric emissions of CO2 to mitigate potential climate change

associated with the role of CO2 as a greenhouse gas.

One of the key issues associated with geologic carbon sequestration is the integrity of the

geological reservoir with respect to containment of CO2 for a significant although yet-to-bedefined time frame so that the strategy serves the intended purpose of reducing net CO2

emissions. An additional concern is that leaking CO2 from geologic sequestration sites may

cause potential health, safety, and environmental (HSE) risks. We have investigated potential

HSE risks in prior research through our modeling of CO2 leakage and seepage in the nearsurface environment (Oldenburg and Unger, 2003; 2004). In this previous work, we focused on

CO2 migration in the vadose zone of on-shore environments. However, geologic carbon

sequestration is being implemented in off-shore environments such as in the Sleipner project

(e.g., Torp and Gale, 2004), and many other off-shore projects are being discussed. Furthermore,

CO2 may seep into surface waters in on-shore environments prior to influencing the vadose zone

or atmospheric surface layer. Consequently, there is a need to investigate CO2 leakage and

seepage in areas where CO2 will seep into surface waters such as rivers, lakes, wetlands, and

oceans in order to understand HSE risks in these environments.

To evaluate surface-water effects on CO2 leakage and seepage, the following key research

questions must be addressed: (1) What are the physical processes relevant to CO2 migration

through sediments and overlying surface water either as bubbles or as a dissolved component in

water? (2) Does surface water attenuate or enhance CO2 seepage flux? (3) Under what conditions

can CO2 concentrations build up at depth and lead to the potential for catastrophic release?

This project focuses on CO2 seepage at relatively low fluxes in which liquid water is the

connected phase and the CO2 exists either in discrete bubbles or as a dissolved component in the

aqueous phase. As will be shown, CO2 in bubbles can be in gaseous, supercritical, and even

liquid phases depending on the pressure and temperature in the surface or pore water. The

salinity, temperature, and pressure (depth) span a wide range in surface- and pore-water systems.

The surface-water bodies of interest are, in order of increasing depth, wetlands, rivers, lakes, and

oceans. We also consider bubble rise in pore water in sediments and pore space in general

immediately below surface water.

The purpose of this report is to summarize the state of knowledge of the transport of CO2

through surface-water bodies and to a lesser extent through water-saturated sediments. In so

doing, we will discuss the physical processes of ebullition and bubble flow as well as transport

by diffusion and dispersion. We also discuss the implications of CO2 seepage into surface water

and subsequent bubble flow and transport on potential leakage and seepage fluxes from geologic

carbon sequestration sites. This project was undertaken with a very limited budget and within a

short time frame, and is therefore necessarily limited in scope.
CO2 Seepage into Surface Water

DRAFT 10 Rev. 1.2

2. DEFINITIONS AND ENVIRONMENT

2.1. Terminology

In this section, we discuss terminology and definitions to formalize the later discussion in the

report. Table 2.1 shows key terms, definitions, and examples that apply to CO2 leakage and

seepage from geologic carbon sequestration sites, and the associated form of transport of CO2 in

surface water and subjacent saturated sediments. In Table 2.2, we present a categorization of

some of the processes and conditions that tend to favor either ebullition or dispersion. We find

that relatively low fluxes and high solubility of CO2 in the surface water tend to favor dispersion,

since bubbles will tend not to form. In contrast, relatively high fluxes and low solubility of CO2

tend to favor ebullition and bubble flux upward. Secondary features such as bottom topography

may also affect ebullition and dispersion by facilitating density-driven flow and associated

mixing.

We present in Fig. 2.1 a schematic of the various ways that CO2 seepage can occur from

subjacent sediments to overlying surface water, with emphasis on the terminology of the process

that occurs upon transition between these two environments. For example, in the first column of

Fig. 2.1, transport is by advection and diffusion in the porous media, and by bubble flux in the

surface water. The transition at the sediment-water interface occurs by the process of ebullition.

Ebullition at the sediment-water interface could occur if CO2 gas solubility in the surface water

is less than in the pore water (e.g., if the surface water is more saline than the groundwater). In

the second column, the transport is by bubble flux in both the sediments and the surface water.

In the third column, transport is by advection and diffusion in both media. And finally, in the

fourth column, transport is by bubble flux in the porous media, and by advection and diffusion in

the surface water, the transition being caused by dissolution at the interface. Dissolution at the

sediment-water interface could occur in cases where the groundwater is warmer than the surface

water, in which case CO2 solubility would increase upon reaching the cooler surface water.

Bubble transport in surface water is familiar to everyone from their experiences observing the

behavior of CO2 bubbles in carbonated beverages. The form of bubble flow in porous media is

not as familiar to people, although fluidized beds and packed-bed reactors with upward gas flow

are well-known chemical processing techniques (Iliuta et al., 1999). We limit our consideration

to the case where the solid grains are not disturbed by the bubble flow, and we present in Fig. 2.2

a sketch of two different end-members within this regime: (1) discrete bubbles, and (2) channel

flow. If the gas flux is low, gases can migrate upward through pore bodies and throats as small

individual bubbles, with deformation and blockage occurring as controlled by solid matrix grains

(Fig. 2.2a). In contrast, when the flux is large, gas bubbles can be larger and/or more numerous

leading to greater entrapment and coalescence. When entrapment and coalescence exceed a

threshold, a connected channel of gas forms between the leading edge of water displacement and

the gas source. When this connectivity occurs, gas flow can be driven by gas-pressure-gradient

rather than buoyancy forces, and these pressure-gradient forces can overcome the capillary,

permeability, and/or liquid displacement resistances and displace water. Flow in a channelized

regime is further favored by the low gas viscosity. Further details on bubble flow in porous

media are presented in Sections 4.3 and 4.4.
CO2 Seepage into Surface Water

DRAFT 11 Rev. 1.2

Table 2.1. Definitions of terms used in this report.

Term Definition Example

Leakage Migration in the subsurface away

from the primary containment

formation.

CO2 escaping from the containment

reservoir through an unrecognized

permeable fault.

Seepage Migration across a boundary such

as the ground surface or into

surface water.

CO2 emissions from the ground into

the atmosphere after leaking up a

permeable fault.

Bubble Immiscible volume of a secondary

fluid phase (e.g., supercritical, gas,

liquid) within a primary connected

phase (e.g., aqueous) in which the

bubble is contained.

CO2 or CH4 gas in surface water

above seepage sites.

Ebullition Formation of bubbles from a liquid

supersaturated with respect to

dissolved gases, either in surface

water or in groundwater.

Concentrations of dissolved CO2 or

CH4 in sediments below wetlands

can reach supersaturation causing

exsolution of gas bubbles.

Bubble flux Flux of component as transported

in discrete bubbles.

CO2 in bubbles moving buoyantly

upward in surface water.

Dissolution Uptake of volatile components

into solution in the liquid phase.

Carbonation of water produces CO2

in solution in fresh water, as in

carbonated drinks prior to

degassing.

Advection Component transport driven by

movement of a phase containing

the component.

CO2 dissolved in water is

transported along with the flowing

water.

Diffusion Component transport driven by

concentration gradients within a

phase.

Biogenic CO2 or CH4 in sediments

below wetlands generated at a low

rate creates concentration gradients

of dissolved species that are then

transported from high to low

concentration (i.e., down the

concentration gradient).

Dispersion Component transport by smallscale advective motions and by

diffusion that can be modeled

collectively as a diffusive process.

CO2 or CH4 transported by

turbulent motions and molecular

diffusion induced by tidal flushing

in wetlands.
CO2 Seepage into Surface Water

DRAFT 12 Rev. 1.2

Table 2.2. Factors favoring ebullition and dispersion.

Property Favoring ebullition Characteristic of ... Favoring dispersion Characteristic of ...

CO2 seepage flux Large, focused High leakage rate Small, diffuse Low leakage rate

Currents Stagnant, stable Oceans, equatorial

lakes

Mixed, unstable Rivers, high-latitude

lakes

Salinity High, salty Shallow inland seas Low, fresh water Rivers, lakes

Temperature Warm Estuaries, wetlands Cold High-latitude rivers,

lakes, deep ocean

Depth Shallow Estuaries, wetlands,

rivers

Deep Oceans, mountain and

crater lakes

Bottom topography Flat, horizontal Oceans, seas Sloping, with relief Rivers, lakes

2.2. Environment of Interest

The focus of this report is on CO2 migration upward through saturated sediments and overlying

surface water. The environments we consider are shown schematically in cross-section in Fig.

2.3. As shown, rivers, lakes, wetlands, estuaries, and continental shelf marine environments are

within the scope of our discussion. Salinity, depth, temperature, and degree of mixing are all key

characteristics that bear on the question of CO2 transport. We consider the existence of nonspecific leakage pathways upward from the deep CO2 injection horizons as being capable of

delivering CO2 to the shallow environment. These leakage pathways could be along faults or

fault zones, but we assume that by the time the CO2 reaches the shallow sediments below surface

water, the CO2 flux is dispersed and relatively small. The reason for this focus is that large

fluxes, e.g., from well blowouts, will be obvious HSE risks that will be mitigated as quickly as

possible. Of more concern from the HSE perspective are small fluxes that may be hard to detect

but that could lead to HSE consequences, either in the long-term, or due to near-surface buildup

and rapid emission (e.g., Lake Nyos (Sigurdsson et al., 1987)). The seepage fluxes that we

consider in our analysis of Section 4.5 are the same as used in our prior work (Oldenburg and

Unger, 2003; 2004).

Within the range of pressures below the surface water bodies of interest, CO2 can be in gaseous,

supercritical, or liquid conditions. As shown in the phase diagram for pure CO2 (Fig. 2.4), CO2

has a critical point of 73.8 bars and 31.0 oC, and is a gas at ambient atmospheric temperature and

pressure (1 bar, 25 o

C). Shown on Fig. 2.4 is a wide band indicating a P-T path within the earth

assuming a geothermal gradient of 25 o

C km-1 and hydrostatic pressure. As shown, the P-T path

passes almost directly through the critical point. In fact, in continental onshore conditions as we
CO2 Seepage into Surface Water

DRAFT 13 Rev. 1.2

have studied in the past (Oldenburg and Unger, 2003), the P-T path from depth to surface passes

below the critical point. By such a path, CO2 changes from supercritical to gaseous, and

undergoes no large jumps in physical properties (e.g., density or viscosity) as it passes through

31 o

C at pressures below 73.8 bars. In contrast, in the offshore or deep surface-water condition,

the P-T path will traverse part of the liquid-stability field from depth to the surface because of

the hydrostatic pressure in the surface water and lack of geothermal gradient there. In essence,

the P-T path in the subsurface is shifted upward when there is surface water, and this causes the

P-T path to intersect part of the liquid field. In Fig. 2.4, the top edge of the wide P-T path can be

considered to be a sub-surface-water P-T path, and the bottom edge a sub-onshore-vadose zone

path. The transition from gaseous to liquid CO2 or vice versa is associated with strong changes

in density, viscosity, and solubility with implications for CO2 seepage into surface water as will

be discussed in Section 4.6.

3. NATURAL CO2 AND CH4 FLUXES

3.1. Introduction

CO2 leakage from geologic carbon sequestration sites, should it occur, will be superimposed on

gas fluxes originating from a variety of biological and hydrological processes and sources.

Numerous studies have been conducted to measure natural CO2 and CH4 fluxes, to estimate the

relative contributions of ebullition and dispersion to the total flux, and to determine the physical

processes controlling ebullition and dispersion. These studies offer direct evidence of how

leakage and seepage fluxes of similar magnitude will behave in similar environments. We have

discussed the issue of natural background gas fluxes with respect to the problem of detecting

CO2 leakage and seepage (Oldenburg and Lewicki, 2004). Below, we present a review of

natural CO2 and CH4 fluxes relevant to developing an understanding of CO2 leakage and seepage

into surface water.

3.2. Groundwater

Recent studies have quantified the flux of CO2 derived from deep crustal and mantle origin that

is dissolved and transported by shallow groundwaters (e.g., Evans et al. 2002; Chiodini et al.,

1999 and 2000). For example, throughout Tyrrhenian Central Italy, widespread non-volcanic

CO2 degassing (likely originating from a crustally-contaminated mantle or a mixture of

magmatic and crustal components) occurs from vent and diffuse soil gas emissions and from

CO2-enriched groundwaters (Chiodini et al., 1999). From the Tyrrhenian Sea to the Apennine

Mountains, buried structural highs act as gas traps. When total pressure of the reservoir fluid

exceeds hydrostatic pressure, a free gas phase forms gas reservoirs from which gas may escape

to the surface. Carbon dioxide is then released to the atmosphere either directly through gas

emissions or by dissolution in groundwaters and subsequent release at surface springs.

Measured CO2 partial pressure (PCO2) values for springs are up to four orders of magnitude

greater than that of the atmosphere (Chiodini et al., 1999). Therefore, when groundwater is

discharged at the surface, it releases a large amount of the carbon through CO2 degassing.

Chiodini et al. (1999, 2000) found that in geographic regions characterized by thick regional

carbonate aquifers, most or part of the deeply derived gas is dissolved by the aquifers, whereas in
CO2 Seepage into Surface Water

DRAFT 14 Rev. 1.2

regions characterized by small aquifers, these aquifers cannot dissolve a large quantity of the

CO2 and extensive vent and soil CO2 emissions occur at the surface. Chiodini et al. (2000) used

mass balance equations coupled with carbon isotopic analyses and hydrologic data to estimate

the flux of deeply derived CO2 into the aquifers. These authors estimated deeply derived CO2

fluxes up to 0.29 g m-2 d-1 into the carbonate Apennine aquifers. For high PCO2 waters, the CO2

flux lost to the atmosphere is of the same order of magnitude as the influx of deep CO2.

Evans et al. (2002) conducted a chemical, isotopic, and hydrologic investigation of cold springs

around Mammoth Mountain, California, USA. Based on these data, they estimated that the cold

groundwater system around Mammoth Mountain discharges ~2 x 104

 tonnes y-1 of magmatic

carbon (as CO2), indicating that these waters have the ability to dissolve and transport large

quantities of deeply derived CO2. They also interpreted the 1 x 105

 tonnes CO2 y

-1 that degasses

diffusely through soils at Mammoth to be the gas that exceeds the dissolving capacity of the

groundwater.

Shipton et al. (2004a, b) investigated the northern Paradox Basin (Utah, USA) as a natural

analog for CO2 leakage from a geologic carbon storage reservoir. Here, CO2 of deep-crustal

origin leaks from numerous storage reservoirs (high PCO2 shallow aquifers) along faults to the

surface. An important loss of CO2 to the atmosphere occurs as groundwaters discharge as

springs at the surface and CO2 degasses, as is evidenced by continual bubbling of CO2 from

many of these springs (Shipton et al., 2004a, b).

3.3. Wetlands

Much attention has focused on understanding the origin, transport, and fate of CH4 in wetlands

(e.g., Harriss and Sebacher, 1981; Wilson et al., 1989; MacDonald et al., 1998; Walter and

Heimann, 2000; Rosenberry et al., 2003; Christensen et al., 2003) because these regions contain

large quantities of stored organic carbon that, if released as CH4, may strongly influence global

climate. Wilson et al. (1989) showed from repeated measurements of CH4 flux in a temperate

freshwater swamp that this flux was highly variable over space and time. Ebullition from the

bottom sediments was an important form of CH4 release; although ebullition was only recorded

in 19% of their measurements, it accounted for 34% of the total flux over time. However, unlike

many other studies, they found that flux was not correlated with water depth. Rosenberry et al.

(2003) presented hydraulic-head data for a peatland in northern Minnesota, USA, which

indicated that the peatland was overpressured at depth and the amount of overpressuring varied

over time. This temporal variability was indicative of changes in the volume of gas bubbles in

the peat column in response to changes in temperature, and rates of gas production, transport,

phase change, and ebullition. The numerous rapid declines observed in overpressuring were

likely caused by ebullition events, which occur to reduce the pressure-head difference with a

decrease in water level (Rosenberry et al., 2003). Christensen et al. (2003) measured in a closed

laboratory system diffusion and ebullition fluxes of CH4 from monoliths taken from wetland

ecosystems in Sweden. They showed that ebullition accounts for 18 to 50% of the total CH4 flux

from their system and that this may represent a minimum contribution expected in nature, due to

the stable laboratory conditions (e.g., isothermal, no wind).
CO2 Seepage into Surface Water

DRAFT 15 Rev. 1.2

3.4. Rivers

Smith et al. (2000) measured both diffusive and bubbling CH4 fluxes in open water, bare soils,

macrophyte mats, and flooded forest along the Orinoco River floodplain, Venezuela. They

found that due to productivity, the flooded forest environment accounted for the highest diffusive

and bubble fluxes and that ebullition accounted for 65% of all emissions. Large temporal

variations in CH4 fluxes were also observed, due primarily to seasonally fluctuating water levels.

The diffusive CH4 flux was constant over the seasons in the open water environment, but

ebullition was higher during dry seasons.

Where the Little Grand Wash Fault Zone crosses the Green River (Utah, USA), CO2 of deepcrustal origin discharges into the Green River. Here, a line of gas bubbles is observed along the

fault trace (e.g., Shipton et al., 2004a, b).

3.5. Lakes and Reservoirs

Numerous investigations have focused on describing and quantifying the production and

transport of CH4 and CO2 in lakes and reservoirs (e.g., Sigurdsson et al., 1987; Oskarsson, 1990;

Giggenbach, 1990; Giggenbach et al., 1991; Keller and Stallard, 1994; Woods and Philips, 1999;

Casper et al., 2000; Joyce and Jewell, 2003). In non-volcanic/magmatic lake environments, CO2

and CH4 are primarily derived from biologic processes. The primary pathways of gas exchange

between water and the atmosphere are molecular diffusion across the air-water interface and

ebullition from the sediment through the water column. Pathways of exchange of CO2 and CH4

between the lake and the atmosphere differ significantly because of their different solubilities,

different concentrations in the epilimnion, and different atmospheric concentrations. Because

the solubility of CH4 in water is about an order of magnitude less than that of CO2 (20 o

C),

elevated CH4 concentrations at depth lead to bubble formation, whereas elevated aqueous CO2

concentrations can build up at depth. Many lakes are supersaturated with respect to CO2,

particularly in the wintertime, when productivity, and therefore photosynthetic uptake, is low.

Ebullition is the primary release mechanism of methane from lakes and other shallow water

environments (i.e., where CH4 production is high and water is shallow). However, bubbling is

episodic and dependent on a variety of factors such as temperature, water depth, barometric

pressure variations, winds, and related bottom shear stress (e.g., Keller and Stallard, 1994;

Walter and Heimann, 2000; Rosenberry et al., 2003; Joyce and Jewell, 2003).

Casper et al. (2000) measured CO2 and CH4 concentration gradients with depth in a small

freshwater lake in the U.K. and determined the diffusion and ebullition fluxes of CH4 and CO2 to

the atmosphere. They found that ebullition accounted for 96% of the CH4 flux and diffusion

accounted for 99% of the CO2 flux. The rate of gas ebullition was highly variable in space and

time and decreased with water depth. Casper et al. (2000) also observed pulses of ebullition to

be correlated with periods of falling barometric pressure. Joyce and Jewell (2003) estimated the

contribution of bubble to total methane flux, its temporal variation, and relationship to current

velocities at several lakes in Panama and Puerto Rico. The authors found a correlation between

current velocity and CH4 flux and also observed temporal correlation of bubbling across sites in

the lakes. They proposed a physical model relating lake-bottom shear stresses to measured

current velocities, whereby sediments can be sheared only by bottom currents that are able to

overcome the sediment cohesive strength. When this occurs, ebullition is induced. However, the

magnitude of ebullition flux depends not only on threshold shear velocity but also on the
CO2 Seepage into Surface Water

DRAFT 16 Rev. 1.2

quantity of the free gas in the sediments available for release. As a result, large bubbling events

may occur without trigger after prolonged periods of quiescence because substantial methane has

accumulated. Conversely, no bubbling may occur with significant current velocities if no gas

has accumulated (Joyce and Jewell, 2003).

Much attention has been paid to the transport and fate of CO2 in lakes in volcanic/magmatic

environments, due to the lethal gas bursts that occurred at Lakes Monoun and Nyos, Cameroon,

in 1984 and 1986, respectively. Approximately 1800 people were killed in these combined

events by the hypothesized overturn and depressurization of CO2-rich lake waters (derived from

emission of magmatic CO2 into the lakes) and subsequent large-scale CO2 ebullition. Lakeoverturn has been suggested to be caused by wind-driven mixing, precipitation, and landslides.

However, the viability of these triggering mechanisms has remained unclear. Regardless of this

uncertainty, these lakes displayed density stratification and within the deep anoxic stagnant

layers, PCO2 built up to equal the ambient hydrostatic pressure (Sigurdsson et al., 1987;

Oskarsson, 1990; Giggenbach, 1990). Under normal conditions, CO2 may have diffused into

shallow waters and escaped gradually to the atmosphere as bubbles formed at shallow water

levels. However, the rapid overturn of these lakes caused depressurization of CO2-rich deep

waters and nucleation of CO2 in the deep water. The resultant ebullition led to the gas bursts at

the surface (Sigurdsson et al., 1987; Oskarsson, 1990; Giggenbach, 1990). In the Lake Nyos

event, 240,000 tonnes of CO2 were lost from the upper 100 m of the lake (Giggenbach, 1990).

Giggenbach et al. (1991) showed that other CO2-rich lakes worldwide (Laacher See, Germany,

Dieng, Indonesia, and Mt. Gambier, Australia) display similar chemical and physical

characteristics to Lakes Nyos and Monoun. In general, seasonal overturn, other periodic deep

mixing processes, or man-made degassing schemes (e.g., Halbwachs et al., 2004) are needed to

prevent density stratification and the potential for extreme buildup of CO2 at depth in lakes

subject to CO2 influxes at depth.

3.6. Marine Environments

Hoveland et al. (1993) presented a review of CH4 degassing from shallow marine sediments

worldwide and estimated the global flux. Based on geophysical mapping, visual observations,

and geochemical sampling, CH4 occurs at aqueous saturation concentrations and in free gas form

at many locations in the upper layers of marine sedimentary basins (Hoveland et al., 1993 and

references therein). This CH4 originates either from microbial degradation of organic material in

shallow sediments or at greater depth in sedimentary basins (> 2 km) by thermal “cracking” of

organic materials to form petroleum hydrocarbons. Methane may then migrate by diffusion in

pore waters or as bubbles. In many locations, gas escapes from shallow marine sediments to the

water column as continuous or intermittent bubble streams (Hoveland et al., 1993 and references

therein). For example, in the Gulf of Mexico, gas seeps are associated with different geological

environments (e.g., deltaic sediments, salt domes, and gas hydrates in sediments on and at the

base of the continental slope) (Anderson and Bryant, 1990). In the North Sea, gas migrates from

depth along deep-seated faults and evidence of gas (acoustic turbidity) close to the seabed is

present over an area of ~120,000 m2

. Within this larger area, ~120 bubble plumes within a 6500

m2

 area have been observed. At Cape Lookout Bight, a marine basin on the Outer Banks of

North Carolina, USA, shallow sediment pore waters become saturated with methane during the

summer and ebullition occurs during low tide due to reduction in hydrostatic pressure (Martens

and Klump, 1980). Martens and Klump (1980) estimated that ~15% of the methane in the
CO2 Seepage into Surface Water

DRAFT 17 Rev. 1.2

bubbles here is lost to solution during transit through the water column and ~6.9 x 107 g CH4 yr

-1

are lost to the atmosphere.

Perhaps the most well studied and quantified hydrocarbon ebullition in shallow marine

environments has occurred near Coal Oil Point, off the coast of Santa Barbara, California, USA

(e.g., Hornafius et al., 1999; Leifer et al., 2000; Washburn et al., 2001; Boles et al., 2001). This

area hosts one of the most prolific hydrocarbon seep fields in the world, where extensive, dense

bubbling plumes emit from faults and fractures along the axes of anticlinal hydrocarbon traps.

Based on sonar data, Hornafius et al. (1999) estimated that the total emission rate of

hydrocarbons into the water column through ebullition was 1.7 ± 0.3 x 105

 m3 d-1 (18 km2 area).

Leifer et al. (2000) measured the bubble gas partial pressures, dissolved gas and oil, and fluid

motions within the rising bubble streams of shallow (<70 m) seeps. They found that near-surface

aqueous methane concentrations were >108

 times greater than atmospheric equilibrium values.

Also, they demonstrated how large seeps can modify the local environment by generating

upwelling flows, turbulence, and saturating the water contained within the bubble plume with

CH4. Therefore, the fraction of gas that is released to the atmosphere versus dissolved in the

water column depends both on the seep itself and the above bubble stream environment (Leifer

et al., 2000). Boles et al. (2001) monitored gas flow rates from a large seep (67 m depth) where

gas is captured by two steel tents and piped to shore to be processed. They observed that tidal

forcing caused gas flow rate to vary by 40% around the average flow rate and high and low tides

were correlated with reduced and increased flow rates, respectively. Boles et al. (2001)

proposed a pore activation model to explain these observations, where gas bubbles are released

from small pores at low pressures but at high pressures, ebullition is inhibited.

4. CO2 LEAKAGE AND BUBBLE FLOW

4.1. Bubble Formation Fundamentals

In order for a bubble to form and persist in water, the pressure within the bubble must be greater

than the ambient hydrostatic pressure plus the surface tension of water that must be overcome to

form the bubble. Mathematically, the pressure inside the bubble (P) is equal to the sum of the

partial pressures of the volatile species which must be in excess of the sum of the ambient

hydrostatic pressure at depth z (Pz) and the surface tension pressure (Pst):

i z st

i

P = ∑CiH > P + P (4.1)

where Hi are the Henry’s law coefficients (Pa or atm) for each species i, Ci are the aqueous

concentrations of the volatile species (mole fractions), and the fluid pressure at depth z is given

by

Pz = PA + ρ w gz (4.2)

where ρw is water density, g is gravity, and PA is atmospheric pressure. A schematic of the

radially outward surface forces and the tangential surface tension forces on a neutrally buoyant
CO2 Seepage into Surface Water

DRAFT 18 Rev. 1.2

single bubble is shown in Fig. 4.1. The Pst in Eq. 4.1 is related to the bubble radius (r) and the

surface tension (σ) of the water according to the Young-Laplace equation (e.g., Pellicer et al.,

2000) as

st P Pz r

P = = − 2σ (4.3).

Surface tension for water is approximately 72 dynes cm-1 (0.072 N m-1), which means that Pst is

negligible relative to Pz for bubbles with radius larger than approximately 150 μm (0.15 mm) for

which 2σ/r ~ 0.1 bar (e.g., Leifer and Patro, 2002).

The surface tension pressure (Pst) implies that the gas pressure in the bubble must be higher than

the gas saturation pressure in the ambient aqueous phase. The bubble gas-phase composition is

determined by the relative magnitude of the gas partial pressures and thus reflects the volatility

(the inverse of the component’s aqueous-phase solubility) of each species and the water

composition. This relationship of ebullition to solubility is a key factor in CO2 leakage because

waters with varying solubility due to different salinity and temperature may be encountered

during the long rise upward of CO2 bubbles. The solubility and buoyancy of CO2 over a

potential migration path will be discussed below in Section 4.7.

Once a bubble is formed and rises upwards, it can exchange mass with the surrounding water.

The bubble molar flux to surrounding water, Fi, is expressed as:

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = = −

i

Bi

Bi i

i

i H

P

q r C

dt

dN F 2 4π , (4.4)

(e.g., Leifer and Patro, 2002) where Ni is the molar content of gas species i in the bubble, qBi is

the individual bubble gas transfer rate, and PBi is the bubble gas partial pressure.

Equation (4.4) is applied to each gas species in the bubble individually. The gas flux is driven

by the difference Ci - PBi/Hi (e.g., Leifer et al., 2000). Therefore, gas outflows from the bubble

when Ci < PBi/Hi and inflows when Ci > PBi/Hi. In the case of a bubble composed predominantly

of CO2, it will dissolve as CO2 outflows and grow as dissolved air (primarily N2 and O2) and/or

CO2 inflow. If for example, CCO2 is elevated due to bubble dissolution, the gas outflow from the

bubble is decreased. If concentrations of dissolved O2 and N2 in the water column are low,

inflow will be reduced and dissolution will occur. With rise through the water column, CO2 may

dissolve and the bubble may shrink, increasing PST as the bubble radius decreases (see Eq. 4.3).

Also, bubble expansion will occur due to decreasing Pz and associated gas expansivity. Upon

rising and increasing in size, the larger bubble will be able to transfer gas more efficiently

because of the increased surface area. The total gas entering the water column from rising

bubbles depends on the cumulative integrated bubble molar flux over the bubble’s lifetime.

So far we have implicitly assumed that the bubble in question is a gas bubble. However, for

applications involving CO2 rising from the deep subsurface during potential leakage from

geologic carbon sequestration sites, the CO2 can be in either a supercritical or liquid phase as

well as a gas phase, depending on pressure and temperature (see Section 4.5, below). Much of

the above fundamentals apply also for these cases in which the bubble contains supercritical or

liquid phase CO2, in which case we would refer to an equilibrium between species that paritition

between the two liquid phases, aqueous and CO2.
CO2 Seepage into Surface Water

DRAFT 19 Rev. 1.2

4.2. Steady-State Bubble Rise in Surface Water

Assuming that the bubble persists throughout its rise through the surface-water body, the bubble

lifetime can be derived from the water-body depth divided by the bubble rise velocity. The

velocity of bubble rise is often given by Stoke’s law:

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ − =

w

w g v d g

μ

ρ ρ

18

2 (4.5)

where d is bubble diameter, ρw and ρg are water and gas density, respectively, and μw is water

viscosity. By this well-known equation, the bubble velocity is directly related to the square of

bubble diameter. Therefore, as Pz decreases, d increases and bubbles accelerate. However, Eq.

4.5 is only valid at very small Reynolds number (Re = ρw v d/μw < ~1) corresponding to either

very small bubble size, small buoyancy contrast, or a very viscous liquid. For CO2 bubbles in

surface water, Re is of order 1 when bubble diameter is of order 10-4 m (0.1 mm). In summary,

Eq. 4.5 is a poor predictor of gas bubble rise velocity in surface water except for very small

bubbles.

A wealth of empirical data from experiments and field measurements has provided a sound basis

for estimating bubble rise velocity. We present in Fig. 4.2 a figure from Leifer and Patro (2002)

showing data from experiments of bubble rise velocity as a function of bubble radius, with

contours of Reynolds number (dashed lines). As shown, Eq. 4.5 applies only in the lowermost

left-hand corner at Re < 1, and furthermore the rate of bubble rise in water has a maximum of

approximately 30 cm s-1 which is reached when the bubble diameter is approximately 1.5 mm (r

= 0.75 mm). Bubbles are known to begin oscillating at radii of approximately 0.7 mm and Re of

400, leading to a decrease in rise velocity as bubble radius increases. While these results are

valid strictly for air bubbles, very similar results would be obtained for pure CO2 gas bubbles

since the driving force is given by the difference in density between the gas phase and water, a

negligible difference when comparing the buoyancy of air (ρ = 1.2 kg m-3) to gaseous CO2 (ρ =

1.8 kg m-3) for bubbles in water (ρ = 1000 kg m-3) at near-surface conditions.

4.3. Bubble and Channel Flow

Within a water-saturated porous medium such as the sediments or fractured rock below a

surface-water body, upward buoyancy forces will act on CO2 bubbles. However, within porous

media, bubble flow is restricted by the presence of solid matrix grains and the tortuous path

around them. In addition, capillary forces can arise from (1) contact of the bubble with the solid

grains, and (2) the deformation of the bubble and corresponding change in bubble radius (r) (see

Eq. 4.3) that occurs when the bubble squeezes through narrow pore throats. Pore throats can

also lead to straining and trapping processes that block bubble flow (e.g., Wan et al., 2003).

Bubble rise in porous media is therefore significantly more complicated than bubble rise in

standing surface water.

The additional complexity of capillary forces due to the solid matrix grains can be quantified by

reference to the Bond number (Bo), the ratio of buoyancy forces driving upward flow to surface

tension forces that tend to retard bubble flow. The Bond number can be defined as
CO2 Seepage into Surface Water

DRAFT 20 Rev. 1.2

( )

σ

ρ ρ

2

Bo w g p − gr = (4.6)

(e.g., Brooks et al., 1999) where rp is a characteristic length scale of the pore space. When Bo >

1, buoyancy forces dominate, and when Bo < 1, capillary forces dominate. Taking values of ρw,

ρg, g, and σ of 1000 kg m-3, 1.8 kg m-3, 9.81 m s-2, and 7.2 x 10-2 N m-1, respectively, we find

that capillary forces will dominate for pore sizes less than approximately 3 mm. Capillarity will

therefore be the important force in medium and fine-grained porous media. A modified Bond

number can be defined to include pore body and pore throat length scales to account for the fact

that buoyancy is more important in pore bodies, while capillarity is more important in pore

throats (Brooks et al., 1999).

The Bond number can be used to classify whether gas flow in saturated porous media will occur

by bubble or by channel flow (Brooks et al., 1999). Bubble flow occurs when buoyancy forces

dominate and gravity drives gas bubbles upward without large capillarity effects. Such flow will

occur when the porous media are coarse, such as in gravels and coarse sands. In contrast, fine

porous media give rise to stronger capillary forces as gas is squeezed through small pore throats

leading to gas becoming trapped by capillarity. As trapped gases accumulate in the medium,

eventually they may form connected paths to the gas source area and pressure-driving forces can

be propagated from the source to the gas-liquid front. At this point, gravity is aided by the

pressure-gradient driving force and capillary forces can be overcome leading to water

displacement as gas advances upward. If snap-off occurs isolating the leading gas-phase region

from the gas source, capillarity can again stop the rise of the gas bubble. In this way, the rise of

gas in medium and fine-grained porous media typically occurs only by channel flows in which

elongated regions of gas flow upward in a gas channel (see Fig. 2.3). This has been observed in

experimental studies of upward air flows in the field of air sparging (e.g., Ji et al., 1993). (Air

sparging is a remediation technique in which air is injected into the ground so that it will bubble

upwards capturing volatile contaminants from water as the air migrates upward.) Beyond the

theoretical considerations of the Bond number, formation heterogeneity inherent in the

subsurface can also control channel-formation.

4.4. Steady-State Bubble Rise in Porous Media

One recent analysis relevant to this study is that of Corapcioglu et al. (2004) who considered the

problem of bubble rise velocity in porous media. Their study was a follow-on to an experimental

study (Roosevelt and Corapcioglu, 1993) which was motivated by the need to understand air

movement in air sparging. Along with a theoretical analysis of bubble rise in porous media,

Corapcioglu et al. (2004) present an excellent review of prior studies of porous media bubble

transport to which we refer interested readers. Here we present the development of Corapcioglu

et al. (2004) and use it to predict CO2 bubble rise velocity in porous media for both gaseous and

liquid CO2. We note that this analysis is valid only for single-bubble rise in coarse sediments,

i.e., Bo > 1.

The analysis begins by considering the forces acting on a single bubble in a porous medium as

shown in Fig. 4.3. For a bubble rising at steady-state, the upward buoyancy forces are exactly

balanced by the surface tension and drag forces that tend to retard motion. These forces can be

written as the buoyancy force, given by
CO2 Seepage into Surface Water

DRAFT 21 Rev. 1.2

( ) 3

3

4 Fb = ρ f − ρ g g π Rb (4.7),

the surface tension force given by

Fst = 2π R'σ sinθ (4.8),

where R’ is an equivalent pore throat radius, and the drag force is given by

( ) ( ) 3

3

2

2 3

2

3

150 1 1.75 1 4

b

p

g b

p

b b

d R

d n

u n

d n

u n F A π μ ρ

⎥

⎥

⎦

⎤

⎢

⎢

⎣

⎡ − + − = (4.9)

(variables are defined in Nomenclature). The first term in brackets in Eq. 4.9 is the Kozeny

term, accounting for viscous drag in laminar flow, while the second term is the Burke-Plummer

term, accounting for turbulent losses. Summing these three forces and allowing for acceleration

of the bubble, we have the balance relation

⎟

⎠

⎞ ⎜

⎝

⎛

∂

∂

+

∂

∂ − − = x

u

u

t

u F F F A R b

b

b

b d st d g b

3

3

4

ρ π (4.10)

where the Ad term accounts for entrained liquid ahead of the bubble and is defined as

g

f Ad CM

ρ

ρ = 1 (4.11). +

Substituting the individual force equations and grouping terms by the powers of bubble rise

velocity (ub), we obtain

( )

x

u

u

t

u C u C u C b

b

b

b b ∂

∂

+

∂

∂ − + 2 + 3 = 2

1 (4.12)

where

( )

dp n Ad

n A C1 3

1.75 1− = (4.13)

( )

p g d

b

d n A

n A C

ρ

μ

2 3

2

2

150 1− = (4.14)

C3 = 1

ρg Ad

3

2

R'σ sinθ

Rb

3 − ( ) ρ f − ρg g

⎡

⎣ ⎢ 

⎤ 

⎦

⎥ (4.15).

The rise velocity (ub) can be calculated using the coefficients of Eqs. 4.13-4.15 in the quadratic

equation 4.12 for which we assume steady state and zero inertia, i.e., right-hand side of Eq. 4.12

is set to zero. The values of the various terms in the above equations are given in Table 4.1,

where we have included some additional sediment particle sizes and porosities to extend the

method toward finer grain sizes than the 4 mm glass beads used in Roosevelt and Corapcioglu

(1993). Many assumptions are made in the analysis, such as constant contact angle, bubble

radius, and fit parameter for which we refer interested readers to Corapcioglu et al. (2004) for

further information.
CO2 Seepage into Surface Water

DRAFT 22 Rev. 1.2

We have calculated bubble rise velocities for the 4 mm glass beads of Corapcioglu et al. (2004)

and two slightly finer grain sizes (dp = 2 mm and 1 mm) (see Table 4.2). We note that the

approach breaks down for medium and fine grain sizes as evidenced by the negative rise velocity

produced as a solution to the quadratic equation (Eq. 4.12). This is to be expected since this

analysis is for bubble flow rather than channel flow which will occur for medium and fine grain

sizes (see Section 4.2). Results are shown in Fig. 4.4 where we have plotted the logarithm of the

calculated bubble-rise velocities for three coarse grain sizes (dp = 4 mm, 2 mm, and 1 mm) for

air and CO2 gas bubbles, along with the calculated rise velocity for a CO2 liquid bubble. The

maximum velocity plotted is approximately 18 cm s-1, which is considered by Corapcioglu et al.

(2004) to be the maximum possible porous media bubble rise velocity, and is approximately onehalf of the maximum surface-water bubble rise velocity (cf. Fig. 4.2). Note from Fig. 4.4 that for

the 4 mm grain size, the CO2 bubble is predicted to rise slightly slower than the air bubble, but

that CO2 bubbles are predicted to rise slightly faster than air bubbles for the less-coarse media.

This cross-over effect is due to the greater buoyancy of air relative to CO2 and its importance in

coarse media, and the greater importance of the lower viscosity of CO2 relative to air in finer

media. Note finally that CO2 liquid bubbles rise more slowly due to their greater density and

viscosity than CO2 gas bubbles. The main conclusion of this analysis is that the density contrast

between air and CO2 is negligible in the analysis of bubble rise velocity because buoyancy is

generated by the density difference between the gas and water, and this difference is nearly the

same because water density is nearly 1000 times larger than the gas density. However, liquid

CO2 density is much larger and liquid CO2 bubbles are correspondingly much less buoyant in

water. Despite the numerous simplifying assumptions in this analysis, the calculations reveal the

importance of grain size, and density and viscosity contrast in predicting bubble rise velocity in

coarse porous media. As for medium and fine porous media, gas flow will be by channel flow

which can be analyzed by a wide range of multiphase reservoir simulation methods beyond the

scope of the present project.
CO2 Seepage into Surface Water

DRAFT 23 Rev. 1.2

Table 4.1. Fluid properties for the analysis of bubble flow in porous media.

Property Symbol Value Units

Surface tension σ 7.2 x 10-2 N m-1

Contact angle q 30 degrees

Viscosity of water μw 1 x 10-3 kg m-1 s-1

Density of water ρw 1000. kg m-3

Viscosity of air μg 1.80 x 10-5 kg m-1 s-1

Density of air ρg 1.2 kg m-3

Viscosity of CO2

Gas (1 bar, 20 oC)

Liquid (61 bars, 22 o

C)

μg

μl

1.47 x 10-5

6.33 x 10-5

kg m-1 s-1

kg m-1 s-1

Density of CO2

Gas (1 bar, 20 oC)

Liquid (61 bars, 22 o

C)

ρg

ρg

1.8

755.2

kg m-3

kg m-3

Gravitational accel. g 9.81 m s-2

Additional mass Ad 1 -

Fit parameter A 26.8 -
CO2 Seepage into Surface Water

DRAFT 24 Rev. 1.2

Table 4.2. Porous media properties and results for bubble flow in porous media.

Property Symbol Units 4 mm glass

beads1

Gravelly

sand2

Coarse

sand2

Porosity n - 0.3954 0.3 0.35

Particle size dp m 4 x 10-3 2 x 10-3 1 x 10-3

Bubble radius Rb m 4 x 10-3 2 x 10-3 1 x 10-3

Equivalent

pore throat

radius

R’ m 3.09 x 10-4 1.55 x 10-4 7.73 x 10-5

Rise velocity

Air

CO2 Gas

CO2 Liquid

ub

ub

ub

m s-1

m s-1

m s-1

1.83 x 10-1

1.68 x 10-1

4.43 x 10-3

2.52 x 10-2

2.91 x 10-2

8.60 x 10-4

7.73 x 10-3

9.40 x 10-3

N/A

BurkePlummer

Permeability

k m2 1.80 x 10-8 1.47 x 10-9 6.76 x 10-10

2

 de Marsily (1986)

1

 Corapcioglu et al. (2004)

4.5. Transport by Bubble Flow and Diffusion in Surface Water

To examine ebullition and diffusion rate, we consider a surface-water system consisting of air

(N2 and O2), CO2, and CH4 similar to that described by Morel and Herring (1993). If seepage of

CO2 and/or CH4 occurs across the sediment surface at depth z into the overlying surface water

body at a constant flux, m (mol cm-2 s-1), we can estimate the rates of ebullition and diffusion of

these species. The following assumptions will be made: (1) bubble formation maintains the sum

of the partial pressures (CO2, CH4, air, H2O) at Pz, i.e., we neglect Pst, (2) bubbles rise so fast

through the water column to the surface that no dissolution occurs, (3) transport of all solutes in

the water column is described by a dispersion coefficient (D = 10-3 cm2

 s-1), and (4) chemical

reactions (e.g., bicarbonate formation from CO2, oxidation of CH4) are ignored.

For each species, the rate of ebullition Ei (mol cm-2 s-1) is proportional to its partial pressure at

the sediment surface:
CO2 Seepage into Surface Water

DRAFT 25 Rev. 1.2

E

P

P

E

z

i

i = (4.17)

where E is the total rate of ebullition of all species together. A steady-state mass balance

equation is written for each species at the sediment surface where the sum of its transport by

diffusion and ebullition is equal to its rate of formation at depth:

( ) [ ][ ] CO CO EK [ ] CO P m

z

D

b − s + CO b z = − −1

2

1

2 2 2 (4.18)

( ) [ ][ ] CH CH EK [ ] CH P m

z

D

b − s + CH b z = − −1

4

1

4 4 4 (4.19)

( ) [][] [ ] − + = 0

air z

b

b s K P

E air air air

z

D (4.20)

where the subscripts b and s refer to the bottom and surface concentrations (mol cm-3),

respectively, and Ki is the Henry’s law constant for each gas species (mol cm-3 atm-1), and the

bottom air flux is assumed to be zero. The diffusive flux is assumed to be driven by the

concentration gradient across the entire depth of the surface-water body.

The aqueous concentrations of species at the surface are calculated to be in equilibrium with the

atmosphere at 10o

C, where PCO2atm, Pairatm, and PCH4atm = 3.12 x 10-4, 1.97 x 10-6, and 9.87 x 10-1

atm, respectively (see Table 4.3 for Ki values):

[CO2]s =PCO2atm KCO2 (4.21)

[CH4]s = PCH4atm KCH4 (4.22)

[air]s =Pairatm Kair (4.23)

Unknowns in mass balance equations are now bottom concentrations and E. The pressure

condition at the sediment surface is:

Pair + PCH4 + PCO2 + PH2O = Pz (4.24)

We can neglect PH2O in Eq. 4.24 relative to the other volatile components and substitute Henry’s

law expressions to obtain

[ ] [ ] [ ] z

air

b

CH

b

CO

b P

K

air

K

CH

K

CO

+ + =

4

4

2

2 (4.25)

where Ki values are for the Pz considered (Table 4.3). With the approximations [CO2]s <<

[CO2]b and [CH4]s << [CH4]b, bottom concentrations from Eqs. 4.18-4.20 are substituted into Eq.

4.25 to yield:

[ ] z

air z

s

CO z CH z

P

K D z E P

D z air

K D z E P

m

K D z E P

m = +

+

+

+

+ / /

( / )

/ / / / 2 4

 (4.26)

By neglecting the first term in Eq. 4.26 and replacing KCH4 and Kair with an average K value, an

approximate solution for E can be obtained:
CO2 Seepage into Surface Water

DRAFT 26 Rev. 1.2

[ ]

z

P KD air

z

D E m z ⎟ s − ⎠

⎞ ⎜

⎝

⎛ = + (4.27)

Substitution of Eq. 4.27 into Eqs. 4.18-4.20 gives the bottom concentrations of species:

[ ] 1 1

2

2 / − − +

≅

CO z

b D z EK P

m CO (4.28)

[ ] 1 1

4

4 / − − +

≅

CH z

b D z EK P

m CH (4.29)

[ ] ( )[ ]

1 1 /

/

− − +

≅

air z

s

b D z EK P

D z air air (4.30)

The diffusive and ebullition fluxes, FD and FE

, respectively, of CO2 and CH4 can then be

calculated:

( ) [ ][ ] b s

D

CO CO CO

z

D F 2 = 2 − 2 (4.31)

( ) [ ][ ] b s

D

CH CH CH

z

D F 4 = 4 − 4 (4.32)

[ ] 1

2

1

2 2

− − = CO b z

E FCO EK CO P (4.33)

[ ] 1 1

4 4 4 − − = CH b z

E FCH EK CH P (4.34)

We calculated FD and FE

 for (1) CO2 and CH4 where seepage of CO2 and CH4 occurs into a

surface water body and mCO2 = mCH4, (2) CO2 where only seepage of CO2 occurs, and (3) CH4

where only seepage of CH4 occurs. In each of these cases (Cases 1-3), we consider a water body

with z = 50, 1000, and 10000 cm, low, medium, and high mCO2 and/or mCH4 values (see Table 4.4

for mCO2 and mCH4 values), and calculate the percent ebullition of total flux for the species that

seep into the water body. The low, medium, and high fluxes used here correspond

approximately to our low, medium, and high seepage fluxes calculated in our prior vadose-zonerelated work (Oldenburg and Unger, 2003; 2004). For comparison, natural fluxes of CO2 from

plant and soil biological processes are approximately 10-9 mol cm-2 s-1 (10 μmol m-2 s-1) efflux to

3 x 10-9 mol cm-2 s-1 (30 μmol m-2 s-1) uptake (e.g., Baldocchi and Wilson, 2001). We present

results for both CO2 and CH4 to demonstrate the contrast in their ebullition and diffusion flux

rates that arises from their different solubilities in water.

Our results (Table 4.4) show that diffusion is important for transport of CO2 to the atmosphere in

water bodies up to 1000 cm deep and for mCO2 up to the medium values considered. At greater

mCO2 or z, CO2 is transported to the atmosphere almost entirely by ebullition. For CH4, diffusion

is only an important transport mechanism for shallow (50 cm) water bodies and low mCH4,

accounting for about half the total CH4 flux. For cases where CH4 seeps into deeper water

bodies of (z = 1000 and 10000 cm) or mCH4 is elevated, ebullition accounts almost entirely for

the CH4 flux to the atmosphere. These differences between ebullition and diffusion fluxes for

CO2 and CH4 are due to the greater solubility of CO2 in water, relative to CH4. In short,

ebullition and bubble transport dominate the transport of sparingly soluble species.
CO2 Seepage into Surface Water

DRAFT 27 Rev. 1.2

Table 4.3. Henry’s law coefficients (Ki) for different Pz values (Spycher, unpublished code).

z

(m)

Pz

(atm)

KCO2

(mol atm-1 cm-3)

KCH4

(mol atm-1 cm-3)

Kair

(mol atm-1 cm-3)

Surface-50 cm 1 4.90 x 10-5 1.98 x 10-6 1.29 x 10-6

1000 2 4.87 x 10-5 1.98 x 10-6 1.29 x 10-6

10000 11 4.63 x 10-5 1.92 x 10-6 1.26 x 10-6

K values are for 10oC. Kair is the average of KN2 and KO2.

Table 4.4. Percentage of flux by ebullition relative to diffusion for CO2 and CH4 at various

depths and flux proportions.

Case z

(cm)

m

CO2

(mol cm-2 s-1)

m

CH4

(mol cm-2 s-1)

% FCO2

E % F CH4

E

1 50 4.59 x 10-11 4.59 x 10-11 4 49

1 1000 4.59 x 10-11 4.59 x 10-11 31 92

1 10000 4.59 x 10-11 4.59 x 10-11 45 95

1 50 4.59 x 10-10 4.59 x 10-10 32 92

1 1000 4.59 x 10-10 4.59 x 10-10 82 99

1 10000 4.59 x 10-10 4.59 x 10-10 89 100

1 50 4.59 x 10-9 4.59 x 10-9 82 99

1 1000 4.59 x 10-9 4.59 x 10-9 98 100

1 10000 4.59 x 10-9 4.59 x 10-9 99 100

2 50 9.18 x 10-11 0 8 NA

2 1000 9.18 x 10-11 0 49 NA

2 10000 9.18 x 10-11 0 63 NA

2 50 9.18 x 10-10 0 31 NA

2 1000 9.18 x 10-10 0 90 NA

2 10000 9.18 x 10-10 0 94 NA

2 50 9.18 x 10-9 0 90 NA

2 1000 9.18 x 10-9 0 99 NA

2 10000 9.18 x 10-9 0 99 NA

3 50 0 9.18 x 10-11 NA 68

3 1000 0 9.18 x 10-11 NA 96

3 10000 0 9.18 x 10-11 NA 98

3 50 0 9.18 x 10-10 NA 96

3 1000 0 9.18 x 10-10 NA 100

3 10000 0 9.18 x 10-10 NA 100

3 50 0 9.18 x 10-9 NA 100

3 1000 0 9.18 x 10-9 NA 100

3 10000 0 9.18 x 10-9 NA 100
CO2 Seepage into Surface Water

DRAFT 28 Rev. 1.2

4.6. Transport of Dissolved CO2 in Surface Water

Transport of the dissolved fraction of CO2 in surface water will occur by diffusive and dispersive

processes in the aqueous phase. Flow occurs in typical surface waters such as rivers, lakes,

estuaries, and shallow seas by combinations of gravity, wind, and tidal forcings (e.g., Fischer et

al., 1979). Such motions are often turbulent involving a wide range of chaotic flow velocities

over a range of length scales which lead to effective dispersion and mixing of dissolved species.

Dispersion and mixing will periodically expose surface water to the atmosphere where it will

potentially equilibrate with atmospheric CO2 creating an effective outgassing that is equal to the

leakage and seepage flux at the bottom at steady state. In lakes, mixing may be somewhat less

than in rivers or coastal environments and vertical mixing may occur only once or twice a year,

or in some special cases not at all (e.g., deep equatorial lakes, or lakes with permanent ice cover)

(Goldman and Horne, 1983). In addition, the density of CO2-saturated water is approximately

1% greater than that of pure water (Ennis-King and Paterson, 2003), creating the possibility of

dissolved CO2 producing a stable density stratification. However, in typical surface waters other

than deep marine environments and certain kinds of lakes, flow forcings such as gravity, wind,

and tides will dominate over density stratification and cause mixing on time scales much smaller

than the objective sequestration time scale (hundreds to thousands of years). Thus we assert that

rivers, lakes, estuaries, and continental shelf ocean water will not be effective at attenuating

leakage and seepage fluxes of CO2 occurring as a dissolved component. Furthermore, as we

have shown in Section 4.5, ebullition will generally occur for the flux magnitudes of interest thus

subordinating the importance of diffusion and dispersion to the overall transport of CO2 leakage

and seepage in surface water.

4.7. Effects of Pressure, Temperature, and Salinity on Ebullition

As shown by the differences in ebullition flux between CO2 and CH4 calculated in Section 4.5,

the solubility of the volatile species is a fundamental control on ebullition. The solubility of CO2

is a strong function of salinity and temperature, both of which may vary within the subsurface

and surface waters through which leaking CO2 can migrate. We have calculated CO2 solubility

for various H2O-NaCl mixtures using the methods of Spycher and Pruess (2004) and Spycher et

al. (2003). We consider the case of a 200-m-deep surface water body at 10 o

C and underlying

porous media with a geothermal gradient equal to 30 o

C km-1 and hydrostatic pressure assuming

ρH2O = 1000 kg m-3. The various solubility profiles are plotted as a function of depth in Fig. 4.6.

The curves on the left-hand side of Fig. 4.6 represent hypersaline brines such as might be found

in a very deep brine formation, and a typical oilfield brine, approximately twice the salinity of

seawater. These two curves are plotted only up to the sediment-water interface because they are

normally found in the subsurface. The final two curves are those of seawater and freshwater and

continue from subsurface through the surface water. The CO2 density profile is calculated from

the online NIST Webbook (Lemmon et al., 2004) for pure CO2 at the given pressures and

temperatures.

The first point to note in Fig. 4.6 is that CO2 transitions from supercritical to liquid to gas as it

rises upwards in this system. This is in stark contrast to the simple change from supercritical to

gas (see Fig. 2.4) that occurs in the absence of surface water (Oldenburg and Unger, 2003). The
CO2 Seepage into Surface Water

DRAFT 29 Rev. 1.2

implication of these phase transitions is that buoyancy forces on CO2 bubbles are nearly constant

with a slight decrease as the bubble rises, for example from –1000 m to –380 m in Fig. 4.6.

Then upon rising through the liquid-gas transition, the enormous density change in CO2 will lead

to approximately a factor of 3.7 change in volume of the bubble, assuming an isothermal

transition, with corresponding increase in upward buoyancy force.

The second important point illustrated in Fig. 4.6 is the variation in CO2 solubility upward from

depth. At intermediate and low salinity, CO2 solubility rises slightly along a bubble migration

path upward from depth until the liquid-gas transition point (depth equal to –380 m). From this

point upward, CO2 solubility declines rapidly as the pressure falls. The implication of this

pattern for bubble transport is that CO2 ebullition is favored as dissolved CO2 is transported

upwards from depths shallower than approximately -380 m in this system.

Finally, Fig. 4.6 shows dramatically the variation in solubility as a function of salinity of water.

This has important implications for situations where the migration pathway of CO2 leakage and

seepage can traverse formations and surface water with contrasting salinity. For example,

consider first the case of a briny groundwater system at depth with overlying fresher aquifers

below a freshwater lake. In this case, a rising CO2 bubble would encounter water with

progressively higher and higher CO2 solubility, making it likely that CO2 bubbles would

disappear as the CO2 dissolved into the aqueous phase. In contrast, there could be a system with

fresh-water aquifers at depth underlying a shallow continental shelf marine environment. In this

case, ebullition may become more important as salinity increases and pressure decreases as the

CO2 flux moves upwards. Combinations of the above transitions are of course possible, and Fig.

4.6 provides a general guide as to the trend toward greater dissolution or greater ebullition in

water as a function of depth and salinity.

5. SUMMARY AND DISCUSSION

5.1. Summary

Our brief investigation and analysis of CO2 leakage and seepage into surface water has resulted

in the following main conclusions:

1. Numerous investigations have been conducted to measure natural CO2 and CH4 fluxes and

concentrations in surface-water environments and to estimate the relative contributions of

ebullition and dispersion to the total fluxes of these species to the atmosphere. These

previous studies provide direct evidence of how CO2 leakage and seepage fluxes of similar

magnitude will behave, and they indicate that local conditions strongly control transport

processes. Natural CO2 and CH4 fluxes and local concentrations are significant and can lead

to ebullition making it challenging to discern leakage and seepage from natural emissions.

2. Prior studies of volcanic lakes that have undergone lethal CO2 outgassing indicate that deep

and stagnant conditions are conducive to the formation of waters that are supersaturated with

respect to CO2. Seasonal overturn, or other regular mixing processes such as natural

convection by hydrothermal heating, neither of which occur at Lakes Nyos or Monoun may

prevent extreme buildup of CO2 and associated potentially lethal outgassing events.
CO2 Seepage into Surface Water

DRAFT 30 Rev. 1.2

3. Previous work in the areas of bubble physics and hydrostatics indicate that in order for a

bubble to form, the sum of the partial pressures of the volatile components must exceed the

local hydrostatic pressure and surface tension. Once a bubble forms and rises upwards, mass

transfer occurs between the bubble and liquid.

4. Although Stokes Law is not formally applicable to gas-bubble rise in surface water for

bubble sizes larger than approximately 0.1 mm, empirical data exist to predict bubble rise

velocity over a wide range of bubble sizes. Bubble-rise velocity reaches a maximum of

approximately 30 cm s-1 for bubbles approximately 0.7 mm in radius and declines for larger

bubbles due to turbulence and related bubble oscillations.

5. In saturated porous media, e.g., below surface water, small CO2 fluxes can be sustained by

bubble flow especially in coarse and highly permeable porous media. For larger CO2 fluxes,

or finer porous media, transport is by channel flow.

6. Bubble-rise velocity in porous media has a maximum of approximately 18 cm s-1 in very

coarse gravels. Bubble-rise velocity is much smaller in typical sediments, which can only

sustain a small flux of CO2 before transitioning to channel flow. CO2 rise velocity in the

channel-flow regime is governed by multiphase flow processes that can be studied using

reservoir engineering simulation approaches.

7. Bubble-rise velocity for a liquid CO2 bubble is slower than for a CO2 gas bubble due to the

much smaller density contrast between liquid CO2 and water than between gaseous CO2 and

water.

8. For the range of seepage fluxes and surface-water depths considered in this study, CO2

transport through the surface water will tend to be by ebullition/bubble flux for relatively

high seepage fluxes and/or deep water bodies and by diffusion/dispersion for relatively low

seepage fluxes and/or shallow water bodies. Species such as CH4 with lower solubility in

water are more likely to be transported by bubble flux.

9. As leaking CO2 rises upwards, liquid-stable CO2 phase conditions may be encountered,

especially if there is overlying surface water. Therefore, CO2 rising from depth will

transition from supercritical to liquid to gas with upward rise. The transition from

supercritical to liquid is not associated with a significant change in physical properties, (e.g.,

density, viscosity, solubility), while the transition from liquid to gas has large changes in

properties and these changes favor bubble flow.

10. The solubility of CO2 in water depends strongly on the P, T, and salinity conditions of water

and the phase properties of the CO2. Leaking CO2 rising from depth through saturated

porous media of varying salinity may tend to dissolve and/or undergo ebullition depending

on the conditions. In general, CO2 solubility decreases with depth at shallow depths, creating

greater potential for ebullition as CO2 rises upward into the near-surface environment.

5.2. Discussion

The results of our study allow us to make the following comments on the key research questions

posed.
CO2 Seepage into Surface Water

DRAFT 31 Rev. 1.2

(1) What are the physical processes relevant to the migration through sediments and

overlying surface water of CO2 either as bubbles or as a dissolved component in water?

Bubbles are subject to buoyancy and surface tension forces in porous media, with surface tension

dominating for fine porous media. CO2 transport is likely to be by channel flow in the fine

sediments below a surface-water body. These channels can be produced by bubble trapping and

coalescence processes that arise in medium- and fine-grained porous media. Channels can also

be created by the heterogeneity inherent in subsurface formations. Upon approaching the

surface-water body as a second phase (gas or liquid), CO2 bubbles will emanate from the

sediment and rapidly rise upwards. Under this scenario, there is no ebullition process since the

CO2 already exists as a second phase in the porous media. Ebullition (i.e., bubble formation) at

the interface of sediment and surface water and/or dispersive transport of CO2 seepage from the

sediment interface will only occur for seepage fluxes on the order of the background flux or

smaller. For larger fluxes, channel flow and bubble flow are expected in the porous media and in

the surface water, respectively. Dissolved CO2 is transported by motions of the aqueous phase

typically driven by gravity, wind, and tidal forcings.

(2) Does surface water attenuate or enhance CO2 seepage flux?

Rising CO2 bubbles are subject to mass transfer with surrounding waters, but the travel times are

relatively short because rise velocities are high. In general, CO2 bubbles, once formed, are

expected to rise from the bottom to the top of typical surface-water bodies as solubility decreases

with decreasing pressure. As for dispersion of dissolved CO2, mixing times in surface waters are

short relative to geologic CO2 sequestration times, and dissolved CO2 added by leakage and

seepage is expected to exsolve rapidly from surface water as it mixes and equilibrates with

atmospheric CO2. Thus CO2 seepage flux is not expected to be significantly attenuated by

surface water.

(3) Under what conditions can CO2 concentrations build up at depth and lead to the

potential for catastrophic release?

Water becomes slightly denser when it contains dissolved CO2. Lakes with deep stagnant

regions subject to CO2 fluxes from below are prone to stratification with water at depth that is

supersaturated with CO2 and subject to rapid outgassing if there is a disturbance to the lake that

initiates overturn. Natural mixing processes such as seasonal overturn and wind-driven

mixing—largely absent from the well known Lakes Nyos and Monoun—and man-made

degassing schemes can be effective at preventing CO2 buildup in deep stagnant lakes.

6. RECOMMENDATIONS FOR FUTURE RESEARCH

6.1. CO2 Flow and Transport in Water

There are significant research needs in the area of leakage and seepage of CO2 in saturated

porous media and surface waters. We offer the following recommendations.

1. In our experience, there are limits to the amount of understanding and knowledge that theory

and modeling can deliver. Actual field experiments invariably result in huge leaps of
CO2 Seepage into Surface Water

DRAFT 32 Rev. 1.2

understanding. We suggest that a small-scale, controlled CO2 release experiment designed to

simulate the migration of CO2 upward from a deep source into the near-surface environment

be carried out. One variant of the field experiment should be a case in which CO2 bubbles up

through saturated sediments into a shallow surface-water body. In the experiment, the form

of CO2 transport through the sediments, its seepage into surface water, and its transport

upward through the surface water will be monitored visually along with various geochemical

and air sampling approaches. We envision an experimental test site could be established to

carry out these experiments in concert with the testing of various surface-monitoring

approaches.

2. We have a very limited understanding of how CO2 displaces water in porous media. This

issue is relevant from small bubbles migrating upward, to channel flow of gas displacing

water, to full multiphase flow of CO2. We propose that a comprehensive experimental

program be established to carry out bubble flow and relative permeability measurements of

gaseous, supercritical, and liquid CO2 flows in water-filled cores, artificial fractures, and

other flow systems to establish credible relations that can be incorporated in models currently

being used to simulate CO2 leakage and seepage. These measurements are essential to our

models, and we feel they have not been carried out to the extent needed.

3. Mass transfer from the bubble to the surrounding water is strongly controlled by the bubblewall (i.e., interface) properties. Gas-liquid interfaces are well known for their tendency to

attract impurities, biological material, and small particles. The extent to which mass transfer

is affected by these materials and whether it stabilizes or destabilizes CO2 bubbles rising in

surface waters of various types has not been investigated. We suggest that an experimental

program be developed to study CO2 bubble mass transfer in surface water. This work would

complement the analogous studies of CH4 bubbles studies (e.g., Leifer and Patro, 2002).

4. The phase transitions and associated enthalpy changes that CO2 undergoes during bubble rise

will lead to temperature changes. We suggest that a simulation study be undertaken to

investigate the degree of cooling that will be expected for the phase transitions (e.g., from

liquid CO2 in bubbles to gaseous CO2 in bubbles) and related effects.

5. As with ground-surface seepage, geostatistical methods should be investigated for

application to surface-water CO2 leakage and seepage monitoring to discern leakage from

natural background fluxes.

ACKNOWLEDGMENTS

We thank Nic Spycher and Karsten Pruess (LBNL) for helpful discussions and constructive

comments and reviews of this report. This work was supported in part by a Cooperative

Research and Development Agreement (CRADA) between BP Corporation North America, as

part of the CO2 Capture Project (CCP) of the Joint Industry Program (JIP), and the U.S.

Department of Energy through the National Energy Technologies Laboratory (NETL), and by

the Ernest Lawrence Berkeley National Laboratory, managed for the U.S. Department of Energy

under Contract No. DE-AC03-76SF00098.
CO2 Seepage into Surface Water

DRAFT 33 Rev. 1.2

NOMENCLATURE

A empirical fit parameter -

Ad additional mass -

dp porous media particle diameter m

D Diffusivity and dispersivity m2

 s-1

E total ebullition rate mol cm-2 s-1

FB buoyancy force N

FD diffusive flux mol cm-2 s-1

FE bubble (ebullition) flux mol cm-2 s-1

Fd drag force N

FE fraction ebullition flux -

g gravitational acceleration m s-2

H Henry’s Law coefficient Pa

K Henry’s Law coefficient mol cm-3 atm-1

k permeability m2

m mole flux mol cm-2 s-1

n porosity -

Ni molar content of gas species i mol

qBi bubble gas transfer rate of species i mol cm-2 s-1

P pressure Pa, atm

PCO2 partial pressure of CO2 Pa, atm

Pst Surface tension pressure N m-2

Pz hydrostatic pressure Pa, atm

r bubble radius m

rp characteristic length scale of pore m
CO2 Seepage into Surface Water

DRAFT 34 Rev. 1.2

R’ equivalent pore throat radius m

Rb bubble radius m

ub bubble velocity m s-1

VB bubble velocity in surface water m s-1

z vertical coordinate m

ρg gas-phase density kg m-3

ρf fluid density kg m-3

σ surface tension N m-1

θ contact angle degrees

[ ] concentration mol cm-3

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FIGURES

Figure 2.1. Schematic showing different combinations of coupled surface-water and porous

media gas transport and transition at the interface between porous media and surface

water.
CO2 Seepage into Surface Water

DRAFT 40 Rev. 1.2

Figure 2.2. Schematic of flow regimes in porous media: (a) bubble flow, and (b) channel flow.
CO2 Seepage into Surface Water

DRAFT 41 Rev. 1.2

Figure 2.3. Schematic of surface-water environments into which CO2 leakage and seepage from

geologic carbon sequestration sites may occur.
CO2 Seepage into Surface Water

DRAFT 42 Rev. 1.2

Figure 2.4. Phase diagram for CO2 showing typical P-T path with depth in the earth.
CO2 Seepage into Surface Water

DRAFT 43 Rev. 1.2

Figure 4.1. Half-section of a spherical bubble showing radiating forces due to pressure along

with the surface tension forces due to Pst along the equator. Pressure in the fluid is Pz,

while pressure in the bubble is P.
CO2 Seepage into Surface Water

DRAFT 44 Rev. 1.2

Figure 4.2. Bubble rise velocity as a function of bubble radius with background contours of

Reynolds number (from Leifer and Patro, 2002).
CO2 Seepage into Surface Water

DRAFT 45 Rev. 1.2

Figure 4.3. Force balance on single CO2 bubble showing buoyancy force (Fb), drag force (Fd),

and surface tension force (Fst) (after Corapcioglu et al., 2004).
CO2 Seepage into Surface Water

DRAFT 46 Rev. 1.2

-4.0

-3.0

-2.0

-1.0

0.0

0 0.001 0.002 0.003 0.004 0.005

Grain Size (m)

log u

b (log m/s)

Air

CO2 Gas 

CO2 Liquid 

Figure 4.4. Log10 ub for three different coarse porous media as a function of particle size.
CO2 Seepage into Surface Water

DRAFT 47 Rev. 1.2

Figure 4.5. Schematic of domain and variables for ebullition vs. dispersive mass transport

analysis. Ebullition is indicated by the bubbles, dispersion by the wiggly vector.
CO2 Seepage into Surface Water

DRAFT 48 Rev. 1.2

Figure 4.6. Solubility of CO2 (mole fraction) and fully ionized salt in water and various brines

as a function of depth within a surface water body (0-200 m) and the underlying

formation (-1000 – 0 m) with the different phase stability fields for CO2 indicated by

the shading. Right-hand figures show corresponding temperature, pressure, and

density of CO2 with depth.
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Deputy Project Manager for the Polk Power Station IGCC project, one of the two 

operating IGCC power plants in the U.S. 

Where are you currently employed? 

I am employed by URS in the Tampa, Florida office. 

What do you do in that job capacity? 

I am responsible for leading our IGCC and gasification business in the power 

industry, across the U.S. My job responsibilities include business development, as 

well as managing large projects in related technical areas. This includes a number 

of projects where we are providing environmental permitting, planning, feasibility 

and engineering services. I personally have been involved in the feasibility 

engineering, permitting or design of ten different coal gasification and IGCC 

projects. 

What is the purpose of your testimony? 

The purpose of my testimony is to show that Florida Power & Light Company’s 

(“FPL”) selection of ultra-supercritical pulverized coal (“USCPC”) technology for 

the proposed FPL Glades Power Park (“FGPP”) is a more prudent one than had 

they selected IGCC technology. This is based on an overall analysis and 

comparison of factors that include technology maturity, efficiency, reliability, 

power generating capability, operational history and environmental performance. 

What is IGCC technology? 

IGCC is a developing technology for generating electricity using coal or other 

similar feedstocks. Unlike conventional pulverized coal (“PC”) fired power 

plants where the coal is combusted in a boiler, and steam is produced, turning a 

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turbine generator to produce electricity, the IGCC process converts coal into a 

synthetic gas, or syngas, which, after cleaning, can be burned in a gas turbine 

generator. An IGCC facility combines gasification technology from the chemical 

industry with combined cycle power generation technology from the power 

industry. Air, steam, nitrogen and other streams are integrated between the 

gasification and combined cycle “islands”; hence, the name Integrated 

Gasification Combined Cycle, or IGCC. 

How much of your background is involved in IGCC technology? 

I have worked with IGCC technology for 15 years, about half of my career. 

How much of your current job is spent working on IGCC issues? 

About 75% of my current work applies directly to IGCC technology. 

Have you written any articles, or done any presentations, on IGCC 

technology? 

Yes. I have written articles and made many presentations on IGCC technology 

over the past 15 years. 

Do you consider yourself an expert in IGCC technology? 

Yes. As I noted, I was the Deputy Project Manager for the Polk Power Station 

IGCC project, one of the two operating IGCC power plants in the U.S. Since then, 

I have been directly involved in a number of IGCC and gasification projects 

across the U. S. This includes providing environmental permitting, technical 

feasibility, and engineering services for a number of these modern IGCC and 

gasification plants that are in development at this time. In addition, I serve on the 

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Electric Power Research Institute’s CoalFleet for Tomorrow Program IGCC 

Experts Group. 

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FGPP SITE 

Can you please describe the technology that FPL is proposing to use at 

FGPP? 

The technology to be used at FGPP is USCPC technology. In this kind of a 

power generation technology, coal is crushed to a fine powder, and blown into a 

boiler with air. The coal-air mixture burns at temperatures of over 2,500 OF. Heat 

from the combustion is transferred to the water that is pumped through the boiler 

tubes, turning it to steam at very high temperatures and pressures. The operating 

pressure of coal-fired power plants is classified as either subcritical pulverized 

coal (“SPC”) or supercritical pulverized coal (“SCPC”). SPC and SCPC refer to 

the state of the water and steam that is used in the steam generation process. SPC 

power plants utilize pressures below the critical point of water in which there is a 

distinct difference in the state of the water and the steam. The critical point of 

water is 3,208 psia and 705 OF. At this “critical” point, there is no difference in 

the density of water and steam. At pressures above 3,208 psia, heat addition no 

longer results in the typical boiling process in which there is an exact division 

between steam and water. The fluid becomes a composite mixture throughout the 

heating process. The majority of the boilers in the U.S. utilize subcritical 

technology, typically with steam temperatures up to 1,050 OF and pressures up to 

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2,400 psia. These units utilize a steam drum and internal separators to separate 

the steam produced in the boiler from the water circulating in the boiler tubes. 

Supercritical units do not utilize a steam drum, since there is no way to separate 

steam from the steam-water mixture. 

In SCPC boilers, all of the water introduced into the boiler is turned into the 

supercritical steam-water mixture. Operation at the higher supercritical pressures 

is more efficient than for subcritical boilers. The U.S. Department of Energy 

(“DOE”) has defined USCPC steam cycles as operating pressures exceeding 

3,600 psia and main steam superheat steam temperatures approaching 1,100 

degrees F. This is even more efficient than conventional SCPC technology. FGPP 

plans to utilize the more efficient USCPC technology. 

The high pressure steam is then piped to the steam turbine, where it turns the 

turbine blades at high speed. The turbine is connected on a shaft to a generator, 

which produces the electricity. The steam is condensed to water, and then 

pumped back to the boiler to be turned into steam again. 

In the boiler, the ash in the coal is converted primarily to fly ash, with some 

falling to the bottom of the boiler; it is called bottom ash. The bottom ash is 

cooled in a water bath and removed for re-use in industry or it can be safely stored 

in a lined landfill. The fly ash is removed in the emission control system. In the 

boiler, low-NOx burners, with overfire air, are an industry-standard design for 

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minimizing the formation of NOx during combustion. The emission control 

system for a coal-fired power plant typically includes a selective catalytic 

reduction (“SCRyy) system for reducing emissions of nitrogen oxide (“NOx”) 

emissions, a sorbent injection system for capture of mercury, a fabric filter for 

removal of the fly ash and captured mercury from the exhaust gas stream, a flue 

gas desulfurization (“FGD”) system for removal of the sulfur dioxide (“S02”) 

produced when the sulfur inherent in the coal is also combusted, and a wet ESP 

for removal of fine particulates. These are all included in the design of FGPP. 

Following the emission control system, the cooled, cleaned exhaust gas exits 

through a stack. 

Is the technology that FPL is proposing to use a proven and reliable 

technology? 

Yes. The USCPC technology that FPL is proposing to use is proven worldwide 

and is a reliable technology for power generation. 

Are other facilities in the United States and around the world using this 

technology? 

Yes. There are approximately 160 supercritical generating units in operation in 

the U.S., with over 500 operating worldwide. This number includes 17 plants 

worldwide using the more advanced USCPC technology proposed for FGPP. 

Several have been operating almost nine years, and operating data shows that 

these units have been very reliable. 

Are you a proponent of IGCC technology? 

Yes. I am. Although IGCC is still in the development phase of, I think that it will 

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be able to significantly reduce emissions and provide low cost electricity, once it 

is proven at a large, commercial scale. 

Has IGCC been used successfully for other power plants in the United States 

and around the world? 

Yes. Although its application was not initially successful due to difficult start-ups 

and low plant availability, these TGCC facilities can now be considered as 

successful. 

Please describe some of the currently existing IGCC plants in the United 

States and around the world. 

There are four coal-based IGCC plants in operation worldwide. They include 

Tampa Electric Company’s Polk Power Station near Mulberry, Florida; SG 

Solutions’ Wabash River Generating Station in West Terre Haute, Indiana; 

Nuon’s Willem-Alexander Centrale Station in Buggenum, The Netherlands; and 

the Elcogas Puertollano Plant in Puertollano, Spain. There was a fifth plant, in 

the U.S., but it is no longer in operation. 

How big are those facilities? 

All four of these are single train gasification plants, each with a net output in the 

range of 250-260 MW. 

Has anyone built a 1,960 MW facility using IGCC? 

No. 

What is the largest facility that has been built using IGCC? 

The largest coal-based IGCC plant is sized at 260 MW (net). 

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Do you know of any proposed 1,960 MW or larger IGCC facilities? 

No. 1 do not. 

What is the largest size IGCC plant that is commercially available? 

The largest size being commercially available is called the 600 MW net 

“reference plant.” This size is being offered by five different IGCC technology 

providers, although the specific commercial and environmental guarantees are not 

publicly available. This 600 MW net size incorporates several gasifiers to 

produce two to three times the amount of syngas produced at each of the 

demonstration facilities, which is sufficient to fblly load two of the modem gas 

turbines being commercially offered for syngas service. Integrated together, the 

net output is about 600 MW. It will first be very important to prove the coal 

gasification technology at this larger scale, as well as proving these new types of 

syngas-fired gas turbines at commercial scale. Once that has been done 

successfully, and I believe that it will be, these companies will begin to offer large 

designs. That is likely to happen about six to eight years from now after this next 

generation of IGCC plants has gone into service. 

Have the current IGCC facilities been funded by their governments? 

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Yes. All four of the operating plants received significant amounts of co-funding 

from their respective federal governments. This is because both private industry 

and the governments were very interested in developing IGCC and demonstrating 

it at commercial scale, but neither was able to bear the entire costs of these plants. 

In the case of Polk Power Station, the DOE funded 20-25% of the capital cost of 

the plant, as well as some of the operating costs during the demonstration period. 

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What has been the track record of these facilities? 

The initial start-up at all of these plants was very difficult and the overall plant 

availability for each of these plants was low for the first several years. Since then, 

many operational problems have been solved, some equipment has been removed 

or modified, and many of the “bugs” have been worked out. 

Are all these facilities still online and functioning? 

No. Only four of the five are in operation. 

Is the facility in Nevada still online and functioning? 

No. The gasification facility at the Piiion Pine IGCC demonstration plant in 

Nevada is no longer functioning, although the power block is operating using 

natural gas as a fbel. 

Why is the Nevada facility not online and functioning? 

This IGCC plant was developed as part of the DOE’S Clean Coal Technology 

Program, as were the Polk Power Station and Wabash River IGCC facilities. The 

gasification technology used at the Piiion Pine IGCC demonstration plant was not 

successfUl, and was shut down following initial start-up and operation. 

How reliable are IGCC facilities? 

The four operating IGCC plants described previously had significant start-up and 

initial operation problems. Reliability in the first three to four years was much 

lower than planned. Since then, many of the design and operation issues have 

been successfully resolved. Availability values are much higher, although none 

of these plants have achieved sustained reliability values of 85%, as planned. In 

its ninth year of operation, Polk Power Station achieved 82% availability of the 

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5 Q. Why do IGCC plants have problems with reliability? 

6 A. The four IGCC plants all have single-train gasification islands. Whenever a 

overall IGCC plant. Wabash River reached about 78% availability in its seventh 

year of operation. The Nuon IGCC plant reached about 78% availability in its 

eleventh year of operation, and Puertollano’s availability peaked at about 60% 

during its fifth year of operation. 

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syngas available for combustion in the gas turbines. At that point, unless a backup fuel is used, the power plant must be shut down. The use of a single train in 

these demonstration plants is a major contributor to the low reliability of IGCC 

plants. Other reasons for low reliability include corrosion and erosion of gasifier 

refractory, requiring an outage for replacement, corrosion of process piping, 

plugging of syngas heat exchangers that leads to outages for cleaning, corrosion 

of process piping, slurry pump problems, and miscellaneous power block 

problems that can occur in any combined cycle plant. A reliability issue that is 

somewhat unique to syngas use relates to high rotor torque. Gas turbines are 

designed to handle the combustion of natural gas. Since syngas has a much lower 

heating value, a much greater amount of syngas is required to fully load the gas 

turbine. This additional rotational stress has had negative impacts on syngas-fired 

gas turbine reliability. 

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There are many gasifiers operating successfully worldwide. They are typically 

used for producing a syngas that can be hrther processed to produce hydrogen for 

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refineries or to make ammonia for fertilizer manufacture, not to produce 

electricity. Some of these facilities, particularly those with spare gasifier trains, 

reach availability values in the high 90% range. Some of the successful gasifiers 

also use refinery bottoms, like asphalt, as a feedstock. Such liquid feedstocks 

require little handling and preparation, versus the coal handling and coal grinding 

systems required in a coal-based IGCC plant. Operating a gasifier by itself is 

significantly less difficult and complicated than when using a gasifier as an 

integrated part of a complex IGCC plant that produces electricity. It is important 

to note that the “integration” part of IGCC is very difficult to design for and to 

operate. All of these components in the gasification and power block islands must 

be operated interdependently. The failure of one system often leads to the entire 

plant being shut down. It is very different from having to operate only a gasifier. 

That is why the reliability of gasifier-only facilities is greater than those of IGCC 

facilities. 

Has there been an effort to improve the performance of IGCC? 

The next generation of IGCC plants is being designed using the lessons learned 

from the four operating plants. Some of the key design enhancements to improve 

reliability include using two 50% sized gasification trains (instead of one 100%- 

sized train), and even adding a third gasifier train as a spare, better integration 

between the gasification island and the power block, better gasifier refractory 

materials, design without convective syngas coolers, and upgraded gas turbine 

burners and materials for syngas service. These design improvements, along with 

other lessons learned, are expected to provide for easier initial start-up, as well as 

Q. 

A. 

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higher availability. Use of a spare gasification train is expected to provide up to 

90-92 % availability, but adds to the cost of the facility. Moreover, these design 

enhancements will not be placed into service until the 201 1-2013 timeframe, so 

that it will be six to eight years from now (allowing for start-up and initial 

operation) before we see whether IGCC reliability can be improved to levels 

greater than 85%. 

Is IGCC technology progressing as quickly as you would like? 

No. It is not. The first generation of IGCC plants went into service between 1994 

and 1998. The second generation will not go into service until 201 1-2013, a time 

delay of about sixteen years. When we designed and built Polk Power Station, it 

was our expectation that the technology would be embraced by the industry, and 

that by now we would have had the critical second generation of IGCC plants 

already in operation, in order to prove the technology on a large, commercial 

scale. 

Does IGCC need more investment in research? 

Yes. IGCC still requires a significant amount of investment in research and 

development. That is why individual power companies, the Electric Power 

Research Institute (“EPRI”), and the U.S. DOE are still planning and hnding 

such research and development (“R&D”) to support further IGCC technology 

development. In the Coal Technology Roadmap developed by EPRI and Coal 

Utilization Research Council, a total of $5.2 billion of R&D and demonstration of 

promising improvements is still needed to provide for the needed IGCC 

enhancements. These include basic system development, efficiency 

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improvements, use of new air separation technology, improvements in gasifier 

refkactory materials, new types of particulate removal devices, sluny pump 

enhancements, gasifier skin temperature monitoring systems, more efficient 

emission control systems, and gas turbines that can handle high hydrogen 

concentration syngas. Of this $5.2 billion, about 60% would be needed from the 

federal government. In addition, the Energy Policy Act of 2005 provides for 

additional IGCC and gasification R&D through the U.S. DOE’S Clean Coal 

Power Initiative, as well as tax incentives and loan guarantees to promote fbrther 

demonstration of IGCC and gasification technology. This legislation specifically 

recognizes the continuing need for R&D and co-funding or economic incentives 

for IGCC technology to succeed at large, commercial scale. 

When do you think IG€C will be commercially available? 

IGCC is commercially available from IGCC technology suppliers at this time, 

based on a 600 MW net IGCC “reference plant” design. However, the plant 

would not be able to be started up for five to six years from the time you began 

the IGCC project. For example, if you began a 600 MW net IGCC reference 

plant project today, it would be late 2012 to 2013 at best before the plant was 

ready for startup. Any changes to the basic reference plant design would take 

longer to design, and may not even be commercially available. 

If IGCC technology were to be selected for this project, FPL would likely use the 

largest size plant available, in order to take advantage of economies of scale, just 

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the closest match to meet the 1,960 MW (net) value would be to use a 3x3~1 

configuration such as the one referenced in the study jointly conducted by FPL 

and Black & Veatch. This study is noted as Document No. DNH-2 in the 

testimony provided by Mr. Hicks of FPL. However, as I noted previously, the 

largest size IGCC facility that is being offered by the IGCC technology suppliers 

is the 600 MW (net) reference plant. Therefore, a non-standard 3x3~1 

configuration, if commercially available, would take even longer to be designed 

and constructed. 

IGCC technology suppliers, in alliance with engineering firms and power block 

suppliers, are offering the technology today with limited guarantees on 

performance and emission limits. Although about a dozen power companies are 

going forward with IGCC projects, none have yet finalized a contract for a 

complete reference plant, so that such terms and conditions, as well as the 

guarantees, have not yet become publicly available. Due to the higher cost of 

IGCC compared to SCPC technology, many of these projects are counting on the 

financial incentives provided by state and federal legislation in order to help make 

the projects commercially feasible. 

Do you think that IGCC technology is commercially ready? 

Although IGCC is commercially available, it will not be commercially ready or 

proven on a large scale for at least another six to eight years, once this next 

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generation of IGCC plants has gone into service and had an opportunity to work 

through initial start-ups and reach steady operation. 

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Do you have concerns regarding the use of IGCC technology at FGPP? 

Yes. I would have some concerns with the use of IGCC technology at this site. 

What are some of your concerns with the use of IGCC technology at the site? 

First, I would be concerned with the potential for reliability problems. FGPP is 

being designed for 92% reliability, which is commercially available and proven 

with SCPC technology. As noted previously, such high reliability levels have not 

yet been demonstrated by existing IGCC power plants, and it will be six to eight 

years before the presently planned IGCC plants are able to prove whether the 

intended design enhancements can provide for improved reliability. 

Second, FGPP is being designed to produce 1,960 MW net, using two USCPC 

generating units. As noted previously, IGCC is only commercially available, but 

not yet “ready” or “proven,” at the 600 MW net size. It would take more than 

three IGCC reference plants to do the job of the two USCPC units. At the present 

15 time, the three IGCC technology supplier alliances are at their busiest ever. I am 

16 concerned that the supplier alliances would not be able to support the engineering, 

17 procurement, and construction of three concurrent 600 MW IGCC reference 

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Third, it takes five to six years to design, permit, and construct an IGCC plant. If 

FPL were to start now, it would be late 2012 or 2013 at best before the first IGCC 

plant could be ready for operation. 

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Do you have reliability concerns with an IGCC plant? 

As I noted previously, the existing IGCC power plants demonstrated poor 

reliability in the initial years of operation, with only medium reliability values at 

maturity. Even though designs are including information from lessons learned, it 

will still be another six to eight years before we know whether IGCC can provide 

the high reliability values that are presently being demonstrated by SCPC plants 

worldwide. 

Why do you have reliability issues with an IGCC plant? 

These concerns are based on the historical poor to moderate performance of the 

four operating IGCC plants worldwide, and the fact that the potential for higher 

reliability will not be known for another six to eight years. 

Why is the plant that FPL is proposing more reliable than an IGCC plant? 

PC technology has been in commercial operation worldwide for about 100 years. 

IGCC has only been in commercial operation worldwide for about 13 years. 

There are more than 300,000 MW of PC capacity in the U.S. There are only 5 10 

MW of IGCC capacity in the U.S. PC technology is proven at a large scale in 

thousands of applications. PC units (whether SPC, SCPC or USCPC) have 

demonstrated high reliability. The operation of a PC unit does not require the 

interdependent operation of a multitude of individual chemical and mechanical 

processes as does IGCC. IGCC plants take several days for a cold start, due to 

limitations in the rate of heating up of the gasifier (to protect the refractory from 

thermal cracking), as well as cooling the air separation “cold box” to well below 

freezing temperatures. Together, these have significant negative impacts on the 

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total number of days per year that the IGCC plant can operate at full load. IGCC 

plants have suffered from these problems and have exhibited reliability problems. 

PC plants require several days for a cold start, but these would typically occur two 

or three times per year. IGCC plants also have a history of many warm or hot 

starts. While these startups do not take as long, they still impact negatively on 

IGCC unit reliability. Two of the IGCC plants being planned at this time for 

operation in the 2011 to 2012 timeframe have noted in their air permit 

applications the potential for over 60 startup and shutdown events per year, far 

more than what is normal for PC units. Taking into account all of these reasons, 

PC units are expected to continue to provide higher reliability than IGCC units. 

Is there a proposed IGCC facility in Orlando? 

Yes. An IGCC plant is being planned in the Orlando area. 

Can you compare that facility to the proposed FGPP? 

The Orlando Gasification Project (“OGP”) is being developed by the Orlando 

Utilities Commission (“OUC”) and Southern Power Company (“Southem”), a 

subsidiary of the Southem Company, which is a large utility holding company. 

OGP is planned to start up in 2010. The OGP proposes to demonstrate the 

Kellogg Brown and Root (“KBR7 transport gasifier in IGCC configuration. The 

KBR technology has been developed from technology used in catalytic crackers 

in the refinery industry. OUC and Southern expect this new IGCC technology to 

provide for higher efficiencies, especially when applied to low quality coals. The 

KBR technology has been pilot tested at the approximately six MW scale at the 

Power Systems Development Facility in Wilsonville, Alabama, adjacent to 

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Alabama Power Company’s Gaston Steam Plant. The KBR technology is an airblown gasification technology, unlike the oxygen-blown gasification technology 

being commercially offered by GE Energy, ConocoPhillips and Shell (although it 

can operate in oxygen-blown mode). In addition, OGP will use Powder River 

Basin subbituminous coal railed in from Wyoming, unlike the higher quality 

bituminous coal planned for FGPP. 

OGP will be sized for a net output of only about 285 MW. This is about one-sixth 

of the power generation capacity to be produced by the USCPC generating units 

planned for FGPP. Overall, OGP will be much smaller in scale than FGPP, and 

will use a power generation technology that is not yet proven at large commercial 

scale. 

Can you compare the efficiency? 

The efficiency of OGP will not be known until it has been in operation for at least 

a year, meaning some time in 2011. For comparisons of SCPC and IGCC 

efficiency, I refer you to the study jointly conducted by FPL and Black & Veatch. 

This study is noted as Document No. DNH-2 in the testimony provided by Mr. 

Hicks of FPL. 

Can you compare the Capital Cost? 

Comparisons of the capital costs of different projects are difficult, due to 

differences in what each estimate includes or excludes. According to the DOE, 

the cost of the OGP will be $557 million. However, I understand from Southern 

that this amount only includes the gasification portion of the project, and not the 

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combined cycle power block. Therefore, it is not possible to make a comparison 

of capital costs with FGPP. For comparisons of SCPC and IGCC cost, I refer you 

to the study jointly conducted by FPL and Black & Veatch. This study is noted as 

Document No. DNH-2 in the testimony provided by Mr. David Hicks of FPL. 

Can you compare the technology status? 

As noted previously, USCPC technology is proven on a large commercial scale. 

IGCC technology is still in development, and is not yet mature. OGP will only 

demonstrate the KBR technology at about half of the IGCC reference plant size 

and one-seventh the size of FGPP. 

Can you compare the scale-up required? 

The USCPC technology proposed for FGPP will not require any technology 

scale-up, as it is already in commercial operation worldwide at the proposed scale. 

The capacity of the KBR gasifier will need to be scaled-up over fifty times. 

Has the Orlando facility received government funding? 

OGP is receiving co-funding under Round two of the DOE’S Clean Coal Power 

Initiative. 

How much funding will it receive under this program? 

According to the DOE, it will be providing $235 million in co-hnding for OGP. 

How effective is the plant that FPL is proposing in reducing emissions? 

The emission control systems planned for the USCPC power generation 

technology proposed for FGPP will be designed to provide state-of-the-art 

emission reductions. 

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NOx 

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Low-NOx burners and overfire 

air to reduce formation of 

NOx, along with Selective 

Catalytic Reduction (SCR) to 

remove NOx from the flue gas 

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SO2 

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Wet Flue Gas desulfurization 

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fly ash from the flue gas, along 

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Can you please discuss each of the emissions, such as nitrogen oxides, sulfur 

dioxide, mercury and other emissions in terms of how they would be handled 

at an IGCC plant versus the proposed FPL plant? 

As I noted previously, an IGCC facility converts coal to a syngas, which is then 

cleaned and combusted in the gas turbine. The reduction of emissions from an 

IGCC plant occurs pre-combustion, so that pollutants are removed or reduced 

before the syngas is burned. This is different from a PC plant, where most of the 

emission reductions are achieved post-combustion, meaning that emissions are 

removed from the exhaust gas after the coal is burned. The table below describes 

the typical emission control methods for the USCPC technology proposed for 

FGPP and for IGCC. 

I FGPP 

(FGD) system 

IGCC Plant 

Syngas humidification and 

injection of diluent nitrogen (for 

oxygen-blown IGCC systems) 

into syngas just prior to the gas 

turbine or in the burners 

Removal of hydrogen sulfide 

from syngas reduces SO2 

emissions when the syngas is 

combusted in the gas turbines 

System can use wet carbon 

scrubber, hot gas cyclone, and/or 

20 
co 

voc 

SAM 

Mercury 

with minimizing fine 

particulate through removal of 

SO3 droplets in a wet ESP 

Good combustion prbtices 

Good combustion practices 

FGD system and wet 

precipitator 

Co-benefits removal in ESP or 

fabric filter, and in FGD 

system, along with sorbent 

injection upstream of the fabric 

filter 

high temperature, high pressure 

candle filter 

Good combustion practices 

Good combustion practices 

Fuel sulfur specification and SO2 

emission control 

Removal in slag, carbon scrubber, 

pre-sulfided activated carbon bed, 

and acid gas removal system 

recirculating solvent 

21 
1 Q* 

2 

3 A. 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

Does reliability affect emissions? In other words, if you have to start up a 

plant more frequently, does that affect emissions? 

Yes. Overall plant reliability can affect overall emissions. When a PC power 

plant starts up, the boiler is fired with coal at a very low throughput, and then it 

gradually ramps up to a higher throughput. When the proper steam conditions are 

reached, the steam is routed to the steam turbine for power generation, although at 

a minimum load. Then the coal throughout, steam production and power 

generation are gradually ramped up to full load. 

During the time a plant is starting up, coal is being consumed without any power 

generation, until steam conditions are right for sending it to the steam turbine. 

Power plants operate at their most efficient point at high loads. During the startup process, the unit operates at a lower efficiency. This means that more coal is 

used for a unit of power generated than it would at a high load. Since more coal 

is being consumed, more emissions are produced per unit of power generated. 

Fortunately, PC units have a fairly short start-up time period. In starting up a 

coal-fired unit, steam requirements are typically met using a small, auxiliary 

boiler. These boilers use fuel oil or natural gas, and contribute to the unit’s 

overall emissions. 

IGCC units have a different start-up profile. As noted previously, a cold start-up 

on an IGCC power plant can take several days. During this time, large amounts 

of coal can be consumed in the gasification process while the emission control 

22 
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4 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

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23 

systems are being started up. Clean or partially cleaned syngas is flared. 

Emissions from the flare can be substantial, depending on the state of operation of 

the emission control systems and the total time of flaring. Combining these 

technical issues with a somewhat lower reliability of IGCC versus PC technology, 

an IGCC plant could actually produce more emissions on an annual basis than a 

PC unit, even though it may have a lower emission rate on a IbNWh or pounds 

per million Btus of heat input basis. 

Based on the technology today, do you believe that the emissions would be 

better for an IGCC facility versus the proposed FPL power plant? 

Not necessarily. The proposed emission rates for some of the pollutants for 

proposed IGCC units are lower than those proposed for FGPP. However, due to 

the impacts of all of the start-up and shutdown cycles inherent with IGCC 

facilities, there can be some substantial overall increases in overall emissions 

from an IGCC facility that are not accounted for in these proposed emission rates. 

URS analyzed the emission data in the air permit applications for several 

proposed IGCC facilities, as well as similar data for FGPP. We looked at the 

proposed emission rates in lb/MWh and then calculated what those values would 

be when incorporating the emissions from the start-up and shutdown cycles. 

What we found was that for FGPP, the emissions from start-up and shutdowns 

increased the overall emission rates by no more than five %. However, it was 

very different for the IGCC units. We saw that the emission rates for the IGCC 

units could actually be increased by an average of 38%, if all of the potential startup and shutdown emissions are accounted for. Based on that analysis, it is 

Q. 

A. 

23 
1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

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14 

15 

16 

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18 

19 

20 

21 

22 

23 

possible that an IGCC unit with an emission rate lower than that for a PC unit 

may actually have an equal or greater potential emission rate, due to the 

differences in the start-up and shutdown issues. I would not expect that in actual 

operation, that all of these start-up and shutdown cycles would occur. The air 

permit applications were written in a way so as not to constrain the units’ 

operation, so that the number of start-up and shutdown cycles was maximized. 

For an actual comparison, each unit’s characteristics would have to be analyzed to 

determine the overall impact of start-ups and shutdowns. 

Is IGCC “C02 Capture Ready”? 

When discussing IGCC technology, the term “C02 capture ready” means that the 

IGCC plant is technically ready to be converted to produce a concentrated stream 

of C02 (through the water shift reaction), and that the C02 can be easily captured 

and removed fiom the syngas stream. An IGCC plant is not capture ready unless 

it has been designed from the beginning to provide for these significant 

modifications. IGCC by itself is not “C02 capture ready.’’ 

What changes are needed to make an IGCC plant COz capture ready? 

First, the IGCC technology being used, as well as the physical plant itself, must 

be capable of the addition of a water shift reactor. This is the primary process 

where the syngas is processed and converted to a stream with high concentrations 

of both hydrogen and CO2. Since the water shift reaction is exothermic, steam is 

typically produced for use elsewhere in the process. The IGCC plant design must 

account for the addition of this water shift reactor and to have a proper place to 

route this low pressure steam. 

Q. 

A. 

Q. 

A. 

24 
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2 

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4 

5 

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7 

8 

9 

10 

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Then there must be room for the addition of a very large C02 capture/removal 

system. While the acid gas removal systems typically used for H2S removal can 

also be used to absorb some of the C02, they are much more selective for the H2S. 

This means that it is much more difficult to remove the C02 than the H2S from the 

syngas. The H2S removal system is much too small to also remove a large portion 

of the C02. It must be able to be scaled up considerably, with much additional 

equipment required. The C02 removal system requires a significant amount of 

high pressure steam to strip (remove) the C02 from the solvent, so that it can be 

concentrated. Therefore, the steam turbine must be designed from day one with 

steam extractions at the right temperatures and pressures for C02 stripping. 

Significant additional power is required for the Cot removal system to operate. 

With the extraction of steam noted previously, and the increased internal power 

use, the IGCC plant’s net output falls considerably, and this deficit must be made 

up by other sources of generation. 

Once the C02 is removed from the syngas, a hydrogen-rich syngas stream 

remains. While gas turbines have the ability to burn syngas and other fuels that 

contain some hydrogen, gas turbines for the combustion of concentrated hydrogen 

streams are not yet commercially available at large scale. Gas turbine 

manufacturers are doing R&D on their products to see how high a concentration 

of hydrogen can be safely combusted (the burning profiles of natural gas, 

hydrogen and syngas are all very different, and the burners must be specifically 

25 
1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 Q. 

12 A. 

13 Q. 

14 A. 

15 

16 

17 

18 

19 

20 

21 

22 

23 

designed to provide for safe, controlled combustion, especially with hydrogen). 

Large, commercially-available gas turbines for hydrogen-rich syngas are not 

expected until 2014. 

Therefore, IGCC is not inherently C02 capture ready without significant 

additions, modifications and impacts to its efficiency and output. I have heard 

many people apply the term “C02 capture ready” to IGCC without really 

understanding what is involved, both technically and financially, to implement 

these significant changes, Just because people call it C02 capture ready does not 

mean that it is. 

Have COz capture technologies been applied to IGCC? 

Yes, but only on a test basis. 

Are EPRI and the DOE funding R&D on COz capture technologies? 

Yes. A significant amount of design development is underway, in order to qualify 

and quantify the modifications described previously. C02 capture for IGCC is not 

yet a commercially available technology. Similar R&D is proceeding for C02 

capture technology that could be applied to PC plants. Applying C02 capture to a 

PC plant is presently much more difficult and expensive than for an IGCC plant. 

This is primarily because the C02 must be removed from the flue gas after 

combustion. Since air is used in combustion, the flue gas stream from a PC unit 

has a high concentration of nitrogen (from the air), and the C02 is at a very low 

concentration. It is much more difficult to remove C02 from a weak stream than 

a concentrated stream. The C02 capture system must be much larger, more 

26 
1 

2 

3 Q. 

4 A. 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 Q. 

19 A. 

20 

21 

22 

expensive and more energy intensive. EPRJ and the DOE are funding R&D for 

C02 capture for both PC and IGCC. 

Would inclusion of C02 capture technology reduce output at the plant? 

Yes. As I noted previously, a considerable amount of steam must be extracted 

from the steam turbine for the CO2 stripping process. This steam would otherwise 

have been used for power generation. In addition, the C02 capture system has 

large internal power requirements for pumps and other equipment. All of these 

reduce the plant’s net output in a significant way. A recent study by the EPA 

shows that the addition of a C02 capture system would reduce the output of an 

IGCC plant by 14% and a SCPC plant by 28%. The result of this is that the plants 

would become very inefficient, and would be unable to meet their intended load 

requirements. 

Another option would be to size the plant to be much larger in the beginning, so 

that the net output, after all of the steam extraction and additional internal power 

ruse, results in the required net output. Of course, this would require the 

expenditure of a significant additional capital cost to build the plant. 

Would C02 capture technology raise the cost of electricity? 

Yes. It would. The equipment required for C02 capture is both extensive and 

expensive. The plant would be more expensive, and the cost of electricity, which 

would include a component to account for this additional capital expenditure, 

would be higher. 

27 
1 Q2 A. 

3 

4 Q* 

5 

6 A. 

7 

8 

9 

IO Q. 

11 

12 A. 

13 

14 Q. 

15 A. 

I6 Q. 

17 A. 

18 

19 

20 

21 

22 

23 

Can you say that IGCC is TO2 capture ready” today? 

It is not. 

previously, IGCC is expected to be C02 capture ready. 

Is IGCC currently effective at removing C02 and then providing an 

appropriate storage location? 

No. It is not. There is no experience with the capture and sequestration of C02 

from the four operating IGCC plants. To date, only pilot testing has been done on 

IGCC plants for COz capture. No sequestration of the C02 captured from those 

tests has occurred. 

Are you aware of any other power companies that have investigated the use 

of IGCC? 

Yes. 

presently investigating, the use of IGCC. 

Has AEP investigated the use of IGCC? 

Yes. It has investigated the use of IGCC. 

Who is AEP and what did it conclude about the use of IGCC? 

AEP is the American Electric Power Corporation. It is the largest generator of 

electric power in the U.S. AEP conducted a major study of IGCC technology. 

The conclusions of that study, as presented by Mr. Michael Mudd of AEP, were 

as follows: 

Once the R&D is completed over the next decade, as described 

I am aware of many power companies that have investigated, or are 

IGCC technology is not yet mature; 

IGCC efficiency is worse than advertised; 

IGCC costs are higher than advertised; 

28 
5 

6 

7 

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9 

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19 

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21 

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23 

IGCC startup is long and complicated; and , 

It is difficult to get a fixed price and guarantees for an IGCC facility; 

More R&D is needed for IGCC to be proven for commercial use. 

Initially, AEP found that the IGCC suppliers were not able to provide a “wrap” of 

guarantees. As business alliances were formed among gasification technology 

suppliers, power block suppliers, and engineering firms, AEP eventually felt 

comfortable in expecting to obtain reasonable guarantees, and proceeded with the 

Front End Engineering and Design (“FEED”) phase for a 600 MW net IGCC 

reference plant. 

Its IGCC plant will be developed in either Ohio or West Virginia, depending on 

which state will allow it to recover the additional costs of building an IGCC plant 

instead of an SCPC plant, This is a critical part of making the project financially 

feasible for AEP. Once this initial design phase is completed, AEP will also have 

a more accurate cost estimate for the plant, and will be able to determine whether 

to continue with the project. AEP was planning for the capital cost premium of 

IGCC over PC to be no greater than 20%. 

In late December, 2006, AEP noted that its FEED study showed that the cost 

would exceed this 20% premium. Because of that, AEP has instructed their 

technology supplier team to re-evaluate and modify the design to find ways to 

reduce the cost to meet this goal. It will likely be another six months before this 

29 
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8 

9 

10 

I1 

12 

13 

14 Q. 

15 

16 A. 

17 

18 

19 

20 

21 

22 

23 

re-design and revision of the cost estimate are completed. AEP will need the new 

cost estimate before it goes before the public utility commission to request 

approval for the costs of detailed design and construction. 

In addition to going forward with this IGCC project, AEP has continued to rely on 

SCPC technology. In August of 2006, AEP announced the development of a 600 

MW USCPC plant to be sited near Fulton, Arkansas, scheduled for operation in 

the summer of 20 1 1. In announcing this new PC plant, the company’s president 

noted that “we believe that a coal- or lignite-fbeled plant is the best choice for 

new base load generation to economically fuel the future growth of the economies 

in our region, allow us to remain a low-cost provider, and prevent over-reliance 

on natural gas for electricity generation as domestic national gas supplies are 

diminishing.” 

Overall, how would you compare the plant efficiency for IGCC technology to 

the proposed FPL plant? 

The “promise” of IGCC technology included much higher efficiencies than PC 

units. In practice, neither Polk Power Station nor Wabash River Generating 

Station has met its efficiency goals. It was expected that through process and 

technology improvement, this next generation of IGCC plants would meet the 

goal of 40% efficiency. Unfortunately, it does not look like that will happen. Of 

all of the coal-based IGCC plants being planned, not one has a planned efficiency 

of over 38%. The highest efficiency values, according to information provided by 

the power companies in their public documents and especially in their air permit 

30 
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8 

9 

10 

11 

12 Q. 

13 

14 A. 

15 Q. 

16 

17 A. 

18 

19 

20 

21 

22 

applications, will be ERORA Corporation’s planned IGCC plants in Kentucky 

and Illinois, with efficiencies of 36.8%. These efficiency values are typically 

provided in the industry at “new and clean” conditions; performance typically 

degrades over time as equipment ages and wears. Earlier this year, Tampa 

Electric Company announced that it was planning to build a second IGCC plant at 

Polk Power Station. Polk Unit #6 will be a 600 MW (net) plant. Its efficiency, as 

noted in Tampa Electric Company’s Ten Year Site Plan submittal, is planned to 

be only 36.6%. 

FGPP is being designed for an efficiency of 38.8%, which is higher than that for 

the next generation of large, commercial-scale, coal-based IGCC power plants. 

How would you compare the emissions between an IGCC plant and the 

proposed FPL plant? 

They are very similar for many of the primary pollutants. 

How would you compare the reliability between an IGCC plant and the 

proposed FPL plant? 

FGPP is being designed for an availability of 92%. This is much higher than what 

the four existing IGCC plants have been able to achieve. As I noted previously, 

design improvements and the addition of spare equipment are expected to provide 

for 8590% availability on the planned IGCC units. It is possible that the 

availability of IGCC and SCPC could be comparable, but we will not know what 

IGCC availability will be for another six to eight years. 

31 
1 Q2 

3 A. 

4 

5 

6 

7 

8 

9 

10 

11 Q. 

12 

13 A. 

14 

15 

16 

17 Q. 

18 

19 A. 

20 

21 

22 

How would you compare the cost certainty between an IGCC plant and the 

proposed FPL plant? 

At the present time, the cost of IGCC is not known in anywhere near the detail or 

accuracy as that of PC units. Since there are hundreds of SCPC units around the 

world, these costs are much more certain. Once one of the companies planning an 

IGCC plant actually signs a contract for the purchase and development of its 

IGCC plant, the industry will have a much better idea of what IGCC will really 

cost. At this time, the range for IGCC cost is very wide and uncertain. It has also 

been difficult to obtain guarantees or risk sharing with the IGCC technology 

suppliers at a reasonable cost. 

How would you compare the maturity of the technology between an IGCC 

plant and the proposed FPL plant? 

USCPC technology is proven worldwide on a large, commercial scale. IGCC is 

still in development, and is not yet mature. However, in six to eight years, we 

will have much more experience with IGCC technology once the units being 

planned actually go into operation. 

In your professional opinion, would you recommend the use of IGCC 

technology for this proposed power plant? 

Based on the requirement for a power generation technology that can provide 

1,960 MW net in the 2012 through 2014 time period, high efficiency, low cost, 

high cost certainty, high reliability, and low emissions, I would not recommend 

IGCC technology for FGPP. 

32 
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4 

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11 

12 

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16 

Q. In your professional opinion, in terms of reliability, cost-effectiveness, 

emissions, and commercial availability, do you recommend the technology 

being proposed by FPL for the proposed power plant? 

A. Yes. I recommend the use of USCPC technology for FGPP. It meets the 

requirement for a power generation technology that can provide 1,960 MW net in 

the 2012 through 2014 time period, high efficiency, low cost, high cost certainty, 

high reliability, and low emissions. 

Q. Please summarize your testimony. 

A. After comparing the USCPC technology proposed for use at the FGPP with IGCC 

technology, I have found that USCPC technology is more technologically mature, 

more efficient, and higher in availability than IGCC technology. It also provides 

for a similar environmental emission profile as IGCC technology, and more cost 

certainty than IGCC. I conclude that the selection of USCPC technology for 

FGPP would be a prudent decision by FPL. 

Q. 

A. Yes. It does. 

Does this conclude your direct testimony? 

33 
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Contact the EPA Docket Center, Public Reading Room to view 

or receive a copy of this document. Requests for copies may be 

made as follows: 

In person/writing: 

Environmental Protection Agency, Docket Center 

1301 Constitution Ave NW, 2822T, Room 3334 

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Email: 

docket-customerservice@epa.gov
Letter ID: 0115 

Commenter: Nancy LaPlaca 

Organization: Bardwell Consulting 

Letter ID: 0115 Comment ID: 22047 Letter Lines: 19 to 23 

Comment Code: 1600 1.3 Risk Associated with CO2 GS 

Comment Code: 1620 1.3.2 Induced seismicity 

Comment: Here are the problems with underground injection of CO2: - it's risky: who will 

bear the risk of leakage? - CO2 is heavier than air and displaces air - couple 

incidents in Africa (one in Cameroon) in late 1980's where large "cloud" of CO2 

was released and suffocated 1800 people and 1100 head of cattle. - liquid CO2 is 

very corrosive - injecting CO2 can induce seismic activity 

Individual Response: The final, tailored, Class VI requirements address the large volumes of 

CO2 injected, its buoyancy, potential corrosivity in the presence of water, and potential 

impurities in the CO2 stream. In addition, EPA expects the tailored permitting, siting, 

construction, operation, monitoring, and post-injection site care requirements in the GS rule to 

prevent leakage from injection formations and protect USDWs. 

Regarding the cost of responding to leaks, the GS rule requires that owners or operators 

demonstrate and maintain financial responsibility for corrective action on wells in the AoR, 

injection well plugging, post-injection site care and site closure, and emergency and remedial 

response at GS sites as specified in §146.85. In the event of contamination or other adverse event 

to a USDW associated with GS, the financial instrument(s), such as insurance, bonds, etc., rather 

than public monies, would cover necessary response actions. 

EPA disagrees that the CO2 releases at Lake Nyos is a valid analogue for GS. GS sites have little 

in common with the physical setting or mechanism that resulted in the release of naturallyoccurring CO2 trapped at the bottom of Lake Nyos, a stratified tropical lake that suddenly 

overturned through a process known as "limnic eruption." No injection was associated with this 

event, and this site would not have been considered sufficiently geologically stable to be issued a 

Class VI permit based on the rigorous site characterization requirements at §146.82 (e.g., 

including lack of confining units). 

GS takes places thousands of feet below the Earth’s surface within porous spaces in deep rock 

formations. CO2 is injected for GS through technically engineered wells with multiple barriers 

designed to isolate the injectate in the well and protect formations outside the well materials. The 

injected CO2 is stored in geologic formations underneath confining layers of rock that act as 

natural barriers to leakage. It is unlikely that CO2 would escape from a GS site that is properly 

characterized, operated, monitored, and closed. During the site selection process, operators of 

Class VI wells identify and evaluate the appropriateness of a site for GS of CO2. The evaluation 

includes the identification of surface and subsurface features such as deep stratified lakes and 

other naturally occurring pockets of CO2. Furthermore, during GS operation, injection pressures 

1
2

and formation conditions are monitored to avoid overpressuring the storage formation. 

EPA acknowledges that induced seismicity is a risk that may be associated with GS but 

maintains that the risk is low (IPCC, 2005). The GS rule contains several requirements to address 

seismic risk. First, as part of the site characterization process, owners or operators must submit 

information about the seismic history of and seismic sources near a proposed GS site, data on 

known or suspected faults in the AoR, geomechanical information on fractures, stress, ductility, 

rock strength, and in situ fluid pressures within the confining zone as specified in §146.82(a)(3). 

This information is evaluated by the Director, who determines the suitability of a potential 

project site for GS. Any sites with the potential for reopening or reactivation of faults or 

unacceptable seismic risk that could otherwise interfere with containment will not be permitted 

as GS sites. During injection, the pressure in the injection zone must not exceed 90 percent of the 

fracture pressure of the injection zone as specified in §146.88(a); this requirement is intended to 

prevent the opening of fractures or faults through over pressurization of the injection zone.