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 ) IN TEGRATED GASIFICATION ) Do cket No. 07F
- 088E COMBINED CYCLE (IGCC) ) PLANT IN BRUSH CO ) COL ORADO )

_____ _ 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. T he 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 hereb y request leave to file a repl y t o Xcel ’s May 10 th Reply , and incorporate this reply and our initial R esponse to Xcel’s Motion to Dismiss
.2 COMPLAINANTS ARE NOT “POISONING THE WELL” BUT MERELY REQUEST ING 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 “quasi

legislative 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 carefull y at existing information and adjudicated proceedings for gasified coal plants that have already occurred in other states. O n May 2, 2007, Delaware Public Service Commission staff recommend ed a wind/natural gas combination for electrical generation rather than an IGCC plant. 2 The wind/gas combo was chosen after careful evaluation using Delaware’s Integrated Resource Plan. ( See Attachment A.) Also, j ust this week, Standard & Poor’s (S&P) iss ued a warning to investors in a report on the financial risk that climate change poses to financial markets, investors and industries. S&P utility analy st 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

- 2 41, 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 wi nd

– we re evaluated in light of its Integrated Resource Plan, as w ell 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 likel y t o have trouble even getting firm construction prices from builders. 3 Complainants believe that Carbon Ca pture 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 an d 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 CL EARLY INTENDS TO BUILD AN IGCC PLANT IN COLORADO Xcel’s Assertion That Mesaba Does Not Apply is Contrary to its Own Statements Xcel briefed man y IGCC issues thoroughl y i n the course of the Mesaba docket, and its submissions are extremely relevant here. X cel argues that although it opposed the Purchase Power Agreement (PPA) in the Mesaba case, it did not question the IGCC technology . Complainants disagree, and not e that many of the issues that have been raised in the analy sis of the proposed IGCC plant an d 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 Delaw are’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 ratepay er s ;

· 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 I GCC/CCS is not likely to be seen as a prudent investment in Colorado , and complainants feel that Xcel alread y 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 D ozens 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 trul y i n the fact

- gathering stage of determining whether or not to build the IGCC plant, it would welcome, rather than discourage, the t ype of scrutin y C omplainants 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, but5

merel y posit s that the technology may have certain benefits. It is in all our best interests

– Xcel’s, ratepay ers, 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 i t 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 L east Cost Plan (L CP), 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 Altho ugh carbon taxes are not included in Colorado’s IGCC statute, C.R.S. 40
- 2
- 123 (2) , the realit y 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, 20 06, 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 Intergover

nmental Panel on Cl imate Change (“IPCC”) has just released a series of updated reports that indicate:

· The planet is threat ened by runaway climate change, and the main greenhouse gas is CO2; approximately 40% of all CO2 is from coal

- fired electrical generation;

· “Sy stem inertia , ” due to the long lived nature of CO2 in the atmosphere and various feedback cy cles , means that in addition to the 1.4 degrees Fahrenheit warming so far, there is 1 degree Fahrenheit in warming alread y i n 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 d ata 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 jum ped 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 s tabilizing the climate , we must start stabilizing CO2 and other greenhouse gas levels in the atmosphere
. 6 T he attached graphic (Attachment E) from the September 2004 issue of National Geographic shows that atmospheric CO2 levels are higher than they have been i n 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 planet 7 , 8 Although no one knows exactly how hot the planet will get, there is no question that the planet will be warming subs tantially 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 gasifi cation. 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 P anel 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 fo r 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 ratepay e rs. 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 Moreo ver, there is str ong support for investing in truly carbon free forms of electricit y. 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 ratepay er funds are spent in the most prudent manner possible, require that Xcel’s Motion t o Dismiss be denied
. Respectfully submitted this 17 th Day of May , 2007

____________________ _________ Nancy LaPlaca 4801 W. Yale Ave. Denver CO 80219 nancylaplaca@y ahoo.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 copi es 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 L ogan, OL2 Denver, CO 80203 And have hand

- delivered, mailed or e

- mailed copies to the following: Ms. Paula M. Connelly , Esq. Christopher M. Irb y, Esq. Xcel Energy Services. Assistant Attorney General 1225 17th St. Ste. 900 1525 Sherman S t., 7 th Floor Denver, CO 80202 Denver CO 80203 paula.connell y@x celenergy .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 dsp iller@rcalaw.com Office of the Attorney General olucas@rcalaw.com 1525 Sherman St., 7 th Floor Denver CO 80203 Stephen.southwick@state.co.us P.B. Schechter Rate/Financial Anal ys t 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 ) IN TEGRATED GASIFICATION ) Do cket No. 07F
- 088E COMBINED CYCLE (IGCC) ) PLANT IN BRUSH CO ) COL ORADO )

_____ _ 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 b y P ublic Service Company of Colorado (“PSCo” or “Xcel”) to hire a vendor for an Integrated Gasification and Combined Cycle coal plant (“IGCC” or “gas ified 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 Comm ission, staff set a formal hearing date of May 31, 2007. PSCo then filed a Motion to Dismiss on April 12 , 2007
. Complainants hereb y r espond 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 F UNDING 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 Goa l 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 Technolo gies Such as Concentrating Solar Power (CSP) is a Goal of C.R.S. 40 - 2 - 123(2) ................................ ................................ ................................ ............................... 15 CERTIFICATE OF SERVICE ................................ ................................ ................................ . 173 INTRODUCTION Complainants filed th is 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 ratepay er 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 othe r issues concerning IGCC to indicate that pursuing an IGCC project further at this point in time would be imprudent . D uring the past year and a half, Xcel has been a participant in Minnesota Pub lic Utilities Commission (PUC) D ocket No. E
- 6472/M

- 05
- 1993 ( Attachment 1 )
. In the Minnesota docket, Xcel was opposed to the IGCC plant. ( A cop y 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 o f the economic and technical concerns about I GCC that Xcel has pointed out in Minnesota will also pertain to any plant proposed for Colorado. Complainants will establish that : I. T hey have stated a claim per the requirements of C.R.S. 40

- 6
- 108, and the compl aint

must also be allowed to stand under C.R.C.P. Rule 12(b) ; II. T he requirements of C.R.S. 40

- 2
- 123(2) do not support dismissal;

1 Com plainants are concerned that in the 2003 Least Cos t 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 36 00 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 C olorado House Bill 07

- 1150 contravene Xcel’s claim that it is merely considering whether to file an application; and IV
. T he Commission’s legislative mandate and rules, which require that its decisions are

prudent, demand that the Commission ensure that Xcel i s 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. R ULE 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 an y corporation, person, chamber of commerce, or board of trade, or b y an y ci vic, commercial, mercantile, traffic, agricultural, or manufacturing association or organization, or by an y b ody politic or municipal corporation b y 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 an y public utility , in violation, or claimed to be in violation, of any provision of law or of any order or rule of the commission. ” ( empha sis 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 [, ] o f any

2 4 CCR 723
- 3, Rule 3613(d)(I)(B), states “To support a Commission decision to disallow investments or expenses associat ed 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 decisi ons 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 fo rward with the I GCC 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 moti on to dismiss for failure to state a claim upon wh ich 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 c omplaint should not be dismissed unless it appears bey ond 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 fo r failure to state a claim so long a s the plaintiff is entitled to some relief upon an y 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 i n a number of newspaper stories, including the March 1, 2007, Rocky Mountain News article by Gargi6

Chakrabart y attached to the initial complaint , titled Xcel’s Plans for Clean

- Coal Plant May Grow that it is considering build ing 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 X cel has essentially started the process of obtaining the necessary licenses and meeting the obligations of C.R.S. 40

- 2
- 123(2); S ince ratepay ers will be paying for the plant as well as for man y o f Xcel’s preliminary activities in preparation of the plant, complainants see no reason wh y X cel 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 th is legislation is rather disingenuous as Xcel play ed a large role in the development of this legislation. More importantly , it is incumbent upon Xcel to conduct an independent and careful anal ys is of the information that is already available. Complainant s contend that there is more than enough information that Xcel “knows or should know” at this point in time to question the prudence of an y f

urther 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 mega watts 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 3 600 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 Revie w a nd Approval of Least

- Cost Resource Plans, stat es: 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 util ity’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 i n 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 p erson, the utility 's actions were not proper. ” This rule speaks directl y t o “changed circumstances” such as those we are currently experiencing, where construction costs are rising rapidly, the cost of renewable resources have decreased dramaticall y, and carbon taxes are on the horizon. Indeed, the U.S. Supreme Court’s recent decision in Massachusetts et al v. E nvironmental Protection A gency et al , C ase 05
- 1120, decided on April 2, 2007, 5 determined that carbon dioxide is a greenhouse gas that fits the d efinition 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 ye ar, Xcel argued persuasively that it should not be forced to bu y power fro m 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 Capacit y P rice of Mesaba may not be exact, it is an “appropriate prox y f or assessing the overall costs of the pro ject to Xcel and Minnesota ratepay ers.”

· 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 significantl y reduce emissions o ver traditional technologies for the designated emissions”; and

· There are significant operational risks shifted to Xcel and its ratepay ers. 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 Exc elsior Energy Inc. For Approval of a Power Purchase Agreement Under Minn. Stat. Section8

Before proceeding further with potential vendors, Xcel should conduct a careful analysis of the information that is alread y 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. X CEL’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, 200 7 Rocky Mountain News article, that Xcel has alread y s pent $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 I GCC technology “may” have signif icant 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 include d 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 electricit y 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 pa rties to start reviewing the many studies about IGCC in a public forum before Xcel proceeds an y 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. 9 Including the IGCC plant as a “clean energy” resource in a bill that establishes a Clean Energy D evelopment Authorit y r esponsible 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 App roval of Least

- Cost Resources, the Commission provides a review on the merits; a basis for its decision; s ufficient evidence demonstrating why it approved or denied the utility ’s plan; and the prudenc y of its decision. 10

9 Curiously, HB07

- 1150 exempts biomass if it is produced from fossil fuels, but includes IGCC, whic h is made from gasified coal, a fossil fuel. 10 See 4 CCR 723
- 3, Rules 3601 and 3613.10

T he 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 an y i nvestments in such a plant
. See C.R.S. 40
- 2
- 123(2)(e)(1). During the 2006 legislative session, Xcel was an integral pa rt 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 Necessit y, 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 exempt ed from the least

- cost bidding process. In , T he Overview and Purpose of the Least Cost Plan (L CP) states:

“ This process is intended to result in least

- cost resource portfolios, taking into consideration projected sy stem needs, reliability of proposed resources, ex pected generation loading characteristics, and various risk factors. The rules are intended to be neutral with respect to fuel ty pe or resource technology
. ” The LCP process is intended to result in least

- cost resource portfolios. The LCP rules exist to p rotect 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 L east Cost Planning process, the Commission’s role in protecting the public from undu e 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 f acilities 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 ratepay ers, 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 Jul y 2006 Study on IGCC These serious issues deserve scrutin y b y 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 Cost s 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 currentl y 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 b igges t IG CC 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 9 th ye ar, Polk has 82% reliability ; other plants availability was 60
- 78%. (p . 9 );

· O peratin g a gasifier is significantly more complicated when integrated with other p rocesses to produce electricity (p. 11 );12 · IGCC takes several day s for a cold start (p. 16 ) ; and could require 60 start
ups/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 emiss ions, and d uring start

- ups, plants use more coal and therefore emit more pollution (p. 22 );

· Thus, e mission rates could increase an average of 38% due to start

- up/shut down events (p. 23 );

· The CO2 capture/removal sy stem 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 si milar for primary pollutants (p. 31 ). Mr. Jenkins testimony is included a s 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 recentl y i ntroduced 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.206913

and is the most carbon

- intensive of all f ossil 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 M any 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 (“AL Js”) rejected Excelsior Energy ’s petition for a Purchase Power Agreement (PPA) for a 600 MW I GCC plant located near Taconite , MN, hereafter referred to as the “Minnesota IGCC” plant. In that docket, the AL Js 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 significantl y reduce either nitrogen oxides or mer cury , it did not quali fy as a “Clean Energy Technology” under Mi nn. 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 p lants. 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 M PUC 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 an y 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 o f 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 man y ex cellent reports on CCS, including the attached July 2006 EPA report, included here as Attachment 3
. IGCC without carbon capture and storage will significantl y 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 captu re the CO2 significantl y r educes 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 AL J’s decisio n in the Mesaba IGCC decision 16 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, Determin ation 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 pos sible consideration to the cost

effective implementation of new clean energy ...in its consideration of generation acquisitions...bearing in mind the beneficial contributions...to Colorado’s energy securit y, economic prosperity, environmental protection, and insu lation 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 fue l 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 hy

brid 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 Comp lainants 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, ar e that the CSP potential is enormous, the technology can be made dispatchable with either thermal storage or through hybridization with fossil fuel plants. 18 S ee Attachment 6, letter dat ed April 27, 2007, from Colorado Representative Judy Solano et al.16

2. Continue to seek way s to promote the deplo ym ent of Concentrating Solar Power in Colorado per the request of Colorado’s legis lators. 19 ) Dated May 3, 2007. Respectfully submitted,

____________________ _________ Nancy LaPlaca 4801 W. Yale Ave. Denver CO 80219 nancylaplaca@y ahoo.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 copie s 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 L ogan, OL2 Denver, CO 80203 And have hand

- delivered, mailed or e

- mailed copies to the follow ing: Ms. Paula M. Connelly , Esq. Christopher M. Irb y, Esq. Xcel Energy Services. Assistant Attorney General 1225 17th St. Ste. 900 1525 Sherman St., 7 th Floor Denver, CO 80202 Denver CO 80203 paula.connell y@x celenergy .com Chris.irby @state.co.us Mr. Dale Hutchins Chere Mitchell Colorado Office of the Attorney General chere.mitch ell@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., 7 th Floor Denver CO 80203 Stephen.southwick@state.co.us P.B. Schechter Rate/Financial Anal ys t 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 availabl e 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 Read ing Room to view or receive a copy of this docu ment. 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.govLBNL- 57768 

# Leakage and Seepage of CO 2

# from Geologic Carbon Sequestration Sites: CO 2

# 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 Re search and Development Agreement (CRADA) between BP Corporation North America, as part of the CO 2Capture Project (CCP) of the Joint Industry Program (JIP), and the

U.S. Department of Energy thr ough 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.CO 2Seepage 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 em ployees, makes any warranty, express or implied, or assumes any legal liab ility 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 constituteor 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 Unite d States Government or any agency thereof.CO 2Seepage 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 CO 2and CH 4 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. CO 2Leakage 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 CO 2 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. CO 2 Flow and Transport in Water .....................................................................................31 Acknowledgments ................................................................................................................ ........32 Nomenclature ................................................................................................................... ............33 References..................................................................................................................... ................34 Figures........................................................................................................................ ...................39CO 2Seepage into Surface Water

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DRAFT 5 Rev. 1.2 

### LIST OF TABLES Table 2.1. Definitions of te rms used in this report. ......................................................................11 Table 2.2. Factors favoring ebullition and dispersion. .................................................................12 Table 4.1. Fluid properties for the anal ysis 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 P zvalues...................................................27 Table 4.4. Precentage of flux by bullition for CO 2 and CH 4 . .......................................................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 su rface-water environments .................................................................41 Figure 2.4. Phase diagram for CO 2 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 CO 2 bubble. .........................................................................45 Figure 4.4. Log 10u b 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 CO 2 in water and various brines as a function of depth........................48CO 2Seepage into Surface Water

DRAFT 6 Rev. 1.2 This page left intentionally blank.CO 2Seepage into Surface Water

DRAFT 7 Rev. 1.2 

### ABSTRACT Geologic carbon sequestration is the captu re of anthropogenic carbon dioxide (CO 2 ) and its storage in deep geologic formations. One of the concerns of geologic carbon sequestration is that injected CO 2 may leak out of the intended storage formation, migrate to the near-surface environment, and seep out of the ground or into su rface water. In this research, we investigate the process of CO 2 leakage and seepage into saturated sediments and overlying surface water bodies such as rivers, lakes, wetlands, and con tinental shelf marine environments. Natural CO 2 and CH 4 fluxes are well studied and provide insight in to the expected transport mechanisms and fate of seepage fluxes of similar magnitude. Also, natural CO 2 and CH 4 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 CO 2 overturned and degassed with le thal effects. Standard bubble formation and hydrostatics are applicable to CO 2 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 insaturated 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 for ces dominate and gas transport tends to occur as channel flow rather than bubble flow. For coarseporous media such as gravels and coarse sand, buoyancy dominates and the maximum bubble rise velo city is predicted to be approximately 18 cm s -1 . Liquid CO 2 bubbles rise slower in water than gaseous CO 2 bubbles due to the smaller density contrast. A comparison of ebullition (i.e., bubble formation) and resulting bubble flow versus dispersive gas transport for CO 2and CH 4 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 bodi es. The solubility of th e gas species in water plays a fundamental role in whether ebullition o ccurs. We used a solubility model to examine CO 2 solubility in waters with varying salinity as a function of depth below a 200 m-deep surface water body. In this system, liquid CO 2is stable between the deep regions where supercritical CO 2 is stable and the shallow regions where gaseous CO 2 is stable. The transition from liquid to gaseous CO 2 is associated with a large change indensity, with corresponding large change in bubble buoyancy. The solubility of CO 2 is lower in high-salinity waters such as might be encountered in the deep subsurface. Therefore, as CO 2 migrates upward through the deep subsurface, it will likely encounter less saline water with increasing capacity to dissolve CO 2 potentially preventing ebullition, depending on the CO 2 leakage flux. However, as CO 2 continues to move upward through shallower depths, CO 2 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 CO 2 and related risk of dangerous rapid discharges. Future research efforts are needed to increase understanding of CO 2leakage and seepage in surface water and saturated porous me dia. For example, we recommend experiments and field tests of CO 2 migration in saturated systems to formulate bubble-driven waterdisplacement models and relative permeability functions that can be used in simulation models.CO 2Seepage into Surface Water

DRAFT 8 Rev. 1.2 This page left intentionally blank.CO 2Seepage into Surface Water

DRAFT 9 Rev. 1.2 

### 1. INTRODUCTION Geologic carbon sequestration is th e capture of anthropogenic CO 2 and its storage in deep underground formations such as depleted oil and ga s reservoirs and deep brine-filled formations. The anthropogenic CO 2 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 CO 2 to mitigate potential climate change associated with the role of CO 2 as a greenhouse gas. One of the key issues associated with geol ogic carbon sequestration is the integrity of the geological reservoir with respect to containment of CO 2 for a significant although yet-to-bedefined time frame so that the strategy se rves the intended purpose of reducing net CO 2 emissions. An additional concern is that leaking CO 2 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 CO 2 leakage and seepage in the nearsurface environment (Oldenburg and Unger, 2003; 2004) . In this previous work, we focused on CO 2 migration in the vadose zone of on-shor e 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-shor e projects are being discussed. Furthermore, CO 2 may seep into surface waters in on-shore envi ronments prior to influencing the vadose zone or atmospheric surface layer. Consequently, there is a need to investigate CO 2 leakage and seepage in areas where CO 2 will seep into surface waters suchas rivers, lakes, wetlands, and oceans in order to understand HSE risks in these environments. To evaluate surface-water effects on CO 2leakage and seepage, the following key research questions must be addressed: (1) What are the physical processes relevant to CO 2 migration through sediments and overlying surface water either as bubbles or as a dissolved component in water? (2) Does surface water attenuate or enhance CO 2 seepage flux? (3) Under what conditions can CO 2 concentrations build up at depth and lead to the potential for catastrophic release? This project focuses on CO 2 seepage at relatively low fluxes in which liquid water is the connected phase and the CO 2 exists either in discrete bubbles or as a dissolved component in the aqueous phase. As will be shown, CO 2in bubbles can be in gaseous, supercritical, and even liquid phases depending on the pressure and temp erature 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 orde r 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 th e state of knowledge of the transport of CO 2 through surface-water bodies and to a lesser extentthrough 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 CO 2 seepage into surface water and subsequent bubble flow and transport on poten tial leakage and seepage fluxes from geologic carbon sequestration sites. This project was unde rtaken with a very limited budget and within a short time frame, and is therefore necessarily limited in scope.CO 2Seepage into Surface Water

DRAFT 10 Rev. 1.2 

### 2. DEFINITIONS AND ENVIRONMENT 2.1. Terminology In this section, we discuss terminology and defin itions to formalize the later discussion in the report. Table 2.1 shows key terms, definitions, and examples that apply to CO 2 leakage and seepage from geologic carbon sequestration sites, and the associated form of transport of CO 2in 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 CO 2 in the surface water tend to favor dispersion, since bubbles will tend not to form. In contrast , relatively high fluxes and low solubility of CO 2 tend to favor ebullition and bubble flux upward. S econdary features such as bottom topography may also affect ebullition and dispersion by f acilitating density-driven flow and associated mixing. We present in Fig. 2.1 a schematic of the various ways that CO 2seepage can occur from subjacent sediments to overlying surface water, w ith emphasis on the terminology of the process that occurs upon transition between these two envir onments. 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 sedime nt-water interface occurs by the process of ebullition
. Ebullition at the sediment-water interface could occur if CO 2 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 fl ux in both the sediments and the surface water. In the third column, transport is by advection a nd diffusion in both media. And finally, in the fourth column, transport is by bubble flux in th e 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 wh ere the groundwater is warmer than the surface water, in which case CO 2 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 CO 2 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 (Iliu ta 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 th is regime: (1) discrete bubbles, and (2) channel flow. If the gas flux is low, gases can migr ate upward through pore bodies and throats as small individual bubbles, with deformation and blockageoccurring as controlled by solid matrix grains (Fig. 2.2a). In contrast, when the flux is larg e, 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 betw een 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 pressu re-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 visc osity. Further details on bubble flow in porous media are presented in Sections 4.3 and 4.4.CO 2Seepage 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. CO 2 escaping from the containment reservoir through an unrecognized permeable fault. Seepage Migration across a boundary such as the ground surface or into surface water. CO 2 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. CO 2 or CH 4 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 CO 2or CH 4 in sediments below wetlands can reach supersaturation causing exsolution of gas bubbles. Bubble flux Flux of component as transported in discrete bubbles. CO 2 in bubbles moving buoyantly upward in surface water. Dissolution Uptake of volatile components into solution in the liquid phase. Carbonation of water produces CO 2 in solution in fresh water, as in carbonated drinks prior to degassing. Advection Component transport driven by movement of a phase containing the component. CO 2 dissolved in water is transported along with the flowing water. Diffusion Component transport driven by concentration gradients within a phase. Biogenic CO 2 or CH 4 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. CO 2 or CH 4 transported by turbulent motions and molecular diffusion induced by tidal flushing in wetlands.CO 2Seepage 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 ... CO 2seepage flux Large, focused High leak age 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, s eas Sloping, with relief Rivers, lakes 

### 2.2. Environment of Interest The focus of this report is on CO 2 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 CO 2 transport. We consider the existence of nonspecific leakage pathways upward from the deep CO 2 injection horizons as being capable of delivering CO 2 to the shallow environment. These leakage pathways could be along faults or fault zones, but we assume that by the time the CO 2 reaches the shallow sediments below surface water, the CO 2 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 perspec tive 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 (Sigurdss on 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, CO 2 can be in gaseous, supercritical, or liquid conditions. As shown in the phase diagram for pure CO 2 (Fig. 2.4), CO 2 has a critical point of 73.8 bars and 31.0 o C, 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 weCO 2Seepage 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, CO 2 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-stab ility 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 whenthere is surface water, and this causes the P-T path to intersect part of the liquid fi eld. 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 CO 2 or vice versa is associated with strong changes in density, viscosity, and solubility with implications for CO 2 seepage into surface water as will be discussed in Section 4.6. 

### 3. NATURAL CO 2

### AND CH 4

### FLUXES 3.1. Introduction CO 2 leakage from geologic carbon sequestration site s, should it occur, will be superimposed on gas fluxes originating from a variety of bi ological and hydrological processes and sources. Numerous studies have been conducted to measure natural CO 2 and CH 4 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 fluxe s with respect to the problem of detecting CO 2 leakage and seepage (Oldenburg and Lewicki, 2004). Below, we present a review of natural CO 2 and CH 4 fluxes relevant to developing an understanding of CO 2 leakage and seepage into surface water. 

### 3.2. Groundwater Recent studies have quantified the flux of CO 2 derived from deep crustal and mantle origin that is dissolved and transported by shallow groundwat ers (e.g., Evans et al. 2002; Chiodini et al., 1999 and 2000). For example, throughout Tyrrhen ian Central Italy, widespread non-volcanic CO 2 degassing (likely originating from a crus tally-contaminated mantle or a mixture of magmatic and crustal components) occurs from vent and diffuse soil gas emissions and from CO 2 -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 form s gas reservoirs from which gas may escape to the surface. Carbon dioxide is then releasedto the atmosphere either directly through gas emissions or by dissolution in groundwaters and subsequent release at surface springs. Measured CO 2 partial pressure ( P CO2 ) 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 CO 2degassing. Chiodini et al. (1999, 2000) found that in geogr aphic regions characterized by thick regional carbonate aquifers, most or part of the deeply de rived gas is dissolved by the aquifers, whereas inCO 2Seepage into Surface Water

DRAFT 14 Rev. 1.2 regions characterized by small aquifers, these a quifers cannot dissolve a large quantity of the CO 2 and extensive vent and soil CO 2 emissions occur at the surface. Chiodini et al. (2000) used mass balance equations coupled with carbon isot opic analyses and hydrologic data to estimate the flux of deeply derived CO 2 into the aquifers. These authors estimated deeply derived CO 2 fluxes up to 0.29 g m -2 d -1 into the carbonate Apennine aquifers. For high P CO2 waters, the CO 2 flux lost to the atmosphere is of the same order of magnitude as the influx of deep CO 2 . Evans et al. (2002) conducted a chemical, isotopi c, 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 10 4 tonnes y -1 of magmatic carbon (as CO 2 ), indicating that these waters have th e ability to dissolve and transport large quantities of deeply derived CO 2 . They also interpreted the 1 x 10 5 tonnes CO 2y -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 CO 2 leakage from a geologic carbon storage reservoir. Here, CO 2 of deep-crustal origin leaks from numerous storage reservoirs (high P CO2 shallow aquifers) along faults to the surface. An important loss of CO 2 to the atmosphere occurs as groundwaters discharge as springs at the surface and CO 2 degasses, as is evidenced by continual bubbling of CO 2 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 CH 4 in wetlands (e.g., Harriss and Sebacher, 1981; Wilson et al ., 1989; MacDonald et al., 1998; Walter and Heimann, 2000; Rosenberry et al., 2003; Christense n et al., 2003) because these regions contain large quantities of stored organic carbon that, if released as CH 4 , may strongly influence global climate. Wilson et al. (1989) showed from repeated measurements of CH 4 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 CH 4 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 p eatland in northern Minnesota, USA, which indicated that the peatland was overpressured atdepth 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 te mperature, 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 CH 4 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).CO 2Seepage into Surface Water

DRAFT 15 Rev. 1.2 

### 3.4. Rivers Smith et al. (2000) measured both diffusive and bubbling CH 4 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 CH 4 fluxes were also observed, due primarily to seasonally fluctuating water levels. The diffusive CH 4 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), CO 2 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 CH 4 and CO 2 in lakes and reservoirs (e.g., Si gurdsson et al., 1987; Oskarsson, 1990; Giggenbach, 1990; Giggenbach et al., 1991; Kelle r and Stallard, 1994; Woods and Philips, 1999; Casper et al., 2000; Joyce and Jewell, 2003). In non-volcanic/magmatic lake environments, CO 2 and CH 4 are primarily derived from biologic processes. The primary pathways of gas exchange between water and the atmosphere are molecu lar diffusion across the air-water interface and ebullition from the sediment through the wate r column. Pathways of exchange of CO 2and CH 4 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 CH 4 in water is about an order of magnitude less than that of CO 2(20 o C), elevated CH 4 concentrations at depth lead to bubbl e formation, whereas elevated aqueous CO 2 concentrations can build up at depth. Many lakes are supersaturated with respect to CO 2 , particularly in the wintertime, when productiv ity, and therefore photosynthetic uptake, is low. Ebullition is the primary release mechanism of methane from lakes and other shallow water environments (i.e., where CH 4 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 bo ttom 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 CO 2 and CH 4 concentration gradients with depth in a small freshwater lake in the U.K. and determined the diffusion and ebullition fluxes of CH 4 and CO 2 to the atmosphere. They found that ebullition accounted for 96% of the CH 4 flux and diffusion accounted for 99% of the CO 2 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 CH 4 flux and also observed temporal correlation of bubbling across sites in the lakes. They proposed a physical model re lating 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 theCO 2Seepage into Surface Water

DRAFT 16 Rev. 1.2 quantity of the free gas in the sediments availabl e 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 CO 2 in lakes in volcanic/magmatic environments, due to the lethal gas bursts th at 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 CO 2 -rich lake waters (derived from emission of magmatic CO 2 into the lakes) and subsequent large-scale CO 2 ebullition. Lakeoverturn has been suggested to be caused by wind-driven mixing, precipitation, and landslides. However, the viability of these triggering mechan isms has remained unclear. Regardless of this uncertainty, these lakes displayed density stratification and within the deep anoxic stagnant layers, P CO2 built up to equal the ambient hydrostatic pressure (Sigurdsson et al., 1987; Oskarsson, 1990; Giggenbach, 1990). Under normal conditions, CO 2 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 CO 2 -rich deep waters and nucleation of CO 2 in the deep water. The resultant ebullition led to the gas bursts at the surface (Sigurdsson et al., 1987; Oskarss on, 1990; Giggenbach, 1990). In the Lake Nyos event, 240,000 tonnes of CO 2 were lost from the upper 100 m of the lake (Giggenbach, 1990). Giggenbach et al. (1991) showed that other CO 2 -rich lakes worldwide (Laacher See, Germany, Dieng, Indonesia, and Mt. Gambier, Austra lia) display similar chemical and physical characteristics to Lakes Nyos and Monoun. In general, seasonal overturn, other periodic deep mixing processes, or man-made degassing sche mes (e.g., Halbwachs et al., 2004) are needed to prevent density stratification and th e potential for extreme buildup of CO 2 at depth in lakes subject to CO 2 influxes at depth. 

### 3.6. Marine Environments Hoveland et al. (1993) presented a review of CH 4 degassing from shallow marine sediments worldwide and estimated the global flux. Ba sed on geophysical mapping, visual observations, and geochemical sampling, CH 4 occurs at aqueous saturation c oncentrations and in free gas form at many locations in the upper layers of mari ne sedimentary basins (Hoveland et al., 1993 and references therein). This CH 4 originates either from microbial degradation of organic material in shallow sediments or at greater depth in sedime ntary basins (> 2 km) by thermal “cracking” of organic materials to form petroleum hydrocar bons. 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 ga s (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 m 2 area have been observed. At Cape Lookout Bight, a marine basin on the Outer Banks of North Carolina, USA, shallow sediment pore wate rs 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 theCO 2Seepage into Surface Water

DRAFT 17 Rev. 1.2 bubbles here is lost to solution during tr ansit through the water column and ~6.9 x 10 7 g CH 4 yr -1 are lost to the atmosphere. Perhaps the most well studied and quantif ied 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 10 5 m 3 d -1 (18 km 2 area). Leifer et al. (2000) measured the bubble gas partial pressures, dissolved gas and oil, and fluid motions within the rising bubble streams of shallo w (<70 m) seeps. They found that near-surface aqueous methane concentrations were >10 8 times greater than atmospheric equilibrium values. Also, they demonstrated how large seeps can modify the local environment by generating upwelling flows, turbulence, and saturating th e water contained within the bubble plume with CH 4 . 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 fl ow 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% ar ound 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 th ese observations, where gas bubbles are released from small pores at low pressures but at high pressures, ebullition is inhibited. 

### 4. CO 2

### 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 su rface 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 ( P st):

st z i i i P P H C P + > = 

## ∑ (4.1) where H i 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 zis given by P z = P A + ρ w g z (4.2) where ρ wis water density, g is gravity, and P A is atmospheric pressure. A schematic of the radially outward surface forces and the tangential surface tension forces on a neutrally buoyantCO 2Seepage into Surface Water

DRAFT 18 Rev. 1.2 single bubble is shown in Fig. 4.1. The P st 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

z st P P r P

− = = σ 2 (4.3). Surface tension for water is approximately 72 dynes cm -1 (0.072 N m -1 ), which means that P st is negligible relative to Pzfor bubbles with radius larger than approximately 150 μ m (0.15 mm) for which 2 σ/r ~ 0.1 bar (e.g., Leifer and Patro, 2002). The surface tension pressure ( P st) 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-pha se solubility) of each species and the water composition. This relationship of ebullition to solubility is a key factor in CO 2leakage because waters with varying solubility due to differe nt salinity and temperature may be encountered during the long rise upward of CO 2bubbles. The solubility and buoyancy of CO 2over 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, F i , is expressed as: ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

− = = i Bi i Bi i i H P C r q dt dN F 2 4

π , (4.4) (e.g., Leifer and Patro, 2002) where N i is the molar content of gas species iin the bubble, qBiis the individual bubble gas transfer rate, and P Biis 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 - P Bi

/H i(e.g., Leifer et al., 2000). Ther efore, gas outflows from the bubble when Ci < P Bi

/H iand inflows when Ci > P Bi

/H i . In the case of a bubble composed predominantly of CO 2 , it will dissolve as CO 2outflows and grow as di ssolved air (primarily N 2and O 2 ) and/or CO 2inflow. If for example, C CO 2is elevated due to bubble dissolution, the gas outflow from the bubble is decreased. If concentrations of dissolved O 2and N 2in the water column are low, inflow will be reduced and di ssolution will occur. With rise through the water column, CO 2may dissolve and the bubble may shrink, increasing P ST as the bubble radius decreases (see Eq. 4.3). Also, bubble expansion will occur due to decreasing Pzand associated gas expansivity. Upon rising and increasing in size, the larger bubble w ill be able to transfer gas more efficiently because of the increased surface area. The to tal 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 bubbl e in question is a gas bubble. However, for applications involving CO 2rising from the deep subsur face during potential leakage from geologic carbon sequestration sites, the CO 2can be in either a supercritical or liquid phase as well as a gas phase, depending on pressure and te mperature (see Section 4.5, below). Much of the above fundamentals apply also for these cases in which the bubble contains supercritical or liquid phase CO 2 , in which case we would refer to an e quilibrium between species that paritition between the two liquid phases, aqueous and CO 2 .CO 2Seepage 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 de pth divided by the bubble rise velocity. The velocity of bubble rise is often given by Stoke’s law: ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

− = w g w g d v μ ρ ρ

18 2 (4.5) where d is bubble diameter, ρ wand ρ g are water and gas density, respectively, and μ wis water viscosity. By this well-known equation, the bubble velocity is directly related to the square of bubble diameter. Therefore, as Pzdecreases, d increases and bubbles accelerate. However, Eq. 4.5 is only valid at very small Reynolds number (Re = ρ w v d / μ

w< ~1) corresponding to either very small bubble size, small buoyancy contra st, or a very viscous liquid. For CO 2bubbles in surface water, Re is of order 1 wh en 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 inFig. 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 th e rate of bubble rise in water has a maximum of approximately 30 cm s -1 which is reached when the bubble di ameter is approximately 1.5 mm ( r = 0.75 mm). Bubbles are known to begin oscillati ng 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 CO 2gas 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 CO 2(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 CO 2bubbles. 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 bubbl e 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 processe s that block bubble flow (e.g., Wan et al., 2003). Bubble rise in porous media is therefore signi ficantly 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 asCO 2Seepage into Surface Water

DRAFT 20 Rev. 1.2 

# ( ) σ ρ ρ 2 Bo p g w r g − = (4.6) (e.g., Brooks et al., 1999) where r p 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 ρ w , ρ

g , 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 por e 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 eff ects. 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 for ces 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-o ff 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 theore tical 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 CO 2bubble rise velocity in porous media for both gaseous and liquid CO 2 . We note that this analysis is valid onl y 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 st eady-state, the upward buoyancy forces are exactly balanced by the surface tension and drag forces th at tend to retard motion. These forces can be written as the buoyancy force, given byCO 2Seepage into Surface Water

DRAFT 21 Rev. 1.2 

# ( ) 3 3 4 b g f b R g F π ρ ρ − = (4.7), the surface tension force given by F

st = 2 π R ' σ sin θ (4.8), where R’ is an equivalent pore throat radius, and the drag force is given by 

## ( ) ( ) 3 3 2 3 2 2 3 4 1 75
. 1 1 150 b p b g p b b d R n d n

u n d n u A F π ρ μ ⎥ ⎥ ⎦ ⎤ ⎢ ⎢ ⎣ ⎡

− + − = (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 th ese three forces and allowing for acceleration of the bubble, we have the balance relation ⎟ ⎠ ⎞ ⎜ ⎝ ⎛ ∂ ∂ + ∂ ∂ = − − x u u t u R A F F F b b b b g d st d b 3 3 4 π ρ (4.10) where the A d term accounts for entrained liquid ahead of the bubble and is defined as

g f M d C A ρ ρ + = 1 (4.11). Substituting the individual force equations and grouping terms by the powers of bubble rise velocity ( u b ), we obtain 

# ( ) x u u t u C u C u C b b b b b ∂ ∂ + ∂ ∂ = + + − 3 2 2 1 (4.12) where 

## ( )
d p A

n d A n C 3

1 1 75
. 1

− = (4.13) 

## ( )
d g p b A n d A n C ρ μ 3 2 2 2 1 150

− = (4.14)
C 3 = 1 ρ

g A d 3 2 R ' σ sin θ R b

3 − ρ f − ρ g 

# ( )g ⎡ ⎣ ⎢ ⎤ ⎦ ⎥ (4.15). The rise velocity ( u b ) 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 term s in the above equations are given in Table 4.1, where we have included some additional sedime nt particle sizes and porosities to extend the method toward finer grain sizes than the 4 mm gl ass 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 inte rested readers to Corapcioglu et al. (2004) for further information.CO 2Seepage into Surface Water

DRAFT 22 Rev. 1.2 We have calculated bubble rise velocities for th e 4 mm glass beads of Corapcioglu et al. (2004) and two slightly finer grain sizes ( d p = 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 (E q. 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 ( d p = 4 mm, 2 mm, and 1 mm) for air and CO 2gas bubbles, along with the calculated rise velocity for a CO 2liquid 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 CO 2bubble is predicted to rise sligh tly slower than the air bubble, but that CO 2bubbles are predicted to rise slightly fast er than air bubbles for the less-coarse media. This cross-over effect is due to th e greater buoyancy of air relative to CO 2and its importance in coarse media, and the greater importance of the lower viscosity of CO 2relative to air in finer media. Note finally that CO 2liquid bubbles rise more slowly due to their greater density and viscosity than CO 2gas bubbles. The main conclusion of this analysis is that the density contrast between air and CO 2is 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 CO 2density is much larger and liquid CO 2bubbles 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.CO 2Seepage 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 μ w 1 x 10 -3 kg m -1 s -1 Density of water ρ w 1000. kg m -3 Viscosity of air μ g 1.80 x 10 -5 kg m -1 s -1 Density of air ρ g 1.2 kg m -3 Viscosity of CO 2 Gas (1 bar, 20 o C) Liquid (61 bars, 22 o C) μ g μ

l 1.47 x 10 -5 6.33 x 10 -5 kg m -1 s -1 kg m -1 s -1 Density of CO 2 Gas (1 bar, 20 o C) Liquid (61 bars, 22 o C) ρ g ρ

g 1.8 755.2 kg m -3 kg m -3 Gravitational accel. g 9.81 m s -2

Additional mass A d 1

-

Fit parameter A 26.8 -CO 2Seepage 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 beads 1 Gravelly sand 2 Coarse sand 2 Porosity n - 0.3954 0.3 0.35 Particle size d p m 4 x 10 -3 2 x 10 -3 1 x 10 -3 Bubble radius R b 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 CO 2Gas CO 2Liquid u b u b u b 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/ABurkePlummer Permeability k m 2 1.80 x 10 -8 1.47 x 10 -9 6.76 x 10 -10

2de 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 cons ider a surface-water system consisting of air (N 2and O 2 ), CO 2 , and CH 4 similar to that described by More l and Herring (1993). If seepage of CO 2and/or CH 4 occurs across the sediment surface at depth zinto 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 (CO 2 , CH 4 , air, H 2 O) at Pz , i.e., we neglect P st , (2) bubbles rise so fast through the water column to the surface that no di ssolution occurs, (3) transport of all solutes in the water column is described by a dispersion coefficient (D = 10 -3 cm 2s -1 ), and (4) chemical reactions (e.g., bicarbonate formation from CO 2 , oxidation of CH 4 ) 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:CO 2Seepage 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 sp ecies together. A steady-state mass balance equation is written for each species at the sedi ment surface where the su m of its transport by diffusion and ebullition is equal to its rate of formation at depth: 

## [ ][ ] 

## ( ) [ ] m P CO EK CO CO z D z b CO s b = + − − − 1 2 1 2 2 2 (4.18) 

## [ ][ ] 

## ( ) [ ] m P CH EK CH CH z D z b CH s b = + − − − 1 4 1 4 4 4 (4.19) 

## [][] ( ) 

## [ ] 0 = + − z air b s b P K air E air air z D (4.20) where the subscripts b and s refer to the bottom and surface concentrations (mol cm -3 ), respectively, and K iis 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 di ffusive 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 surf ace are calculated to be in equilibrium with the atmosphere at 10 o C, where P CO2 atm , P air atm , andP CH4 atm= 3.12 x 10 -4 , 1.97 x 10 -6 , and 9.87 x 10 -1 atm, respectively (see Table 4.3 for K i values): [ CO 2 ] s=P CO2 atmK CO2 (4.21) [ CH 4 ] s= P CH4 atmK CH4 (4.22) [ air] s=P air atmK air

(4.23) Unknowns in mass balance equations are now bottom concentrations and E . The pressure condition at the sediment surface is: P air + P CH4+ P CO2 + P H2O= Pz (4.24) We can neglect PH2Oin Eq. 4.24 relative to the other volatile components and substitute Henry’s law expressions to obtain 

## [ ] [ ] [ ]
z airb CH b CO b P K air K CH K CO = + + 4 4 2 2 (4.25) where K ivalues are for the Pz considered (Table 4.3). With the approximations [CO 2 ] s << [CO 2 ] b and [CH 4 ] s << [CH 4 ] b , bottom concentrations from Eqs. 4.18-4.20 are substituted into Eq. 4.25 to yield: 

## [ ]
z z air s z CH z CO P P E z D K air z D P E z D K m P E z D K m = + + + + + / / ) / ( / / / / 4 2 (4.26) By neglecting the first term in Eq. 4.26 and replacing K CH4 and K air

with an average K value, an approximate solution for E can be obtained:CO 2Seepage into Surface Water

DRAFT 26 Rev. 1.2 

## [ ] z KD P air z D m E 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 / − − + ≅ z CO b P EK z D m CO (4.28) 

## [ ] 1 1 4 4 / − − + ≅ z CH b P EK z D m CH (4.29) 

## [ ] ( ) 

## [ ] 1 1 / /

− − + ≅ z air s b P EK z D air z D air (4.30) The diffusive and ebullition fluxes, F Dand F E , respectively, of CO 2and CH 4 can then be calculated: 

## [ ][ ] 

## ( ) s b D CO CO CO z D F 2 2 2 −

= (4.31) 

## [ ][ ] 

## ( ) s b D CH CH CH z D F 4 4 4 −

= (4.32) 

## [ ] 1 2 1 2 2 − − = z b CO E CO P CO EK F (4.33) 

## [ ] 1 1 4 4 4 − − = z b CH E CH P CH EK F (4.34) We calculated F Dand F E

for (1) CO 2and CH 4 where seepage of CO 2and CH 4 occurs into a surface water body and m CO2 = m CH4 , (2) CO 2where only seepage of CO 2 occurs, and (3) CH 4 where only seepage of CH 4 occurs. In each of these cases (C ases 1-3), we consider a water body with z= 50, 1000, and 10000 cm, low, medium, and high m CO2 and/or m CH4values (see Table 4.4 for m CO2 and m CH4values), and calculate the percent e bullition 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 seep age fluxes calculated in our prior vadose-zonerelated work (Oldenburg and Unger, 2003; 2004) . For comparison, natural fluxes of CO 2from plant and soil biological processes are approximately 10 -9 mol cm -2s -1 (10 μ mol m -2 s -1 ) efflux to 3 x 10 -9 mol cm -2 s -1 (30 μ mol m -2s -1 ) uptake (e.g., Baldocchi and Wilson, 2001). We present results for both CO 2and CH 4 to demonstrate the contrast intheir 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 CO 2to the atmosphere in water bodies up to 1000 cm deep and for m CO2 up to the medium values considered. At greater m CO2 or z , CO 2is transported to the atmosphere almost entirely by ebullition. For CH 4 , diffusion is only an important transport mechanism for shallow (50 cm) water bodies and low m CH4 , accounting for about half the total CH 4 flux. For cases where CH 4 seeps into deeper water bodies of ( z= 1000 and 10000 cm) or m CH4is elevated, ebullition accounts almost entirely for the CH 4 flux to the atmosphere. These differences between ebullition and diffusion fluxes for CO 2and CH 4 are due to the greater solubility of CO 2in water, relative to CH 4 . In short, ebullition and bubble transport dominate the transport of sparingly soluble species.CO 2Seepage into Surface Water

DRAFT 27 Rev. 1.2 Table 4.3. Henry’s law coefficients ( Ki ) for different P zvalues (Spycher, unpublished code). z (m) Pz (atm) K CO2 (mol atm -1 cm -3 ) K CH4 (mol atm -1 cm -3 ) K ai r (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 10 o C. K ai r

is the average of K N2 and K O2 . Table 4.4. Percentage of flux by ebullition relative to diffusion for CO 2 and CH 4at various depths and flux proportions. Case z (cm) m CO2 (mol cm -2s -1 ) m CH4 (mol cm -2s -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 100CO 2Seepage into Surface Water

DRAFT 28 Rev. 1.2 

### 4.6. Transport of Dissolved CO 2

### in Surface Water Transport of the dissolved fraction of CO 2in 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 invol ving a wide range of chaotic flow velocities over a range of length scales which lead to eff ective dispersion and mixing of dissolved species. Dispersion and mixing will periodically expose su rface water to the atmosphere where it will potentially equilibrate with atmospheric CO 2creating an effective outgassing that is equal to the leakage and seepage flux at the bottom at steady st ate. In lakes, mixing may be somewhat less than in rivers or coastal environments and ve rtical mixing may occur onl y 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 CO 2 -saturated water is approximately 1% greater than that of pur e water (Ennis-King and Paterson, 2003), creating the possibility of dissolved CO 2producing 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 stratificati on 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 CO 2occurring as a dissolved com ponent. 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 CO 2leakage and seepage in surface water. 

### 4.7. Effects of Pressure, Temp erature, and Salinity on Ebullition As shown by the differences in ebullition flux between CO 2and CH 4 calculated in Section 4.5, the solubility of the volatile species is a fundamental control on ebullition. The solubility of CO 2 is a strong function of salinity and temperature, both of which may vary within the subsurface and surface waters through which leaking CO 2can migrate. We have calculated CO 2solubility for various H 2 O-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 ρ

H2O= 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 re present hypersaline brines such as might be found in a very deep brine formation, and a typical o ilfield 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 CO 2density profile is calculated from the online NIST Webbook (Lemmon et al., 2004) for pure CO 2at the given pressures and temperatures. The first point to note inFig. 4.6 is that CO 2transitions from supercritical to liquid to gas as it rises upwards in this system. This is in stark c ontrast to the simple change from supercritical to gas (see Fig. 2.4) that occurs in the absence of surface water (Oldenbur g and Unger, 2003). TheCO 2Seepage into Surface Water

DRAFT 29 Rev. 1.2 implication of these phase trans itions is that buoyancy forces on CO 2bubbles 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 CO 2will lead to approximately a factor of 3.7 change involume of the bubble, assuming an isothermal transition, with corresponding increase in upward buoyancy force. The second important point illustrated inFig. 4.6 is the variation in CO 2solubility upward from depth. At intermediate and low salinity, CO 2solubility rises slightly along a bubble migration path upward from depth until the liquid-gas trans ition point (depth equal to –380 m). From this point upward, CO 2solubility declines rapidly as the pressure falls. The implication of this pattern for bubble transport is that CO 2ebullition is favored as dissolved CO 2is 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 CO 2leakage and seepage can traverse formations and surface water with contrasting salinity. For example, consider first the case of a briny groundwater sy stem at depth with overlying fresher aquifers below a freshwater lake. In this case, a rising CO 2bubble would encounter water with progressively higher and higher CO 2solubility, making it likely that CO 2bubbles would disappear as the CO 2dissolved 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 CO 2flux moves upwards. Combinations of the abovetransitions are of course possible, and Fig. 4.6 provides a general guide as to the trend to ward 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 CO 2leakage and seepage into surface water has resulted in the following main conclusions: 1. Numerous investigations have been conducted to measure natural CO 2and CH 4 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 CO 2leakage and seepage fluxes of similar magnitude will behave, and they indicate thatlocal conditions strongly control transport processes. Natural CO 2and CH 4 fluxes and local concentrati ons 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 CO 2outgassing indicate that deep and stagnant conditions are conducive to the formation of waters that are supersaturated with respect to CO 2 . 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 CO 2and associated potentially lethal outgassing events.CO 2Seepage 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 pressure s 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 applicab le 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 CO 2fluxes can be sustained by bubble flow especially in coarse and highl y permeable porous media. For larger CO 2fluxes, or finer porous media, transport is by channel flow. 6. Bubble-rise velocity in porous media ha s 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 CO 2before transitioning to channel flow. CO 2rise 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 CO 2bubble is slower than for a CO 2gas bubble due to the much smaller density contrast between liquid CO 2and water than between gaseous CO 2and water. 8. For the range of seepage fluxes and surface-water depths considered in this study, CO 2 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 CH 4 with lower solubility in water are more likely to be transported by bubble flux. 9. As leaking CO 2rises upwards, liquid-stable CO 2phase conditions may be encountered, especially if there is overlying surface water. Therefore, CO 2rising 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 trans ition from liquid to gas has large changes in properties and these changes favor bubble flow. 10. The solubility of CO 2in water depends strongly on the P , T , and salinity conditions of water and the phase properties of the CO 2 . Leaking CO 2rising from depth through saturated porous media of varying salinity may tend to dissolve and/or undergo ebullition depending on the conditions. In general, CO 2solubility decreases with depth at shallow depths, creating greater potential for ebullition as CO 2rises upward into the near-surface environment. 

### 5.2. Discussion The results of our study allow us to make th e following comments on the key research questions posed.CO 2Seepage into Surface Water

DRAFT 31 Rev. 1.2 (1) What are the physical processes relevan t to the migration through sediments and overlying surface water of CO 2either 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. CO 2transport is likely to be by channel flow in the fine sediments below a surface-water body. These ch annels 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), CO 2bubbles will emanate from the sediment and rapidly rise upwards. Under this scenario, there is no ebullition process since the CO 2already exists as a second phase in the por ous media. Ebullition (i.e., bubble formation) at the interface of sediment and surface water and/or dispersive transport of CO 2seepage from the sediment interface will only occur for seepag e 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 CO 2is transported by motions of the aqueous phase typically driven by gravity, wind, and tidal forcings. (2) Does surface water attenuate or enhance CO 2seepage flux? Rising CO 2bubbles are subject to mass transfer with surrounding waters, but the travel times are relatively short because rise velocities are high. In general, CO 2bubbles, 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 CO 2 , mixing times in surface waters are short relative to geologic CO 2sequestration times, and dissolved CO 2added by leakage and seepage is expected to exsolve rapidly from surface water as it mixe s and equilibrates with atmospheric CO 2 . Thus CO 2seepage flux is not expected to be significantly attenuated by surface water. (3) Under what conditions can CO 2concentrations build up at depth and lead to the potential for catastrophic release? Water becomes slightly denser when it contains dissolved CO 2 . Lakes with deep stagnant regions subject to CO 2fluxes from below are prone to stratif ication with water at depth that is supersaturated with CO 2and subject to rapid outgassing if ther e is a disturbance to the lake that initiates overturn. Natural mixing processe s 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 CO 2buildup in deep stagnant lakes.



### 6. RECOMMENDATIONS FOR FUTURE RESEARCH 6.1. CO 2

### Flow and Transport in Water There are significant research needs in the area of leakage and seepage of CO 2in 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 expe riments invariably result in huge leaps ofCO 2Seepage into Surface Water

DRAFT 32 Rev. 1.2 understanding. We suggest that a small-scale, controlled CO 2release experiment designed to simulate the migration of CO 2upward from a deep source into the near-surface environment be carried out. One variant of the fiel d experiment should be a case in which CO 2bubbles up through saturated sediments into a shallow su rface-water body. In the experiment, the form of CO 2transport through the sediments, its seepage into surface water, and its transport upward through the surface water will be monito red visually along with various geochemical and air sampling approaches. We envision an e xperimental test site could be established to carry out these experiments in concert withthe testing of various surface-monitoring approaches. 2. We have a very limited understanding of how CO 2displaces water in porous media. This issue is relevant from small bubbles migrati ng upward, to channel flow of gas displacing water, to full multiphase flow of CO 2 . We propose that a comprehensive experimental program be established to carry out bubble fl ow and relative permeability measurements of gaseous, supercritical, and liquid CO 2flows 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 CO 2leakage 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 surroundi ng 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 CO 2bubbles rising in surface waters of various types has not been i nvestigated. We suggest that an experimental program be developed to study CO 2bubble mass transfer in surface water. This work would complement the analogous studies of CH 4 bubbles studies (e.g., Leifer and Patro, 2002). 4. The phase transitions and associated enthalpy changes that CO 2undergoes during bubble rise will lead to temperature changes. We s uggest that a simulation study be undertaken to investigate the degree of cooling that will be expected for the phase transitions (e.g., from liquid CO 2in bubbles to gaseous CO 2in bubbles) and related effects. 5. As with ground-surface seepage, geostatistical methods should be investigated for application to surface-water CO 2leakage and seepage monitoring to discern leakage from natural background fluxes. 

### ACKNOWLEDGMENTS We thank Nic Spycher and Karsten Pruess (LBN L) 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 CO 2Capture 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.CO 2Seepage into Surface Water

DRAFT 33 Rev. 1.2 

### NOMENCLATURE A empirical fit parameter - A d additional mass - d

p porous media particle diameter m D Diffusivity and dispersivity m2s -1 E total ebullition rate mol cm -2s -1 F

B buoyancy force N F

D diffusive flux mol cm -2s -1 F

E bubble (ebullition) flux mol cm -2s -1 F

d drag force N F

E 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 -2s -1

n porosity - N

i molar content of gas species imol qBi bubble gas transfer rate of species i mol cm -2s -1 P pressure Pa, atm P CO2 partial pressure of CO 2 Pa, atm P st Surface tension pressure N m -2 Pz hydrostatic pressure Pa, atm
r bubble radius m
r p characteristic length scale of pore mCO 2Seepage into Surface Water

DRAFT 34 Rev. 1.2 R’ equivalent pore throat radius m R b bubble radius m
u b bubble velocity m s -1 V

B bubble velocity in surface water m s -1 z vertical coordinate m ρ

g gas-phase density kg m -3 ρ

f fluid density kg m -3
σ surface tension N m -1 θ contact angle degrees [ ] concentration mol cm -3 

### REFERENCES Anderson, A.L. and W.R. Bryant, Gassy sedime nt occurrence and properties: northern Gulf of Mexico, Geo-Marine Lett., 10 , 209-220, 1990. Baldocchi, D.D., and K.B. Wilson, Modeling CO 2and water vapor exchange of a temperate broadleaved forest across hourly to decadal time scales, Ecological Modelling , 142 , 155-184, 2001. Boles, J.R., J.F. Clark, I. Leifer, and L. Was hburn, Temporal variation in natural methane seep rate due to tides, Coal Oil Point area, California , J. Geophys. Res., 106 , 27,077-27,086, 2001. Brooks, M.C., W.R. Zise, and M.D. Annable, Fundamental changes in in-situ airsparging flow patterns, Ground Water Monit. Rem. , 19 (2), 105–113, 1999. Casper, P., S.C. Maberly, G.H. Hall, and B.J. Finlay, Fluxes of methane and carbon dioxide from a small productive lake to the atmosphere, Biogeochemistry, 49 , 1-19, 2000. Chiodini, G., F. Frondini, D.M. Kerrick, J. Rogie, F. parello, L. Peruzzi, and A.R. Zanzari, Quantification of deep CO 2fluxes from Central Italy. Examples of carbon balance for regional aquifers and of soil diffuse degassing, Chem. Geol., 159 , 205-222, 1999. Chiodini, G., F. Frondini, C, Cardellini, F. Parello, and L. Peruzzi, Rate of diffuse carbon dioxide Earth degassing estimated from carbon ba lance of regional aquifers: The case of the central Apennine, Italy, J. Geophys. Res., 105 , 8423-8424, 2000.CO 2Seepage into Surface Water

DRAFT 35 Rev. 1.2 Christensen, T.R., N. Panikov, M. Mastepanov, A. Joabsson, A. Stewart, M. Oquist, M. Sommerkorn, S. Reynaud, and B. Svensson, Biotic controls on CO 2and CH 4 exchange in wetlands – a closed environment study, Biogeochem., 64, 337-354, 2003. Corapcioglu, M.Y., A. Cihan, M. Drazenovic, Rise velocity of an air bubble in porous media: Theoretical studies, Water Resour. Res. , 40 , W04214, doi:10.1029/2003WR002618, 2004. Ennis-King, J., and L. Paterson, Rate of disso lution due to convective mixing in the underground storage of carbon dioxide, in Ga le, J., and Y. Kaya (eds.), Proceedings of the 6thIntl. Conf. On Greenhouse Gas Control Technologies , Vol. 1 , p. 507-510, 2003. Evans, W.C., M.L. Sorey, A.C. Cook, B.M. Kenne dy, D.L. Shuster, E.M. Colvard, L.D. White, and M.A. Huebner, Tracing and quantif ying magmatic carbon discharge in cold groundwaters: lessons learned from Mammoth Mountain, USA, J. Volcanol. Geotherm. Res., 114 , 291-312, 2002. Fischer, H.B, E.J. List, J. Imberger, and N.H. Brooks, Mixing in Inland and Coastal Waters , Academic Press, New York, 483 pp., 1979. Giggenbach, W.F., Water and gas chemistry of Lake Nyos and its bearing on the eruptive process, J. Volcanol., Geotherm. Res., 42 , 33-362, 1990. Giggenbach, W.F., Y. Sano, and H.U. Schmincke, CO2-rich gases from Lakes Nyos and Monoun, Cameroon; Laacher See, Germany, Die ng, Indonesia, and Mt. Gambier, Australiavariations on a common theme, J. Volcanol. Geotherm. Res., 45 , 3110323, 1991. Goldman, C.R., and A.J. Horne, Limnology , McGraw-Hill, New York, 454 pp, 1983. Halbwachs, M., Sabroux, J.-C., Grangeon, J., G. Kayser, J.-C. Tochon-Danguy, A. Felix, J.-C. Beard, A. Veilleveille, G. Vitter, P. Rishon, A. Wuest, and J. Hell, Degassing the “killer lakes” Nyos and Monoun, Cameroon, Trans. Am. Geophys. Union EOS, 281-285, 85(3), 27 July 2004. Harriss, R.C. and D.I. Sebacher, methane flux in forested freshwater swamps of the southeastern United States, Geophys. Res. Lett., 8 , 1002-1004, 1981. Hornafius, S.J., D. Quigley, and B.P. Luyendyk, The world’s most spectacular marine hydrocarbon seeps (Coal Oil Point, Santa Barb ara Channel, California): Quantification of emissions, J. Geophys. Res., 104 , 20,703-20,711, 1999. Hovland, M., A.G. Judd, and R.A. Burke, Jr., The global flux of methane from shallow marine sediments, Chemosphere, 26 , 559-578, 1993. Iliuta, I, A. Ortiz-Arroyo, F. Larachi, B.P. A. Grandjean and Gwild, Hydrodynamics and mass transfer in trickle-bed reactors: an overview, Chemical Engineering Science , 54(21), pp. 5329-5337, 1999. Ji, W., A. Dahmani, D.P. Ahfield, J.D. Lin, and E.Hill III, Laboratory study of air sparging: AirCO 2Seepage into Surface Water

DRAFT 36 Rev. 1.2 flow visualization, Ground Water Monit. Rem. , 13 (4), 115–126, 1993. Joyce, J. and P.W. Jewell, Physical controls on methane ebullition from reservoirs and lakes, Env. Eng. Geosc., 9, 167-178, 2003. Keller, M.and R.F. Stallard, Methane emission by bubbling from Gatun Lake, Panama, J. Geophys. Res., 99 , 8307-8319, 1994. Leifer, I. And R.K. Patro, The bubble mechanism for methane transport from the shallow sea bed to the surface: A review and sensitivity study, Continental Shelf Res., 22 , 2409-2428, 2002. Leifer, I., J.F. Clark, and R.F. Chen, Modifications of the local environment by natural marine hydrocarbon seeps, Geophys. Res. Lett., 27, 3711-3714, 2000. Lemmon, E.W., M.O. McLinden and D.G. Friend, "Thermophysical Properties of Fluid Systems" in NIST Chemistry WebBook, NIST Standard Reference Database Number 69 , Eds. P.J. Linstrom and W.G. Mallard, Marc h 2003, National Institute of Standards and Technology, Gaithersburg MD, 20899 ( http://webbook.nist.gov)
. Macdonald J.A., D. Fowler, K.J. Hargreaves, U. Skiba, I.D. Leith, and M.B. Murray, Methane emission rates from a northern wetland - response to temperature, water table and transport, Atmos. Environ., 32 , 3219-3227, 1998. de Marsily, G., Quantitative Hydrogeology , Academic Press, New York, 1986. Martens, C.S. and J.V. Klump, Biogeochemical cy cling in an organic rich coastal marine basin. 1. Methane sediment-water exchange processes, Geochim. Cosmochim. Acta, 44 , 471-490, 1980. Morel, F.M.M. and J.G. Hering, Principles and Applications of Aquatic Geochemistry , Wiley, New York, 1993. Oldenburg, C.M., and A.J.A. Unger, On leakag e and seepage from geologic carbon sequestration sites: unsaturated zone attenuation, Vadose Zone Journal , 2, 287-296, 2003. Oldenburg, C.M., and A.J.A. Unger, CoupledVadose Zone and Atmospheric Surface-Layer Transport of CO 2from Geologic Carbon Sequestration Sites, Vadose Zone Journal , 3, 848- 857, 2004. Oldenburg, C.M., J.L. Lewicki, and R.P. Hepple, Near-surface monitoring strategies for geologic carbon dioxide storage verification, Lawr ence Berkeley National Laboratory Report LBNL54089, October 2003. Oskarsson, N., Carbon dioxide bursts of lake Nyos, Cameroon, modeled as a periodic supersaturation in a countercurrent reactor, J. Volcanol. Geotherm. Res., 42 , 307-318, 1990. Pellicer, J., V. Garcia-Morales, and M.J. Herna ndez, On the demonstration of the Young-Laplace equation in introductory physics courses, Phys. Educ. , 35 (2), 2000.CO 2Seepage into Surface Water

DRAFT 37 Rev. 1.2 Roosevelt, S.E., and M.Y. Corapcioglu, Air bubble migration in a granular porous medium: Experimental studies, Water Resour. Res. , 34 (5), 1131–1142, 1998. Rosenberry, D.O., P.H. Glaser, D.I. Siegle, and E. P. Weeks, Use of Hydraulic head to estimate volumetric gas content and ebullition flux in northern peatlands , Water. Resour. Res., 39 , 1066, 2003. Shipton, Z.K., J.P. Evans, B. Dockrill, J. Heath, A. Williams, D. Kirschner, and P.T. Kolesar, Natural leaking CO 2 -charged systems as analogs for fa iled geologic sequestration reservoirs, In: Carbon Dioxide Capture for Storage in D eep Geologic Formations – Results from the CO 2Capture Project, Volume 2: Geologic Storage of Carbon Dioxide with Monitoring and Verification; Elsevier Ltd., 2004a. Shipton, Z.K., J.P. Evans, D. Kirschner, P.T. Kolesar, A.P. Williams, and J. Heath, Analysis of CO 2leakage through “low-permeability” faults fr om natural reservoirs in the Colorado Plateau, east-central Utah, in Baines, S.J., and R.H. Worden (eds.), Geological Storage of Carbon Dioxide , Geol. Soc. London, Special Publications , 233 , 43-58, 2004b. Sigurdsson, H., J.D. Devine, F.M. Tchoua, T.S. Presser, M.K.W. Pringle, and W.C. Evans, Origin of the lethal gas burst from Lake Monoun, Cameroun, J. Volcanol. Geotherm. Res., 31 , 1-16, 1987. Smith, L.K., W.M. Lewis, J.P. Chanton, G. Cr onin, and S.K. Hamilton, Methane emissions from the Orinoco River floodplain, Venezuela, Biogeochemistry , 51 , 113-140, 2000. Spycher, N., J. Ennis-King, and K. Pruess, CO 2 -H 2 O mixtures in the geological sequestration of CO 2 . I. Assessment and calculation of mutual solubilities from 12 to 100 C and up to 600 bar. Geochemica et Cosmochimica Acta , 67, 3015-3031, 2003. Spycher, N, and K. Pruess, CO 2 -H 2 O mixtures in the geological sequestration of CO 2 . II. Partitioning in chloride brines at 12-100 C and up to 600 bar, Lawrence Berkeley National Laboratory Report LBNL-56334 , September 2004. Torp T.A., and J. Gale, Demonstrating storage of CO 2in geological reservoirs: The sleipner and SACS projects, Energy, 29(9-10), 1361-1369, 2004. Walter, B.P. and M. Heimann, A process-base d, climate sensitive model to derive methane emissions from natural wetlands: Application of five wetland sites, sensitivity to model parameters, and climate, Global Biogeochem. Cycles, 14 , 745-765, 2000. Wan, J, S. Veerapaneni, F. Gadelle, T.K. T okunaga, Generation of stable microbubbles and their transport through porous media, Water Resour. Res. , 37(5), p. 1173 (2000WR900331), 2001. Washburn, L., C. Johnson, C.C. Gotschalk, and E.T. Egland, A gas-capture buoy for measuring bubbling gas flux in oceans and lakes, J. Atm. Ocean. Technol., 18 , 1411-1420, 2001. Wilson, J.O., P.M. Crill, K.B. Bartlett, D.I. Sebacher, R.C. Harriss, and R.L. Sann, Seasonal variation of methane emissions from a temperate swamp, Biogeochemistry, 8 , 55-71, 1989.CO 2Seepage into Surface Water

DRAFT 38 Rev. 1.2 Woods, A.W. and J.C. Philips, Turbulent bubble plumes and CO 2 -driven lake eruptions, J. Volcanol. Geotherm. Res., 92 , 259-270, 1999.CO 2Seepage into Surface Water

DRAFT 39 Rev. 1.2 

### FIGURES

Figure 2.1. Schematic showing different co mbinations of coupled surface-water and porous media gas transport and transition at the in terface between porous media and surface water.CO 2Seepage 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.CO 2Seepage into Surface Water

DRAFT 41 Rev. 1.2 Figure 2.3. Schematic of surface-water environments into which CO 2 leakage and seepage from geologic carbon sequestration sites may occur.CO 2Seepage into Surface Water

DRAFT 42 Rev. 1.2 Figure 2.4. Phase diagram for CO 2 showing typical P-Tpath with depth in the earth.CO 2Seepage into Surface Water

DRAFT 43 Rev. 1.2 Figure 4.1. Half-section of a spherical bubble s howing radiating forces due to pressure along with the surface tension forces due to P st along the equator. Pressure in the fluid is Pz, while pressure in the bubble is P.CO 2Seepage into Surface Water

DRAFT 44 Rev. 1.2 Figure 4.2. Bubble rise velocity as a func tion of bubble radius with background contours of Reynolds number (from Leifer and Patro, 2002).CO 2Seepage into Surface Water

DRAFT 45 Rev. 1.2 Figure 4.3. Force balance on single CO 2 bubble showing buoyancy force (F b ), drag force (F d), and surface tension force (F st) (after Corapcioglu et al., 2004).CO 2Seepage 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 ub(log m/s) 

### Air CO2 Gas CO2 Liquid

Figure 4.4. Log 10 u b for three different coarse porous media as a function of particle size.CO 2Seepage into Surface Water

DRAFT 47 Rev. 1.2 Figure 4.5. Schematic of domain and variabl es for ebullition vs. dispersive mass transport analysis. Ebullition is indicated by the bubbles, dispersion by the wiggly vector.CO 2Seepage into Surface Water

DRAFT 48 Rev. 1.2 Figure 4.6. Solubility of CO 2 (mole fraction) and fully ionized salt in water and various brines as a function of depth within a surf ace water body (0-200 m) and the underlying formation (-1000 – 0 m) with the different phase stability fields for CO 2 indicated by the shading. Right-hand figures show corresponding temperature, pressure, and density of CO 2 with depth.

## This document is not availabl e 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 Read ing Room to view or receive a copy of this docu ment. 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

## 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 CMP COM 5/



## DIRECT TESTIMONY 

## & EXHIBIT OF: STEPHEN D. JENKINS1 2 3 BEFORE THE FLORIDA PUBLIC SERVICE COMMISSION FLORIDA POWER & LIGHT COMPANY DIRECT TESTIMONY OF STEPHEN 

### D. JENKINS

4 5 6 7 8 9 10 11 12 13 14 15 16 

### Q. A. 

### Q. A. 

### Q. A. 

### Q. A. DOCKET NO. 07 

## - E1 JANUARY 29,2007

Please state your name and business address. My name is Stephen D. Jenkins. My business address is URS Corporation, 7650 West Courtney Campbell Causeway, Tampa, Florida 33607. By whom are you employed and what is your position? I am employed by 

### URS Corporation (“URS”) as the IGCC Technology Leader. Please describe your educational background. 

### I received a Bachelor of Science in Chemical Engineering fiom the University of South Florida in 1976. Please describe your work and professional experience. I have over 30 years of experience in the power industry, primarily in the design, 17 18 19 20 21 22 23 permitting, and operation of large coal-fired and oil-fired power plants, emission control systems for coal-fired power plants, and Integrated Gasification Combined Cycle (“IGCC”) power plants. Prior to joining 

### URS, I worked for TECO Energy, as well as several of its subsidiaries, including Tampa Electric Company and TECO Power Services, I worked in a number of areas in these companies, including power plant operations, power plant engineering, fuels, environmental planning, finance, governmental affairs and regulatory affairs. 

### I also served as the1 2 3 

### Q4 A. 5 

### Q. 6 A. 7 8 9 10 11 12 13 

### Q. 14 A. 15 16 17 18 19 20 Q. 21 A. 22 23 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

21 2 3 4

8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 

## QA. 

### Q. A. 

### Q.

A. 

### Q. A. 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

31 2 Electric Power Research Institute’s CoalFleet for Tomorrow Program IGCC Experts Group. 3 4 5 6 

### Q* 7 8 A. 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 

### 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

41 2 3 4 5 6 I 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 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

51 2 3 4 5 6 7 8 9 10 11 Q. 12 13 A. 14 15 Q. 16 17 A. 18 19 20 21 22 

### Q. 23 A. 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

61 2 3 

## Q4 5 A. 6 I 8 

## Q* 9 io A. 11 12 13 14 15 16 

### Q. 17 A. 18 19 Q. 20 A. 21’ Q. 22 A. 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).

71 

### Q* 2 A. 3 

### Q* 4 A. 5 6 7 8 9 10 11 12 13 14 15 16 17 Q. 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? 18 A. 19 20 21 22 23 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.

81 

### Q* 2 A. 3 4 5 6 

### Q. 7 A. 8 

### Q. 9 A. 10 11 12 Q. 13 A. 14 15 16 17 Q. 18 A. 19 20 21 22 23 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

91 2 3 4 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.

7 single train is removed from service due to operational problems, there is no 8 9 10 11 12 13 14 15 16 17 18 19 20 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. 21 22 23 There are many gasifiers operating successfully worldwide. They are typically used for producing a syngas that can be hrther processed to produce hydrogen for

101 2 3 4 5 6 I 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 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.

111 2 3 4 5 6 7 

### Q. 8 A. 9 10 11 12 13 14 15 

### Q. 16 A. 17 18 19 20 21 22 23 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

121 2 3 4 5 6 7

10 11 12 Q. 13 A. 14 15 16 17 18 19 20 21 22 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 23 as it has already done in choosing large 980 MW (net) USCPC units. For IGCC,

131 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Q. 20 A. 21 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 22 23 generation of IGCC plants has gone into service and had an opportunity to work through initial start-ups and reach steady operation.

148 9 10 11 12 13 14 

### 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 I8 plants. 19 20 21 22 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.

151 

### Q2 A. 3 4 5 6 7 8 

### Q9 A. 10 11 12 Q. 13 A. 14 15 16 17 18 19 20 21 22 23 

### 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

161

4 5 6

9 10 11 Q. 12 A. 13 

### Q. 14 A. 15 16 17 18 19 20 21 22 23 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

171 2 3 4 5

9 10 11 12 13 Q. 14 A. 15 16 17 18 19 

### Q. 20 A. 21 22 23 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

181 I 2 3 4 5 

## Q* 6 A. 7 8 9 io Q. 11 A. 12 13 14 Q. 15 A. 16 17 Q. 18 A. 19 Q. 20 A. 21 22 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.

191 

## Q. 2 3

NOx 

# I 4 A.

Low-NOx burners and overfire air to reduce formation of NOx, along with Selective Catalytic Reduction (SCR) to remove NOx from the flue gas 5

SO2 8

Wet Flue Gas desulfurization 9

PIWPM10 10

Use of fabric filter to remove fly ash from the flue gas, along 11 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

211 

## 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

223 4

8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 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.

231 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 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.

241 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 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

251 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

261 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.

271 

### 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;

285 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 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

291 2 3 4 5 6 7 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

301

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.

311 

### 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.

321 2 3 4 5

8 9 10 11 12 13 14 15 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

## This document is not availabl e 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 Read ing Room to view or receive a copy of this docu ment. 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.govLetter 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 inje ction 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 require ments 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 re quirements in the GS rule to prevent leakage from injection formations and protect USDWs. Regarding the cost of responding to leaks, the GS rule requires thatowners or operators demonstrate and maintain financial responsibility for corrective action on wells in the AoR, injection well plugging, pos t-injection site care and site closure, and emergency and remedial response at GS sites as specified in §146.85. In th e event of contamination or other adverse event to a USDW associated with GS, the financial inst rument(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 bo ttom of Lake Nyos, a stratified tropical lake that suddenly overturned through a process known as "limnic erupti on." No injection was a ssociated with this event, and this site would not have been considered sufficiently geol ogically 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 porou s spaces in deep rock formations. CO2 is injected for GS through techni cally 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 unde rneath 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 sele ction 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 subsurfa ce features such as deep stratified lakes and other naturally occurring pockets of CO2. Furthe rmore, during GS operation, injection pressures

12 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 characte rization process, owners or operators must submit information about the seismic history of and se ismic sources near a proposed GS site, data on known or suspected faults in the AoR, geomechan ical 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 wi th 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 mu st not exceed 90 percent of the fracture pressure of the injection zone as spec ified in §146.88(a); this requ irement is intended to prevent the opening of fractures or faults thr ough over pressurization of the injection zone.