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# c GEOLOGIC C02 SEQUESTRATION ISSUE SPOTTINGAND ANALYSIS WHITE PAPER Timothy R Gablehouse1 Gablehouse Calkins & GranbergLLC July 22, 2009 OBJECTIVE This paperhas beenprepared for APPA's electric utilitymembers and waterutilities for the purpose ofsurveyingthe widerange ofissues thatwill influence the implementation of geologic carbon sequestration. Aswith manythings, sequestration is not as simple as itseems. Injection ofanything into the subsurface is regulated. Which agencies will acttoregulate and the criteria theywill follow depends uponthe answerto the questions raised inthis paperquestions that Congress and state legislatures will need to address ifsequestrationis tobe implementedon a scaleremotely adequate to make a difference inthe amountofC02 reaching the atmosphere. Withouta doubt sequestrationprojects willgo forward. Manyare alreadyunderway. Nothing inthis White Paper shouldchange anyone's viewonthe technology available for geologic sequestration. Nor should anyone readthis paperto suggestthatthere are fatal legal impediments to theseprojects. There are substantial legal issues and a prudentmanagerwould be well advisedto factor these issues into the business plan for a sequestrationproject Much ofthis paperlooks atthe existing rules that applyto geologic sequestration. From wherewe standtodayit is these rules that willapplyabsent actionbylegislativebodies. For example, ifthe C02 beinginjected is a wastewenextneed to know ifits hazardous waste and

1 Timothy Gablehouse is the managing partner ofthe environmental law firm ofGablebouse Calkins &-,Granberg LLC in Denver Colorado. 410**17 ~**  St, Ste 1375 Denver CO**80~c02** tgablehouse@gcgllc.com ;', 1regulated under RCRA. 

### Ifinjection is limited to producing oil andgas operations for enhanced
recovery, then injection willberegulatedbythe state agencies thatpermit oil andgas operations,2 Thepolicies andprocedures ofthese agencies andwhichpermits mightberequired

are sometimes radically different state-by-state having thepotential to drastically change the regulatoryburden 

### and economics ofany project. Common law theories dealing with trespass, mineral rights and waterrights all are implicated as injection mayresult intrespass orharmto surfacepropertyrights, mineralrights or waterrights. Dependingupon inwhich state injection operations occur, there are significant questions regarding the ownership and access to the subsurface spaces wherethe C02 willbe placed. As the C02 is intendedto remain inthe ground inperpetuity, then we also need to examine who remains responsible inperpetuity. Regardless ofwhether these entities areprivate corporations or public entities long-term liability issues will need to be address and understood. Absent new legislative actionexisting statutes such a CERCLA ("Superfund'') will playa role which means thatthe landowner, mineral owner, injection operator andthe entity thatproduced the C02 all mayhave some liabilityinperpetuity. It's importantto understand whatthis WhitePaperis notintended to accomplish. While itwill identifY a broadrange ofproperty and liability issues associatedwith injectionprojects, it will not suggest solutions to all ofthem. Itwill not address the range ofliability issues associated with thehigh-pressure pipeline infrastructure necessaryto move acid gases from the point ofgeneration to the pointofinjection. For geologic C02 sequestrationto becomebroadly · viable there will needtobepredictability onhow these issues are handled. Many will have no predictable solution until andunless wehave federal 

### and state legislation.

2 Acid gas injection for enhanced recovery ofoil & gas is different from hydraulic fracturing which is also used to enhance recovery byphysically opening the subsurface formations using very high pressure. proprietary formulas and particulates to hold the fractures open. 

### 2BACKGROUND Muchworkhas gone into the technicalreview ofgeologic C02sequestration. (Frequently this isreferred to more generically as carbon capture and storage or "CCS"- the remainder ofthis paperwill utilize this nomenclature.) Some workhas gone into potential regulatoryprograms baseduponextensions ofthe currentEPAUndergroundInjection Control (''UIC") program. EPA has proposed a regulatory approach which isthe topic ofa September l0, 2008 White Paper available to readers. (As nothinghas reallychanged on this front, this White Paper will notcoverthateffort in anydetail.) Some states are adoptingregulatoryprograms with various degrees ofcomplexity. In general they arebaseduponexistingVICprograms oron injection of"acidgas" forproduction enhancement inexisting oil orgas operations. These canberadically different approaches and the internalpolitical situationalong withtheperceived importance ofthe oil and gas industryhas

a large impact. 

### Itis critical to distinguish betweenproductionenhancementinjectionprograms and injection ofC02 solelyfor sequestrationpurposes as they areradicallydifferent in intent, liability, risk andregulatory regime. A mineral ownertypicallyhas substantial rights to use techniques such as fluid injection in orderto producethe ''minerals" like natural gas and petroleum. Oil and gas production companies have substantial experience with this activity and tendnotto view it as very risky eventhough it's currentlybenignregulatoryposture is under attack. As anexample, the long-term liabilities associated withproduction enhancementversus CCS scenarios have substantially different legal postures. Forexample, a land owneroreven an impactedneighbor mayhave products liability claims againstthe producer ofthe injected



### 3enhancement fluid should itcause adverse impacts outside ofthe natural gas orpetroleum productionpool.' In a CCS projectwewouldinsteadneed to lookto CERCLA orRCRA for guidance onlong-term responsibility for the C02• Notresolvedto any satisfactory degree are the questions oflegal access to property for thepmpose ofCCS, whether itis waste disposal or somethingelse, liabilityfor the entire host of things thatpeople can imagine might go wrong, and long-termmaintenance/monitoring. All one need do is examine EPA's 2008 Technical Support Document entitled "VulnerabilityEvaluation Framework for Geologic Sequestration ofCarbon Dioxide"to get a sense ofthe complexityof theproblem and the difficulty ofassessingpotential risks.4 Thattheserisks are a real concern when itcomes topermitting and operation shouldbe obvious. Some examplesmayhelp to illuminate the risks thatthe public will fear: Fluid injection is suspected ofcausing Texas earthquakes. 

### Wall StreetJournal, June 12, 2009, Page A3. Earthquakes causedbydeep well injection ofwastes atRockyMountainArsenal. http://earthquake.usgs.gov/regional/states/coloradolhistory.php Crystal GeyserUT- C02 cold watereruptions through a mamnadewell. http://www.uweb.ucsb.edu/-glennonlcrvstalgeyser/ 1986 LakeNyoseruption and deaths. "CCS mobilization ofhazardous, naturally occurring materials is a riskthatmustbe characterized." "Injection into saline formations has thepotential to disturb regional ground-water flow systems and could contaminate drinking water." Paraphrased from the testimony ofDr. Burruss,USGS, SubcommitteeonEnvironmentand Hazardous Materials, House Committee onEnergy and Commerce, July24, 2008 Transportationinfrastructure to transport C02 to injection sites does not exist- USGS projects that an infrastructure larger

### than the existingnatural gas/petroleum industry willberequired to achieve meaningful levels ofCCS. http://energy.er.usgs.oov/health environment/C02 seguestration/C02 illustrations.html

3 SeeModesto. City ofv. The Dow Chemical Co:. et al., No.**98~999345,** Calif. Super., San Francisco Co. (liability based on products liability theories found for dry cleaning fluid off-site impacts) 4 http://www.ena.gov/cliffiatechange/emissions/downl:oads/VEF-Technical Document**0724~8** .pdf 

### 4

### ( ISSUES andDISCUSSION



## ( I. Liability DuringInjection 

### I OperationalLilibillty Operational liability includes the environmental, health, and safetyrisks associated with C02 capture, transport, and injection. Enhanced fluid recovery contractors are already subjectto

a duty ofcare definedundertortJaw and areusually subject to standards ofconductundertheir contractual arrangements. Companiesprovidingthese specific services have experience intheir industries, and are subjectto liability forworker safety andproperty damage resulting from their conduct. These companies arebestpositionedto manage therisks associated with their own conduct and are able to obtainliabilityinsurance for theirconduct and workers.5 

### In surveys and

case studies, these companies were willing to provide services on a commercialbasis and generally willing to accept liability for their actions.6 However, it is foreseeable thatlarge-scale CCS could make it less likely that companies will

### be willing to accept liability for injection. Forexample, 

### ifthere was contamination at the surface during injection operations itcouldpotentially affectdrinking water. There is currently no lawprotectingcommercial orpublic operations from the full range ofliabilities should they

causecontamination. 

### In theory government agencies could conductthe injection operations to limit liability associated with injection. 

### An example ofthis is Lawrence v. Buena Vista Sanitation District.' Neighbors brought a trespass claim against the sanitation district, alleging contamination from leakage at the district's wastewatertreatment facility butdid not argue that negligence was

5 M.A. deFigueiredo, D.M. Reiner, H.J. Herzog, Towards a Long-Term Liability Framework For Geologic Carbon Sequestration, Presented at the Second Annual Conference on Carbon Sequestration, Alexandria, Va. May 2003. 6 Craig A. Hart,Advancing Carbon Sequestration Research in an Uncertain Legal andRegulatory Environment: A. Study of Phase IIof the DOERegional Carbon Sequestration,Partnerships Program, DiscuSsion Paper 2009-01, Cambridge, Mass.: Belfer Center for Science and Internationa,l Affairs, January 2009 (finding drilling companies willing to participate in CCS and accept liability for their actions). 7**Law~ence** v. Buena Vista Sanitation Dist., 989 P.2d 254 (Colo.App. 1999) 

### 5present. The courtheld thatthe district was immune from a trespass claim under Governmental ImmunityAct "unless negligence isproven". Trespass is nota dangerous conditionofa public
water facility orpublic sanitation facility; because the trespass claimdid notrequireproofof negligence itwas barredbyGovernmental Immunity. Nobody shonld take this sortofoutcome

as anindicationthatgovernment agencies can conductthese operations with impunity- there are manyother available theories ofliability. II. PostInjection Liability A. Ownership ofPore Space The surface ownerusuallyowns pore space because mineral conveyances, including leases, normallyonlypass title to the minerals, not thepore space itself. Thatdoes not,however, end the conversation overwho controls the pore spacepropertyright. The surfaee ownercannot violate the mineral estate owner'sor lessees' rights by doing somethinginterferingwith access
to the minerals, making the minerals more expensive to exploitormaking the development of the minerals economicallyimpractical. Clearlyinjection into the pore space couldcause this sort ofharm. The surfaceownermust also allowreasonableuse oftheproperty to give access to the mineral estate.8 For CCS projects to proceeditis somewhatreckless to assumethat agreement with the surface owner is the onlynecessary step. It seemsprudent to have agreements with both surface andmineral owners eventhoughit seems likelythat the surface owner owns the
pore space.' B. Risk ofLeakage Post-injectionliabilityincludesharmto human health, 

### the environment, property, 

### and the climate liabilityrelated to leakage ormigration ofcarbon dioxide from geological reservoirs and

8 Cassinos v. Union Oil, 14 Cal.App.4th 1785 (1993) 9 Geologic C02 Sequestration:**Wh~.,** Owns the Pore Space?, 9 WY LR 98, 2009. 6

### ( the effectonclimate change. Potentialpathways for carbon dioxide release include leakage through the pores oflow-permeability caprocks ifthe carbondioxide is injected at too high a pressure, leakagethrough openings inthecaprock, leakage through abandoned or improperly sealedwells, andmigration 

### via faults. 10 Reportedly, there is a low risk ofcapturedcarbonleaking into the atmospherein amounts significant enough to pose a risk. 11 C02 and natural gas has been storednaturallyingeologic formations for millions ofyears and companies already store natural gas underground with a lot ofexperience. There are naturallyoccurring C02 reservoirs inthe western states that haveheld
gas formillions ofyears. Furthermore, over I00 milliontons ofC02 has been injected into oil reservoirs for enhancedfluid recovery as well as into deep saline aquifers (over 80 projects have beenimplemented worldwide). 12 Commercial and experimentalprojectshave shown the potential for CCS across a wide range ofgeological settings. 

# ( There are, however, reports suggesting that an exceptionallydetailed analysis ofgeologic conditions is critical tounderstandinghow the C02 is being sequestered in each case. Whether C02 isbeing mineral trapped, in which case itmay

### be stable on geologic time scales, versus dissolution in groundwateris criticalto anassessment ofwhether a potential for leakage is present. Dissolutionin groundwateris notpreferred as it hasthe greatestpotential for eventual leakage to the atmosphere. 13 The long-termliability associated with C02 leakagethat damages health orproperty is difficult to establishbecause itis dissimilar to otherregulatory schemes and has a timeframe of thousands ofyears. We simply do notknowwhat risks long-term geologic stomgepresents.

10 IPCC, IPCC special report on carbon dioxide capture and storage; 2005. 11 Feidman, This work performed under the auspices ofthe U.S. Department ofEnergybyLawrence Livennore National Laboratory under Contract DE-AC52-07NA27344 12 Rocky Mountian Mineral Law Institute 13 Aeschbach-Hertig, Clean Coal and Sparkling Water, NATURE, Vol458, Page 583, April2009. 

### 7

### ( Exposure to CO, typically is not dangerous except inveryhigh concen1rations 

### (> 15,000 ppm). Forexample, in Lake Nyos 1,500people died when a lake overa magmapoolreleased large
amounts ofCO,. This is unlikelyto occurat injection wells whenproperlymonitored. Researchers have successfullyplugged and abandoned C02 injection wells, evenbadlydamaged and failed wells. In wells thathave failed and released C02, almost all were detected quickly and stopped. 14
EPAproduced aJuly 2008 whitepaper entitledApproaches To Geologic Sequestration Site StewardshipAfterSite Closure." Theydescribe the advantages anddisadvantages of stakeholderdeveloped models as well as models basedupon existingfederal lawsranging from the NuclearIndustries IndemnityAct through CERCLA. 

### IfCCS is viewed as waste disposal the "cradle-to-grave" model oftheRCRA and perpetual nature ofliabilityunderCERCLA wouldbe inconsistent with anyeffortto limitresponsibility for injected CO, and especially anypotentially hazardous contaminants entrained in 1he injectedmaterials. EPA's analysis has been criticized asunrealistic given 1hat geologic storage ofC02 is intended to be indefinite andwellbeyond 50 years. The au1hors ofa recentreportview 1his as 1he single greatest legal obstacleto commercial deployment ofCCS. 16 Quite obviously, legislation will be 

### required to address this issue 

### if !hereis to be any time limit on liability. C. PropertyRights Issues Related to Migration ofInjected CO, 1. Natural Gas StorageLaw MayProvide Some Insight

14 S. Julio Friedmann, Carbon Management Program APL Global Security Principle Directorate, LLNL. .S. Department ofEnergy byLawrenceLivermore Nationa·l Laboratory under Contract DE-AC52-07NA27344 15 http://www.epa.gov/OGWDW/uic/pdfs/support uic C02**stewardshipforsitedosur~pdf** 16 World Climate Change Report, 87 WCCR,OS/08/2009, BNA. 

### 8( Gas that is injected for storage remains theproperty ofthe injector. 17 Injection ofgas intopropertythat the injector does not ownis a trespass. 18 Pore space for suchprojects canbe purchasedorleased from the landowner, and/orthemineral estate owner, so long as itdoes not damage otherpersons.19 Agreement withthe mineral estate owner orlessee will generallybe prudent inorderto avoid laterdamage ortrespass claims as there is ambiguity in some states regarding whether a mineral ownerowns the pore spacepreviously occupiedbythe minerals, natural gas orpetroleumtheyhave removed.20 Liabilityfor negligent operation ofstorage operations exists.21 Undermanyfederal and state laws utility companies have eminentdomain rights for utilityfacilities. Thisbegs the question ofwhether CCS operations represent a utility facility underthese statutes- ifviewedas waste disposal, there is doubt These statutes do not address the ability to exercise eminent

### domain rights overbuffer zones thatmaybe desirablebecause of the potential for 

### gas migration. Bufferzones shouldbeincludedbecause gas escape is a trespass; however, how such a buffermightbevaluedin an eminent domain action is unknown. With regards to carbon sequestrationthe concept ofcondemnationposes several problems. CCS potentiallyinvolves large areas ofland

- hundreds ofacres - depending uponthe subsurface conditions and resulting available storage volumes.22 The uncertainty over whether statutory authority to exercise imminentdomain applies suggests aninitial effort to negotiate and purchase rights. Ifinjectionrequires approval from anylandownerthat couldbe affected, thenit

17 Ellis v. Arkansas Louisiana Gas Co., 450 F. Supp. 412,419 (D.'t. OKL 1978) •nd many others 18 Kuntz, The Law ofOil and Gas s 2.6, p.71 19 Ellis, at 450 F. Supp. 412 · 20 Geologic C02 Sequestration: Who Ow"ns..tkePore Space?, 9 WY LR 98, 2009. 21 In a recent case from LouiS**ian~'** ajury awarded S9.2M to a**petrole~m** company whose ability to exploit reserves wa-s adversely impacted by improper maintenance and operation ofaneighboring salt dome storage facility. 22 Separation andcapture of C02from large stationarysOurces andsequestration in geological formatiolts-­ coalbeds anddeep saline aquifers. JAir Waste ManagAssoc. 2003**Jun;53(6):645~715** 

### 9willbenecesslll)' to secure consent from a potentially large number ofpeople. Negotiation and condemnationwill therefore imposehigh costs andlong acquisition times. As itwill notbe the intent (in most cases) to laterretrieve the gas, there are interesting questions and serious unknownsregarding the rights andduties ofthepropertyowners laterin time. Establishing ownership ofC02 inperpetuityis a keypartofthis problem, especiallygiven the vast amounts oftimeitwillbe sequestered. 

### Ifthere is no intentto recoverperhaps there is

no duty to protect andpreservethe C02 orthe associated surface facilities. 

### Ifthe entitythat owned the C02 whenitwas injected disappears, then whetherthe CCS process is waste disposal

or something else will be critical to understanding the on-going duties ofthe landowner. Any resolution ofthis issue will 

### require legislation. 2.Enhanced Oil Recovery Oil and gas leases typically contain the right to injectfluids to aid inthe production of gas oroil, butnot for disposal ofwaste. Leases and state laws often give theproducerthe right


### to "unitize" for secondlll)'recovery allowing injection invarious locations ofa field. These enhaocedrecovery effurts are notnecessarily designed to sequester C02 even 

### if"acidgas" is used. Given the lease/contract rights these processes are probablynot a goodmechanism to examinethebroader liabilityissues associated with CCS projects unassociated with oil and gas production. Asnotedbefore liabilityfor the injected materials, such as hydraulic fracturing fluid or acid gas, exists regardless ofwhythese materials were injected. Contract or lease theories will apply and maybe ofvalue in the short-term until thenormal statute oflimitations runs. Beyond these theories liability is likelyperpetual underfederal environmental laws as these fluids will

10

### ( typically containhazardous substances. 

### As noted earlier, products liabilitytheories may applyto the entity that producedthe fluid ifit harms thirdpersons. 

### 3. Waste Injection Wastewaterwells are subject to permittingbyEPA and/or states. Failureto obtain permits oroperate withinthe terms ofa permitwill make theoperator subjectto agency enforcement and citizen suits. Obviously the partyinjecting musthave the legalrightto do so; however, whatthose rights meanwill be highlyvariable. InChancev. BP Chemical, the Supreme CourtofOhio determined thatthe defendant committed a trespass when chemicals injectedunderground migratedunderplaintiff'spropertyforwhich no rights hadbeen acquired. Even so, theproperevaluationofdamages is veryuncertain. The court held that 

### the surface owner's rightswere notabsolute, butwerecontingent on the reasonable and foreseeable use oftheirproperty.23 Accordingto the court, subsurfacerights includethe right to exclude invasions ofthe subsurface propertythat actuallyinterfere withthe propertyowner'sreasonable and foreseeable use ofthe subsurface." This would mostcertainly includeharmto minerals oroil and gas resources leasedbythe landowner. This sort ofanalogy would workwell for CCS because landowner's that are notharmed bystored C02 wouldhaveno cause ofaction. 

### Itseemsto follow thatthere would onlybe a

cause ofaction after C0 2 specifically damages the health orpropertyofa landowner

- notfor speculationthat gas couldpotentiallyleak from geologic formations orinterfere with access to minerals oroil and

### gas. Manycourts wouldlikely disagree and wouldfind diminished value simplydueto thetrespass. Legislation, rather than litigation, is byfar thebestway to establish the rules inthis arena.

23 Chance v. BP Chemical.t995 WL !43827 (Ohio Ct. App 1995) 24 Id. 

### Il

## I 4. Wastewater In Cassinos v. Union Oil Co., the owners ofa mineral estate sueddefendant for damages whendefendant injected wastewater into the mineral estate. The CaliforniaAppeals Court rejected the defendant's claimthat it should notbe liable because the plaintiffdid not establish the extentofdamage to the mineral estate. The courtheldthat there was substantial evidence the defendant's actions interfered with and damaged the mineral estate. Therefore, the defendant committed a trespass. The court also heldthat theplaintiffin the case couldwaivethe tort claim and collecton an alternative theory ofcontract impliedin law to recover the value oftheuse taken. 25 From Chance (supra) and Cassinos, itis apparentthat a cause ofaction is not likely to

occurifthereis no damage done. Interference with mineral rights shouldbe a concernbecause CCS can displace subsurface gases and groundwater, which could damage mineral estates. The holderofa mineral estate or lease wouldhave a cause ofaction along withthe surface owner. 

### Ifthe activity is allowedby statute itdoes not necessarilymeanthatthe injector will be absolved ofliability. In Tidewater Oil Co. v. Jackson, there weredamages toplaintiffs' oil wells

as a result ofwater flooding operations conductedby defendant on adjoining property. The Court ofAppeals heldthat where defendanfs water flooding activities were intentional and damage to wells on adjoining land was foreseeable, defendant was liable under Kansas law for damage to wells ofadjoining leaseholders. These findings were inconsistent withthe administrative findings to the effectthatthe
waterflooding operations were carried on in a lawful manner. In the view the courttook, itwas unnecessaryto reconcile the findings. Itwas sufficientthatthe water flooding activities were intentional and the consequences foreseeable. A legal claimwas available, eventhough the

25 Cassinos v. Union Oil Co., 14 Cai.App.4th 1710,18 C (Cal App 1993) 

### 12flooding was lawfully carriedon. because it caused substantial injurytothe claimants.26 This

case is importantbecause ithighlights that regulations that allow CCS maynot absolve the defendant ofcommon law property law liability. 4. Water Law Itmost ofthe WesternUS surface and groundwater is a public resource dedicatedto the beneficial use ofpublic agencies andprivatepersons whereverthey might makebeneficial use of the water. (Texas is a bit different inthat groundwaterbelongs to the landowner and isnot subject to prior appropriation. Thatcanresult in significantfights betweenneighbors should one pump so much groundwaterthat a neighbor's wellbecomes dry. This law ofthe ''biggestpump" has beenmitigatedthrough administrative processes such as conservation districts regulating the

use ofgroundwater. 27) Underthe general western approach, including surface waterinTexas,
waterquality andquantity are propertyrights subjectto statutoryandcommon lawprotections. Thebiggest differencebetweenwater andreal propertyis thattheprotections available for water frequently exceedthose available for real property. The right ofwateruse includes the right to cross the lands ofothers toplace waterinto, · occupyand.conveywaterthrough, and withdraw waterfrom the natural waterbearing formations within the state in the exercise ofwateruse right. Naturalwaterbearing formations
may also be used for the transport andretention ofwater. 28 Waterauthorities caninjectwaterfor laterwithdrawal withnopayment for thepore space. The property rights oflandowners or mineral estate owners/lessees do not include theright to controltheuse ofwaterinthe ground and cannotclaim control ofaquifers as part oftheir estate. Except for Texas, groundwater is part of"waters ofthe state" and eitherbyConstitution orstatute, the general assembly ofeach state

26 Tidewater Oil Co. v. Jackson, 320 F.2d 157 (C.A. Kao. 1963) 27 Sipriano v. Great Spring Waters of America, eta/., 1 SW3d 75 (Texas 1999) 28 Board ofCountyCom'rs ofCounty ofPark v. Park County Sportsmen's Ranch, 45 P.3d 693,706 (Colo. 2002) 

### 13has control overthe use and disposition ofgroundwaterregardless ofwhetherit is or is not directly discharged to a natural stream. The law inmost states prohibits the taking ofprivatepropertyforpublic orprivateuse withoutthepropertyowner's consent, but there are frequently exceptions whichpertainto constructed waterfacilities.29 For example manywestern stateconstitutions provide for access
to the water source across the lands ofothers and further recognize and address theprivateright ofcondemnation for the construction ofwaterworks. 30 There is a requirementfor compensation for use ofanother's land, butthat does notextend to employmentofnatural waterbearing subsurface formations onorwithin the landowner's propertyforthe movement ofappropriated water." An applicant for a conditional decree toutilize available aquifer storage space must demonstrate that itwill capture, possess, and control waterlawfully available toitand without injuryto otherwaterrights.32
Water storageunder a landowner's propertyis not a trespass ifitdoes notinhibittheuse, benefit, or enjoyment ofproperty." 

### In Board ofCountyCommissioners v. PCSR. LLP, PCSR proposedto store waterinunderground aquifers underlying approximately 115 square miles. The landowners claimedthat storage ofwaterunderground in aquifers underneath theirland would constitute a trespass. The Court heldthatit wouldnotbe a trespass andtheprojectwould
notrequire the Landowner's consent orcondemnation and the payment of justcompensation underthe provisions ofArticle XVI. The court, in applying Causby,34 found thattheprojectdid
notinclude construction ofanyfacilities onorin the Landowner'sproperties and the

29 Colo. Cons!. art. XVI § 7 3

# °Colo. Const. art II§ 14 31 Sportsmen's Ranch, at 45 P.3d 708 32 !d. 33­

Sportsmens's Ranch, 45 P.3d at 708 34 U.S. v. Causby, 328 U.S. 256 (1946) (ruled that property owner's rights were not unlimited with respect to airspace), 14

### ( Landowner's hadnotalleged thatthe use, benefit, and enjoyment oftheirproperties wouldbe invaded orcompromisedin anyway. Therefore, it was not a trespass. The court statedthat the GeneralAssembly, in authorizing the use ofaquifers for storage ofartificiallyrecharged projects further supplantedthe Landowners' common-law property ownership theory." The court found it ''particularly [significant]" that: (I) [F]ederalpatents to land do notinclude water, (2) ground wateris not a mineral underthe federal mining laws

... , (3) federal statutes as interpretedbythe Supreme Court recognize [a state's] authority to adopt its own system for the use ofall waters within the state in accordance with the needs ofits citizens, subjecttothe prohibitions against interference with federal reserved rights, with interstate commerce, and with navigability ofany navigable waters, (4)the right ofprior appropriation applies

... to waters ofthe natural stream, including surface water and tributary ground water; (5) the propertyrights oflandowners do notinclude theright to control the use ofwater inthe ground, whatever the character ofthat water; and (6) the General Assembly hasplenarycontrol overthe use and disposition ofground waterthat is notpartofthe natural stream.'6

In sum, the holders ofwater use rights mayemployunderground as well as surfacewater bearing formations inthe state for the placement ofwaterinto, occupation ofwater in,
conveyance ofwaterthrough, and withdrawal ofwater from the natural waterbearing formations inthe exercise ofwateruse rights.37 Consentorjustcompensation was notrequiredbecausethe plaintiffs didnothavethe right to restrictthe defendant's use ofthewater thatwas done within regulations. CCS presents a uniqueproblem becausethe underground storage ofC02 could potentially affectthe flow andlocation ofgroundwater. This couldoccurbecause theprocess of physicaltrapping may displace naturally occurring water and other gases.'' Any effect onwater

resources couldposepotential liability ifitlimits access to water that has already been 35 !d. at 703 36 !d. 37 !d. at 712 38 Statement ofDr. Robert Burrus, Research Geologist, Enerby Resources Team U.S. Geological Survey U.S. Dep. Ofthe Interior Before the Subcommittee on Environement and Hazardous Materials House Committee on Energy and Commerce Hearing on "Carbon Sequestration: Risks, 15appropriated tobeneficialuse. Physical displacement ofgroundwater can also have adverse practical impacts onprivate owners andutilities. As a resultitwill normally

### be prudent to evaluate whether on-site groundwater wells, especiallythose used bypublic water systems, will bedisrupted byCCS operations. Inmostplaces a waterright includes the right to a particularquality as well as a particularquantity ofwater. These cases are typically framed inthe context ofdeprivation of quantitybutthese waterrights are also protectedfrom activities ofanother that injure the quality ofa waterright. 39 Therefore, ifwaterquality is affected bythe precipitatethathopefully forms from the geochemical reactions intended as partofCCS operations the owner ofthat water could have a causeofaction against the entityinjecting andthe owner ofthe gas injected. Historically such interference involvedthedischarge ofmine and otherwastes into the streambutthere is no

reason to believethe resultwould be different with CCS.40 

### ill. Regulation 

### A. EPA VIC Rulemaking The UIC Program regulates underground injectionunderfive different classes of injection wells, depending on the type offluid being injected, the purpose for injection, and the subsurface location wherethe fluid is to remain. States are allowed to assumeprimary responsibility for implementing the UIC requirements in theirborders, as long as the state program is consistent with EPAregulations andhas received regulatory approval. Injection operators are required to provide financial assurance in case they cease operations, with the level ofassurance a function ofthe estimatedcostofplugging and abandoningthe injection well. If there is a violation ofa UIC permit, an enforcement actionmaybebroughtbythe EPA
39 2A COPRAC § 76.11 40 Game & Fish Comm1n v. Farmers Irr. Co., 162 Colo. 301, 426 P.2d 562 (1967); Wilmore v. Chain O'Mines, 96 Colo. 319,44 P.2d 1024 (1934). 

### 16

### ( Administrator orthe applicable state agency. Violators may be 

### subjectto administrative orders, civil penalties, and criminal penalties. The scope ofthe VIC statute is 

### contamination ofdrinking water, and under its current application to C02 

### storage, the VIC Program gives more limited treatment, ifany, to otherharms to human health, the environment, and property.41 

### While there are requirements for constructing and monitoring injectionwell operation, there are no federal requirements for monitoring actual movement offluids within the injection
zones, nor are there requirements for monitoring in overlying zones to detect leakage with the exception ofspecific class I hazardous wells, where this monitoring can be mandated.42 

### On

### July 15 2008, the EPA proposed a rulemaking package that wouldregulate geologic sequestration ofcarbon dioxide underthe VIC

..The proposed rules would create a new category ofVIC well (Class VI) 

### designed specifically for injection ofC02 into geologic formations. The proposal includes detailed technical requirements for characterizing the scope and suitability of the target formations, assuring that the injection zone will not affect any actual orpotential

source ofdrinking water, monitoring and reporting on well conditions during and after the sequestration is complete, and requiring as part ofwell permit applications plans for 50 years of post-injection monitoring." The proposed rules do not directly address air quality issues. The Class VI C02 

### injection well requirements are designed to assure that there are no significantreleases ofC02 

### or contaminants inthe C02 

### into the ambient atmosphere. The EPA declined to classifyC02 

### as a hazardous waste but the proposed rules place aburden onthe permittee to assure that the C02 

### does notcontain impurities that would trigger RCRA hazardous waste management

41 Craig A. Haf'4 Advancing Carbon Sequestration Research in an Uncertain LegalandRegulatoryEnvironment: A Study of Phase IIof theDOERegional Carbon Sequestration PartnershipsProgf.am, Discussion Paper 2009-01, Cambridge, Mass.: Belfer Center for Science and International Affairs, January 2009. 42 Regulating the ultimate sink: managing the risks ofgeologic C02 storage. Page 3479 43 http://www.epa.gov/ogwdw/uic/wells_sequestration.html 

### 17requirements. Therisks associated with this classification are manifest. Injection ofhazardous
waste is highlyregulated and would likelybring a CCS projectto a screeching halt. None ofthis overrides the applicable provisions ofCERCLA orRCRA. To the extent there are hazardous substancesreleased from the sequestrationprocess liabilityunderCERCLA
maybepresent.44 Likewise ifmaterials injected are hazardous wastethe daunting permitting and corrective actionprovisions ofRCRA and the state programs will apply. As an example, EPA issued orders under RCRAto require management ofpropane that hadleaked from anunderground distribution system. In EPA'sview, the momentthepropane leaked from the distribution system itwas a waste andpresented a hazard. Dependingupon the factual setting, CCS operations could find themselves in the same situation. 

### B. State Regulation In the absence offederal action onthe carbon sequestrationissue, many states are in the process ofenactingtheir ownregulations. Some examples follow: 

### l.Wyoming House Bill 89 (createdWyoming Statute § 34-1-152 and amendedWyoming Statute § 34-1-202) addresses the ownership ofPore Space. The Bill establishes that the surface owner

owns pore space underneath the surface estate andthatthe pore space is conveyeduponthe
conveyance ofthe surface, unless the space has beenpreviouslyconveyed oris explicitly excluded inthe surface conveyance (in the same manneras a mineral interest). In addition, legal requirements for notice to surface owners and/or mineral interest owners shallnotbe construed
torequire notice to the pore space ownerunless the law specifies that such notice to the pore space ownerisrequired. The statute expresslyrecognizes the dominance ofthe mineral estate

44;http://www.bhclimatechange.com/climate_change/2008/07/epa-,releases-pr.html 18

## ( anddoes not alterthe common law as itrelates to the rights ofthe mineral estate. Thebill states explicitlythat itdoes not affect the common law regarding the dominance ofthe mineral estate.45 House Bill90 (effective July 1, 2008; created Wyoming Statute§§ 30-5-501 and 35-ll313 and amended Wyoming Statute§ 35-ll-103(c))mandates VICpermitforGCS. It makes a clear distinction from EOR. Itinstructs the Wyoming Department ofEnvironmental Qualityto establish and issuepermits to new "sub-classes ofwells" within theVIC program and to regulate well standards, bonding and monitoring. Thebill requires the DEQ to create an advisoryboard andrules to expandthe VIC program to include carbon sequestration. Under the bill, a working group including the supervisor ofthe oil and gas commission, the state geologist, and the director ofthe DEQ will setbondingprocedures. Jurisdiction subsequentextraction of sequestered carbon dioxide rests with the Wyoming Oil and Gas Conservation Commission. The billdoes notimpactthe oil and othermineral interest owners' right to drill orbore through sequestration sites, nordoes itinclude within its scopethe regulation ofenhanced oil recovery operations using carbon dioxide.46 Like HB 89, Wyoming's carbon capture and sequestration legislationrecognizes the continuing dominance ofthe mineral estate. § 30-5-501 states specificallythatthe carbon sequestration legislation enactedby § 35-11-313 shallnot "affectthe otherwise lawful right ofa surface ormineral ownerto drill orbore through a geologic sequestration site" so long as the drilling is conducted in conformitywithrules for protecting the sequestration site against the
escape ofC02•47

45 Id. at 143-45 46 Delissa Hayano, Guarding the Viability of Coal & Coal-FiredPowerPlantS': A RoadMap For Wyoming's Cradle to Grave Regulation of Geologic C02 Sequestration, 9 Wyo. L. Rev. 139,**145~49** (2009) 47 Id. 19

### 2.0klahoma Senate Bil!I765 (May2008) was a proposalthatrequired the development ofGCS permittingregime andtransferred ownership ofwells to state andreleased owners from liability I 0 years after closure. The Bill that was passed, however, was relatively disappointing. It mandated a task force to 

### report to the Governorwith GCSpermitting recommendations by December2008 (extended to December 2009) and is modeledbased on the IOGCC model
statute.48 

### 3.Kansas UnderHB 2419 (2007), GCS rules were supposed to be developed byJuly 2008 (draft in progress). Underthe Bill, a state GCS fund would paylong-term GCS related monitoring and remedial activities. It also exempts GCS property and anyelectric unit utilizing GCS from taxes for 5 years. Finally, it allows for accelerated depreciation ofGCS equipment.49 

### 4. Washington ESSB 6001, passed Aprill7 2008. It codifies the emissions-reduction goals andpolicy recommendations for the state. 

### The bill also sets an Emissions Performance Standard (EPS) that limits electric utilities' ability to sign new orrenewed long-term contracts with powerplants whose greenhouse-gas emissions exceed those ofa modemnatural gas-fueled powerplant. The bill essentially ends construction ofpulverizedcoal plants to serveWashington loads, makes the price ofiGCCpowerreflect some ofits emissions disposal costs, andjumpstarts the process toward a comprehensive greenhouse-gas emissions reductionplan for the state.5°

48 de Figueiredo MA, Reiner DM, Herzog HJ. Framing the long-tenn in situ liability issue for geologic carbon storage in the United States. Mitigation Adapt. Strat. Global Change 2005;10:647-57. 49 --M-elisa F. Pollak ,HumphreyInstitute ofPublic Affairs, Big Sky Carbon Sequestration**Partn~sbip** Annual Meetin. Oct. l8, 2008 50 NW Energy Coalition, Aprill9, 2007. www.nwenergy.org/publications/fact-sheets/6001**~20FINAL%2** 20

### Will Water Issues/Regulatory Capacity Allow or Prevent Geologic Sequestration for New Power Plants? A Review of the Underground Injection Control Program and Carbon Capture and Storage

Authors: Jonathan Gledhill, Policy Navigation Group James Rollins, Policy Navigation Group Theresa Pugh, Director, Environmental Services, APPA**Am~~iriCIIn** Pul:llk: 

### PoMr 

### AI!IIIOcl!ilioo and

American Public Power Association 1875 Connecticut Ave, NW Suite 1200 Washington, DC 20009-5715Executive Summary 

### International concern over global climate change has spurred a search to identify ways to reduce greenhouse gas (GHG) emissions. Of the six gases comprising greenhouse emissions, carbon dioxide (C02

- "carbon") emissions far exceed the other five in the amount emitted. 1 

### The U.S. is considering a number of voluntary options for an 18 percent reduction in C02 emissions by the year 2012. 

### One technology receiving serious consideration by the international agencies, Congress, states, and the Bush Administration is carbon capture and storage (CCS) or sequestration2 First the carbon dioxide from a power plant would have to be separated and removed from the power plant. Carbon sequestration really refers to the geologic storage in deep geological formations below the earth's surface. Carbon dioxide injection has been used for several years in enhanced oil recovery operations. Through government and private partnerships, the U.S., through the Department of Energy (DOE), is evaluating the viability of long-term CCS by conducting demonstration and validation testing of CCS pilot projects. APPA supports carbon storage demonstrations through the DOE and FutureGen to determine if the injection of C02is safe and effective as a mitigation measure. The CCS issue is of considerable import to the electricity/power plant sector which the U.S. DOE considers to be one of the largest emitters of C02 , accounting for 38 percent of C02 emissions among all energy sectors.3 

### While the U.S. DOE is pushing aggressively to deploy CCS for full-scale commercial use, there are a number of technical, regulatory, and policy issues related to long-term C02 storage or geosequestration that remain to be studied and resolved. The U.S. Environmental Protection Agency (EPA) has regulatory authority over injection of wastes into wells through the Underground Injection Control program (UIC) created by Congress under the Safe Water Drinking Act. Congress specifically created the program out of concern for the protection of underground drinking water sources. Although the UIC program has established five classes to address various injection well activities, the Agency currently does not have a regulatory framework by which to regulate CCS activities. U.S. EPA has recently issued guidance to assist its regional offices and state regulators with permitting and operational decisions related to CCS pilot projects. The U.S. EPA has classified CCS pilot projects as Class Vexperimental technology; however, the regulatory framework for Class Vwells is insufficient to provide the necessary safeguards to ensure protection of groundwater sources. Therefore regulators have relied on the stringent requirements established for Class I hazardous waste wells, which includes the requirement that operators demonstrate no-migration of injection fluids (which would include C02 ) for a period of 10,000 

### years.

1 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Environmental Reference Document ("NETL Reference Document"), Aug. 2007, at 1·2. See also, Electric Power Research Institute, Electricity Technologies in a Carbon-Constrained World, ("Electricity sector is responsible for 1/3 of U.S. C02 emissions"). 2 Sometimes sequestration is also referred to as geosequestration. 3 NETL Reference Document, at 1-2.

### In summary, there are major limitations in the technical, regulatory, and administrative requirements of the UIC program that appear to preclude, in the short term, commercialscale sequestration of carbon in non-oil and gas sites in large parts of the country. These limitations are important for utilities and policy officials to evaluate as they consider CCS projects. For electric utilities that wish to build additional generation to meet the needs of their communities, the challenges include very difficult issues. APPA recommends that States and Public Utility Commissions consider and investigate the several limitations identified in this paper prior to mandating CCS as a part of permit approval. APPA also recommends working with the U.S. EPA on the cross-cutting and multimedia regulatory issues as the Agency moves forward towards determining the best regulatory framework for CCS.

2

### Introduction What is the Issue and Why does it Matter to Utilities and Municipal Government? Policy officials and scientists alike, searching for viable ways to reduce carbon dioxide (C02) 

### emissions, have identified carbon capture and storage (CCS) 4 

### as a promising technology. This technology separates C02 

### from emissions of large stationary sources like power plants and injects the captured 

# co, deep into the earth. Figure 1 gives a simple picture of this technology. The Intergovernmental Panel on Climate Change (IPCC) 

### has identified CCS as a way of achieving overall reductions in greenhouse gas emissions. 5 

### This enthusiasm is shared by the U.S. government. The U.S. Department of Energy (DOE) is engaged in research and development of various CCS technologies to determine the viability of full scale deployment of CCS by the year 2012. The U.S. DOE is leading the Regional Carbon Sequestration Partnerships to conduct research and development of CCS and supporting small scale demonstration and validation pilot projects to determine the potential of this technology. Figure 1: Diagram of a Carbon Capture and Storage Operation•**Seq...~estered** (st""d)

### co, Plume CO;: Pip:!li**~**

Primary Seal**(C.~ok)** Target Sal irla Fcrmati on



### The benefits of reducing C02 

### emissions through CCS must be balanced against the potential increased risks of groundwater pollution from CCS. Utilities provide water and power to their

4 Carbon Capture and Storage is also referred to as Carbon Geologic Sequestration. 5 Intergovernmental Panel on Climate Change, Special Report: Carbon Dioxide Capture and Storage, Summary of Po/icymakers, 2005. 6 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Environmental Reference Document, Aug. 2007, at 3·53 Fig. 3·22.



### 3

### communities and rely on available water supplies to produce power. Utilities are uniquely positioned and therefore must understand the potential promise and limitations of CCS. The potential trade-offs will tighten in the future as demand increases for power, water, and GHG reductions. According to EPA, ground water systems account for 91 percent of the total public drinking water systems in the U.S., serving 36 percent of the U.S. population. 7 

### Demand for drinking water increases with population growth, number of households, and manufacturing. While conservation has reduced this need for some new sources, groundwater levels in many parts of the U.S. are declining due to increased pumping.' Meanwhile, the demand for electric is expected to increase by 39 percent from 2005 

### to 2050( 

### requiring new capacity. If new power plants use CCS as some states are considering, underground drinking water sources will face pressure from both power and water needs. The American Water Works Association (AWWA) and the American Public Power Association (APPA) commissioned this paper to consider the drinking water and groundwater issues with CCS and to identify the regulatory and technical hurdles that might minimize opportunities for CCS. More than 1,000 

### of the nation's municipalities provide electricity to homes; businesses and factories also manage many water utilities providing drinking water to residential, industrial, and commercial customers. There are several cautions to assuming a seamless fit between current regulation and CCS. First, the existing regulations and regulatory program arose over 20 

### years ago, long before CCS was envisioned. Since CCS does not fit neatly into the existing program for power plants, the EPA is still in the process of crafting a regulatory approach. Second, for CCS to have a meaningful impact on U.S. emissions, the volume of C02 

### to be injected underground will dwarf current amounts by 10 

### to 20 

### times. While the nation has the ingenuity to tackle this challenge, it will require investing in technical skills, data, research, and education both in the private sector and in regulatory agencies. Currently, regulatory agencies do not have the capacity to review and permit CCS at any significant level. To illustrate this issue, this paper reviews the current UIC program, its current implementation, the current regulatory framework for CCS, and the skill shortages states and EPA will face if CCS moves toward fullscale implementation. Finally, this paper highlights the major limitations for CCS that power plant and water utility managers should consider. What is Underground Injection? 

### Underground injection involves the use of simple or complex technology to inject fluids into the earth most often for purposes of waste disposal or extraction of fossil fuels and minerals. Wells regulated by the EPA include common shallow septic tank systems to highly-engineered, large volume systems that inject materials more than a mile underground. While shallow wells may only dispose of a few gallons per day, large disposal systems may each day pump the volume of an Olympic-sized swimming pool.

7 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006. 8 Source: U.S. Geological Survey at http://ga

.water.usgs.gov/edulgwdepletion.html. 9 Energy Information Administration, Annual Energy Outlook 2007, Feb. 2007, at 82.

4

### What is the Underground Injection Control (UIC) Program? Congress and EPA established the legal framework for regulating underground disposal over 30 years ago. Congress established the UIC program as part of the Safe Drinking Water Act (SDWA) of 1974 providing EPA with the authority to regulate underground injection activities to ensure the protection of the nation's underground sources of drinking water. Almost all U.S. public water systems rely on some groundwater for drinking water. 10 

### Congress strengthened the regulatory requirements for hazardous waste UIC disposal in 1984. In the last 20 years, there have not been significant changes to the UIC program's legal authority. Congress intended for the UIC program to be administered by states due to the large number of wells and to the tradition of local control and regulation of drinking water. As such, the SDWA allows states to submit an application to EPA for primary enforcement or "primacy" for each part, or "class," of the program. EPA can delegate primacy to a state, U.S. territory, or a federally recognized Native American tribe. The UIC program may be executed by the EPA, the state, or both under four separate scenarios: 1) EPA administers the program for all well classes within a state if the latter chooses not to apply for primacy; 2) a state is delegated primacy for all five classes; 3) a state has primacy for Class II (oil and gas) wells only; or, 4) a state has primacy for all classes except Class II oil and gas wells. EPA has delegated primacy for the entire program to 34 states and three territories, shares responsibility with six states, and retains full responsibility in ten states. The ten states for which EPA has primacy are: Arizona, Hawaii, Iowa, Kentucky, Michigan, Minnesota, New York, Pennsylvania, Tennessee, and Virginia. These states have determined that committing state resources to run the program is not a high priority. How does EPA Regulate Underground Injection? EPA established five classes of injection wells (Class I, II, Ill, IV, and V) under the UIC program based upon how the well is used, constructed, and operated. 11 

### The classes provide a consistent way for EPA to apply technical standards to similar activities to ensure the protection of underground drinking water and human health. The classes are ranked by their potential hazard. Class Iwells are for the largest volume and the most hazardous wastes. Class Vwells are for shallow septic systems, dry wells, and low volume systems. Most UIC wells are either Class V, Class I, or Class II wells. All underground injection wells must have a permit. For each class, EPA has established minimum technical standards, public participation, and a permitting process review that

10 See EPA website, http: I/www.epa.gov/safewater/uic/whatis.htm!. 11 40 CFR Part 144.6. 

# stc a•1•tn !!@!&A(h1jiilij$ 

### and Eiiih'@n¥14 5

### states must include in their permitting process. With approximately 834,000 wells across the U.S., 12 

### the UIC program is one of the largest environmental permitting programs.

12 U.S. EPA, Factoids: Drinking Water and Ground Water Statisticsfor 2005, Dec. 2006; http://www.epa.gov/safewater/uic/classes.html.

6What are the Five Classes of Injection Wells under the UIC Program? Class /Injection Wells 

### Subject to the most stringent regulations, Class Iwells include industrial hazardous, nonhazardous, and municipal sewage waste. Class Iwells inject wastes deep into rock formations that are located beneath the lowest underground sources of drinking water13 

### and that are capped by an impermeable rock formation between the injection zone and drinking water sources above. Figure 2: Diagram of Class I Well 14

13 Class I hazardous wastes are injected to depths anywhere from 1,700 feet down to 10,000 feet below the earth's surface. 14 U.S. EPA Office ofWater, Class I Underground Injection Control Program: Study of the Risks Associated with Class I UIC Wells, Mar. 2001, at 11.

7

### In 1984, Congress tightened Class Irequirements by instituting a no-migration standard for disposal of hazardous waste via injection and creating a petition process by which operators must obtain approval to continue hazardous waste injection operations. Specifically, Congress prohibited injection of untreated hazardous wastes unless it is demonstrated that the waste has been treated to be non hazardous or unless the waste will not migrate out of the injection zone or contaminate drinking water for at least 10,000 years. 15 

### Because of the large volume of wastes injected, Class Iinjection is economical if it can show a "no migration" of the waste. Well operators, filing the petition to operate such wells, must accomplish this demonstration by modeling waste behavior underground. 16 

### While there are a total of 529 Class Iwells nationwide, there are only 163 Class I hazardous waste wells nationwide. Most Class Iwells are found in Texas and Louisiana. Class Iwells are banned in Missouri. The map below shows the location of Class I hazardous waste wells in the U.S. 17 

### As the map below shows, only 11 states have active Class I hazardous waste wells.

15 NRDC v. EPA, 907 F. 2d at 1158 16 RCRA, Section 3004, 40 CFR Part 148 (53 FR 28118). In the final regulations, EPA explained that 10,000 year requirement is based on ensuring for long term waste confinement. Specifically, demonstrations that can show nomigration over a 10,000 year period are likely to result in containment for an even longer period of time. Additionally, confinement for that period of time can result in waste immobilize due to geochemical transformation. 17 See EPA website, http: I/www.epa.govIsafewaterIuic/dassi.htmt.



### 8

### Figure 2: Hazardous Waste Wells in the U.S. 

# UIC Class I Deep/HighTeelmology Hazardous Waste Wells

No HVVWells 1-10 HWWells

## ~I 11-20 HVVWells r=±:-d > 

## 10 HVVWells

·AmmieM lli!fliM!-1111!E!:t\l

P4bfie Pfm(!r 

# AFIM

- Al't!locialion and *¥'*•9'ffff1'!UI 

### 9

### There are 366 nonhazardous Class Iwaste wells in 19 states. Nonhazardous Class Iwaste wells are required to comply with the same technical standards as hazardous waste wells. Class II Injection Wells 

### Oil and gas production facilities use Class II wells to inject fluids to pump hard-to-get oil and gas deposits to the surface. The recovered crude oil and natural gas comes to the surface mixed with salty water and other impurities. States require injection of this salty water underground so as not to pollute drinking water. Class II wells must comply with strict construction and operating standards and are often similar in construction to Class Ideep wells. There are approximately 167,000 Class II wells, predominantly found in the southwestern U.S. The map below shows the location of Class II wells in the U.S. 18 

### Twenty-two states do not have any Class II wells.

18 See EPA Website, http://www.epa.gov/safewater/uic/classii.html

.
',_1/ A1ntrrican**Publtc~r** 

# AFR4­
AssodaUM and 

### 10Figure 3: UIC Class II Oil & Gas Wells in the U.S. 

# UlC Class 

# n Oil&GasWeUs

No 

## KM'Wrll We:lls 

# Em ,.,ao**wa~rs** 

## 1

# Ot·5.,000Wells**~** 

### Pu111tt.:l RP:io



# - 5,001·25,00

# o Wells**evi~r}iills** fallds


## _,_ Mme !lhail'l25,WOWels eAi!M!ro,U'! S:ilmo.ll

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### T1il:re:s: 

### Gul'f!

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# APR("""""" PobltcPow¢r ASsociation and 

# MhuW ki:::tLJeiiJ!J 11Class Ill and Class IV Injection Wells 

### Class Ill wells typically involve using injection of fluids to extract minerals. Mining operations for salt, sulfur, and uranium rely heavily on injection using Class Ill wells. Class Ill wells have minimum standards for which operators must comply, including required casing and cementing of wells to prevent the migration of fluids into drinking water sources, a prohibition on injection of fluid between the outermost casing and well bore, and required integrity tests of well casings every five years. In Class IV wells, hazardous waste is injected directly into or above underwater drinking water. Although Class IV wells, like Class V, generally involve shallow wells, EPA created a separate class for injection activities that present a heightened risk. Class IV wells have been banned except in very narrow circumstances. Class VInjection Wells 

### Most injection wells in the U.S. are Class Vwells with an estimated 650,000 Class Vwells in the nation. 19 

### Class Vwells inject nonhazardous waste into or above underground drinking water and occur in a variety of residential and commercial settings including sewage disposal, aquifer recharge, and mineral recovery. Class Vwells include advanced systems used by industry for wastewater disposal as well as less advanced types found in septic systems, cesspools, and agriculture drainage wells. Injection activities that do not fit into the other classes

- like CCS

- are called Class Vwells. Experimental technologies that are in the demonstration phase are classified as Class V injection. 20 

### Although there are no federal requirements that specifically address Class V experimental technology wells, over the years EPA has issued guidance to cover certain experimental technologies. Notably, EPA issued guidance in 1983 clarifying that technologies in the experimental phase which would have otherwise fallen under another UIC programclass based upon well function, may be reclassified into one of the five classes once the technology has advanced for commercial use. However, the technology remains under Class V until proven for commercial use and it is shown that the technical standards of the other class would provide sufficient protection of underground drinking water and human health once the new technology is deployed for commercial use. If the technical standards of the other classes are unable to provide sufficient protection, the new technology remains under Class V until EPA adopts protective technical standards.21 

### EPA did not establish technical standards for Class Vwells until the 1990s. Because of the diversity and sheer number of these wells, EPA did not set minimal technical standards for Class Vwells. Since EPA finished the Class Vrule over 10 years ago, EPA has not issued major policy changes to the program.

19 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006. 20 See, Underground Injection Control (UIC) Regulations as amended, 40 CFR Part 146.05(e), Aug. 27, 1981 (46 FR 43156), and 40 CFR Part 146.03, Feb. 3, 1982 (47 FR 1416). 21 Victor J. Kimm, Memorandum: Appropriate Classification and Regulatory Treatment ofExperimental Technologies. Ground-WaterProgram Guidance No. 28 (GWPG #28), May 31, 1983.



## - ?J

# t Q¥)ilfi li§%fUWI!el$1 12

### How Does CCS Fit into the UIC Program and Why Does this Matter to Electric Utilities? Congress and EPA did not envision sequestration of carbon dioxide when they established the program for the chemical industry over 30 

### years ago so no federal regulatory framework exists to regulate CCS activities specifically. Yet, EPA has considered how CCS is regulated under the UIC program. In 2006 

### EPA determined that CCS activities are "underground injection" and that SDWA mechanisms are sufficient to regulate and to permit pilot projects. As a result, EPA issued a directive that CCS pilot projects are to be permitted as Class V experimental technology wells. 22 

### This policy directive might be supplanted by an EPA rulemaking in 2008. 

### Since there are no federal requirements governing Class Vexperimental technology wells, there has been a lot of confusion and uncertainty. In March 2007 

### EPA issued guidance for permitting and operation of CCS pilot projects as a Class Vexperimental technology wells. 23 

### This guidance for CCS pilot projects tries to straddle between the current legal framework and the environmental standards necessary to inject a large volume of carbon dioxide safely. Legally, EPA confirms that Class Vis "the best mechanism for authorizing pilot GS project,"24 

### and that Class Vgeneral permitting and public participation requirements apply. The permits can remain in effect as long as needed to cover the timetable of project goals and may be modified or extended to alter the goals or timetable, but cannot exceed state or federal permit limits. As a counterpoint to the flexibility inherent in a Class Vpermit, the guidance then lays out why states should consider more stringent permit conditions in the CCS Class Vpermit. EPA emphasizes throughout the guidance that protection of underground drinking water and human health is the overriding concern. EPA lays out a number of considerations for regional and state directors to take into account for purposes of permitting and operation, including:

• Siting considerations;

• Consideration of the underground area affected by the injection;

• Injection well construction;

• Injection well operation and monitoring program considerations; and,

• Site closure. UIC program directors are also encouraged to consult with deep well experts including Class I and Class II directors to ensure appropriate standards are applied for CCS pilot projects. However, EPA stops short of recommending CCS pilots have all the features of Class I permits, although UIC directors can opt for Class I requirements. The 2007 

### EPA guidance stresses that the primary goal of pilot projects is for EPA, the states, and well operators to collect and share data to better understand how C02 

### reacts and moves underground, as well as

22 Cynthia C. Dougherty, Letter to State Regional U/C Contacts re: CCS pilot projects, U.S. EPA Office ofWater, Jul. 5, 2006. http://www.epa.gov/safewater/uic/pdfs/memo_wells_sequestration_7·5·06.pdf 23 U/CPG # 83. http://www.epa.gov/safewater/uic/pdfs/guide_uic_carbonsequestration_final·03·07.pdf 24 UICPG # 83, at 6.



### 13

### understanding what the risks are associated with 

# co, injection. To determine how best to manage commercial scale CCS injection operations, the guidance suggests EPA regional and state directors adopt a more flexible approach in approving permits and identifying permit conditions to allow operators to "achieve project objectives."25 How have States Regulated CCS Pilots? 

### EPA and the states have looked to Class Iand II regulations for permit conditions for CCS pilots because of the depth of injection and the larger volume of C02 

### injected. Today C02 

### is currently is being injected to recover oil and gas in wells subject to Class II well requirements. Some CCS pilots have occurred in oil and gas formations in Class II wells. 26 

### In the few cases to date, states have granted Class Vpermits for CCS pilots sequestration with many - if not all

- of the technical requirements for a Class I permit. What are the Specific Class I and II Technical Requirements? 

### The technical requirements for Class Iand II wells include siting, well construction, operation, reporting, monitoring, permitting, financial assurance, and closure standards. The regulatory system is designed to minimize leaks into drinking water formations as waste and fluids are pumped down through these layers and after they are put underground. Siting 

### Class I permits require three separate hydrogeologic investigations to permit a deep injection well: reviewing the geology of the area, conducting an area of review study, and finally submitting a no migration petition. In the geologic study, permit applicants must show that the area is geologically stable; the area is not seismically active now and has not had earthquakes in recent geologic time. The formation must have suitable room to store the injected wastes and thick enough to dissipate the pressure without cracking the confining layer. The geologic study must also show the area around the well is free of vertical faults that could allow the injected fluids to migrate up to drinking water layers. Finally, the geologic study must also demonstrate that the injection layer's rocks are chemically compatible with the waste. 27 

### The second study is the Area of Review. In this study, well operators must investigate all wells in the area that penetrate the injection or the confining layer. Operators must demonstrate that all of these wells are sufficiently capped and closed to prevent migration out of the injection layer. Under federal regulations for Class I hazardous waste wells, the Area of Review is defined as either a 2 mile radius from the well or to the zone of endangering influence on underground drinking water, whichever is a greater distance. States require larger Areas of Review; Texas, for example, uses a 2.5 radius for its Area of Review. For nonhazardous waste, the Area of Review can be a low as 

### Y< of a mile. 28

25 UICPG #83, at 3. 26 According to U.S. DOE, there are at 75 oil reserve carbon sequestration projects in the following states: Arkansas, Colorado, Louisiana, Oklahoma, and Texas. See, U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Environmental Reference Document, Aug. 2007, at 3-60. 27 U.S. EPA Office of Water, Class I Underground Injection Control Program: Study of the Risks Associatedwith Class /Injection Wells, Mar. 2001, at 18. " Ibid, at 19.

14

### One of the biggest challenges for Class Ioperators is to demonstrate no-migration of waste for at least ten thousand years. This demonstration requires computer modeling, knowledge of regional geology, and detailed geologic information of the area around the well. Small faults or buried channels can create a connection between deep formations and shallower drinking water sources. Injecting fluids also changes the volume and pressure underground, possibly activating dormant faults. Permit applicants must also search for abandoned wells that might connect the injection zone with upper layers. 

### Construction Operators prevent leaking by wrapping their wells in impermeable casing. Operators of enhanced recovery and hydrocarbon storage wells are required to case and cement the wells to prevent migration of fluids into underground drinking water. Specific casing and cementing requirements are determined by the state on a case-by-case basis; however, as part of that process they must take into account injection zone depth, depth of the bottom of all drinking water formations, injection pressures, and the nature of fluids to be injected." The well has essentially three walls so that breaching one still contains the waste. As shown in Figure 4, the injection tubing transports the waste to the injection zone. It is made of corrosion-resistant material and it is surrounded by the long string casing. This casing is sealed at the bottom by the packer and at the top by the well head. Operators must pressurize this space between the long string casing and the injection tubing to monitor for and to prevent leaks. Finally, the outermost wall, the well casing, supports the well structurally. Operators must maintain mechanical integrity of the well until plugged and abandoned. 30

29 40 CFR Part 144.Z8(e) 30 40 CFR Part 144.Z8(f)



### 15Figure 4: Diagram of Class I Well Technology"



## Ideal Injection Well and Site



# --­

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' "". ';"C · ;,'"**~** ·:· ", ,"'' 'i

## ~l>fi~t'!!.~t':'~ .•**Packer--~~~** klje..tion zon• No....USDW Perl'oral&d """'1Q,QOD m.g/ITDS 

### casing

Monitoring 

### Monitoring requirements include monitoring of the well and other formations. Class Iwell operators are required to analyze injection fluids to identify fluid characteristics, to use continuous recording devices to monitor injection pressure, flow rate, and volume, and to monitor for any leaks into drinking water with monitoring wells. 32 

### Operators also minimize any leaks by carefully watching injection pressure. If there is a leak in a well, the pressure in the well will drop as the fluids escape out of the circumference. Regulations require well operators to use continuous recording devices to monitor injection pressure, flow rate, and volume. 33 

### To demonstrate mechanical integrity, well operators must show that fluids will not

31 Source: U.S. EPA website: http://www.epa.gov/safewater/uic/idealweLhtmL 32 40 CFR Part 144.28(g)(1). 33 40 CFR Part 144.26(g)(1).

16

### leak while traveling to the well, will not leak out of the well as it is injected, nor move into underground drinking water once injected into the deep rock. 34 

### The UIC program requires mechanical integrity demonstrations at least once every five years for both Class Iand Class II wells. 35 

### Class Ioperators are also required to develop approved ambient monitoring programs as determined by the Program Director to protect against fluid movement out of the injection zone. Monitoring programs are based upon a site-specific assessment and must include at a minimum annual monitoring for injection zone pressure. 36 

### The Director may also require the following as part of the monitoring program: 1) Continuous monitoring for pressure in the aquifer located directly above the injection zone; 2) Other site specific data to include information on the position of the waste front within the injection zone or water quality; 3) Monitoring of ground water quality of the aquifer located directly above the injection zone; 

### 4) Monitoring of ground water quality in the lowest underground source of drinking water; and, 5) Any additional monitoring to determine if there is fluid movement into underground sources of drinking water.37 

### Class II well operators are required to monitor injected fluids to determine how it moves and changes while in the injection zone, and the frequency of which is determined in each permit based upon site specific criteria.38 

### Operators are also required to monitor and record injection pressure, flow rate, and cumulative volume, the frequency of which can vary from daily to monthly, dependent upon the type of well operations." Well operators must demonstrate mechanical integrity at least every five years.4° Reporting 

### Reporting requirements also differ between Class Iand Class II wells. Operators of Class I wells must submit quarterly reports with the following information: various characteristics of the injection fluid, monthly average and minimum and maximum values for injection pressure, flow rate/volume, well pressure monitoring well results, and the results of injection

34 40 CFR Part 146.8 35 40 CFR Parts 146.13 and 146.23. 36 40 CFR Part 146.13(d)(1 ). 37 40 CFR Part 146.13(d)(Z). 38 40 CFR Part 146.Z3(b)(1). 39 40 CFR Part 144.Z8(g)(Z); 40 CFR Part 146.Z3(b)(Z). 40 40 CFR Part 144.Z8(g)(Z)(iv); 40 CFR Part 146.Z3(b)(3).

17

### well tests.41 

### Class II well operators are required to submit annual reports providing a summary of results from any required monitoring activities. 42 

### Financial Assurance For now, APPA is 

### not aware ofany additionalfinancial assurance programs or systems envisioned

### for CCS. 

### However, the existing 

### law does require thatfinancial responsibility is 

### met. APPA has caution about embracing CCS 

### technology and long-term storage or 

### geosequestrationfor newpowerplants until this

### financial responsibility issue is 

### better understood. To APPA's knowledge, there has been nothing like this/eve/ of financial assurance required in 

### the electric power sectorfor conventional pollution issues 

### and liability concerns. Currently, Class Ioperators must demonstrate and maintain financial responsibility for each well to ensure the operator is financially able to eventually close and abandon the well in accordance with an approved well abandonment plan.<' Class Ioperators have several options from which to choose in order to demonstrate financial responsibility. 1) Establish a trust fund in an amount equal to the estimated cost of plugging and abandonment; 2) Obtain a surety bond to guarantee payment into a standby trust fund; 3) Obtain a surety bond to guarantee well plugging and abandonment; 4) Obtain a letter of irrevocable plugging and abandonment letter of credit; 5) Plugging and abandonment insurance; 6) Meet financial criteria and obtain a corporate guarantee for plugging and abandonment; or, 7) Demonstrate financial responsibility using a combination of options 1, 2, 4, 5. 44 

### Closure Well operators must submit plans for plugging and abandonment as part of the permit approval process. 45 

### UIC program regulation requires Class I, II, Ill, and Vwells to be plugged with cement sufficiently to prevent migration or leakage of the injection fluid. Class Ipermit holders must also monitor groundwater until they can demonstrate that the pressure in the injection zone decays to the point where there is no potential to influence underground drinking water sources. 46 

### Class Voperators are also required to dispose of any waste, sludge, fluids, etc., that are found near the wells. 47 

### Well operators are required to submit a report

41 40 CFR Part 144.28(h)(1). 42 40 CFR Part 144.28(h)(2). 43 40 CFR Part 144.28(d). 44 40 CFR Part 144.63. 45 40 CFR Part 144.28(c). 46 40 CFR Part 14.28(g)(1 )(iii). 47 40 CFR Part 146.10.



### 18

### certified as accurate to the Director stating that well abandonment was conducted and completed in accordance with the abandonment plan. What are the Challenges for Permitting CCS Under the UIC Program for Electric Utilities Evaluating CCS Options? With the international, federal, and state interest in CCS, academic, public interest groups, and the federal government researchers are promoting the availability of sequestration sites. The Department of Energy estimates that North America has the capacity to store all of its annual power plant emissions underground. The APPA is very skeptical of DOE's optimistic view because APPA does not believe that hydrological concerns and proximity to transmission lines, water issues and other infrastructure needs have been considered. Yet, new electric utilities are being asked to respond and to consider CCS as part of new plant design now. The APPA is concerned that these studies do not fully consider the technical, regulatory, and practical limitations of commercial-scale CCS. The current UIC regulatory program illustrates some of the major limitations utilities and policy officials must consider: Cost and Space Requirements for CCS at the Power Plant 

### The DOE estimates that a 300 MW power plan will require 60 acres of land to build and to operate the carbon capture technology. 48 

### Constructing the pipeline terminus for C02 

### compression and transport via pipeline will require an additional 20 acres of land. DOE further estimates that carbon capture will consume 0.5 millions of gallons of water per day and over 15 megawatts of power or approximately 0.8 MGD per day for a 500 MW power plant. If utilities do not have readily available land and water, and can afford the costs of excess generating capacity, they will face limitations on their ability to construct

## ccs_4' Uncertainty Concerning Regulatory Requirements 

### Since EPA is formulating guidance or regulation on CCS and the UIC program, there is substantial uncertainty as to the ultimate siting, construction, and other permit requirements. If EPA embarks on a rulemaking, a final rule may not be promulgated until 2012. Once EPA completes its policies, states may enact their own more stringent provisions. This uncertainty complicates commercial scale planning for new power plants with coal on the drawing board today. Operators of Class I, II, or Ill wells are expected to take corrective measures when there is noncompliance or malfunction of the injection system, which may include temporary shut down and capping of the well. The operators are required to notify the UIC regulatory manager within 24 hours of when the operator becomes aware of the problem. Operators are also expected to include in their noncompliance report its cause, period of time it occurred, actions taken (or are taking) to correct the issue, and plans to prevent recurrence. 50 

### Other specific requirements may be established as part of the operators UIC permit. However, the difficulty for well operators involved in CCS operations is finding an alternative means of disposing C02 

### emissions if injection operations must temporarily cease. Operators may have to negotiate this issue as part of the well permitting process.

48 NETL report, at 2·44. 49 NETL report, at 2·44. 50 40 CFR Part 144.28(b)

19Limitations on Class I Well Siting 

### If EPA and states draw upon the criteria for Class Iwells for CCS wells, there are regulatory, technical, and transportation limitations for CCS that utilities must consider. On a technical basis, some areas of the U.S. would be unsuitable due to the relatively increased risk of earthquakes, for example. Many of the coal regions of the United States also correspond to areas that are relatively geologically active (e.g., areas of Wyoming51 ). 

### Injection near population centers along the West Coast also might be ruled out due to seismic concerns. Until the siting criteria are defined, utilities may not be certain whether they can inject locally or be required to pipe C02 

### hundreds of miles to areas with Class Iwells such as the Gulf Coast. Sheer Size of CCS to Have Meaningful Impact on U.S. GHG Emissions 

### Another limitation is that the EPA and states may not have the human and financial resources to administer an expansion of the UIC program for CCS. Comparing the relative size of C02 

### emissions and current underground injection gives some answer to this question. Power plants accounted for 2.4 

### billion metric tons of C02 

### emissions in 200652 

### or approximately 86 

### percent of point source C02 

### emissions in the U.S. 53 

### By way of comparison, EPA reported that 21.8 

### million tons were injected into hazardous waste wells in 2005, 54 

### less than one percent of the amount of carbon dioxide released. Approximately 43 million metric tons of carbon dioxide is injected into wells today for enhanced oil and gas recovery.55 

### If perhaps 10-20 

### percent of carbon dioxide emissions were captured, the UIC programs would need to permit wells injecting masses 10

- 20 

### times the total mass currently injected for oil recovery or for all hazardous waste disposals. This expansion would pose a substantial challenge to the existing state permitting systems. APPA remains skeptical that more than a slip stream of C02 

### can be separated and injected and remains doubtful that a new coal power plant (regardless of type) could separate and inject more than 50 

### percent of the C02 

### from the plant.

51 http://ga.water.usgs.govIedu/gwdepletion.html 52 Electric Power Research Institute, Electricity Technologies in a Carbon-Constrained World. 53 Carbon Sequestration Atlas, at 11. 54 U.S. EPA Office of Solid Waste and Emergency Response, National Biennial RCRA Hazardous Waste Report: Based on 2005 Data, Dec. 2006, at 2-5, Exhibit 2-5. 55 Source: Advanced Resourced International, 2007.


### y

# It 4·1'14' lk$Nif!iil#i$1 &iJIQiflii(.ii!ij 20Figure 5: Comparison of CCS Volumes to Current UlC Volumes

Space Requirements for the Injection Well 

### DOE has estimated that injecting 0.

### 9 million metric tons of C02 

### will require a land area of over 2,750 

### acres. This carbon mass is only 40 

### percent of one year's generation from a 300 

### MW coal power plant with a 90 

### percent efficient CCS. Using DOE's estimate, to hold 30 

### years of C02 

### captured from a 300 

### MW boiler, the surface area requirement is over 200,000 

### acres, or 312.5 

### square miles. 59 

### This land choice must also consider load, transmission lines, coal or rail access, surface water (used to produce electricity) and conventional air pollution issues such as 

# so, and NOX. The injection well, observational well and Area of Review (AoR) space issues will dictate where the future power plants can be built. The U.S. DOE's estimate may significantly underestimate the land area needed. As a gas, carbon dioxide is different then diluted wastewaters currently injected in Class Iwells. It is more buoyant than the underwater fluids and will rise to the top of the injection layer. If the injection layer has dips and rises, C02 

### will flow to fill in each rise first. In other words, unlike current injected fluids, it will migrate via diffusion on its own away from the injection well. Like natural gas, it will concentrate in traps miles away from the injection zone. ln other words, applicants could have areas of review much greater than 2.5 

### miles currently thought protective for liquid injection. Astudy in the saline formations of Texas where there are many Class Iwells suggests that a formation large enough to store 30 

### years of

# co, from a single power plant could have traps over a 13 mile by 13 

### mile area.'0 

### Afurther complication is the difference in property law traditions across the United States. ln several Homestead laws, Congress gave away land to settlers who stayed upon and improved the land. However, the federal government retained the subsurface rights to the land, creating "split-estate" properties where the surface owner does not have title to the subsurface. Over 20 

### million acres of land in western U.S. states have splitestates between private entities and the federal government.'' In other states, the mineral rights have been sold to private parties creating split estates between parties. In the eastern U.S., property titles typically include surface and subsurface rights. Depending on the state, utilities may

56 Electric Power Research Institute, Electridty Technologies in a Carbon-Constrained World. 57 Source: Advanced Resourced International, 2007, 58 U.S. EPA Office of Solid Waste and Emergency Response, National Biennial RCRA Hazardous Waste Report: Based on 2005 Data, Dec. 2006, at 2-5, Exhibit 2-5. 59 NETL report, at 2-71 60 J.P. Nicot etat., Area ofReview: How large is large enoughfor carbon storage?, Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin, 2006. 61 NETL report, at 4-83.

21

### face the limitation that it is impractical, impossible, or extremely costly to acquire title to hundreds of thousands of acres of land. Unique Potential Hazards of Carbon Dioxide Injection 

### While deepwell injection of liquids has occurred safely for over 20 

### years, there is less experience with injecting gasses like C02• 

### While most C02 

### injections for enhanced oil recovery have occurred safely, problems that have occurred illustrate the unique hazards that utilities and regulators must consider. Afew of these potential hazards include the following. Blowout 

### Well blowouts occur when gas escapes through old or unknown wells. In January 2001, 

### a natural gas leak from a cracked gas well casing leading to salt caverns and used as a natural gas storage facility resulted in an initial gas explosion below two stores in downtown Hutchinson, KS. The initial gas explosion was followed by an eruption of natural gas and water geysers two miles east of the initial explosion later that day and for several days thereafter. Two people residing in a trailer home were killed as a result of one of the explosions. The gas leak originated from a cracked well casing at a depth close to 600 

### feet and proceeded to migrate horizontally, traveling along abandoned brine wells and ultimately reaching the surface some distance away from the initial explosion."' In another case involving C02, 

### a blowout occurred during drilling at a production well in March 1982 

### causing the free flow of C02 

### at the well head and leakage from ground fractures directly above the site. The high rate of C02 

### from the well caused containment not to occur until the following month. 63 

### Areportjointly funded by U.S. EPA and U.S. DOE looked at injection well accidents in both the U.S. and abroad and issued recommendations for protecting against future accidents. 64 

### The report issued a number of recommendations including: determining the potential for C02 

### migration along unsealed fault and fracture zones; the potential for magmatic or seismic activity to cause damage to sealing caps resulting in C02 

### releases; the potential for wells to transport C02 

### to the surface; and implementation of public education and C02 

### monitoring programs to minimize impact to human health and the environment from releases.65 

### The risk of blowout is hard to quantify since there is little information on the number of abandoned wells in the United States. It is difficult to estimate the number of these wells since some do not have observable caps or metal casings that can be detected through sensors. Texas estimates that there are approximately 11 ,000 

### orphan abandoned wells that it is gradually closing through a state program. 66 

### Operators of CCS injection wells will have to find, close, and cap abandoned wells within the Area of Review.

62 Lewicki et at., at 41 ·2. 63 Lewicki et at., at 39·40. 64 Jennifer L. Lewicki et at., Natural and Industrial Analogues for Release of C0 2 from Storage Reservoirs: Identification ofFeatures, Events, andProcesses and Lessons Learned, Earnest Orlando Lawrence Berkeley National Laboratory, Feb. 2006. 65 Lewicki etal., at 48-9. 66 Source Texas Railroad Commission at: http:/lwwwxrc.state.lx.us/news-releases/20061100606.html..

22

### The DOE has a method of finding abandoned wells under its SEQURE program, however this program is not set up for national application. The SEQURE program uses low flying airplanes to detect abandoned wells and, as discussed above, aerial methods may not detect wells which do not have metal cases or other markers. Economic Damage 

### The saline formations in Texas produce some oil and gas in formations nearby or overlaying the potential injection formations. In addition to well blowout, less apparent seeps from the injection zone into oil and gas producing layers can dilute the value of these deposits and ultimately return the C02 

### to the atmosphere! 7 Corrosion 

### As 

# co, rises to the top of the injection layer, it may contact closed wells or the cement casings of older wells. If the C02 reacts with water to form acidic compounds, these acids could start to erode the concrete. As more is eroded, the process accelerates, creating a reinforcing-negative cycle that could allow the C02 

### to rise up the abandoned well to drinking water layers. While this problem can be prevented through different well closure approaches, the potential problem will increase the cost of an applicant's Area of Review study and demonstration! Permitting Costs 

### In 2001, EPA estimated the costs of the siting requirements -the geologic study, the Area of Review study, and the no migration petition

- as at least $2 million for a Class Ihazardous waste well. 69 

### EPA based its estimate on applicant experience, including an Area of Review of 2.5 miles. If, as discussed above, the zone of influence could stretch to a radius of 13 miles, the Area of Review would be 26 times larger than for a typical Class Iwell. The siting studies and corrective measures for closing abandoned wells could approach $20 to $50 million. Operators (presumably electric utilities) would still need to pay for the well construction costs (estimated to be well over $1 million), permitting fees, operating, and the other costs. Regulatory Capacity 

### In all, a Class I permit application can fill a bookcase with the required plans, analyses, and reports. States may spend over a year reviewing a renewal permit and several years reviewing a new Class Iwell permit. 70 

### Because of the regulatory burdens, APPA staff speculates that states will require considerable permit fees to pay for these new state employees as well as analyses of new and renewed71 

### permit applications; ClassII permits can be approved more rapidly. However, and as the maps show, as the UIC program has matured, Class Iand II wells primarily now only occur where there is ample experience and knowledge of local and regional geography.

67 Nicot, et al. 68 Nicot, et al. 69 EPA, 2001, at 20. 70 Source: Texas Commission on Environmental Quality (TCEQ) at http:llwww.tceq.state.tx.us/assets/publicicomm

__execlpubs/sir/057 _06. pdf. Class I permits may remain in effect for up to ten years as determined by the Program Director. See, 40 CFR 144.28. 71



### 23

### Even moderate adoption of CCS by new electric utilities would be the biggest expansion of underground injection in U.S. history. From the volumes above, the U.S. must undertake a dramatic expansion in its technical infrastructure to support safe CCS. ln the private sector, engineers and geologists must identify, map, and investigate many more Ul sites. In the near term there may be a shortage of experienced investigators. For the public sector, the skill gap is even more critical. Regulatory agencies must have sufficient in-house experience to review all of the technical information provided and to evaluate permit applications against the regulatory standards. The size of the current regulatory skill shortage is illustrated by the following:


### • Less than halfofregulatory agencies across the states have experience reviewing Class Ior Class IIpermits. As the charts show, only about 20 

### states have experience permitting deep, high-volume injection wells. For CCS to occur in geologic formations around the U.S., many states must hire and train permitting staff or rely on EPA regional offices.


### • Experience is concentrated in afew regions ofthe country. Current experience is not distributed throughout the country, but concentrated in Texas, Louisiana, Florida, and a few other states. Unless states accept deep well injection in their states, CCS may require special CCS pipelines or via surface shipping carbon dioxide gas hundreds or thousands of miles from a power plant to an injection well. Pipeline shipment and booster compressors along the CCS pipeline increase the cost and perhaps the perception of the hazards of CCS.


### • EPA regions must also boost their technical capacity. It is not only states that will be deluged with CCS permit applications. EPA regions approve UIC permits in some of the nation's largest states and in states with large coal-fired power plants. EPA regions must craft their own approaches and technical requirements for CCS Class V permit applications.


### • Even in states with experience, states would need a significant boost in resources topermit a larger number ofCCS wells. In 2006, 

### Texas had ten new and eight Class Ihazardous waste permit renewals under review. The average processing time was over one year for these permits. If CCS increases by a factor of ten the effective number of Class Iwells in Texas, the regulatory system must either grow rapidly or the time needed to gain approval will soar. Another consideration is the increased regulatory burden faced by electrical utilities when partnering with enhanced oil recovery (EOR) operations. Electrical utilities partnering with Class II well operators for EOR presumably would be subject to current Class Iregulatory provisions, and ultimately any new regulatory requirements or framework established by U.S. EPA specifically to address CCS injection activities. Conclusion Although the concept of CCS sounds promising, regulatory agencies' paramount responsibility will be to ensure current and future protection of the nation's drinking water supplies. For CCS to have a meaningful impact on U.S. power plant emissions, the mass of C02 

### to be injected underground will dwarf current amounts by 10 

### to 20 

### times. While the nation has the ingenuity to tackle this challenge, it will require investing in technical skills, data, research,

24

### carbon separationtechnology at the powerplant. This is a step that, generally speaking, EOR sites do not require. 3


### The purpose ofthis white paper is to introduce environmental and legal issues that may require additional research before large-scale CCS can be implemented safely and effectively in the public powerutility sector. 

### Human Health and the Environment Despite the successes ofEOR or tertiary recovery ofoil and gas using C02 injection, leakage from embedded C02deposits could result io the endangerment ofecological and human health given the scale ofthe utility sector's emissions. A better understandiog of these impacts is necessary io order to take precautionary steps to mitigate them or avoid them entirely.


## • Prolonged exposure to elevated concentrations ofC02 

### can be harmful to human respiratory and central nervous systems. 

## • The release oflarge volumes ofhigh concentrations ofC02can result inthe suffocation ofhumans, animals, orplants above ground. For instance, natural C02 long-term seepage destroyed 40 hectares oftrees on Mammoth Mountain in the Eastern Sierra Nevada mountain range in California. 4 

## • Leakage from injected C02could migrate into Underground Sources ofDrinking Water (USDWs). Migrating C02deposits may alter the pH ofsubsurface groundwater or displace potable water resources by forcing saline waters to merge with fresh water formations. 

## • Accordiog to the U.S. EPA, 44 percent ofall U.S. drinking water is from groundwater, a considerable increase from only 5 years ago when most U.S. drinking water was from surface water sources. 

### • Current research suggests that injecting carbon into saline aquifers poses a threat to groundwater because ofbrine contamination.5 

### Since it is not clear how large-scale CCS activities would address this concern, additional research is required considering the growing reliance on groundwater for use as drioking water. 

## • CCS could potentially cause displacement ofnative fluids and chemical constituents, movement ofpossible hazardous substances, or potentialleachiog ofnaturally occurring metals and mioerals mixed in the C02 injection. 

## • Ifthe CCS process is responsible for discharge ofa pollutant or hazardous substance (such as arsenic) into or upon navigable waters, this may iocur admioistrative and/or civil penalties under the Clean Water Act (CWA) 6

Complete explanation ofseparation technology issues available. See L. D. (Doug) Carter, Carbon Capture and Storage From Coal-based Power Plants: A White Paper on Technology, American Public Power Association, 22 May 2007. 4 C.D. Farrar, M.L. Sorrey, W.C. Evans, J.F. Howle, B.D. Kerr, B.M. Kennedy, C.-Y. King, and J.R. Southron, "Forest-killing Diffuse C02 Emission at Mammoth Mountain as a Sign ofMagmatic Unrest," Nature 376 (1995): 675-678. 5 Brian McPherson and Peter Lichter, C02 Sequestration in DeepAquifers, http:/ /www.netl.doe.gov/publications/proceedings/O !/carbon_seq/7a2.pdf. 6 CWA§ 101 3

### Property Rights The legal mechanism for securing property rights for large carbon sequestration sites may currently be ineffective in many states, leading to unforeseen costs and delays. It 

### also may lead to tensions between large-scale CCS projects and individual property rights.


## • Since sub-surface land canbeprivately owned in the United States, C02 

### injection into geologic formations may require permission from all private owners ofintersected sub-surface property. A proposed deposit for a FutureGen zero-emissions plant site may require property rights from 69 individual property owners. 7 

## • Compulsoryunitization laws for oil and gas production operations, currently used in some states to compel private property owners to permit large oil and gas sub-surface projects when a high percentage ofaffected property owners do accept, may be used extensively for enhanced oil recovery-related CCS. 

### • For non-oil and gas production projects, the use ofeminent domain laws, currently used for sub-surface natural gas storage fields, may be necessary for CCS projects. Widespread use oflocal and state eminent domain laws for CCS may bepolitically difficult, given the public backlash against eminent domain driven by the Supreme Court case 

### Keto v. NewLondon.8 

## • There is currently a significant level ofuncertainty in predicting migration and movement oflarge C02 

### deposits in large geologic formations. Without further research, the scale ofproperty right acquisition for CCS projects will remain high, as industryparticipants will seek to minimize liability from property trespass claims related to sub-surface trespass, geological surveying, and deposit monitoring. 

## • This scientific uncertainty may interfere with the availability ofliability insurance for CCS project participants. Ifinsurance companies cannot accurately calculate the risk ofC02 damages, orfuture potential environmental liability, they may decline to offer coverage to public power utilities. Some public powerutilities may not have the insurance coverage thoughtto be sufficient to handle the perceived risks for geologic sequestration or storage ofC02. 

## • The utilization ofregional landuse controls to banlarge-scale CCS projects near valuable natural resources may be an obstacle to implementing projects in viable locations. General Regulatory Framework The current federal and state regulatory framework may be insufficient for ensuring a fair resolution in the event ofleakage damage to human health or private property.


### • Currently, C02has not yet been classified as a pollutant or a hazardous substance. If embedded C02 

### is not classified as such, then federal environmental statutes may lose protection from C02leakage damage, since these laws were created to assess and assign responsibility for damage from hazardous substances. However, C02

### could ultimately be classified as a pollutant, especially iflarge-scale implementation of CCS leads to negative impacts on environmental media. This classification would

7 Elizabeth Wilson and Mark de Figueiredo. "The Impact ofLiability on the Adoption and Diffusion of Carbon Capture and Sequestration Technologies," page 6. 8 545

## u.s. 469 (2005).have a significant legal impact and would likely increase the costs associated with CCS activities. 

## • There is uncertainty in the governance ofthe Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) over private property damage cases that are caused by sequestered C02• No carbon injection subsurface trespass legal precedents exist, and there is scientific uncertainty ofembedded C02impacts. 

### • Ifthe CCS process causes a release or substantial threat ofa release ofanypollutant that maypresent an imminent and substantial danger to the public health or welfare, liability will likely attach under CERCLA9 

### • Ifarea-wide contamination is the result ofCCS activities, potential parties could be held liable under CERCLA. To the extent that specific provisions ofthe CWA and the Safe Drinking Water Act (SDWA) are incorporated into the applicable orrelevant and appropriate requirements (ARARs), those standards could then govern the remedial activities ofa CERCLA cleanup. 

### • In the case that CCS results in collateral damage to natural resources, responsible parties could be made liable under the Natural Resources Damage Assessment (NRDA). 

## • The existence ofcitizen suit provisions, especially with respect to water laws in the Western U.S., introduces another level ofuncertainty because any regulatory balance can be altered by a citizenbringing suit because ofa lack ofprosecutorial diligence, whether actual orperceived. 

### • Innuisance tort cases or other grievances related to C02leakage, the potentially responsible parties under CERCLA are unclear. Federal and state government regulators, carbon injection operators, and public power generators ofC02 may all be candidates for some portion ofliabilityunder the 'joint and several liability" provision inthe CERCLA statute's "cradle to grave" liability scheme. 

## • There may be legal difficulty in assigning responsibility for seismic disruption damages caused by carbon injection due to scientific uncertainty and lack ofa legal precedent. 

## • In the case ofnatural seismic action leading to future C02 leakages, assigning liability based on fault may be impossible and lead to difficulty inhandling the resultant damages. 

### Long-Term Stewardship and Liability Assignment ofliability associated with leakage and migration ofC02deposits and resulting public health or environmental impact is further complicated by the extended time frame ofcarbon storage, which may exceed the lifespan ofindustry participants. For example, determining which party is responsible for the C02monitoring at a power plant after the plant is decommissioned orretired is difficult.

• The existing legal framework for EOR carbon sequestration has insufficient long-term storage and monitoring controls for large-scale CCS projects. • The continuous existence ofa viable entity is questionable under the current legal framework. Itis still an open question whether long-term liability should rest with a public or private entity. To ensure the future economic burden associated withthe

9 CERCLA § 104

### CCS site will not rest on the public as a whole, issues oflong-term stewardship, land use controls, and data tracking will need to be addressed. • Assignment ofliability in C02 

### releases is especially difficult ifthe companies that managed the injection and monitoring no longer exist or ifthey utilize subsidiaries to limit liability. • Additional research is required to improve scientific knowledge ofcarbon storage, which would help to inform the liability debate. • Plugged CCS injection sites will require effective long-term stewardship performed by a government or private entity. A detailed framework mustbe firmly established inthe U.S. Environmental Protection Agency's (EPA) Underground Injection Control Program, which provides governance for C02 

### injection under the SDW A. 10 

### • Although geologic sequestration currently meets the statutory definition of "underground injection" in section 142l(d)(l) ofthe SDWA, EPA is currently evaluating Department ofEnergy (DOE) pilot projects to determine ifchanges to the regulations are required for long-term CCS. • Since EPA currently has the statutory mandate to protect underground sources of drinking water and aquifers, the unknown results ofthese DOE pilot projects leaves legal uncertainty with respect to the future ofCCS activities. 

### Further Research This white paper is intended as an overview ofpotential environmental and legal issues that could arise in a large-scale CCS operation. It

### is meant to promote further research and discussion ofthese areas before large-scale CCS implementation can provide one of the many technological solutions to constraining carbon from existing or future power plants. A pressing need for reducing greenhouse gas emissions and halting their effect on climate change is driving the current political impetus to institute commercial-level CCS on a short time frame. However, for commercial CCS to effectively reduce emissions and mitigate the effects ofclimate change, a comprehensive plan and effective regulatory framework that respect potential obstacles and adverse impacts are essential. Technical and economic barriers to implementing commercial-level CCS are substantiaL butthey are also currently under significant scrutiny. The legal and environmental challenges ofCCS should be analyzed and addressed with similar vigor in order to promote effective and sustainable practices inthe United States. Research on these aspects will inform cost-benefit analyses ofCCS in relation to other methods being developed to mitigate climate change, allowing for optimal distribution ofpublic and private resources.

\

10 Testimony ofActing Assistant Administrator William Wehrum and Assistant Administrator Ben Grumbles, U.S. Environmental Protection Agency. Subcommittee on Energy andAir Quality, UnitedStates House of Representatives, 6 March 2007.

### Marianne L. Horinko is the Executive Vice President ofthe Global Environment & 

### TechnologyFoundation (GETF). Prior tojoining GETF, she served as Assistant Administrator for the Office ofSolid Waste and Emergency Response (OSWER) at the U.S. Environmental Protection Agency from 2001 to 2004, and Acting EPA Administrator in 2003. She led the emergency responses to the 9/11 attacks, anthrax contamination, and the Columbia Space Shuttle disaster. She brought new approaches to environmental protectionusing partnerships, flexibility, and innovation. The Brownfields program, signed into law byPresident Bush in 2002, embodies these goals. During the first Bush Administration, Ms. Horinko was Attorney Advisor at EPA. Subsequently, she served as President ofClay Associates and practiced environmental law at Morgan, Lewis & 

### Bockius, a national environmental policy firm, where she assisted in the creation ofthe RCRA Policy Forum. She graduated from the University of Maryland (analytical chemistry) and Georgetown University Law School. GETF is a 50l(c) (3) not-for-profit foundation that works with government, industry, academia, and non-governmental organizations to advance sustainable solutions and practices that promote environmental stewardship.Ameri<llln P!>blie Po-wr Asoocialloo American Public Power Association 1875 Connecticut Ave, NW Suite 1200 Washington, D.C 20009 202-467-2900; fax: 202-467-2910 www.APPAnet.org

Retrofitting Carbon Capture Systems on Existing Coal-fired Power Plants A White Paper for the American Public Power Association (APPA) L.D. Carter December 2007

Summary: Itwill be necessary to reduce C02 emissions from existing coal-firedpowerplants for the U.S. to reach the goals stated by some legislators for managing global climate change. The majortechoology choices for existing plants include post-combustion capture systems using chemical sorbents to isolate and concentrate C02, and reconfiguring the unit to use pure oxygen ratherthan air as the combustion oxidant (yielding flue gas with a muchhigher concentration of C02). Both existing techoology approaches arecostly, and both involve large parasitic power needs that canreduce the output ofthe existing unit by one-third. The changes introduced by retrofitting carbon capture and storage (CCS) on an existing powerplant will raise variable costs, and could thereby lower the unit in the utility's dispatch order. Capture and storage concepts have been implemented on a small scale, but not on the scale necessary for large coal-fired powerplants. Furthermore, most research on CCS is focused on new powerplants and not issues that maybe more relevant to existing powerplants. In addition to overcoming technical issues, CCS retrofits will face as yet undefined regulatory challenges, as well as liability issues related to the underground migration ofstored C02 over a timescale that exceeds the scope oftraditional risk mitigation instrmnents, like insurance. These challenges are daunting. Research and policy development are bothproceeding, but whether current efforts will be sufficient to result in a solution set that enables the nation to continue to enjoy the benefits oflow-cost electric powerremains to be seen.

1Introduction Existing coal-fired powerplaots inthe U.S. emitted 1.96 billion metric tons ofC02 in2005, or about 27% oftotal U.S. emissions ofgreenhouse gases (GHGs). 1 These powerplants generate about one-halfofthe electricity in the U.S., aod are in large part responsible for the U.S. enjoying power costs that are among the lowest in the world.2 Congress has notpassed legislation to reduce GHG emissions, butmaoy bills have been introduced and others are under development, with some seeking reductions in U.S. emissions as high as 30% in 2030 and 80% in 2050. 3 The Chairmao ofthe House Energy and Commerce Committee has identified a reduction goal for that committee's legislation of"between 60 percent aod 80 percentby 2050."4 Such large emission reduction goals will notbe met without significaotly reducing emissions from existing coal-fired powerplants. To date, most discussion ofGHG emission mitigation related to coal-basedpowerproduction has focused on new coal-based powerproduction, aod detailed engineering studies have evaluated the cost aodperformance ofvarious options for those newunits. 5 With currently available technologies, C02 capture aod storage options (in saline formations) from these new units cost 7 $30- 70perton ofC02 avoided. 6 The reader is referred to an earlier APPA White Paper for a general overview ofcarbon capture and storage (CCS) from coal-based powerplaots. 8 This paper addresses those aspects ofCCS that are ofparticular interest to retrofitting this technology on existing coal-fired powerplants. Withrespect to retrofitting existing coalunits, a 2005 IPCC report concluded: "Retrofitting existingplants with C02 capture is expectedto leadto higher costs andsignificantly reduced overall efficiencies thanfor newly builtpowerplants with capture. The cost disadvantages of retrofitting may be reduced in the case of some relatively new andhighly efficient existingplants orwhere aplant is substantially upgradedor rebuilt. " 9

1 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1900-2005, U.S. EPA, EPA 430-R07-002, April15, 2007. Note that the percentage includes non- C02 greenhouse gases, and excludes sinks. 2 Electricity Prices for lndustrv, DOE/EIA, June 2007, http://www.eia.doe.gov/emeu/international/elecprii.html

. 3Climate Change: GHG Reduction Bills in the 11 O'h Congress, Congressional Research Service, Rpt. #RL33846, January 31, 2007. 4 Memorandum from John Dingell, Chairman ofCommittee on Energy and Commerce, and Rick Boucher, Chairman of Subcommittee on Energy and Air Quality, to Members, Committee on Energy and Commerce, October 3, 2007. 5 See, for example, Cost and Performance Baseline for Fossil Energy Plants, U.S. DOE National Energy Technology Laboratory, DOE/NETL-2007/1281, May 2007. 6 Ibid. It should be noted, however, that most publicly available reports on C02 capture and storage are based on markets that existing before 2005, and that since that time, power plant capital costs have escalated dramatically. The NETL report states (p.42) that it incorporated escalation through the Yd Quarter of2006, but the basic power system costs cited still appear below costs reported by utilities in the news media. 7 Carbon Dioxide Capture and Storage, UNEP/IPCC, 2005, avoided costs projected at 30-70 $/t C02 for new pulverized coal units and 14-53 $/t C02 for new IGCC units, p.347. 8 Carbon Capture and Storage From Coal-based Power Plants: AWhite Paper on Technology for the American Public PowerAssociation (APPAl, L.D. Carter, May 22, 2007 (available from APPA at http://www.appanet.org/files/PDFs/Attachment%20%233.pdf ). 9 Op.Cit., Carbon Dioxide Capture and Storage, p.10. 2Technology Choices The vast majority ofexisting coal-firedpowerplants are pulverized coal units. Pulverized coal units have two choices for CCS retrofit: post-combustion capture ofC02 using chemical sorbents, and replacing the existing air-combustion system with an oxygen-fired system, thereby creating a flue gas which is mostly C02 . 10 Post-combustion C02 capture Figure I depicts a post-combustion C02 capture system. Inthis system, an acid gas sorbent vessel is placed downstream ofconventionalpollution capture systems. C02 is absorbed into an appropriate chemical, such as an amine, which is heated in a separate vessel to release a high concentration stream ofC02 and the regenerated sorbent. The concentrated C02 streamis then pressurized to about 2000 psia, for transport (as a supercritical fluid) viapipeline to an injection field. There it is injected into a stable formation as deep as one mile underground. Theprocess requires large amounts ofenergy, bothto strip the C02 from the sorbent and to compress the concentrated C02• In a study ofcapture technology at greenfield, or new, powerplants, NETL 11 concludedthat whether the plant was subcritical or supercritical in design, the CCS system resulted in about a 12% absolute drop in efficiency (e.g., from 33% to 21 %). 12 Figure 2 shows the components responsible for the additional power needs in the CCS-equipped system, based on data inthe NETLreport for a subcritical powerplant. As canbe seen from the figure, about onehalfthe power needs related to C02 compression, about one-fourth was attributable to the C02 amine system, and most ofthe rest derived from additional fans andpumps needed for the enlarged generation system (which bums more coal for the samepower output) and the greatly enhanced cooling system. The C02 capture system (alone) requires about twice as much cooling water as the originalpowerplant. An additional complexity ofthe CCS-equipped system is an S02 polishing unit. For a high sulfur (IL #6) coal system, even a 98% efficient wet FGD system exhausts flue gas with about 40 ppm SO,. To suppress formation ofheat stable salts inthe sorbent, this mustbe lowered to about 10 ppm. The NETL design accomplishes this at a new unit by using a serial combination ofa traditional wet limestone FGD and a sodiumhydroxide polishing scrubber. The various pieces ofhardware required for C02 capture and compressionrequire space. NETL reports that about one acre oflandis needed for each 100 MW ofgenerating capacity. 13 A separate NETL report suggests that landrequirements for capture and compression equipment at a 500 MW unit wouldbe 60 acres, or 12 times the first estimate. 14 In either case, this space requirement canbe a major obstacle to retrofitting C02 capture systems on existing units which are already space-limited due to previous retrofits for S02, NOx, and mercury control systems.

10 An innovative multipollutant ammonia-based capture technology is currently being investigated by U.S. DOE, in collaboration with Powerspan Corporation. The lack of publicly available data on a commercial version of this technology preclude its inclusion in this analysis. Additional information is available at: http://www.netl.doe.gov/publications/factsheets/rd/R&D043.pdf

. 11 NETL is the National Energy Technology Laboratory, which is owned and operated by the U.S. Department of Energy. See: http://www.netl.doe.gov/. 12 Op.Cit., Cost and Performance Baseline for Fossil Energy Plants, Exhibit ES-2. 13 Carbon Dioxide Capture from Existing Coal-Fired Power Plants, DOE/NETL-401/120106, p.xviii, December 2006. 14 Carbon Sequestration Program Environmental Reference Document, DOE/NETL DE-AT26­ 04NT42070, August 2007, p.2-42. 3Regarding technology readiness, the 2007 NETL report states: "The post-combustion C02 removal technology for the PC and NGCC cases is immature technology. This technology remains unproven at commercial scale in power generation applications." 15 Oxy-combustion approaches Ifa pulverized coal powerplant is fired with nearly pure oxygen, instead ofwith air, the nitrogen in the traditional combustion air is eliminated from the flue gas, and the flue gas is composed primarily ofC02, water vapor, excess oxygen and trace gases like S02, NOx, and HCl, although air infiltration can reintroduce nitrogen and more oxygen. After removal ofwater vapor, the flue gas is approximately 80-98% C02. 16 As a result, the sorption/desorption equipment needed in the "Post-combustion" example above is mmecessary, although some purification may be needed prior to C02 injection and storage. Forpurposes ofthis paper, this oxygen-based approach to C02 capture will be termed "oxy-combustion", even though it is actually another form of"postcombustion" C02 capture. In the oxy-combustion system, some ofthe C02 from the flue gas (about twice the volume ofthe ()Xygen supplied) must be recycled to reduce combustion gas temperatures from 3500 "C to a boiler tolerant 1900 "C. Oxy-combustion raises the possibility ofreduced cost for downstream cleanup oftraditional pollutants, either by storing them with the C02 or by reducing the volume ofthe flue gas stream dramatically through elimination ofnitrogen oxide and use ofC02 recycle. 17 Additionally, the potentially higher combustion temperatures and the improved heat transfer properties ofoxy-combustion gases meanthat it maybe possible to achieve higher thermal efficiencies than possible with other approaches to C02 capture. The major drawbacks to this approach for C02 capture are large parasitic powerrequirements, primarily for oxygen production and C02 compression, and the cost ofthe oxygen production facility. Ongoing research into improved techniques for oxygen production may mitigate these drawbacks to some degree. With current technology, cost and parasitic powerneeds for oxycombustion are about the same as for post-combustion C02 capture. The potential advantages for oxy-combustion C02 capture are speculative at this point. Itmaybe easier to locate an oxygen plant than a C02 sorption tower at an existing plant, where access to flue gas is already encumbered by retrofit S02 scrubbers and other hardware installed after the plant was initially constructed. Andthe parasitic powerneeds for an oxy-combustion plant are more electrical than steam, so integration with the existing unit may be simpler. A cross-platform comparison A recently published report by DOE/NETL compares a basic newpulverized coal unit both to one with similar power output, butwith post-combustion C02 capture, and to a coal unit with oxy-combustion C02 capture. NETL examined both supercritical and ultra-supercritical designs. 18 Table 1 presents several outputs from the study for the supercritical designs.

15 Op.Cit., Cost and Performance Baseline for Fossil Energy Plants, p.40. "PC" refers to pulverized coal power plants, the traditional technology for burning coal to produce electricity. "NGCC" stands for natural gas combined cycle power generation. In a NGCC, natural gas is burned in a combustion turbine (much like ajet engine) that drives a generator to make electricity. Hot exhaust gases from the combustion turbine are used to convert water to steam, which expands through a steam turbine to drive a second generator. 16 Op.Cit., Carbon Dioxide Capture and Storage, p. 122. 17 Ibid., p.123. 18 Pulverized Coal Oxycombustion Power Plants, DOE/NETL-2007/1291, August 2007. 4Note that both approaches to C02 capture, with currenttechnology applied to**a~** power plant, nearly doubled the power plant's capital cost and the cost ofelectricity produced. Table I. Comparison ofcost and performance ofcapture systems (new plant). Parameter Post-comb'n Base Oxv-comb'n C02 capture 90% No 100% Gross capacity, MWe 667 584 793 Net capacity, MWe 554 549 546 Netplant beatrate, Btu/kwh 8,649 12,538 12,074 Netplant efficiency (HHV),% 39.5 27.2 28.3 Total Plant Cost, $/kw 1563 2857 2930 Levelized cost ofelectricity, $/MWh 62.9 114.4 113.0 Cost ofcapture, $/ton C02 avoided n.a. 63 52 Negligible S02 emissions, #S02/mmBtu 0.085 0.003 NOx emissions, #NOx/mmBtu 0.07 0.07 0.07

It should be repeated that the above table relates to newpowerplants. Traditional pollution control technologies designed for new powerplants usually have a higher cost per unit ofpower output when applied to existing units. These cost "retrofit factors" have notbeen established for carbon capture technology, but for traditional pollutants like S02 and NOx, they canbe a 25-40% cost increase over the cost ofa comparable system at a new facility. The other major distinction for existing units is that they cannot easily be expanded to accommodate the very large amount of parasitic powerneeded to run the capture systems. Note that for the new units in Table 1, gross generating capacity was increased 15-35% to provide that power. At a retrofit unit with 33% energy conversion efficiency, a loss of12% (absolute) efficiency means a loss ofmore than one-third ofthe output ofthe power plant. Replacement ofthis parasitic power, at today's escalated prices for newpower plants, will introduce a major cost barrier to retrofitting existing units for C02 capture. It could also present limitations on how quickly regulations could be implemented. For example, recall that the 2005 Clean AirInterstate Rule (CA!R) was by necessity introduced inphases (the necessity being that skilled labor limitations precluded a one-step regulatory process). 19 Consider the comparative difficulty ofretrofitting C02 capture systems onthe existing 320 GW coal-fired powerplant fleet. The utility industry would need to install over 100 GW of additional new capacity for replacement power needs (above expected demand growth needs), and simultaneously install 320 GW ofC02 capture and compression systems, versus roughly 100 GW ofS02 scrubbers and NOx selective catalytic reduction systems under CAIR. A final issue specific to existing units is that a different level ofC02 capture performance may be appropriate for those units. Most technical studies assume a high level, e.g., 90%, ofC02 capture for new units 20 • Under either a cap and trade or carbon tax approach to managing greenhouse gas reductions, the best strategy is usually considered to be the one that achieves the desired global emissions reduction at the lowest cost. For existing pulverized coal-fired power plants, it is too early to determine what the most cost-effective level ofcontrol will be, but it might be much lower than 90%.

19 Federal Register, 70FR25197, May 12, 2005. 20 This level of performance has yet to be demonstrated as either technically or economically feasible. 5Operational issues related to CCS Most generating unit-level analyses ofthe cost impacts ofenvironmental requirements focus on the levelized cost ofelectricity (COE) implications ofmeeting the rules. Itis also important to examine dispatching costs (or variable costs) under alternative compliance scenarios, because if variable costs increase significantly, the unit may become too expensive to dispatch, making the capacity factor assumptions inthe COE projections (and the COEresults) invalid21 The costs for CCS retrofits are so large, and impacts on variable costs likewise large, that it is quite possible that a unit in which a large investment was made would not be used very much in an economically dispatched system. One only has to consider the significant amount ofidle natural gas combined cycle (NGCC) units in the U.S. to recognize the reality that flawed assumptions with major economic ramifications are notjust a theoretical possibility. The large parasitic powerrequirements ofCCS introduce additional analytical complexity regarding the use ofsystems equipped with C02 capture, particularly retrofitunits. Dispatching costs for these units willbe much greater due to the higher fuel consumption, and purchase of replacementpower. Moreover, ifreplacement power were purchased from another source, then all ofthe cost ofreplacement electricity could be considered a variable cost. Figure 4 compares dispatching costs (or variable costs) for several hypothetical systems, based on cost and performance darn reported by DOE/NETL.22 The NETL costs were adjusted by assuming EIA AE0-2007 costs for natural gas and coal in 2020 (both the EIA reference price and "High Price" scenarios were used for natural gas). In addition, the NETL analysis was for a greenfield, ornew powerplant. A retrofit factor of50% was applied to the capital and variable O&M costs for the new plant figures in the NETL report. Figure 4 presents dispatching costs for a range ofcarbon taxes (0-100 $/metric ton C02), for coal and natural gas. Additionally, the costs in the figure reflect purchase ofmakeup powerto replace the power required to run the CCS system, an issue further discussed below. Note that the basic coal plant has a variable cost ofabout 20 $/MWh and a natural gas plant is about twice that amount, without any C02 capture. At 90% capture, variable costs increase to about 60-65 $/MWh for the coal system and for natural gas combined cycle systems equipped for capture, for a range ofnatural gas prices. The dashed lines in the figure represent an uncontrolled plantpaying the relevant "tax", rather than capturing the C02, and a "hybrid" approach of controlling halfthe C02 and paying the tax for the remainder. These calculations are imprecise, but they indicate that until C02 taxes or cap/trade costs exceed about $50/ton C02, coal units without capture (and paying a C02 tax) will be dispatched ahead of coal and natural gas units with capture. Other factors, such as subsidies paidto units that capture C02 and improvements in the technology, could certainly impact these results dramatically. For perspective, S.1766 (Senator Bingaman's climate change bill), which becomes progressively more stringent over time, begins with a "safety valve" price of 12 $/ton C02 in 2012, and reaches $50/ton in about 2040.

21 For example, most simplistic analyses oftechnology options assume a constant level of power generation (or capacity factor) across technology alternatives. In practice, however, utilities operate most those units with the least variable costs (which include fuel consumption and variable operation and maintenance costs). Ifthese variable costs increase markedly for some technology options, then the assumption of constant generation across technology alternatives is incorrect, and the resulting COE calculations are likewise in error because fixed costs (such as capital costs) must now be paid with fewer kilowatt-hours of generation. 22 Op.Cit., Cost and Performance Baseline for Fossil Energy Plants. 6A keyparameter in these cost comparisons is the cost ofreplacement power for the CCS system. Replacement poweris estimated to be about 30% ofthe total plant generation for a pulverized coal system, and about one-halfthat for a natural gas combined cycle (NGCC) system. Who provides the replacement power is also important to dispatching costs. Ifthe power is purchased from another utility, then its costs can be taken entirely as variable costs. Ifthe replacement power is generated by the same utility that is retrofitting the CCS system, then only its variable costs are included in the dispatching costs for the retrofit system. Dispatching costs for this latter case ("self-generation" ofreplacement or parasitic power) are presented in Figure 5. This differential effect ofwho supplies the replacementpower can be seen in comparing Figures 4 and 5. The coal-based systems with CCS show a significantreduction in dispatching costs for the "selfgenerated" replacement power case (Figure 5), relative to the "purchasedpower" CCS case (Figure 4). Note that the break-even point for coal systems "paying the tax" versus retrofitting CCS has shifted from a tax level of $50/ton C02, to $20/ton C02 for the self-generated replacement power scenario. The NGCC systems are not as sensitive to the source ofthe replacement power, because most ofthe cost ofNGCC power is the fuel cost, which is a variable cost in either scenario. Forthe self-generatedreplacement power scenario, the dispatching costs for a pulverized coal unit retrofit with CCS is about 40-50 $/MWh over a range ofcarbon taxes, which makes it comparable to NGCC systems without CCS retrofits. The take-home message here is not the absolute values ofthese projected costs, but rather the fact that analysts and decision-makers must be careful regarding how these costs are evaluated, and ensure that the assumptions used are appropriate for the systembeing evaluated, or they canbe seriously misled. A related factor is the impact ofparasitic powerneeds onbulktransmission ofelectric powerto regions that are traditionally "net importers" ofpower. Ifa utility has generation capability that exceeds its local needs, it generally tries to sell that powerto neighboring power consumers that have insufficient self-generation capacity. Iflocal excess power is eliminated by retrofitting CCS systems on existing coal (and gas) powerplants, then those utilities that previously purchased the excess power will quite likely lose that source ofelectricity. Hence, the sudden broad deployment ofthe current generation ofCCS technology could be disruptive to power systems that do not even operate fossil fuel-fired generators. Carbon dioxide transport and storage The cost and performance aspects ofcarbon dioxide transport and storage are well covered in the literature. 23 The important factors related to transport and storage are: 1. The cost oftransport and storage are believed to be a small fraction ofthe capture costs. 2. There is experience with pipeline transport and injection/storage at relatively small scale, but no experience with storage atthe scale ofcommercial coal-fired power plants (e.g., 3 million metric tons peryear for a single 500 MW unit). DOE is now beginning a program for evaluating "1 million TPY" demonstration projects, butresults are years away. 3. There is no environmental regulatory framework for addressing the injection and storage ofC02 in the most likely resource for coal-firedpowerplants: saline geological formations perhaps one mile below the surface. EPA recently announced its intent to begin development of such a program under the Underground Injection Controlprogram (UIC). See APPApaper on the current UIC program posted at http://www.appanct.org/filcs/HTM/ccs.html 4. There is likewise no framework for addressing financial liability associated with CO, storage. Existing insurance mechanisms are not practical for a system that must maintain its

23 Op. Cit., Carbon Dioxide Capture and Storage, Chapters 4 and 5. 7integrity for hundreds ofyears. Itis unlikely that electric utilities will embrace CCS technology until pragmatic frameworks are established. Regulatory Issues for Retrofits Clean AirActPermits andFederalNew SourceReviewIssues Aside from the obvious regulatory issues associated with C02 capture and storage that include permitting underground injection wells and obtaining rights to underground caverns for disposal, 24 it also is likely that the retrofit ofan existing electric generating unit will result in the retrofit being deemed a "major modification ofa major Clean Air Act-regulated source." 25 This is because the C02 capture system may lead to increases in other pollutants regulated under the Clean AirAct. Major modifications are suhject to the federal new source review (NSR) program, which includes lengthy permitting, modeling ofair quality impacts, and installation ofstate-ofthe-art pollution control equipment on the retrofitted boiler and ancillary emitting equipment. Under current federal law even environmentally beneficial projects canbe subjected to lengthy regulatory processes, public scrutiny which can include legal challenges, and additional costs deriving from analytic requirements for permitpreparation and additional pollution controls. It should be noted that NSRmay be required for S02 and NOxretrofits installed pursuant to the 2005 Clean AirInterstate Rule (CAIR) because the S02 and NOx pollution control equipment may leadto small increases ofpollutants other than S02 andNOx.26 However, even ifthe NSR exemption for "pollution control projects" still existed27

, typical retrofits to existing powerplants likely still wouldrequire NSRreview. The large parasitic power requirements ofCCS technology will very likely lead to increases in coal use at existing units. 28 For some pollutants, like S02, the additional reduction ofthat pollutant that occurs as part ofthe CO, capture process will negate the increased amount ofcombustion. Forothers, like particulate matter, the situation is not as clear. In addition, some ofthe components ofthe C02 capture

24 It is important to note that in some states, ownership of surface rights does not convey ownership of subsurface mineral or other rights needed for the disposal of carbon dioxide underground. 25 This term "major modification of a major source" has been the subject of extensive historical and ongoing regulatory and litigation controversy. This paper does not attempt to unscramble or recount these controversies, but instead calls to the reader's attention that caution and additional costs associated with federal (and state) Clean Air Act permits will be associated with CCS retrofits. 26 See, for example, Clean Air Report, Inside EPA, September 20, 2007, p.1; and New Source Review for CAIR and CAMR Projects, August24, 2007 draft proposal by Indiana agency representatives to the Environmental Council ofthe States (not adopted by ECOS). 27 The D.C. Circuit Court ofAppeals held that EPA could not exempt pollution control projects from New Source Review regulations, New York v. EPA, 413 F.3d 3 (D.C. Cir. 2006). 26 Consider the following simplistic example. An existing coal-fired power plant operates 60% of the year at full load, 30% at half-load, and is down for maintenance 10% of the year. After retrofit for CCS, the amount of coal used (and emissions) are unchanged for the full load and no load portions of the year. But for the 30% ofthe year historically run at half load, assuming demand remains the same and ignoring dispatching economics, to produce the same amount of megawatt-hours the unit will have to operate at approximately 70% capacity factor due to parasitic power loss. This higher operating level would lead to greater uncontrolled emissions. Increases in operating hours are not an exclusion from NSR if the increase is a direct result of a physical change at the unit. The ultimate determination ofwhether these circumstances constitute a "major modification" would depend on how State, EPA, and the courts interpret the regulations, as well as possible emission mitigating measures that the retrofit facility might undertake. 8system may be sources offugitive emissions ofvarious pollutants regulated under the Clean Air Act. NSR Review of C02 and Other Green House Gases (GHG) C02 and other GHG also are likely to be regulated NSRpollutants for purposes ofNSR review by the end of2008 pursuant to a decision by the United States Supreme Court that these emissions were Clean Air Act "pollutants."29 EPA officials announced at the September 2007 meeting ofthe federal Clean Air Act Advisory Committee that the agency intended to complete regulations limiting C02 and five other GHG from motor vehicles and possibly refineries by the end of2008. The regulation ofC02 under Clean Air Act requirements (except as a "hazardous airpollutant" 30) renders these substances a "regulated air pollutant" for purposes ofNew Source Review and Federal Operating Permits under 40 CFR subparts 51, 52 and 70 (the NSR and Part 70 Operating Permit regulations). EPA officials also announced that they intend to undertake an NSR rulemaking by the time GHG are regulated to define what a "major source" ofGHG is, and even more importantly, what "significant increases" ofGHG are for purposes ofdefming the term "major modification." 31 Assuming C02 and other GHGbecome regulated air pollutants, a significant netincrease ofany GHG within the facility will trigger NSR. This creates a situation analogous to the previously discussed paradox where environmentally beneficial hardware installed to reduce S02 and NOx emissions under the CAIR rule could trigger NSRrequirements due to small associated increases in particulate matter emissions. Similarly, the retrofit oftraditional pollution control devices, like SO, scrubbers, also could trigger "majormodification" status for that facility for COz, in the absence ofthe now-defunct "pollution control exemption". This would lead to case-by-case Best Available Control Technology (BACT) reviews for C02 emissions. Reconstruction and Clean AirActNew Source Performance Standards Ifa facility retrofit constitutes a "reconstruction" ofa facility under the Clean Air Act's New Source Performance Standards (NSPS) regulations, the owner or operator must meet NSPS for the "affected source." Thus, it is important to examine how EPA has interpreted the term, 32 defined in the regulations as: 40CRF60.15 (b) "Reconstruction" means the replacement of components ofan existing facility to such an extent that: (1) The fixed capital cost ofthe new components exceeds 50 percent of

29 In Massachusetts v. EPA U.S. 127 S.Ct.1438, 75 USLW4149 (April2, 2007), the Court addressed Massachusetts and other states' petition challenging the agency for failing to regulate GHGs under the Clean Air Act's mobile source program. The Court determined that these substances were "air pollutants" underthe Act and essentially held that EPA must regulate vehicular emission of C02 unless the Agency determines that C02 does not endanger the public's health and welfare. EPA is expected to regulate C02 emissions from mobile sources, and that regulation will likely trigger requirements for new or modified major stationary sources such as power plants ifthey have more than de minimis increases in C02 emissions. 30 Note that if C02 were regulated as a hazardous air pollutant under Title Ill of the Clean Air Act, PSD would not apply pursuant to section 112(b)(6). 31 Until EPA defines what a "significant emission increase" is under 40 CFR §§51.166(b)(23) and 52.21 {b){23 ofthe NSR regulations, "any" increase of pollutants will trigger NSR (and BACT) review. 32 EPA interpretations of NSPS for various affected industries can be searched on the Office of Enforcement and Compliance website on the "Applicability Determination Index" at http://cfpub.epa.gov/adi/. 9the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) Itis technologically and economically feasible to meetthe applicable standards set forth in this part. (c) "Fixed capital cost" means the capital needed to provide all the depreciable components. Since the addition ofa capture system does not fit neatly into the concept of"replacement of components," the applicability ofthe NSPS "reconstruction" test to CCS is unclear, in part because it is not clear whether the cost ofa "pollution control" is included in determining the cost ofa facility replacement." Also, "pollution control projects" (PCPs) and "clean coal technology" continue to be exempt from the NSPS definition of"modification" under 40 CFR §60.14(e)(5), even following a Court's ruling that the NSR exemption for PCPs was illegal because it might cause an increase in actual emissions.33 Nevertheless, even ifall ofthese conditions are met, a regulatory obligation for reconstruction based on C02 emissions can only exist after EPA adopts a C02 NSPS, under 40 CFR Part 60. Note, that this future rulemaking could create a preference for an oxy-fueled system versus a post-combustion system, depending on how the rules are specified. Storage Rules There is general recognition that the current underground injection control (UIC) program for waste injection is not well designed to address issues associated with C02 storage in deep saline reservoirs. The Interstate Oil and Gas Compact Commission (IOGCC) recently proposed that states take the lead onthis type ofregulation, given their extensive regulatory experience with C02 -based enhanced oil recovery. 34 Moreover, IOGCC expressed the view that C02 should be treated as a resource, rather than as a waste, and that treatment ofC02 as a waste "would diminish significantly the potential to meaningfully mitigate the impact ofC02 emissions through geologic storage." Shortly after IOGCC's report and announcement calling for state primacy, U.S. EPA announced that it was beginning a federal rulemaking, under the authority ofthe Safe Drinking Water Act, to address underground injection ofC02•35 Another local consideration that needs to be considered in the context ofCCS is the ownership of surface and subsurface rights. In certain states (and most with significant mineral rights), ownership ofunderground caverns may be distinct from ownership ofsurface rights. Careful examination ofdeeds and other landrecords may be necessary to establish property ownership and rights ofway for transport and sequestration ofgases.

33 New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005). 34 Storage ofC02 in Geologic Structures- A Legal and Regulatory Guide for States and Provinces, IOGCC, September 25, 2007. "A key conclusion ofthot report [a 2005 JOGCC study] was that given the jurisdiction, experience, andexpertise of states and provinces in the regulation of oil andnaturalgasproduction and naturalgasstorage in the United States and Canada, the states and provinces wouldbe the most logicaland experiencedregulators of the geologic storage of carbon dioxide."
35"EPA Rulemaking Plan May End States' Bid for Lead Role On C02 Storage", Inside EPA, October 12,2007, citing an Oct 11 announcement by EPAAdministrator Stephen Johnson. 10Other liabilities Two additional areas ofrisk management related to C02 storage are: 1. The potential for stored C02 to migrate into areas ofother valued resources, such as natural gas deposits, and diminish the value ofthose resources; and 2. The potential for C02 migration after closure ofthe injection site. Injection ofC02 from an operating plant may last for decades, but for the storage to be effective, the C02 must be contained for centuries. This timeframe is beyond the scope ofavailable commercial risk management issues. Effectively managing these risks mayrequire government participation, and that may require additional legislative authority. Looking to the future There is much ongoing activity related to CCS. The Department ofEnergy is focusing on both capture and storage, and several large storage projects are starting under the Regional Partnerships program. As noted earlier, EPA is beginning to develop rules for C02 storage, and initial regulatory responses to Massachusetts versus EPA are likely by the end of2007. Climate change mitigation legislation is receiving much attention in Congress. Nevertheless, given the significant contribution ofexisting coal-fired powerplants to both the nation's electricity supply and to national greenhouse gas emission rates, and the high cost of currently available mitigation techniques, the resources focused specifically on developing pragmatic solutions for this C02 emission group seem quite limited. Additional effort appears warranted to:

• Significantly drive down the cost ofC02 capture, both through "learning by doing" using current technology, and through additional research. • Explore ways to modifY the existing power plant itself, such as replacing turbines or turbine components, orupgrading boilers, so that the existing plant becomes more efficient and productive. This would provide both a partial cost offset to the increased cost ofelectricity due to CCS retrofit, and (possibly) reduce the impact ofparasitic power needs to drive the CCS hardware. • Gain experience with storing large quantities ofC02 in different types ofgeologic saline structures. The Regional Partnerships program may be a good start, but a few large projects are unlikely to be representative ofthe full range ofgeologies in the U.S. that are attractive for C02 storage • Increase our knowledge base and simplify traditional preconstruction pennitting procedures to expedite the permitting ofCCS retrofit projects.

11Abouttheauthor-Doug

### Cart~risan indel?endent consultmtorre!lergyteclmology ancl rela,ted environrnentalissJ.les: Hiscurrentpractiq,focus<;s 0ni!dvising clien,ts regarding advancedcoal-basedtechnologies and.theirpotential role inmitigating globalcli111ate**,·ch~11ge:** .Mr. Carter'sresumeincludes.25years

# \Vith theU.S, Department ofEnergy, where he wasDirectorqfthe Office ofP.i<mninga11dEnvironmentalAnalysis, within the Office of Fossil Energy. Hehadpreviously s.erved withthe Office ofEnforcement andOffice ofAir QualityPlanning and Standards.atthe U.S. EnvironmentalProtectionAgency

..·Mr. Carter holdsdegreesinMeehani(>ai Engineering andEnvironmentalEngineering. He can

### No

. reached at Carter2250@comcast.nct

. The America11 PublicPower Association isthe nation!\! service organizationrepresentingthe ·uation's moni than 2,000 community- and state-0wnedelectrkuiilities. APPA'swebsite is**~w.appanetorg** The dedic!lted website address for information on geologic sequestration andcarbon, capture an,d**!';eol~gic** sequestration orstorageis:. http://www.appanet.orgltlles/HTM/?cs.html

. .·,· .•.• ......· APPAContact: TheresaPu!>;ll, Director, Euvironrnentar Services, 

### 1875 Conn<;cticutAve, NW, Suite 1200,Washinglon, D.C. 20009c57!5orat(2()2}467c2943

Seepage 13-16 for figures



### 12Cooling system F&P, 13% Figures Figure 1. Pulverized coal powerplaut with carbon capture.

Coal

& Boiler

# &1\~1,

. '\SCRl

Sulfur ByProducts


### ' F1yash**~** Recycle**~**

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I

### ~------- -( Conde-nser 

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Figure 2. Sources ofparasitic power.
Additional Power Needs for CCS

Other,

C02 compression, 53% Amine system Aux. 24%

13Figure 3. An Oxy-combustion unit with C02 capture.

Electric Power Solid 

# I 1 

## 1---+---------l By Products

- - - - - COndensCI:' Note: C02 recirculation maybe taken from before or after the FGD system, depending on

### so2 concentration. 

### ' Flya.h Recycle



## ---------------------**~~** 

# .., Sulfur ByProducts

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14Figure 4. Dispatching costs assuming replacement power is purchased. 

## Dispatching Cost for Fossil Generating Options

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### ;: 80 

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# - II) 60 0 <>



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# "' 40


### > 

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### Carbon Tax, $/metric ton C02

"" "" PC, no capture but paying tax PC, w/50% capture • -PC,w/90% capture

... .., NGCC, no capture but paying lax -NGCCw/90% capture, Ref. Price gas -NGCCw/90% capture,**$6.6~-- ~~~** 



### 15Figure 5. Dispatching costs assuming self-generated replacement power.

120

100**~** ..c: 

### ;:: 80 ::;;; 

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## Dispatching Cost for Fossil Generating Options

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### 16American Public Power Association



### Carbon Capture and Storage From Coal-based Power Plants: A White Paper on Technology for theAmerican Public Power Association (APPA) L.D. Carter 

### May 22,2007 Introduction Technology for carbon capture and storage (CCS) from coal-based electric powerplants is rapidly emerging. The component technologies for capture and transport exist, although they are relatively costly compared to other emission control systems (increasing the cost ofelectricity by over 60%). Technologies for injecting carbon dioxide (C02) into partially depleted oil reservoirs have been used for enhanced oil recovery (EOR) in the U.S. for over 30 years. Similar techniques have beenused since 1990 to inject C02 into saline reservoirs in Canada, in association with oil and natural gas processing1

. Additionally, a limitednumber ofpower plants have used chemical sorbents to capture C02 for reuse at very small scale (a few hundred tons per day, or less) 2 However, there is no commercial experience with commercial scalepowerplants capturing and storing large quantities ofC02 in geologic formations. Additionally, there is no existing regulatory framework that adequately addresses one unique feature of carbon storage: it must bepermanentto be effective. The challenge facing industry, and the regulatory community, is to address the technical gaps in integration ofthe technologies at hand, move aggressively with research and demonstration projects to significantly reduce the cost ofmore advanced carboncontrolled systems, build an improved understanding ofthe long-termbehavior ofC02 stored underground, and craft a pragmatic risk management framework for conducting C02 storage. Increasing the difficulty of this challenge is the fact that all ofthis must be done simultaneously, with limited resources, and at a time when continuous construction ofnewpowerplants is necessary to supply a healthy and growing economy.
1 Overview ofAcid-Gas Injection Operations in Western Canada. S. Bachu, Alberta Energy and Utilities Board, Edmonton, Canada, http:iiuregina.ca.igbgtJiPDFipapers.ipeer,...58R.pdf. 2 For example: Kerr-McGee/ ABB Lummus Crest Processusing MEA (Mono-Ethanolamine), Fluor Daniel ECONAMINETM MEAprocess, Kansai Electric Power Co. I Mitsubishi Heavy Industries, Ltd. (KEPCO/MHI) process using KS-1, KS-2, and KS-3 solvents. Source: Carbon dioxide Capture and Storage, IPCC, 2005, p.ll6.

1

### This paper will discuss the status of technology to capture C02 

### both from combustion-based and gasification-based power generation fueled by coal, and technologies to transport and store C02 

### in underground (geologic) formations. This paper is not intended to be a technology treatise, but rather to draw from the work of others to present decision-makers in the utility sector and the regulatory sector with an overview ofwhat is practical today and what is possible in the near future. C02 capture from combustion-based coal power plants Two C02 

### capture approaches are receiving strong interest for application with combustion-based power plants. The first is based on absorption offlue gas C02 

### by an aqueous solvent. COz concentrations in flue gas are modest, 12-15%, due primarily to presence of significant amounts of combustion-air nitrogen, and to "excess" air needed to ensure complete combustion of coal. For these concentrations, chemical sorbents have been shown to be effective at separating COz from the other flue gases, and releasing it in a concentrated stream for further processing. Figure 1 presents a diagram of a conventional pulverized coal power plant, equipped with such a COz "scrubber". Possible solvents include a family ofamine chemicals, which are molecular "cousins" to ammonia; proprietary solvents designed specifically to capture COz, such as "KS-1" solvent from Mitsubishi Heavy Industries; and advanced solvent concepts, such as chilled ammonia. For these chemical solvent-based capture systems, the C02 

### is captured in an absorption vessel (amines typically operate at 50

# oc (120 °F)). The C02

### -enriched sorbent is then pumped to a second vessel and heated to about 120 °C (250 °F) to drive off a concentrated stream of C02 

### and regenerate the lean solvent. The concentrated Cbz is dried and compressed to about 2200 psia for pipeline transport in a supercritical state to a site for use or storage. Parasitic power needs are substantial and include pumps, fans, solvent regeneration, and COz compression. In addition, the COz solvents tend to form "heat stable salts" with any remaining SOz or NOx in the flue gas. These stable salts do not break down in the solvent regenerator, so there is loss of solvent unless 802 

### and NOx are reduced to extremely low concentrations. These factors combine to lead to a 25% increase in fuel consumption per kilowatt-hour generated, and increase cost ofelectricity by over 60%. 3 

### Looking to the future, an absorption process using ammonia is under development by Powerspan, and will be tested on a slipstream from First Energy's 50 MW Burger plant in 2007 and 2008. Alstom and EPRI will test a chilled ammonia system at a 5 MW scale at WE-Energy's Pleasant Prairie station in 2007. AEP has signed a memorandum of understanding to test the technology at the Mountaineer Plant in West Virginia in 2008, and if successful, at the Northeastern Station in Oklahoma in 2011, for use with enhanced oil

3 Carbon Dioxide Capture and Storage, IPCC, Chapter 3, 2005.


### 2

### recovery.4 

### Ammonia is lower cost, has higher levels of C02 absorption, and requires less energy for regeneration than currently used chemical solvents, so success in these technologies could reduce the cost and energy penalty of C02 capture at conventional power plants. Oxy-combustion is a second approach to capturing C02 from pulverized coal power plants, and takes a radically different approach than C02 absorption. With oxy-combustion, the coal is burned with pure oxygen, not air, so the products of combustion are primarily C02, water vapor, and some excess oxygen (see Figure 2). To moderate boiler temperatures to about 1900 °C (3450 °F), it is necessary to recirculate a portion of the flue gas C02 (downstream ofthe particulate matter control system) back into the boiler. Particulate matter must be removed as usual, but nitrogen oxide formation is very low so the traditional selective catalytic reduction (SCR) system is unnecessary. The S02 system can be significantly downsized because it does not process the flow of excess air or nitrogen normally encountered with air-based combustion. The C02 capture system consists essentially of gas drying and compression, although some additional gas purification may be needed. This design approach can take advantage of highertemperatures and improved heat transfer from C02/H20 mixtures to allow a more compact (cheaper) boiler. Parasitic energy demands are high (e.g., 25%), because of the oxygen plant and C02 compression. None of these systems has been operated at a commercial scale, although most ofthe component technology is commercially available. Looking to the future, AEP has announced its intent to conduct a pilot demonstration of oxy-combustion in Summer 2007, followed by retrofit to an existing commercial coal-fired unit by 2015.5 

### In addition, DOE is working with Air Products and Chemicals, Inc., to develop an ion Transport Membrane approach for producing oxygen, to replace the conventional cryogenic oxygen plant, thereby reducing the cost and energy required for oxygen production. 6 

### C02 capture from IGCC 

### A different approach to C02 capture is associated with Integrated Gasification Combined Cycle (IGCC) power plants. In a conventionaiiGCC, coal is gasified to produce synthesis gas (primarily hydrogen, carbon monoxide, and carbon dioxide), which is then treated to remove contaminants and burned in a combustion turbine, which drives a generator to produce power. Hot exhaust gases from the combustion turbine are moved through a heat recovery steam generator to produce steam, which is expanded through a steam turbine and

4 Corporate Citizenship. the role oftechnology, AEP news release, http://www.aep.com/citizenship/crreport/climatechanqe/theroleoftechnoloqy.asp

. 5 Ibid. 6 Development of lon Transport Membrane Oxygen Technology for Integration in IGCC and Other Advanced Power Generation Systems, NETL project factsheet #136, May 2006, http://www.netl.doe.qov/publications/factsheets/projecUProj 136 .pdf

. 

### 3generates additional power (hence, the term "combined cycle"). Rather than capture the C02 at the end ofthis process, in an IGCC C02 is captured prior to combustion ofthe synthesis gas. This is possible because the synthesis gas can be reacted with water in a catalytic "shift reactor" to convert most ofthe carbon monoxide to hydrogen and C02. This leaves a modified synthesis gas consisting largely of hydrogen, water vapor, and C02, still under the relatively high pressure created in the gasifier. C02 is much easier to separate in this concentrated, pressurized state, than in normal flue gas. Following H2S removal, a physical solvent process, such as Selexol, can be used to separate the C02 from the hydrogen. The C02-rich solvent is then pumped to a separate vessel where concentrated C02 and lean solvent are regenerated by a reduction in pressure, rather than by the addition of heat as with chemical sorbents (see Figure 3). The hydrogen (instead of CO-rich syngas) is burned in a combustion turbine, and waste heat is used to generate steam which generates additional power, similar to an IGCC without C02 capture. The inherent advantage ofthis power generation approach is that the C02 capture system uses much less parasitic power, and costs less than systems designed for pulverized coal power plants. The inherent disadvantage is that the basic IGCC system (without C02 capture) remains a relatively immature technology, and costs more than comparably sized pulverized coal system without C02 capture. For example, Duke Energy estimates the capital cost of its proposed Edwardsport, Indiana, IGCC to be $1.985 billion for the 630 MWfacility, or over $3000/kw. 7 These costs are substantially higher than recent government reports which projected costs for such systems.8 Complicating this high capital cost is the fact that none ofthe four existing coal-based IGCCs has met its original design reliability goal with coal. In addition, high-efficiency combustion turbines fueled by hydrogen have not been commercially demonstrated. It may be possible to reduce the cost of C02 capture from IGCC systems, and use generation systems that do not require a hydrogen turbine, by capturing less than 90% ofthe plant's C02. For example, DOE's most recent analysis of IGCC gasifiers indicates that the GE system converts about 30% ofthe coal carbon into C02 in the synthesis gas (the rate for the ConocoPhillips design is about 25%, and the Shell system analyzed was much less). 9 This C02 could be captured at lower cost and with much less disruption to the overall plant design that a system including a shift reactor. Alternatively, the gas could be partially shifted, lowering the cost ofthe shift reaction, and probably leaving enough CO in the syngas to enable use of demonstrated combustion turbines, at the sacrifice of high rates of C02 capture. However, neither ofthese systems has been commercially demonstrated, or even well developed in published technical papers providing

7 Edwardsport IGCC FEED Study Report, (Redacted Copy), Duke Energy, as filed with the Indiana Utility Regulatory Commission, 2April2007. 8 Cost and Performance Baseline for Fossil Energy Plants- Updated Technical Performance, DOE/NETL, 10April2007, http://www.netl.doe.gov/technologies/coalpower/refshelf.html

. 9 1bid.


### 4

### detailed design or cost estimates. And neither would appear to overcome the basic cost and reliability issues associated with IGCCs without C02 capture. A number of developments that are underway are intended to make IGCC both more reliable and affordable. These include improved refractory, for refractory-lined gasifiers, which should reduce the outage time for rebricking, as well as allow higher gasifier temperatures, which will help carbon conversion; lower cost oxygen production processes (see above discussion of lon Transport Membranes); warm gas H2 S cleanup, which allows efficiency improvements; dry-feed coal "pumps" for gasifiers to replace lock-hopper approaches, and possibly, slurry feeds; and R&D on hydrogen fueled combustion turbines. Several of these improved system components should be ready for commercialscale demonstration on the FutureGen system, which is scheduled to begin operation in late 2012. 

### C02 transport Quantities of C02 on the scale of a coal-fired power plant's production (3 million tons peryear for a 500MW unit) will almost certainly be transported by pipeline unless injection occurs at the plant site. For pipeline transport, C02 is pressurized to a supercritical state that has the lowviscosity of a gas, and yet can be efficiently pumped like a liquid. Because ofthe extensive use of C02 for enhanced oil recovery, C02pipelines are a mature technology, and have been operating reliably in the U.S. for over 30 years. There are over 1500 miles of C02 pipelines in the U.S., transporting over 50 million tons of C02 per year. For example, the Weyburn pipeline carries 5000 tonnes per day of C02 (96% C02 and 0.9% H2 S) for 200 rniles between the Great Plains Synfuels plant in North Dakota and the Weyburn EOR project in Saskatchewan, Canada. Although C02 is considered an "acid" gas, as long as the flow is kept moisture free, standard carbon-manganese steels can be used for pipelines. 10 

### It should be noted that different states have different constraints on the concentrations of non-C02 gases permitted in C02 pipelines. Pipeline transport cost is generally not a major component of overall capture, transport, and storage costs. However, pipeline costs vary by the size ofthe pipeline with significant economies of scale. For example, transport via a 150 mile pipeline for C02 from a 500 MW power plant (about 3 million TPY) is estimated to cost about $3.00- 5.00/Tonne C02, whereas transport for a 2,000 MW facility would cost about $1.40- 2.10/Tonne C02. 11 

### An important issue related to pipelines is obtaining right-of-way for the pipeline. Additional legislation may be needed to ensure the ability to construCt C02 pipelines (eminent domain).

10 Op.Cit., IPCC 2005, p.182-3. 11 Op.Cit., IPCC 2005, p. 192; figures are in 2002 dollars.


### 5COz storage A number of options are available for C02storage. Figure 412 presents several ofthese options, including storage in depleted natural gas or oil reservoirs (which can involve EOR), storage in deep saline structures, and use for enhanced coalbed methane production. It appears that those storage options that provide a "rebate" on storage, such as EOR, will be insufficient to meet the storage requirements of a program requiring industry-wide capture and storage of C02. Additionally, power plants must compete with other, lower cost sources of C02, such as C02 produced from underground deposits, or C02 from natural gas processing plants. Most C02 currently used for EOR in the U.S. is from underground deposits, and most ofthe remainder is from natural gas processing plants. However, it also appears that, at least in the U.S., additional saline reservoirs will be adequate to handle storage needs for hundreds ofyears of emissions. 13 An important caveat on storage is that the needed geological storage formations are not evenly distributed throughout the U.S. Figure 5, taken from DOE's Sequestration Atlas, shows the distribution of deep saline formations. 14
In general, the process for injecting C02 into geological formations is well understood, having been used for approximately 90 EOR projects worldwide, which cumulatively store about

### 40 million tonnes peryear of COz (compared to about 3 million tons per year (TPY) of C02from a single 500 MW coal-based power plant). 15 The key features separating C02 injection for long-term storage versus COz injection for EOR are: • C02 retention is not the primary goal for EOR operations. EOR operations focused on maximizing C02 retention would likely follow different procedures. • With EOR operations, an impermeable caprock is likely associated with the oil deposit. In saline formations, the presence of caprock is presumed ifthe site is being considered for storage, but the integrity ofthe caprock has not been established by its ability to retain oil or natural gas over hundreds ofthousands ofyears. • In EOR situations, the operator's liability generally ends with the decommissioning ofthe injection well, as demonstrated by the return of surety bonds held by state agencies to assure remediation in the event of a leak. Leakage of C02 from a properly designed and operated storage facility is considered unlikely. The IPCC concluded that "it is considered likely that 99% or

12 Op.Cit., IPCC 2005. 13 Carbon Sequestration Atlas ofthe U.S. and Canada, USDOE/NETL, March 2007. 14 1bid. 15 Discussion Paper For 2"' IEA!CSLF Workshop on Legal Aspects of Storing C02 (draft), International Energy Agency, 170ctober2006.


### 6

### more of the injected C02 

### will be retained for 

### 1000 years." 16 

### However, if leakage occurs, it can be a serious matter. Figure 6 displays various pathways by which COz can escape storage. 17 

### The most commonly stated concern is leakage via existing oil or gas wells that might penetrate the caprock near the COz injection site. It is commonplace in oil producing regions to "discover" wells long since abandoned and forgotten. Mitigation is straightforward: plug the well at a cost of 

### $15,000- $25,000. Although relatively low concentrations of COz are essential for the support of plant life, concentrations over 

### 50,000 ppm have been shown to cause impairment of mental processing, and death is possible from exposure to concentrations exceeding about 

### 10% COz. Volcanic leaks leading to soil root concentrations of 

### 20-30% C02 

### have killed trees at Mammoth Mountain, California. 18 

### If C02 

### escaped a deep saline reservoir, it might also migrate into a more shallow fresh water aquifer, and there is concern that the acidic nature of COz could mobilize metals that would harm such aquifers. It should be noted that no leakage or safety incident has been reported for the Canadian acid gas injection program, which has been operational since 

### 1990. 19 

### The FutureGen project implemented a comprehensive above ground and below ground site analysis for all sites being considered for the project. 20 

### Threetypes of criteria were considered: • Qualifying criteria, which were required to be fully met. • Scoring criteria that involve a numerical evaluation, but did not have to be met 

### 100%. There were 

### 261 such criteria. • "Best value" criteria, which were non-quantitative, but important to the goals ofthe project. This type of comprehensive analysis is a useful template for the next generation of COz storage projects. Site selection will follow an extremely cautious approach until much more experience has been gained with this technology. In a report on regulatory needs related to carbon capture and storage (CCS), the Interstate Oil and Gas Compact Commission (IOGCC) concluded that most aspects of CCS were adequately addressed by existing regulatory frameworks, butthat post-injection monitoring and risk management needed additional attention. 21

16 Op.Cit., IPCC, p.197. 17 Op.Cit., IPCC, p. 243. 18 Lessons Learned from Natural and Industrial Analogues for Storage of C02 in Deep Geological Formations. S. Benson, et.al., Lawrence Berkeley National Laboratory, March 2002. 19 Op.Cit., Bachu. 20 Results of Site Offeror Proposal Evaluation, FutureGen Alliance, 21July2006. 21 Carbon Capture and Storage: A Regulatorv Framework for States, Interstate Oil and Gas Compact Commission, January 2005.


### 7

### EPA has issued guidance applicable to pilot-scale C02 injection projects, such as those being conducted by the DOE Regional Partnerships program. However, the guidance was clear in stating that it did not extend to commercial-scale projects, and implied that projects storing both C02 and other materials like 802 or H2S would face additional, unstated requirements.22 It is reasonable to expect that EPA will eventually adopt regulations governing C02 injection for non-EOR purposes, probably under the Underground Injection Control (UIC) program. Until then, however, commercial scale projects will be regulated on a case-bycase basis, using current UIC regulatory authority. One can assume an abundance of caution will accompany early commercial projects, which could impact both the cost ofthe storage project and the time needed for obtaining necessary permits. It should be noted, particularly in light ofthe IOGCC report, that there is no existing legal framework within which to address the**long~term** 

### liabilities associated with C02 storage. The timeframes for storage integrity exceed normal life cycles for corporations, and insurance instruments for such long periods have no "actuarial" basis for calculating appropriate fees. It seems likely that this gap will have to be filled, probably by a system of sharing liability between the private and public sector, before most entities will be willing to embrace non-EOR C02 storage projects. 

### Costs We are in a period of rapid cost changes for major construction projects such as power plants. Therefore, any generic cost estimate must be taken as establishing an approximate value. The following capture cost estimates are taken from an April 2007 DOE/NETL report23 ; 

### pipeline and injection costs are taken from an IPCC report24

, 

### and adjusted to 2007 dollars using the Chemical Engineering plant cost index.

• Capture and compression, new IGCC: $30-40 $/tonne C02 avoided. • Capture and compression, new SCPC w/ amine scrubber: 69 $/tonne C02 avoided • 150 mile pipeline, 12 million tonne per year capacity (- 2000 MW): 1.80­ 2.70 $/tonne C02. Costs per tonne approximately double for a pipeline capacity of 3 million tonne per year. • Injection: Saline formation, 0.50- 5.80 $/tonne C02 • Injection: Depleted oil field, 0.65- 5.20 $/tonne C02 • Injection: Depleted gas field, 0.65- 15.70 $/tonne C02

22 Using the Class V Experimental Technology Well Classification for Pilot Geologic Sequestration Projects- UIC Program Guidance (UICPG #83), From C. Dougherty & B. McLean (EPA HQ), to Water management Division Directors and Air Division Directors, EPA Regions 1-X, 1March2007.
23 Op.Cit., DOE/NETL 2007. p.36. 24 Op.Cit., IPCC 2005, p.192, 260.


### 8

### The approximate value of C02 purchased for EOR might range from 1-2 $/thousand standard cubic feet, or about 18-36 $/tonne C02, and varies with the price of oil. Several caveats are essential for proper interpretation ofthese cost estimates. 1. It must be emphasized that they apply to a new facility, where there is freedom of design. Retrofitting would amplify costs not only due to space limitations, less likelihood of proximity to storage geology, and generally lower "beginning" plant efficiency (which exacerbates the impacts of parasitic power consumption), but also due to hardware issues such as the inability to easily extract steam for C02 sorbent regeneration. 2. The apparent lower cost of capture from IGCC, compared to SCPC, is significantly offset by the higher cost ofthe IGCC system without capture, compared to SCPC without capture. If both systems with capture are compared to a SCPC system without capture, the overall impact of capture and pressurization (without the transport and injection) is typically in the range of a 60-70% increase in the levelized cost of electricity. 3. The DOE estimates are for bituminous coal-based systems. Most studies conclude that capital costs are higher for both IGCC and SCPC systems on subbituminous coals, but the increase is greater for IGCC units. 4. One should not assume that power plants built near old oil or gas fields will enjoy a large "rebate" from C02sales for oil or gas recovery. A number of existing industrial processes produce voluminous supplies of relatively pure C02which are already separated from other gases.25 Probably most important, is the. fact that no power plant in the world has demonstrated C02 capture, transport,· and storage in saline reservoirs. Such demonstrations are several years away. Pieces of the puzzle have been solved, but no one has yet assembled the entire puzzle. Moreover, it would seem very prudent to take the time to evaluate the technology at commercial scale before embarking on large scale deployment, regardless of how the costs look. It is very likely that additional RD&D will reduce the cost of C02capture and compression, perhaps significantly. However, pipeline and injection systems use relatively mature technologies and are not likely to enjoy such declines over time.

25 Natural gas processing plants, for example, often process raw gas that is too high in C02 for sale to pipelines, so the COz is separated and vented to the atmosphere. As noted earlier, this gas is available and much cheaper to capture than C02 from power plants, and natural gas processing plants are usually in the vicinity of gas and oil fields. It is not coincidence that most of the C02 now used for EOR that is not from natural deposits comes from natural gas processing plants. In a carbon constrained world, it is reasonable to assume that these processes will need to find storage for their emissions, and thatthe value of C02 will drop as more emitters seek to sell their C02. 

### 9

### Summary: Key issues requiring additional attention With respect to C02 

### capture from coal-based power plants, the major issues are technology integration and costs. COz capture from conventional power plants has occurred only at a very small scale (a few megawatts), and without integration with storage systems. Integration requires development of systems to address malfunctions in the carbon capture/compression/transport/or storage system. Cost barriers at new conventional pulverized coal power plants suggest that much cheaper sorbent systems, or lower cost oxygen production systems will be needed to avoid a major increase in power costs. Retrofit systems present additional issues that exceed the scope ofthis paper. For gasification-based systems (IGCC), the major challenges are the relatively high cost of the IGCC itself, absent C02 

### capture, and concerns regarding reliability. In addition, for 

### 90% C02 capture, the resulting fuel for the combustion turbine will be almost all hydrogen, and high efficiency combustion turbines fueled with hydrogen have not been commercially demonstrated. Transport and injection of COz are relatively mature technologies. But we have very limited experience with the fate of COz injected in non-EOR applications at rates of 3 million TPY or more (comparable to a 

### 500 MW coal-based power plant). We will need several multi-year research projects, at commercial scale, in which injected COz is carefully monitored, to gain the necessary understanding of what happens to such C02 

### volumes over long periods oftime. And it must be emphasized that not all areas ofthe U.S. are proximate to attractive storage formations. As a final caveat, it should be noted thatpeople often fear what is not well understood, and COz storage is not well understood by the general population, or by government bodies that regulate power plants. It would not be particularly challenging for groups opposed to coal use in general to generate public opposition to plants pursuing CCS technology, or unexpected for regulators to impose overly onerous requirements in an abundance of caution. The next few years will be a critical period during which we must both exercise due caution and yet embrace projects that will develop commercial scale knowledge about these technologies. Aggravating this situation is the lack of a system to manage COz storage sites decades after injection has been completed. The most obvious solution to this social/regulatory barrier is to immediately develop an interim regulatory plan, covering a limited set of pioneer plants that are injecting large volumes of COz, to apply until we can generate the data needed to support a permanent regulatory framework for broad deployment ofthis technology.



### 10

### About the author- Doug Carter is an independent consultant on energy technology and related environmental issues. His current practice focuses on advising clients regarding advanced coal-based technologies and their potential role in mitigating global climate change. Mr. Carter's resume includes 25 years with the U.S. Department of Energy, where he was Director ofthe Office of Planning and Environmental Analysis, within the Office of Fossil Energy. He had previously served with the Office of Enforcement and Office of Air Quality Planning and Standards at the U.S. Environmental Protection Agency. Mr. Carter holds degrees in Mechanical Engineering and Environmental Engineering. He can be reached at Carter2250@comcast.net.



### 11

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### 14