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c 

GEOLOGIC C02 SEQUESTRATION 

ISSUE SPOTTING AND ANALYSIS WHITE PAPER 


Timothy R Gablehouse1 


Gablehouse Calkins & Granberg LLC 


July 22, 2009 


OBJECTIVE 


This paper has been prepared for APPA's electric utility members and water utilities for 

the purpose ofsurveying the wide range ofissues that will influence the implementation of 

geologic carbon sequestration. As with many things, sequestration is not as simple as itseems. 

Injection ofanything into the subsurface is regulated. Which agencies will act to regulate and 

the criteria they will follow depends upon the answer to the questions raised in this paperquestions that Congress and state legislatures will need to address ifsequestration is to be 

implemented on a scale remotely adequate to make a difference in the amount ofC02 reaching 

the atmosphere. 

Without a doubt sequestration projects will go forward. Many are already underway. 

Nothing in this White Paper should change anyone's view on the technology available for 

geologic sequestration. Nor should anyone read this paper to suggest that there are fatal legal 

impediments to these projects. There are substantial legal issues and a prudent manager would 

be well advised to factor these issues into the business plan for a sequestration project 

Much ofthis paper looks at the existing rules that apply to geologic sequestration. From 

where we stand today it is these rules that will apply absent action by legislative bodies. For 

example, ifthe C02 being injected is a waste we next need to know ifits hazardous waste and 

1 Timothy Gablehouse is the managing partner of the environmental law firm ofGablebouse Calkins &-,Granberg 

LLC in Denver Colorado. 410 17 ~ St, Ste 1375 Denver CO 80~c02 tgablehouse@gcgllc.com ;', 

1 
regulated under RCRA. Ifinjection is limited to producing oil and gas operations for enhanced 

recovery, then injection will be regulated by the state agencies that permit oil and gas 

operations,2 The policies and procedures ofthese agencies and which permits might be required 

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

regulatory burden and economics ofany project. 

Common law theories dealing with trespass, mineral rights and water rights all are 

implicated as injection may result in trespass or harm to surface property rights, mineral rights or 

water rights. Depending upon in which state injection operations occur, there are significant 

questions regarding the ownership and access to the subsurface spaces where the C02 will be 

placed. As the C02 is intended to remain in the ground in perpetuity, then we also need to 

examine who remains responsible in perpetuity. Regardless ofwhether these entities are private 

corporations or public entities long-term liability issues will need to be address and understood. 

Absent new legislative action existing statutes such a CERCLA ("Superfund'') will play a role 

which means that the landowner, mineral owner, injection operator and the entity that produced 

the C02 all may have some liability in perpetuity. 

It's important to understand what this White Paper is not intended to accomplish. While 

it will identifY a broad range ofproperty and liability issues associated with injection projects, it 

will not suggest solutions to all ofthem. It will not address the range ofliability issues 

associated with the high-pressure pipeline infrastructure necessary to move acid gases from the 

point ofgeneration to the point of injection. For geologic C02 sequestration to become broadly · 

viable there will need to be predictability on how these issues are handled. Many will have no 

predictable solution until and unless we have federal and state legislation. 

2 Acid gas injection for enhanced recovery of oil & gas is different from hydraulic fracturing which is also used to 

enhance recovery by physically opening the subsurface formations using very high pressure. proprietary formulas 

and particulates to hold the fractures open. 

2 
BACKGROUND 

Much work has gone into the technical review ofgeologic C02 sequestration. 

(Frequently this is referred to more generically as carbon capture and storage or "CCS"-the 

remainder of this paper will utilize this nomenclature.) Some work has gone into potential 

regulatory programs based upon extensions ofthe current EPA Underground Injection Control 

(''UIC") program. EPA has proposed a regulatory approach which is the topic ofa September 

l 0, 2008 White Paper available to readers. (As nothing has really changed on this front, this 

White Paper will not cover that effort in any detail.) 

Some states are adopting regulatory programs with various degrees ofcomplexity. In 

general they are based upon existing VIC programs or on injection of "acid gas" for production 

enhancement in existing oil or gas operations. These can be radically different approaches and 

the internal political situation along with the perceived importance ofthe oil and gas industry has 

a large impact. 

It is critical to distinguish between production enhancement injection programs and 

injection ofC02 solely for sequestration purposes as they are radically different in intent, 

liability, risk and regulatory regime. A mineral owner typically has substantial rights to use 

techniques such as fluid injection in order to produce the ''minerals" like natural gas and 

petroleum. Oil and gas production companies have substantial experience with this activity and 

tend not to view it as very risky even though it's currently benign regulatory posture is under 

attack. 

As an example, the long-term liabilities associated with production enhancement versus 

CCS scenarios have substantially different legal postures. For example, a land owner or even an 

impacted neighbor may have products liability claims against the producer ofthe injected 

3 
enhancement fluid should it cause adverse impacts outside ofthe natural gas or petroleum 

production pool.' In a CCS project we would instead need to look to CERCLA or RCRA for 

guidance on long-term responsibility for the C02• 

Not resolved to any satisfactory degree are the questions oflegal access to property for 

the pmpose ofCCS, whether it is waste disposal or something else, liability for the entire host of 

things that people can imagine might go wrong, and long-term maintenance/monitoring. All one 

need do is examine EPA's 2008 Technical Support Document entitled "Vulnerability Evaluation 

Framework for Geologic Sequestration ofCarbon Dioxide" to get a sense ofthe complexity of 

the problem and the difficulty ofassessing potential risks.4 

That these risks are a real concern when it comes to permitting and operation should be 

obvious. Some examples may help to illuminate the risks that the public will fear: 

Fluid injection is suspected ofcausing Texas earthquakes. Wall Street Journal, June 

12, 2009, Page A3. 

Earthquakes caused by deep well injection ofwastes at Rocky Mountain Arsenal. 

http://earthquake.usgs.gov/regional/states/coloradolhistory.php 

Crystal Geyser UT- C02 cold water eruptions through a mamnade well. 

http://www.uweb.ucsb.edu/-glennonlcrvstalgeyser/ 

1986 Lake Nyos eruption and deaths. 

"CCS mobilization ofhazardous, naturally occurring materials is a risk that must be 

characterized." "Injection into saline formations has the potential to disturb regional 

ground-water flow systems and could contaminate drinking water." Paraphrased 

from the testimony ofDr. Burruss, USGS, Subcommittee on Environment and 

Hazardous Materials, House Committee on Energy and Commerce, July 24, 2008 

Transportation infrastructure to transport C02 to injection sites does not exist-USGS 

projects that an infrastructure largerthan the existing natural gas/petroleum industry 

will be required to achieve meaningful levels ofCCS. 

http://energy.er.usgs.oov/health environment/C02 seguestration/C02 illustrations.html 

3 See Modesto. 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 and DISCUSSION 

( 


I. Liability During Injection I Operational Lilibillty 

Operational liability includes the environmental, health, and safety risks associated with 

C02 capture, transport, and injection. Enhanced fluid recovery contractors are already subject to 

a duty ofcare defined under tort Jaw and are usually subject to standards ofconduct under their 

contractual arrangements. Companies providing these specific services have experience in their 

industries, and are subject to liability for worker safety and property damage resulting from their 

conduct. These companies are best positioned to manage the risks associated with their own 

conduct and are able to obtain liability insurance for their conduct and workers. 5 In surveys and 

case studies, these companies were willing to provide services on a commercial basis and 

generally willing to accept liability for their actions. 6 

However, it is foreseeable that large-scale CCS could make it less likely that companies 

will be willing to accept liability for injection. For example, ifthere was contamination at the 

surface during injection operations it could potentially affect drinking water. There is currently 

no law protecting commercial or public operations from the full range ofliabilities should they 

cause contamination. 

In theory government agencies could conduct the 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 wastewater treatment facility but did not argue that negligence was 

5 M.A. de Figueiredo, 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 and Regulatory Environment: A. 

Study ofPhase II ofthe DOE Regional 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) 

5 
present. The court held that the district was immune from a trespass claim under Governmental 

Immunity Act "unless negligence is proven". Trespass is not a dangerous condition ofa public 

water facility or public sanitation facility; because the trespass claim did not require proof of 

negligence it was barred by Governmental Immunity. Nobody shonld take this sort ofoutcome 

as an indication that government agencies can conduct these operations with impunity- there are 

many other available theories ofliability. 

II. Post Injection Liability 

A. Ownership of Pore Space 

The surface owner usually owns pore space because mineral conveyances, including 

leases, normally only pass title to the minerals, not the pore space itself. That does not, however, 

end the conversation over who controls the pore space property right. The surfaee owner cannot 

violate the mineral estate owner's or lessees' rights by doing something interfering with access 

to the minerals, making the minerals more expensive to exploit or making the development of 

the minerals economically impractical. Clearly injection into the pore space could cause this sort 

ofharm. The surface owner must also allow reasonable use ofthe property to give access to the 

mineral estate. 8 For CCS projects to proceed it is somewhat reckless to assume that agreement 

with the surface owner is the only necessary step. It seems prudent to have agreements with 

both surface and mineral owners even though it seems likely that the surface owner owns the 

pore space.' 

B. Risk of Leakage 

Post-injection liability includes harm to human health, the environment, property, and the 

climate liability related to leakage or migration 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 effect on climate change. Potential pathways for carbon dioxide release include leakage 

through the pores oflow-permeability cap rocks ifthe carbon dioxide is injected at too high a 

pressure, leakage through openings in the cap rock, leakage through abandoned or improperly 

sealed wells, and migration via faults. 10 

Reportedly, there is a low risk of captured carbon leaking into the atmosphere in amounts 

significant enough to pose a risk. 11 C02 and natural gas has been stored naturally in geologic 

formations for millions ofyears and companies already store natural gas underground with a lot 

ofexperience. There are naturally occurring C02 reservoirs in the western states that have held 

gas for millions ofyears. Furthermore, over I 00 million tons ofC02 has been injected into oil 

reservoirs for enhanced fluid recovery as well as into deep saline aquifers (over 80 projects have 

been implemented worldwide). 12 Commercial and experimental projects have shown the 

potential for CCS across a wide range of geological settings. 

( 

There are, however, reports suggesting that an exceptionally detailed analysis ofgeologic 

conditions is critical to understanding how the C02 is being sequestered in each case. Whether 

C02 is being mineral trapped, in which case it may be stable on geologic time scales, versus 

dissolution in groundwater is critical to an assessment ofwhether a potential for leakage is 

present. Dissolution in groundwater is not preferred as it has the greatest potential for eventual 

leakage to the atmosphere. 13 

The long-term liability associated with C02 leakage that damages health or property is 

difficult to establish because it is dissimilar to other regulatory schemes and has a timeframe of 

thousands of years. We simply do not know what risks long-term geologic stomge presents. 

10 IPCC, IPCC special report on carbon dioxide capture and storage; 2005. 11 Feidman, This work performed under the auspices of the U.S. Department of Energy by Lawrence 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 in very high concen1rations (> 15,000 ppm). 

For example, in Lake Nyos 1,500 people died when a lake over a magma pool released large 

amounts ofCO,. This is unlikely to occur at injection wells when properly monitored. 

Researchers have successfully plugged and abandoned C02 injection wells, even badly damaged 

and failed wells. In wells that have failed and released C02, almost all were detected quickly and 

stopped. 14 

EPA produced a July 2008 white paper entitled Approaches To Geologic Sequestration 

Site Stewardship After Site Closure." They describe the advantages and disadvantages of 

stakeholder developed models as well as models based upon existing federal laws ranging from 

the Nuclear Industries Indemnity Act through CERCLA. IfCCS is viewed as waste disposal the 

"cradle-to-grave" model ofthe RCRA and perpetual nature ofliability under CERCLA would be 

inconsistent with any effort to limit responsibility for injected CO, and especially any potentially 

hazardous contaminants entrained in 1he injected materials. 

EPA's analysis has been criticized as unrealistic given 1hat geologic storage ofC02 is 

intended to be indefinite and well beyond 50 years. The au1hors of a recent report view 1his as 

1he single greatest legal obstacle to commercial deployment ofCCS. 16 Quite obviously, 

legislation will be required to address this issue if !here is to be any time limit on liability. 

C. Property Rights Issues Related to Migration ofInjected CO, 

1. Natural Gas Storage Law May Provide Some Insight 

14 S. Julio Friedmann, Carbon Management Program APL Global Security Principle Directorate, LLNL. .S. 

Department ofEnergy by Lawrence Livermore 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 the property ofthe injector. 17 Injection ofgas 

into property that the injector does not own is a trespass.18 Pore space for such projects can be 

purchased or leased from the landowner, and/or the mineral estate owner, so long as it does not 

damage other persons. 19 Agreement with the mineral estate owner or lessee will generally be 

prudent in order to avoid later damage or trespass claims as there is ambiguity in some states 

regarding whether a mineral owner owns the pore space previously occupied by the minerals, 

natural gas or petroleum they have removed. 20 Liability for negligent operation ofstorage 

operations exists. 21 

Under many federal and state laws utility companies have eminent domain rights for 

utility facilities. This begs the question ofwhether CCS operations represent a utility facility 

under these statutes- ifviewed as waste disposal, there is doubt These statutes do not address 

the ability to exercise eminent domain rights over buffer zones that may be desirable because of 

the potential for gas migration. Buffer zones should be included because gas escape is a 

trespass; however, how such a buffer might be valued in an eminent domain action is unknown. 

With regards to carbon sequestration the concept ofcondemnation poses several 

problems. CCS potentially involves large areas ofland - hundreds of acres - depending upon the 

subsurface conditions and resulting available storage volumes.22 The uncertainty over whether 

statutory authority to exercise imminent domain applies suggests an initial effort to negotiate and 

purchase rights. Ifinjection requires approval from any landowner that could be affected, then it 

17 Ellis v. Arkansas Louisiana Gas Co., 450 F. Supp. 412,419 (D.'t. OKL 1978) •nd many others 
 18 Kuntz, The Law of Oil and Gas s 2.6, p.71 
 19 Ellis, at 450 F. Supp. 412 · 
 20 Geologic C02 Sequestration: Who Ow"ns.. tke Pore Space?, 9 WY LR 98, 2009. 


21 In a recent case from LouiS ian~' a jury awarded S9.2M to a petrole~m company whose ability to exploit reserves 


wa-s adversely impacted by improper maintenance and operation of a neighboring salt dome storage facility. 22 Separation and capture ofC02 from large stationary sOurces and sequestration in geological formatiolts-­

coalbeds and deep saline aquifers. J Air Waste Manag Assoc. 2003 Jun;53(6):645~715 

9 

will be necesslll)' to secure consent from a potentially large number ofpeople. Negotiation and 

condemnation will therefore impose high costs and long acquisition times. 

As it will not be the intent (in most cases) to later retrieve the gas, there are interesting 

questions and serious unknowns regarding the rights and duties ofthe property owners later in 

time. Establishing ownership ofC02 in perpetuity is a key part ofthis problem, especially given 

the vast amounts oftime it will be sequestered. Ifthere is no intent to recover perhaps there is 

no duty to protect and preserve the C02 or the associated surface facilities. Ifthe entity that 

owned the C02 when it was injected disappears, then whether the 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 inject fluids to aid in the production of 

gas or oil, but not for disposal ofwaste. Leases and state laws often give the producer the right 

to "unitize" for secondlll)' recovery allowing injection in various locations ofa field. These 

enhaoced recovery effurts are not necessarily designed to sequester C02 even if"acid gas" is 

used. Given the lease/contract rights these processes are probably not a good mechanism to 

examine the broader liability issues associated with CCS projects unassociated with oil and gas 

production. 

As noted before liability for the injected materials, such as hydraulic fracturing fluid or 

acid gas, exists regardless ofwhy these materials were injected. Contract or lease theories will 

apply and may be ofvalue in the short-term until the normal statute of limitations runs. Beyond 

these theories liability is likely perpetual under federal environmental laws as these fluids will 

10 
( typically contain hazardous substances. As noted earlier, products liability theories may apply to 

the entity that produced the fluid ifit harms third persons. 

3. Waste Injection 

Wastewater wells are subject to permitting by EPA and/or states. Failure to obtain 

permits or operate within the terms ofa permit will make the operator subject to agency 

enforcement and citizen suits. Obviously the party injecting must have the legal right to do so; 

however, what those rights mean will be highly variable. In Chance v. BP Chemical, the 

Supreme Court ofOhio determined that the defendant committed a trespass when chemicals 

injected underground migrated under plaintiff's property for which no rights had been acquired. 

Even so, the proper evaluation ofdamages is very uncertain. 

The court held that the surface owner's rights were not absolute, but were contingent on 

the reasonable and foreseeable use oftheir property. 23 According to the court, subsurface rights 

include the right to exclude invasions ofthe subsurface property that actually interfere with the 

property owner's reasonable and foreseeable use ofthe subsurface." This would most certainly 

include harm to minerals or oil and gas resources leased by the landowner. 

This sort of analogy would work well for CCS because landowner's that are not harmed 

by stored C02 would have no cause ofaction. It seems to follow that there would only be a 

cause ofaction after C02 specifically damages the health or property ofa landowner - not for 

speculation that gas could potentially leak from geologic formations or interfere with access to 

minerals or oil and gas. Many courts would likely disagree and would find diminished value 

simply due to the trespass. Legislation, rather than litigation, is by far the best way to establish 

the rules in this 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 of a mineral estate sued defendant for damages 

when defendant injected wastewater into the mineral estate. The California Appeals Court 

rejected the defendant's claim that it should not be liable because the plaintiff did not establish 

the extent ofdamage to the mineral estate. The court held that there was substantial evidence the 

defendant's actions interfered with and damaged the mineral estate. Therefore, the defendant 

committed a trespass. The court also held that the plaintiff in the case could waive the tort claim 

and collect on an alternative theory ofcontract implied in law to recover the value ofthe use 

taken.25 

From Chance (supra) and Cassinos, it is apparent that a cause ofaction is not likely to 

occur ifthere is no damage done. Interference with mineral rights should be a concern because 

CCS can displace subsurface gases and groundwater, which could damage mineral estates. The 

holder of a mineral estate or lease would have a cause ofaction along with the surface owner. 

Ifthe activity is allowed by statute it does not necessarily mean that the injector will be 

absolved ofliability. In Tidewater Oil Co. v. Jackson, there were damages to plaintiffs' oil wells 

as a result ofwater flooding operations conducted by defendant on adjoining property. The Court 

of Appeals held that 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 of adjoining leaseholders. 

These findings were inconsistent with the administrative findings to the effect that the 

water flooding operations were carried on in a lawful manner. In the view the court took, it was 

unnecessary to reconcile the findings. It was sufficient that the water flooding activities were 

intentional and the consequences foreseeable. A legal claim was available, even though the 

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

12 
flooding was lawfully carried on. because it caused substantial injury to the claimants. 26 This 

case is important because it highlights that regulations that allow CCS may not absolve the 

defendant ofcommon law property law liability. 

4. Water Law 

It most ofthe Western US surface and groundwater is a public resource dedicated to the 

beneficial use ofpublic agencies and private persons wherever they might make beneficial use of 

the water. (Texas is a bit different in that groundwater belongs to the landowner and is not 

subject to prior appropriation. That can result in significant fights between neighbors should one 

pump so much groundwater that a neighbor's well becomes dry. This law ofthe ''biggest pump" 

has been mitigated through administrative processes such as conservation districts regulating the 

use ofgroundwater. 27) Under the general western approach, including surface water in Texas, 

water quality and quantity are property rights subject to statutory and common law protections. 

The biggest difference between water and real property is that the protections available for water 

frequently exceed those available for real property. 

The right of water use includes the right to cross the lands of others to place water into, · 

occupy and. convey water through, and withdraw water from the natural water bearing 

formations within the state in the exercise ofwater use right. Natural water bearing formations 

may also be used for the transport and retention ofwater.28 Water authorities can inject water for 

later withdrawal with no payment for the pore space. The property rights oflandowners or 

mineral estate owners/lessees do not include the right to control the use ofwater in the ground 

and cannot claim control of aquifers as part oftheir estate. Except for Texas, groundwater is part 

of"waters of the state" and either by Constitution or statute, 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 ofAmerica, eta/., 1 SW3d 75 (Texas 1999) 


28 Board ofCountyCom'rs ofCounty of Park v. Park County Sportsmen's Ranch, 45 P.3d 693,706 (Colo. 2002) 


13 
has control over the use and disposition ofgroundwater regardless ofwhether it is or is not 

directly discharged to a natural stream. 

The law in most states prohibits the taking ofprivate property for public or private use 

without the property owner's consent, but there are frequently exceptions which pertain to 

constructed water facilities. 29 For example many western state constitutions provide for access 

to the water source across the lands of others and further recognize and address the private right 

of condemnation for the construction ofwaterworks.30 There is a requirement for compensation 

for use of another's land, but that does not extend to employment ofnatural water bearing 

subsurface formations on or within the landowner's property for the movement ofappropriated 

water." An applicant for a conditional decree to utilize available aquifer storage space must 

demonstrate that it will capture, possess, and control water lawfully available to it and without 

injury to other water rights. 32 

Water storage under a landowner's property is not a trespass ifit does not inhibit the use, 

benefit, or enjoyment ofproperty." In Board ofCounty Commissioners v. PCSR. LLP, PCSR 

proposed to store water in underground aquifers underlying approximately 115 square miles. 

The landowners claimed that storage ofwater underground in aquifers underneath their land 

would constitute a trespass. The Court held that it would not be a trespass and the project would 

not require the Landowner's consent or condemnation and the payment ofjust compensation 

under the provisions ofArticle XVI. The court, in applying Causby,34 found that the project did 

not include construction of any facilities on or in the Landowner's properties 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 had not alleged that the use, benefit, and enjoyment oftheir properties would be 

invaded or compromised in any way. Therefore, it was not a trespass. 

The court stated that the General Assembly, in authorizing the use ofaquifers for storage 

ofartificially recharged projects further supplanted the Landowners' common-law property 

ownership theory." The court found it ''particularly [significant]" that: 

(I) [F]ederal patents to land do not include water, (2) ground water is not a mineral 

under the federal mining laws ..., (3) federal statutes as interpreted by the Supreme Court 

recognize [a state's] authority to adopt its own system for the use of all waters within the 

state in accordance with the needs ofits citizens, subject to the prohibitions against 

interference with federal reserved rights, with interstate commerce, and with navigability 

ofany navigable waters, ( 4) the right ofprior appropriation applies ... to waters of the 

natural stream, including surface water and tributary ground water; ( 5) the property rights 

oflandowners do not include the right to control the use ofwater in the ground, whatever 

the character ofthat water; and (6) the General Assembly has plenary control over the 

use and disposition ofground water that is not part ofthe natural stream.'6 

In sum, the holders ofwater use rights may employ underground as well as surface water 

bearing formations in the state for the placement ofwater into, occupation ofwater in, 

conveyance ofwater through, and withdrawal ofwater from the natural water bearing formations 

in the exercise ofwater use rights. 37 Consent or just compensation was not required because the 

plaintiffs did not have the right to restrict the defendant's use ofthe water that was done within 

regulations. 

CCS presents a unique problem because the underground storage ofC02 could 

potentially affect the flow and location of groundwater. This could occur because the process of 

physical trapping may displace naturally occurring water and other gases.'' Any effect on water 

resources could pose potential liability ifit limits access to water that has already been 

35 !d. at 703 

36 !d. 


37 !d. at 712 


38 Statement of Dr. Robert Burrus, Research Geologist, Enerby Resources Team U.S. Geological Survey U.S. Dep. 


Of the Interior Before the Subcommittee on Environement and Hazardous Materials House Committee on Energy 

and Commerce Hearing on "Carbon Sequestration: Risks, 

15 
appropriated to beneficial use. Physical displacement of groundwater can also have adverse 

practical impacts on private owners and utilities. As a result it will normally be prudent to 

evaluate whether on-site groundwater wells, especially those used by public water systems, will 

be disrupted by CCS operations. 

In most places a water right includes the right to a particular quality as well as a 

particular quantity of water. These cases are typically framed in the context ofdeprivation of 

quantity but these water rights are also protected from activities ofanother that injure the quality 

of a water right.39 Therefore, ifwater quality is affected by the precipitate that hopefully forms 

from the geochemical reactions intended as part ofCCS operations the owner ofthat water could 

have a cause ofaction against the entity injecting and the owner ofthe gas injected. Historically 

such interference involved the discharge of mine and other wastes into the stream but there is no 

reason to believe the result would be different with CCS.40 

ill. Regulation 

A. EPA VIC Rulemaking 

The UIC Program regulates underground injection under five different classes of 

injection wells, depending on the type offluid being injected, the purpose for injection, and the 

subsurface location where the fluid is to remain. States are allowed to assume primary 

responsibility for implementing the UIC requirements in their borders, as long as the state 

program is consistent with EPA regulations and has received regulatory approval. Injection 

operators are required to provide financial assurance in case they cease operations, with the level 

ofassurance a function ofthe estimated cost of plugging and abandoning the injection well. If 

there is a violation ofa UIC permit, an enforcement action may be brought by the EPA 

39 2A COPRAC § 76.11 40 Game & Fish Comm1

n 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 or the applicable state agency. Violators may be subject to administrative orders, 

civil penalties, and criminal penalties. The scope ofthe VIC statute is contamination of drinking 

water, and under its current application to C02 storage, the VIC Program gives more limited 

treatment, if any, to other harms to human health, the environment, and property.41 

While there are requirements for constructing and monitoring injection well 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 of specific class I hazardous wells, where this monitoring can be mandated.42 

On July 15 2008, the EPA proposed a rulemaking package that would regulate geologic 

sequestration of carbon dioxide under the 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 or potential 

source of drinking 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 significant releases of C02 or 

contaminants in the C02 into the ambient atmosphere. The EPA declined to classify C02 as a 

hazardous waste but the proposed rules place a burden on the permittee to assure that the C02 

does not contain impurities that would trigger RCRA hazardous waste management 

41 Craig A. Haf'4 Advancing Carbon Sequestration Research in an Uncertain Legal and Regulatory Environment: A 

Study ofPhase II ofthe DOE Regional Carbon Sequestration Partnerships Progf.am, Discussion Paper 2009-01, 

Cambridge, Mass.: Belfer Center for Science and International Affairs, January 2009. 

42 Regulating the ultimate sink: managing the risks of geologic C02 storage. Page 3479 

43 http://www.epa.gov/ogwdw/uic/wells_sequestration.html 

17 
requirements. The risks associated with this classification are manifest. Injection ofhazardous 

waste is highly regulated and would likely bring a CCS project to a screeching halt. 

None ofthis overrides the applicable provisions ofCERCLA or RCRA. To the extent 

there are hazardous substances released from the sequestration process liability under CERCLA 

may be present.44 Likewise ifmaterials injected are hazardous waste the daunting permitting and 

corrective action provisions ofRCRA and the state programs will apply. 

As an example, EPA issued orders under RCRA to require management ofpropane that 

had leaked from an underground distribution system. In EPA's view, the moment the propane 

leaked from the distribution system it was a waste and presented a hazard. Depending upon the 

factual setting, CCS operations could find themselves in the same situation. 

B. State Regulation 

In the absence offederal action on the carbon sequestration issue, many states are in the 

process of enacting their own regulations. Some examples follow: 

l.Wyoming 

House Bill 89 (created Wyoming Statute § 34-1-152 and amended Wyoming Statute § 

34-1-202) addresses the ownership ofPore Space. The Bill establishes that the surface owner 

owns pore space underneath the surface estate and that the pore space is conveyed upon the 

conveyance ofthe surface, unless the space has been previously conveyed or is explicitly 

excluded in the surface conveyance (in the same manner as a mineral interest). In addition, legal 

requirements for notice to surface owners and/or mineral interest owners shall not be construed 

to require notice to the pore space owner unless the law specifies that such notice to the pore 

space owner is required. The statute expressly recognizes the dominance of the mineral estate 

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

18 
( and does not alter the common law as it relates to the rights ofthe mineral estate. The bill states 

explicitly that it does 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. It instructs the Wyoming Department ofEnvironmental Quality to 

establish and issue permits to new "sub-classes ofwells" within the VIC program and to regulate 

well standards, bonding and monitoring. The bill requires the DEQ to create an advisory board 

and rules to expand the 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 set bonding procedures. Jurisdiction subsequent extraction of 

sequestered carbon dioxide rests with the Wyoming Oil and Gas Conservation Commission. The 

bill does not impact the oil and other mineral interest owners' right to drill or bore through 

sequestration sites, nor does it include within its scope the regulation of enhanced oil recovery 

operations using carbon dioxide. 46 

Like HB 89, Wyoming's carbon capture and sequestration legislation recognizes the 

continuing dominance ofthe mineral estate. § 30-5-501 states specifically that the carbon 

sequestration legislation enacted by § 35-11-313 shall not "affect the otherwise lawful right ofa 

surface or mineral owner to drill or bore through a geologic sequestration site" so long as the 

drilling is conducted in conformity with rules for protecting the sequestration site against the 

escape ofC02•

47 

45 Id. at 143-45 

46 Delissa Hayano, Guarding the Viability ofCoal & Coal-Fired Power PlantS': A Road Map For Wyoming's Cradle 

to Grave Regulation ofGeologic C02 Sequestration, 9 Wyo. L. Rev. 139, 145~49 (2009) 

47 Id. 


19 

2.0klahoma 

Senate Bil!I765 (May 2008) was a proposal that required the development of GCS 

permitting regime and transferred ownership ofwells to state and released 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 Governor with GCS permitting recommendations by 

December 2008 (extended to December 2009) and is modeled based on the IOGCC model 

statute.48 

3.Kansas 

Under HB 2419 (2007), GCS rules were supposed to be developed by July 2008 (draft in 

progress). Under the Bill, a state GCS fund would pay long-term GCS related monitoring and 

remedial activities. It also exempts GCS property and any electric 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 and policy 

recommendations for the state. The bill also sets an Emissions Performance Standard (EPS) that 

limits electric utilities' ability to sign new or renewed long-term contracts with power plants 

whose greenhouse-gas emissions exceed those of a modem natural gas-fueled power plant. The 

bill essentially ends construction ofpulverized coal plants to serve Washington loads, makes the 

price ofiGCC power reflect some ofits emissions disposal costs, andjumpstarts the process 

toward a comprehensive greenhouse-gas emissions reduction plan 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 ,Humphrey Institute of Public 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 20009-5715 
Executive 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 V experimental technology; however, 

the regulatory framework for Class V wells 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 (I PCC) 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;: Pi p:!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 I wells are for the largest volume and 

the most hazardous wastes. Class V wells 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 Statistics for 2005, Dec. 2006; 

http: //www.epa.gov /safewater /uic/ classes.html. 

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

Class /Injection Wells 

Subject to the most stringent regulations, Class I wells include industrial hazardous, 

nonhazardous, and municipal sewage waste. Class I wells 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 of Water, 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 I requirements 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 I injection 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 I wells nationwide, there are only 163 Class I hazardous 

waste wells nationwide. Most Class I wells are found in Texas and Louisiana. Class I wells 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.govI safewaterI uic/dassi .htmt. 

8 
Figure 2: Hazardous Waste Wells in the U.S. 

UIC Class I Deep/High Teelmology 


Hazardous Waste Wells 

No HVVWells 

1-10 HWWells 

~I 11-20 HVVWells 

r=±:-d > 10 HVV Wells 

·AmmieM lli!fliM!-1111!E!:t\l AFIM P4bfie Pfm(!r

- Al't!locialion and *¥'*•9'ffff1'!UI 9 
There are 366 nonhazardous Class I waste wells in 19 states. Nonhazardous Class I waste 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 I deep 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 AFR4 Publtc~r

­

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

UlC Class n Oil&Gas WeUs 


No KM'Wrll We:lls Em ,., ao wa~rs 

1Ot·5.,000 Wells 

~ Pu111tt.:l RP:io - 5,001·25,00 oWells evi~r}iills fallds _,_ Mme !lhail'l25,WOWels eAi!M!ro,U'! S:ilmo.ll 

· • ~IFJdian T1il:re:s: 

Gul'f! 

-,._L/ 

APR( """"""

PobltcPow¢r 

ASsociation and 

MhuW 

ki:::tLJeiiJ!J 11 
Class 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 V Injection Wells 

Most injection wells in the U.S. are Class V wells with an estimated 650,000 Class V wells in 

the nation. 19 Class V wells 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 V wells 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 V wells. 

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 V wells until the 1990s. Because of the 

diversity and sheer number of these wells, EPA did not set minimal technical standards for 

Class V wells. Since EPA finished the Class V rule 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 of Experimental 

Technologies. Ground-Water Program 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 V experimental 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 V experimental 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 V is "the best mechanism for authorizing pilot GS project, "

24 

and that Class V general 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 V permit, the guidance then lays out 

why states should consider more stringent permit conditions in the CCS Class V permit. 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 of Water, 

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 I and 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 V permits 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 I and 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 Associated with 


Class /Injection Wells, Mar. 2001, at 18. 


" Ibid, at 19. 


14 
One of the biggest challenges for Class I operators 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) 

15 
Figure 4: Diagram of Class I Well Technology" 

Ideal Injection Well 

and Site 

--­

j,lort-lJSOW "". ';"C · ;,'" ~ ' ·:· ", ,"'' 'i 

~l>fi~t'!!.~t':'~ .• Packer--~~~ 

klje..tion zon • 

Perl'oral&d No....USDW

casing """'1Q,QOD m.g/ITDS

Monitoring 

Monitoring requirements include monitoring of the well and other formations. Class I well 

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 I and Class II 

wells. 35 

Class I operators 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 I and 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 of any additional financial assurance programs or systems 

envisioned for CCS. However, the existing law does require that financial responsibility is 

met. APPA has caution about embracing CCS technology and long-term storage or 

geosequestration for new power plants 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 sector for conventional pollution issues and liability 

concerns. 

Currently, Class I operators 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 I operators 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 V wells to be plugged 

with cement sufficiently to prevent migration or leakage of the injection fluid. Class I permit 

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 V operators 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) 

19 
Limitations on Class I Well Siting 

If EPA and states draw upon the criteria for Class I wells 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 I wells 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.gov I edu/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. 

yIt 4·1'14' 

lk$Nif!iil#i$1 

&iJIQiflii(.ii!ij 20 
Figure 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 I wells. 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. A study in the saline formations of Texas where there are 

many Class I wells 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 

A further 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 split estates 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 et at., Area of Review: How large is large enough for 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. A few 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 

A report jointly 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 C02 from Storage Reservoirs: 

Identification of Features, Events, and Processes and Lessons Learned, Earnest Orlando Lawrence Berkeley 

National Laboratory, Feb. 2006. 

65 Lewicki et al., at 48-9. 

66 Source Texas Railroad Commission at: http:/lwwwxrc.state.lx.us/news-releases/200611 00606.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 I hazardous 

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 I well. 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 I well 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; Class II permits can 

be approved more rapidly. However, and as the maps show, as the UIC program has matured, 

Class I and 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/publici comm __execl pubs/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 half of regulatory agencies across the states have experience reviewing 

Class I or Class II permits. 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 a few regions of the 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 

to permit a larger number of CCS wells. In 2006, Texas had ten new and eight Class 

I hazardous 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 I wells 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 I regulatory 

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 separation technology at the power plant. This is a step that, generally speaking, 

EOR sites do not require. 3 

The purpose of this 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 power utility sector. 

Human Health and the Environment 

Despite the successes ofEOR or tertiary recovery of oil and gas using C02 injection, 

leakage from embedded C02deposits could result io the endangerment of ecological and 

human health given the scale of the 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 of C02 can be harmful to human 

respiratory and central nervous systems. 

• 	 The release of large volumes ofhigh concentrations of C02can result in the 

suffocation ofhumans, animals, or plants above ground. For instance, natural C02 

long-term seepage destroyed 40 hectares of trees on Mammoth Mountain in the 

Eastern Sierra Nevada mountain range in California.4 

• 	 Leakage from injected C02 could migrate into Underground Sources of Drinking 

Water (USDWs). Migrating C02deposits may alter the pH of subsurface 

groundwater or displace potable water resources by forcing saline waters to merge 

with fresh water formations. 

• 	 Accordiog to the U.S. EPA, 44 percent of all 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 of brine 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 of native fluids and chemical constituents, 

movement ofpossible hazardous substances, or potentialleachiog ofnaturally 

occurring metals and mioerals mixed in the C02 injection. 

• 	 If the CCS process is responsible for discharge of a 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 of separation 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 of Magmatic Unrest," 

Nature 376 (1995): 675-678. 5 Brian McPherson and Peter Lichter, C02 Sequestration in Deep Aquifers, 

http:/ /www.netl.doe.gov/publications/proceedings/O !/carbon_seq/7 a2.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 can be privately owned in the United States, C02 injection into 

geologic formations may require permission from all private owners of intersected 

sub-surface property. A proposed deposit for a FutureGen zero-emissions plant site 

may require property rights from 69 individual property owners.7 

• 	 Compulsory unitization 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 of affected property owners do accept, may be used 

extensively for enhanced oil recovery-related CCS. 

• 	 For non-oil and gas production projects, the use of eminent 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 be politically 

difficult, given the public backlash against eminent domain driven by the Supreme 

Court case Keto v. New London. 8 

• 	 There is currently a significant level of uncertainty in predicting migration and 

movement of large C02 deposits in large geologic formations. Without further 

research, the scale of property right acquisition for CCS projects will remain high, as 

industry participants 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. If insurance companies cannot accurately calculate the risk 

of C02 damages, or future potential environmental liability, they may decline to offer 

coverage to public power utilities. Some public power utilities may not have the 

insurance coverage thought to be sufficient to handle the perceived risks for geologic 

sequestration or storage of C02. 

• 	 The utilization of regional land use controls to ban large-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 of leakage damage to human health or private property. 

• 	 Currently, C02 has 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 if large-scale implementation of 

CCS leads to negative impacts on environmental media. This classification would 

7 Elizabeth Wilson and Mark de Figueiredo. "The Impact of Liability 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 of the 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 of embedded C02 impacts. 

• 	 If the CCS process causes a release or substantial threat of a release of any pollutant 

that may present an imminent and substantial danger to the public health or welfare, 

liability will likely attach under CERCLA9 

• 	 If area-wide contamination is the result of CCS activities, potential parties could be 

held liable under CERCLA. To the extent that specific provisions of the CWA and 

the Safe Drinking Water Act (SDWA) are incorporated into the applicable or relevant 

and appropriate requirements (ARARs), those standards could then govern the 

remedial activities of a 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 of citizen suit provisions, especially with respect to water laws in the 

Western U.S., introduces another level of uncertainty because any regulatory balance 

can be altered by a citizen bringing suit because of a lack ofprosecutorial diligence, 

whether actual or perceived. 

• 	 In nuisance 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 of C02 may all be 

candidates for some portion of liability under the 'joint and several liability" 

provision in the 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 of a legal 

precedent. 

• 	 In the case of natural seismic action leading to future C02 leakages, assigning liability 

based on fault may be impossible and lead to difficulty in handling the resultant 

damages. 

Long-Term Stewardship and Liability 

Assignment of liability associated with leakage and migration of C02 deposits and 

resulting public health or environmental impact is further complicated by the extended 

time frame of carbon storage, which may exceed the lifespan of industry participants. 

For example, determining which party is responsible for the C02monitoring at a power 

plant after the plant is decommissioned or retired 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 of a viable entity is questionable under the current legal 

framework. It is still an open question whether long-term liability should rest with a 

public or private entity. To ensure the future economic burden associated with the 

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 if the companies that 

managed the injection and monitoring no longer exist or if they utilize subsidiaries to 

limit liability. 

• 	 Additional research is required to improve scientific knowledge of carbon 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 must be firmly established 

in the 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) of the SDWA, EPA is currently 

evaluating Department of Energy (DOE) pilot projects to determine if changes 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 of these DOE pilot projects leaves 

legal uncertainty with respect to the future of CCS activities. 

Further Research 

This white paper is intended as an overview of potential environmental and legal issues 

that could arise in a large-scale CCS operation. It is meant to promote further research 

and discussion of these 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 of climate 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 

but they are also currently under significant scrutiny. The legal and environmental 

challenges of CCS should be analyzed and addressed with similar vigor in order to 

promote effective and sustainable practices in the United States. Research on these 

aspects will inform cost-benefit analyses of CCS in relation to other methods being 

developed to mitigate climate change, allowing for optimal distribution ofpublic and 

private resources. 

\ 


10 Testimony of Acting Assistant Administrator William Wehrum and Assistant Administrator Ben 

Grumbles, U.S. Environmental Protection Agency. Subcommittee on Energy and Air Quality, United States 

House ofRepresentatives, 6 March 2007. 
Marianne L. Horinko is the Executive Vice President of the Global Environment & 

Technology Foundation (GETF). Prior to joining GETF, she served as Assistant 

Administrator for the Office of Solid 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 protection using partnerships, flexibility, and innovation. The 

Brownfields program, signed into law by President Bush in 2002, embodies these goals. 

During the first Bush Administration, Ms. Horinko was Attorney Advisor at EPA. 

Subsequently, she served as President of Clay Associates and practiced environmental 

law at Morgan, Lewis & Bockius, a national environmental policy firm, where she 

assisted in the creation of the 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 (APP A) 

L.D. Carter 


December 2007 


Summary: It will be necessary to reduce C02 emissions from existing coal-fired power plants 

for the U.S. to reach the goals stated by some legislators for managing global climate change. 

The major techoology 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 

rather than air as the combustion oxidant (yielding flue gas with a much higher concentration of 

C02). Both existing techoology approaches are costly, and both involve large parasitic power 

needs that can reduce the output ofthe existing unit by one-third. The changes introduced by 

retrofitting carbon capture and storage (CCS) on an existing power plant 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 power plants. Furthermore, most research on CCS is focused on 

new power plants and not issues that may be more relevant to existing power plants. 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 of stored C02 over a timescale that 

exceeds the scope of traditional risk mitigation instrmnents, like insurance. 

These challenges are daunting. Research and policy development are both proceeding, 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 power remains to be seen. 

1 
Introduction 

Existing coal-fired power plaots in the U.S. emitted 1.96 billion metric tons of C02 in 2005, or 

about 27% oftotal U.S. emissions of greenhouse gases (GHGs). 1 These power plants generate 

about one-half ofthe 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 not passed legislation to 

reduce GHG emissions, but maoy 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 of the House Energy and Commerce Committee has identified a reduction goal for that 

committee's legislation of"between 60 percent aod 80 percent by 2050."4 Such large emission 

reduction goals will not be met without significaotly reducing emissions from existing coal-fired 

power plants. 

To date, most discussion ofGHG emission mitigation related to coal-based power production has 

focused on new coal-based power production, aod detailed engineering studies have evaluated the 

cost aod performance ofvarious options for those new units. 5 With currently available 

technologies, C02 capture aod storage options (in saline formations) from these new units cost 7 $30- 70 per ton of C02 avoided. 6 The reader is referred to an earlier APPA White Paper for a 

general overview of carbon capture and storage (CCS) from coal-based power plaots. 8 This 

paper addresses those aspects of CCS that are of particular interest to retrofitting this technology 

on existing coal-fired power plants. 

With respect to retrofitting existing coal units, a 2005 IPCC report concluded: "Retrofitting 

existing plants with C02 capture is expected to lead to higher costs and significantly reduced 

overall efficiencies than for newly built power plants with capture. The cost disadvantages of 

retrofitting may be reduced in the case ofsome relatively new and highly efficient existing plants 

or where a plant is substantially upgraded or 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 . 
 3 Climate Change: GHG Reduction Bills in the 11 O'h Congress, Congressional Research Service, 


Rpt. #RL33846, January 31, 2007. 
 4 Memorandum from John Dingell, Chairman of Committee 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 of 2006, 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: A White Paper on Technology 


for the American Public Power Association (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. 


2 
Technology Choices 

The vast majority of existing coal-fired power plants are pulverized coal units. Pulverized coal 

units have two choices for CCS retrofit: post-combustion capture of C02 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. In this system, an acid gas sorbent 

vessel is placed downstream of conventional pollution 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 stream is then 

pressurized to about 2000 psia, for transport (as a supercritical fluid) via pipeline to an injection 

field. There it is injected into a stable formation as deep as one mile underground. The process 

requires large amounts of energy, both to strip the C02 from the sorbent and to compress the 

concentrated C02• In a study of capture technology at greenfield, or new, power plants, NETL11 

concluded that 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 in the NETL report for a subcritical power plant. As can be 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 and pumps needed for the 

enlarged generation system (which bums more coal for the same power output) and the greatly 

enhanced cooling system. The C02 capture system (alone) requires about twice as much cooling 

water as the original power plant. 

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 of heat stable salts in the sorbent, this must be lowered to about 10 

ppm. The NETL design accomplishes this at a new unit by using a serial combination of a 

traditional wet limestone FGD and a sodium hydroxide polishing scrubber. 

The various pieces of hardware required for C02 capture and compression require space. NETL 

reports that about one acre ofland is needed for each 100 MW of generating capacity. 13 A 

separate NETL report suggests that land requirements for capture and compression equipment at 

a 500 MW unit would be 60 acres, or 12 times the first estimate. 14 In either case, this space 

requirement can be 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. 


3 
Regarding 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 

If a pulverized coal power plant is fired with nearly pure oxygen, instead of with air, the nitrogen 

in the traditional combustion air is eliminated from the flue gas, and the flue gas is composed 

primarily of C02, 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. For purposes of this 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 of the 

()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 of nitrogen oxide and use of C02 

recycle. 17 Additionally, the potentially higher combustion temperatures and the improved heat 

transfer properties of oxy-combustion gases mean that it may be 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 power requirements, 

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 power needs 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. It may be 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. And the parasitic power needs 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 new pulverized coal unit both to 

one with similar power output, but with 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 a jet 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. 


4 
Note that both approaches to C02 capture, with current technology applied to a~ power 

plant, nearly doubled the power plant's capital cost and the cost of electricity produced. 

Table I. Comparison of cost and performance of capture systems (new plant). 

Parameter Base Post-comb'n Oxv-comb'n 

C02 capture No 90% 100% 

Gross capacity, MWe 584 667 793 

Net capacity, MWe 554 549 546 

Net plant beat rate, Btu/kwh 8,649 12,538 12,074 

Net plant efficiency (HHV),% 39.5 27.2 28.3 

Total Plant Cost, $/kw 1563 2857 2930 

Levelized cost of electricity, $/MWh 62.9 114.4 113.0 

Cost of capture, $/ton C02 avoided n.a. 63 52 

S02 emissions, #S02/mmBtu 0.085 Negligible 0.003 

NOx emissions, #NOx/mmBtu 0.07 0.07 0.07 

It should be repeated that the above table relates to new power plants. Traditional pollution 

control technologies designed for new power plants usually have a higher cost per unit of power 

output when applied to existing units. These cost "retrofit factors" have not been established for 

carbon capture technology, but for traditional pollutants like S02 and NOx, they can be a 25-40% 

cost increase over the cost of a 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 power needed 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 of more than 

one-third of the output of the power plant. 

Replacement of this parasitic power, at today's escalated prices for new power 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 Air Interstate Rule (CA!R) was by necessity introduced in phases (the necessity being that 

skilled labor limitations precluded a one-step regulatory process). 19 Consider the comparative 

difficulty of retrofitting C02 capture systems on the existing 320 GW coal-fired power plant 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 of C02 capture and compression systems, versus roughly 100 GW of S02 

scrubbers and NOx selective catalytic reduction systems under CAIR. 

A final issue specific to existing units is that a different level of C02 capture performance may be 

appropriate for those units. Most technical studies assume a high level, e.g., 90%, of C02 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 of control 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. 


5 
Operational issues related to CCS 

Most generating unit-level analyses of the cost impacts of environmental requirements focus on 

the levelized cost of electricity (COE) implications of meeting the rules. It is 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 in the COE projections (and the COE results) 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 of idle natural 

gas combined cycle (NGCC) units in the U.S. to recognize the reality that flawed assumptions 

with major economic ramifications are not just a theoretical possibility. 

The large parasitic power requirements of CCS introduce additional analytical complexity 

regarding the use of systems equipped with C02 capture, particularly retrofit units. Dispatching 

costs for these units will be much greater due to the higher fuel consumption, and purchase of 

replacement power. Moreover, if replacement 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, or new 

power plant. A retrofit factor of 50% 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 of carbon 

taxes (0-100 $/metric ton C02), for coal and natural gas. Additionally, the costs in the figure 

reflect purchase of makeup power to replace the power required to run the CCS system, an issue 

further discussed below. 

Note that the basic coal plant has a variable cost of about 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 of natural gas prices. The dashed lines in the figure represent an uncontrolled 

plant paying the relevant "tax", rather than capturing the C02, and a "hybrid" approach of 

controlling half the 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 paid to 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 of technology 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). If these 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. 

6 
A key parameter in these cost comparisons is the cost of replacement power for the CCS system. 

Replacement power is estimated to be about 30% ofthe total plant generation for a pulverized 

coal system, and about one-half that for a natural gas combined cycle (NGCC) system. Who 

provides the replacement power is also important to dispatching costs. If the power is purchased 

from another utility, then its costs can be taken entirely as variable costs. If the 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" of replacement or parasitic power) are presented in Figure 5. This 

differential effect ofwho supplies the replacement power can be seen in comparing Figures 4 and 

5. 

The coal-based systems with CCS show a significant reduction in dispatching costs for the "selfgenerated" replacement power case (Figure 5), relative to the "purchased power" 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 of the 

replacement power, because most of the cost ofNGCC power is the fuel cost, which is a variable 

cost in either scenario. For the self-generated replacement power scenario, the dispatching costs 

for a pulverized coal unit retrofit with CCS is about 40-50 $/MWh over a range of carbon taxes, 

which makes it comparable to NGCC systems without CCS retrofits. The take-home message 

here is not the absolute values of these 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 system being evaluated, or they can be seriously misled. 

A related factor is the impact of parasitic power needs on bulk transmission of electric power to 

regions that are traditionally "net importers" of power. If a utility has generation capability that 

exceeds its local needs, it generally tries to sell that power to neighboring power consumers that 

have insufficient self-generation capacity. Iflocal excess power is eliminated by retrofitting CCS 

systems on existing coal (and gas) power plants, then those utilities that previously purchased the 

excess power will quite likely lose that source of electricity. Hence, the sudden broad 

deployment ofthe current generation of CCS 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 of carbon 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 of the capture costs. 

2. There is experience with pipeline transport and injection/storage at relatively small scale, 

but no experience with storage at the scale of commercial coal-fired power plants (e.g., 3 million 

metric tons per year for a single 500 MW unit). DOE is now beginning a program for evaluating 

"1 million TPY" demonstration projects, but results are years away. 

3. There is no environmental regulatory framework for addressing the injection and storage 

of C02 in the most likely resource for coal-fired power plants: 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 Control program (UIC). See APPA paper 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. 

7 
integrity for hundreds of years. It is unlikely that electric utilities will embrace CCS technology 

until pragmatic frameworks are established. 

Regulatory Issues for Retrofits 

Clean Air Act Permits and Federal New Source Review Issues 

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 of an existing electric generating unit will result in the 

retrofit being deemed a "major modification of a 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 Air Act. Major modifications are suhject to the federal new source review (NSR) program, 

which includes lengthy permitting, modeling of air quality impacts, and installation of state-ofthe-art pollution control equipment on the retrofitted boiler and ancillary emitting equipment. 

Under current federal law even environmentally beneficial projects can be subjected to lengthy 

regulatory processes, public scrutiny which can include legal challenges, and additional costs 

deriving from analytic requirements for permit preparation and additional pollution controls. It 

should be noted that NSR may be required for S02 and NOx retrofits installed pursuant to the 

2005 Clean Air Interstate Rule (CAIR) because the S02 and NOx pollution control equipment 

may lead to small increases of pollutants other than S02 and NOx. 26 

However, even ifthe NSR exemption for "pollution control projects" still existed27 , typical 

retrofits to existing power plants likely still would require NSR review. The large parasitic power 

requirements of CCS technology will very likely lead to increases in coal use at existing units. 28 

For some pollutants, like S02, the additional reduction of that pollutant that occurs as part of the 

CO, capture process will negate the increased amount of combustion. For others, like particulate 

matter, the situation is not as clear. In addition, some of the components of the 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 of the States (not adopted by ECOS). 27 The D.C. Circuit Court of Appeals 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% of the 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 of whether 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. 

8 
system may be sources of fugitive emissions of various pollutants regulated under the Clean Air 

Act. 

NSR Review ofC02 and Other Green House Gases (GHG) 

C02 and other GHG also are likely to be regulated NSR pollutants for purposes of NSR review 

by the end of 2008 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 of 2008. The regulation of C02 under Clean Air Act requirements (except as a "hazardous 

air pollutant" 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" of GHG is, and 

even more importantly, what "significant increases" of GHG are for purposes of defming the term 

"major modification."31 

Assuming C02 and other GHG become regulated air pollutants, a significant net increase of any 

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 NSR requirements due to small associated increases 

in particulate matter emissions. Similarly, the retrofit of traditional pollution control devices, like 

SO, scrubbers, also could trigger "major modification" status for that facility for COz, in the 

absence of the now-defunct "pollution control exemption". This would lead to case-by-case Best 

Available Control Technology (BACT) reviews for C02 emissions. 

Reconstruction and Clean Air Act New Source Performance Standards 

If a facility retrofit constitutes a "reconstruction" of a 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 of an existing facility to such an extent that: 

(1) The fixed capital cost of the new components exceeds 50 percent of 

29 In Massachusetts v. EPA U.S. 127 S.Ct.1438, 75 USLW 4149 (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" under the 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 if they 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 of the 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/. 

9 
the fixed capital cost that would be required to construct a comparable 

entirely new facility, and 

(2) It is technologically and economically feasible to meet the applicable 

standards set forth in this part. 

(c) "Fixed capital cost" means the capital needed to provide all the 

depreciable components. 

Since the addition of a 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 of a "pollution control" is included in determining the cost 

of a 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 if all of these 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 on this 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 of C02 as a waste "would diminish 

significantly the potential to meaningfully mitigate the impact of C02 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 of the Safe Drinking 

Water Act, to address underground injection ofC02•

35 

Another local consideration that needs to be considered in the context of CCS 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 of surface rights. Careful 

examination of deeds and other land records may be necessary to establish property ownership 

and rights ofway for transport and sequestration of gases. 

33 New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005). 


34 Storage of C02 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, and expertise ofstates andprovinces in the regulation ofoil and natural gas production and 

natural gas storage in the United States and Canada, the states and provinces would be the most logical and 

experienced regulators ofthe geologic storage ofcarbon 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 EPA Administrator Stephen Johnson. 

10 
Other liabilities 

Two additional areas ofrisk management related to C02 storage are: 

1. The potential for stored C02 to migrate into areas of other valued resources, such as 

natural gas deposits, and diminish the value of those resources; and 

2. The potential for C02 migration after closure ofthe injection site. Injection of C02 

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 of available commercial risk 

management issues. 

Effectively managing these risks may require government participation, and that may require 

additional legislative authority. 

Looking to the future 

There is much ongoing activity related to CCS. The Department of Energy 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 of existing coal-fired power plants 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 of C02 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, or upgrading boilers, so that the existing plant becomes more efficient and 

productive. This would provide both a partial cost offset to the increased cost of electricity due to 

CCS retrofit, and (possibly) reduce the impact of parasitic power needs to drive the CCS 

hardware. 

• Gain experience with storing large quantities of C02 in different types of geologic saline 

structures. The Regional Partnerships program may be a good start, but a few large projects are 

unlikely to be representative of the full range of geologies in the U.S. that are attractive for C02 

storage 

• Increase our knowledge base and simplify traditional preconstruction pennitting 

procedures to expedite the permitting of CCS retrofit projects. 

11 
Abouttheauthor -Doug Cart~risan indel?endent consultmt orre!lergyteclmology ancl 


rela,ted environrnentalissJ.les: His currentpractiq, focus<;s 0ni!dvising clien,ts regarding 


advancedcoal-based technologies and.their potential role in mitigating globalcli111ate 


,·ch~11ge: .Mr. Carter'sresumeincludes.25years \Vith theU.S, Department ofEnergy, where 

he was Directorqfthe Office ofP.i<mninga11d Environmental Analysis, within the Office of 

Fossil Energy. He had previously s.erved with the Office ofEnforcement and Office ofAir 

Quality Planning and Standards. at the U.S. Environmental Protection Agency..·Mr.Carter 

holdsdegreesin Meehani(>ai Engineering and Environmental Engineering. He can No . reached at Carter2250@comcast.nct . 

The America11 Public Power Association isthe nation!\! service organization representing the 

·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 

and carbon, capture an,d !';eol~gic sequestration or storage is:. 

http://www.appanet.orgltlles/HTM/?cs.html . .·,· .•.• ......· 

APPAContact: Theresa Pu!>;ll, Director, Euvironrnentar Services, 1875 Conn<;cticut Ave, 

NW, Suite 1200,Washinglon, D.C. 20009c57!5orat(2()2} 467c2943 

See page 13-16forfigures 

12 
Cooling system 

F&P, 13% 

Figures 


Figure 1. Pulverized coal power plaut with carbon capture. 


Coal 

& 

Boiler 

&1\~1, . '\SCRl 

Sulfur 

By Products 

' 

F1yash 

Recycle ~ 

~ 

----------------------­ al 

I 

~------- -( Conde-nser l+---------­ ~ 

Sequestration 

Ready C02 

Stack 

Electric 

Figure 2. Sources of parasitic power. 

Additional Power Needs for CCS 

Other, 

C02 compression, 

53% 

Amine system Aux. 

24% 

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

Electric 

Power 

Solid I 1 

By Products - - - - - COndensCI:' 1---+---------l

Note: C02 recirculation may be taken from before or after the FGD 

system, depending on so2 concentration. 

' 

Flya.h 

Recycle 

--------------------- ~~

.., 

Sulfur 

By Products 

Steam Turbine 

Sequestration 

Ready C02 

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

Dispatching Cost for Fossil Generating Options 

120 


100 


~ 

..c: 

;: 80 


-
 II)

-II) 60 


0 


<> 


... 


..c 

·;: "' 40 


>"' 

20 


0 10 20 30 40 50 60 70 80 90 100 


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 -NGCC w/90% capture, Ref. Price gas -NGCC w/90% capture, $6.6~-- ~~~ 

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

120 

100 

~ 

..c: 

;:: 

::;;; 80

-

--"'

"' 60 0 

(..) 

..!!! 

J:l 

"' 40

·;: 

> "' 

20 

Dispatching Cost for Fossil Generating Options 

0 10 20 30 40 50 60 70 80 90 100 


Carbon Tax, $/metric ton C02 

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

"" "" NGCC, no captu~~.~~ying tax -NGCC w/90% capture, Ref. Price gas -NGCC w/9~Xo capture, $6.63 gas 

16 
American 

Public Power 

Association 

Carbon Capture and Storage From Coal-based Power Plants: 


A White Paper on Technology 


for the American Public Power Association (APP A) 


L.D. Carter 


May 22,2007 


Introduction 

Technology for carbon capture and storage (CCS) from coal-based electric 

power plants 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 of electricity 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 been used since 1990 to inject C02 into saline reservoirs in 

Canada, in association with oil and natural gas processing1

. Additionally, a 

limited number of power 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 scale power plants 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 be permanent to be effective. 

The challenge facing industry, and the regulatory community, is to address the 

technical gaps in integration of the technologies at hand, move aggressively with research 

and demonstration projects to significantly reduce the cost of more advanced carboncontrolled systems, build an improved understanding ofthe long-term behavior of C02 

stored underground, and craft a pragmatic risk 

management framework for conducting C02 storage. Increasing the difficulty of 

this challenge is the fact that all of this must be done simultaneously, with limited 

resources, and at a time when continuous construction ofnew power plants is necessary 

to supply a healthy and growing economy. 

1Overview of Acid-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 Process using MEA (Mono-Ethanolamine), 

Fluor Daniel ECONAMINETM MEA process, 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 of what 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 of flue 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 of amine 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 of electricity 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 of the 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 

higher temperatures 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 C02compression. None of these 

systems has been operated at a commercial scale, although most of the 

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 of technology, 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 . 


3 

generates additional power (hence, the term "combined cycle"). Rather than 

capture the C02 at the end of this process, in an IGCC C02 is captured prior to 

combustion of the synthesis gas. This is possible because the synthesis gas can 

be reacted with water in a catalytic "shift reactor" to convert most of the 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 of this 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 MW facility, 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 of the 

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% of the plant's C02. For example, DOE's most recent analysis of IGCC 

gasifiers indicates that the GE system converts about 30% of the 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 of the 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 of these 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 H2S 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 per year 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 low viscosity of a gas, and yet 

can be efficiently pumped like a liquid. Because of the 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% H2S) 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 of the 

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. 


5 

COz storage 

A number of options are available for C02 storage. Figure 412 presents several 

of these 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 of the 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 of years 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 per year 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 

if the site is being considered for storage, but the integrity of the caprock 

has not been established by its ability to retain oil or natural gas over 

hundreds of thousands of years. 

• 	 In EOR situations, the operator's liability generally ends with the 

decommissioning of the 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 of the 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 Three types 

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 of the 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, 

but that 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-E OR 

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 of the storage project and the time needed for obtaining 

necessary permits. 

It should be noted, particularly in light of the 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-E OR 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, 

1 March2007. 

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 of these 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 of the 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 that the 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 of this 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-E OR 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 of time. And it must be 

emphasized that not all areas of the U.S. are proximate to attractive storage 

formations. 

As a final caveat, it should be noted that people 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 of this 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 ofEnergy, where he was Director of the 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 

Figures 

II 

Boiler 

Coal 

& 

Air 

' ~· 

~· ' '.a------- --1 

Sulfur 

By Products 

Condenser j.­ _________ -~ 

=--~Sequestration 

Ready C02 

Stack 

Electric 

Flyash 

Recycle 

Sulfur 

By Products 

-------------------~"f' Steam Turbine 

Solid 1 

By Products '-4---- -I Condenser }-- -+-­ ----­ __ ..!. 

Sequestration 

Ready C02 

Electric 

Power 

12 

Electricity 

Slag/Fines 

13 

(Formations are 

14