This comment letter response contains two parts:

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

Notes about the response letters:

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

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

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

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

• Each response letter includes: comment text; an EPA

‐ assigned comment code; and an

individual response. These are described and explained below.

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

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

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

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

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

appropriately addressed.

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

Comment ID. Additionally, one or more Comment Codes (i.e., unique topic area ID) was assigned to each discrete point raised by a commenter. This information was added to

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

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

construction requirements).

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

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

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

commenter was given a unique response.

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

Each letter response is a compilation of each comment and its individual response, compiled in the order of the original comment letter. As a result of this process, there is

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

and attention to each comment letter that was submitted.

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

Responses on each topic area are compiled and are also available in the rulemaking docket.FutureGen Industrial Alliance, Inc. 1101 Pennsylvania Ave NW

6th floor Washington DC 20004 www.FutureGenAlliance.org

Michael J. Mudd

Chief Executive Officer

614-716-1585

December 12, 2008

Water Docket Environmental Protection Agency

Mailcode: 2822T 1200 Pennsylvania Ave., NW Washington, DC 20460

Re: Docket ID No. EPA–HQ– OW–2008–0390

Proposed Rule: Federal Requirements Und er the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells

The attached comments and observations are su bmitted by the FutureGen Industrial Alliance (FGIA) in response to the United States Envi ronmental Protection Agency proposing Federal requirements under the Safe Drinking Water Ac t (SDWA) for undergro und injection of carbon dioxide (CO 2 ) for the purpose of geologic sequestration (GS). Inquiries about these comments can be directed to my attention.

Sincerely,

Michael J. Mudd

Chief Executive Officer

FutureGen Alliance

The FutureGen Industrial Alliance Member Companies

American Electric Power Service Corporation

x Anglo American Services (UK) Limited

x BHP Billiton Energy Coal, Inc. China Huaneng Group

x CONSOL Energy, Inc

x E.ON U.S. LLC

x Foundation Coal Corporation

x Peabody Energy Rio Tinto Energy America Services

x Southern Company Services, Inc.

x Xstrata Coal Pty LimitedDocket ID No. EPA-HQ-OW-2008-0390

INTRODUCTION

The FGIA has been working under contract to the US DOE to design and build a 275 MW IGCC power plant that will capture and seques ter one million tonnes per year of CO 2 in a saline aquifer

at a site near Mattoon, Illinois. The FGIA has completed site evaluation of 12 proposed sites in seven states and conducted a complete NEPA revi ew of four of those sites. The FGIA has completed an Initial Conceptual Design and is in the final stages of completing a preliminary design for the power plant and CO 2 sequestration site including a detailed multi-year measurement, mitigation and verification program for the selected site. The FGIA offers the following comments based on the real-world expe rience it has gained in developing an IGCC power plant site for CO 2 capture and sequestration in a sa line aquifer. Battelle, as its sequestration contractor has he lped the FGIA develop these co mments. Detailed comments are

offered on several programmatic areas identified in th e proposed regulations. Comments are also provided on other topics incl uding comments on the “Cost Analysis Technical Support Document”. Many of the estimates in the Co st Analysis do not appear to be realistic.

COMMENTS

Impact on Class II and Class V Wells p.43502, c. 1

The Proposed Rule for Class VI wells should have no impact on existing or future Class II or

Class V wells, which should be stated in the Proposed Rule in clear, unambiguous, and strong language. Furthermore, the Proposed Rule allows for the construction of existing Class II and Class V wells to be grandfathered, but there is no provision to allow th e grandfathering of the existing siting, area of review, operations, or monitoring plan. These areas should be grandfathered, too. Multiple Confining Layers Could be Requi red at the Direction of the Director

p. 53536, c. 3 The Proposed Rules for Class VI wells identifie d by EPA include a requirement for a confining zone with suitable properties to contain the injected CO 2 (§ 146.83(a). In addition, under subsection (b) of the proposed regulation, owne rs or operators may be required to identify and characterize multiple confining layers, at th e discretion of the Director (§ 146.83(b)).

Comment:

• Subsection (b) of § 146.83 of the proposed regula tions, which grants th e Director discretion to require the presence of multiple confin ing layers, does not promote sound policy and should be removed from the proposed regulation.

• If EPA chooses to retain the option described in subsection (b ), then the discretion of the

Director should be limited, and there should be specification of the types of conditions under which multiple confining layers might be required.

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This optional requirement may elim inate suitable GS sites without re ducing risk. It also adds a potential risk to a proposed project because the likelihood and cost of this additional requirement will not be known during the project initiation phase.

The rationale for inclusion of an optional requir ement for multiple confining layers is not provided. There does not appear to be any clear need for that additional requirement, which goes beyond what is currently required for Class I UIC wells that inject hazardous wastes. The proposed regulation could lead to significant proble ms in the future, but more importantly, this requirement is not needed. If subsection (b) of § 146.83 were re moved, and if the Director or his staff find that the confining system identified by an operator does not appear to be reliable, they can reject the application and/or require that the operator provide information on additional confining layers. The description of the requirement s for a confining system given in part (2) of subsection (a) would cover this situation, and would allow protect ion of USDW’s and the public without creating the potential for confusion th at would arise with the option outlined in subsection (b).

Previous experience and research have demonstrat ed that a single well-characterized confining system can provide more than adequate prot ection by preventing the upward migration of CO 2

. For example, time-lapse seismic imaging at the Sl eipner Project demonstrates “the caprock is an effective seal that prevents CO 2 migration out of the storage formation” (IPCC 2005). Examination of recent surveys of the safety of underground CO 2 sequestration found no suggestion that multiple confining systems are needed or should be required (e.g., IPCC 2005; Benson and Surles 2006). In addition, the technical support document provided by EPA for the proposed rule changes (Vulnerability Evaluation Fr amework for Geologic Sequestration of Carbon Dioxide, EPA430-R-08-009) does not provide any s upport for requirement of multiple confining layers.

The proposed regulations do not specify or in any way limit the conditions under which multiple confining layers might be required. Thus, ther e is no guidance for imposition of the rule, and no limitations on the discretion of the Director. Including this additional discretionary requirement as an option in the regulations is troublesome because there then is a good possibility that it could become the default requirement. If that were the case, the requirement of multiple confining layers would lead to potential disqualification of excellent storage sites, and additional

costs for characterization.

An additional problem with the optional requiremen t of multiple confining layers is one of perception. We know of no precedent within current UIC regulations, other applicable U.S. environmental law, or internationally, for the requir ement of multiple confining layers to containinjected fluids. Given the lack of precedent, the inclusion of the requirement for multiple confining layers for CO 2 in the proposed regulations for Class VI wells could lead to the incorrect perception by the public that injection and storage of CO 2 is more dangerous to the public than subsurface injection of hazardous wastes. This pe rception of high risk, which does not appear to be justified by previous studies of the risks of subsurface CO 2 sequestration (e.g., IPCC 2005; Benson and Surles 2006) could lead to decrease d use of carbon sequestra tion as an option to limit global climate change, and therefore to de creased potential for full use of U.S. energy

resources.

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References:

Benson SM and T Surles. 2006. Ca rbon Dioxide Capture and Stor age: An Overview with Emphasis on Capture and Storage in Deep Geol ogical Formations, The Proceedings Special

Issue, Institute of Electrical and Electronics Engineers (IEEE), Vol. 94, No 10, October 2006,

DOI 10.1109/PROC.2006.883716.

IPCC. 2005. IPCC Special Report: Carbon Dioxide Capture and Storage. Summary for Policy Makers and Technical Summary, B. Metz, O. Da vidson, H. de Coninck, M. Loos, and L. Meyer (eds.). Cambridge University Press, New York.

Area of Review (AoR) and Area of Monitoring (AoM)

p. 43493, c. 2 The Proposed Rule defines Area of Review (AoR) as “The region surrounding the geologic sequestration project that may be impacted by the injection activity”. The area of review is based on computational modeling that a ccounts for the physica l and chemical properties of all phases of the injected carbon dioxide stream.

The proposed regulation uses the Area of Review (AoR) for defining both monitoring requirements and corrective actions:

p. 43499, c. 1 Area of Review (AoR) and Co rrective Action: The Agency requires examination of both the vertical and horizontal extent of the area that will potentially be influenced by injection and storage activities and iden tification of all ar tificial penetrations in th e area that may act as conduits for fluid movement into USDWs (e .g., active and abandoned wells) and, as needed, perform corrective action to these open wells (i.e., artificial penetrations).

p. 43539, c. 3 (d)(2) The monitoring frequency and spatial distribution of mon itoring wells must be based on baseline geochemical data that has been collected under §146.82(a )(6) and any modeling results in the area of review eval uation required by §146.84(b);

Comment:

• EPA should define two regulatory regions surr ounding the geologic sequestration project and provide specific definitions for those regions; 1) Area of Mon itoring (AoM) and 2) Area of

Review; where the AoM is used to define the spatial distribution of monitoring wells and the

AoR is used to define the limit of Corrective Action:

• Area of Monitoring (AoM): The region surrounding the geologic sequestration project that

contains 95% of the carbon dioxide mass. Th e area of monitoring is based on monitoring data and computational modeling that accounts for the physical a nd chemical properties of all

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phases of the injected carbon dioxide stream. In the absence of monitori ng data, the area of monitoring is based on computational modeling.

• Area of Review (AoR): The region surrounding the geologic seque stration reservoir that has or is indicated to develop pressures that are gr eater than 10% different from the pre-injection formation fluid pressure, but no less than the Ar ea of Monitoring. The area of review is based on monitoring data and computational modeling that accounts for the physical and chemical properties of all phase s of the injected carbon dioxid e stream. In the absence of monitoring data, the area of review is based on computational modeling.

• The proposed definitions of AoM and AoR have several important components:

− The AoM has a mass-based definition.

− The AoR has a pressure-differential-based definition.

− The AoR is never smaller than the AoM.

− The AoR and AoM may be asymmetr ical around the injection well(s).

− The AoR and AoM may vary over time.

− The carbon dioxide mass should be determined using a combination of monitoring data and computational modeling.

− Pressure differentials are based on equilibrium hydrostatic conditions.

Relative to existing UIC regulati ons governing waste disposal, EP A is introducing fundamentally new concepts for defining the area of review (AoR) for CO 2 injection. The newly proposed concept is flawed and will pose an unjustifiable barrier to CO 2 injection projects unless the approach for defining the AoR is addressed in the regulation. It is neithe r possible, nor practical, to predict where every molecule of CO 2 will migrate; therefore, a threshold levels are required. In the case of large-scale injection projects, ch anges in formation pressures could be expected dozens to hundreds of miles from the injection we ll. It would not be practical for the AoR to comprise the entire area experiencing changes in formation pressure. A reasonable threshold for establishing the AoM might be where pressure ch anges are greater than 10% of the standard formation pressure.

The proposed regulation defines the Area of Review (AoR) as being the region that may be impacted by the injectio n activity, without defining or quantifying impact. To be useful the bounding areas for corrective actions and monitoring activities must have specific definitions. Under deep geologic sequestration conditions the injected fluid (i.e., supercritical CO 2 ) has low compressibility, the displaced fluid (i.e., brin e) has low compressibility, and the reservoir formation (e.g., sandstone) generally has low comp ressibility, all of wh ich suggest that the impact (i.e., pressure change) of the injection activity could be detected at great distances from the injection well(s).

Injection of CO 2 into deep saline formations is driven by differences between the well injection pressure and formation pressure. To avoid induc ing fractures or opening ex isting fractures in theformation and caprock, well injection pressure will be limited to some fraction below the fracturing pressure. As CO 2 migrates into the formation the fo rmation pressure increases around the injection well. The pressure distribution in the formation around the in jection well depends on the formation properties, structure, and injection ra te. Injection formations will be required to be

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confined vertically and/or horizon tally to prevent the vertical mi gration of injected fluids and

saline reservoir flui ds into USDWs.

Confined formations (e.g., a caprock overlying a horizontally extensive formation) allow the formation fluid to be displaced latera lly by the injected fluid. Injecting CO 2 will result in elevated pressures both inside and beyond the CO 2 plume. Elevated pressures within the CO 2 plume have the potential to force CO 2 and formation fluid through pe rmeable wells, fractures, or faults that penetrate the formation. Elevated pressures outside the CO 2 plume have the potential to force formation fluid through permeable wells, fract ures or faults that pe netrate the formation. The higher the formation pressure is above th e ambient formation pressure, the greater the potential for CO 2 and formation fluid to leak through permeable wells, fractures, and faults. The lateral pressure distribution is a function of the injection rate and the lateral distribution of formation permeability. When CO 2 injection is halted, elevated pressures decay over time as the injected and formation fluids migrate away from the injection well(s).

The proposed regulations define an AoR and Co rrective Action as being an area within which artificial penetrations may act as conduits for fluid moveme nt into USDWs (e.g., active and abandoned wells) and, as needed, require the appli cant to perform correctiv e action to seal these open wells. The potential for fluid moveme nt into USDWs from the injection of CO 2 into the injection formation is correlated with the area of elevated formation pressure, which is usually larger than the area that contains the injected CO 2 mass. For confined formations, this area is defined by the lateral pressure dist ribution around the injection well(s).

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Stratigraphic Restriction of Saline and Ot her Reservoirs to Below Lowermost USDW

The Proposed Regulation for saline formations state:

p. 43494, c. 2 Saline formations: Deep and geographically exte nsive sedimentary rock layers saturated

with waters or brines that have a high total dissolved solid s (TDS) content (i.e., >10,000 mg/L TDS).

Proposed Geologic Siting Requirements: p.43505, c. 1 Existing UIC requirements for siting injecti on wells include identi fication of geologic formations suitable to receive the injected fluids and confine them such that they are

isolated below the lowermost USDWs, mini mizing the potential for endangerment.

Target geologic formations: p.43502-43503, section H

As with unmineable coal seams, EPA seeks comment on prohibiting injection into such formations [basalts, salt domes, and shales] if they are above the lowermost USDW

.

The EPA is soliciting comments on these issues:

1. Whether CO 2 injection should be allowed into an injection zone (saline sedimentary

formations, unminable coal seam, basalt, salt caverns, shales, or ot her reservoirs) above

the lowermost USDW, when the Director dete rmines that geologic conditions exist that will prevent fluid movement into adjacent USDWs.

2. Whether a designated USDW should be exempted to allow for GS, and under what conditions should these exemptions be approved.

3. Whether all USDWs should be exempted below a CO 2 injection receiving bed.

4. Whether the EPA should set a minimum injectio n depth requirement for GS, rather than require that such injection take place below the lowermost USDW.

Comments:

GS should be permitted in the following: 1) reservoirs containing >10,000 mg/L TDS, 2) where the formation water is <10,000 mg/L but is non-potable for other reasons, or 3) formations exempted as USDWs by the state.

GS should not be restricted to strati graphic zones below the lowermost USDW.

• Prohibition of CO 2 injection into saline formations above USDWs is overly restrictive and would severely limit GS in states such as Wyoming, where deep sedimentary formations in

much of the state have TDS lower than 10,000mg/l (NETL). Thus almost any formation considered for GS would likely overlie a low TDS formation.

• GS should be allowed into an injec tion zone above the lowermost USDW ( whether saline or other formation ) when the Director determines that geologic conditions exist that will prevent fluid movement into nearby USDW s. Conditions that will prevent downward

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movement of fluids include the presence of intact low permeability beds between the receiving bed and the underlying USDW. In consideration of the buoyant behavior of injected CO 2 , the requirement of thousands of feet of intervening formations may be less important than the demonstration of the seal ing capacity of the intervening layers. We

believe that “thousands of feet” is a vague requirement, when the more rigorous test is the demonstration of the sealing capac ity of the intervening layers.

• The draft rule is far too restrictive and is not based on technical risk factors. Risk of CO 2 contamination to a USDW is lower for aquifers that underlie an injection reservoir due to the inherent buoyancy of the CO 2 . Vertical migration can be interrupted completely by the presence of one or more low permeability laye rs. Hence, a prohibition on injecting above the

shallowest USDW is not based on real technical risk of a GS project.

• The conditions for exemptions of aquifers shoul d be clarified. Aquifer exemptions should be allowed for GS (“a receiving bed for Class VI we lls”) when it can be demonstrated that there is no reasonable expectation that the formation will be considered for a drinking water

source, and when it can be demonstrated that CO 2 is highly unlikely to migrate updip into a portion of the formation that may be considered for use as a USDW.

• Blanket aquifer exemption of all USDWs below a GS zone is not needed if there is demonstration of a competent seal between the injection zone a nd the first underlying USDW.

• No blanket prohibition should be introduced for any potential non- saline reservoir; promising GS targets of basalt, unmineable coal seams, etc., should be evaluated with methodologies

similar to those for saline formations.

• GS is better served by neither mandating a se t minimum depth for injection nor by requiring injection take place below the lowermost US DW. Minimum depth requirements would be unnecessarily proscriptive. Shallow injections could be done for very small commercial producers or in cases where reservoir engineerin g practices (such as pr e-dissolution of the

CO 2 into formation water) are done so that no free CO 2 phase exists.

Three of the most important issues here are (a) the physical locati on of saline formations or other types of geologic reservoirs fo r GS, relative to USDWs; (b) unde r what circumstances the EPA should remove one or more water-bearing zones fr om the list of USDWs to allow injection; and (c) under what other conditions should th e EPA allow injection above a USDW.

In addition to injection into saline formati ons, EPA recognizes that basalt, unmineable coal

seams, salt domes, abandoned mines, black shal es and other types of reservoirs may be promising, emerging targets. Basalts, in particular appear to have considerable potential for GS. Research by PNNL and others i ndicates that extruded basalt flow tops and flow bases may have regional, multi-gigaton capacity for CO2 storage. In addition, laboratory experiments suggest that mineralization of large volumes of CO2 may proceed within a few years of injection (McGrail et al, 2006).

In the proposed rule, the new Class VI wells woul d be allowed to inject CO2 into basalts, deep saline reservoirs, and other poten tial reservoirs only when th ey are beneath the lowermost

USDW.

A USDW is defined by the EPA as “An aquifer or portion of an aquifer that supplies any publicwater system or that contains a sufficient quantity of ground water to supply a public water sysThis material is a product of the FutureGen Industrial AllianceDocket ID No. EPA-HQ-OW-2008-0390

tem, and currently supplies drinking water for hu man consumption, or that contains fewer than 10,000 mg/l total dissolved solids and is not an exem pted aquifer.” This definition would include many non-potable aquifers that would be candidates for GS.

The EPA’s reliance on the standard definition of a USDW as being solely <10,000 mg/L TDS is far too restrictive. In many states, this standard is not applied – all gr oundwaters are protected regardless of water quality. In at least one state GS operations would be permitted if removing anthropogenic CO2 is considered a greater public benefit than the lo ss of a marginal aquifer.

The EPA is aware that restricting GS to a position below all EPA defined USDWs would severely limit GS in many areas. Under the curr ent proposed rule, direct ors may grant injection into deep, marginal USDWs that directly overlie crystalline basement rock and/or unmineable coal seams. In addition to these exceptions, the EPA would consider allowing operation of GS wells where receiving formations are above the lowermost USDW only where there are

thousands of feet between th e injection zone and the overl ying and underlying USDWs.

As currently defined by the EPA, “aquifer exemp tions” permanently remove a specified aquifer from protection as a USDW. Aquifer exemp tions are currently gr anted for mineral or hydrocarbon exploration by Class III solution mining wells, or by Class II oil and gas related

wells, when there is no reasonable expectation that the formation wi ll be used as a drinking water supply. It is important to note th at the EPA has not previously c onsidered the purpose of creating additional capacity for the emplacement of fluids as sufficient cause for granting an exemption. Under the new rule, it would be possible for operato rs to apply to change the designation of some aquifers being used for Class II injection. These aquifers would need a new, separate exemption

for GS.

The EPA suggests the following possible alternat ives that would allow injection between

USDWs or above the lowest USDW:

1. Injection approval for GS betw een USDWs formations is at the Director’s discretion in circumstances in which it may be demonstr ated that USDWs would not be endangered.

2. Directors may be allowed to exempt, at thei r discretion, all USDWs below a GS injection zone. (This would permanently remove these aquifers from protection as USDWs).

References McGrail, B. P., H. T. Schaef, A. M. Ho, Y. Chien, J. J. Dooley, and C. L. Davidson. 2006. Potential for Carbon Dioxide Sequestration in Flood Basalts, J. Geophys. Res. 111, B12201.

NETL. 2007. National Carbon Sequestration Atlas. http://www.netl.doe.gov/technologies/ carbon_seq/refshelf /atlas/index.html

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Proposed Mechanical Integrity Testing Requirement

Proposed Regulation

p. 43513, c. 3 ...require owners and operators of Class VI GS proj ect to monitor internal mechanical integrity of their injection wells by continuously monito ring injection pressure, flow rate, and injected

volumes...

p. 43514, c. 1 ...require owners and operators of CO2 wells to de monstrate injection we ll external mechanical integrity at least once annually.

The EPA seeks comment on the appropriate freque ncy of internal and external MITs for GS injection wells.

Comments:

• We recommend that an external MIT be performed on a recurren ce interval of every 5 years, as is now typically done for other classes of UIC wells. The external MIT should rely primarily on results obtained from geophysical wire-line logging surveys, and (if warranted by wireline geophysical survey results), conducting direct leakage-detection tests of suspected areas of concern. If the external MI T indicates the potential for a compromise to the cement seal characteristics or well casing integrity, then additional, more quantitative tests (e.g. Gasda et al. 2008) and subseque nt corrective actions may be warranted.

• The recommended external MIT recurrence assessm ent of every 5 years is predicated on no indications of injection system compromise that would be observed by changes in monitored internal MIT parameters duri ng injection (e.g., injection or annular zone pressure), or pressure fall-off test response following normal, temporary operational shut-down periods. If at any time the monitoring parameters or pressure data responses indicate anomalous injection test system behavior, then this could indicate the need for an external MIT evaluation to be performed, at the discretion of the Director.

During the injection period the pr oposed rule states that intern al MIT should be performed continuously by monitoring pressu res (e.g., injection and annular zones), injection rates and volumes, etc., and external MIT should be performed annually. Continuous monitoring of injection rates, volumes, and pressures duri ng the injection phase seems reasonable and appropriate. The semi-annual reporting frequenc y of such results also seems reasonable.

The proposed rule also states that external MIT be performed annually during the injection phase. The rationale for this is to protect USDWs given the potential corrosive effects on injection well components (steel casing and cement) that are expos ed to the GS stream and the buoyant nature of the injected fluid.

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To execute an annual external MIT, the injecti on well would be required to be shut down (i.e., cease CO2 injection operation) and the internal CO2 injection delivery tubing system to be physically removed from the injection well. At a minimum, this would require that all GS projects, no matter how large, to have a backup in jection well or multiple injection wells to be available so as to not adversely impact or interrupt daily plant operations.

In general, we believe that annual external MIT evaluations would be excessive and overly disruptive for normal plant operations. This is be cause quantitative external MIT evaluation tests would require:

• Removal of the surface wellhead and internal CO2 injection delivery tubing system

• Performing detailed wireline geophysical surv eys for cement-seal and well casing integrity (e.g., cement-bond log), and

• If warranted by the results of the wireline ge ophysical surveys, conduct¬ing direct leakagedetection tests with installed internal test equipment (e.g., downhole inte rnal straddle-packer system) of suspected areas of concern

The performance of the various aforementioned el ements of an external MIT and re-installation of components of the injection we ll system are likely to take between 2 to 5 days, depending on the characteristics of the injecti on well (e.g., injection rese rvoir depth), complexity of the internal CO2 injection well system, and whether quantita tive leakage detection tests are warranted. Because of extended time required to conduct an external MIT program, the performance of

fixed-annual external MIT eval uations (outside the schedul e of planned plant operation maintenance shut-downs) are believed to be excessively disruptive.

Reference

Gasda, S. E., J. M. Nordbotten, and M. A. Celia. 2008. Determining effective wellbore permeability from a field pressure test: a numerical analysis of detection limits. Environmental Geology, 54(6), 1207-1215, doi:10.1007/s00254-007-0903-7.

Unmineable Coal Seams p. 43503, c.2)

While coal seams are well studie d and understood, the process of CO 2 adsorption to coal has not been proven and the chemical reaction of supercritical CO 2 with coal formations are not well

understood.

Comment: This statement is contentious and does not add to the substance of the Propose Rule. In fact, the process of CO 2 absorption is well understood. Suggest removing the statement.

In addition, many ECBM recovery ope rations will likely be shallow. Shallow storage will result

in the CO 2 remaining in a gaseous state, which can limit the amount of CO 2 that can be sequestered.

Comment:

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These statements are not true. The statements would be true for storag e into shallow aquifer pore space, such as in shallow saline formations , but it is not the case fo r storage into shallow

coal seams. In shallow coal seams CO 2 is absorbed and remains in the condensed phase and not in the gaseous state. Suggest removing the statement.

EPA is concerned that coal seams in the close proximity to USDWs and CO 2 injection for GS could endanger USDWs. In some cases, coal seams are considered USDWs and may serve as public drinking water supplies. As a result, EPA is proposing to preclude the injection of CO 2 for long-term storage into coal seams where they are above the lowermost USDW.

Comment:

See comments above under the heading Stratigraphic Restriction of GS to Below Lowermost

USDW.

Post-Injection Monitoring Period p. 43540-43541

The owner or operator shall continue to c onduct monitoring as specified in the Directorapproved post-injection site ca re and site closure plan for at least 50 years following the cessation of injection...If the owner or operato r can demonstrate to th e satisfaction of the Director before 50 years, based on monitoring an d other site-specific data, that the geologic sequestration project no longer pos es an endangerment to USDWs.

Comment: The basis for the 50 year minimum period is not clear. The minimum period should be tied to both risk and project specific in formation. Although there is th e possibility that post-injection monitoring period can be reduced given suffici ent data, this appro ach adds significant uncertainty to both the project sche dule and cost. It appears unlike that an owner or operator will be able to know with certainty during the planning stage for GS what the post-injection monitoring period will be. The end result is for owners and operators to assume the entire 50 year period, which will have an adverse effect on the cost, schedule and feasibility of the project. A time period of 10 years seems more reasonable, but would need to be confirmed by risk and project specific information.

Hazardous Waste Exclusion p. 43503, c. 3

Because the types of impurities and their concentrations in the CO 2 stream are likely to vary by facility, coal composition, plant operating c onditions, and pollution removal technologies, EPA cannot make a categorical determin ation as to whether injected CO 2 is hazardous under RCRA. Owners or operators will need to characterize their CO 2 stream as part of their permit application to determine if the in jectate is considered hazardous as defined in 40 CFR Part 261. If the injectate is considered hazardous unde r RCRA, then the more stringent UIC Class I requirements for injection of hazardous waste apply. The design changes EPA is proposing are meant to address the mobility and corrosi vity caused by long term GS of CO 2 , and not the long term storage of hazardous wastes.

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This material is a product of the FutureGen Industrial Alliance By defining ‘‘carbon dioxide stream ’’ to exclude hazardous wastes (146.81(d)), today’s rule, if finalized, assures that it would apply only to CO 2 streams that are not hazardous wastes as defined in 40 CFR Part 261. As a result, today’s proposed rule would preclude the injection of hazardous wastes in Class VI injection wells. EPA seeks comment on this approach and other considerations associated with the presence of impurities in the CO 2 stream.

Comment: Relegating CO 2 waste streams that designate as hazardous waste to the Class I hazardous waste program will prevent their inclusion in the proposed Class VI well classification where standards, guidance, and expertise will tailored for the properties of the bulk solvent.

GS is being pursued to address the burden of CO 2 release to the atmosphere from power plants. In burning fossil fuels for power, there is a consid erable amount of othe r products of combustion and other components that are typically scrubbed or otherwis e removed from the off-gas stream to prevent their release to the atmosphere. Th e clean up steps for removing these various gas and products of combustion from the CO 2 waste stream ultimately impact the power plant’s net energy output, which adversely affects the cost of electricity. Significantly increasing the cost of electricity will discourage GS.

If the objective of GS is to re duce and/or reduce the release of CO 2 to the atmosphere, the delta in energy cost may be made more palatable by combining other products of combustion with the

CO 2 waste stream. Additional technical informati on is needed to understand the merits and risks of co-injection of contaminants. A Proposed Rule for GS based on a high-purity CO 2 stream prior to understanding the trade-offs of co-injec tion of contaminants seems short-sighted. The Proposed Rule should have provisions and leeway for regulators and industry to balance cost, energy conservation, waste reduct ion, and waste management pr ogram while protecting USDWs and safety of the public.

Primacy Question

If an injection site boarder more than one state, which state or region will have primacy over the UIC permit?Additional Comments:Section in PublicNotice (Jul 15, 2008)CorrespondingSection inFederalRegister (Jul25, 2008)CommentSection III. Is Injected CO2considered aHazardous WasteUnder RCRA?II-I.EPA should specify the information neededto characterize the CO2 stream to determine ifmeets the definition of “Hazardous” as defined in 40 CFR Part 261If a CO2 stream is determined to behazardous per RCRA, can the CO2 stream still beinjected via wells that are constructed andoperated per the Class I UIC regulations, ordoes this preclude injection of the hazardous CO2 stream?Section IIIaA-1. ProposedGeologic SitingRequirementsIII-A-1.This section mentions several types ofgeologic/geochemical/geomechanical informationneeded to assess a site’s viability. EPA should specify the information required to supportthis analysis.A-4 Proposed InjectionWell OperatingRequirementsIII-A-4Class I wells are typicallyrequired to maintain an annular-fluid pressure that is greaterthan the injection tubing pressure to prevent outward leakage fromthe injection tubing.Typically, these wells operate at pressures much lower than CO2 injection wells. Thissame requirement imposed on CO2 injection wells would require specialized high-pressureequipment to maintain the required pressure differential on the annular fluid.The use of down-hole shut-off valves thatwould automatically shut-in the well isrecommended as a possible safety device in CO2 injection wells. This reviewer recentlycontacted the vendor cited by EPA (Schlumberger) for information on safety valves for aCO2 injection well and was told that they arenot available in sizesthat would be neededfor most on-shore injection wells because these devices are primarily used in larger offshore wells. The use of safety valves needs more consideration.A-5 MechanicalIntegrity TestingRequirementsIII-A-5Automated down-hole shutvalves sound problematic, especially if they are intended torespond to excursions in annular pressureand volume which are subject to temperaturefluctuations. See above comment.14Docket ID No. EPA-HQ-OW-2008-0390Regarding external MITs, it isn’t clear whether the requirement involves testing whileinjection CO2 or another fluid (e.g., water).Also, it isn’t clear whether or not thesemethods work with CO2; therefore,new/alternate methods may be needed.A-6 Proposed Plumeand pressure FrontMonitoringIII-A-6Page 102. Pressure gaugesplaced in the first formation overlying the confining zonewould not be useful for tracking the lateral migration of the CO2 plume or pressure front.Would EPA require monitoring wells that penetrate through the confining zone and intothe storage formation for this purpose?Fiber optic pressure and temperature sensors are likely to be prohibitively expensive.A-7 Record Keepingand ReportingRequirementsIII-A-7We support the requirementfor 1) a monitoring and testingplan 2) an AoR and CorrectionAction Plan and 3) a Post-Injection Site Care and Site Closure plan.To comply with a requirement for electronicrecord-keeping, new data storage tools will berequired to deal with the diverse nature of information thatwill be generated during thecourse of a CCS project.Cost Analysis Technical Support DocumentTable 2. Site Characterization CostsThe allotment of labor hours seems unrealisticallylow (this comment applies to most costtables). Some individual tasks are especially low(e.g., develop list of penetrations into injectionzone = 12 hours).In this table and others, laborrates appear to be low – perhaps underestimated by a factor of 1.5to 2 depending on task/activity.It appears that someimportant site characterization activities/tests havenot been included – e.g.,wireline logging, hydraulic testing, fluid sampling and analysis. These should be included.3D seismic survey costs may be underestimated – recent quotes suggest ~$100 K per squaremile. 2D seismic should be allowed because3D may be impracticable to implement inmany/most areas.Costs that are identified as“initial estimates” or “ICF estimates” should be assigned very highuncertainty/low confidence.Table 3. Monitoring CostsCosts for FEED study should be higher. Monitoring a CCS site willrequire in-depth planning.Monitoring wells will need to be of a large enough diameter to accommodate down-holeinstrumentation (e.g., cross-well seismic); thus,costs for monitoring wells based on slim-holeThis material is a product of the FutureGen Industrial AllianceDocket ID No. EPA-HQ-OW-2008-0390Cost Analysis Technical Support Documentprices may not be appropriate.Number of hours allocated for updating reservoir model based on monitoring data andconducting simulations, recalibratingetc. is grossly underestimated.Costs need to be included for assimilating, evaluating, interpreting the enormous amount ofdiverse monitoring data that will be generated. The currently allocated amounts - 20 hrs for anannual report, 15 hrs for quarterly reports, and 8 hrs allocated for monthly reports – areunrealistically low.Costs that are identified as“initial estimates” or “ICF estimates” should be assigned very highuncertainty/low confidence.Table 4. Well Construction CostsFEED cost seems high if thisis intended to cover the design of the injection wells.UIC permit costs are grossly underestimated ($10,000 per site plus $5,000per injection well)Rights of way costs should bebased on area (e.g., acre) not wellCosts for wellhead and control equipment isunderestimated. A wellhead (with Christmas Tree)alone can cost more than $100K. Controls canalso be quite expensive if they includeautomated valves, real-time downholesensors, automatic shut-offs etc.Pumps will not be required at all sites, i.e., if compression alone can achieve required injectionpressures.Pipeline costs are likely underestimated ($60K per inchmile all inclusive).Surcharge for corrosion resistant casing ($1.75 per ft-inch diameter) and tubing ($1.10 per ftinch diam) seems underestimated based on recent quotes obtained from this reviewer.Costs that are identified as“initial estimates” or “ICF estimates” should be assigned very highuncertainty/low confidence.Table 5. Area of Review/CorrectiveAction CostsThe amount of time allotted for fluid/reservoir modeling is too low to construct, calibrate andsimulate CO2 fate and transport.Labor rates of $53.52 per hourare unrealistically low.Well remediation costs appear to be low – seeTCEQ cost spreadsheet for estimating costs forplugging/abandoning wells.Costs that are identified as“initial estimates” or “ICF estimates” should be assigned very highuncertainty/low confidence.Table 6. Well Operation Unit CostsIt isn’t clear how/why this is distinguished from Mechanical Integrity Testing.Costs that are identified as“initial estimates” or “ICF estimates” should be assigned very highuncertainty/low confidence.This material is a product of the FutureGen Industrial AllianceDocket ID No. EPA-HQ-OW-2008-0390This material is a product of the FutureGen Industrial AllianceCost Analysis Technical Support DocumentTable 7. Mechanical Integrity TestsUnit CostsBased on recent quotations obtained by this reviewerfor these types of tests, the costs listedhere are too low. In addition, there will be ancillary costs associated with conducting these testssuch as the cost of a service rig.Costs that are identified as“initial estimates” or “ICF estimates” should be assigned very highuncertainty/low confidence.Table 8. Post Injection WellPlugging etcCost for flushing wells is estimated at $500; thiswill not cover all thematerials and servicesrequired to accomplish this. Costs that are identified as “initial estimates” or “ICF estimates”should be assigned very high uncertainty/low confidence.Well plugging/abandoning costs appear to be low– see TCEQ cost spreadsheet for estimatingcosts for plugging/abandoning wells.Letter ID: 0167

Commenter: Michael Mudd Organization: FutureGen Alliance (FGIA)

Letter ID: 0167 Comment ID: 22456 Letter Lines: 67 to 75

Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment)

Comment Code: 2066 1.5.3.3 Grandfathering construction of Class V wells (seeking comment)

Comment: Impact on Class II and Class V Wells p.43502, c. 1

The Proposed Rule for Class VI wells shoul d have no impact on existing or future Class II or Class V wells, which should be stated in the Proposed Rule in clear, unambiguous, and strong language. Furthermor e, the Proposed Rule allows for the construction of existing Class II and Cla ss V wells to be grandfathered, but there is no provision to allow the gra ndfathering of the ex isting siting, area of review, operations, or monitoring plan. These areas should be grandfathered,

too.

Individual Response: EPA agrees that many Class II a nd Class V experimental technology wells are designed and constructed to withstand exposure to CO2. The final GS rule provides for the construction of these wells to be grandf athered per §146.81(c), pr ovided the owner or operator can demonstrate to the Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and ensure prot ection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR requirements) should also be grandfathered. Fo llowing re-permitting of the well as Class VI, many of the unique factors of GS sites (e.g., increa sed reservoir pressures associated with large volumes of stored CO2 and the corrosivity of CO 2 in the presence of water) will result in an increased risk profile, warranting the specific requirements in the final GS rule. Therefore, following re-permitting as Class VI wells, these proj ects must be subject to the operational, MIT, monitoring, reporting, plugging, and post- injection site care and site closure requirements in the

final GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Letter ID: 0167 Comment ID: 22457 Letter Lines: 77 to 160

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones (seeking comment)

Comment: Multiple Confining Layers Could be Required at the Direction of the

Director

p. 53536, c. 3 The Proposed Rules for Class VI wells identified by EPA include a

1requirement for a confining zone with suitable properties to contain the injected CO2 (§ 146.83(a). In addition, under subsection (b) of the proposed regulation, owners or operators may be re quired to identify and characterize multiple confining layers, at the disc retion of the Director (§ 146.83(b)).

Comment:

- Subsection (b) of § 146.83 of the propos ed regulations, which grants the Director discretion to requi re the presence of multiple confining layers, does not promote sound policy and should be re moved from the proposed regulation.

- If EPA chooses to retain the option de scribed in subsection (b), then the

discretion of the Director should be lim ited, and there should be specification of the types of conditions under which multiple confining layers might be required.

This optional requirement may eliminate su itable GS sites wit hout reducing risk. It also adds a potential risk to a pr oposed project because the likelihood and cost of this additional requirement wi ll not be known during the project initiation phase.

The rationale for inclusion of an optional requirement for multiple confining layers is not provided. There does not appe ar to be any clear need for that additional requirement, which goes beyond what is currently required for Class I UIC wells that inject hazardous wastes. The proposed regulati on could lead to significant problems in the future, but mo re importantly, this requirement is not needed. If subsection (b) of § 146.83 we re removed, and if the Director or his staff find that the confining syst em identified by an operator does not appear to be reliable, they can reject the application and/or require that the operator provide information on additional confining layers. The description of the requirements for a confining system given in part (2) of subsection (a) would cover this situation, and would allo w protection of USDW’s and the public without creating the potential for confusi on that would arise with the option outlined in subsection (b).

Previous experience and research have demonstrated that a single wellcharacterized confining system can provi de more than adequate protection by preventing the upward migration of CO2. Fo r example, time-lapse seismic imaging at the Sleipner Project demonstrates "the caprock is an effective seal that prevents CO2 migration out of the stor age formation" (IPCC 2005). Examination of recent surveys of the safety of underground CO2 sequestration found no suggestion that multiple confining systems are needed or should be required (e.g., IPCC 2005; Benson and Surles 2006). In addition, the technical support document provided by EPA for the proposed ru le changes (Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide, EPA430-R-08-009) does not provide any support for requirement of multiple confining layers.

2The proposed regulations do not specify or in any way limit the conditions under which multiple confining layers might be required. Thus, there is no guidance for imposition of the rule, and no limitations on the discretion of the Director. Including this additional discre tionary requirement as an option in the regulations is troublesome because th ere then is a good po ssibility that it could become the default requirement. If th at were the case, the requirement of multiple confining layers would lead to potential disqualification of excellent storage sites, and additional costs for characterization.

An additional problem with the optional requ irement of multiple confining layers is one of perception. We know of no preced ent within current UIC regulations, other applicable U.S. environmental law, or internationally, for the requirement of multiple confining layers to contain injected fluids. Given the lack of precedent, the inclusion of the requirement for multiple confining layers for CO2 in the proposed regulations for Class VI wells could lead to the incorrect perception by the public that in jection and storage of CO2 is more dangerous to the public than subsurface injection of hazardous wastes. This perception of high risk, which does not a ppear to be justified by previous studies of the risks of subsurface CO2 sequestration (e.g., IPCC 2005; Benson and Surles 2006) could lead to decrea sed use of carbon sequestration as an option to limit global climate change, and therefore to decreased potential for full use of U.S. energy resources.

References:

Benson SM and T Surles. 2006. Carbon Dioxide Capture and Storage: An Overview with Emphasis on Capture and Storage in Deep Geological Formations, The Proceedings Special Issue, Institute of Electrical and Electronics Engineers (IEEE), Vol. 94, No 10, October 2006, DOI 10.1109/PROC.2006.883716.

IPCC. 2005. IPCC Special Report: Carbon Dioxi de Capture and Stor age. Summary for Policy Makers and Technical Summary, B. Metz, O. Davidson, H. de Coninck, M. Loos, and L. Meyer (eds.). Cambridge University Press, New York.

Individual Response: EPA retains the requirement to iden tify additional containment/confining zones, if required by the Di rector, as proposed (§146.83(b)). EPA acknowledges that such additional zones may not be needed in all circumst ances, and clarifies that this requirement is at the Director's discretion, based on his or her understanding of a part icular site. EPA believes that, in some situations, the presence of additional confining and containment zones above the primary (i.e., lowermost) confining zone can improve USDW protecti on. These layers could further impede vertical fluid movement and al low for pressure dissipation, and also provide additional sites for monitoring, mitigation, and re mediation. The Agency's decision is supported by commenters representing states, water associati ons, and an electric utility who assert that these requirements promote a flexible, risk-base d, site-specific approach to characterizing and permitting a site for GS projects, and are intende d to improve understanding of the project as a

3whole and promote better modeling of the site.

EPA is developing guidance on site characterization for GS projects to assist owners or operators and Directors in evaluating permit requirements and applications under §146.82. The guidance provides recommendations regard ing characterizing the region al geology and hydrogeology of a proposed GS site as well as performing th e necessary geochemical, geomechanical, and geophysical analyses of the injection and confin ing zone. EPA expects that this guidance will assist permit writers in making an objective deci sion about requiring additional confining layers. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0167 Comment ID: 22458 Letter Lines: 162 to 282

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

Comment: Area of Review (AoR) and Area of Monitoring (AoM)

p. 43493, c. 2 The Proposed Rule defines Area of Review (AoR) as "The region surrounding the geologic sequestration pr oject that may be impacted by the injection activity". The area of review is based on computational modeling that accounts for the physical and chemical prope rties of all phases of the injected

carbon dioxide stream.

The proposed regulation uses the Area of Review (AoR) for defining both monitoring requirements and corrective actions:

p. 43499, c. 1 Area of Review (AoR) and Co rrective Action: The Agency requires

examination of both the vertical and horiz ontal extent of the area that will potentially be influenced by injection a nd storage activities and identification of all artificial pene trations in the area that ma y act as conduits for fluid movement into USDWs (e.g., active and aba ndoned wells) and, as needed, perform corrective action to these open wells (i.e., artificial penetrations).

p. 43539, c. 3 (d)(2) The monitoring freque ncy and spatial distribution of monitoring wells must be based on baseli ne geochemical data that has been collected under §146.82(a)(6) a nd any modeling results in the area of review evaluation required by §146.84(b);

Comment:

- EPA should define two regulatory regions surrounding the geologic sequestration project and provide specifi c definitions for those regions; 1) Area of Monitoring (AoM) and 2) Area of Revi ew; where the AoM is used to define the spatial distribution of monitoring wells and the AoR is used to define the

4limit of Corrective Action:

- Area of Monitoring (AoM): The region surrounding the geologic sequestration project that contains 95% of the carbon di oxide mass. The area of monitoring is based on monitoring data and computa tional modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. In the absence of monitoring data , the area of monitoring is based on computational modeling.

- Area of Review (AoR): The region su rrounding the geologic sequestration

reservoir that has or is indicated to de velop pressures that are greater than 10% different from the pre-injection form ation fluid pressure, but no less than the Area of Monitoring. The area of revi ew is based on monitoring data and computational modeling that accounts for th e physical and chemi cal properties of all phases of the in jected carbon dioxide stream. In the absence of monitoring data, the area of review is based on computational modeling.

• The proposed definitions of AoM and Ao R have several important components:

- The AoM has a mass-based definition.

- The AoR has a pressure-di fferential-based definition.

- The AoR is never smaller than the AoM.

- The AoR and AoM may be asymmetri cal around the injection well(s).

- The AoR and AoM may vary over time.

- The carbon dioxide mass should be determin ed using a combination of monitoring data and computa tional modeling.

- Pressure differentials are based on equilibrium hydrostatic conditions.

Relative to existing UIC regulations governing waste disposal, EPA is introducing fundamentally new concepts for defining the area of review (AoR) for CO2 injection. The newly proposed con cept is flawed and will pose an unjustifiable barrier to CO2 injection proj ects unless the approach for defining the AoR is addressed in the regulation. It is neither possible, nor practical, to predict where every molecule of CO2 will migrate; therefore, a threshold levels are required. In the case of large-scale injection projects, changes in formation pressures could be expected dozens to hundreds of miles from the injection well. It would not be practical for the AoR to comprise the entire area experiencing changes in formation pressure. A reasonable threshold for establishing the AoM might be where pressure changes are greater than 10% of the standard formation pressure.

5The proposed regulation defines the Area of Review (AoR) as being the region that may be impacted by the injection activity, without defining or quantifying impact. To be useful the bounding areas for corrective actions and monitoring activities must have specific definiti ons. Under deep geologic sequestration conditions the injected fluid (i.e., supe rcritical CO2) has low compressibility, the displaced fluid (i.e., brine) has lo w compressibility, a nd the reservoir formation (e.g., sandstone) generally has low compressibility, all of which suggest that the impact (i.e., pressure change) of the injec tion activity could be detected at great distances from the injection well(s).

Injection of CO2 into deep saline forma tions is driven by differences between the well injection pressure and formation pressure. To avoid inducing fractures or opening existing fractures in the fo rmation and caprock, well injection pressure will be limited to some fract ion below the fracturing pressure. As CO2 migrates into the formation the fo rmation pressure increases around the injection well. The pressure distribution in the formation ar ound the injection well depends on the formation properties, structure, and injection rate. Injection formations will be required to be confined ve rtically and/or horizontally to prevent the vertical migration of inj ected fluids and saline

reservoir fluids into USDWs.

Confined formations (e.g., a caprock overlying a horizontally extensive formation) allow the formation fluid to be displaced laterally by the injected fluid. Injecting CO2 will result in elevated pressures both inside and beyond the CO2 plume. Elevated pressures within the CO2 plume have the potential to force CO2 and formation fluid through permeab le wells, fractures, or faults that penetrate the formation. Elevated pre ssures outside the CO2 plume have the potential to force formation fluid through permeable wells, fractures or faults that penetrate the formation. The higher the formation pressure is above the ambient formation pressure, the greate r the potential for CO2 and formation fluid to leak through permeable wells, fractures, and faults. The lateral pressure distribution is a function of the injection rate and the lateral distribution of formation permeability. When CO2 injection is halted, elevated pressures decay over time as th e injected and formation fluids migrate away from the injection well(s).

The proposed regulations define an AoR and Corrective Action as being an area within which artificial pene trations may act as conduits for fluid movement into USDWs (e.g., active and abandoned wells) and, as needed, require the applicant to perform corrective action to seal th ese open wells. The potential for fluid movement into USDWs from the injection of CO2 into the injection formation is

correlated with the area of elevated form ation pressure, which is usually larger than the area that contains the injected CO2 mass. For confined formations, this area is defined by the lateral pressu re distribution around the injection well(s).

6Individual Response: EPA believes that, while the commente r offers different terminology for the AoR and the area to be monitored, the GS rule addresses the commenter's suggestions. Notably, the owner or operator is required ( under 146.90) to develop and implement a testing and monitoring plan for each GS project that mu st consider the delineated AoR that includes both the CO2 plume and associated pressure front and incorporates many of the attributes suggested by the commenter. EPA clarifies that delineation of the AoR, as required at 146.84(c), must account for the physical and chemical properties of all phase s of the injected CO2 stream,

based on available site characteriza tion, monitoring, and operational data.

Furthermore, any changes to the AoR would necess itate a review of and po tential change in the testing and monitoring plan, consistent with the commenter's a ssertion that the AoR may vary over time. The final GS regulation includes a requirement at 146.84(e) that the AoR be reevaluated at least every 5 years, and also requ ires that the owner or operator review the AoR and corrective action, testing and monitoring, and emergency and remedial response plans within one year of an AoR reevaluation (as well as follo wing significant changes to the facility, or when required by the Director). The relationship betw een the AoR reevaluation and the testing and monitoring plan should allow for consider ations suggested by the commenter.

EPA believes that by linking develo pment and review of the testi ng and monitoring plan to the AoR evaluation and reevaluation process, the GS ru le, in effect, incorporates and addresses many

of the commenter's considerati ons for an area of monitoring.

Letter ID: 0167 Comment ID: 22459 Letter Lines: 284 to 442

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Stratigraphic Restriction of Saline and Other Reservoirs to Below Lowermost

USDW

The Proposed Regulation for saline formations state:

p. 43494, c. 2 Saline formations: Deep and geographically extensive sedimentary rock layers saturated with waters or br ines that have a high total dissolved solids (TDS) content (i.e., >10,000 mg/L TDS).

Proposed Geologic Siting Requirements: p.43505, c. 1 Existing UIC requirements for siting injection wells include iden tification of geologic formations suitable to receive the injected fluids and confine them such that they are isolated below the lowermost USDWs, mini mizing the potential for endangerment.

Target geologic formations: p.43502-43503, sec tion H As with unmineable coal seams, EPA seeks comment on prohibiting inje ction into such formations [basalts, salt domes, and shales] if they are above the lowermost USDW.

7The EPA is soliciting comments on these issues:

1.Whether CO2 injection should be allowe d into an injection zone (saline sedimentary formations, unmi nable coal seam, basalt, salt caverns, shales, or other reservoirs) above the lowermost USDW , when the Director determines that geologic conditions exist that will prevent fluid movement into adjacent USDWs.

2.Whether a designated USDW should be exempted to a llow for GS, and under what conditions should these exemptions be approved.

3.Whether all USDWs should be exempted below a CO2 injection receiving bed.

4.Whether the EPA should set a minimum injection depth requirement for GS, rather than require that such injectio n take place below the lowermost USDW.

Comments:

GS should be permitted in the following:

1)reservoirs containi ng >10,000 mg/L TDS,

2) where the formation water is

reasons, or

3)formations exempted as USDWs by the state.

GS should not be restricted to stratigr aphic zones below the lowermost USDW.

- Prohibition of CO2 injection into salin e formations above USDWs is overly

restrictive and would severe ly limit GS in states such as Wyoming, where deep sedimentary formations in much of th e state have TDS lower than 10,000mg/l (NETL). Thus almost any formation considered for GS would likely overlie a low

TDS formation.

- GS should be allowed into an injection zone above the lowermost USDW (whether saline or other formation) when the Direct or determines that geologic conditions exist that will prevent fluid movement into nearby USDWs. Cond itions that will prevent downward movement of fluids include the presence of intact low permeability beds between the receivi ng bed and the underlying USDW. In consideration of the buoyant behavior of injected CO2, the requirement of thousands of feet of intervening forma tions may be less important than the demonstration of the sealing capacity of th e intervening layers. We believe that "thousands of feet" is a vague requirement, when the more rigorous test is the demonstration of the sealing capac ity of the intervening layers.

8- The draft rule is far too restrictiv e and is not based on technical risk

factors. Risk of CO2 contamination to a USDW is lower for aquifers that underlie an injection reservoir due to the inherent buoyancy of the CO2. Vertical migration can be interrupted comp letely by the presence of one or more low permeability layers. Hence, a prohibi tion on injecting above the shallowest

USDW is not based on real techni cal risk of a GS project.

- The conditions for exemptions of aqui fers should be clarified. Aquifer exemptions should be allowed for GS ("a r eceiving bed for Class VI wells") when

it can be demonstrated that there is no reasonable expectation that the formation will be considered for a drinking water source, and when it can be demonstrated that CO2 is highly unlikely to migrate updip into a portion of the formation that may be considered for use as a USDW.

- Blanket aquifer exemption of all USDWs be low a GS zone is not needed if there is demon-stration of a competent seal be tween the injection zone and the first underlying USDW.

- No blanket prohibition should be in troduced for any potential non-saline reservoir; promising GS targets of basalt, unmineable coal seams, etc., should be evaluated with methodologies simila r to those for saline formations.

- GS is better served by neither mandati ng a set minimum depth for injection nor by requiring injection take place below the lowermost USDW. Minimum depth requirements would be unnecessarily proscr iptive. Shallow injections could be done for very small commercial producers or in cases where reservoir engineering practices (such as pre-dissol ution of the CO2 into formation water) are done so that no free CO2 phase exists.

Three of the most important issues here are (a) the physical location of saline formations or other types of geologic reservoirs for GS, relative to USDWs; (b) under what circumstances the EPA should remove one or more water-bearing zones from the list of USDWs to allow injectio n; and (c) under what other conditions should the EPA allow injection above a USDW.

In addition to injection into saline fo rmations, EPA recognizes that basalt, unmineable coal seams, salt domes, abandone d mines, black shales and other types of reservoirs may be promising, emerging ta rgets. Basalts, in particular appear to have considerable potential for GS. Re search by PNNL and others indicates that extruded basalt flow tops and flow bases may have regional, multi-gigaton capacity for CO2 storage. In addition, laboratory experiment s suggest that mineralization of large volumes of CO2 may proceed within a few years of injection (McGrail et al, 2006).

In the proposed rule, the new Class VI wells would be allowed to inject CO2 into basalts, deep saline reservoirs, and othe r potential reservoirs only when they

9are beneath the lowermost USDW.

A USDW is defined by the EPA as "An a quifer or portion of an aquifer that supplies any public water system or that contains a sufficient quantity of ground water to supply a public water sys- tem, and currently supplies drinking water for human consumption, or that contains fewer than 10,000 mg/l total dissolved solids and is not an exempted aquifer." This defini tion would include many non-potable aquifers that would be candidates for GS.

The EPA’s reliance on the standard defi nition of a USDW as being solely mg/L TDS is far too restrictive. In many states, this standard is not applied - all groundwaters are protected regardless of water quality. In at least one state GS operations would be permitted if removing anthropogenic CO2 is considered a greater public benefit than the loss of a marginal aquifer.

The EPA is aware that restricting GS to a position below all EPA defined USDWs would severely limit GS in many areas . Under the current proposed rule, directors may grant injection into deep, marginal USDWs that directly overlie crystalline basement rock and/or unmineab le coal seams. In addition to these exceptions, the EPA would consider a llowing operation of GS wells where receiving formations are above the lowerm ost USDW only where there are thousands of feet between the injection zone and the overlying and underlying USDWs.

As currently defined by the EPA, "aquife r exemptions" permanently remove a specified aquifer from protection as a US DW. Aquifer exemptions are currently granted for mineral or hydrocarbon expl oration by Class III solution mining wells, or by Class II oil a nd gas related wells, when there is no reasonable expectation that the formation will be us ed as a drinking water supply. It is important to note that the EPA has not previously considered the purpose of creating additional capacity for the emplacement of fluids as sufficient cause for granting an exemption. Under the ne w rule, it would be possible for operators to apply to cha nge the designation of some aquifers being used for Class II injection. These aquifers would n eed a new, separate exemption for GS.

The EPA suggests the following possible alte rnatives that would allow injection

between USDWs or above the lowest USDW:

1.Injection approval for GS between USDWs formations is at the Director’s

discretion in circumstances in which it ma y be demonstrated that USDWs would not be endangered.

2.Directors may be allowed to exempt, at their discretion, all USDWs below a GS injection zone. (This would permanently rem ove these aquifers from protection as USDWs).

References McGrail, B. P., H. T. Schaef, A. M. Ho, Y. Chien, J. J. Dooley, and

10C. L. Davidson. 2006. Potential for Carbon Dioxide Sequestration in Flood Basalts, J. Geophys. Res. 111, B12201.

NETL. 2007. National Carbon Sequestration Atlas. http://www.netl.doe.gov/technologies/car bon_seq/refshelf/a tlas/index.html

Individual Response: EPA acknowledges that there are lim ited circumstances where injection above the lowermost USDW can be performe d in a manner that protects USDWs from endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which owne rs or operators can seek a waiv er of the Class VI injection depth requirements for injecti on into non-USDW formations above and/or between USDWs. The

final rule also establishes limited circumstances under which expansions of the areal extent of aquifer exemptions may be granted for owne rs or operators of Class II EOR/EGR wells transitioning to Class VI injection for GS. The final rule allows for the expansion of the areal extent of existing aquifer exemptions for Cl ass II EOR/EGR wells tran sitioning to Class VI injection for GS pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for Class VI wells in the final GS rule. Additionally, the final GS rule does not categorically prec lude or prohibit injection in to any type of formation.

EPA agrees that it is not appropr iate to set a minimum injection depth for GS projects and the Agency believes that a determination of site-su itability for GS (i.e., th at subsurface formations will receive and confine injected CO2) should be made on a site-specific basis. The GS rule, at §146.82, requires the owner or operator to prov ide extensive site- and project-specific

information to the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, a nd that USDWs will be protected from endangerment.

EPA believes that these requirements will ensure USDW protection while providing flexibility to UIC program Directors and owne rs or operators who undertak e CO2 injection for GS. The Agency believes this approach: 1) responds to co ncerns about local and re gional geologic storage capacity limitations imposed by th e proposed injection depth require ments; 2) allows for a more site-specific assessment of injection depth for GS projects; 3) accommodates injection into different formation types; 4) a llows for injection of CO2 for GS into non-USDWs above and/or between USDWs when appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to concerns about the use of aqui fer exemptions for GS. Finally, EPA’s approach to addressing injection depth va riability through a waiver process responds to concerns about future drinking wa ter resource availability and the need to ensure that high quality water remains available in sufficient quantities to supply dr inking water needs.

For additional information on the waiver approa ch and aquifer exemptions for Class VI wells, please see the final rule and pr eamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0167 Comment ID: 22460 Letter Lines: 415 to 424

11Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain

circumstances

Comment: As currently defined by the EPA, "aquife r exemptions" permanently remove a specified aquifer from protection as a US DW. Aquifer exemptions are currently granted for mineral or hydrocarbon expl oration by Class III solution mining wells, or by Class II oil a nd gas related wells, when there is no reasonable expectation that the formation will be us ed as a drinking water supply. It is important to note that the EPA has not previously considered the purpose of creating additional capacity for the emplacement of fluids as sufficient cause for granting an exemption. Under the ne w rule, it would be possible for operators to apply to cha nge the designation of some aquifers being used for Class II injection. These aquifers would n eed a new, separate exemption for GS.

Individual Response: The final rule allows for the expans ion of the areal extent of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for GS wells in the final GS rule. However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that is, aquifer exemptions will only be granted for projects that are transitioni ng from Class II EOR/EGR wells to Class VI.

This approach is designed to ensure that th e differences between traditional Class II EOR/EGR operations and Class VI operati ons are considered during the aquifer exemption application process and the Class VI permitting process. Thes e differences include the anticipated large CO2 injection volumes associated with GS, the buoyant and mobile nature of the injectate, and its corrosivity in the presence of water. The Agen cy believes that this process will encourage owners or operators and Directors to consider the use of alterna tive formations for GS, including non-USDW formations through the waiver process, prior to applying for or approving aquifer exemption expansions for Class II EOR/EGR we lls transitioning to Cl ass VI GS operations.

EPA clarifies that all decisions regarding whethe r expansion of existing aquifer exemptions will

be at the Director's discretion and based on site -specific information. If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above and/or between USDWs, the perm it applicant must also apply for a waiver of the injection depth requirements pursuant to §146 .95 to ensure that if a waiver is granted, USDWs above and below the injection z one are protected from endangerment.

For additional information on aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's responses to comments on the Notice of Da ta Availability and Request for Comment.

Letter ID: 0167 Comment ID: 22461 Letter Lines: 444 to 524

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment)

12Comment: Proposed Mechanical Integr ity Testing Requirement

Proposed Regulation

p. 43513, c. 3 "require owners and operators of Class VI GS project to monitor internal mechanical integrity of th eir injection wells by continuously monitoring injection pressure, flow rate, and injected volumes"

p. 43514, c. 1 -require owners and operat ors of CO2 wells to demonstrate injection well external mechanical integrity at least once annually.

The EPA seeks comment on the appropriate freq uency of internal and external MITs for GS injection wells.

Comments:

- We recommend that an external MIT be performed on a recurre nce interval of every 5 years, as is now typically done for other classes of UIC wells. The external MIT should rely primarily on re sults obtained from geophysical wireline logging surveys, and (if warranted by wireline geophysical survey results), conducting direct leakage-detection tests of suspected areas of concern. If the external MIT indicates the potential for a compromise to the cement seal characteristics or well casing integrity, then additional, more quantitative tests (e.g. Gasda et al. 2008) and subs equent corrective actions may be

warranted.

- The recommended external MIT recurrence assessment of every 5 years is predicated on no indications of injecti on system compromise that would be observed by changes in monitored internal MIT parameters during injection (e.g., injection or annular zone pressure), or pressure fall-off test response following normal, temporary operational sh ut-down periods. If at any time the monitoring parameters or pressure data responses indicate an omalous injection test system behavior, then this could indicate the need for an external MIT evaluation to be performed, at the discretion of the Director.

During the injection period the proposed rule states that internal MIT should be performed continuously by monitoring pr essures (e.g., injection and annular zones), injection rates and volumes, etc., and external MIT should be performed annually. Continuous monitoring of injection rates, volumes , and pressures during the injection phase seems reasona ble and appropriate. The semi-annual reporting frequency of such resu lts also seems reasonable.

The proposed rule also states that extern al MIT be performed annually during the injection phase. The rationale for this is to protect USDWs given the potential corrosive effects on injection well com ponents (steel casing and cement) that are exposed to the GS stream and the buoyant nature of the injected fluid.

13To execute an annual external MIT, the injection well would be required to be shut down (i.e., cease CO2 injection operati on) and the internal CO2 injection delivery tubing system to be physically removed from the injection well. At a minimum, this would require that all GS projects, no matter how large, to have a backup injection well or multiple injection wells to be available so as to not adversely impact or interrupt daily plant operations.

In general, we believe that annual extern al MIT evaluations w ould be excessive and overly disruptive for normal plant opera tions. This is because quantitative

external MIT evaluationtests would require:

- Removal of the surface wellhead and internal CO2 injection delivery tubing

system

- Performing detailed wireline geophysic al surveys for cement-seal and well casing integrity (e.g., ce ment-bond log), and

- If warranted by the results of the wi reline geophysical surveys, conduct¬ing direct leakage-detection tests with in stalled internal te st equipment (e.g., downhole internal straddle-packer system) of suspect ed areas of concern

The performance of the various aforementi oned elements of an external MIT and re-installation of components of the inj ection well system are likely to take between 2 to 5 days, depending on the ch aracteristics of the injection well (e.g., injection reservoir depth), complexity of the internal CO2 injection well system, and whether quantitative leakage detection tests are warranted. Because of extended time required to conduct an exte rnal MIT program, the performance of fixed-annual external MIT evaluations ( outside the schedule of planned plant operation maintenance shut-downs) are belie ved to be excessively disruptive.

Reference Gasda, S. E., J. M. Nordbo tten, and M. A. Celia. 2008. Determining effective wellbore permeability from a fiel d pressure test: a nu merical analysis of detection limits. Environmental Geology, 54(6), 1207-1215,

doi:10.1007/s00254-007-0903-7.

Individual Response: EPA disagrees that a five-year extern al MIT is appropriate. The final GS regulation retains the requirement that owners or operators of Class VI wells must demonstrate injection well external mech anical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the protecti on of USDWs from endangerment given the unique nature of CO2 GS relative to other injection operations, including the pote ntial corrosive impact of CO2 in the presence of water and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase ch anges, the temperature and pressure effects associated with injecting supercritical CO2, and the buoyant nature of th e injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more cons ervative initial approach in the early stages of deployment for GS.

14In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT failure and, for this reason, EPA be lieves that the tailored MIT requi rements in the final GS rule are appropriate. Regarding concer ns about disruptions of plan t operations, EPA believes that, due to the expected size of GS fields, many GS operations will have more than one injection well, and that testing of each we ll can be timed to avoid complete interruption of the project.

EPA believes that the external MI Ts described in 146.89(c) of the ru le (an approved tracer log or temperature or noise logs) are effective methods to demonstr ate external MI, provide an important early warning of pot ential problems in the injectio n well system, and represent standard techniques that have been used succes sfully by the drilling industry and for the UIC Program for decades. EPA clarifies that the re gulations provides the Director discretion to require additional methods or, with the Administrator's approval, to approve the use of alternative MIT methods based on specific informa tion about the site or the well. See §146.89(e).

EPA acknowledges the commenter’s support of con tinuous monitoring to demonstrate internal MI; the final rule retains th is requirement at §146.89(b).

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0167 Comment ID: 22462 Letter Lines: 526 to 553

Comment Code: 2160 1.6.3 Unmineable coal seams

Comment: Unmineable Coal Seams p. 43503, c.2)

While coal seams are well studied and unde rstood, the process of CO2 adsorption to coal has not been proven and the chem ical reaction of supercritical CO2 with

coal formations are not well understood.

Comment: This statement is contentious a nd does not add to the substance of the Propose Rule. In fact, the process of CO2 absorption is well understood. Suggest removing the statement.

In addition, many ECBM recovery operations will likely be shallow. Shallow storage will result in the CO2 remaining in a gaseous state, which can limit the amount of CO2 that can be sequestered.

Comment: These statements are not true. The statements would be true for

15storage into shallow aquifer pore space, such as in shallow saline formations, but it is not the case for storage into sh allow coal seams. In shallow coal

seams CO2 is absorbed and remains in the condensed phase and not in the gaseous state. Suggest removing the statement.

EPA is concerned that coal seams in the close proximity to USDWs and CO2 injection for GS could endanger USDWs. In some cases, coal seams are considered USDWs and may serve as public drinking wa ter supplies. As a result, EPA is proposing to preclude the inje ction of CO2 for long-term storage into coal seams where they are above the lowermost USDW.

Comment: See comments above under the headi ng Stratigraphic Restriction of GS to

Below Lowermost USDW.

Individual Response: EPA acknowledges that site-suitability for GS is dependent on a number of factors and that many formation types may be suitable for GS. EPA agrees that GS into

unmineable coal seams has the potential to allow sequestration while ensuring USDW protection from endangerment, as described by commenter s citing the process of enhanced methane recovery. The final GS rule doe s not preclude injection into un mineable coal seams provided owners or operators can demonstr ate that GS can be performed in a manner that protects USDWs from endangerment. The Agency clarifies that ow ners or operators of Class VI wells used for injecting CO2 into unmineable coal seams are s ubject to the same site characterization, well construction, operation, monitoring, pos t-injection site care and site closure requirements that are required of projects injecting into other formation types.

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the lowermost USDW; however, owners or operators may apply for a waiver from this requirement, as described in §146.95. For more information, see the discussion of waivers in the preamble to

the final rule.

Letter ID: 0167 Comment ID: 22463 Letter Lines: 555 to 574

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment)

Comment: Post-Injection Monitoring Period p. 43540-43541

The owner or operator shall continue to conduct monitori ng as specified in the Director-approved post-inject ion site care and site clos ure plan for at least 50 years following the cessation of inject ion.If the owner or operator can

demonstrate to the satisfaction of the Director before 50 years, based on monitoring and other site-specific data, th at the geologic sequ estration project no longer poses an endangerment to USDWs.

Comment: The basis for the 50 year mini mum period is not clear. The minimum period should be tied to both risk and project specific information. Although

16there is the possibility that post-inje ction monitoring period can be reduced given sufficient data, this approach adds significant uncerta inty to both the project schedule and cost. It appears unlike that an owne r or operator will be able to know with certainty during the planning stage for GS what the postinjection monitoring period will be. The end result is for owners and operators to assume the entire 50 year period, whic h will have an adverse effect on the cost, schedule and feasibility of the pr oject. A time period of 10 years seems more reasonable, but would need to be confirmed by risk and project specific

information.

Individual Response: EPA clarifies that it proposed a default post-injection site care timeframe of 50 years based on a review of research studi es, industry reports, and existing environmental programs. This analysis was included in an EPA- prepared background document that is available in the federal docket, titled "Computationa l Modeling of Underground Injection of Carbon

Dioxide for Determination of Area-of-Review a nd Potential Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes based on additional review of

research studies and evalua tion of public comments.

While numerous commenters suggested that EPA s horten the monitoring timeframe, none of the commenters provided sufficient da ta or other evidence to warra nt a change in the proposed timeframe. While the 10- or 30-year timeframe suggested by some of these commenters may be within the timeframe suggested in some studi es, EPA believes that the potential risks of endangering USDWs will likely not decline within these timeframes and available data, including data submitted by commenters, do not s upport a different default timeframe. However, EPA recognizes that alternative timeframes may be appropriate under limited, specific circumstances, which is why EPA is providing the Director discre tion to approve an alternative post-injection site care timeframe as long as the owner or operator can meet the requirements provided at §146.93(c). The GS rule offers owners or operators flexibili ty regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the PISC period based on site-specific data, pursuant to requirements at §146.93(b); or (2) affording

the Director discretion to allow a Class VI we ll owner or operator to demonstrate, based on substantial data during the permitting process, that an alternative PISC timeframe may be appropriate if it ensures non-e ndangerment of USDWs pursuan t to requirements at §146.93(c). EPA believes that a default post-injection site car e timeframe of 50 years, with flexibility to adjust the timeframe for a limited number of GS projects during the permitting process where

substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts. EPA believes that a 50 year pos t-injection site care timeframe represents a reasonable and protective monitoring period and available data, including data submitted by commenters, do not support a different default timeframe. Furthermor e, EPA believes that a 50-year default postinjection site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not

17exaggerate the risks associated with GS, is consistent with other environmental programs, and sufficiently protects USDWs from endangerment.

Letter ID: 0167 Comment ID: 22464 Letter Lines: 576 to 619

Comment Code: 1630 1.3.3 RCRA/hazardous waste i ssues (seeking comment)

Comment: Hazardous Waste Exclusion p. 43503, c. 3

Because the types of impurities and their concentrations in the CO2 stream are likely to vary by facility, coal com position, plant operating conditions, and pollution removal technologies, EPA cannot make a categorical determination as to whether injected CO2 is hazardous unde r RCRA. Owners or ope rators will need to characterize their CO2 stream as pa rt of their permit application to determine if the injectate is considered hazardous as defined in 40 CFR Part 261. If the injectate is considered hazardous under RCRA, then the more stringent UIC Class I requirements for in jection of hazardous waste apply. The design changes EPA is proposing are m eant to address the mobility and corrosivity caused by long term GS of CO2, and not the long term storage of

hazardous wastes.

By defining ‘‘carbon dioxide stream’’ to exclude hazardous wastes (146.81(d)), today’s rule, if finalized, assures that it would apply only to CO2 streams that

are not hazardous wastes as defined in 40 CFR Part 261. As a result, today’s proposed rule would preclude the injec tion of hazardous wastes in Class VI injection wells. EPA seeks comment on this approach and other considerations associated with the presence of impurities in the CO2 stream.

Comment: Relegating CO2 waste streams that designate as hazardous waste to the Class I hazardous waste program will prevent their inclusion in the proposed

Class VI well classification where standa rds, guidance, and expertise will tailored for the properties of the bulk solvent.

GS is being pursued to address the burden of CO2 release to the atmosphere from power plants. In burning fossil fuels for power, there is a considerable amount of other products of combustion a nd other components that are typically

scrubbed or otherwise removed from the o ff-gas stream to prev ent their release to the atmosphere. The clean up steps for removing these various gas and products of combustion from the CO2 waste stream ultimately impact the power plant’s net energy output, which adversel y affects the cost of electricity. Significantly increasing the cost of electricity will discourage GS.

If the objective of GS is to reduce an d/or reduce the release of CO2 to the atmosphere, the delta in energy cost may be made more palatable by combining other products of combustion with the CO 2 waste stream. Additional technical

18information is needed to understand the merits and risks of co-injection of contaminants. A Proposed Rule for GS ba sed on a high-purity CO2 stream prior to understanding the trade-offs of co-inj ection of contaminants seems shortsighted. The Proposed Rule should have pr ovisions and leeway for regulators and industry to balance cost, energy cons ervation, waste reduction, and waste management program while protecting USDWs and safety of the public.

Individual Response: The GS rule does not set generic purity standards for CO2 injectate streams (e.g., a percent CO2). Instead, the GS rule addresse s the quality and quantity of impurities by requiring owners or operators to submit information on the source of the CO2 and its physical and chemical propertie s. Specifically, the GS rule requi res the owner or operator to submit data about the site, including an analysis of the chemical and physi cal characteristics of the CO2 stream, as required at §146.82(a)(7)(iv), and informati on on the compatibility of the CO2 stream with fluids in the injection zone a nd minerals in both the in jection and the confining

zones and the materials used to construct the well, per §146.82(c)(3). This information can help the Director determine the potential for geoche mical reactions between the injectate (CO2) and the host geologic formations, which could result in the plugging of pore spaces or the dissolution

of formation minerals. EPA clarifies that Class VI wells cannot be used for the co-injection of RCRA hazardous wastes (i.e., hazardous wastes that are injected along with the CO2 stream).

EPA received many comments regarding the applicab ility of the RCRA regulations and statute to CO2 streams that are geologically sequestered under the final Cl ass VI UIC well requirements. As a result, EPA has decided to initiate a sepa rate proposed rulemaking specifically to examine the issue of RCRA applicability to CO2 stream s being geologically sequestered, including the possible option of a conditional exemption from the RCRA requirements for CO2 GS in Class VI wells. EPA will consider these comments as pa rt of its development of that proposal. The Agency will consider issues particular to RCRA in the context of that separate rulemaking, and recommends that the commenter read that propose d rule when it is published. The Agency notes

that commenters who wish to submit comments on the RCRA proposal will need to do so during the comment period for that rule. Finally, EPA also notes that the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any changes to the RCRA regulations.

Letter ID: 0167 Comment ID: 22465 Letter Lines: 621 to 625

Comment Code: 5600 2.11 Comments related to UIC Program primacy for Class VI wells

Comment: Primacy Question

If an injection site boarder more than one state, which state or region will have primacy over the UIC permit?

Individual Response: EPA clarifies that issuance and oversi ght of a GS permit, including any associated AoR boundary-related coordination, is the responsibility of the primacy (State, Tribal, or Territorial) or regional DI program in the state where the injection well is located.

19EPA is developing primacy implementation mate rials for states that describe recommended approaches to addressing trans-boundary issues that a state may need to address when permitting Class VI wells under the GS regulation. The materials will be available at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

Letter ID: 0167 Comment ID: 22466 Letter Lines: 633 to 639

Comment Code: 1630 1.3.3 RCRA/hazardous waste i ssues (seeking comment)

Comment: I. Is Injected CO2 considered a Hazar dous Waste Under RCRA? II-I. EPA should specify the information needed to charac terize the CO2 stream to determine if

meets the definition of "Hazardous" as defined in 40 CFR Part 261

If a CO2 stream is determined to be hazardous per RCRA, can the CO2 stream still be injected via wells that are co nstructed and operated per the Class I UIC regulations, or does this preclude in jection of the hazardous CO2 stream?

Individual Response: EPA clarifies that GS rule, at §146.81( d), prohibits the injection of CO2

streams that meet the definition of a hazardous waste under 40 CFR part 261. Therefore, owners or operators will need to charac terize their CO2 stream as part of their permit application to determine if the injectate is c onsidered hazardous as defined u nder RCRA. If the CO2 stream is determined to be a hazardous waste, injec tion may only occur in a Class I hazardous waste injection well under 40 CFR Part 146 Subpart G.

Letter ID: 0167 Comment ID: 22467 Letter Lines: 643 to 646

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

Comment: A-1. Proposed Geologic Siting Requirement s III-A-1. This section mentions several types of geologic/geochemical/geo mechanical information needed to assess a site’s viability. EPA should sp ecify the information required to support this analysis.

Individual Response: EPA is developing guidance on site ch aracterization for GS projects to assist owners or operators and Directors in evaluating permit requirements and applications under §146.82. The guidance provides recommendati ons to owners or operators regarding information to characterize the regional geol ogy and hydrogeology of a proposed GS site as well as performing the necessary geochemical, geom echanical, and geophysical analyses of the injection and confining zone. EPA is also de veloping a number of technical guidances and implementation materials to assist owners or op erators and Directors in the permitting process. These guidances will provide recommendations to perform many of the ac tivities necessary for applying for a permit, including developing all required plans a nd conducting site characterizations that meet the requirements of §146.82. The draft guidance material can be found on EPA’s website at http:/ /water.epa.gov/type/groundwater/ uic/wells_sequestration.cfm.

20Letter ID: 0167 Comment ID: 22468 Letter Lines: 648 to 654

Comment Code: 4000 2.4 Proposed Injection Well Operat ing Requirements (40 CFR 146.88)

Comment: A-4 Proposed Injection Well Operating Re quirements III-A-4 Class I wells are typically required to maintain an annula r-fluid pressure that is greater than the injection tubing pressure to preven t outward leakage from the injection tubing. Typically, these wells operate at pressures much lower than CO2 injection wells. This same requirement imposed on CO2 injection wells would require specialized high-pressure equipmen t to maintain the required pressure

differential on the annular fluid.

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the injection pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the annulus fluid will move into the tubing, rather than the injectate moving out of the tubing and potentially along the outside of the well. EPA belie ves this requirement is appropriate for Class VI wells given the potential high volumes and superc ritical nature of the CO2 injectate, potential geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical integrity loss.

Letter ID: 0167 Comment ID: 22469 Letter Lines: 656 to 662

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

Comment: The use of down-hole shut-off valves that would automatically shut-in the well is recommended as a possible safety device in CO2 injection wells. This reviewer recently contacted the vend or cited by EPA (Schlumberger) for information on safety valves for a CO2 injection well and was told that they

are not available in sizes that would be needed for most on-shore injection wells because these devices are primarily used in larger off-shore wells. The use of safety valves ne eds more consideration.

Individual Response: After evaluating the risks and benefi ts of down-hole shut-off systems and considering additional research, EPA will not re quire automatic down-hole shut-off devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, the final rule, at §146.88(e)(2 ), requires that owne rs or operators of

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's

discretion to mandate automatic down-hole shut -off devices in onshore situations that may warrant their use. The rule requ ires, at §146.88(e)(3), that owners or operators of offshore wells

within State territorial waters install automatic down-hole shut-off systems. EPA believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent subsurface

fluid movement and ensure protection of USDWs.

While EPA acknowledges that the likelihood of damage to onshore f acilities is lower than that for offshore facilities, down-hole shut-off valves are still commonly used in onshore facilities

21such as acid gas injection wells and high pressu re, high-temperature wells. However, the Agency believes that offshore Class VI wells present unique construction and operational conditions, including isolation from shorelin es and the need to construct we lls through the water column and the subsurface, which may delay response time in the event of well difficulties. While valve failure is a concern, EPA believes that technol ogy has advanced sufficiently to make valve failure a rare occurrence and to appropriately ha ndle such failure if it occurs. For example, wireline retrievable devices can allow repair or replacement of damaged devices without necessitating pulling the tubing.

EPA believes that, while the smaller valve sizes n eeded for onshore injection wells may not be as common, these devices have been installed in ot her similar projects and therefore should be available. Acid gas injection wells commonl y use down-hole shut-off valves (IEA Greenhouse Gas Research Program, 2003; Bachu and Gunter, 2003).

Letter ID: 0167 Comment ID: 22470 Letter Lines: 664 to 667

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment)

Comment: A-5 Mechanical Integrity Testing Require ments III-A-5 Automated down-hole shut valves sound problematic, especially if they are intended to respond to excursions in annular pressure and volume which are subject to temperature

fluctuations. See above comment.

Individual Response: As described above, EPA will not require automatic down-hole shut-off

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, the final rule , at §146.88(e)(2), requires that owners or operators of onshore Class VI wells install auto matic surface shut-off devices. The rule affords

Director's discretion to mandate automatic down-hole shut-off devi ces in onshore situations that may warrant their use. The rule requires, at §146. 88(e)(3), that owners or operators of offshore

wells within State territorial waters inst all automatic down-hole shut-off systems.

EPA believes that requiring the in stallation of automatic surfac e shut-off devices for onshore wells (and affording Director's discretion to requir e down-hole devices where necessary) and

automatic down-hole shut-off devices for offsho re wells in submerged lands within the jurisdiction of a State ensures that proper pre cautions are taken to prevent subsurface fluid movement and ensure pr otection of USDWs.

Letter ID: 0167 Comment ID: 22471 Letter Lines: 669 to 672

Comment Code: 4540 2.5.2 Proposed external MIT requirements

Comment: Regarding external MITs, it isn’t clea r whether the requirement involves testing while injection CO2 or anothe r fluid (e.g., water). Also, it isn’t

clear whether or not these methods work with CO2; therefore, new/alternate methods may be needed.

22Individual Response: EPA believes that the MITs describe d in §146.89(c) of the rule (e.g., an approved tracer log or temperat ure or noise logs) are effec tive methods for demonstrating external MI. They are currently used by owners or operators of Class I and Class II wells, including owners or operators injecting CO2. The Agency notes that the regulations do provide the Director the flexibility at §146.89(e) to approve the use of alternative MIT methods. They have been used successfully by injection well operators for decades and provide an important early warning of potential probl ems in the injection well syst em. For additional information, please see the discussion of MITs in the final rule preamble.

EPA is using an adaptive approach to regulati ng GS. The Agency plans to collect and review data every six years on GS projects to determ ine whether the appropria te amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0167 Comment ID: 22472 Letter Lines: 674 to 681

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

Comment: A-6 Proposed Plume and pressure Front Monitoring III-A-6 Page 102. Pressure gauges placed in the first formation overl ying the confining z one would not be useful for tracking the late ral migration of the CO2 plume or pressure front. Would EPA require monitori ng wells that penetrate th rough the confining zone and into the storage formation for this purpose?

Fiber optic pressure and temperature se nsors are likely to be prohibitively expensive.

Individual Response: EPA has revised this requirement in the final rule. Instead, the final GS regulation, at §146.90(g)(1), requires all GS project owners or opera tors to monitor for pressure changes in the injection zone. EPA believes that pressure monitoring in the injection zone is necessary to track the development and moveme nt of the pressure front and CO2 plume.

Pressure monitoring within the injection zone is necessary because any such monitoring above the confining zone would not de tect movement of the pressure front unless a breach of the confining zone occurs. EPA believes that monitori ng using wells in the inje ction zone (i.e., that penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow between the injection zone a nd USDWs or other layers above the confining zone. Such construction technologies exist and have been us ed in the oil and gas industry for years. EPA believes that the benefits of monitoring in the injection formation outweigh the manageable risk of those monitoring wells serving as conduits for fluid movement. EPA adds that owners or operators may consider performi ng additional pressure monitoring in wells that are above the confining zone (e.g., in the same wells used to perform ground water quality monitoring required at §146.90(d)) to provide additional verification that no pressure ch anges are occurr ing above the confining zone due to CO2 leakage. Monitoring al so identifies needed re medial actions, provides

23inputs for AoR reevaluation modeling, and ta rgets additional geochemical and surface monitoring needs. Knowledge of th e location of the CO2 plume and the associated pressure front will assure the public that GS projects are proceeding according to plan, provide sufficient information to the owner or operator and Director, or allow for appropriate actions to address any

indication that USDWs may be endangered.

EPA acknowledges that, at certain sites, there may be a need for additional or different monitoring schemes (which may include monitoring in the confining zone), and adds that it is important to balance the need for adequate monitoring that ensures USDW protection from endangerment against too many artificial penetra tions which could serve as conduits for fluid migration. EPA expects site-speci fic testing and monitoring plan s to describe the proposed monitoring regime, which must be approved by the Director.

EPA does not believe that prescrib ing specific technologies to be us ed in all cases for GS would be appropriate given the variabil ity in sites. Rather, EPA is de veloping guidance on testing and monitoring to assist owners or operators a nd Directors in evaluating requirements under §146.90, including proposed monitoring plans. The gui dance describes availa ble technologies and recommended approaches for implementing a testing and monitoring plan, including preoperational geophysical logging and testing of injection wells, MI Ts, injection well testing during operation, groundwater qualit y monitoring, tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices manual entitled "Monitoring, Verificat ion, and Accounting of CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this manual is included in

the docket for the for the final GS rule.

EPA acknowledges the commenters' concern abou t the cost of monitoring. However, EPA believes that monitoring is essential for protecti on of USDWs at GS site s. Although a significant cost in absolute terms, monito ring costs are expected to be a small fraction of site operating costs, according to EPA's cost analysis for the GS rulemaking (which is av ailable in the docket).

Letter ID: 0167 Comment ID: 22473 Letter Lines: 683 to 685

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment)

Comment: A-7 Record Keeping and Reporting Re quirements III-A-7 We support the requirement for 1) a monitoring and testing plan 2) an AoR and Correction Action Plan and 3) a Post-Injection Site Care and Site Closure plan.

Individual Response: EPA acknowledges the commenter’s s upport of the GS project plans. EPA believes that the requirement for the plans a ssociated with GS projects will promote an ongoing dialogue between the owner or operator and the Director to ensure that USDWs are

24protected from endangerment. EPA is developing guidance for owners or operators describing recommended approaches to prepare the project plans. The guidance will be available on EPA's web site, at http://water.epa.gov/type/g roundwater/uic/wells _sequestration.cfm.

EPA agrees that developing, implementing, and pe riodically reviewing th e required GS project plans is an important part of assu ring that a GS project is operati ng properly and is crucial for the early detection of potential endangerment to USDW s. EPA also believes th at periodic updates to the plans are appropriate. EPA clarifies that the final GS regulation includ es a requirement that the AoR be reevaluated at least every 5 years, and it specifies at §146.90(j) that the operator revise the testing and monitoring plan to inco rporate the results of the most recent AoR reevaluation and recent operational and monitoring data. EPA also agrees that the site-specific plans required for GS projects will maximize protection of USDWs from endangerment.

Letter ID: 0167 Comment ID: 22474 Letter Lines: 687 to 689

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment)

Comment: To comply with a requirement for electro nic record-keeping, new data storage tools will be required to deal with the diverse nature of information that will be generated during the c ourse of a CCS project.

Individual Response: EPA believes that electronic formatting is the most appropriate format for submitting Class VI project information to the Director, and based on comments received on the proposed rule, the majority of Class VI GS well owners or operators will have the capability to report electronically, and re quires this at §146.91(e).

EPA believes that it is prudent to provide assi stance by developing a centr al framework for the electronic system that will be used by States to gather and track owner or operator data. This will enable owners or operators to submit data without having to wait for a State to develop a system. It will also provide for standardized submissions across the country and enable States to focus State resources on reviewing and approving permit applications rath er than building or upgrading separate, independent databases for GS informa tion. EPA believes that electronic formatting is the most appropriate format for submitting Class VI project information to the Director, and that many GS well owners or operators will have the capability to report electronically.

EPA is developing guidance for states that describes the record keeping, reporting, and additional data management needs associated with GS activities and provides recommended guidelines on the types of data to be collected for tracking GS projects, reporting to EPA for compliance tracking, and transfer of data to EPA's GS data system. The recordkeeping and reporting guidance will be avai lable on EPA's web site, at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0167 Comment ID: 22475 Letter Lines: 691 to 710

Comment Code: 6100 3.1 Comments on the cost estimates

25Comment: Cost Analysis Technical Support Document

Table 2. Site Characterization Costs Th e allotment of labor hours seems unrealistically low (this comme nt applies to most cost tables). Some individual tasks are especially low (e.g., develop lis t of penetrations into injection zone = 12 hours).

In this table and others, labor rates app ear to be low - perhaps underestimated by a factor of 1.5 to 2 depending on task/activity.

It appears that some important site ch aracterization activities/tests have not been included - e.g., wireline logging, hydraulic testing, fluid sampling and analysis. These should be included.

3D seismic survey costs may be underestimated - recent quotes suggest ~$100 K per square mile. 2D seismic should be a llowed because 3D may be impracticable to implement in many/most areas.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncerta inty/low confidence.

Individual Response: EPA has considered each public comment on the assumed hours needed to perform each task and in few instances, such as hours required to perform reservoir simulation modeling, has made upward adjustments. Note that the cost algorithms apply to specific units of measure that need to be multiplied by one or more factors to produce the total hours or dollars required per site or per project. For example, the time needed to develop a list of penetrations into the injection zone using well history database s or maps is assumed to be 12 hours per square mile. A 25 square mile site would require 12 hours per square mile x 25 square miles per site = 300 hours per site. EPA assumes that four candidate sites must be evaluated to find a feasible saline aquifer site; therefore, th e total time per project is 300 hours per site x 4 sites per project = 1,200 hours per project for well searches. Moreover, this cost item is just for searching well histories in databases and maps. There is a separate cost item for physically looking for wells using air and ground magnetic surveys.

Using industry survey data from AAPG and SPE as presented in th e cost analysis, EPA increased the estimated labor rates significantly from the BLS estimates used in the cost analysis for the proposed rule. The updated loaded hourly labor ra tes in the final rule cost analysis are $107.23 and $110.62 in 2008 dollars for engineering geolog ists and engineers, respectively. These correspond approximately to annual salaries of $139,400 and $143,800 and represent increases from the proposed rule analysis.

EPA clarifies that costs for wi reline logging are included under the monitoring costs; these monitoring costs are estimated at $10,400 per monitoring well. Monitoring costs are assumed to include measurements of pressure, temperature, a nd resistivity above or into the injection zone. Fluid sampling costs for measuring salinity, CO2, trac ers, etc., in or above the injection zone (a

26portion of equipment may be at surface, e.g., for peri odic in situ sampling using U-tubes) are also included in monitoring costs. EP A notes that costs for analyzi ng water-CO2-rock geochemistry

and mineral interactions are accounted fo r under the site characterization costs.

To account for hydraulic and fluid testing, site ch aracterization costs also include unit costs for obtaining geomechanical information on fractures, stress, rock strength, and in situ fluid pressures from existing data and liter ature and from new cores and tests.

EPA acknowledges that the seismic survey costs us ed in the proposed rule cost analysis (and associated documents) may have been underestimated. Based on several published reports that present a range of $40,000 to $160,000 per square mile, EPA's final cost analysis is based on an estimate of $104,000 per square mile. The Agency clarifies that site characterization requirements at §146.82 do not specify the use of 3D seismic. Instead, the requirements afford owners or operators the flexibility to select te chnologies that are appr opriate to a given site provided the technologies produce suffi cient information to demonstrat e that a site is appropriate for GS. Using the cost of 3D provides for a mo re conservative estimate in cases where 2D may be appropriate.

Costs identified in the proposed rule as "initial " or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. Th e estimate of the costs for transporting CO2, for example, has been updated from the previous $3 to $4.60 per ton CO2 based on the following source: “Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges,” Feb. 2009, INGAA Foundation.

For additional information on the final costing ap proach, please see the final cost analysis and technology and cost document in the final rule docket.

Letter ID: 0167 Comment ID: 29276 Letter Lines: 712 to 728

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Table 3. Monitoring Costs Costs for FEED study should be higher. Monitoring a CCS site will require in-depth planning.

Monitoring wells will need to be of a large enough diameter to accommodate down-hole instrumentation (e.g., cross- well seismic); thus, costs for monitoring wells based on slim-hole pr ices may not be appropriate.

Number of hours allocated for updating re servoir model based on monitoring data and conducting simulations, recalibrating etc. is grossly underestimated.

Costs need to be included for assi milating, evaluating, interpreting the enormous amount of diverse monitoring data that will be generated. The currently allocated amounts - 20 hrs for an annual report, 15 hrs for quarterly reports, and 8 hrs allocated for monthl y reports - are unrealistically low.

27Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncerta inty/low confidence.

Individual Response: EPA believes that the cost estimate for front end engineering design (FEED) work specified under element B-3 is appropr iate, as it only encompasses design work for monitoring and not other project components. FEED work for in jection wells is covered under

cost element C-1.

EPA acknowledges that slim-hole wells (deepest casing of 3.5 inches in diameter) may not accommodate the necessary monitoring equipment. Therefore, in its final rule cost analysis, EPA estimates drilling costs for monitoring wells that are 5.5 in ches in diameter.

EPA notes that, in the cost analysis for the pr oposed rule, a less sophisticated reservoir model was assumed for the lower-cost regulatory options . However, for the selected regulatory option as presented in the proposed and final rules, un it cost B-18 applies. Unit cost B-18 accounts for updating the complex model every 5 years and applie s to all projects under the GS rule. This includes 180 hours of engineer's time per site pl us 64 hours of engineer's time per well, which EPA believes to be an appropriate estimate.

EPA agrees that interpretation and reconciliation of monitoring data is an important part of site monitoring and that considerable re sources must be devoted to that task. This effort is captured under cost item B-18 for period ic calibration and running of complex reservoir simulation models to track past and future migration of th e CO2 plume and other rese rvoir parameters such as pressure gradients. As desc ribed above, this effort is esti mated to require 180 hours per site plus 64 hours per injection well. For example, a site with four injec tion wells would take 436 hours per model update. Much of the effort for the update would be a history matching exercise in which monitored data (injection volumes, in jection pressures, rese rvoir pressures, plume location, etc.) are reconciled in the model to develop the best current picture of reservoir performance. Other cost items for compiling and submitting periodic reports are intended to cover the time needed to prepare the reports themselves. The modeling and report preparation efforts are expected to be higher at first, then are expected to decrease substantially over the learning curve for operators. The labor burden estimat ed in the cost model represents a long term average of the labor expected to be needed.

Costs identified in the proposed rule as "initial " or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. Th e estimate of the costs for transporting CO2, for example, has been updated from the previous $3 to $4.60 per ton CO2 based on the following source: “Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges,” Feb. 2009, INGAA Foundation.

For additional information on the final costing ap proach, please see the final cost analysis and technology and cost document in the final rule docket.

28Letter ID: 0167 Comment ID: 29277 Letter Lines: 730 to 753

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Table 4. Well Construction Costs FEED cost seems high if this is intended to cover the design of the injection wells.

UIC permit costs are grossly underestimat ed ($10,000 per site plus $5,000 per injection well)

Rights of way costs should be ba sed on area (e.g., acre) not well

Costs for wellhead and control equipmen t is underestimated. A wellhead (with Christmas Tree) alone can cost more th an $100K. Controls can also be quite expensive if they include automated valves, real-time downhole sensors,

automatic shut-offs etc.

Pumps will not be required at all sites, i.e., if compression alone can achieve required injection pressures.

Pipeline costs are likely unde restimated ($60K per inch mile all inclusive).

Surcharge for corrosion re sistant casing ($1.75 per ft -inch diameter) and tubing ($1.10 per ft-inch diam) seems underestimated based on recent quotes

obtained from this reviewer.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncerta inty/low confidence.

Individual Response: EPA clarifies that the front end e ngineering cost (FEED) estimated under unit cost item C-1 includes the entire proj ect FEED (including the costs of design and engineering as well as pre-ope rational logging, sampling, and test ing), with the exclusion of FEED for monitoring wells, which is covered by unit co st item B-3.

In the final rule, the costs for operators to compile and submit the necessary UIC permit applications for a given site ar e $10,400 per site plus $6,000 per well for the first five wells at a site and $2,000 per well for subsequent wells. EPA believes this cost is adequate based on the efficiencies realized in filing multiple well applications for a given site.

Effectively, the cost model does assign right-of- way costs on a per area ba sis; the cost model includes a pro forma case for each type of project (saline vs. ER and pilot vs. commercial scale) that is based on a fixed number of injecti on wells and a fixed square-mile area. For a representative saline commercial project, EPA assumes that the area is 23 square miles and there are 4 injection wells. Costs for surface rights of way are then equivalently expressed as $80,000 per project site (23 square miles) or $20,000 per injector.

29The unit cost estimate for wellhead and control e quipment used in the cost analyses for both the proposed and final rules is based on a 2008 Petrol eum Services Association of Canada (PSAC) Well Cost Study and accounts for the maximum tons injected per well per day. EPA notes that in the cost analysis, wellhead and control equipment costs for pilot-scale saline projects are less than $100,000, but costs for commercial-scale sa line projects are grea ter than $100,000; these

cost estimates are consistent wi th the commenter's suggestion.

For costing purposes, EPA adopts the conservative assumption that all project sites will need compressors/pumps. This costs $20,700 per in jection well and $1,550 per pump horsepower.

EPA acknowledges that the pipeline cost estimate in the cost analysis for the proposed rule of $60,000 per inch-mile may be an underestimate. In th e final rule cost analysis, EPA is using an estimate of $83,000 per inch-mile ba sed on pipeline cost data re ported to FERC and published annually in the Oil and Gas Journal.

The cost of corrosion-resistant casing ranges from $1.81 (low alloy) to $ 2.70 per foot length-inch diameter (higher alloy).

As described above, costs identifie d in the proposed rule as "ini tial" or "ICF" estimates have been reevaluated to confirm or refine them, ba sed on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. For additional information on the final costing approach, pl ease see the final cost analysis and technology and cost

document in the final rule docket.

Letter ID: 0167 Comment ID: 29278 Letter Lines: 755 to 765

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Table 5. Area of Review/Corrective Action Costs The amount of time allotted for fluid/reservoir modeling is too low to c onstruct, calibrate and simulate CO2 fate and transport.

Labor rates of $53.52 per hour ar e unrealistically low.

Well remediation costs appear to be lo w - see TCEQ cost spreadsheet for estimating costs for plugging/abandoning wells.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncerta inty/low confidence.

Individual Response: As noted previously, in the final GS Rule cost analysis, EPA assumes that all GS well owners or operators will perform complex fluid flow modeling, rather than less sophisticated modeling as assumed for some proj ects in the proposed rule . EPA estimates this modeling will require 180 hours per project, plus 64 hours of engine er labor per injection well.

EPA acknowledges that corrective action costs (pre sented in D-7 and D-8) will vary widely.

30However, EPA notes that the logging and plugging costs are base d on the 2008 Petroleum Services Association of Canada (PSAC) Well Cost Study. The estimate in the cost analysis for both the proposed and final rules assumes 3 days of rig use at $10,400 per day (these costs are from the Land Rig newsletter, US Land Rig Rates, November 2007).

Regarding labor rates, as described above, EPA in creased the estimated labor rates significantly

from the BLS estimates used in the cost anal ysis for the proposed rule. Additionally, costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either indus try sources or EPA's best prof essional judgment, as shown in the appendix of the cost analys is. For additional information on th e final costing approach, please see the final cost analysis a nd technology and cost document in the final rule docket.

Letter ID: 0167 Comment ID: 29279 Letter Lines: 767 to 771

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Table 6. Well Operation Unit Costs It isn’t clear how/why this is distinguished from Mechanical Integrity Testing.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncerta inty/low confidence.

Individual Response: The costs for MITs were separated from operating costs to allow easier analysis and discussion by EPA of alternative regulatory options re lated to operations and testing and monitoring, including the frequency at wh ich different MIT test s might be required.

As described above, costs identifie d in the proposed rule as "ini tial" or "ICF" estimates have been reevaluated to confirm or refine them, ba sed on either industry sources or EPA's best professional judgment, as shown in th e appendix of the cost analysis.

Letter ID: 0167 Comment ID: 29280 Letter Lines: 773 to 779

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Table 7. Mechanical Integrity Tests Unit Costs Based on recent quotations obtained by this reviewer for these types of tests, the costs listed here are too low. In addition, there will be ancillary costs asso ciated with conducting these tests such as the cost of a service rig.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncerta inty/low confidence.

Individual Response: MIT costs were developed based on the following sources: Carbon Dioxide Storage: Geological Se curity and Environmental Issues – Case Study on the Sleipner Field, Norway, S. Soloman, Bellona Foundation, May, 2007; UIC Program Mechanical Integrity

31Testing: Lessons for Carbon Capture and Storage, Jonathan Koplos, Bruce Kobelski, Anhar Karimjee, and Chi Ho Sham, Fifth Annual C onference on Carbon Capture and Sequestration, DOE/NETL, May, 2006; Determination of the Mech anical Integrity of Injection Wells, EPA Region 5 website, www.epa.gov/region5/water/uic/r 5guid/r5_05.htm; and U nderground Injection Control Rules, Montana Board of Oil and Gas Conservation, www.bogc.dnrc.state.mt.us/uicrules.htm.

As described above, costs identifie d in the proposed rule as "ini tial" or "ICF" estimates have been reevaluated to confirm or refine them, ba sed on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. For additional information on the final costing approach, pl ease see the final cost analysis and technology and cost

document in the final rule docket.

Letter ID: 0167 Comment ID: 29281 Letter Lines: 781 to 787

Comment Code: 6100 3.1 Comments on the cost estimates

Comment: Table 8. Post Injection Well Plugging etc Co st for flushing wells is estimated at $500; this will not cover all the ma terials and services required to accomplish this. Costs that are identifie d as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.

Well plugging/abandoning costs appear to be low - see TCEQ cost spreadsheet for estimating costs for plugging/abandoning wells.

Individual Response: EPA acknowledges that the estimates in the proposed rule cost analysis for flushing wells with a buffer flui d were too low. In the final rule cost analysis, EPA increased the costs to $1,000 plus $0.085/inch -foot of casing diameter.

There are five cost items that relate to the per-well cost of abandoning injection wells. Those items and their values for a typical 4,000 foot deep well are as follows:

♣ G-3: Perform a mechanical inte grity test prior to plugging to ev aluate integrity of casing and cement to remain in ground ($18,670)

♣ G-1: Flush wells with a buffe r fluid before closing ($1,340)

♣ G-2: Plug injection wells with cement and mud ($24,900)

♣ G-5: Remove surface equipment, st ructures, restore vegetation ($25,900)

♣ G-12: Operating G&A ($14,162)

The total cost of thes e items is $84,972 for a 4,000 foot deep injection well. EPA believes these

costs to be conservative and in line with rule-of-thumb cost s of $50,000 per well in most Texas counties (based on $10 per foot of abandoned well and oil/gas well bond requirements).

As described above, costs identifie d in the proposed rule as "ini tial" or "ICF" estimates have been reevaluated to confirm or refine them, ba sed on either industry sources or EPA's best

3233 professional judgment, as shown in the appendix of the cost analysis. For additional information on the final costing approach, pl ease see the final cost analysis and technology and cost

document in the final rule docket.