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 Under the Underground Injection Control (UIC) 

Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells 

The attached comments and observations are submitted by the FutureGen Industrial Alliance 

(FGIA) in response to the United States Environmental Protection Agency proposing Federal 

requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon 

dioxide (CO2) 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 Limited 
Docket 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 sequester one million tonnes per year of CO2 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 review 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 CO2 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 experience it has gained in developing an IGCC 

power plant site for CO2 capture and sequestration in a saline aquifer. Battelle, as its 

sequestration contractor has helped the FGIA develop these comments. Detailed comments are 

offered on several programmatic areas identified in the proposed regulations. Comments are also 

provided on other topics including comments on the “Cost Analysis Technical Support 

Document”. Many of the estimates in the Cost 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 the grandfathering of the 

existing siting, area of review, operations, or monitoring plan. These areas should be 

grandfathered, too. 

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 requirement 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 required to identify and 

characterize multiple confining layers, at the discretion of the Director (§ 146.83(b)). 

Comment: 

 

• Subsection (b) of § 146.83 of the proposed regulations, which grants the Director discretion 

to require the presence of multiple confining 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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Docket ID No. EPA-HQ-OW-2008-0390 

This optional requirement may eliminate suitable GS sites without reducing 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 requirement 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 problems in the future, but more importantly, this 

requirement is not needed. If subsection (b) of § 146.83 were removed, 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 requirements for a confining system given in part (2) of 

subsection (a) would cover this situation, and would allow protection of USDW’s and the public 

without creating the potential for confusion that would arise with the option outlined in 

subsection (b). 

Previous experience and research have demonstrated that a single well-characterized confining 

system can provide more than adequate protection by preventing the upward migration of CO2. 

For example, time-lapse seismic imaging at the Sleipner Project demonstrates “the caprock is an 

effective seal that prevents CO2 migration out of the storage 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 

rule 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. 

The 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 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 requirement 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 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 injection and storage of CO2 is more dangerous to the public than 

subsurface injection of hazardous wastes. This perception of high risk, which does not appear to 

be justified by previous studies of the risks of subsurface CO2 sequestration (e.g., IPCC 2005; 

Benson and Surles 2006) could lead to decreased 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. 

This material is a product of the FutureGen Industrial Alliance 
Docket ID No. EPA-HQ-OW-2008-0390 

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 Dioxide Capture and Storage. 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. 

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 accounts for the physical 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 Corrective 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 identification of all artificial penetrations in the 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 monitoring 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 evaluation required by §146.84(b); 

Comment: 

• EPA should define two regulatory regions surrounding the geologic sequestration project and 

provide specific definitions for those regions; 1) Area of Monitoring (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. The area of monitoring is based on monitoring 

data and computational modeling that accounts for the physical and chemical properties of all 

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Docket ID No. EPA-HQ-OW-2008-0390 

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 surrounding the geologic sequestration reservoir that has 

or is indicated to develop pressures that are greater than 10% different from the pre-injection 

formation fluid pressure, but no less than the Area of Monitoring. The area of review is 

based on monitoring data and computational 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 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 asymmetrical 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 regulations governing waste disposal, EPA is introducing fundamentally 

new concepts for defining the area of review (AoR) for CO2 injection. The newly proposed 

concept is flawed and will pose an unjustifiable barrier to CO2 injection projects 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. 

The 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 definitions. 

Under deep geologic sequestration conditions the injected fluid (i.e., supercritical CO2) has low 

compressibility, the displaced fluid (i.e., brine) has low compressibility, and the reservoir 

formation (e.g., sandstone) generally has low compressibility, all of which 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 CO2 into deep saline formations is driven by differences between the well injection 

pressure and formation pressure. To avoid inducing fractures or opening existing fractures in the 

formation and caprock, well injection pressure will be limited to some fraction below the fracturing pressure. As CO2 migrates into the formation the formation pressure increases around the 

injection well. The pressure distribution in the formation around the injection well depends on 

the formation properties, structure, and injection rate. Injection formations will be required to be 

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Docket ID No. EPA-HQ-OW-2008-0390 

confined vertically and/or horizontally to prevent the vertical migration of injected 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 permeable wells, fractures, or 

faults that penetrate the formation. Elevated pressures 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 greater 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 the 

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 penetrations 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 these 

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 formation pressure, which is usually 

larger than the area that contains the injected CO2 mass. For confined formations, this area is 

defined by the lateral pressure distribution around the injection well(s). 

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Docket ID No. EPA-HQ-OW-2008-0390 

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 brines 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 identification of geologic 

formations suitable to receive the injected fluids and confine them such that they are 

isolated below the lowermost USDWs, minimizing 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 CO2 injection should be allowed into an injection zone (saline sedimentary 

formations, unminable 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 allow 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 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 stratigraphic zones below the lowermost USDW. 

 

• Prohibition of CO2 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 injection 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 USDWs. Conditions that will prevent downward 

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Docket ID No. EPA-HQ-OW-2008-0390 

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 CO2, the requirement of thousands of feet of intervening formations may be less 

important than the demonstration of the sealing 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 capacity of the intervening layers. 

• The draft rule is far too restrictive 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 completely by the 

presence of one or more low permeability layers. 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 should be clarified. Aquifer exemptions should be 

allowed for GS (“a receiving 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 below a GS zone is not needed if there is demonstration of a competent seal between the injection zone and 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 set minimum depth for injection nor by requiring 

injection take place below the lowermost USDW. Minimum depth requirements would be 

unnecessarily proscriptive. Shallow injections could be done for very small commercial 

producers or in cases where reservoir engineering practices (such as pre-dissolution 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 injection; and 

(c) under what other conditions should the EPA allow injection above a USDW. 

 

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

seams, salt domes, abandoned mines, black shales 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 indicates 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 would be allowed to inject CO2 into basalts, deep 

saline reservoirs, and other potential reservoirs only when they are beneath the lowermost 

USDW. 

A USDW is defined by the EPA as “An aquifer 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 sysThis material is a product of the FutureGen Industrial Alliance 
Docket ID No. EPA-HQ-OW-2008-0390 

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 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 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 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 the injection zone and the overlying and underlying USDWs. 

As currently defined by the EPA, “aquifer exemptions” permanently remove a specified aquifer 

from protection as a USDW. Aquifer exemptions are currently granted 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 will be used 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 new rule, it would be possible for operators 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 alternatives 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 may 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 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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Docket ID No. EPA-HQ-OW-2008-0390 

Proposed Mechanical Integrity Testing Requirement 

Proposed Regulation 

p. 43513, c. 3 

...require owners and operators of Class VI GS project to monitor internal mechanical integrity 

of their injection wells by continuously monitoring injection pressure, flow rate, and injected 

volumes... 

p. 43514, c. 1 

...require owners and operators of CO2 wells to demonstrate injection well external mechanical 

integrity at least once annually. 

The EPA seeks comment on the appropriate frequency of internal and external MITs for GS 

injection wells. 

Comments: 

• We recommend that an external MIT be performed on a recurrence 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 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 subsequent corrective actions may be warranted. 

• The recommended external MIT recurrence assessment of every 5 years is predicated on no 

indications of injection 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 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 proposed rule states that internal MIT should be performed 

continuously by monitoring pressures (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 reasonable and 

appropriate. The semi-annual reporting frequency 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 exposed to the GS stream and the 

buoyant nature of the injected fluid. 

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To execute an annual external MIT, the injection 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 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 external MIT evaluations would be excessive and overly 

disruptive for normal plant operations. This is because quantitative external MIT evaluation tests 

would require: 

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

• Performing detailed wireline geophysical surveys for cement-seal and well casing integrity 

(e.g., cement-bond log), and 

• If warranted by the results of the wireline geophysical surveys, conduct¬ing direct leakagedetection tests with installed internal test equipment (e.g., downhole internal straddle-packer 

system) of suspected areas of concern 

The performance of the various aforementioned elements of an external MIT and re-installation 

of components of the injection well system are likely to take between 2 to 5 days, depending on 

the characteristics 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 external MIT program, the performance of 

fixed-annual external MIT evaluations (outside the schedule 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 studied and understood, the process of CO2 adsorption to coal has not 

been proven and the chemical reaction of supercritical CO2 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 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: 

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Docket ID No. EPA-HQ-OW-2008-0390 

These statements are not true. The statements would be true for storage into shallow aquifer 

pore space, such as in shallow saline formations, but it is not the case for storage into shallow 

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 water supplies. As a result, EPA is proposing to preclude the injection of CO2

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 conduct monitoring as specified in the Directorapproved post-injection site care and site closure plan for at least 50 years following the 

cessation of injection...If the owner or operator can demonstrate to the satisfaction of the 

Director before 50 years, based on monitoring and other site-specific data, that the geologic 

sequestration project no longer poses 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 information. Although there is the possibility that post-injection 

monitoring period can be reduced given sufficient data, this approach adds significant 

uncertainty to both the project schedule 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 CO2 stream are likely to vary by 

facility, coal composition, plant operating conditions, and pollution removal technologies, EPA 

cannot make a categorical determination as to whether injected CO2 is hazardous under RCRA. 

Owners or operators will need to characterize their CO2 stream as part 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 injection of hazardous waste apply. The design changes EPA is proposing are 

meant to address the mobility and corrosivity caused by long term GS of CO2, and not the long 

term storage of hazardous wastes. 

This material is a product of the FutureGen Industrial Alliance 
Docket ID No. EPA-HQ-OW-2008-0390 

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 CO2 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 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 

standards, 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 

and other components that are typically scrubbed or otherwise removed from the off-gas stream 

to prevent 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 adversely affects the cost of electricity. Significantly increasing the cost of 

electricity will discourage GS. 

If the objective of GS is to reduce and/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 

CO2 waste stream. Additional technical information is needed to understand the merits and risks 

of co-injection of contaminants. A Proposed Rule for GS based on a high-purity CO2 stream 

prior to understanding the trade-offs of co-injection of contaminants seems short-sighted. The 

Proposed Rule should have provisions and leeway for regulators and industry to balance cost, 

energy conservation, waste reduction, and waste management program 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 Public Notice (Jul 15, 2008) 

Corresponding Section in Federal Register (Jul 25, 2008) 

Comment 

Section II I. Is Injected CO2 considered a Hazardous Waste Under RCRA? 

II-I. EPA should specify the information needed to characterize the CO2 s

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 COinjected via wells that are constructed and operated per the Class I UIdoes this preclude injection of the hazardous CO2 stream? 

Section IIIa A-1. Proposed Geologic Siting Requirements 

III-A-1. This section mentions several types of geologic/geochemical/geomec

needed to assess a site’s viability. EPA should specify the informatiothis analysis. 

A-4 Proposed Injection Well Operating Requirements 

III-A-4 Class I wells are typically required to maintain an annular-fluid press

than the injection tubing pressure to prevent outward leakage from th

Typically, these wells operate at pressures much lower than CO2 injesame requirement imposed on CO2 injection wells would require speequipment to maintain the required pressure differential on the annulThe use of down-hole shut-off valves that would automatically shut-irecommended as a possible safety device in CO2 injection wells. Thi

contacted the vendor cited by EPA (Schlumberger) for information oCO2 injection well and was told that they are not available in sizes thfor most on-shore injection wells because these devices are primarily 

shore wells. The use of safety valves needs more consideration. 

A-5 Mechanical Integrity Testing Requirements 

III-A-5 Automated down-hole shut valves sound problematic, especially if th

respond to excursions in annular pressure and volume which are subj

fluctuations. See above comment. 

14 
Docket ID No. EPA-HQ-OW-2008-0390 

Regarding external MITs, it isn’t clear whether the requirement invol

injection CO2 or another fluid (e.g., water). Also, it isn’t clear wheth

methods work with CO2; therefore, new/alternate methods may be ne

A-6 Proposed Plume and pressure Front Monitoring 

III-A-6 Page 102. Pressure gauges placed in the first formation overlying the 

would not be useful for tracking the lateral migration of the CO2 plumWould EPA require monitoring wells that penetrate through the confthe storage formation for this purpose? Fiber optic pressure and temperature sensors are likely to be prohibit

A-7 Record Keeping and Reporting Requirements 

III-A-7 We support the requirement for 1) a monitoring and testing plan 2) an 

Action Plan and 3) a Post-Injection Site Care and Site Closure plan. To comply with a requirement for electronic record-keeping, new dat

required to deal with the diverse nature of information that will be gecourse of a CCS project. 

Cost Analysis Technical Support Document Table 2. Site Characterization Costs The allotment of labor hours seems unrealistically low (this comment appl

tables). Some individual tasks are especially low (e.g., develop list of penezone = 12 hours). 

In this table and others, labor rates appear to be low – perhaps underestima

to 2 depending on task/activity. 

It appears that some important site characterization activities/tests have no

wireline logging, hydraulic testing, fluid sampling and analysis. These sh

3D seismic survey costs may be underestimated – recent quotes suggest ~mile. 2D seismic should be allowed because 3D may be impracticable to i

many/most areas. 

Costs that are identified as “initial estimates” or “ICF estimates” should be 

uncertainty/low confidence. 

Table 3. Monitoring Costs Costs for FEED study should be higher. Monitoring a CCS site will requir

Monitoring wells will need to be of a large enough diameter to accommodinstrumentation (e.g., cross-well seismic); thus, costs for monitoring wells 

This material is a product of the FutureGen Industrial Alliance 
Docket ID No. EPA-HQ-OW-2008-0390 

Cost Analysis Technical Support Document 

prices may not be appropriate. Number of hours allocated for updating reservoir model based on monitor

conducting simulations, recalibrating etc. is grossly underestimated. 

Costs need to be included for assimilating, evaluating, interpreting the enodiverse monitoring data that will be generated. The currently allocated am

annual report, 15 hrs for quarterly reports, and 8 hrs allocated for monthly 

unrealistically low. Costs that are identified as “initial estimates” or “ICF estimates” should be 

uncertainty/low confidence. 

Table 4. Well Construction Costs FEED cost seems high if this is intended to cover the design of the injectio

UIC permit costs are grossly underestimated ($10,000 per site plus $5,000 Rights of way costs should be based on area (e.g., acre) not well Costs for wellhead and control equipment is underestimated. A wellhead (

alone can cost more than $100K. Controls can also be quite expensive if tautomated valves, real-time downhole sensors, automatic shut-offs etc. 

Pumps will not be required at all sites, i.e., if compression alone can achiepressures. Pipeline costs are likely underestimated ($60K per inch mile all inclusive)Surcharge for corrosion resistant casing ($1.75 per ft-inch diameter) and tu

inch diam) seems underestimated based on recent quotes obtained from th

Costs that are identified as “initial estimates” or “ICF estimates” should be 

uncertainty/low confidence. 

Table 5. Area of Review/Corrective Action Costs 

The amount of time allotted for fluid/reservoir modeling is too low to conssimulate CO2 fate and transport. Labor rates of $53.52 per hour are unrealistically low. Well remediation costs appear to be low – see TCEQ cost spreadsheet for plugging/abandoning wells. Costs that are identified as “initial estimates” or “ICF estimates” should be 

uncertainty/low confidence. 

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

Costs that are identified as “initial estimates” or “ICF estimates” should be 

uncertainty/low confidence. 

This material is a product of the FutureGen Industrial Alliance 
Docket ID No. EPA-HQ-OW-2008-0390 

This material is a product of the FutureGen Industrial Alliance 

Cost Analysis Technical Support Document Table 7. Mechanical Integrity Tests Unit Costs 

Based on recent quotations obtained by this reviewer for these types of teshere are too low. In addition, there will be ancillary costs associated with csuch as the cost of a service rig. Costs that are identified as “initial estimates” or “ICF estimates” should be 

uncertainty/low confidence. 

Table 8. Post Injection Well Plugging etc 

Cost for flushing wells is estimated at $500; this will not cover all the mat

required to accomplish this. Costs that are identified as “initial estimates” should be assigned very high uncertainty/low confidence. 

Well plugging/abandoning costs appear to be low – see TCEQ cost spreadcosts 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 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 the grandfathering of the existing siting, area 

of review, operations, or monitoring plan. These areas should be grandfathered, 

too. 

Individual Response: EPA agrees that many Class II and 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 grandfathered per §146.81(c), provided 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 protection 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. Following re-permitting of the well as Class VI, 

many of the unique factors of GS sites (e.g., increased reservoir pressures associated with large 

volumes of stored CO2 and the corrosivity of CO2 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 projects 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 

1
requirement 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 required to identify and characterize 

multiple confining layers, at the discretion of the Director (§ 146.83(b)). 

Comment: 

- Subsection (b) of § 146.83 of the proposed regulations, which grants the 

Director discretion to require the presence of multiple confining 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. 

This optional requirement may eliminate suitable GS sites without reducing 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 requirement 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 problems in the future, but more importantly, this requirement is 

not needed. If subsection (b) of § 146.83 were removed, 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 requirements for a confining system given in part (2) of subsection (a) 

would cover this situation, and would allow protection of USDW’s and the public 

without creating the potential for confusion that would arise with the option 

outlined in subsection (b). 

Previous experience and research have demonstrated that a single wellcharacterized confining system can provide more than adequate protection by 

preventing the upward migration of CO2. For example, time-lapse seismic imaging 

at the Sleipner Project demonstrates "the caprock is an effective seal that 

prevents CO2 migration out of the storage 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 rule 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. 

2
The 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 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 requirement 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 

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 injection and storage of CO2 is more 

dangerous to the public than subsurface injection of hazardous wastes. This 

perception of high risk, which does not appear to be justified by previous 

studies of the risks of subsurface CO2 sequestration (e.g., IPCC 2005; Benson 

and Surles 2006) could lead to decreased 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 Dioxide Capture and Storage. 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 identify additional containment/confining 

zones, if required by the Director, as proposed (§146.83(b)). EPA acknowledges that such 

additional zones may not be needed in all circumstances, and clarifies that this requirement is at 

the Director's discretion, based on his or her understanding of a particular 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 protection. These layers could 

further impede vertical fluid movement and allow for pressure dissipation, and also provide 

additional sites for monitoring, mitigation, and remediation. The Agency's decision is supported 

by commenters representing states, water associations, and an electric utility who assert that 

these requirements promote a flexible, risk-based, site-specific approach to characterizing and 

permitting a site for GS projects, and are intended to improve understanding of the project as a 

3
whole 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 regarding characterizing the regional geology and hydrogeology of a 

proposed GS site as well as performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA expects that this guidance will 

assist permit writers in making an objective decision 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/Modeling 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 project that may be impacted by the 

injection activity". The area of review is based on computational modeling that 

accounts for the physical 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 Corrective 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 identification 

of all artificial penetrations in the 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 

monitoring 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 

evaluation required by §146.84(b); 

Comment: 

- EPA should define two regulatory regions surrounding the geologic 

sequestration project and provide specific definitions for those regions; 1) 

Area of Monitoring (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 

4
limit of Corrective Action: 

- Area of Monitoring (AoM): The region surrounding the geologic sequestration 

project that contains 95% of the carbon dioxide mass. The area of monitoring is 

based on monitoring data and computational 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 surrounding the geologic sequestration 

reservoir that has or is indicated to develop pressures that are greater than 

10% different from the pre-injection formation fluid pressure, but no less than 

the Area of Monitoring. The area of review is based on monitoring data and 

computational 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 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 asymmetrical 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 regulations governing waste disposal, EPA is 

introducing fundamentally new concepts for defining the area of review (AoR) for 

CO2 injection. The newly proposed concept is flawed and will pose an 

unjustifiable barrier to CO2 injection projects 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. 

5
The 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 definitions. Under deep geologic sequestration 

conditions the injected fluid (i.e., supercritical CO2) has low compressibility, 

the displaced fluid (i.e., brine) has low compressibility, and the reservoir 

formation (e.g., sandstone) generally has low compressibility, all of which 

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 CO2 into deep saline formations is driven by differences between 

the well injection pressure and formation pressure. To avoid inducing fractures 

or opening existing fractures in the formation and caprock, well injection 

pressure will be limited to some fraction below the fracturing pressure. As 

CO2 migrates into the formation the formation pressure increases around the 

injection well. The pressure distribution in the formation around the injection 

well depends on the formation properties, structure, and injection rate. 

Injection formations will be required to be confined vertically and/or 

horizontally to prevent the vertical migration of injected 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 permeable wells, fractures, or faults that 

penetrate the formation. Elevated pressures 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 greater 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 the 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 penetrations 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 these 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 formation pressure, which is usually larger 

than the area that contains the injected CO2 mass. For confined formations, this 

area is defined by the lateral pressure distribution around the injection 

well(s). 

6
Individual Response: EPA believes that, while the commenter 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 must 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 phases of the injected CO2 stream, 

based on available site characterization, monitoring, and operational data. 

Furthermore, any changes to the AoR would necessitate a review of and potential change in the 

testing and monitoring plan, consistent with the commenter's assertion 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 requires 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 following significant changes to the facility, or when 

required by the Director). The relationship between the AoR reevaluation and the testing and 

monitoring plan should allow for considerations suggested by the commenter. 

EPA believes that by linking development and review of the testing and monitoring plan to the 

AoR evaluation and reevaluation process, the GS rule, in effect, incorporates and addresses many 

of the commenter's considerations 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 brines 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 identification of geologic formations 

suitable to receive the injected fluids and confine them such that they are 

isolated below the lowermost USDWs, minimizing 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. 

7
The EPA is soliciting comments on these issues: 

1.Whether CO2 injection should be allowed into an injection zone (saline 

sedimentary formations, unminable 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 allow 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 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 

reasons, or 

3)formations exempted as USDWs by the state. 

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

- Prohibition of CO2 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 injection 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 USDWs. Conditions that will 

prevent downward 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 CO2, the requirement of 

thousands of feet of intervening formations may be less important than the 

demonstration of the sealing 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 capacity of the intervening layers. 

8
- The draft rule is far too restrictive 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 completely by the presence of one or more 

low permeability layers. 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 should be clarified. Aquifer 

exemptions should be allowed for GS ("a receiving 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 below a GS zone is not needed if there 

is demon-stration of a competent seal between the injection zone and 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 set minimum depth for injection nor 

by requiring injection take place below the lowermost USDW. Minimum depth 

requirements would be unnecessarily proscriptive. Shallow injections could be 

done for very small commercial producers or in cases where reservoir engineering 

practices (such as pre-dissolution 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 injection; and (c) under what other conditions 

should the EPA allow injection above a USDW. 

In addition to injection into saline formations, EPA recognizes that basalt, 

unmineable coal seams, salt domes, abandoned mines, black shales 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 indicates 

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 would be allowed to inject CO2 into 

basalts, deep saline reservoirs, and other potential reservoirs only when they 

9
are beneath the lowermost USDW. 

A USDW is defined by the EPA as "An aquifer 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 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 

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 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 the injection zone and the overlying and underlying USDWs. 

As currently defined by the EPA, "aquifer exemptions" permanently remove a 

specified aquifer from protection as a USDW. Aquifer exemptions are currently 

granted 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 will be used 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 new rule, it would be possible for 

operators 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 alternatives 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 may 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 remove these aquifers from protection as 

USDWs). 

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

10
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 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed 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 owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection 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 owners 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 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 Class VI wells in the final GS rule. Additionally, the final GS 

rule does not categorically preclude or prohibit injection into any type of formation. 

EPA agrees that it is not appropriate to set a minimum injection depth for GS projects and the 

Agency believes that a determination of site-suitability for GS (i.e., that 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 provide 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, and that USDWs will be 

protected from endangerment. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows 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 aquifer exemptions for GS. Finally, 

EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. 

For additional information on the waiver approach and 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 

Data Availability and Request for Comment. 

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

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

circumstances 

Comment: As currently defined by the EPA, "aquifer exemptions" permanently remove a 

specified aquifer from protection as a USDW. Aquifer exemptions are currently 

granted 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 will be used 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 new rule, it would be possible for 

operators 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. 

Individual Response: The final rule allows for the expansion 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 transitioning from Class II EOR/EGR wells to Class VI. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR 

operations and Class VI operations are considered during the aquifer exemption application 

process and the Class VI permitting process. These 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 Agency believes that this process will encourage 

owners or operators and Directors to consider the use of alternative 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 wells transitioning to Class VI GS operations. 

EPA clarifies that all decisions regarding whether 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 permit 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 zone 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 Data 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) 

12
Comment: Proposed Mechanical Integrity Testing Requirement 

Proposed Regulation 

p. 43513, c. 3 "require owners and operators of Class VI GS project to monitor 

internal mechanical integrity of their injection wells by continuously 

monitoring injection pressure, flow rate, and injected volumes" 

p. 43514, c. 1 -require owners and operators of CO2 wells to demonstrate 

injection well external mechanical integrity at least once annually. 

The EPA seeks comment on the appropriate frequency of internal and external MITs 

for GS injection wells. 

Comments: 

- We recommend that an external MIT be performed on a recurrence 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 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 subsequent corrective actions may be 

warranted. 

- The recommended external MIT recurrence assessment of every 5 years is 

predicated on no indications of injection 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 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 proposed rule states that internal MIT should be 

performed continuously by monitoring pressures (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 reasonable and appropriate. The semi-annual 

reporting frequency 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 exposed to the GS stream and the buoyant nature of the injected fluid. 

13
To execute an annual external MIT, the injection 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 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 external MIT evaluations would be excessive 

and overly disruptive for normal plant operations. This is because quantitative 

external MIT evaluation tests would require: 

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

system 

- Performing detailed wireline geophysical surveys for cement-seal and well 

casing integrity (e.g., cement-bond log), and 

- If warranted by the results of the wireline geophysical surveys, conduct¬ing 

direct leakage-detection tests with installed internal test equipment (e.g., 

downhole internal straddle-packer system) of suspected areas of concern 

The performance of the various aforementioned elements of an external MIT and 

re-installation of components of the injection well system are likely to take 

between 2 to 5 days, depending on the characteristics 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 external MIT program, the performance of 

fixed-annual external MIT evaluations (outside the schedule 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. 

Individual Response: EPA disagrees that a five-year external MIT is appropriate. The final GS 

regulation retains the requirement that owners or operators of Class VI wells must demonstrate 

injection well external mechanical integrity at least once annually under §146.89(c). EPA 

believes this is justifiable for the protection of USDWs from endangerment given the unique 

nature of CO2 GS relative to other injection operations, including the potential 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 changes, the temperature and pressure effects 

associated with injecting supercritical CO2, and the buoyant nature of the injected CO2. Because 

of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial approach in 

the early stages of deployment for GS. 

14
In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found 

that Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those 

that inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., 

in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT 

failure and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule 

are appropriate. Regarding concerns about disruptions of plant 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 well can be timed to avoid complete interruption of the project. 

EPA believes that the external MITs described in 146.89(c) of the rule (an approved tracer log or 

temperature or noise logs) are effective methods to demonstrate external MI, provide an 

important early warning of potential problems in the injection well system, and represent 

standard techniques that have been used successfully by the drilling industry and for the UIC 

Program for decades. EPA clarifies that the regulations 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 information about the site or the well. See §146.89(e). 

EPA acknowledges the commenter’s support of continuous monitoring to demonstrate internal 

MI; the final rule retains this requirement at §146.89(b). 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, to determine whether the 

appropriate 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: 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 understood, the process of CO2 adsorption 

to coal has not been proven and the chemical reaction of supercritical CO2 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 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 

15
storage into shallow aquifer pore space, such as in shallow saline formations, 

but it is not the case for storage into shallow 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 water supplies. As a result, EPA is 

proposing to preclude the injection of CO2 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. 

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 commenters citing the process of enhanced methane 

recovery. The final GS rule does not preclude injection into unmineable coal seams provided 

owners or operators can demonstrate that GS can be performed in a manner that protects USDWs 

from endangerment. The Agency clarifies that owners or operators of Class VI wells used for 

injecting CO2 into unmineable coal seams are subject to the same site characterization, well 

construction, operation, monitoring, post-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 monitoring as specified in the 

Director-approved post-injection site care and site closure plan for at least 50 

years following the cessation of injection.If the owner or operator can 

demonstrate to the satisfaction of the Director before 50 years, based on 

monitoring and other site-specific data, that the geologic sequestration project 

no longer poses 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 information. Although 

16
there is the possibility that post-injection monitoring period can be reduced 

given sufficient data, this approach adds significant uncertainty to both the 

project schedule 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 postinjection 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. 

Individual Response: EPA clarifies that it proposed a default post-injection site care timeframe 

of 50 years based on a review of research studies, industry reports, and existing environmental 

programs. This analysis was included in an EPA-prepared background document that is available 

in the federal docket, titled "Computational Modeling of Underground Injection of Carbon 

Dioxide for Determination of Area-of-Review and Potential Risk to Underground Sources of 

Drinking Water." EPA assessed various default timeframes based on additional review of 

research studies and evaluation of public comments. 

While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the 

commenters provided sufficient data or other evidence to warrant 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 studies, 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 support 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 discretion 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 flexibility 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 well 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-endangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care 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 accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA believes that a 50 year post-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. Furthermore, EPA believes that a 50-year default postinjection site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not 

17
exaggerate 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 issues (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 composition, plant operating conditions, and 

pollution removal technologies, EPA cannot make a categorical determination as 

to whether injected CO2 is hazardous under RCRA. Owners or operators will need 

to characterize their CO2 stream as part 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 injection of hazardous waste apply. The 

design changes EPA is proposing are meant 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 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 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 standards, 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 and other components that are typically 

scrubbed or otherwise removed from the off-gas stream to prevent 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 adversely affects the cost of electricity. 

Significantly increasing the cost of electricity will discourage GS. 

If the objective of GS is to reduce and/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 CO2 waste stream. Additional technical 

18
information is needed to understand the merits and risks of co-injection of 

contaminants. A Proposed Rule for GS based on a high-purity CO2 stream prior 

to understanding the trade-offs of co-injection of contaminants seems shortsighted. The Proposed Rule should have provisions and leeway for regulators and 

industry to balance cost, energy conservation, 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 addresses 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 properties. Specifically, the GS rule requires the owner or operator to 

submit data about the site, including an analysis of the chemical and physical characteristics of 

the CO2 stream, as required at §146.82(a)(7)(iv), and information on the compatibility of the 

CO2 stream with fluids in the injection zone and minerals in both the injection 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 geochemical 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 applicability of the RCRA regulations and statute to 

CO2 streams that are geologically sequestered under the final Class VI UIC well requirements. 

As a result, EPA has decided to initiate a separate proposed rulemaking specifically to examine 

the issue of RCRA applicability to CO2 streams 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 part 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 proposed 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 oversight 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. 

19
EPA is developing primacy implementation materials 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/groundwater/uic/wells_sequestration.cfm. 

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

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

Comment: I. Is Injected CO2 considered a Hazardous Waste Under RCRA? II-I. EPA should 

specify the information needed to characterize 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 constructed and operated per the Class I 

UIC regulations, or does this preclude injection 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 characterize their CO2 stream as part of their permit application to 

determine if the injectate is considered hazardous as defined under RCRA. If the CO2 stream is 

determined to be a hazardous waste, injection 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 Requirements III-A-1. This section mentions 

several types of geologic/geochemical/geomechanical information needed to 

assess a site’s viability. EPA should specify the information required to 

support this analysis. 

Individual Response: 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 to owners or operators regarding 

information to characterize the regional geology and hydrogeology of a proposed GS site as well 

as performing the necessary geochemical, geomechanical, and geophysical analyses of the 

injection and confining zone. EPA is also developing a number of technical guidances and 

implementation materials to assist owners or operators and Directors in the permitting process. 

These guidances will provide recommendations to perform many of the activities necessary for 

applying for a permit, including developing all required plans and 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. 

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

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

Comment: A-4 Proposed Injection Well Operating Requirements III-A-4 Class I wells are 

typically required to maintain an annular-fluid pressure that is greater than 

the injection tubing pressure to prevent 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 equipment 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 believes this requirement is appropriate for Class 

VI wells given the potential high volumes and supercritical 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 vendor 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 needs more consideration. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, 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 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 requires, 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 facilities is lower than that 

for offshore facilities, down-hole shut-off valves are still commonly used in onshore facilities 

21
such as acid gas injection wells and high pressure, high-temperature wells. However, the Agency 

believes that offshore Class VI wells present unique construction and operational conditions, 

including isolation from shorelines and the need to construct wells 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 technology has advanced sufficiently to make valve 

failure a rare occurrence and to appropriately handle 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 needed for onshore injection wells may not be as 

common, these devices have been installed in other similar projects and therefore should be 

available. Acid gas injection wells commonly 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 Requirements 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 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 requires, 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 requiring the installation of automatic surface shut-off devices for onshore 

wells (and affording Director's discretion to require down-hole devices where necessary) and 

automatic down-hole shut-off devices for offshore wells in submerged lands within the 

jurisdiction of a State ensures that proper precautions are taken to prevent subsurface fluid 

movement and ensure protection 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 clear whether the requirement involves 

testing while injection CO2 or another fluid (e.g., water). Also, it isn’t 

clear whether or not these methods work with CO2; therefore, new/alternate 

methods may be needed. 

22
Individual Response: EPA believes that the MITs described in §146.89(c) of the rule (e.g., an 

approved tracer log or temperature or noise logs) are effective 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 problems in the injection well system. For additional information, 

please see the discussion of MITs in the final rule preamble. 

EPA is using an adaptive approach to regulating GS. The Agency plans to collect and review 

data every six years on GS projects to determine whether the appropriate 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 front tracking (seeking comment) 

Comment: A-6 Proposed Plume and pressure Front Monitoring III-A-6 Page 102. Pressure 

gauges placed in the first formation overlying the confining zone would 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 into the storage formation for this purpose? 

Fiber optic pressure and temperature sensors 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 operators 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 movement 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 detect movement of the pressure front unless a breach of the 

confining zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow 

between the injection zone and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used 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 performing 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 changes are occurring above the 

confining zone due to CO2 leakage. Monitoring also identifies needed remedial actions, provides 

23
inputs for AoR reevaluation modeling, and targets additional geochemical and surface 

monitoring needs. Knowledge of the 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 penetrations which could serve as conduits for fluid 

migration. EPA expects site-specific testing and monitoring plans to describe the proposed 

monitoring regime, which must be approved by the Director. 

EPA does not believe that prescribing specific technologies to be used in all cases for GS would 

be appropriate given the variability in sites. Rather, EPA is developing guidance on testing and 

monitoring to assist owners or operators and Directors in evaluating requirements under §146.90, 

including proposed monitoring plans. The guidance describes available technologies and 

recommended approaches for implementing a testing and monitoring plan, including preoperational geophysical logging and testing of injection wells, MITs, injection well testing 

during operation, groundwater quality 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/groundwater/uic/wells_sequestration.cfm. In addition, in January 2009, 

DOE published a best practices manual entitled "Monitoring, Verification, 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 about the cost of monitoring. However, EPA 

believes that monitoring is essential for protection of USDWs at GS sites. Although a significant 

cost in absolute terms, monitoring costs are expected to be a small fraction of site operating 

costs, according to EPA's cost analysis for the GS rulemaking (which is available 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 Requirements 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 support of the GS project plans. 

EPA believes that the requirement for the plans associated with GS projects will promote an 

ongoing dialogue between the owner or operator and the Director to ensure that USDWs are 

24
protected 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/groundwater/uic/wells_sequestration.cfm. 

EPA agrees that developing, implementing, and periodically reviewing the required GS project 

plans is an important part of assuring that a GS project is operating properly and is crucial for the 

early detection of potential endangerment to USDWs. EPA also believes that periodic updates to 

the plans are appropriate. EPA clarifies that the final GS regulation includes 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 incorporate 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 electronic record-keeping, new data storage 

tools will be required to deal with the diverse nature of information that will 

be generated during the course 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 requires this at §146.91(e). 

EPA believes that it is prudent to provide assistance by developing a central 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 rather than building or upgrading 

separate, independent databases for GS information. 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 available 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 

25
Comment: Cost Analysis Technical Support Document 

Table 2. Site Characterization Costs The allotment of labor hours seems 

unrealistically low (this comment applies to most cost tables). Some individual 

tasks are especially low (e.g., develop list of penetrations into injection 

zone = 12 hours). 

In this table and others, labor rates appear to be low - perhaps underestimated 

by a factor of 1.5 to 2 depending on task/activity. 

It appears that some important site characterization 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 allowed 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 uncertainty/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 databases 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, the 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 the 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 rates in the final rule cost analysis are $107.23 

and $110.62 in 2008 dollars for engineering geologists 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 wireline 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, and resistivity above or into the injection zone. 

Fluid sampling costs for measuring salinity, CO2, tracers, etc., in or above the injection zone (a 

26
portion of equipment may be at surface, e.g., for periodic in situ sampling using U-tubes) are also 

included in monitoring costs. EPA notes that costs for analyzing water-CO2-rock geochemistry 

and mineral interactions are accounted for under the site characterization costs. 

To account for hydraulic and fluid testing, site characterization costs also include unit costs for 

obtaining geomechanical information on fractures, stress, rock strength, and in situ fluid 

pressures from existing data and literature and from new cores and tests. 

EPA acknowledges that the seismic survey costs used 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 technologies that are appropriate to a given site 

provided the technologies produce sufficient information to demonstrate that a site is appropriate 

for GS. Using the cost of 3D provides for a more 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. The 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 approach, 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 prices may not be appropriate. 

Number of hours allocated for updating reservoir model based on monitoring data 

and conducting simulations, recalibrating etc. is grossly underestimated. 

Costs need to be included for assimilating, 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 monthly reports - are unrealistically low. 

27
Costs that are identified as "initial estimates" or "ICF estimates" should be 

assigned very high uncertainty/low confidence. 

Individual Response: EPA believes that the cost estimate for front end engineering design 

(FEED) work specified under element B-3 is appropriate, as it only encompasses design work for 

monitoring and not other project components. FEED work for injection 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 inches in diameter. 

EPA notes that, in the cost analysis for the proposed 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, unit cost B-18 applies. Unit cost B-18 accounts for 

updating the complex model every 5 years and applies to all projects under the GS rule. This 

includes 180 hours of engineer's time per site plus 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 resources must be devoted to that task. This effort is captured 

under cost item B-18 for periodic calibration and running of complex reservoir simulation 

models to track past and future migration of the CO2 plume and other reservoir parameters such 

as pressure gradients. As described above, this effort is estimated to require 180 hours per site 

plus 64 hours per injection well. For example, a site with four injection 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, injection pressures, reservoir 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 estimated 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. The 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 approach, please see the final cost analysis and 

technology and cost document in the final rule docket. 

28
Letter 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 underestimated ($10,000 per site plus $5,000 per 

injection well) 

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

Costs for wellhead and control equipment is underestimated. A wellhead (with 

Christmas Tree) alone can cost more than $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 underestimated ($60K per inch mile all inclusive). 

Surcharge for corrosion resistant 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 uncertainty/low confidence. 

Individual Response: EPA clarifies that the front end engineering cost (FEED) estimated under 

unit cost item C-1 includes the entire project FEED (including the costs of design and 

engineering as well as pre-operational logging, sampling, and testing), with the exclusion of 

FEED for monitoring wells, which is covered by unit cost item B-3. 

In the final rule, the costs for operators to compile and submit the necessary UIC permit 

applications for a given site are $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 basis; 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 injection 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. 

29
The unit cost estimate for wellhead and control equipment used in the cost analyses for both the 

proposed and final rules is based on a 2008 Petroleum 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 saline projects are greater than $100,000; these 

cost estimates are consistent with 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 injection 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 the final rule cost analysis, EPA is using an 

estimate of $83,000 per inch-mile based on pipeline cost data reported 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 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. For additional information 

on the final costing approach, please 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 construct, calibrate and simulate CO2 

fate and transport. 

Labor rates of $53.52 per hour are unrealistically low. 

Well remediation costs appear to be low - 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 uncertainty/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 projects in the proposed rule. EPA estimates this 

modeling will require 180 hours per project, plus 64 hours of engineer labor per injection well. 

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

30
However, EPA notes that the logging and plugging costs are based 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 increased the estimated labor rates significantly 

from the BLS estimates used in the cost analysis 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 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, please 

see the final cost analysis and 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 uncertainty/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 related to operations and testing 

and monitoring, including the frequency at which different MIT tests might be required. 

As described above, 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. 

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 associated 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 uncertainty/low confidence. 

Individual Response: MIT costs were developed based on the following sources: Carbon 

Dioxide Storage: Geological Security and Environmental Issues – Case Study on the Sleipner 

Field, Norway, S. Soloman, Bellona Foundation, May, 2007; UIC Program Mechanical Integrity 

31
Testing: Lessons for Carbon Capture and Storage, Jonathan Koplos, Bruce Kobelski, Anhar 

Karimjee, and Chi Ho Sham, Fifth Annual Conference on Carbon Capture and Sequestration, 

DOE/NETL, May, 2006; Determination of the Mechanical Integrity of Injection Wells, EPA 

Region 5 website, www.epa.gov/region5/water/uic/r5guid/r5_05.htm; and Underground Injection 

Control Rules, Montana Board of Oil and Gas Conservation, 

www.bogc.dnrc.state.mt.us/uicrules.htm. 

As described above, 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. For additional information 

on the final costing approach, please 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 Cost for flushing wells is estimated 

at $500; this will not cover all the materials and services required 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 

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 fluid 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 integrity test prior to plugging to evaluate integrity of casing and 

cement to remain in ground ($18,670) 

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

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

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

♣ G-12: Operating G&A ($14,162) 

The total cost of these 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 costs 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 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 

32
33

professional judgment, as shown in the appendix of the cost analysis. For additional information 

on the final costing approach, please see the final cost analysis and technology and cost 

document in the final rule docket.