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.
Federal Requirements Under the Underground Injection Control Program for 

Carbon Dioxide Geologic Sequestration Wells 

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

73 Fed. Reg. 43492 (July 25, 2008) 

Comments of the Electric Power Research Institute 

The Electric Power Research Institute (EPRI) is pleased to have the opportunity to 

provide comments on the Environmental Protection Agency’s proposed rule for the 

geologic storage (GS) of carbon dioxide (CO2) under the Underground Injection Control 

(UIC) Program, issued on July 25, 2008 (Docket ID No. EPA-HQ-OW-2008-0390), 73 

Fed. Reg. 43492. 

EPRI conducts research on key issues facing the electric power industry on behalf of its 

members, energy stakeholders, and society. EPRI was established as an independent, 

nonprofit center for public interest energy and environmental research. Our members 

represent over 90% of the electricity generated in the United States. 

EPRI supports the development of a clear (unambiguous), reasonable, and flexible 

framework that enables wide deployment of geologic storage of CO2 in a safe, 

environmentally protective, and cost-effective manner. 

We focus our comments largely on the technical aspects of the proposed rule. 

General comment

EPRI COMMENT#1: The proposed rule allows the EPA Director to make discretionary 

decisions regarding numerous program elements including, but not limited to, 

characterization, monitoring, testing, and site closure. EPRI urges EPA to provide clarity 

in the final rule regarding the technical or administrative criteria that trigger the need for 

discretionary decision making. 

Specific comments

Specific EPRI comments on the EPA preamble and draft rule follow. EPA draft rules, 

interpretations or requests for comments are shown in bold print and are identified by 

page number where they appear in the Federal Register / Vol. 73, No. 144 / Friday, July 

25, 2008 / Proposed Rules. EPRI comments immediately follow the EPA citation. 

Preamble, page 43505: “The confining system should be of sufficient regional 

thickness and lateral extent to contain the entire CO2 plume and associated pressure 

front under the confining system following the plume’s maximum lateral 

expansion.” 

 12/17/08 
EPRI COMMENT #2: The criteria for defining the leading edge of the plume and 

associated pressure front are not specified in the rule, nor is the basis for determining if 

these criteria are met — physical measurement or numerical computation. In either case, 

what minimum change in pressure from background will EPA use to define the location 

of the pressure front? Will the lateral extent of the CO2 plume be defined by the leading 

edge of the dissolved plume or free-phase portion of the plume? Given the difficulties in 

defining and measuring the leading edge of the plume and pressure front, EPRI believes 

that the technical focus should be on demonstrating caprock containment, rather than 

tracking fronts. 

Preamble, page 43505, §146.82(g), and § 146.90(d): “Today’s proposal would 

require owners or operators to submit geochemical data on a) the injection zone, b) 

the confining zones, c) containment zones above the confining zones in which any 

potentially migrating CO2 could be trapped, d) all USDWs, and e) any other 

geologic zone or formation that is important to the proposed monitoring program.” 

EPRI COMMENT #3A: EPA does not provide the technical justification for collecting 

geochemical data from all zones, geologic formations and USDWs. We believe the 

collection of data should be limited to zones needed to demonstrate system performance 

defined by the minimum siting criteria specified in §146.83(a)(1) and (a)(2). 

EPRI believes that system performance with the end goal of protecting USDW can be 

achieved by collecting geochemical data from a maximum of four zones for the reasons 

provided below: 

1) Injection zone – during site characterization, check for conditions that could lead 

to CO2-induced rock dissolution, potentially resulting in formation and injection 

well collapse (well integrity); 

2) Primary confining zone – during site characterization, check for conditions that 

could lead to caprock dissolution and degradation, potentially resulting in loss of 

CO2 containment with subsequent CO2 movement through the primary barrier 

(caprock integrity); 

3) Monitoring zone – a zone proposed by the applicant and approved by the EPA 

where performance monitoring is required to take place in accordance with 

§146.90(d). The monitoring zone would lie between the primary confining zone 

and the USDW. It would be the only zone sampled on a routine schedule during 

CO2 injection operations and closure to detect the leakage of CO2 through the 

primary confining zone (performance monitoring) as noted ; and 

4) USDW zone – during site characterization, collect optional samples at or near the 

closest USDW boundary to the injection zone to establish baseline water quality. 

EPRI COMMENT #3B: Before promulgating the rule, a comprehensive study of deep 

well fluid sampling techniques needs to be performed to ensure that the techniques cited 

by EPA consistently produce samples that are representative of deep reservoir conditions. 

Otherwise, interpretation of geochemical data derived from methods producing 

EPRI UIC comments Page 2 of 10 12/17/08 
inconsistent or non-representative sample data could result in erroneous conclusions, 

including unnecessary or inappropriate corrective action. Collecting representative deep 

well samples from confining zones is especially challenging (see EPRI comment #14). 

Preamble, page 43505-43506 and §146.83(b): “Today’s proposal would provide the 

Director the discretion to require the owner or operator to identify and characterize 

additional confining and containment zones above the primary (i.e., lowermost) 

confining zone that could further impede vertical fluid movement and allow for 

pressure dissipation ... EPA specifically seeks comment on the merits of identifying 

these additional zones.” 

EPRI COMMENT #4A: From a technical perspective, the key criterion for requiring 

additional characterization should be that the applicant cannot demonstrate compliance 

with the minimum criteria for siting a GS project specified in §146.83(a)(1) and (a)(2) -- 

specifically if the applicant must rely on [a] multiple injection zones to receive the 

anticipated total volume (§146.83(a)(1)) without fracturing the formation or displacing 

fluids or [b] multiple confining units to impede vertical movement (§146.83(a)(2)). 

Section §146.83(b) requires characterization of additional zones that will impede fluid 

movement, which seems redundant to §146.83 (a)(2). EPA should remove Section 

§146.83(b) and characterization of additional zones should be limited to those needed by 

the applicant to demonstrate capacity and containment (i.e., §146.83(a)(1) and (a)(2)). 

EPRI COMMENT #4B: The minimum siting criterion specified in §146.83(a)(2) that 

states the confining zone must be “free of transmissive faults or fractures” is too vague 

and open to interpretation by permit writers, potentially leading to inconsistent 

application throughout the United States. Faults and fractures are ubiquitous and quite 

common in deep sedimentary basins where the natural accumulation of thick sediments 

causes differential compaction and settling, resulting in fracturing and faulting. 

However, some faults and fractures are sealed or have very low transmissivity, allowing 

them to be present in the caprock without jeopardizing containment. Therefore, if taken 

literally, the language in the proposed rule could limit permitting to those sites that are 

totally “free” of faults and fractures, potentially eliminating numerous sedimentary basins 

with excellent CO2 storage potential. EPRI recommends that the EPA remove the 

language “free of transmissive faults or fractures” from this section of the rule and, 

instead, base its decision on a site-by-site demonstration of capacity and containment 

using data and model results provided by the applicant. 

EPRI COMMENT #4C: Section §146.83(b) of the rule states that the Director may 

require an applicant to characterize additional zones that will impede vertical fluid 

movement that are “free of faults and fractures.” Because fracture-free confining units 

are rare and many confining units that contain fractures can provide effective 

confinement (see EPRI Comment #4B), and because §146.83(a)(2) provides for 

additional characterization of multiple confining zones if needed, EPRI recommends that 

this section be eliminated. 

EPRI UIC comments Page 3 of 10 12/17/08 
EPRI COMMENT #4D: If EPA retains the language in the rule requiring that confining 

zones be free of transmissive faults and fractures, EPRI wants to point out that reliable 

techniques for characterizing deep faults/fractures are rudimentary. Drilling through the 

fault or fracture plane and hydraulically testing it to determine its local transmissivity is 

the most direct and reliable characterization method. EPRI is concerned about any 

requirement to characterize the hydraulic properties of faults cutting across confining 

zones because this can only be achieved by drilling through and hydraulically testing the 

fault, creating potential fast-flow pathways in the caprock, potentially jeopardizing 

containment. 

Preamble, page 43507: “Today’s proposal does not prescribe the specific cements to 

be used to plug abandoned wells ...” 

Also, preamble, page 43510: “EPA seeks comment regarding requirements for 

degradation-resistant well construction materials, such as acid-resistant cements 

and corrosion resistant casing.” 

EPRI COMMENT #5: We question the adequacy of the evidence employed to justify 

requiring the use of corrosion resistant cements in all cases. The laboratory study 

performed by Duguid, et al. (2004) cited by EPA exposed portland cement samples to 

acidified waters in an aggressive flow configuration uncharacteristic of a borehole 

environment. In contrast, the field study by Crow, et al. (2008) performed on a 30 year 

old production well is characteristic of a borehole environment. Side-wall cores of the 

casing, acoustic bond logs and well integrity tests did not show signs of casing corrosion, 

leakage or cement-bond degradation. While side-wall cores of the cement indicated that 

CO2-induced cement alteration had occurred, the hydraulic integrity of the cement seal 

was still highly effective. EPA states that the cement alteration found in the study 

demonstrates that CO2 migrated up the borehole. We question this conclusion and believe 

the study is not conclusive on this point. Given that the study was performed on a natural 

CO2 reservoir, free and dissolved CO2 are expected to be present throughout the 

stratigraphic column from the top of the reservoir through the confining unit to the 

surface. Therefore, an alternative hypothesis is that the native CO2 present in the 

confining unit or caprock adjacent to the cement seal caused the observed alteration. 

Evidence that the cement underwent greater alteration at the cement-formation interface 

adjacent to the caprock compared to the cement-casing interface located further from the 

caprock helps support this hypothesis. Most importantly, the seal maintained its integrity, 

exhibiting very low cement matrix, and low interface permeabilities, as determined by 

laboratory and vertical interference tests in the field, respectively. However, should the 

EPA eventually adopt a requirement for corrosion-resistant materials, we believe EPA is 

taking the correct approach by not prescribing the type of corrosion-resistant cements and 

casing to be used in well completions and abandonments; a number of materials are 

available and selection of a given material may be driven by site-specific well 

characteristics. 

EPRI UIC comments Page 4 of 10 12/17/08 
Duguid, A., M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia. 2004. The 

Effect of CO2 Sequestration on Oil Well Cements. Presented at the Greenhouse Gas 

Technologies Conference (GHGT–7), September 5–9, 2004. Vancouver, Canada. 

Crow, W., D.B. Williams., B. Carey, M. Celia, and S. Gasda. 2008. CO2 Capture Project 

Field Study of A Wellbore from a Natural CO2 Reservoir. Presented at the 7th Annual 

Conference on Carbon Capture and Sequestration, May 5–8, 2008. Pittsburgh, 

Pennsylvania. 

Preamble, page 43507: “EPA seeks comment on the applicability of computational 

fluid flow models for delineating the AoR of GS sites.” 

Also preamble, page 43507 “EPA seeks comment on requiring the reevaluation of 

the site AoR on a periodic basis, under what conditions the AoR should be 

reevaluated, and the appropriateness of a 10 year minimum fixed frequency for 

AoR reevaluation.” 

EPRI COMMENT #6: We believe that the use of computer models as a tool to predict the 

size of the area of review (AoR) is appropriate and provides a flexible, phased approach 

to assessing the number of abandoned wells requiring mitigation. 

The proposed rule uses an arbitrary 10-year minimum fixed frequency for AoR 

reevaluation and does not present the technical criteria EPA used in determining this 

frequency. EPRI believes that it would be more logical to base the frequency of AoR 

reevaluation on performance measures including the observed speed of the plume and its 

anticipated arrival time at the edge of the computed AoR. Or, if plume speed cannot be 

observed directly (e.g., no CO2 is observed in wells completed in the monitoring zone) 

nor indirectly (e.g., using remote monitoring techniques like seismic), then the model 

predictions for CO2 plume speed and arrival at the AoR boundary should be used to set 

the reevaluation frequency. 

Preamble, page 43508: “Today’s proposal would give the Director the discretion to 

allow owners or operators to perform corrective action on an iterative, phased basis 

over the operational life of a GS project.” 

EPRI COMMENT #7: A phased approach for corrective action simultaneously ensures 

permanence of the stored CO2 and cost-effective management of the storage operation. 

Therefore, it will encourage GS project development. 

Preamble, page 43509: “EPA seeks comment on the proposed GS well requirements 

for depth of surface casing, the cementing of long-string casing, and construction 

with a packer set opposite a cemented interval.” 

EPRI UIC comments Page 5 of 10 12/17/08 
EPRI COMMENT #8: Cementing the entire length of the long-string casing is not 

standard practice in the oil and natural gas industry and not adequately justified by EPA 

in the preamble to the rule. Compared to CO2, natural gas is highly flammable and, in the 

absence of pressure gradients, much more buoyant because of its lower density and 

higher mobility in the formation. In contrast, during CO2 injection, where pressure 

gradients are large and buoyancy effects are comparatively small, models show that CO2

dries out the formation around the well (Pruess and Spycher, 2006), significantly 

lowering the risk of cement corrosion. Therefore, cementing standards adopted for 

natural gas wells designed to be protective of USDWs should be more than adequate for 

ensuring safe and permanent sequestration of the injected CO2. Wellbore conditioning 

prior to cementing and a well designed and executed cementing operation have greater 

impact on the cement integrity than the overall length of the cement seal. EPRI 

encourages the EPA to develop and adopt less stringent cementing requirements for the 

long-string casing, consistent with natural gas wells currently in use. (See for example, 

Chapter 4 Development, Regulation, and Conservation of Oil and Gas Resources, 

Article 3 Requirements, Section 1722.4 Cementing Casing, in the State of California, 

California Code of Regulations, Title 14: Natural Resources; Division 2: Department of 

Conservation, Publication No. PRC04). 

Pruess, K. and N. Spycher, 2006. ECO2N - A New TOUGH2 Fluid Property Module for 

Studies of CO2 Storage in Saline Aquifers, Proceedings: TOUGH Symposium 2006, 

Lawrence Berkeley National Laboratory, Berkeley, California, May 15–17, 2006. 

Preamble, page 43509: “EPA seeks comment on the merits of horizontal well 

drilling techniques for GS wells and the applicability of well construction 

requirements discussed in this proposal.” 

EPRI COMMENT #9: We agree with the EPA arguments for this technology and, 

therefore, believe the merits of horizontal injection wells are correctly stated. In addition, 

the rule provides flexibility and will encourage GS project development, especially in 

lower permeability formations needing additional injectivity. 

Preamble, page 43511: “In case of well failure, a down-hole shut-off device would 

isolate the injectate below USDWs, rather than just below the surface. EPA seeks 

comment on the merits of requiring down-hole shut-off valves in GS wells.” 

EPRI COMMENT #10: Since a downhole shut-off valve would just prevent CO2 from 

flowing from the injection zone up the production tubing to the atmosphere if the 

wellhead were damaged, it doesn’t serve a function in protecting USDWs. Further, 

because, recorded cases of catastrophic wellhead failure are rare, and the valve would not 

protect CO2 from backflowing to the surface should the packer also fail, EPRI does not 

believe that a down-hole shut-off valve provides more safety than an easier-to-maintain 

near-surface shut-off valve. In addition, a downhole valve will interfere with logging 

operations, mechanical integrity testing, video inspection logs, etc. Downhole tools 

EPRI UIC comments Page 6 of 10 12/17/08 
typically associated with these activities are deployed by wireline inside the production 

tubing, requiring that the operator needlessly kill the well, and remove the tubing and 

valve to gain access to the section of well below the valve position. 

Preamble, page 43512: “In summary, EPA is soliciting comment on whether CO2

injection should be allowed into an injection zone above the lowermost USDW, 

when the Director determines that geologic conditions (e.g., thousands of feet of 

intervening formations between the injection zone and the overlying and/or 

underlying USDWs) exist that will prevent fluid movement into adjacent USDWs. 

EPA is also requesting comments on whether aquifer exemptions should be allowed 

for the purpose of Class VI injection, and under what conditions should such 

aquifer exemptions be approved. Finally, EPA seeks comment on whether the 

Agency should set a minimum injection depth requirement for CO2 GS, rather than 

require that such injection take place below the lowermost USDW.” 

EPRI COMMENT #11: EPRI believes that a proposed GS site should be considered to be 

protective of USDWs as long as the applicant demonstrates to the EPA that it meets the 

minimum siting criteria specified in §146.83(a)(1), (a)(2) (also see EPRI Comment #4). 

Whether or not the injection zone lies above or below the lower most USDW, or below a 

given depth, is not important as long as the minimum criteria are met. 

Preamble, page 43513: “EPA seeks comment on the use of tracers in CO2 GS 

operations, and any potential impact of tracers on human health or ecosystems as 

they relate to USDWs.” 

EPRI COMMENT #12: Too little is known about how tracers (especially PFT's) partition 

between the CO2, water and oil phase and how they adsorb onto organic or mineral 

surfaces at reservoir conditions (high temperatures and pressure) to conclude that they act 

as conservative tracers. Any tracer added to the CO2 that is soluble in water will lose 

mass to the water phase and will not act as a conservative tracer for the CO2 phase. EPA 

should not require the use of tracers unless and until more is known about their fate and 

transport. 

Preamble, page 43514 & 43515: “Under today’s proposal, owners or operators 

would be required to track the subsurface extent of the CO2 plume and pressure 

front using pressure gauges in the first formation overlying the confining zone or 

using indirect geophysical techniques (e.g., seismic, electrical, gravity, or 

electromagnetic surveys) or other down-hole CO2 detection tools, monitor for 

geochemical changes in subsurface formations, and if directed, monitor at the 

surface. Today’s proposal would also require owners or operators to monitor 

ground water quality and geochemical changes above the confining system.” 

EPRI COMMENT #13: Refer to EPRI comment #2 for questions regarding how EPA 

intends to define each front and the need to demonstrate containment instead. Also, EPRI 

EPRI UIC comments Page 7 of 10 12/17/08 
comments #3B and #14 for representative geochemical sampling and sampling of lowyield formations, respectively. 

EPRI is not aware of any remote field measurements, including seismic techniques, that 

can be used to determine the position of the dissolved CO2 front. Therefore, definition of 

the CO2 front should be limited to the leading edge of the free-CO2 plume if remote 

monitoring techniques are used. Remote monitoring techniques may not work in all 

geologic settings. Very small pressure changes measured in the first formation overlying 

the confining zone may be masked by other pressure effects. For example, relatively 

large barometric pressure fluctuations translated down the well to the monitoring zone, 

changes in fluid pressure caused by nearby pumping wells, or limited transducer 

resolution, accuracy and electronic noise may interfere with or distort the pressure signal, 

making it difficult to measure the pressure front. Appropriateness of detection tools will 

need to be evaluated on a site-by-site basis, and the proposed rule recognizes this need. 

However, EPRI believes the emphasis should be on demonstrating containment through 

careful characterization of the storage reservoir and caprock, coupled with predictive CO2

fate and transport models of reservoir and caprock performance, rather than on plume and 

pressure front tracking, as the latter may not be practical or possible. 

Preamble, page 43515: “Monitoring within the confining zone for pressure, pH, 

salinity, or the presence of dissolved minerals, heavy metals, or organic 

contaminants requires direct access to the subsurface via monitoring wells.” 

EPRI COMMENT #14: See EPRI comment #3B. We believe that measuring pressure in 

a deep confining zone is possible, but collecting representative deep well samples from 

confining zones for geochemical characterization may not be technically possible (with 

emphasis on representative). This could lead to erroneous results and conclusions. EPA 

currently requires that all monitoring wells be purged of “stagnant” groundwater in the 

well prior to sampling to produce a “fresh” sample from the adjacent formation that is 

representative of the formation fluid. Low-yield confining units are typically purged dry 

prior to sampling or pumped at a very slow rate to prevent the formation from being 

dewatered. In either case, this typically results in significant sample depressurization 

when sampling deep wells. Important geochemical parameters including pH, alkalinity, 

and dissolved metals (which are dependent on groundwater pH) will change when 

depressurization occurs, producing erroneous analytical results. The u-tube sample 

method described by Friefeld et al (2005) cannot be used to overcome this limitation for 

low-yield confining zones. 

Freifeld B.M., R.C. Trautz, Y.K. Kharaka, T.J. Phelps, L.R. Myer, S.D. Hovorka, D.J. 

Collins (2005) The U-tube: a novel system for acquiring borehole fluid samples from a 

deep geologic CO2 sequestration experiment. Journal of Geophysical Research, 110, 

B10203, doi:10.1029/2005JB003735. 

EPRI UIC comments Page 8 of 10 12/17/08 
Preamble, page 43517: “EPA seeks comment on the merits of requiring plans for 

monitoring, AoR, and post-injection site care as part of a permit application.” 

EPRI COMMENT #15: Submitting a monitoring and AoR plan with the application 

seems practical since these activities will occur in the reasonably near future after the 

permit is issued. However, requiring too much specificity in a post-injection site care 

plan as part of the permit application may cement in methods that will be obsolete by the 

time the GS project enters the post-injection phase, 20-50 years from the permit date. 

EPA could instead require that a preliminary post-injection site care plan be submitted at 

the time of application outlining the general approach and parameters needed to 

demonstrate closure, and that a final detailed plan be prepared for approval a certain 

period of time prior to implementation of this phase. 

Preamble, page 43518: “Today’s proposal would require owners or operators to 

submit a well plugging plan at the same time the permit application is submitted 

and to have this plan approved by the Director.” 

EPRI COMMENT #16: Again, well plugging and abandonment are activities that take 

place far in the future, perhaps several decades off. Therefore, submitting this plan at the 

time of permit application could render it obsolete when implementation is needed. EPA 

could instead require a preliminary plan outlining the general approach at the time of 

application and require that a final detailed plugging and abandonment plan be submitted 

for approval a certain period of time prior to implementation of this activity, allowing for 

the incorporation and use of new/better technologies. 

Preamble, page 43519-43520: “EPA requests comment on the proposed use of a 

tentative 50-year fixed timeframe that could be modified at the Director’s discretion 

based on monitoring and modeling data.” 

EPRI COMMENT #17: EPA’s 50-year fixed timeframe described in the preamble 

appears to be based on professional judgment interpreting a limited number of citations 

and/or modeling scenarios. We question the need for defining a fixed timeframe of any 

length because it runs counter to the EPA’s implied intent to close sites based on the 

owner/operator’s ability to meet specific performance criteria defined in §146.93(b). (See 

EPRI comment #2, #13, and #18 regarding these criteria (i.e., front tracking and 

stability)). 

Preamble, page 43520: “Once the owners or operators provide documentation that 

demonstrates that the models predicting CO2 movement are consistent with 

monitoring results and that there are no longer risks of endangerment to USDWs, 

they could request that the Director authorize site closure. EPA is also proposing to 

allow the Director to shorten or lengthen the 50-year time frame based on 

performance of the site... EPA wishes to emphasize that site closure cannot occur 

EPRI UIC comments Page 9 of 10 12/17/08 
until monitoring and modeling data establish to the Director’s satisfaction that 

potential risks of endangerment to USDWs have ceased.” 

EPRI COMMENT #18: EPA’s requirement for demonstrating plume stability for site 

closure is based on the ability to both observe and successfully model the speed and 

stability of the advancing CO2 front, a very discrete boundary that is difficult to define, 

model accurately when complex reservoir heterogeneity and fast flow pathways are 

present, and measure in the field on a large scale. (See also EPRI’s comment #2 on 

defining the front). If remote methods like surface seismic, cross-well seismic or gravity 

are not successful in tracking front position, and CO2 is never directly detected in sentinel 

observations wells, then model validation based on CO2 front position may be 

questioned. In such a case, if the model predicts the continued advance of the CO2 front 

while the observed data do not, the EPA Director may not be satisfied with the absence of 

a potential risk of endangerment to USDWs and may unnecessarily delay site closure for 

decades. EPRI recommends that the final rule contain alternative provisions for site 

closure if model validation is unsuccessful. 

EPRI UIC comments Page 10 of 10 12/17/08 
Letter ID: 0168 

Commenter: Michael J. Miller 

Organization: Electric Power Research Institute (EPRI) 

Letter ID: 0168 Comment ID: 22491 Letter Lines: 42 to 46 

Comment Code: 1260 1.1.1.5 More certainty/stringency is needed 

Comment: EPRI COMMENT#1: The proposed rule allows the EPA Director to make 

discretionary 

decisions regarding numerous program elements including, but not limited to, 

characterization, monitoring, testing, and site closure. EPRI urges EPA to 

provide clarity in the final rule regarding the technical or administrative 

criteria that trigger the need for discretionary decision making. 

Individual Response: EPA is developing guidances for States that describe the process of 

applying for and receiving primary enforcement authority (primacy) for GS Class VI wells under 

Section 1422 of SDWA, as well as the technical and administrative issues on developing GS 

regulations that are the equivalent of minimum federal criteria and requirements. The guidance 

will describe areas of Directorial discretion and considerations for how that discretion would be 

exercised. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

The Agency believes that the Class VI requirements balance site-specific flexibility with USDW 

protection. Rather than setting performance or technology-based standards for GS projects, EPA 

is adopting a flexible approach, where operators of GS projects would develop and implement 

site-specific plans for delineating the AoR, testing and monitoring the site, performing corrective 

action, and post-injection site care. EPA believes that the plans—which would be reviewed and 

approved by the Director and periodically updated throughout the life of the project—promote an 

ongoing dialogue between the operator and the Director that will encourage use of the most 

appropriate technologies for a particular project. 

Letter ID: 0168 Comment ID: 22492 Letter Lines: 56 to 70 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

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

Comment: Preamble, page 43505: "The confining system should be of sufficient regional 

thickness and lateral extent to contain the entire CO2 plume and associated 

pressure front under the confining system following the plume’s maximum lateral 

expansion." 

EPRI COMMENT #2: The criteria for defining the leading edge of the plume and 

associated pressure front are not specified in the rule, nor is the basis for 

determining if these criteria are met -- physical measurement or numerical 

1
computation. In either case, what minimum change in pressure from background 

will EPA use to define the location of the pressure front? Will the lateral 

extent of the CO2 plume be defined by the leading edge of the dissolved plume or 

free-phase portion of the plume? Given the difficulties in defining and 

measuring the leading edge of the plume and pressure front, EPRI believes that 

the technical focus should be on demonstrating caprock containment, rather than 

tracking fronts. 

Individual Response: EPA agrees that demonstrating cap rock containment is an important 

technical focal point for permitting Class VI wells, however the Agency also believes that it is 

important to know the extent of the CO2 plume and pressure front to ensure cap rock integrity 

and protection of USDWs. 

EPA clarifies that the pressure front (defined at §146.81) is the zone of elevated pressure that is 

created by the injection of CO2 into the subsurface. The pressure front of a CO2 plume refers to 

a zone where there is a pressure differential sufficient to cause the movement of injected fluids or 

formation fluids into a USDW. The pressure front includes all areas wherein pressure is great 

enough to cause fluid movement into a USDW if a conduit were to exist. 

The calculation of the threshold pressure that defines the edge of the pressure front is dependent 

on properties of the injection and confining zones, including permeability, porosity, and 

compressibility, the distance between the injection zone and the lowermost USDW, and 

operational conditions including injection pressure and rate. For these reasons, the definition of 

the pressure front is site- and project-specific, and a single pressure value can not be provided for 

all sites. EPA is developing guidance on AoR and corrective action at GS Class VI sites to assist 

owners or operators and Directors in evaluating requirements and proposed AoR and corrective 

action plans under 146.84. The guidance describes EPA's recommended approaches for the data 

to be considered in an initial AoR delineation, how to apply computational modeling to delineate 

the AoR, performing corrective action at GS sites, and, when appropriate, completing AoR 

reevaluations. The guidance will be available on EPA's web site, at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA is also developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, which will include discussion of identifying 

the extent of the CO2 plume. The guidance describes available technologies and recommended 

approaches for implementing a testing and monitoring plan, including pre-operational 

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. 

2
Letter ID: 0168 Comment ID: 22493 Letter Lines: 72 to 114 

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: Preamble, page 43505, §146.82(g), and § 146.90(d): "Today’s proposal would 

require owners or operators to submit geochemical data on a) the injection zone, 

b) the confining zones, c) containment zones above the confining zones in which 

any potentially migrating CO2 could be trapped, d) all USDWs, and e) any other 

geologic zone or formation that is important to the proposed monitoring 

program." 

EPRI COMMENT #3A: EPA does not provide the technical justification for 

collecting geochemical data from all zones, geologic formations and USDWs. We 

believe the collection of data should be limited to zones needed to demonstrate 

system performance defined by the minimum siting criteria specified in 

§146.83(a)(1) and (a)(2). EPRI believes that system performance with the end 

goal of protecting USDW can be achieved by collecting geochemical data from a 

maximum of four zones for the reasons provided below: 

1) Injection zone -- during site characterization, check for conditions that 

could lead to CO2-induced rock dissolution, potentially resulting in formation 

and injection well collapse (well integrity); 

2) Primary confining zone -- during site characterization, check for conditions 

that could lead to caprock dissolution and degradation, potentially resulting in 

loss of CO2 containment with subsequent CO2 movement through the primary barrier 

(caprock integrity); 

3) Monitoring zone -- a zone proposed by the applicant and approved by the EPA 

where performance monitoring is required to take place in accordance with 

§146.90(d). The monitoring zone would lie between the primary confining zone and 

the USDW. It would be the only zone sampled on a routine schedule during CO2 

injection operations and closure to detect the leakage of CO2 through the 

primary confining zone (performance monitoring) as noted ; and 

4) USDW zone -- during site characterization, collect optional samples at or 

near the closest USDW boundary to the injection zone to establish baseline water 

quality. 

EPRI COMMENT #3B: Before promulgating the rule, a comprehensive study of deep 

well fluid sampling techniques needs to be performed to ensure that the 

techniques cited by EPA consistently produce samples that are representative of 

deep reservoir conditions. Otherwise, interpretation of geochemical data derived 

from methods producing inconsistent or non-representative sample data could 

result in erroneous conclusions, including unnecessary or inappropriate 

3
corrective action. Collecting representative deep well samples from confining 

zones is especially challenging (see EPRI comment #14). 

Individual Response: The GS regulation, at §146.82(a)(6), requires the owner or operator to 

submit baseline geochemical data on subsurface geologic formations. EPA is not specifying for 

which formations this information should be submitted to allow flexibility, but examples may 

include the following formations: a) the injection zone, b) the confining zones, c) containment 

zones above the confining zones in which any potentially migrating CO2 could be trapped, d) all 

USDWs, and e) any other geologic zone or formation that is important to the proposed 

monitoring program. The Director has the authority to request additional geochemical data as 

well. 

EPA believes that the necessary sampling techniques are available, and 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. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

On the topic of sampling, EPA recognizes that the collection of representative ground water 

samples from depth poses challenges and that special methods, such as U-tubes, will be needed 

to preserve the integrity of such samples. 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 pre-operational 

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. 

Regarding the comment about the technical justifications and difficulty of sampling within the 

confining zone, EPA clarifies that §146.90(d) requires owners and operators to monitor ground 

water quality and geochemical changes above the confining zone(s), rather than within the 

confining zone. 

Letter ID: 0168 Comment ID: 22494 Letter Lines: 116 to 134 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: Preamble, page 43505-43506 and §146.83(b): "Today’s proposal would provide the 

Director the discretion to require the owner or operator to identify and 

characterize additional confining and containment zones above the primary (i.e., 

4
lowermost) confining zone that could further impede vertical fluid movement and 

allow for pressure dissipation ... EPA specifically seeks comment on the merits 

of identifying these additional zones." 

EPRI COMMENT #4A: From a technical perspective, the key criterion for requiring 

additional characterization should be that the applicant cannot demonstrate 

compliance with the minimum criteria for siting a GS project specified in 

§146.83(a)(1) and (a)(2) -- specifically if the applicant must rely on [a] 

multiple injection zones to receive the anticipated total volume (§146.83(a)(1)) 

without fracturing the formation or displacing fluids or [b] multiple confining 

units to impede vertical movement (§146.83(a)(2)). Section §146.83(b) requires 

characterization of additional zones that will impede fluid movement, which 

seems redundant to §146.83 (a)(2). EPA should remove Section §146.83(b) and 

characterization of additional zones should be limited to those needed by the 

applicant to demonstrate capacity and containment (i.e., §146.83(a)(1) and (a) 

(2)). 

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 

whole and promote better modeling of the site. 

Letter ID: 0168 Comment ID: 22495 Letter Lines: 136 to 151 

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment: EPRI COMMENT #4B: The minimum siting criterion specified in §146.83(a)(2) that 

states the confining zone must be "free of transmissive faults or fractures" is 

too vague and open to interpretation by permit writers, potentially leading to 

inconsistent application throughout the United States. Faults and fractures are 

ubiquitous and quite common in deep sedimentary basins where the natural 

accumulation of thick sediments causes differential compaction and settling, 

resulting in fracturing and faulting. However, some faults and fractures are 

sealed or have very low transmissivity, allowing them to be present in the 

caprock without jeopardizing containment. Therefore, if taken literally, the 

language in the proposed rule could limit permitting to those sites that are 

totally "free" of faults and fractures, potentially eliminating numerous 

5
sedimentary basins with excellent CO2 storage potential. EPRI recommends that 

the EPA remove the language "free of transmissive faults or fractures" from this 

section of the rule and, instead, base its decision on a site-by-site 

demonstration of capacity and containment using data and model results provided 

by the applicant. 

Individual Response: EPA disagrees that the language is vague. The Agency believes that the 

requirement at §146.83(a)(2) that the confining zone be free of transmissive faults or fractures is 

appropriate for Class VI wells and is necessary to ensure containment of the injectate and that 

requiring the confining zone to be free of transmissive faults maximizes protection of USDWs 

from endangerment. Class I hazardous waste injection well operators must also meet a similar 

requirement that the site is free of transmissive faults or fractures; they have successfully made 

such demonstrations in the past. 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. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0168 Comment ID: 22496 Letter Lines: 153 to 159 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: EPRI COMMENT #4C: Section §146.83(b) of the rule states that the Director may 

require an applicant to characterize additional zones that will impede vertical 

fluid movement that are "free of faults and fractures." Because fracture-free 

confining units are rare and many confining units that contain fractures can 

provide effective confinement (see EPRI Comment #4B), and because §146.83(a)(2) 

provides for additional characterization of multiple confining zones if needed, 

EPRI recommends that this section be eliminated. 

Individual Response: The Agency believes that the requirement at §146.83(a)(2) that the 

confining zone(s) be free of transmissive faults or fractures is appropriate for Class VI wells and 

is necessary to ensure containment of the injectate and that requiring the confining zone to be 

free of transmissive faults maximizes protection of USDWs from endangerment. 

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, 

6
mitigation, and remediation. 

Letter ID: 0168 Comment ID: 22497 Letter Lines: 161 to 170 

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment: EPRI COMMENT #4D: If EPA retains the language in the rule requiring that 

confining zones be free of transmissive faults and fractures, EPRI wants to 

point out that reliable techniques for characterizing deep faults/fractures are 

rudimentary. Drilling through the fault or fracture plane and hydraulically 

testing it to determine its local transmissivity is the most direct and reliable 

characterization method. EPRI is concerned about any requirement to characterize 

the hydraulic properties of faults cutting across confining zones because this 

can only be achieved by drilling through and hydraulically testing the fault, 

creating potential fast-flow pathways in the caprock, potentially jeopardizing 

containment. 

Individual Response: While core samples obtained through drilling and hydraulic testing are 

direct methods to obtain such information, geophysical techniques such as seismic or 

electromagnetic surveys can also be used in many geologic settings to demonstrate the absence 

of or identify and characterize the presence of faults or fractures. At sites where deep faults (even 

with little or no surface expression) are present, processing and interpreting data from multiple 

geophysical sensing methods has been shown to detect faults better than analysis of data from 

individual methods (Goussev et al, 2004). Drilling through faults or fractures with appropriate 

well design, materials, and operation, would not result in an increase in their permeability or a 

decrease in CO2 containment properties of the related CO2 storage reservoir. In some cases, the 

use of complementary drilling and geophysical methods might provide the most dependable 

characterization of potential transmissive faults and fractures. EPA adds that the Director must 

evaluate all geologic data on the site to ensure protection of USDWs from endangerment before 

approving a site for a GS project. 

Letter ID: 0168 Comment ID: 22498 Letter Lines: 172 to 216 

Comment Code: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking 

comment) 

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: Preamble, page 43507: "Today’s proposal does not prescribe the specific cements 

to be used to plug abandoned wells..." 

Also, preamble, page 43510: "EPA seeks comment regarding requirements for 

7
degradation-resistant well construction materials, such as acid-resistant 

cements and corrosion resistant casing." 

EPRI COMMENT #5: We question the adequacy of the evidence employed to justify 

requiring the use of corrosion resistant cements in all cases. The laboratory 

study performed by Duguid, et al. (2004) cited by EPA exposed portland cement 

samples to acidified waters in an aggressive flow configuration uncharacteristic 

of a borehole environment. In contrast, the field study by Crow, et al. (2008) 

performed on a 30 year old production well is characteristic of a borehole 

environment. Side-wall cores of the casing, acoustic bond logs and well 

integrity tests did not show signs of casing corrosion, leakage or cement-bond 

degradation. While side-wall cores of the cement indicated that CO2-induced 

cement alteration had occurred, the hydraulic integrity of the cement seal was 

still highly effective. EPA states that the cement alteration found in the study 

demonstrates that CO2 migrated up the borehole. We question this conclusion and 

believe the study is not conclusive on this point. Given that the study was 

performed on a natural CO2 reservoir, free and dissolved CO2 are expected to be 

present throughout the stratigraphic column from the top of the reservoir 

through the confining unit to the surface. Therefore, an alternative hypothesis 

is that the native CO2 present in the confining unit or caprock adjacent to the 

cement seal caused the observed alteration. Evidence that the cement underwent 

greater alteration at the cement-formation interface adjacent to the caprock 

compared to the cement-casing interface located further from the caprock helps 

support this hypothesis. Most importantly, the seal maintained its integrity, 

exhibiting very low cement matrix, and low interface permeabilities, as 

determined by laboratory and vertical interference tests in the field, 

respectively. However, should the EPA eventually adopt a requirement for 

corrosion-resistant materials, we believe EPA is taking the correct approach by 

not prescribing the type of corrosion-resistant cements and casing to be used in 

well completions and abandonments; a number of materials are available and 

selection of a given material may be driven by site-specific well 

characteristics. 

Duguid, A., M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia. 2004. 

The Effect of CO2 Sequestration on Oil Well Cements. Presented at the Greenhouse 

Gas Technologies Conference (GHGT-7), September 5-9, 2004. Vancouver, Canada. 

Crow, W., D.B. Williams., B. Carey, M. Celia, and S. Gasda. 2008. CO2 Capture 

Project Field Study of A Wellbore from a Natural CO2 Reservoir. Presented at the 

7th Annual Conference on Carbon Capture and Sequestration, May 5-8, 2008. 

Pittsburgh, Pennsylvania. 

Individual Response: EPA considered both field and lab studies in developing the requirements 

for Class VI well construction. The Duguid study referenced by the commenter examined a 

CO2-saturated brine flux condition that may be found in some injection environments such as a 

saline aquifer. The Crow study mentioned was a well that produced gaseous CO2 from a natural 

8
CO2 deposit. In the studies examined, cement alteration and corrosion was found to occur at 

differing rates. Factors such as contact with brine, temperature, CO2 flux, and time between 

cement curing and CO2 exposure may all be relevant. See the discussion of Class VI well 

construction requirements in the preamble to the final GS rule for additional information. 

EPA clarifies that corrosion-resistant cement is not specifically required in a Class VI injection 

well. Rather, as stated in §146.86(b)(1), casings and cement used must have sufficient strength 

and be designed for the life of the sequestration project. Further, materials must meet standards 

listed in the rule and be compatible with fluids with which the materials may be expected to 

come into contact. Therefore, some well materials may need to be acid-resistant and some may 

not if they do not come in contact with the CO2 stream or other corrosive fluids and if approved 

by the Director. 

EPA clarifies that the GS rule does not prescribe the specific cements to be used to plug 

abandoned wells in the AoR because industry standards, such as those developed by API or 

ASTM International, reflect the current state of the science and the expertise of industrial users 

on CO2-compatible materials, as specified in §146.92(b). Providing flexibility to choose 

materials for plugging, provided they are compatible with the injected fluid, is consistent with 

requirements for other injection well classes and will allow operators to utilize improved well 

technologies as they become available in the future without a need to amend the regulation. 

EPA plans to, every six years, collect and review project data on early GS projects and continue 

to monitor field and laboratory research 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: 0168 Comment ID: 22499 Letter Lines: 218 to 219 ; 226 to 228 

Comment Code: 3310 2.2.1.1 Comments in favor of requiring computational models to 

delineate the AoR (seeking comment) 

Comment: Preamble, page 43507: "EPA seeks comment on the applicability of computational 

fluid flow models for delineating the AoR of GS sites." 

EPRI COMMENT #6: We believe that the use of computer models as a tool to predict 

the size of the area of review (AoR) is appropriate and provides a flexible, 

phased approach to assessing the number of abandoned wells requiring mitigation. 

Individual Response: EPA acknowledges the commenter’s support and agrees that predicting 

the complex multiphase, buoyant flow of the CO2, co-injectates, and compounds that may be 

mobilized due to injection requires the sophistication of computational models, as required at 

§146.84(c)(1). Models can predict CO2 fate and transport, as well as changes in formation 

pressure, in three dimensions, as a function of time in order to delineate the subsurface storage 

site and the AoR. Models can account for site-specific and predicted operating conditions as well 

as geologic heterogeneities and potential migration through faults, fractures, and artificial 

penetrations. 

9
Letter ID: 0168 Comment ID: 22500 Letter Lines: 221 to 224 ; 230 to 239 

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

Comment: Also preamble, page 43507 "EPA seeks comment on requiring the reevaluation of 

the site AoR on a periodic basis, under what conditions the AoR should be 

reevaluated, and the appropriateness of a 10 year minimum fixed frequency for 

AoR reevaluation." 

The proposed rule uses an arbitrary 10-year minimum fixed frequency for AoR 

reevaluation and does not present the technical criteria EPA used in determining 

this frequency. EPRI believes that it would be more logical to base the 

frequency of AoR reevaluation on performance measures including the observed 

speed of the plume and its anticipated arrival time at the edge of the computed 

AoR. Or, if plume speed cannot be observed directly (e.g., no CO2 is observed in 

wells completed in the monitoring zone) nor indirectly (e.g., using remote 

monitoring techniques like seismic), then the model predictions for CO2 plume 

speed and arrival at the AoR boundary should be used to set the reevaluation 

frequency. 

Individual Response: EPA disagrees that the requirement at §146.84(e) for a periodic AoR 

reevaluation is arbitrary. EPA proposed the ten-year frequency based on input from stakeholders 

and experts at the technical workshops on "Geological Considerations and AoR Studies" and 

"Modeling and Reservoir Simulation for Geologic Carbon Storage." EPA also requested 

comment on the ten-year frequency. In the preamble to the proposed rule, EPA identified 

benefits to periodically reevaluating the AoR, including allowing refinement to the AoR 

delineation based on real-world conditions and monitoring results, increasing confidence in the 

modeled predictions, and targeting monitoring in those areas subject to the greatest potential risk. 

Based on the comments received (including those by water associations, an energy company, 

associations, industries, states, and environmental groups), EPA has changed the minimum 

frequency for the AoR reevaluation from 10 years to at least every 5 years. EPA believes that 

this revised frequency addresses commenters' concerns about the inherent uncertainties in 

modeling CO2 movement, the emerging nature of GS technology, risk-based targeting of 

monitoring activities, and the unique nature of CO2 GS. 

EPA believes that periodic AoR reevaluation at a set frequency is necessary to ensure protection 

of USDWs from endangerment and address the uncertainties inherent in predictive modeling. 

Periodic AoR reevaluations at §146.84(e) ensure that a deliberate effort is made to verify, based 

on monitoring and operational data, that the CO2 plume is moving within the subsurface as 

predicted. EPA believes that less frequent reevaluations may not be sufficient to appropriately 

model plume and pressure front movement, establish conditions for corrective action, and ensure 

protection of USDWs from endangerment. 

EPA adds that the GS rule at §146.84(e) requires the AoR reevaluation, along with the iterative 

10
process of developing and executing the various plans required of GS well operators (e.g., for 

AoR and corrective action, testing and monitoring, injection well plugging, post-injection site 

care, and emergency and remedial response) instead of period permit renewals (e.g., of 10 years 

for Class I wells). EPA believes the iterative process and subsequent reevaluations of the AoR 

and corrective action, testing and monitoring, and emergency and remedial response plans are 

preferable to a periodic permit reapplication and review of the entire permit because they focus 

time and resources to the most critical aspects of the permit. Additionally, AoRs reevaluated 

after at least every 5 years of injection will provide data on GS projects to inform EPA's adaptive 

rulemaking approach. 

Letter ID: 0168 Comment ID: 22501 Letter Lines: 241 to 247 

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action 

Comment: Preamble, page 43508: "Today’s proposal would give the Director the discretion 

to allow owners or operators to perform corrective action on an iterative, 

phased basis over the operational life of a GS project." 

EPRI COMMENT #7: A phased approach for corrective action simultaneously ensures 

permanence of the stored CO2 and cost-effective management of the storage 

operation. Therefore, it will encourage GS project development. 

Individual Response: EPA acknowledges the commenter’s support of phased corrective action 

and agrees that phased corrective action may provide many benefits to a project including, but 

not limited to, spreading the burden of cost, avoiding delays in project start-up, allowing for use 

of future, improved corrective action techniques and addressing unanticipated changes in the 

movement of the CO2 plume or pressure front. EPA believes that the phased corrective action 

approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS 

regulation. 

Letter ID: 0168 Comment ID: 22502 Letter Lines: 249 to 275 

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

Comment: Preamble, page 43509: "EPA seeks comment on the proposed GS well requirements 

for depth of surface casing, the cementing of long-string casing, and 

construction with a packer set opposite a cemented interval." 

EPRI COMMENT #8: Cementing the entire length of the long-string casing is not 

standard practice in the oil and natural gas industry and not adequately 

justified by EPA in the preamble to the rule. Compared to CO2, natural gas is 

highly flammable and, in the absence of pressure gradients, much more buoyant 

because of its lower density and higher mobility in the formation. In contrast, 

during CO2 injection, where pressure gradients are large and buoyancy effects 

11
are comparatively small, models show that CO2 dries out the formation around the 

well (Pruess and Spycher, 2006), significantly lowering the risk of cement 

corrosion. Therefore, cementing standards adopted for natural gas wells designed 

to be protective of USDWs should be more than adequate for ensuring safe and 

permanent sequestration of the injected CO2. Wellbore conditioning prior to 

cementing and a well designed and executed cementing operation have greater 

impact on the cement integrity than the overall length of the cement seal. EPRI 

encourages the EPA to develop and adopt less stringent cementing requirements 

for the long-string casing, consistent with natural gas wells currently in use. 

(See for example, Chapter 4 Development, Regulation, and Conservation of Oil and 

Gas Resources, Article 3 Requirements, Section 1722.4 Cementing Casing, in the 

State of California, California Code of Regulations, Title 14: Natural 

Resources; Division 2: Department of Conservation, Publication No. PRC04). 

Pruess, K. and N. Spycher, 2006. ECO2N - A New TOUGH2 Fluid Property Module for 

Studies of CO2 Storage in Saline Aquifers, Proceedings: TOUGH Symposium 2006, 

Lawrence Berkeley National Laboratory, Berkeley, California, May 15-17, 2006. 

Individual Response: EPA disagrees that the construction requirements for Class VI wells at 

§146.86 are not justifiable. The Class VI well requirements address the unique nature of CO2 GS 

(including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence 

of water, the potential presence of impurities in captured CO2, and its mobility within subsurface 

geologic formations), and were informed by numerous stakeholder workshops, EPA and DOE 

research, and oil and gas industry studies on well construction. EPA adds that commenters 

representing states, a water association, and industry supported this provision, saying that the 

requirement provides, at a reasonable cost, corrosion protection of the casing; prevents 

undesirable migration of fluids behind the casing; provides support to the casing; and provides 

multiple barriers against endangerment of USDWs. EPA adds that cementing of deep wells has 

been performed successfully in the past, for example, by owners or operators of Class I 

hazardous and Class I municipal waste disposal wells. Some of these wells, which must meet the 

same cementing requirements for long-string casing as Class VI wells, are up to 12,000 feet deep 

(EPA, 2001). 

EPA recognizes that the GS rule includes requirements (e.g., cementing the entire length of the 

long-string casing) that are not standard practice in the oil and natural gas industry, but believes 

that there are significant operational differences between ER and GS. For example, the volume 

of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. 

Reservoir pressure conditions will be different, with Class VI injection operations involving 

large volumes of CO2 and likely having higher pressures within their storage formations than 

Class II ER projects. In addition, CO2 in the presence of water may be corrosive to well 

materials. For these reasons, EPA believes that GS is sufficiently different from Class II ER 

operations to warrant the tailored construction requirements for Class VI wells at §146.86. 

Letter ID: 0168 Comment ID: 22503 Letter Lines: 277 to 285 

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment) 

12
Comment: Preamble, page 43509: "EPA seeks comment on the merits of horizontal well 

drilling techniques for GS wells and the applicability of well construction 

requirements discussed in this proposal." 

EPRI COMMENT #9: We agree with the EPA arguments for this technology and, 

therefore, believe the merits of horizontal injection wells are correctly 

stated. In addition, the rule provides flexibility and will encourage GS project 

development, especially in lower permeability formations needing additional 

injectivity. 

Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In 

the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques 

for Class VI wells, and commenters representing energy companies, electric utilities, the oil and 

gas industry, CCS associations, states, and the public, unanimously supported the concept and 

provided many reasons why horizontal wells could be beneficial at GS sites. Based on an 

evaluation of these comments and additional research by EPA, the Agency has concluded that 

horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to 

meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment. 

Letter ID: 0168 Comment ID: 22504 Letter Lines: 287 to 302 

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

Comment: Preamble, page 43511: "In case of well failure, a down-hole shut-off device 

would isolate the injectate below USDWs, rather than just below the surface. EPA 

seeks comment on the merits of requiring down-hole shut-off valves in GS wells." 

EPRI COMMENT #10: Since a downhole shut-off valve would just prevent CO2 from 

flowing from the injection zone up the production tubing to the atmosphere if 

the wellhead were damaged, it doesn’t serve a function in protecting USDWs. 

Further, because, recorded cases of catastrophic wellhead failure are rare, and 

the valve would not protect CO2 from backflowing to the surface should the 

packer also fail, EPRI does not believe that a down-hole shut-off valve provides 

more safety than an easier-to-maintain near-surface shut-off valve. In addition, 

a downhole valve will interfere with logging operations, mechanical integrity 

testing, video inspection logs, etc. Downhole tools typically associated with 

these activities are deployed by wireline inside the production tubing, 

requiring that the operator needlessly kill the well, and remove the tubing and 

valve to gain access to the section of well below the valve position. 

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 

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discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. 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. 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. 

EPA believes that requiring automatic surface shut-off devices instead of down-hole devices for 

onshore wells provides more flexibility to owners or operators when performing required 

mechanical integrity tests. Additionally, this requirement addresses concerns about risks 

associated with routine well workovers that may be complicated by the presence of down-hole 

devices while still maintaining USDW protection. 

Letter ID: 0168 Comment ID: 22505 Letter Lines: 304 to 320 

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

USDW 

Comment: Preamble, page 43512: "In summary, EPA is soliciting comment on whether CO2 

injection should be allowed into an injection zone above the lowermost USDW, 

when the Director determines that geologic conditions (e.g., thousands of feet 

of intervening formations between the injection zone and the overlying and/or 

underlying USDWs) exist that will prevent fluid movement into adjacent USDWs. 

EPA is also requesting comments on whether aquifer exemptions should be allowed 

for the purpose of Class VI injection, and under what conditions should such 

aquifer exemptions be approved. Finally, EPA seeks comment on whether the Agency 

should set a minimum injection depth requirement for CO2 GS, rather than require 

that such injection take place below the lowermost USDW." 

EPRI COMMENT #11: EPRI believes that a proposed GS site should be considered to 

be protective of USDWs as long as the applicant demonstrates to the EPA that it 

meets the minimum siting criteria specified in §146.83(a)(1), (a)(2) (also see 

EPRI Comment #4). Whether or not the injection zone lies above or below the 

lower most USDW, or below a given depth, is not important as long as the minimum 

criteria are met. 

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. It 

establishes: 1) requirements specifying information that owners or operators must submit, and 

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of 

a waiver application and for Director-Regional Administrator communication; 3) the waiver 

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issuance process; and, 4) additional requirements that apply to owners or operators of Class VI 

wells granted a waiver of the injection depth requirements to ensure USDW protection above and 

below the injection zone. 

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, 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: 0168 Comment ID: 22506 Letter Lines: 322 to 332 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

(seeking comment) 

Comment: Preamble, page 43513: "EPA seeks comment on the use of tracers in CO2 GS 

operations, and any potential impact of tracers on human health or ecosystems as 

they relate to USDWs." 

EPRI COMMENT #12: Too little is known about how tracers (especially PFT's) 

partition between the CO2, water and oil phase and how they adsorb onto organic 

or mineral surfaces at reservoir conditions (high temperatures and pressure) to 

conclude that they act as conservative tracers. Any tracer added to the CO2 that 

is soluble in water will lose mass to the water phase and will not act as a 

conservative tracer for the CO2 phase. EPA should not require the use of tracers 

unless and until more is known about their fate and transport. 

Individual Response: EPA agrees that the use of tracers should not be required at all GS sites, 

but should be available as an option. For this reason, EPA does not require the use of tracers at 

all GS sites; however, the Director has discretion to require their use if he/she determines that the 

use of tracers could improve monitoring of the site and enhance USDW protection from 

endangerment. The rule will also allow their use if proposed by the owner or operator and 

approved by the Director. 

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For 

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of 

tracers, including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases 

krypton, neon, and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; 

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McCallum et al., 2005) found that tracers can provide useful CO2 monitoring information at 

injection wells at depth and at near-surface locations. At Frio, tracers enabled quantification of 

CO2 plume behavior and provided a technique for model validity testing (McCallum et al., 

2005). EPA will continue to track research related to tracer use. The Agency plans to, every six 

years, collect and review data 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: 0168 Comment ID: 22507 Letter Lines: 334 to 364 

Comment Code: 4655 2.6.5.1 Plume tracking techniques/geophysical methods (seeking 

comment) 

Comment: Preamble, page 43514 & 43515: "Under today’s proposal, owners or operators 

would be required to track the subsurface extent of the CO2 plume and pressure 

front using pressure gauges in the first formation overlying the confining zone 

or using indirect geophysical techniques (e.g., seismic, electrical, gravity, or 

electromagnetic surveys) or other down-hole CO2 detection tools, monitor for 

geochemical changes in subsurface formations, and if directed, monitor at the 

surface. Today’s proposal would also require owners or operators to monitor 

ground water quality and geochemical changes above the confining system." 

EPRI COMMENT #13: Refer to EPRI comment #2 for questions regarding how EPA 

intends to define each front and the need to demonstrate containment instead. 

Also, EPRI comments #3B and #14 for representative geochemical sampling and 

sampling of low-yield formations, respectively. 

EPRI is not aware of any remote field measurements, including seismic 

techniques, that can be used to determine the position of the dissolved CO2 

front. Therefore, definition of the CO2 front should be limited to the leading 

edge of the free-CO2 plume if remote monitoring techniques are used. Remote 

monitoring techniques may not work in all geologic settings. Very small pressure 

changes measured in the first formation overlying the confining zone may be 

masked by other pressure effects. For example, relatively large barometric 

pressure fluctuations translated down the well to the monitoring zone, changes 

in fluid pressure caused by nearby pumping wells, or limited transducer 

resolution, accuracy and electronic noise may interfere with or distort the 

pressure signal, making it difficult to measure the pressure front. 

Appropriateness of detection tools will need to be evaluated on a site-by-site 

basis, and the proposed rule recognizes this need. However, EPRI believes the 

emphasis should be on demonstrating containment through careful characterization 

of the storage reservoir and caprock, coupled with predictive CO2 fate and 

transport models of reservoir and caprock performance, rather than on plume and 

pressure front tracking, as the latter may not be practical or possible. 

Individual Response: In response to comments regarding the pressure front at GS sites, EPA 

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clarifies that the pressure front (defined at §146.81) is the zone of elevated pressure that is 

created by the injection of CO2 into the subsurface. The pressure front of a CO2 plume refers to 

a zone where there is a pressure differential sufficient to cause the movement of injected fluids or 

formation fluids into a USDW. The pressure front includes all areas wherein pressure is great 

enough to cause fluid movement into a USDW if a conduit were to exist. The calculation of the 

threshold pressure that defines the edge of the pressure front is dependent on properties of the 

injection and confining zones, including permeability, porosity, and compressibility, the distance 

between the injection zone and the lowermost USDW, and operational conditions including 

injection pressure and rate. For these reasons, the definition of the pressure front is site- and 

project-specific, and a single pressure value can not be provided for all sites. 

EPA has revised the final rule, at §146.90(g), to require owners or operators to perform 

monitoring to track the extent of the CO2 plume and pressure front. The owner or operator must 

use direct methods to monitor for pressure changes in the injection zone. Indirect methods (e.g., 

seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) 

are required unless the Director determines, based on site-specific geology that such methods are 

not appropriate. 

EPA believes that pressure monitoring in the injection zone is necessary to track the 

development and movement of the pressure front and CO2 plume. Monitoring can also identify 

needed remedial actions, provide inputs for AoR reevaluation modeling, evaluate predictions of 

plume movement, and target 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 is affording Director's discretion regarding the use of geophysical techniques at some sites 

because the Agency recognizes that geophysical methods are not appropriate in all geologic 

settings. For example, geophysical methods are difficult to execute in areas that are structurally 

and topographically complex or where lithologies have limited contrast in density, porosity, 

permeability, and other physical properties. EPA clarifies that this determination will be made by 

the Director based on the site-specific geologic information submitted by the owner or operator 

with their permit application. 

Letter ID: 0168 Comment ID: 22508 Letter Lines: 366 to 389 

Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: Preamble, page 43515: "Monitoring within the confining zone for pressure, pH, 

salinity, or the presence of dissolved minerals, heavy metals, or organic 

contaminants requires direct access to the subsurface via monitoring wells." 

EPRI COMMENT #14: See EPRI comment #3B. We believe that measuring pressure in a 

deep confining zone is possible, but collecting representative deep well samples 

from confining zones for geochemical characterization may not be technically 

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possible (with emphasis on representative). This could lead to erroneous 

results and conclusions. EPA currently requires that all monitoring wells be 

purged of "stagnant" groundwater in the well prior to sampling to produce a 

"fresh" sample from the adjacent formation that is representative of the 

formation fluid. Low-yield confining units are typically purged dry prior to 

sampling or pumped at a very slow rate to prevent the formation from being 

dewatered. In either case, this typically results in significant sample 

depressurization when sampling deep wells. Important geochemical parameters 

including pH, alkalinity, and dissolved metals (which are dependent on 

groundwater pH) will change when depressurization occurs, producing erroneous 

analytical results. The u-tube sample method described by Friefeld et al (2005) 

cannot be used to overcome this limitation for low-yield confining zones. 

Freifeld B.M., R.C. Trautz, Y.K. Kharaka, T.J. Phelps, L.R. Myer, S.D. Hovorka, 

D.J. Collins (2005) The U-tube: a novel system for acquiring borehole fluid 

samples from a deep geologic CO2 sequestration experiment. Journal of 

Geophysical Research, 110, B10203, doi:10.1029/2005JB003735. 

Individual Response: As described above, EPA recognizes that the collection of representative 

ground water samples from depth poses challenges and that special methods, such as U-tubes, 

will be needed to preserve the integrity of such samples. 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. 

Letter ID: 0168 Comment ID: 22509 Letter Lines: 391 to 416 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Preamble, page 43517: "EPA seeks comment on the merits of requiring plans for 

monitoring, AoR, and post-injection site care as part of a permit application." 

EPRI COMMENT #15: Submitting a monitoring and AoR plan with the application 

seems practical since these activities will occur in the reasonably near future 

after the permit is issued. However, requiring too much specificity in a postinjection site care plan as part of the permit application may cement in methods 

that will be obsolete by the time the GS project enters the post-injection 

phase, 20-50 years from the permit date. EPA could instead require that a 

preliminary post-injection site care plan be submitted at the time of 

application outlining the general approach and parameters needed to demonstrate 

closure, and that a final detailed plan be prepared for approval a certain 

period of time prior to implementation of this phase. 

Preamble, page 43518: "Today’s proposal would require owners or operators to 

submit a well plugging plan at the same time the permit application is submitted 

and to have this plan approved by the Director." 

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EPRI COMMENT #16: Again, well plugging and abandonment are activities that take 

place far in the future, perhaps several decades off. Therefore, submitting 

this plan at the time of permit application could render it obsolete when 

implementation is needed. EPA could instead require a preliminary plan 

outlining the general approach at the time of application and require that a 

final detailed plugging and abandonment plan be submitted for approval a certain 

period of time prior to implementation of this activity, allowing for the 

incorporation and use of new/better technologies. 

Individual Response: EPA believes that incorporating the plans into the permit rather than 

establishing specific requirements for corrective action, monitoring, injection well plugging, and 

post-injection site care in the regulation provide the appropriate flexibility to address the variety 

of site-specific conditions that may be encountered at GS sites. 

EPA also believes that it is appropriate to require owners and operators to submit all plans, 

including the injection well plugging and post-injection site care and site closure plans, at the 

time of permit application. EPA believes that the Director needs a satisfactory level of assurance 

that the owner or operator has planned for these events before injection commences and that the 

owner or operator has ensured that appropriate financial resources are available to fund all 

required activities, as required at §146.85. The final rule retains requirements for submitting 

these plans with the permit application at §146.82(a). EPA believes that the requirement for this 

and other plans associated with GS projects will promote an ongoing dialogue between the 

owner or operator and the Director to ensure USDWs are protected from endangerment. In 

addition, these plans will support a demonstration that owners and operators have adequate 

financial resources to meet well plugging and post-injection site care and site closure 

requirements. 

EPA recognizes that the injection well plugging and post-injection site care and site closure plans 

may need to be modified when injection ceases, as well as prior to site closure, which is why 

§146.92(c) and §146.93(a) require review of these plans to ascertain whether the plan needs to be 

modified. EPA notes that §144.39 and §144.41 contain requirements regarding permit 

modifications that may be triggered as a result of these plan modifications. 

Please see the final rule and the discussion of the Class VI project plans in the preamble for 

additional information. 

Letter ID: 0168 Comment ID: 22510 Letter Lines: 418 to 428 

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

Comment: Preamble, page 43519-43520: "EPA requests comment on the proposed use of a 

tentative 50-year fixed timeframe that could be modified at the Director’s 

discretion based on monitoring and modeling data." 

EPRI COMMENT #17: EPA’s 50-year fixed timeframe described in the preamble 

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appears to be based on professional judgment interpreting a limited number of 

citations and/or modeling scenarios. We question the need for defining a fixed 

timeframe of any length because it runs counter to the EPA’s implied intent to 

close sites based on the owner/operator’s ability to meet specific performance 

criteria defined in §146.93(b). (See EPRI comment #2, #13, and #18 regarding 

these criteria (i.e., front tracking and stability)). 

Individual Response: EPA disagrees with this comment. In determining the post-injection site 

care-timeframe for the proposed regulation, EPA reviewed industry reports, existing 

environmental programs, and initial GS research studies. EPA provided a synthesis of pertinent 

results from GS modeling studies in the preamble to the proposed regulation. Further explanation 

of 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." Based on review of these studies, modeling results indicate that the CO2 plume 

stabilization may occur on the timeframe of 10-100 years after the cessation of injection. EPA 

believes that a 50-year default post-injection site care timeframe is a reasonable midpoint for 

most GS projects and available data, including data submitted by commenters, do not support a 

different default timeframe, and has retained this in the final regulation. 

EPA agrees that some owners or operators will be able to demonstrate, in less than 50 years, that 

the pressure front and plume no longer pose a risk of endangerment to USDWs. However, based 

on studies, EPA believes that the 50 year default time frame is warranted in most cases based on 

additional review of research studies and reports and evaluation of public comments. EPA 

believes that the best way to address all possibilities, while ensuring USDW protection from 

endangerment, is to set a 50 year default post-injection site care timeframe, with flexibility to: 

(1) allow 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) afford 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. 

Letter ID: 0168 Comment ID: 22511 Letter Lines: 430 to 452 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

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Comment: Preamble, page 43520: "Once the owners or operators provide documentation that 

demonstrates that the models predicting CO2 movement are consistent with 

monitoring results and that there are no longer risks of endangerment to USDWs, 

they could request that the Director authorize site closure. EPA is also 

proposing to allow the Director to shorten or lengthen the 50-year time frame 

based on performance of the site... EPA wishes to emphasize that site closure 

cannot occur until monitoring and modeling data establish to the Director’s 

satisfaction that potential risks of endangerment to USDWs have ceased." 

EPRI COMMENT #18: EPA’s requirement for demonstrating plume stability for site 

closure is based on the ability to both observe and successfully model the speed 

and stability of the advancing CO2 front, a very discrete boundary that is 

difficult to define, model accurately when complex reservoir heterogeneity and 

fast flow pathways are present, and measure in the field on a large scale. (See 

also EPRI’s comment #2 on defining the front). If remote methods like surface 

seismic, cross-well seismic or gravity are not successful in tracking front 

position, and CO2 is never directly detected in sentinel observations wells, 

then model validation based on CO2 front position may be questioned. In such a 

case, if the model predicts the continued advance of the CO2 front while the 

observed data do not, the EPA Director may not be satisfied with the absence of 

a potential risk of endangerment to USDWs and may unnecessarily delay site 

closure for decades. EPRI recommends that the final rule contain alternative 

provisions for site closure if model validation is unsuccessful. 

Individual Response: EPA acknowledges that many site-specific factors will influence the 

determination of when the CO2 plume and pressure front no longer pose a risk of endangerment 

to USDWs. It is for this reason that EPA believes that individual UIC Directors, in consultation 

with operators, will be in the best position to determine whether additional post-injection site 

care is needed. EPA expects this decision to be made based on relevant site data and in 

consultation with all potentially impacted parties. 

EPA also agrees that a complete cessation of plume movement may not occur at some sites for 

long time periods due to density differences, natural formation flow gradients and diffusion. EPA 

clarifies that a complete cessation of plume movement is not required, only a demonstration that 

the plume and pressure front no longer pose a risk of endangerment to USDWs. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate non endangerment; and perform site closure activities. 

The guidance will be available at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

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