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.
Comments on Proposed Rule 40 CFR Parts 144 and 146 Federal 

Requirements Under the Underground Injection Control (UIC) Program for 

Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells: As published in 

the Federal Register July 25, 2008 

James J Dooley 

Senior Staff Scientist 

Joint Global Change Research Institute 

Pacific Northwest National Laboratory 

December 9, 2008 

PNNL-18059 

Comments on the proposed Class VI GS CO2 storage proposal are divided into three 

sections. “Tier 1 Comments” address large thematic issues that cut across many sections 

of the proposed rule. “Tier 2 Comments” are comments on narrower topics within the 

proposed rule, while “Tier 3 Comments” are less consequential comments including 

suggestions for word changes to improve the clarity of the proposed rule. 

1
Tier 1 Comments 

Proposed Requirement of Computational Models to Support Permit Is Extremely 

Appropriate Requirement 

The USEPA should be commended for requiring the use of computational models as a 

part of the permitting process and for the renewal of permits as well as a means of 

demonstrating compliance with the permit. These computational models are sufficiently 

well developed at this point in time that they can provide a robust set of technical 

information that will be needed for issuing Class VI permits. While the use of these 

models is a highly technical enterprise and will most likely be something that permitees 

will contract out, the cost of using these models is trivial compared to the capital cost of a 

complete end to end CCS system or the cost of purchasing enough emissions offsets to 

cover the CO2 emissions from something like a large power plant over its multidecade 

lifetime if that facility chose not to implement CCS. It is extremely appropriate to require 

the use of these sophisticated state of the art modeling tools. 

 

Page 43506. The USEPA should also be commended for explicitly ruling out the use of 

simple “fixed radius or simple mathematical computations” to compute the AOR for 

large scale GS projects. Sophisticated computational tools exists which can do AOR 

calculations while taking into account a large number of key variable and processes. 

These tools and not a back of the envelope calculation should be required. It is 

appropriate for EPA to explicitly forbid the use of these simple methodologies for Class 

VI AOR. By disallowing these simple methods, the USEPA is not materially increasing 

the cost of employing CCS. While this argument might be put forward by others as a 

reason to keep these simple AOR tools, it is extremely hard to imagine a private sector 

firm risking billions to tens of billions of dollars of capital needed to construct and 

operate a CCS-enabled power plant or industrial facility without employing sophisticated 

geochemical/geomechanical tools to assess a prospective GS reservoir. So the USEPA is 

simply asking for access to data that will most likely already exists with the applicant and 

is therefore not creating a new cost for CCS deployment. 

Page 43507. The USEPA specifically asks for comments on the appropriateness of 

allowing proprietary models to be used in support of a Class VI permit. There is nothing 

wrong with using proprietary models. The test as to whether it is appropriate to use 

proprietary models (or “open community” models) should be whether these models are 

seen by the USEPA and the technical community as providing robust, accurate, and 

useful results. It is much more important to understand a model’s track record in this 

regard than to ask for documentation of “code assumptions, relevant equations, and 

scientific basis.” Given the inherent complexity of these models, asking for “code 

assumptions, relevant equations, and scientific basis” could result in the submittal of an 

extremely long technical document that is so dense it will not be read or the submittal of 

a very superficial treatment of the model. The USEPA should -- without delay -- begin 

deliberations on methodologies that could be used to transparently establish the 

robustness of these models and their results/outputs. This could be done – for example – 

2
through formal model intercomparisons using a set of test cases and repeating this 

process every couple of years. It will be far more useful to invest the time, thinking and 

if need be resources now to help establish which models are useful and for what 

applications than to request that each Class VI permit application include a detailed 100-

1000 page description of the model used and how key geomechanical/geophysical 

processes were parameterized. USEPA is strongly encouraged to change the focus here 

from a process oriented assessment of how these models work to a more outcome 

oriented measure of the perceived usefulness and robustness of these models by the 

technical community and other stakeholders (e.g., Wall Street) as useful tools for GS. 

Filling in the Missing Linkages between Class VI Rule and a Larger National 

Climate Policy 

It is clear from the draft Class VI storage rule that the USEPA was constrained to issuing 

the rule under the existing authorities it has via the Safe Drinking Water Act (SDWA). 

The federal employees who put together the current draft Class VI storage rule did an 

admirable job of staying within the confines of the authorities granted by the SDWA and 

in doing so produced a draft rule for CO2 storage that helps to answer many key questions 

about how CO2 storage will be regulated within the United States. 

However, there are still many, many critical issues that need to be addressed that go 

beyond the statutory authority granted by the SDWA. If EPA does not begin to address 

these issues, the resulting lack of clarity is potentially as large of a stumbling block for 

the commercial deployment of CCS technologies as would be the case if there was not 

this well thought out draft of the Class VI rule. 

One simple to articulate but difficult /complex to answer question that must be resolved 

is: 

Is compliance with the requirements of a Class VI well rule sufficient to establish 

that CO2 has not been emitted to the atmosphere for the purposes of accounting 

for a firm’s annual CO2 emissions and therefore assessing that firm’s compliance 

with future climate policy? 

It is clear that the answer to this question is not a simple “yes” or “no.” For example, 

there are good GS reservoir management practices that could lead to the intentional, 

controlled release of some previously injected CO2 that would not be consistent with 

creating verified CO2 emissions reductions. 

As the USEPA revises and finalizes this draft Class VI rule, it must begin to devote 

significant attention to these issues and begin to communicate and dialogue with 

numerous classes of stakeholders to get their input on how compliance with the Class VI 

rule will be integrated into a larger national climate policy. 

Page 43520. As correctly noted by the USEPA in the draft Class VI rule, the financial 

responsibility requirements of the SDWA do not extend to activities not related to 

3
protection of USDWs. So this is another example of the need to understand what else is 

needed to take this Class VI rule and make it part of a national climate policy. 

On the Issue of Primacy: An Example of the Challenge Inherent in “Filling in the 

Missing Linkages between Class VI Rule and a Larger National Climate Policy” 

Given the need to link the issuance and compliance with a Class VI injection permit to a 

larger national climate policy and eventually the need to link that U.S. national climate 

policy to an international climate policy regime, careful consideration should be given 

about how high the bar should be set for granting primacy to States, Territories, and 

Tribes. There is a significant imperative to make sure that CCS derived emissions 

reductions are comparable (and more precisely fungible) with GHG emission reductions 

obtained by implementing other greenhouse gas mitigation technologies and measures. A 

delicate balance must be sought between the desire to delegate authority to the local level 

with a need to preserve a sufficient level of national uniformity in how CO2 storage is 

carried out in practice. At a very minimum, the USEPA needs to recognize and reject as 

insufficient such reasoning that says because a state has shown that it can handle the 

Class II program they should also be given primacy for Class VI wells. The requirements 

to eventually integrate this proposed Class VI rule which in its present form is bounded 

by the SDWA into a much larger climate protection regulatory structure implies that the 

decision to grant primacy must be deliberate and must explicitly take account of how it 

would complicate the smooth and efficient functioning of a national climate policy. 

The degree to which EPA changes what is proposed as a common federal rule for Class 

VI CO2 storage wells because some states might be further along in the development of 

their own CO2 storage regulations (see for example discussion of “Who implements the 

UIC program” p. 43497) must also take into account the need for an owner/operator of 

CCS infrastructure to eventually be able to take CO2 injected under a class VI permit in 

Ohio, Georgia, Michigan, California, Washington State, etc. and turn that into a 

tradable/fungible emissions reduction credit (or a verified non-emission) that could be 

used to satisfy the requirements of a national climate policy. The degree to which the 

federal class VI CO2 storage policy should be amended to allow for discrepancies in how 

individual states are currently planning on regulating CO2 storage must take into account 

the need to create an economically efficient national climate change policy. This 

consideration goes well beyond the boundaries of the SDWA but it must be addressed by 

the USEPA as a whole if this proposed Class VI storage rule is to be put into practice 

(e.g., if this issue is not resolved it is hard to see the private sector motivation for 

deploying CCS technologies even if the Class VI rule is in place). 

Page 43504. In laying out its reasoning for why it did not select Regulatory Alternative 

Number 1 as the basis of the proposed Class VI rule, the USEPA correctly notes that 

there is value in having a common federal approach as there are many potential CCS 

adopters that will operate facilities in numerous different states. This is true and it is 

appropriate for USEPA to note this. It is also important to realize that there are numerous 

reasons for pursuing a common federal approach and that decision will cascade through 

4
numerous parts of the proposed rule and how it is implemented in practice and how it is 

integrated into a future national climate policy. 

On Allowing Class II EOR and Class VI GS to Evolve on Parallel Tracks: An 

Example of the Challenge Inherent in “Filling in the Missing Linkages between 

Class VI Rule and a Larger National Climate Policy” 

The USEPA is to be commended for resisting numerous calls from a number of 

stakeholders to fit GS CO2 storage into the existing framework for CO2-driven enhanced 

oil recovery (EOR). It is critically important that all stakeholders understand that these 

are very different processes with distinct infrastructures and operating practices and 

which are driven by different economic motives. The fact that they both inject CO2 into 

the deep subsurface is not a sufficient reason to treat CO2-driven EOR and GS CO2

storage in the same regulatory manner (see page 43502, “Why is EPA Proposing to 

Develop a New Class of Injection Well for GS of CO2?” as well as the section on that 

same page “How Would this Proposal Affect Existing Injection Wells Under the UIC 

Program?) 

Page 43502. Again, the USEPA should be commended for critically thinking through the 

extent to which Class II EOR practices and future Class VI CO2 storage are similar in 

practice. Allowing for the possibility of conversion of Class II wells into Class VI wells 

is a reasonable step to take which might, in a very limited number of instances in specific 

regions of the U.S., lower the cost of complying with the proposed Class VI rule. And 

the proposed Class VI rule is correct in clearly stating that only the construction 

requirements could be grandfathered assuming that all other aspects of the proposed 

Class VI rule are fulfilled (e.g., identifying and remediating all artificial penetrations 

within the AoR). This is a clear demonstration that the USEPA understands that simply 

injecting CO2 into the deep subsurface does not mean that Class II CO2 driven EOR and 

Class VI GS are the same thing. However, it is not clear if the USEPA has gone far 

enough in differentiating between these two practices. In particular, the proposed Class 

VI rule should be explicit as to whether hydrocarbon recovery will still be allowed for 

wells/fields that have been permitted under Class VI. That is, a class VI well that is 

injecting CO2 in order to drive oil or natural gas towards adjacent production wells is not 

completely consistent with the overarching goal of the Class VI rule of permanently 

isolating CO2 from the atmosphere (i.e., some of the injected CO2 will come up with the 

produced oil or gas, in some cases significant quantities of the injected CO2 will come up 

the production wells). The USEPA should consider whether it should explicitly state that 

the “grandfathering” of the construction requirements for Class II wells is also contingent 

upon the cessation of hydrocarbon production processes. Should this grandfathering only 

be allowed in depleted oil and gas fields that are no longer going to be used for enhanced 

hydrocarbon recovery and will exclusively be used for CO2 storage? This issue of 

grandfathering of Class II wells must also be a part of EPA’s needed deliberations about 

what else it needs to do in terms of rule making that lies outside of the SDWA to make 

CO2 stored in accord with the Class VI rule into something that can be used in the 

accounting framework of a national climate policy program.

5
On the Appropriateness of Allowing CO2 Storage above a USDW 

It seems that the overriding principle should be does the proposed Class VI rule help 

protect the wellbeing of humans and the health of the environment. Framing the issue in 

this way makes it clear that there is an explicit tradeoff being made about the use of 

USDWs for CO2 storage or the use of water bearing bodies that have more than 10,000 

TDS but are shallower than another formation which has waters with less than 10,000 

TDS. This calls for a flexible and site or region specific approach as opposed to an 

arbitrary criterion like “thousands of feet between the injection zone and overlying and 

underlying USDWs” ... (page 43512) If there are adequate caprocks above and below 

the “water bearing bodies that have more than 10,000 TDS but are shallower than another 

formation which has waters with less than 10,000 TDS” that should be a key (and 

explicitly noted in the final Class VI rule) criterion for deciding whether to allow a 

formation to be used for CO2 storage. 

The USEPA, as a whole, and not just the Office of Water that administers the UIC 

program, will likely need to create a transparent methodology for deciding whether it is 

better to use some specific deep saline-water bearing formations (total dissolved solids 

exceeding 10,000 mg/L) as repositories for anthropogenic CO2 or not. This is a complex 

decision that goes beyond the confines of the SDWA as one would not only need to 

consider the potential human uses for these waters (e.g., as a potential source of potable 

water via desalinization) or as a CO2 storage formation. This methodology should also 

take into account whether there are other potential large scale and economic means of 

reducing CO2 emissions that could be employed to offset potential emissions and whether 

there are other bodies of water that could be treated to provide a more economical source 

of potable water. The methodology should be broader and more meaningful than simply 

asserting that either CO2 is injected into a given formation or it is vented to the 

atmosphere. The calculus here is more complex and nuanced. 

The USEPA should also explain what authority it has (or needs to be given) to ensure that 

any future wells (oil, gas, water, injection) that drill through a water bearing formation 

with greater than 10,000 TDS which has previously been used for CO2 storage are built to 

withstand the higher pressures and acidity of these formations without becoming 

pathways for the migration of previously stored CO2 out of the target storage formation. 

If the USEPA has no way of regulating the construction of production wells that 

penetrate through a water bearing formation that has been used for CO2 storage and if it 

believes that it will not be granted this authority, then this needs to bear on decisions to 

allow storage in formations that are shallower than a USDW. 

Lastly, it is important to note that my research group has performed preliminary analysis 

which sheds light on the extent to which this might be a significant issue. We have 

included a copy of this research along with our comments on the class VI rule. There are 

two points that are worth summarizing briefly here. 

o First, these are preliminary results. We stress that point because there is a lack of 

high quality and detailed data that would be needed to present a more rigorous 

analysis. This lack of high quality data is likely to persist for a very long time. 

6
o Second, it is clear to us from this analysis that the nation’s ability to cost 

effectively address climate change will not be significantly impacted regardless of 

whether the USEPA allows injection into formations that are shallower than the 

lowermost USDW or not, as the vast majority of the nation’s geologic CO2

storage capacity is in formations that do not fall into this category (i.e., most DSF 

storage formations lie below the lowermost USDW). Having said that, it is clear 

that certain regions of the country might see their ability to deploy CCS 

constrained if the USEPA disallows the use of formations shallower than an 

USDW. While these impacts will be localized and region-specific it could be 

consequential for certain regions, firms, states and could narrow their portfolio of 

options for reducing CO2 emissions to the atmosphere. 

o This research of ours is documented in:

 CL Davidson, Dooley JJ, and RT Dahowski. 2008. "Assessing the 

Impacts of Future Demand for Saline Groundwater on Commercial 

Deployment of CCS in the United States." In the Proceedings of the 9th 

International Conference on Greenhouse Gas Technologies. PNNL-SA63047, Pacific Northwest National Laboratory, Richland, WA. 

 CL Davidson, JJ Dooley, SA Finne, RT Dahowski. February 2008. "How 

do salinity constraints impact the U.S. CO2 storage resource?" Joint 

Global Change Research Institute, Pacific Northwest National 

Laboratory. Richland, Washington. PNNL-SA-58998. 

On page 43503, the EPA requests comment on whether GS CO2 storage in coal seams 

which lie above a USDW should be categorically prohibited. In keeping with the 

discussion above, it seems that a more robust set of metrics and a broader framework 

should be employed rather than a blanket prohibition. If there is a suitable coal seam that 

is isolated above and below by strong caprocks and if EPA has the ability to influence / 

control how drilling through this formation in the future might occur then there’s no 

obvious reason to prohibit a Class VI application. It would be more rigorous and more in 

keeping with the spirit of the SDWA to establish a set of technical benchmarks that need 

to be satisfied rather than seemingly ruling certain GS applications out. This comment 

also applies to the proposed prohibition on injection into “Other Formations” (p. 43503); 

rather than creating an inflexible prohibition USEPA should work to establish rigorous 

benchmarks and thresholds that would need to be satisfied to allow CO2 storage in these 

formations. If these benchmarks are difficult to satisfy because there is solid reasoning 

for creating higher thresholds, then that would have the same impact as a prohibition but 

still leave the door open for technological progress to make it feasible. 

In the actual text of the proposed rule’s definition of key terms (page 43535), a geologic 

storage project is specifically defined as one in which wells are used to “emplace a 

carbon dioxide stream beneath the lowermost USDW.” Was this intentional to rule out 

these other practices that are mentioned in the preamble as items that are still under 

discussion, by defining a GS project in this narrow manner in the draft rule language? 

7
Costs of Compliance with Class VI Rule Seem Methodologically Problematic 

On page 43524 EPA acknowledges that there is a need to revisit the Cost Analysis. EPA 

is commended for recognizing this need and is encouraged to consider fundamentally 

modifying large aspects of the Cost Analysis of this proposed class VI rule in subsequent 

revisions. The following is a selection of methodological issues in the economic analysis 

of this rule that argue in favor of rethinking the approach used here and making 

significant revisions for subsequent versions of the proposed Class VI rule. Suggestions 

to consider when revising the cost analysis include: 

o Page 43525. I see no rigorous basis for asserting that 22 projects will deploy in 

25 years. It would be far better to present costs for a range (high, medium and 

low) of CCS deployment scenarios and then explain the basis of these scenarios. 

o Page 43527. I also do not understand the rationale for assuming that a power plant 

would only capture half of its lifetime emissions. Why was that deemed to be an 

appropriate assumption to make? 

o Page 43527. This page includes a reference to a research paper from my technical 

group as the basis for “we can use a long term average estimate of $3/tonCO2” for 

transportation costs. This research paper of ours does not speak to that specific 

monetary figure so I am not sure where that number comes from. There could be 

many instances where the cost of CO2 transport via a pipeline falls outside this 

$3/tonCO2 range. 

o Page 43528. The conclusion that “monitoring requirements account for 60 

percent of the incremental regulatory costs, of which 70 percent is incurred for the 

construction, operation, and maintenance of monitoring wells” is likely heavily 

influenced by the assumption that there would be three monitoring wells for each 

injector well. The assumption that there are three monitoring wells per injector 

well is a significant cost driver. It is not clear that this would hold true in a field 

with multiple injector wells; for example a five spot injection pattern would 

require 15 monitoring wells, which could be excessive. For GS projects that have 

very large injection fields with numerous injector wells there is no reason to 

believe that this 3:1 ratio would hold true. USEPA should consider modeling out 

a number of different deployment scenarios to see how robust this assertion is. 

This seems to be a worthwhile effort as this is the largest cost component caused 

by this Class VI rule and therefore this estimated cost is one that could receive a 

good deal of attention. My sense is that adhering to this 3:1 ratio exaggerates the 

cost of the proposed Class VI rule. 

o Page 43530. It is important to note that the determination as to whether this 

proposed rule will cost the public and or the private sectors more than $100 

million in any given year is a function of the pace of CCS deployment which is 

something that will be driven by future climate policy. If there is no future 

national climate policy, then the cost of complying with this new rule should be 

close to $0. If there is a very tight / constraining climate policy, the cost could be 

significant. The USEPA is encouraged to model out a number of different climate 

policies and then assess what the incremental cost of complying with this rule is 

rather than basing the cost on assumptions about there only being 22 pilot projects 

over the next 25 years. Without doing this calculation, there is no way of 

8
knowing how robust the assertion is that the cost of complying with the proposed 

rule will not exceed $100 million in any given year. 

o Page 43527. The text here says that it is “unlikely that all coal plants would 

deploy CCS simultaneously.” Not only is it “unlikely” it is simply impossible. 

There is no reason to hypothesize such a future deployment scenario and the 

computed results are meaningless for the purpose of public policy making. There 

is also no need to approach this particular calculation in this manner. My research 

group has completed a number of studies (as have other research groups) that 

could bound realistic CCS deployment rates. It is far better to use something 

within the realm of the possible as a basis for informing / justifying this important 

rule making. See for example: 

o MA Wise and JJ Dooley. 2008. “The Value of Post-Combustion Carbon Dioxide 

Capture and Storage Technologies in a World with Uncertain Greenhouse Gas 

Emissions Constraints.” International Journal of Greenhouse Gas Control. In 

press. 

o Dooley JJ, RT Dahowski, and CL Davidson. 2008. "Comparing Existing 

Pipeline Networks with the Potential Scale of Future U.S. CO2 Pipeline 

Networks." In the Proceedings of the 9th International Conference on 

Greenhouse Gas Technologies. PNNL-SA-62187, Pacific Northwest National 

Laboratory, Richland, WA. 

o Wise MA, JJ Dooley, RT Dahowski, and CL Davidson (2007). “Modeling the 

impacts of climate policy on the deployment of carbon dioxide capture and 

geologic storage across electric power regions in the United States." 

International Journal of Greenhouse Gas Control. Volume 1, Issue 2, April 2007, 

Pages 261-270. doi:10.1016/S1750-5836(07)00017-5

o Dooley, James, J.; Davidson, Casie L.; Wise, Marshall A.; Dahowski, Robert T. 

“Accelerated Adoption of Carbon Dioxide Capture and Storage within the United 

States Electric Utility Industry: the Impact of Stabilizing at 450 ppmv and 550 

ppmv.” In, ES Rubin, DW Keith and CF Gilboy (Eds.), Greenhouse Gas Control 

Technologies, Volume I (pp. 891-899). Elsevier Science, 2005.

Demonstrating Sufficient CO2 Storage Capacity 

Page 43536. The draft Class VI rule states that the applicant is required to identify “An 

injection zone of sufficient areal extent, thickness, porosity, and permeability to receive 

the total anticipated volume of the carbon dioxide stream.” This is a good requirement 

but it is incomplete. There needs to be some time element here. That is the proposed rule 

needs to address “total anticipated volume” over what period of time. There is no need to 

establish an arbitrary quantitative figure here (e.g., “over 40 years”). Rather the 

calculation could be predicated on the expected lifetime of the facility, the duration of the 

injection permit, etc. It would be prudent to modify this sentence to explicitly 

communicate that the USEPA was not considering “the total anticipated volume of the 

carbon dioxide stream” for any given year of operations. 

9
Lack of Clarity throughout Draft Rule with respect to the “CO2 Stream” 

Page 43493 and 43535. The draft Class VI rule has not adequately specified the critical 

concept of the “CO2 Stream.” There are many instances in the rule where critical 

decisions are made with respect to the “CO2 stream,” but this term itself is not well 

defined nor does it seem to be consistently used. 

o Page 43497. Under “Potential USDW Impacts” the text says that the “CO2

stream” may contain other impurities and lists as an example H2S. 

o Page 43493. The Definition of “Geologic Sequestration” only speaks to CO2

being injected. 

o Page 43496 contains a discussion about whether CO2 is a commodity or a 

pollutant. This issue of whether CO2 is a commodity or a pollutant is a red 

herring as far as this Class VI GS rule is concerned and EPA should be 

commended for saying that its ability to regulate CO2 injection under the 

SDWA is not contingent on determining whether it is a commodity or a 

pollutant. However, the rule is never very clear about what an acceptable 

“CO2 stream” is. 

o Pages 43503 and 43504. Are a bit clearer on what is and is not a “CO2

stream” in the context of a Class VI well but it still is not clear what is 

allowed and what is not. 

o Page 43535. Defines the “carbon dioxide stream” as CO2 from an 

anthropogenic source “plus incidental associated substances derived from the 

source materials and the capture process” as well as any tracers. This is more 

precise as it clearly would rule out the intentional comingling of other gaseous 

waste products that were not derived from the primary anthropogenic CO2

point source. Yet it still hinges on the rather vague concept of “incidental”. 

The issue of how pure the “CO2 stream” needs to be and whether trace or more 

significant quantities of other gases or liquids can be injected into a Class VI well is a 

critical issue that will influence the overall economics of CCS and could impact the 

safety and efficacy of GS. Greater clarity on this issue (while still allowing for some sitespecific flexibility) would help the business community better understand what the cost 

of using CCS will be. The USEPA is encouraged to continue trying to narrow the 

definition of the “CO2 stream” in subsequent versions of the draft rule. While this is a 

difficult issue and there is no obvious “correct answer”, USEPA is encouraged to 

continue research and dialogues with various stakeholders to see if a narrower definition 

of what degree of co-injection is allowable for a Class VI well. It is possible that it could 

take many years maybe even decades to finalize this but it is important to begin pursuing 

it now. 

No Minimum Injection Depth Specified 

Page 43511. It is difficult to envision that there will be widescale deployment of CCS 

that would utilize formations that are shallow enough to favor injection of CO2 as a gas 

and not as supercritical fluid. It seems that a better way to approach this from a 

regulatory standpoint would be to require injection at depth that would call for injection 

10
as a supercritical fluid but to allow the Director to waive that requirement for cause and 

that the waiver would be contingent on the Class VI permitee satisfying additional 

requirements designed to ensure that the overarching goals of the SDWA and other 

environmental policies are fulfilled. 

It seems odd and inconsistent to not specify a minimum depth when CO2 is being injected 

into a water bearing formation that is below the lower most USDW, but EPA is proposing 

that there would need to be “thousands of feet between the injection zone and [BOTH] 

the overlying and underlying USDWs.” (p. 43512). The overarching goal of the Class VI 

rule making is to protect USDWs and human health and welfare. If CO2 is buoyant and 

there are concerns about it migrating out of the target injection zone, it doesn’t seem 

consistent to specify a minimum depth in one relatively small subset of potential GS 

applications (injection of CO2 into a formation above the lowermost USDW) but not 

define a minimum depth for the vast majority of GS applications (injection of CO2 below 

the lower most USDW). 

Lastly, perhaps “depth” is too narrow of a concept of what is being discussed here. 

“Deeper than any USDW and not in communication (i.e., not connected 

hydrodynamically or via faults or other intrusions) with any USDW” or “Deeper than any 

USDW and geochemically and geomechanically isolated under current and modeled coand post-injection conditions with any USDW” seems much closer to the mark in terms 

of protecting what society wants protected. 

It is Appropriate to Utilize both a Fixed Time Frame and Performance Standard for 

Establishing the Period of Post Closure Monitoring 

Given humanity’s knowledge about GS deployed at the scale of millions of tons per year 

for decades at a given injection field is quite slim, the USEPA’s proposal of a fixed time 

frame in conjunction with a performance standard appears to be an appropriate balance 

between discharging its responsibilities to protect human health and the environment and 

not placing overly burdensome, unneeded requirements on prospective GS owner / 

operators (pp 43519-43520). The 50 year time frame will allow owners / operators to 

budget for post site closure within the bounds of what is currently known. The 

performance standard is an assurance to the public that a site will not be released until it 

has reached a certain point of stability. Given where humanity is with GS, the USEPA 

should be commended for crafting this compromise and should retain this language in 

subsequent versions of this draft Class VI rule. 

Requirement to Document GS Sites and Pass that Information on to Future 

Potential Users of the Land Above as well as any Subsurface Zones Is Appropriate 

Page 43541. It is appropriate for the USEPA to require that steps be taken to document 

the CO2 injection formation and to ensure that information is passed on into the future. 

The steps spelled out here are reasonable and not overly burdensome (e.g., survey plat 

11
and deed for land must include a notation that the deep subsurface was used for CO2

storage). This language should be retained in subsequent versions of the Class VI rule. 

All Wells and “All Known Wells” are not the Same 

Page 43507 and 43517. The proposed Class VI rule needs to be much more precise in its 

use of language in a couple of key areas. The rule requires an applicant for a Class VI 

permit to “identify all artificial penetrations.” What exactly does this mean? Is it all 

known artificial penetrations (the rule speaks to the operator “review(ing) available 

information”)? What is the test for what is a known well or available information (does it 

require detailed field surveys or does one only need to do a quick search of a database of 

wells drilled in the area)? If on the other hand it means literally all human penetrations, 

then one must ask if this is technologically possible (e.g., are there technologies which 

would allow for the identification of a small diameter non-steel walled well that has no 

visible surface features)? Is there a danger in asking for something that can not actually 

be delivered? One can guess what was likely meant by “identify all artificial 

penetrations” in terms of drafting this rule but it is not at all clear how this would be 

opperationalized at actual prospective GS sites. 

More importantly on Page 43535 under “144.55 Corrective Action”, the rule says that 

owners/operators need to identify the location of “all known wells” which seems to be a 

lesser standard. In the actual text of the rule (page 43526), the applicant is told “Only 

information of public record is required to be included on this map.” Given how many 

times the rule and its preamble talk about old wells being a potential conduit for CO2

release from the storage formation, this seems like an overly lax threshold. It would 

seem appropriate to require the applicant survey the actual site itself for artificial 

penetrations that might not be in the public record (the survey could include a number of 

different methods / tools). Further on in this section, the applicant is asked to submit a 

“tabulation of all wells within the area of review which penetrate the injection or 

confining zones.” Again, “all wells” and “all known wells” and how much work does 

one need to do to determine if they have tried to find “all the wells” must be better 

articulated in the final rule. This same kind of language shows up on page 43537 within 

the discussion of the Area of Review and Corrective Action. 

Lastly, given the large amounts of money involved in a commercial CO2 storage project, 

I would think that the electric production, oil and gas, or other large industrial company 

contemplating a large CCS-enabled facility would want (or be required) to go beyond 

simply collecting existing data as a way of decreasing risk and uncertainty. In this 

context, the proposed “requirement” for going beyond existing data could be imposed by 

entities other than state or federal environmental regulators and could be imposed by 

shareholders, a public utility commission, or a firm’s own board of directors. In terms of 

abandoned wells, it seems likely that commercial firms would see it to be in their own 

best interest to do some kind of physical search / assessment of whether there are any 

known or unknown wells within the area of review given the relatively minor cost 

associated with something like an aerial magnetic survey versus the costs associated with 

12
loss of CO2 and any fines, the cost associated with any required post-leakage activities, or 

simply the cost of litigation and or loss of good will associated with such sloppy 

management of a critical, capital intensive pollution abatement facility. 

In this same section (page 43526), the applicant is asked to submit information on “the 

presence and depth of seismic sources” but this falls under a heading that is limited to the 

“proposed storage site and overlying formations.” So if a proposed GS site sat 10 cm, 

10m or 10km north of any aspect of the New Madrid Fault, that would not be noted in the 

application. Limiting the scope of data collection to the boundaries of the project site 

might not be appropriate for data related to “the presence and depth of seismic sources” 

It Should Be a Requirement to Periodically Revaluate Funds Set Aside for Well 

Plugging and Post-Injection Site Care 

Page 43520. The USEPA should mandate that owners / operators periodically update the 

cost estimate for well plugging, post-injection site care, ect. Given how long GS projects 

are likely to last, there is no reason to believe that the amount of money set aside at the 

start of the project even if it were invested in something that kept up with inflation would 

necessarily be sufficient to cover these costs. The US DOE Energy Information 

Administration in its Annual Energy Outlook: 2007 

(http://www.eia.doe.gov/oiaf/aeo/otheranalysis/cecei.html) documented how drilling and 

other associated costs have escalated at a rate that is far above the core inflation rate for 

the economy as a whole. On page 43522, the draft rule says “Trying to determine the cost 

for post injection site care, possible 30 to 50 years in the future, could be difficult...” 

Yes, it is difficult to understand what anything would cost 50 years in the future. 

However, one can figure out what it would cost to do those things now and then one 

could periodically reassess those costs. That is quite straightforward and the USDOE’s 

EIA maintains a Oil and Gas Lease Equipment and Operating Costs Index which could 

easily be used to true up these costs as needed to account for inflation (see 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipme

nt_production/current/coststudy.html). The Oil and Gas Journal also publishes indices of 

construction costs which could be used to true up these costs over the life time of a GS 

project. Again, there are many reasons to mandate that these costs be revised periodically 

and if need be the corresponding financial assurance mechanisms should be revalued. 

90% of the Injection Zone or the Caprock’s Fracture Pressure 

Page 43510 under “Proposed Injection Well Operating Requirements.” Citing the 

IOGCC report and the expert opinion of permit writers is not the most rigorous basis for 

asserting that injection pressure can not exceed 90% of fracture pressure for all GS 

applications. Perhaps in a Notice of Data Availability (NODA) for this rule, USEPA 

could ask for data or studies that would help establish a firmer basis for this threshold. 

This is an important criteria as it directly impacts how much CO2 can be put down a 

given well and therefore how many wells will be needed to handle the anthropogenic CO2

13
from a given facility. The number of injector wells is a key determinant of the cost of 

CO2 storage. On page 43538, this same language is found in the proposed rule text (i.e., 

not in the preamble). 

More importantly did the USEPA intend to tie this 90% pressure threshold to the fracture 

pressure of the “injection zone” or the fracture pressure of the “primary caprock / seal 

above the injection zone”? If a GS project was injecting at the bottom of a 500 meter 

thick interval of a sandstone, is there any harm in allowing for some amount of 

deformation to areas near the injection point in the target formation? In many areas, the 

caprocks are stronger than the injection zones based on the rock types, degree of 

cementation etc. In such cases, it may be good to have a mechanism where you can 

stimulate the injection zone more aggressively to increase permeability / injectivity. 

Fracturing of the injection zones may be critical in improving injection performance and 

even in making some of the marginal injectivity sites into viable sites. 

It Is Appropriate to Require Class II Fields to be Recertified before Conversion to 

Class VI Fields 

Page 43512. It is appropriate for the USEPA to require a new aquifer exemption for a 

formerly Class II injection field if there is a desire to use that field for GS. EPA should 

retain this requirement in the final rule. Just because a formation was deemed 

appropriate for Class II activities, does not guarantee that it is suitable for GS and 

therefore EPA is right to ask for more fact finding and potentially remediation of artificial 

penetrations before allowing the formation to be exempted and used for GS. 

Allowing the Director the Discretion to Ask for Additional Fact Finding on 

Supplemental Confining Layers 

Page 43505-43506. EPA specifically asks for comments on allowing the Director to 

require that additional confining zones be identified for certain projects. Assuming that 

the Director uses this authority to require more fact finding for cause (i.e., it is not a 

capricious request), then it seems as if USEPA has struck an appropriate balance here and 

should retain this flexibility in the final rule. Given the capital cost of something like an 

IGCC+CCS, it does not seem unreasonable to ask that cores be taken from a second or 

third overlying caprock if there is some reason to want to ensure that there are additional 

containment systems beyond the caprock immediately above the target injection zone. 

While the USEPA might receive comments saying that this is potentially a significant 

unknown cost that could delay CCS deployment, the cost of this additional fact finding is 

likely denominated in the millions of dollars or less while the rest of the complete end-toend CCS facility could be worth tens of billions of dollars. Again assuming that this 

flexibility is only used when needed and for cause, it seems to be an appropriate and cost 

effective tool for ensuring the overall goals of the Class VI program are fulfilled. 

14
Dialogue between the Regulated and Regulator Isn’t Obvious 

The draft Class VI rule and especially the preamble assert numerous times that a key to 

ensuring the safety and efficacy of geologic sequestration is a well functioning dialogue 

between the regulated entity and the regulatory agency. There are at least three 

intertwined concerns I have with the way the current draft Class VI rule is written that if 

left unresolved would hamper a robust, meaningful dialogue between the regulated entity 

and the regulator has been created by this rule. 

1) The concept that there is “working” relationship between the permitee and the 

permit-granting agency doesn’t really come through here. This seems like a very 

arms length relationship. 

2) The draft rule never establishes that the process of moving from initial site 

selection to permitting, to operations to renewal of permits to closure is an 

iterative one between the operator and the EPA or state permit writer (acting as 

stewards of the public’s welfare) as new data are generated and incorporated into 

the site management plan. That is, the rule could do a much better job of 

explaining that the permittee and the regulator should be learning a great deal 

about how a particular geostorage field is operating in practice and that this 

knowledge will be factored into how the field is regulated in the future (including 

decisions about post closure). 

3) Data is collected but it is not clear how it is used by the regulator nor is it clear 

who has access to this data. In particular, there appears to be only two instances 

(one at the very earliest stages of site selection and the other before site closure) 

where the public is invited to learn and comment on a GS project. 

Given that humanity is in the early days/decades of CCS deployment, it seems to me that 

much could be learned by having closer and more frequent communication between the 

regulator and owner/operator of a GS project, and allowing for some dissemination of the 

massive amount of data generated by these projects. A more transparent and meaningful 

dialogue between these two parties would also help with stakeholder acceptance of CCS. 

Much Data Is Collected; But how is it used and who has access to the data? 

o Page 43514 includes a requirement that mechanical integrity be demonstrated 

annually, but it does not say what is done with this information or what it is used 

for. How long is this data retained? 

o Page 43514 includes a requirement that owners / operators report semi-annually 

on the injection pressure, flow rate, temperature, volume and annular pressure and 

on MIT test results. What is the data collection method and who will have access 

to these data? Is it an open website like the Toxic Report Inventory (TRI) where 

any citizen could view this information, or is it a single hard copy report locked in 

a state or regional EPA office that can only be seen via a FOIA request by 

members of the public or other stakeholders? 

o Page 43514. EPA asks for “comments on the requirements for monitoring” but it 

is not clear that there are any requirements articulated here. The USEPA should 

require that data on the areal extent of the CO2 plume and the pressure front as 

well as any other relevant data from MMV be reported to EPA on an annual / 

15
semi-annual basis. USEPA still must come to some consensus on how these data 

will be collected, who will have access to them, ect. 

o Page 43514 under “Monitoring CO2 Movement and Reservoir Pressure”, USEPA 

states that the owner/operator must compare the results of monitoring to baseline 

data but the text of the proposed rule does not require that this information be 

shared with the USEPA or state permitting agency. Isn’t this critically important 

information on how GS is working at a site? Isn’t that information needed by 

USEPA to understand whether the Class VI rule is effective in protecting USDWs 

and the other goals of the SDWA? There should be a requirement that this data 

and comparison be shared with regulators. 

o Page 43517 contains a requirement to report various data on the performance of 

GS on a semi-annual basis, but again it is not clear how these data will be used, 

retained, or who has access to them. 

o Page 43538. Owners and operators of Class VI wells are required to install and 

use continuous recording devices to monitor a number of critical performance 

variables. The rule does not specify how long these data are to be retained and 

who has access to them. 

Who has access to reports on an ongoing GS project? 

o Page 43517. It is asserted that the requirement for “monitoring, testing, AOR, 

and corrective action” plans will help establish “an ongoing dialogue between the 

operator and the permitting authority.” This reviewer just doesn’t see this 

“dialogue” in this rule. There is no discussion of how these plans are used and 

therefore this looks like a very distant and at arms length process. I am 100% in 

support of there being an ongoing dialogue between the operator and the regulator 

and I believe that these additional plans are a wise requirement for Class VI GS 

wells. 

o Page 43517. Records retention of only 3 years after site closure. That seems 

incredibly short. Also it is not clear how this requirement to hold on to these data 

for three years after site closure is consistent with the owner operators 

requirement to discharge its responsibilities under the post closure period 

including establishing that non-endangerment continues to be the case. Wouldn’t 

access to baseline and data collected during the period of principal operations be 

needed to report out these findings during the period of post closure. This short 

record retention period also seems to undercut assertion of a open continuous 

dialogue being a center piece of how USEPA and any states that have Class VI 

primacy will ensure public safety. 

o Page 43517. USEPA asks for comments on electronic reporting. Yes, electronic 

reporting should be mandatory. USEPA also needs to find a way to ensure that 

electronic reports are eventually consolidated at a national level. Having the 

reports be submitted to a state but not having the reporting go any further will 

frustrate efforts to improve our knowledge about how CCS works in practice and 

it will frustrate efforts to cost effectively include GS in to the structure of a 

national climate policy. Page 43529. The USEPA should consider whether a 

requirement of being granted primacy for Class VI wells would be a requirement 

to share data collected at the state or Tribal area with the federal USEPA. EPA 

16
Stakeholder Input and the Periodicity of this Involvement 

o Page 43520. The draft rule states “During this 50 year period, the owner or 

operator would be required to submit periodic reports...” What’s the periodicity 

of these reports? A layperson would likely see this as a more meaningful step to 

regulate GS if the periodicity was annually as opposed to once every 15 years. I 

do not intend to imply that annual reporting is the appropriate periodicity but by 

not specifying the interval the value of this as a regulatory tool or a means of 

building public trust in nascent GS technologies is largely gutted. 

o Page 43520. The draft rule seems to imply that the draft site closure plan would 

be made publically available. That is fine and appropriate, but the rule does not 

address what data will be made publically available when the GS project is being 

planned or during its operational phase. I do not see how the USEPA can be 

silent on this point. 

o Pages 43522-43523 contain an explicit discussion of public involvement in GS 

projects. This passage says that a summary of this pre-construction public 

involvement activity would become part of the public record. So the rule says 

that something at the very earliest stages of a GS project and something at the 

very end are public documents, but it is not clear what data during the 30-50 year 

operational life of the project are publically available. 

Page 43523. EPA explicitly asserts that because it (or a state that has primacy) has such a 

rigorous on-going dialogue with owners/operators that it is prudent to issue injection 

permits “for the life of the GS project including the post-injection site care period.” This 

very consequential decision hinges upon whether or not there truly is an ongoing 

dialogue that is substantive and happens with enough frequency to allow problems to be 

detected and remediated quickly. I am not sure that I see this dialogue as being that 

robust. 

Page 43528. The proposed Class VI rule states “The information gathered as a result of 

this proposed rule .... allows the Agency to verify throughout the life of the injection 

project that UIC protective requirements are in place and that USDWs are protected.” At 

the end of the day, this is indeed the figure of merit. Does this rule allow for sufficient 

exchange of information between the owners/operators of GS projects and regulators and 

stakeholders (?). This reviewer is not convinced that this metric is satisfied by the 

proposed rule. 

17
Tier II Comments 

• Page 43497. To the extent that EPA will revise this preamble language, please 

consider ending the section on “Potential USDW Impacts” with a new sentence that 

reaffirms that the purpose of this proposed rule is to put in place regulations, best 

practices, enforcement mechanisms, etc. to ensure that all of the previously 

mentioned bad things that could go wrong with a CO2 storage project do not take 

place. This reviewer thinks that given the negative tone of much of the material in this 

section it is appropriate for the USEPA to reinforce the point that the purpose of this 

rule is to ensure that CO2 storage is done safely thus significantly reducing if not 

eliminating the extent to which any of these things actually happen. 

• Page 43495 under “Why is Geologic Sequestration Under Consideration...”. Please 

change sentence which says in part “The capture and storage of CO2 would enable the 

continued use of coal in a manner that ...” The first deployments of CCS are not 

going to be at coal fired electric power plants. There is no reason for this rule to be 

overly focused on coal based CCS applications and is not appropriate for this Class 

VI UIC rule since it is bounded by the SDWA which means that the source of CO2 is 

not a critical aspect of this rule. Focusing on coal can also bring in a lot of ancillary 

(although important) issues surrounding the use of coal like mining practices that do 

not need to be discussed within the boundaries of a proposed Class VI UIC rule. 

CCS is more than just coal. 

• Page 43498. Second paragraph on that page. “However, some CO2 releases from 

injection activities have been documented.” Crystal Geyser is not an “injection 

activity” as that term is used in the context of this Class VI rule. The text in that 

paragraph makes it clear that the CO2 which erupts from Crystal Geyser is from 

“improper well plugging.” It is technically inaccurate, misleading and prejudicial to 

start off this paragraph by saying “some CO2 releases from injection activities have 

been documented.” 

• Page 43498. The USEPA is to be commended for the passage here on Lake Nyos and 

Lake Monoun and in particular for the forcefulness with which the draft Class VI rule 

makes it clear that these are not analogous to CO2 injected into a deep geologic 

formation. 

• Page 43498, section on “Seismic Events.” The first sentence in this section is clearly 

speaking to the potential for CO2 injection to cause seismic activity in the future when 

commercial deployment of CCS becomes more common place. However, the second 

sentence and the subsequent discussion of induced seismicity at the Rocky Mountain 

Arsenal are not related to CO2 injection. To be clear, it was not CO2 that was being 

injected into deep geologic formations beneath the Rocky Mountain Arsenal. If this 

section of the preamble is retained in future versions of this proposed rule, this 

section must be rewritten to make it clear that the technical literature suggests that 

18
poorly managed CO2 injection could in the future induce small scale seismic activity. 

And then if there is a need to discuss previous instances where injection of fluids that 

were not CO2 triggered seismic activity the language needs to be clear and explicit so 

the reader understands that these are not past instances of poor CO2 injection. 

• Page 43503. While it is a widely held belief that much more is known about depleted 

oil and gas (DOG) fields within the US as opposed to DSFs, it is not at all clear if this 

is true or significant in terms of the proposed Class VI rule or in terms of the decision 

making process a private firm would use to decide whether to utilize DOG or DSF 

fields in a commercial CO2 storage project. To the extent that there is more known 

about DOG fields, much of this data is proprietary and is in the hands of oil 

companies and oil field service companies. For more than a decade members of the 

CCS community have been seeking access to this presumed treasure trove of geologic 

data to build a national CO2 storage reservoir data base with this presumably high 

quality data. But the data have not been released, likely due to legitimate private 

sector concerns over protecting valuable proprietary information or perhaps this 

wealth of easily exploitable high quality data do not exist at these firms. So if the 

data exist but are not available, it seems immaterial to assert here that a significant 

cost savings could be had by exploiting DOG fields. This has not been proven in 

practice and I believe it might not ever be proven out in practice. 

• Page 43509, last full paragraph on that page. The text here seems to imply that the 

cement used for CO2 storage wells will be eaten away by “acid” in one week. This is 

one example of a number of places in the rule where – perhaps inadvertently in the 

editing process – it seems as if text was deleted that would have helped a reader 

understand that “we are now discussing a scientific study that has some bearing on 

the topic at hand but isn’t exactly like GS” and “now are switching to an explicit 

discussion of what the USEPA will require of owners and operators of GS projects.” 

If this text is retained in subsequent interations of the Class VI rule it would be good 

to explain why this study is germane to regulating GS in the United States and 

whether the same thing is expected to happen in practice. If cements in wells are 

going to fail in a week, then there isn’t much point in promulgating this rule. 

• Page 43511. The USEPA does a good job of explaining why the cost of requiring 

down hole shut off valves should not be seen as being overly burdensome for 

potential operators of GS sites. While the logic and data presented here seem 

convincing and make the point, it seems that a cost/benefit calculation might be a 

secondary issue. If the USEPA believes that these down hole shut off valves are 

needed to discharge its responsibilities under the SDWA (i.e., protect USDWs) then 

that should be the primary reason. The USEPA should not need to defend 

requirements needed to carry out its responsibilities under the SDWA with 

cost/benefit analyses. 

• Page 43513. EPA should not require that tracers be used in all GS applications across 

the very heterogeneous set of deep geologic formations that could be used to store 

CO2 in the USA. The USEPA (and in particular the Office of Air and Radiation) 

19
might want to consider doing full life-cycle analyses of the manufacture, storage, use 

and potential leakage of tracers to help better inform the technical community about 

the cost / benefits of using this one class of MMV technologies. 

• Page 43515. It strikes this reviewer as odd to cite only one study (Burton et al, 2007) 

to support the statement that “current monitoring technologies are more than adequate 

for monitoring pressure in a GS project.” It is not clear if by including this in the 

preamble to the draft rule whether EPA shares this assessment or not. This seems like 

an awfully broad and sweeping statement. Consider rewording. Consider being 

explicit as to whether EPA shares this view or if part of any NODA associated with 

this rule making should try to collect information that goes beyond this one study to 

confirm or refute this assertion that pressure monitoring technologies which exist 

today are sufficient to meet any GS need in any kind of formation anywhere and at 

any time across all regions of the USA. 

• Page 43516. It is not clear if the USEPA is asserting that using “seismic crosswell 

methods” are “costly and time consuming” or if that is a finding of the GEO-SEQ 

(2004) report mentioned at the start of this paragraph. If it is the latter then it is 

important to clearly attribute that statement to the authors of the GEO-SEQ report. 

Otherwise, it appears that the USEPA is calling into question the cost effectiveness 

and utility of a technique that has yet to be robustly tested with respect to GS. That 

would seem to be a premature assumption based only on the results of the GEO-SEQ 

project, since crosswell seismic could be a preferred option for some sites where 

alternative options are impractical or economically infeasible. This section contains a 

number of implicit references to cost/benefit calculations for monitoring technologies. 

If the USEPA believes that these techniques are needed to discharge its 

responsibilities under the SDWA, then that should be stated and these techniques 

should be required. The text could say something about encouraging technological 

progress in the hopes of coming up with less costly but equally effective monitoring 

technologies, but it does not seem appropriate to try and justify some actions by 

alluding to cost benefit analyses as the basis for decision making. 

• Page 43519. Consider explicitly referencing the work laid out by Benson to support 

the statement that physical and geochemical trapping mechanisms will help to 

improve the integrity of storage as time moves forward. This is a critically important 

– but widely misunderstood – point about how GS will work in practice. It would be 

good to include at least one citation to technical work to back up this point. 

o OTC 19244. Multi-Phase Flow and Trapping of CO2 in Saline Aquifers. Sally 

M. Benson, SPE, Stanford University. Copyright 2008, Offshore Technology 

Conference This paper was prepared for presentation at the 2008 Offshore 

Technology Conference held in Houston, Texas, U.S.A., 5–8 May 2008. 

• Page 43521. The text here briefly mentions on going analysis of “pay-in periods for 

trust funds” in the context of financial assurance. I do not understand the statement 

here that says “EPA is considering a guidance approach that would recommend a pay 

in period of three years for GS projects.” “Three years” seems completely arbitrary. 

20
What would be the basis for the fee paid in those three years? Would it be a charge 

of $1/tonCO2 or $50/tonCO2? There is no way to understand the utility of a three 

year pay-in period without knowing much more about what costs this fund was 

supposed to cover, how the fee would be assessed, at what level would the fee be set, 

etc... We have recently completed an analysis that sheds light on a number of issues 

specifically related to trust funds applied to GS and I believe it is potentially relevant 

to the USEPA’s ongoing evaluation of these issues. Please see: 

o Dooley JJ, C Trabucchi, and L Patton. 2008. “Tipping Fees Can't Save us 

from the Tipping Point: The Need to Create Rational Approaches to Risk 

Management that Motivate Geologic CO2 Storage Best Practices.” To be 

published in the Proceedings of the 9th International Conference on 

Greenhouse Gas Technologies. October 2008. PNWD-SA-8349, Pacific 

Northwest National Laboratory, Richland, WA. 

o Page 43530. The draft rule correctly states “Sequestering CO2 via injection wells is a 

voluntary action that would only be undertaken by an entity if it were in its interest 

compared to other alternatives it may have.” This point is worth repeating a number 

of times in this proposed rule. In particular, this might be worth repeating in 

discussions of what is required for Class VI wells and the cost of meeting these 

requirements. At times, it seems as if the USEPA is apologizing for requiring 

compliance with measures designed to protect USDWs. The USEPA should ask for 

the public and other stakeholders to perform a thorough and rigorous review of any 

proposed requirements but there is no need to apologize. As the draft Class VI rule 

makes clear, no one is being required to use GS. That is important to remember and 

likely bears repeating. 

o What if any are the construction requirements and mechanical integrity requirements 

for monitoring wells? 

o Page 43531. The USEPA invites the public to identify peer reviewed studies that 

assess the effects on infants and toddlers who are exposed to drinking water that has 

been degraded “by geologic sequestration of carbon dioxide.” The wording here 

seems to assume a number of key steps that I am not sure one can assert given where 

humanity is in terms of the commercial deployment of GS. This request for 

information would be better if it requested information on studies that speak to the 

impact of drinking contaminated water by infants and toddlers caused by processes 

that could result from a poorly functioning GS project at some point in the future. I 

do not see how there can be existing studies that show negative impacts on children 

from drinking water contaminated by a malfunctioning GS project. It is worth 

comparing the language here with the far more balanced and accurate language on 

page 43532 where the USEPA forcefully asserts that the proposed rule will not have a 

disproportionate impact on minority and low-income populations. 

o Page 43540 under “Post-injection site care and site closure.” The USEPA should ask 

for a seismic image or other data that depicts the current extent and placement of the 

CO2 plume. The current language asks for “the predicted position.” If the EPA 

21
would like modeling of the predicted position for some purpose that is fine but there 

is no reason not to ask for data that shows where the plume really is. 

22
Tier III Comments

• Page 43493, in the “Definitions.” Consideration should be given to breaking the 

definition of EOR/EGR into two different short paragraphs. The physical processes 

as well as economic drivers involved in EOR and EGR are not strictly similar and it is 

not clear that these should be lumped together in something like a federal regulation. 

• Page 43495, third column, under “II What is EPA Proposing?” I believe the IPCC 

Special Report on Carbon Dioxide Capture and Storage (IPCC SR on CCS) and/or 

more recent peer reviewed papers can shed light on the timeframes under which 

primary and secondary trapping mechanism begin to operate. Adding some 

quantification to this point would likely help stakeholders better understand and be 

more familiar with CO2 storage. Consider adding something like “Some of these 

trapping mechanisms begin as soon as the CO2 is injected into the host formation 

while others take hundred to thousands of years to run their course.” I believe one 

could cite the IPCC SR on CCS to substantiate that point. 

• Page 43497 under “What are the risks associated with CO2 GS?” I do not see any 

reason to include the modifier “likely” in the first sentence of “Potential USDW 

Impacts.” Under what set of circumstances would CO2 injected into a water-bearing 

deep geologic formation not come into contact with formation waters? Delete 

“likely” from this sentence. It does not help readers understand CCS or how EPA 

will regulate CO2 storage. 

• Page 43497 under what are the “Potential USDW Impacts.” Please consider adding at 

the very end of this section a sentence that reaffirms for the reader that the 

fundamental purpose of the proposed Class VI rule is to make sure that the bad things 

above enumerated do not occur. 

• Page 43502, third sentence under “How Would this Proposal Affect Existing 

Injection Wells Under the UIC Program?” Please consider being specific as to what 

kind of “production” is being discussed here. From the context of this sentence it 

would seem to be “production of oil” or perhaps “production of hydrocarbons” but it 

would not seem to cover “production of brackish waters for the purpose of 

desalination to provide potable water.” The phrase “any production” seems overly 

vauge. 

• Page 43505 within the discussion of CO2 storage in coal seams. It is incorrect to state 

that “the process of CO2 adsorption to the coal has not been proven.” This is well 

established. I think what USEPA intended to say was something like “the 

commercial application of coal-based CO2 storage has not been proven.” The 

fundamental principle of CO2 adsorbing on the coal surface is established. Whether 

this is going to work in situ and at commercial scale has not been established / 

proven. Please consider rewording. 

23
24

• Page 43516. “Simulations discussed in the manual confirm seismic and ...” What 

“manual”? It is not clear what is being discussed here. 

• Page 43538. Does the USEPA (or states that have primacy for Class VI wells) really 

want to take physical possession of cores from prospective GS sites? The rule 

currently states “The owner or operator must take and submit to the Director whole 

cores or sidewall cores of the injection zone and confining system and formation fluid 

samples from the injection zone(s).” I understand the requirement that the Class VI 

permit applicant needs to take cores and needs to perform tests upon them but 

wouldn’t it be more meaningful for the “Director” to receive a written summary of 

those tests and a description of the methodologies used in the testing of the cores than 

to literally take physical possession of the cores themselves? The USEPA should 

consider rewording this passage. 
This document is not available in Regulations.gov since it 

contains copyrighted material that may not be reproduced 

without consent of the copyright holder. 

Contact the EPA Docket Center, Public Reading Room to view 

or receive a copy of this document. Requests for copies may be 

made as follows: 

In person/writing: 

Environmental Protection Agency, Docket Center 

1301 Constitution Ave NW, 2822T, Room 3334 

Washington, DC. 20004 

Telephone: 

202-566-1744 

Fax: 

202-566- 9744 

Email: 

docket-customerservice@epa.gov
This document is not available in Regulations.gov since it 

contains copyrighted material that may not be reproduced 

without consent of the copyright holder. 

Contact the EPA Docket Center, Public Reading Room to view 

or receive a copy of this document. Requests for copies may be 

made as follows: 

In person/writing: 

Environmental Protection Agency, Docket Center 

1301 Constitution Ave NW, 2822T, Room 3334 

Washington, DC. 20004 

Telephone: 

202-566-1744 

Fax: 

202-566- 9744 

Email: 

docket-customerservice@epa.gov
This document is not available in Regulations.gov since it 

contains copyrighted material that may not be reproduced 

without consent of the copyright holder. 

Contact the EPA Docket Center, Public Reading Room to view 

or receive a copy of this document. Requests for copies may be 

made as follows: 

In person/writing: 

Environmental Protection Agency, Docket Center 

1301 Constitution Ave NW, 2822T, Room 3334 

Washington, DC. 20004 

Telephone: 

202-566-1744 

Fax: 

202-566- 9744 

Email: 

docket-customerservice@epa.gov
Letter ID: 0156 

Commenter: James Dooley 

Organization: Joint Global Change Research Institute, Pacific Northwest National Laboratory 

Letter ID: 0156 Comment ID: 22616 Letter Lines: 40 to 70 

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

delineate the AoR (seeking comment) 

Comment: Proposed Requirement of Computational Models to Support Permit Is Extremely 

Appropriate Requirement 

The USEPA should be commended for requiring the use of computational models as a 

part of the permitting process and for the renewal of permits as well as a means 

of demonstrating compliance with the permit. These computational models are 

sufficiently well developed at this point in time that they can provide a robust 

set of technical information that will be needed for issuing Class VI permits. 

While the use of these models is a highly technical enterprise and will most 

likely be something that permitees will contract out, the cost of using these 

models is trivial compared to the capital cost of a complete end to end CCS 

system or the cost of purchasing enough emissions offsets to cover the CO2 

emissions from something like a large power plant over its multidecade lifetime 

if that facility chose not to implement CCS. It is extremely appropriate to 

require the use of these sophisticated state of the art modeling tools. 

Page 43506. The USEPA should also be commended for explicitly ruling out the 

use of simple "fixed radius or simple mathematical computations" to compute the 

AOR for large scale GS projects. Sophisticated computational tools exists which 

can do AOR calculations while taking into account a large number of key variable 

and processes. These tools and not a back of the envelope calculation should be 

required. It is appropriate for EPA to explicitly forbid the use of these 

simple methodologies for Class VI AOR. By disallowing these simple methods, the 

USEPA is not materially increasing the cost of employing CCS. While this 

argument might be put forward by others as a reason to keep these simple AOR 

tools, it is extremely hard to imagine a private sector firm risking billions to 

tens of billions of dollars of capital needed to construct and operate a CCSenabled power plant or industrial facility without employing sophisticated 

geochemical/geomechanical tools to assess a prospective GS reservoir. So the 

USEPA is simply asking for access to data that will most likely already exists 

with the applicant and is therefore not creating a new cost for CCS deployment. 

Individual Response: EPA acknowledges the commenter’s support and believes 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 

1
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. 

Letter ID: 0156 Comment ID: 22617 Letter Lines: 72 to 96 

Comment Code: 3350 2.2.1.5 Use of proprietary models for GS sites (seeking comment) 

Comment: Page 43507. The USEPA specifically asks for comments on the appropriateness of 

allowing proprietary models to be used in support of a Class VI permit. There 

is nothing wrong with using proprietary models. The test as to whether it is 

appropriate to use proprietary models (or "open community" models) should be 

whether these models are seen by the USEPA and the technical community as 

providing robust, accurate, and useful results. It is much more important to 

understand a model’s track record in this regard than to ask for documentation 

of "code assumptions, relevant equations, and scientific basis." Given the 

inherent complexity of these models, asking for "code assumptions, relevant 

equations, and scientific basis" could result in the submittal of an extremely 

long technical document that is so dense it will not be read or the submittal of 

a very superficial treatment of the model. The USEPA should -- without delay -- 

begin deliberations on methodologies that could be used to transparently 

establish the robustness of these models and their results/outputs. This could 

be done - for example - through formal model intercomparisons using a set of 

test cases and repeating this process every couple of years. It will be far 

more useful to invest the time, thinking and if need be resources now to help 

establish which models are useful and for what applications than to request that 

each Class VI permit application include a detailed 100-1000 page description of 

the model used and how key geomechanical/geophysical processes were 

parameterized. USEPA is strongly encouraged to change the focus here from a 

process oriented assessment of how these models work to a more outcome oriented 

measure of the perceived usefulness and robustness of these models by the 

technical community and other stakeholders (e.g., Wall Street) as useful tools 

for GS. 

Individual Response: EPA agrees that some of the available proprietary models may meet the 

needs for calculating the AoRs of GS sites. EPA will allow their use in meeting the requirements 

for the GS regulation, but clarifies that GS well operators using proprietary models are required 

to disclose, to the Director's satisfaction, the code assumptions, relevant equations, and scientific 

basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir 

engineering professionals as well as in peer-reviewed studies to model CO2 sequestration. EPA 

adds that its Confidential Business Information requirements at 40 CFR 144.5 will apply to the 

use of proprietary models. 

EPA does not plan to initiate a formal review of models or modeling methodologies, as the 

commenter suggests. Instead, EPA believes that it is appropriate to allow operators the flexibility 

2
to select modeling techniques that are most appropriate to site conditions and available types and 

amounts of data. The owner or operator must demonstrate, in the proposed AoR and corrective 

action plan required at §146.84(b), to the satisfaction of the Director, that the modeled AoR will 

be based on detailed geologic data collected on the site. EPA anticipates that any model that does 

this in a satisfactory manner will be approved by the Director. EPA acknowledges that modeling 

technology is expected to continuously improve, and encourages and expects owners or 

operators to use the best available multiphase computational models to determine the AoR. 

Reliance on improved models will likely increase the accuracy and quality of the AoR 

characterization, resulting in better protection of USDWs from endangerment. 

Letter ID: 0156 Comment ID: 22618 Letter Lines: 98 to 114 

Comment Code: 1430 1.2.1.2 Support EPA's authority to regulate CO2 injection 

Comment: Filling in the Missing Linkages between Class VI Rule and a Larger National 

Climate Policy 

It is clear from the draft Class VI storage rule that the USEPA was constrained 

to issuing the rule under the existing authorities it has via the Safe Drinking 

Water Act (SDWA). The federal employees who put together the current draft 

Class VI storage rule did an admirable job of staying within the confines of the 

authorities granted by the SDWA and in doing so produced a draft rule for CO2 

storage that helps to answer many key questions about how CO2 storage will be 

regulated within the United States. 

However, there are still many, many critical issues that need to be addressed 

that go beyond the statutory authority granted by the SDWA. If EPA does not 

begin to address these issues, the resulting lack of clarity is potentially as 

large of a stumbling block for the commercial deployment of CCS technologies as 

would be the case if there was not this well thought out draft of the Class VI 

rule. 

Individual Response: EPA clarifies that the scope of the GS regulation is limited to injection of 

CO2, and that all requirements in the GS rule are designed for the purpose of protecting USDWs 

from endangerment. The SDWA does not provide the UIC Program with the authority to develop 

regulations for all areas related to GS, such as releases to the atmosphere. 

EPA acknowledges that GS falls within the broader context of CCS and the need for regulatory 

clarity to ensure that USDWs are protected from endangerment. In developing the final GS rule, 

the Office of Water coordinated with other Agency program offices and across federal agencies 

(e.g., with the Department of Energy; United States Geological Survey; Bureau of Ocean Energy 

Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau 

of Land Management). The Agency continues to evaluate areas of potential applicability of other 

Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource 

Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, 

3
and Liability Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of 

GS and CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize 

redundancy and maximize efficiencies for owners or operators. For additional information, 

please see the discussion entitled "How Does This Rulemaking Relate to Other Federal 

Authorities and GS and CCS Activities?" in the preamble to the final GS rule. 

Letter ID: 0156 Comment ID: 22619 Letter Lines: 116 to 131 

Comment Code: 1540 1.2.3.2 Climate change legislation 

Comment: One simple to articulate but difficult /complex to answer question that must be 

resolved is: Is compliance with the requirements of a Class VI well rule 

sufficient to establish that CO2 has not been emitted to the atmosphere for the 

purposes of accounting for a firm’s annual CO2 emissions and therefore assessing 

that firm’s compliance with future climate policy? 

It is clear that the answer to this question is not a simple "yes" or "no." For 

example, there are good GS reservoir management practices that could lead to the 

intentional, controlled release of some previously injected CO2 that would not 

be consistent with creating verified CO2 emissions reductions. 

As the USEPA revises and finalizes this draft Class VI rule, it must begin to 

devote significant attention to these issues and begin to communicate and 

dialogue with numerous classes of stakeholders to get their input on how 

compliance with the Class VI rule will be integrated into a larger national 

climate policy. 

Individual Response: EPA acknowledges that carbon crediting and greenhouse gas accounting 

are important issues. However, these issues are outside of the UIC Program's authority under the 

Safe Drinking Water Act and outside the scope of this rulemaking. The UIC requirements are 

designed to ensure that where GS is employed, it is done in a manner that protects USDWs from 

endangerment. 

EPA acknowledges that GS falls within the broader context of CCS and the need for regulatory 

clarity to ensure that USDWs are protected from endangerment. In developing the final GS rule, 

the Office of Water coordinated with other Agency program offices and across federal agencies 

(e.g., with the Department of Energy; United States Geological Survey; Bureau of Ocean Energy 

Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau 

of Land Management). The Agency continues to evaluate areas of potential applicability of other 

Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource 

Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, 

and Liability Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of 

GS and CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize 

redundancy and maximize efficiencies for owners or operators. For additional information, 

please see the discussion entitled "How Does This Rulemaking Relate to Other Federal 

Authorities and GS and CCS Activities?" in the preamble to the final GS rule. 

4
In a separate rulemaking under authority of the Clean Air Act, EPA is amending the Greenhouse 

Gas (GHG) Reporting Program at 40 CFR Part 98 to add reporting requirements for facilities 

that conduct GS (subpart RR) and all other facilities that inject CO2 underground (subpart UU). 

For additional information, see the section of the final GS rule preamble entitled, "How Does 

Mandatory Reporting of Greenhouse Gases (GHGs) Relate to This Rulemaking?” and the GHG 

Reporting Program rulemaking and docket. 

Letter ID: 0156 Comment ID: 22620 Letter Lines: 133 to 137 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: Page 43520. As correctly noted by the USEPA in the draft Class VI rule, the 

financial responsibility requirements of the SDWA do not extend to activities 

not related to protection of USDWs. So this is another example of the need to 

understand what else is needed to take this Class VI rule and make it part of a 

national climate policy. 

Individual Response: EPA clarifies that the Class VI GS requirements are designed to ensure 

that, where deployed, GS is conducted in a manner that protects USDWs from endangerment. 

The requirements apply to owners or operators of injection wells used to inject CO2 for 

permanent storage. The Class VI GS rulemaking is promulgated under Safe Drinking Water Act 

authority and does not relate to any endangerment and cause or contribute findings under the 

Clean Air Act. The Class VI GS requirements do not depend upon, and are unaffected by, Clean 

Air Act endangerment and cause or contribute findings. 

Letter ID: 0156 Comment ID: 22621 Letter Lines: 139 to 177 

Comment Code: 1540 1.2.3.2 Climate change legislation 

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

Comment: On the Issue of Primacy: An Example of the Challenge Inherent in "Filling in the 

Missing Linkages between Class VI Rule and a Larger National Climate Policy" 

Given the need to link the issuance and compliance with a Class VI injection 

permit to a larger national climate policy and eventually the need to link that 

U.S. national climate policy to an international climate policy regime, careful 

consideration should be given about how high the bar should be set for granting 

primacy to States, Territories, and Tribes. There is a significant imperative 

to make sure that CCS derived emissions reductions are comparable (and more 

precisely fungible) with GHG emission reductions obtained by implementing other 

greenhouse gas mitigation technologies and measures. A delicate balance must be 

sought between the desire to delegate authority to the local level with a need 

to preserve a sufficient level of national uniformity in how CO2 storage is 

5
carried out in practice. At a very minimum, the USEPA needs to recognize and 

reject as insufficient such reasoning that says because a state has shown that 

it can handle the Class II program they should also be given primacy for Class 

VI wells. The requirements to eventually integrate this proposed Class VI rule 

which in its present form is bounded by the SDWA into a much larger climate 

protection regulatory structure implies that the decision to grant primacy must 

be deliberate and must explicitly take account of how it would complicate the 

smooth and efficient functioning of a national climate policy. 

The degree to which EPA changes what is proposed as a common federal rule for 

Class VI CO2 storage wells because some states might be further along in the 

development of their own CO2 storage regulations (see for example discussion of 

"Who implements the UIC program" p. 43497) must also take into account the need 

for an owner/operator of CCS infrastructure to eventually be able to take CO2 

injected under a class VI permit in Ohio, Georgia, Michigan, California, 

Washington State, etc. and turn that into a tradable/fungible emissions 

reduction credit (or a verified non-emission) that could be used to satisfy the 

requirements of a national climate policy. The degree to which the federal 

class VI CO2 storage policy should be amended to allow for discrepancies in how 

individual states are currently planning on regulating CO2 storage must take 

into account the need to create an economically efficient national climate 

change policy. This consideration goes well beyond the boundaries of the SDWA 

but it must be addressed by the USEPA as a whole if this proposed Class VI 

storage rule is to be put into practice (e.g., if this issue is not resolved it 

is hard to see the private sector motivation for deploying CCS technologies even 

if the Class VI rule is in place). 

Individual Response: EPA agrees that it is important to balance flexibility and national 

consistency. EPA clarifies that the primacy approval processes for Class II and Class VI differ. 

The SDWA directs EPA to grant primary enforcement responsibility (or primacy) to the States 

through two statutory provisions. The first provision, under Section 1422, provides for States to 

demonstrate that their proposed UIC program is at least as stringent as the minimum Federal 

requirements in order to prevent endangerment of USDWs. The second provision, under Section 

1425, allows States to submit an alternative demonstration for their Class II programs (oil and 

gas) where the State only has to demonstrate that its proposed Class II program is an effective 

program to prevent underground injection that endangers USDWs. 

EPA acknowledges the expertise of state oil and gas agencies that have been regulating Class II 

wells for decades under section 1425 of SDWA. These agencies already understand many of the 

issues pertaining to Class VI wells and have experience with CO2 injection, subsurface 

operations, and pipeline transport, as well as familiarity with local interests and the SDWA. EPA 

assumes that this experience, along with the agencies' familiarity with UIC permitting 

requirements, will help facilitate the adoption of Class VI primacy programs and assumes that 

many states with Class II programs will choose to have the Class II primacy agency implement 

the Class VI program. However, EPA clarifies that, while there are many similarities between 

Class II and Class VI wells, additional requirements are needed to fully address the unique nature 

6
of Class VI wells for CO2 GS, and because GS wells are not oil and gas wells, they must be 

regulated under authority of Section 1422 of SDWA. 

EPA believes that the requirement that states' regulations meet the minimum federal 

requirements will promote national consistency. To further ensure the final rule is applied 

consistently, EPA is developing guidance documents for states that describe the process of 

applying for and receiving primary enforcement responsibility (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. 

EPA acknowledges that some states and tribes are developing statutory frameworks, regulations, 

technical guidance, and strategies for addressing broader issues related to CCS and GS, and 

encourages states to seek primacy for Class VI wells to further these efforts. 

EPA acknowledges that carbon crediting and greenhouse gas accounting are important issues. 

However, these issues are outside of the UIC Program's authority under the Safe Drinking Water 

Act and outside the scope of this rulemaking. The UIC requirements are designed to ensure that 

where GS is employed, it is done in a manner that protects USDWs from endangerment. All of 

the requirements of the GS rule are for the purpose of protecting USDWs from endangerment, 

consistent with the UIC Program's authority under SDWA. 

In a separate rulemaking under authority of the Clean Air Act, EPA is amending the Greenhouse 

Gas (GHG) Reporting Program at 40 CFR Part 98 to add reporting requirements for facilities 

that conduct GS (subpart RR) and all other facilities that inject CO2 underground (subpart UU). 

For additional information, see the section of the final GS rule preamble entitled, "How Does 

Mandatory Reporting of Greenhouse Gases (GHGs) Relate to This Rulemaking?” and the GHG 

Reporting Program rulemaking and docket. 

Letter ID: 0156 Comment ID: 22622 Letter Lines: 179 to 187 

Comment Code: 1540 1.2.3.2 Climate change legislation 

Comment Code: 2320 1.7.2 Comments on Alternative 1 

Comment: Page 43504. In laying out its reasoning for why it did not select Regulatory 

Alternative Number 1 as the basis of the proposed Class VI rule, the USEPA 

correctly notes that there is value in having a common federal approach as there 

are many potential CCS adopters that will operate facilities in numerous 

different states. This is true and it is appropriate for USEPA to note this. It 

is also important to realize that there are numerous reasons for pursuing a 

common federal approach and that decision will cascade through numerous parts of 

the proposed rule and how it is implemented in practice and how it is integrated 

into a future national climate policy. 

Individual Response: As described above, EPA agrees that a consistent approach to regulating 

GS activities across the United States is important. 

7
EPA believes that the technical requirements in Regulatory Alternative 3 build upon the existing 

UIC regulatory framework for deep wells and are appropriately tailored to address the unique 

nature of full-scale CO2 GS, including the volumes of CO2 being anticipated for long-term 

storage, the buoyant and mobile nature of the injectate, and its corrosivity in the presence of 

water. 

This approach provides a foundation for national consistency in permitting of GS projects, 

promotes USDW protection, incorporates flexibility or the discretion of the permitting authority 

when appropriate, and seeks to limit burden on owners or operators and permitting agencies. The 

tailored approach in this alternative (and the final GS rule) modifies the existing UIC 

requirements for site characterization, area of review, well construction, mechanical integrity 

testing, monitoring, well plugging, post-injection site care, and site closure, to address full-scale 

GS. 

Letter ID: 0156 Comment ID: 22623 Letter Lines: 189 to 209 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: On Allowing Class II EOR and Class VI GS to Evolve on Parallel Tracks: An 

Example of the Challenge Inherent in "Filling in the Missing Linkages between 

Class VI Rule and a Larger National Climate Policy" 

The USEPA is to be commended for resisting numerous calls from a number of 

stakeholders to fit GS CO2 storage into the existing framework for CO2-driven 

enhanced oil recovery (EOR). It is critically important that all stakeholders 

understand that these are very different processes with distinct infrastructures 

and operating practices and which are driven by different economic motives. 

The fact that they both inject CO2 into the deep subsurface is not a sufficient 

reason to treat CO2-driven EOR and GS CO2 storage in the same regulatory manner 

(see page 43502, "Why is EPA Proposing to Develop a New Class of Injection Well 

for GS of CO2?" as well as the section on that same page (How Would this 

Proposal Affect Existing Injection Wells Under the UIC Program?) 

Page 43502. Again, the USEPA should be commended for critically thinking 

through the extent to which Class II EOR practices and future Class VI CO2 

storage are similar in practice. Allowing for the possibility of conversion of 

Class II wells into Class VI wells is a reasonable step to take which might, in 

a very limited number of instances in specific regions of the U.S., lower the 

cost of complying with the proposed Class VI rule. And the proposed Class VI 

Individual Response: EPA agrees that tailored requirements for Class VI wells are necessary to 

address the unique nature and risks associated with injecting large volumes of CO2 and to ensure 

that USDWs are protected from endangerment. The GS rule contains tailored requirements for 

8
the permitting, geologic site characterization, AoR and corrective action, well construction, 

operation, mechanical integrity testing, monitoring, well plugging, post-injection site care, and 

site closure of GS wells that directly address issues unique to the nature of large-scale CO2 

injection for GS. 

EPA also agrees that the risks posed by long term storage of CO2 for GS cannot be addressed 

under existing UIC requirements, such as those for Class II wells. EPA believes that there are 

significant differences between how projects are operated, as well as the risks posed by these 

different injection activities. The new tailored approach of the GS rule was designed to address 

the general risks deep injection may pose to USDWs and was tailored specifically to address the 

risks posed by long term storage of CO2 (i.e., very large volumes, very long time-periods, and 

reservoir pressure conditions). 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. For more information, please see the discussion on 

transition of Class II wells in the preamble to the final GS rule. 

Letter ID: 0156 Comment ID: 22624 Letter Lines: 210 to 234 

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

Comment: rule is correct in clearly stating that only the construction requirements could 

be grandfathered assuming that all other aspects of the proposed Class VI rule 

are fulfilled (e.g., identifying and remediating all artificial penetrations 

within the AoR). This is a clear demonstration that the USEPA understands that 

simply injecting CO2 into the deep subsurface does not mean that Class II CO2 

driven EOR and Class VI GS are the same thing. However, it is not clear if the 

USEPA has gone far enough in differentiating between these two practices. In 

particular, the proposed Class VI rule should be explicit as to whether 

hydrocarbon recovery will still be allowed for wells/fields that have been 

permitted under Class VI. That is, a class VI well that is injecting CO2 in 

order to drive oil or natural gas towards adjacent production wells is not 

completely consistent with the overarching goal of the Class VI rule of 

permanently isolating CO2 from the atmosphere (i.e., some of the injected CO2 

will come up with the produced oil or gas, in some cases significant quantities 

of the injected CO2 will come up the production wells). The USEPA should 

consider whether it should explicitly state that the "grandfathering" of the 

construction requirements for Class II wells is also contingent upon the 

cessation of hydrocarbon production processes. Should this grandfathering only 

9
be allowed in depleted oil and gas fields that are no longer going to be used 

for enhanced hydrocarbon recovery and will exclusively be used for CO2 storage? 

This issue of grandfathering of Class II wells must also be a part of EPA’s 

needed deliberations about what else it needs to do in terms of rule making that 

lies outside of the SDWA to make CO2 stored in accord with the Class VI rule 

into something that can be used in the accounting framework of a national 

climate policy program. 

Individual Response: EPA agrees that a cautious approach to grandfathering is appropriate, 

particularly given that the converted well will be used for a substantially different process, which 

involves increased reservoir pressures associated with large volumes of stored CO2 and the 

corrosivity of CO2 in the presence of water. The final GS rule provides for the construction of 

these wells to be grandfathered (per 146.81(c)). EPA has included a requirement in the final GS 

rule that owners or operators seeking to convert existing wells for long term storage must 

demonstrate to the Director that the grandfathered wells were engineered and constructed meet 

the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at 

§146.86(b) and §146.87(a). 

EPA adds that, following re-permitting as Class VI wells, these projects must be subject to the 

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure 

requirements in the final GS rule. EPA believes this is necessary, because following repermitting of the project as GS, many of the unique factors of GS sites (e.g., increased reservoir 

pressures associated with large volumes of stored CO2 and the corrosivity of CO2 in the 

presence of water) will result in an increased risk profile, warranting the specific requirements in 

the final GS rule. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in evaluating whether an injection project should be transitioned from Class 

II where the primary purpose is oil and gas production to Class VI where the primary purpose is 

long-term storage of large volumes of CO2. The guidance describes recommended methods the 

Director may use when determining changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

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

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

10
EPA adds that GHG accounting and broader climate policy issues are outside the scope of the 

GS rulemaking. 

Letter ID: 0156 Comment ID: 22625 Letter Lines: 236 to 311 

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between 

USDWs in certain circumstances 

Comment: On the Appropriateness of Allowing CO2 Storage above a USDW 

It seems that the overriding principle should be does the proposed Class VI rule 

help protect the wellbeing of humans and the health of the environment. Framing 

the issue in this way makes it clear that there is an explicit tradeoff being 

made about the use of USDWs for CO2 storage or the use of water bearing bodies 

that have more than 10,000 TDS but are shallower than another formation which 

has waters with less than 10,000 TDS. This calls for a flexible and site or 

region specific approach as opposed to an arbitrary criterion like "thousands of 

feet between the injection zone and overlying and underlying USDWs" - (page 

43512) If there are adequate caprocks above and below the "water bearing bodies 

that have more than 10,000 TDS but are shallower than another formation which 

has waters with less than 10,000 TDS" that should be a key (and explicitly noted 

in the final Class VI rule) criterion for deciding whether to allow a formation 

to be used for CO2 storage. 

The USEPA, as a whole, and not just the Office of Water that administers the UIC 

program, will likely need to create a transparent methodology for deciding 

whether it is better to use some specific deep saline-water bearing formations 

(total dissolved solids exceeding 10,000 mg/L) as repositories for anthropogenic 

CO2 or not. This is a complex decision that goes beyond the confines of the 

SDWA as one would not only need to consider the potential human uses for these 

waters (e.g., as a potential source of potable water via desalinization) or as a 

CO2 storage formation. This methodology should also take into account whether 

there are other potential large scale and economic means of reducing CO2 

emissions that could be employed to offset potential emissions and whether there 

are other bodies of water that could be treated to provide a more economical 

source of potable water. The methodology should be broader and more meaningful 

than simply asserting that either CO2 is injected into a given formation or it 

is vented to the atmosphere. The calculus here is more complex and nuanced. 

The USEPA should also explain what authority it has (or needs to be given) to 

ensure that any future wells (oil, gas, water, injection) that drill through a 

water bearing formation with greater than 10,000 TDS which has previously been 

used for CO2 storage are built to withstand the higher pressures and acidity of 

these formations without becoming pathways for the migration of previously 

stored CO2 out of the target storage formation. If the USEPA has no way of 

regulating the construction of production wells that penetrate through a water 

11
bearing formation that has been used for CO2 storage and if it believes that it 

will not be granted this authority, then this needs to bear on decisions to 

allow storage in formations that are shallower than a USDW. 

Lastly, it is important to note that my research group has performed preliminary 

analysis which sheds light on the extent to which this might be a significant 

issue. We have included a copy of this research along with our comments on the 

class VI rule. There are two points that are worth summarizing briefly here. 

o First, these are preliminary results. We stress that point because there is a 

lack of high quality and detailed data that would be needed to present a more 

rigorous analysis. This lack of high quality data is likely to persist for a 

very long time. 

o Second, it is clear to us from this analysis that the nation’s ability to cost 

effectively address climate change will not be significantly impacted regardless 

of whether the USEPA allows injection into formations that are shallower than 

the lowermost USDW or not, as the vast majority of the nation’s geologic CO2 

storage capacity is in formations that do not fall into this category (i.e., 

most DSF storage formations lie below the lowermost USDW). Having said that, it 

is clear that certain regions of the country might see their ability to deploy 

CCS constrained if the USEPA disallows the use of formations shallower than an 

USDW. While these impacts will be localized and region-specific it could be 

consequential for certain regions, firms, states and could narrow their 

portfolio of options for reducing CO2 emissions to the atmosphere. 

o This research of ours is documented in: 

CL Davidson, Dooley JJ, and RT Dahowski. 2008. "Assessing the Impacts of 

Future Demand for Saline Groundwater on Commercial Deployment of CCS in the 

United States." In the Proceedings of the 9th International Conference on 

Greenhouse Gas Technologies. PNNL-SA-63047, Pacific Northwest National 

Laboratory, Richland, WA. [SEE PDF TO VIEW THIS DOCUMENT.] 

CL Davidson, JJ Dooley, SA Finne, RT Dahowski. February 2008. "How do salinity 

constraints impact the U.S. CO2 storage resource?" Joint Global Change Research 

Institute, Pacific Northwest National Laboratory. Richland, Washington. PNNLSA-58998. [SEE PDF TO VIEW THIS DOCUMENT.] 

Individual Response: EPA recognizes that there is increasing demand for water resources and 

that technology improvements may make high TDS aquifers viable drinking water sources. EPA 

believes these potential resources should be considered when injection depth waivers are sought. 

Therefore, the final GS rule at §146.95(b) requires the Director to consider these issues in 

determining whether an injection depth waiver is appropriate. 

EPA adds that the GS rule requires that the Director, in evaluating whether a waiver is 

12
appropriate, must consider planned needs, potential and/or future use of USDWs and nonUSDWs in the area; along with whether alternative injection sites are available; community 

needs, demands, and supply from drinking water resources; and a plan for securing alternative 

resources or treating USDW formation waters in the event of contamination related to the Class 

VI injection activity. 

EPA clarifies that the purpose of the GS rule is to protect any formations that meet the definition 

of a USDW where GS is to be employed. It is not the intent of the GS rule to evaluate the 

tradeoffs for the use of deep saline formations. 

EPA is not changing the USDW definition; changing the definition of a USDW is outside the 

scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required 

under the SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term 

storage. For additional information on the waiver approach and aquifer exemptions for Class VI 

wells, please see the final rule and preamble, as well as EPA's responses to comments on the 

Notice of Data Availability and Request for Comment. 

Letter ID: 0156 Comment ID: 22626 Letter Lines: 313 to 329 

Comment Code: 4430 2.4.4.3.3 Injection into coal seams above USDWs (seeking comment) 

Comment: On page 43503, the EPA requests comment on whether GS CO2 storage in coal 

seams 

which lie above a USDW should be categorically prohibited. In keeping with the 

discussion above, it seems that a more robust set of metrics and a broader 

framework should be employed rather than a blanket prohibition. If there is a 

suitable coal seam that is isolated above and below by strong caprocks and if 

EPA has the ability to influence / control how drilling through this formation 

in the future might occur then there’s no obvious reason to prohibit a Class VI 

application. It would be more rigorous and more in keeping with the spirit of 

the SDWA to establish a set of technical benchmarks that need to be satisfied 

rather than seemingly ruling certain GS applications out. This comment also 

applies to the proposed prohibition on injection into "Other Formations" (p. 

43503); rather than creating an inflexible prohibition USEPA should work to 

establish rigorous benchmarks and thresholds that would need to be satisfied to 

allow CO2 storage in these formations. If these benchmarks are difficult to 

satisfy because there is solid reasoning for creating higher thresholds, then 

that would have the same impact as a prohibition but still leave the door open 

for technological progress to make it feasible. 

Individual Response: The final GS rule does not categorically preclude or prohibit injection 

into any type of formation, including coal seams. Instead, the requirements are designed to 

ensure protection of USDWs from endangerment through proper siting, well construction, 

operation, monitoring, and PISC at all sites selected for GS. 

EPA recognizes that some types of formations, such as coal seams and basalts, are typically 

13
shallow and above the lowermost USDW. EPA expects that most injection wells conducting GS 

in these shallow formations will be permitted as Class VI wells and such wells will be issued 

waivers, provided that their owners or operators can meet all of the requirements for an injection 

depth waiver at §146.95 and demonstrate that such injection can be performed in a manner that 

protects USDWs, as long as appropriate protections are in place. The Class V experimental 

technology well classification, may, in some instances be an appropriate permitting alternative. 

This decision should be informed through a discussion between the injection well owner or 

operator and the Director to determine the purpose and proper design of the well. 

For additional information on the waiver approach and aquifer exemptions for Class VI wells, 

please see the final rule and preamble, as well as EPA's responses to comments on the Notice of 

Data Availability and Request for Comment. 

Letter ID: 0156 Comment ID: 22627 Letter Lines: 331 to 336 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: In the actual text of the proposed rule’s definition of key terms (page 43535), 

a geologic storage project is specifically defined as one in which wells are 

used to "emplace a carbon dioxide stream beneath the lowermost USDW." Was this 

intentional to rule out these other practices that are mentioned in the preamble 

as items that are still under discussion, by defining a GS project in this 

narrow manner in the draft rule language? 

Individual Response: EPA disagrees with the suggested edit and retains the language: "emplace 

a carbon dioxide stream beneath the lowermost USDW." EPA has modified the definition of 

geologic sequestration project to read as follows: “Geologic sequestration project means an 

injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW; or, wells used for geologic sequestration of carbon dioxide that have been 

granted a waiver of the injection depth requirements pursuant to requirements at §146.95; or, 

wells used for geologic sequestration of carbon dioxide that have received an aquifer exemption 

expansion. It includes the subsurface three-dimensional extent of the carbon dioxide plume, 

associated pressure front, and displaced brine, as well as the surface area above that delineated 

region.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0156 Comment ID: 22628 Letter Lines: 338 to 363 ; 382 to 426 

Comment Code: 6200 3.2 Comments on costing methodology 

Comment: Costs of Compliance with Class VI Rule Seem Methodologically Problematic 

14
On page 43524 EPA acknowledges that there is a need to revisit the Cost 

Analysis. EPA is commended for recognizing this need and is encouraged to 

consider fundamentally modifying large aspects of the Cost Analysis of this 

proposed class VI rule in subsequent revisions. The following is a selection of 

methodological issues in the economic analysis of this rule that argue in favor 

of rethinking the approach used here and making significant revisions for 

subsequent versions of the proposed Class VI rule. Suggestions to consider when 

revising the cost analysis include: 

o Page 43525. I see no rigorous basis for asserting that 22 projects will 

deploy in 25 years. It would be far better to present costs for a range (high, 

medium and low) of CCS deployment scenarios and then explain the basis of these 

scenarios. 

o Page 43527. I also do not understand the rationale for assuming that a power 

plant would only capture half of its lifetime emissions. Why was that deemed to 

be an appropriate assumption to make? 

o Page 43527. This page includes a reference to a research paper from my 

technical group as the basis for "we can use a long term average estimate of 

$3/tonCO2" for transportation costs. This research paper of ours does not speak 

to that specific monetary figure so I am not sure where that number comes from. 

There could be many instances where the cost of CO2 transport via a pipeline 

falls outside this $3/tonCO2 range. 

o Page 43530. It is important to note that the determination as to whether this 

proposed rule will cost the public and or the private sectors more than $100 

million in any given year is a function of the pace of CCS deployment which is 

something that will be driven by future climate policy. If there is no future 

national climate policy, then the cost of complying with this new rule should be 

close to $0. If there is a very tight / constraining climate policy, the cost 

could be significant. The USEPA is encouraged to model out a number of 

different climate policies and then assess what the incremental cost of 

complying with this rule is rather than basing the cost on assumptions about 

there only being 22 pilot projects over the next 25 years. Without doing this 

calculation, there is no way of knowing how robust the assertion is that the 

cost of complying with the proposed rule will not exceed $100 million in any 

given year. 

o Page 43527. The text here says that it is "unlikely that all coal plants 

would deploy CCS simultaneously." Not only is it "unlikely" it is simply 

impossible. There is no reason to hypothesize such a future deployment scenario 

and the computed results are meaningless for the purpose of public policy 

making. There is also no need to approach this particular calculation in this 

manner. My research group has completed a number of studies (as have other 

research groups) that could bound realistic CCS deployment rates. It is far 

15
better to use something within the realm of the possible as a basis for 

informing / justifying this important rule making. See for example: 

o MA Wise and JJ Dooley. 2008. "The Value of Post-Combustion Carbon Dioxide 

Capture and Storage Technologies in a World with Uncertain Greenhouse Gas 

Emissions Constraints." International Journal of Greenhouse Gas Control. In 

press. 

o Dooley JJ, RT Dahowski, and CL Davidson. 2008. "Comparing Existing Pipeline 

Networks with the Potential Scale of Future U.S. CO2 Pipeline Networks." In the 

Proceedings of the 9th International Conference on Greenhouse Gas Technologies. 

PNNL-SA-62187, Pacific Northwest National Laboratory, Richland, WA. 

o Wise MA, JJ Dooley, RT Dahowski, and CL Davidson (2007). "Modeling the 

impacts of climate policy on the deployment of carbon dioxide capture and 

geologic storage across electric power regions in the United States." 

International Journal of Greenhouse Gas Control. Volume 1, Issue 2, April 2007, 

Pages 261-270. doi:10.1016/S1750-5836(07)00017-5 

o Dooley, James, J.; Davidson, Casie L.; Wise, Marshall A.; Dahowski, Robert T. 

"Accelerated Adoption of Carbon Dioxide Capture and Storage within the United 

States Electric Utility Industry: the Impact of Stabilizing at 450 ppmv and 550 

ppmv." In, ES Rubin, DW Keith and CF Gilboy (Eds.), Greenhouse Gas Control 

Technologies, Volume I (pp. 891-899). Elsevier Science, 2005. 

Individual Response: In the cost analysis for the proposed rule, EPA used information from 

contacts in government and industry and its best professional judgment to develop the estimate 

of 22 baseline projects. The cost analysis also presented a sensitivity analysis that considered a 

50-percent increase and a 50-percent decrease in this estimated baseline. 

The cost analysis for the proposed rule assumed that each pro forma saline injection site would 

operate for 20 years and that two sites would be developed to cover the typical 40-year operating 

life of each power plant. The current cost estimate is based on one storage site operating for 40 

years. 

In updating the cost analysis baseline for the final rule, EPA consulted with DOE on the current 

number of planned or actual deployments because GS is in a nascent stage and there has been 

fluctuation in the number of planned projects. EPA also used publicly available data, e.g., from 

the Carbon Sequestration Leadership Forum's web site, to estimate the number of projects. Based 

on the information provided by DOE, the updated cost analysis uses an initial baseline of 29 

projects, including 13 in saline formations and 16 at ER sites, as described in Chapter 3 of the 

Cost Analysis for the Final GS Rule. The final rule cost analysis also presents the alternative 

deployment scenarios of 50 percent more or 50 percent fewer projects. 

The estimate of the costs for transporting CO2 has been updated from the previous $3 to $4.60 

per ton CO2 based on the following source: “Developing a Pipeline Infrastructure for CO2 

16
Capture and Storage: Issues and Challenges,” Feb. 2009, INGAA Foundation. 

For additional information on the final costing approach, please see the final cost analysis and 

technology and cost document in the final rule docket. 

Letter ID: 0156 Comment ID: 22629 Letter Lines: 365 to 380 

Comment Code: 6220 3.2.2 Assumptions about the number of monitoring wells (seeking 

comment) 

Comment: o Page 43528. The conclusion that "monitoring requirements account for 60 

percent of the incremental regulatory costs, of which 70 percent is incurred for 

the construction, operation, and maintenance of monitoring wells" is likely 

heavily influenced by the assumption that there would be three monitoring wells 

for each injector well. The assumption that there are three monitoring wells 

per injector well is a significant cost driver. It is not clear that this would 

hold true in a field with multiple injector wells; for example a five spot 

injection pattern would require 15 monitoring wells, which could be excessive. 

For GS projects that have very large injection fields with numerous injector 

wells there is no reason to believe that this 3:1 ratio would hold true. USEPA 

should consider modeling out a number of different deployment scenarios to see 

how robust this assertion is. This seems to be a worthwhile effort as this is 

the largest cost component caused by this Class VI rule and therefore this 

estimated cost is one that could receive a good deal of attention. My sense is 

that adhering to this 3:1 ratio exaggerates the cost of the proposed Class VI 

rule. 

Individual Response: EPA recognizes that the number of monitoring wells associated with GS 

projects will be site-specific and vary based on many factors, including the local geologic 

characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 

injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to 

the number of injection wells; EPA clarifies that the number of injection wells was based on the 

size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly 

based on the size of the AoR. Because ER project sites have injection wells that are more 

clustered than those in saline formations, the AoR and the number of monitoring wells were 

anticipated to be smaller at an ER project site compared to a saline formation project. EPA 

retained this assumption regarding the density of injection wells for the final rule analysis, but it 

changed its assumption on the number of monitoring wells at each site. For the final rule, the 

Agency assumes one monitoring well above the injection zone per two square miles of AoR; for 

monitoring wells into the injection zone, the Agency assumes one monitoring well per four 

square miles. EPA assumes monitoring wells into the injection zone will also be used to sample 

above the injection zone. The number of monitoring wells assumed for each project type is 

presented in Exhibit 5.2 of the Cost Analysis. 

Because the actual number of monitoring wells that will be necessary for a given project site is 

uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells 

17
by applying a 25 percent decrease and increase in monitoring wells per project type to the 

original assumptions. This change results in annualized incremental rule costs approximately 16 

percent less and 16 percent greater than costs estimated for the primary analysis (as shown in 

Exhibit 5.26 of the Cost Analysis). 

For additional information on EPA's final regulatory approach, including testing and monitoring 

requirements, please see the final rule and preamble. 

Letter ID: 0156 Comment ID: 22630 Letter Lines: 428 to 441 

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

trapping mechanism) 

Comment: Demonstrating Sufficient CO2 Storage Capacity 

Page 43536. The draft Class VI rule states that the applicant is required to 

identify "An injection zone of sufficient areal extent, thickness, porosity, and 

permeability to receive the total anticipated volume of the carbon dioxide 

stream." This is a good requirement but it is incomplete. There needs to be 

some time element here. That is the proposed rule needs to address "total 

anticipated volume" over what period of time. There is no need to establish an 

arbitrary quantitative figure here (e.g., "over 40 years"). Rather the 

calculation could be predicated on the expected lifetime of the facility, the 

duration of the injection permit, etc. It would be prudent to modify this 

sentence to explicitly communicate that the USEPA was not considering "the total 

anticipated volume of the carbon dioxide stream" for any given year of 

operations. 

Individual Response: The Agency agrees with the commenter, in the final regulation, the owner 

or operator must demonstrate that the receiving formation (injection zone) is "sufficient... to 

receive the total anticipated volume of the CO2 stream" (§146.83 (a)(2)). In addition, the 

Director will also consider the owner or operator's proposed AoR and corrective action plan, in 

which the owner or operator must delineate, through modeling, the predicted extent of the CO2 

plume over the duration of the project. 

Letter ID: 0156 Comment ID: 22631 Letter Lines: 443 to 472 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: Lack of Clarity throughout Draft Rule with respect to the "CO2 Stream" 

Page 43493 and 43535. The draft Class VI rule has not adequately specified the 

critical concept of the "CO2 Stream." There are many instances in the rule where 

critical decisions are made with respect to the "CO2 stream," but this term 

itself is not well defined nor does it seem to be consistently used. 

18
o Page 43497. Under "Potential USDW Impacts" the text says that the "CO2 stream" 

may contain other impurities and lists as an example H2S. 

o Page 43493. The Definition of "Geologic Sequestration" only speaks to CO2 

being injected. 

o Page 43496 contains a discussion about whether CO2 is a commodity or a 

pollutant. This issue of whether CO2 is a commodity or a pollutant is a red 

herring as far as this Class VI GS rule is concerned and EPA should be commended 

for saying that its ability to regulate CO2 injection under the SDWA is not 

contingent on determining whether it is a commodity or a pollutant. However, 

the rule is never very clear about what an acceptable "CO2 stream" is. 

o Pages 43503 and 43504. Are a bit clearer on what is and is not a "CO2 stream" 

in the context of a Class VI well but it still is not clear what is allowed and 

what is not. 

o Page 43535. Defines the "carbon dioxide stream" as CO2 from an anthropogenic 

source "plus incidental associated substances derived from the source materials 

and the capture process" as well as any tracers. This is more precise as it 

clearly would rule out the intentional comingling of other gaseous waste 

products that were not derived from the primary anthropogenic CO2 point source. 

Yet it still hinges on the rather vague concept of "incidental". 

Individual Response: The final definition of carbon dioxide stream at §146.81(d) remains 

unchanged from the rule proposal and reads as follows: “Carbon dioxide that has been captured 

from an emission source (e.g., a power plant), plus incidental associated substances derived from 

the source materials and the capture process, and any substances added to the stream to enable or 

improve the injection process. This subpart does not apply to any carbon dioxide stream that 

meets the definition of a hazardous waste under 40 CFR part 261.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0156 Comment ID: 22632 Letter Lines: 474 to 486 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

Comment: The issue of how pure the "CO2 stream" needs to be and whether trace or more 

significant quantities of other gases or liquids can be injected into a Class VI 

well is a critical issue that will influence the overall economics of CCS and 

could impact the safety and efficacy of GS. Greater clarity on this issue 

(while still allowing for some site-specific flexibility) would help the 

19
business community better understand what the cost of using CCS will be. The 

USEPA is encouraged to continue trying to narrow the definition of the "CO2 

stream" in subsequent versions of the draft rule. While this is a difficult 

issue and there is no obvious "correct answer", USEPA is encouraged to continue 

research and dialogues with various stakeholders to see if a narrower definition 

of what degree of co-injection is allowable for a Class VI well. It is possible 

that it could take many years maybe even decades to finalize this but it is 

important to begin pursuing it now. 

Individual Response: EPA understands that many CO2 streams may be relatively pure, and 

research indicates that the estimated amounts of impurities in a CO2 stream are likely to be low. 

However, these estimates are based on limited information, and uncertainties remain about the 

expected concentrations of impurities from the various types of CO2 streams. The concentrations 

of minor and trace elements in CO2 streams for GS projects are likely to vary by facility, coal 

composition, plant operating conditions, and pollution removal technologies. 

The GS rule does not set generic purity standards for CO2 injectate streams (e.g., a percent 

CO2). Instead, the GS rule addresses the quality and quantity of impurities by requiring owners 

or operators to submit information on the source of the CO2 and its physical and chemical 

properties. Specifically, the GS rule requires the owner or operator to submit data about the site, 

including an analysis of the chemical and physical characteristics of the CO2 stream, as required 

at §146.82(a)(7)(iv), and information on the compatibility of the CO2 stream with fluids in the 

injection zone and minerals in both the injection and the confining zones and the materials used 

to construct the well, per §146.82(c)(3). This information can help the Director determine the 

potential for geochemical reactions between the injectate (CO2) and the host geologic 

formations, which could result in the plugging of pore spaces or the dissolution of formation 

minerals. 

Letter ID: 0156 Comment ID: 22633 Letter Lines: 488 to 517 

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: No Minimum Injection Depth Specified 

Page 43511. It is difficult to envision that there will be widescale deployment 

of CCS that would utilize formations that are shallow enough to favor injection 

of CO2 as a gas and not as supercritical fluid. It seems that a better way to 

approach this from a regulatory standpoint would be to require injection at 

depth that would call for injection as a supercritical fluid but to allow the 

Director to waive that requirement for cause and that the waiver would be 

contingent on the Class VI permitee satisfying additional requirements designed 

to ensure that the overarching goals of the SDWA and other environmental 

policies are fulfilled. 

It seems odd and inconsistent to not specify a minimum depth when CO2 is being 

injected into a water bearing formation that is below the lower most USDW, but 

20
EPA is proposing that there would need to be "thousands of feet between the 

injection zone and [BOTH] the overlying and underlying USDWs." (p. 43512). The 

overarching goal of the Class VI rule making is to protect USDWs and human 

health and welfare. If CO2 is buoyant and there are concerns about it migrating 

out of the target injection zone, it doesn’t seem consistent to specify a 

minimum depth in one relatively small subset of potential GS applications 

(injection of CO2 into a formation above the lowermost USDW) but not define a 

minimum depth for the vast majority of GS applications (injection of CO2 below 

the lower most USDW). 

Lastly, perhaps "depth" is too narrow of a concept of what is being discussed 

here. "Deeper than any USDW and not in communication (i.e., not connected 

hydrodynamically or via faults or other intrusions) with any USDW" or "Deeper 

than any USDW and geochemically and geomechanically isolated under current and 

modeled co- and post-injection conditions with any USDW" seems much closer to 

the mark in terms of protecting what society wants protected. 

Individual Response: EPA disagrees that it is appropriate to set a minimum injection depth for 

GS projects and the Agency believes that a determination of site-suitability for GS (i.e., that 

subsurface formations will receive and confine injected CO2) should be made on a site-specific 

basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and 

project-specific information to the Director to demonstrate that the site meets the minimum site 

criteria at §146.83, that the CO2 will be contained within the injection formation, and that 

USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs, as long as appropriate protections 

are in place. The final GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements for injection into non-USDW 

formations above and/or between USDWs. The waiver approach requires the submission of 

extensive, site-specific information (in conjunction with the permit application submission) to 

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be 

done in a manner that is protective of USDWs. The requirements are designed to ensure that the 

owner or operator, the Director, and the Regional Administrator consider, on a site specific basis, 

the implications, benefits, and challenges associated with GS and ensuring water availability and 

USDW protection. 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: 0156 Comment ID: 22634 Letter Lines: 519 to 533 

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

Comment: It is Appropriate to Utilize both a Fixed Time Frame and Performance Standard 

for Establishing the Period of Post Closure Monitoring 

21
Given humanity’s knowledge about GS deployed at the scale of millions of tons 

per year for decades at a given injection field is quite slim, the USEPA’s 

proposal of a fixed time frame in conjunction with a performance standard 

appears to be an appropriate balance between discharging its responsibilities to 

protect human health and the environment and not placing overly burdensome, 

unneeded requirements on prospective GS owner / operators (pp 43519-43520). The 

50 year time frame will allow owners / operators to budget for post site closure 

within the bounds of what is currently known. The performance standard is an 

assurance to the public that a site will not be released until it has reached a 

certain point of stability. Given where humanity is with GS, the USEPA should 

be commended for crafting this compromise and should retain this language in 

subsequent versions of this draft Class VI rule. 

Individual Response: EPA acknowledges the commenter’s support and has implemented a 

combination fixed timeframe and performance standard approach for post-injection site care 

monitoring for Class VI wells in the final GS rule. The PISC requirements in the final GS rule, as 

specified in §146.93(b), incorporate a combination of a fixed timeframe and a performance 

standard approach. EPA believes that a default PISC timeframe of 50 years, with Director's 

discretion to shorten or lengthen this timeframe, combined with a site-specific Director’s 

discretion to create an alternative PISC time frame, ensures that USDWs are protected. The GS 

rule offers owners or operators flexibility regarding the duration of the PISC timeframe by: (1) 

allowing the Director discretion to shorten or lengthen the PISC timeframe during the PISC 

period based on site-specific data, pursuant to requirements at §146.93(b); or (2) affording the 

Director discretion to allow a Class VI well owner or operator to demonstrate, based on 

substantial data during the permitting process, that an alternative PISC timeframe may be 

appropriate if it ensures non-endangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

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

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

impacts. 

Letter ID: 0156 Comment ID: 22635 Letter Lines: 535 to 542 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: Requirement to Document GS Sites and Pass that Information on to Future 

Potential Users of the Land Above as well as any Subsurface Zones Is Appropriate 

Page 43541. It is appropriate for the USEPA to require that steps be taken to 

document the CO2 injection formation and to ensure that information is passed on 

into the future. The steps spelled out here are reasonable and not overly 

burdensome (e.g., survey plat and deed for land must include a notation that the 

22
deep subsurface was used for CO2 storage). This language should be retained in 

subsequent versions of the Class VI rule. 

Individual Response: The GS regulation at §146.93(g) requires the owner or operator to record 

a notation that the land has been used to sequester CO2 on the deed to the facility property at the 

time of site closure. 

Letter ID: 0156 Comment ID: 22636 Letter Lines: 544 to 592 

Comment Code: 3420 2.2.2.1 Scope of the inventory process (e.g., reliance on publicly 

available information, depth of wells) 

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

comment) 

Comment: All Wells and "All Known Wells" are not the Same Page 43507 and 43517. The 

proposed Class VI rule needs to be much more precise in its use of language in a 

couple of key areas. The rule requires an applicant for a Class VI permit to 

"identify all artificial penetrations." What exactly does this mean? Is it all 

known artificial penetrations (the rule speaks to the operator "review(ing) 

available information")? What is the test for what is a known well or available 

information (does it require detailed field surveys or does one only need to do 

a quick search of a database of wells drilled in the area)? If on the other 

hand it means literally all human penetrations, then one must ask if this is 

technologically possible (e.g., are there technologies which would allow for the 

identification of a small diameter non-steel walled well that has no visible 

surface features)? Is there a danger in asking for something that can not 

actually be delivered? One can guess what was likely meant by "identify all 

artificial penetrations" in terms of drafting this rule but it is not at all 

clear how this would be opperationalized at actual prospective GS sites. 

More importantly on Page 43535 under "144.55 Corrective Action", the rule says 

that owners/operators need to identify the location of "all known wells" which 

seems to be a lesser standard. In the actual text of the rule (page 43526), the 

applicant is told "Only information of public record is required to be included 

on this map." Given how many times the rule and its preamble talk about old 

wells being a potential conduit for CO2 release from the storage formation, this 

seems like an overly lax threshold. It would seem appropriate to require the 

applicant survey the actual site itself for artificial penetrations that might 

not be in the public record (the survey could include a number of different 

methods / tools). Further on in this section, the applicant is asked to submit 

a "tabulation of all wells within the area of review which penetrate the 

injection or confining zones." Again, "all wells" and "all known wells" and how 

much work does one need to do to determine if they have tried to find "all the 

wells" must be better articulated in the final rule. This same kind of language 

shows up on page 43537 within the discussion of the Area of Review and 

Corrective Action. 

23
Lastly, given the large amounts of money involved in a commercial CO2 storage 

project, I would think that the electric production, oil and gas, or other large 

industrial company contemplating a large CCS-enabled facility would want (or be 

required) to go beyond simply collecting existing data as a way of decreasing 

risk and uncertainty. In this context, the proposed "requirement" for going 

beyond existing data could be imposed by entities other than state or federal 

environmental regulators and could be imposed by shareholders, a public utility 

commission, or a firm’s own board of directors. In terms of abandoned wells, it 

seems likely that commercial firms would see it to be in their own best interest 

to do some kind of physical search / assessment of whether there are any known 

or unknown wells within the area of review given the relatively minor cost 

associated with something like an aerial magnetic survey versus the costs 

associated with loss of CO2 and any fines, the cost associated with any required 

post-leakage activities, or simply the cost of litigation and or loss of good 

will associated with such sloppy management of a critical, capital intensive 

pollution abatement facility. 

Individual Response: EPA believes that, for the most part, data base and other public records 

searches will be sufficient to identify artificial penetrations in the AoR. This inventory and 

review process is similar to what is required of Class I and Class II injection well operators, that 

that the AoR and corrective action process for these well types has been successful. 

EPA is developing guidance on AoR and corrective action for GS sites. 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 agrees with commenters that, for most GS sites, relying on database and other public 

records searches (i.e., of "known" artificial penetrations) will be sufficient to meet the 

requirements at §146.84(c)(2). However, the Agency recognizes that there may be situations 

where additional surveys or research to locate wells may be appropriate. For example, there may 

be cases where the Director may determine that ground or airborne surveys for wells are 

appropriate, e.g., if there is reason to believe, based on knowledge of the site or of available data, 

that the incompleteness of information on known wells could compromise USDW protection 

from endangerment. In order to preserve the Director's discretion to require an operator to 

supplement a records search, EPA did not make the suggested change. EPA encourages owners 

or operators to expand their searches, as the commenter suggests. EPA adds that all corrective 

action must be performed pursuant to the approved AoR and corrective action plan, which 

affords the Director the discretion to require any additional information needed (including 

information that is not publically available) to ensure that all necessary corrective action is 

performed. 

24
Letter ID: 0156 Comment ID: 22637 Letter Lines: 594 to 600 

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

comment) 

Comment: In this same section (page 43526), the applicant is asked to submit information 

on "the presence and depth of seismic sources" but this falls under a heading 

that is limited to the "proposed storage site and overlying formations." So if 

a proposed GS site sat 10 cm, 10m or 10km north of any aspect of the New Madrid 

Fault, that would not be noted in the application. Limiting the scope of data 

collection to the boundaries of the project site might not be appropriate for 

data related to "the presence and depth of seismic sources" 

Individual Response: EPA believes that consideration of local and regional seismicity is 

important and this type of review is relevant to every project. The site characterization provisions 

in the GS rule, including a review of the local and regional geology, and detailed review of any 

known or potential seismically active terrain in the vicinity of a proposed GS site, are necessary 

to minimize the potential for induced seismic events or the reactivation of faults, which are a 

known potential risk associated with underground injection and are addressed in all aspects of 

the UIC regulations. 

Letter ID: 0156 Comment ID: 22638 Letter Lines: 602 to 626 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: It Should Be a Requirement to Periodically Revaluate Funds Set Aside for Well 

Plugging and Post-Injection Site Care Page 43520. The USEPA should mandate that 

owners / operators periodically update the cost estimate for well plugging, 

post-injection site care, ect. Given how long GS projects are likely to last, 

there is no reason to believe that the amount of money set aside at the start of 

the project even if it were invested in something that kept up with inflation 

would necessarily be sufficient to cover these costs. The US DOE Energy 

Information Administration in its Annual Energy Outlook: 2007 ( 

http://www.eia.doe.gov/oiaf/aeo/otheranalysis/cecei.html) documented how 

drilling and other associated costs have escalated at a rate that is far above 

the core inflation rate for the economy as a whole. On page 43522, the draft 

rule says "Trying to determine the cost for post injection site care, possible 

30 to 50 years in the future, could be difficult." Yes, it is difficult to 

understand what anything would cost 50 years in the future. However, one can 

figure out what it would cost to do those things now and then one could 

periodically reassess those costs. That is quite straightforward and the 

USDOE’s EIA maintains a Oil and Gas Lease Equipment and Operating Costs Index 

which could easily be used to true up these costs as needed to account for 

inflation (see 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_eq 

25
uipment_production/current/coststudy.html). The Oil and Gas Journal also 

publishes indices of construction costs which could be used to true up these 

costs over the life time of a GS project. Again, there are many reasons to 

mandate that these costs be revised periodically and if need be the 

corresponding financial assurance mechanisms should be revalued. 

Individual Response: EPA agrees that it is important to periodically update cost estimates that 

support financial responsibility determinations, which is why the final GS rule, at §146.85(c) 

requires the owner or operator to provide annual updates to the cost estimate to account for any 

amendments to the AoR and corrective action plan, the injection well plugging plan, the PISC 

and site closure plan, and the emergency and remedial response plan. EPA adds that the Director 

can also require the owner or operator to provide an adjustment of the cost estimate if the 

Director determines that the original demonstration is no longer adequate, as specified at 

§146.85(e). The owner or operator must also update the cost estimate for inflation annually under 

§146.85(c)(2). See the final rule and preamble for further discussion of EPA's final approach to 

financial responsibility. 

EPA will include DOE's EIA Oil and Gas Lease Equipment and Operating Costs and the Oil and 

Gas Journal as sources of information in the discussion on estimating costs in its guidance on 

financial responsibility. 

Letter ID: 0156 Comment ID: 22639 Letter Lines: 628 to 639 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: 90% of the Injection Zone or the Caprock’s Fracture Pressure Page 43510 under 

"Proposed Injection Well Operating Requirements." Citing the IOGCC report and 

the expert opinion of permit writers is not the most rigorous basis for 

asserting that injection pressure can not exceed 90% of fracture pressure for 

all GS applications. Perhaps in a Notice of Data Availability (NODA) for this 

rule, USEPA could ask for data or studies that would help establish a firmer 

basis for this threshold. This is an important criteria as it directly impacts 

how much CO2 can be put down a given well and therefore how many wells will be 

needed to handle the anthropogenic CO2 from a given facility. The number of 

injector wells is a key determinant of the cost of CO2 storage. On page 43538, 

this same language is found in the proposed rule text (i.e., not in the 

preamble). 

Individual Response: EPA believes that the injection pressure limits in the final GS rule are 

appropriate and necessary to protects USDWs from endangerment. The injection pressure limit 

for each GS project will be based on site-specific conditions, and be informed by data on the 

injection zone. During injection, the pressure in the injection zone must not exceed 90 percent of 

the fracture pressure of the injection zone, as specified at §146.88(a). The fracture pressure (and, 

therefore, the injection pressure) are based on site-specific geologic and geomechanical data 

collected during the site characterization process required at §146.82. Tests are available and 

have been used by injection well operators, e.g., Class I operators, to measure fracture pressure. 

26
Examples include the step-rate test, in-situ stress tests, and a combination of a long spaced sonic 

log with laboratory measurement of the mechanical properties of cores. To meet the GS 

requirements, the permitting authority would set the injection pressure limit at 90 percent of this 

value. 

The Director will also review geologic, hydrogeologic, and geomechanical information 

submitted by the owner or operator in setting permit conditions. If, based on this information, a 

lower pressure limitation is appropriate, the Director has the authority to set a lower limit in the 

operating permit. EPA clarifies that fracturing of the confining zone during injection and/or 

stimulation is also prohibited at §146.88(a). 

EPA published a Notice of Data Availability and Request for Comment on August 31, 2009 (74 

FR 44802) that described research underway at several pilot projects and LBNL and sought 

comment on any other research associated with potential environmental risks and risk 

management approaches for GS. EPA received a variety of comments and data in response, but 

none of the comments or information provided by commenters provided scientific rationale to 

support changing the injection pressure limitation. 

Letter ID: 0156 Comment ID: 22640 Letter Lines: 641 to 651 

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment) 

Comment: More importantly did the USEPA intend to tie this 90% pressure threshold to the 

fracture pressure of the "injection zone" or the fracture pressure of the 

"primary caprock / seal above the injection zone"? If a GS project was 

injecting at the bottom of a 500 meter thick interval of a sandstone, is there 

any harm in allowing for some amount of deformation to areas near the injection 

point in the target formation? In many areas, the caprocks are stronger than 

the injection zones based on the rock types, degree of cementation etc. In such 

cases, it may be good to have a mechanism where you can stimulate the injection 

zone more aggressively to increase permeability / injectivity. Fracturing of 

the injection zones may be critical in improving injection performance and even 

in making some of the marginal injectivity sites into viable sites. 

Individual Response: EPA clarifies that the injection pressure must not exceed 90 percent of the 

fracture pressure of the injection zone. The final rule retains this provision at §146.88(a). EPA 

believes that the 90 percent requirement, which was suggested by state representatives whom 

EPA consulted when writing the regulation, is a satisfactory margin of safety for well operation. 

EPA recognizes that there may be well completions which require intermittent treatments that 

include stimulation to improve wellbore injectivity. Stimulation of the injection zone during a 

well workover will be permissible, if approved by the Director (operators seeking to use 

stimulation must submit the proposed stimulation program as part of the permit application under 

§146.82(a)(9) where injection pressure limits will be set). EPA has also added a requirement that 

owners or operators notify the Director in advance of any planned stimulation activities, as 

specified at §146.91(d). During injection, the injection pressure must not exceed 90 percent of 

27
the fracture pressure, as specified in §146.88(a). EPA clarifies that the injection pressure limit at 

§146.88(a) applies only to the period of injection, not well stimulation. 

Letter ID: 0156 Comment ID: 22641 Letter Lines: 653 to 660 

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

circumstances 

Comment: It Is Appropriate to Require Class II Fields to be Recertified before Conversion 

to Class VI Fields Page 43512. It is appropriate for the USEPA to require a new 

aquifer exemption for a formerly Class II injection field if there is a desire 

to use that field for GS. EPA should retain this requirement in the final rule. 

Just because a formation was deemed appropriate for Class II activities, does 

not guarantee that it is suitable for GS and therefore EPA is right to ask for 

more fact finding and potentially remediation of artificial penetrations before 

allowing the formation to be exempted and used for GS. 

Individual Response: EPA recognizes that there are limited circumstances where aquifer 

exemptions for GS may be warranted, and the final GS rule allows for the expansion of the areal 

extent of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI 

injection for GS pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators 

granted expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet 

all of the tailored requirements for GS wells in the final GS rule. 

EPA agrees that Class II EOR/EGR owners or operators should reapply for exemptions before 

transforming to Class VI status. If an owner or operator applies for a Class VI permit to inject 

CO2 into a previously exempted aquifer (non-USDW) that is located above and/or between 

USDWs, the permit applicant must also apply for a waiver of the injection depth requirements 

pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the injection 

zone are protected from endangerment. 

EPA clarifies that the final rule precludes the issuance of new aquifer exemptions for Class VI 

GS wells; that is, aquifer exemptions will only be granted for projects that are transitioning from 

Class II EOR/EGR wells to Class VI. 

EPA adds that any Class II well owner or operator seeking to inject CO2 for the purpose of GS 

would need to have their well re-permitted as Class VI. The final Class VI regulations require 

that any owner or operator injecting CO2 for the primary purpose of long term storage obtain a 

Class VI permit with some special consideration for the fact that they are transitioning from a 

well not originally designed to meet Class VI requirements. The Director has the authority to 

determine at what point a Class VI permit is required for those projects that are transitioning 

from the primary purpose of EOR to long term storage of CO2. The final regulation provides a 

set of technical factors for the Director to evaluate in making this determination, at §144.19. EPA 

believes that this approach provides sufficient protection of USDWs when there is an increased 

risk to USDWs as compared to traditional Class II operations while allowing for site-specific 

flexibility. See the preamble and final rule for additional information on EPA's approach 

28
transitioning of Class II wells for GS. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and 

preamble, as well as EPA's responses to comments on the Notice of Data Availability and 

Request for Comment. 

Letter ID: 0156 Comment ID: 22642 Letter Lines: 662 to 679 

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

(seeking comment) 

Comment: Allowing the Director the Discretion to Ask for Additional Fact Finding on 

Supplemental Confining Layers Page 43505-43506. EPA specifically asks for 

comments on allowing the Director to require that additional confining zones be 

identified for certain projects. Assuming that the Director uses this authority 

to require more fact finding for cause (i.e., it is not a capricious request), 

then it seems as if USEPA has struck an appropriate balance here and should 

retain this flexibility in the final rule. Given the capital cost of something 

like an IGCC+CCS, it does not seem unreasonable to ask that cores be taken from 

a second or third overlying caprock if there is some reason to want to ensure 

that there are additional containment systems beyond the caprock immediately 

above the target injection zone. While the USEPA might receive comments saying 

that this is potentially a significant unknown cost that could delay CCS 

deployment, the cost of this additional fact finding is likely denominated in 

the millions of dollars or less while the rest of the complete end-to-end CCS 

facility could be worth tens of billions of dollars. Again assuming that this 

flexibility is only used when needed and for cause, it seems to be an 

appropriate and cost effective tool for ensuring the overall goals of the Class 

VI program are fulfilled. 

Individual Response: EPA acknowledges the commenter's support and agrees that, in some 

situations, the presence of additional confining and containment zones above the primary (i.e., 

lowermost) confining zone can improve USDW protection from endangerment. The final 

regulation retains the requirement at §146.83(b) which affords the Director discretion to require 

owners or operators to identify and characterize additional zones. 

Letter ID: 0156 Comment ID: 22643 Letter Lines: 681 to 714 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment: Dialogue between the Regulated and Regulator Isn’t Obvious The draft Class VI 

rule and especially the preamble assert numerous times that a key to ensuring 

the safety and efficacy of geologic sequestration is a well functioning dialogue 

between the regulated entity and the regulatory agency. There are at least 

three intertwined concerns I have with the way the current draft Class VI rule 

29
is written that if left unresolved would hamper a robust, meaningful dialogue 

between the regulated entity and the regulator has been created by this rule. 

1) The concept that there is "working" relationship between the permitee and the 

permit-granting agency doesn’t really come through here. This seems like a very 

arms length relationship. 

2) The draft rule never establishes that the process of moving from initial site 

selection to permitting, to operations to renewal of permits to closure is an 

iterative one between the operator and the EPA or state permit writer (acting as 

stewards of the public’s welfare) as new data are generated and incorporated 

into the site management plan. That is, the rule could do a much better job of 

explaining that the permittee and the regulator should be learning a great deal 

about how a particular geostorage field is operating in practice and that this 

knowledge will be factored into how the field is regulated in the future 

(including decisions about post closure). 

3) Data is collected but it is not clear how it is used by the regulator nor is 

it clear who has access to this data. In particular, there appears to be only 

two instances (one at the very earliest stages of site selection and the other 

before site closure) where the public is invited to learn and comment on a GS 

project. 

Given that humanity is in the early days/decades of CCS deployment, it seems to 

me that much could be learned by having closer and more frequent communication 

between the regulator and owner/operator of a GS project, and allowing for some 

dissemination of the massive amount of data generated by these projects. A more 

transparent and meaningful dialogue between these two parties would also help 

with stakeholder acceptance of CCS. 

Individual Response: EPA agrees that communication and coordination between owners or 

operators and permitting authorities are important. The GS rule incorporates a flexible approach, 

where operators of GS projects develop and implement site-specific plans for delineating the 

AoR, performing corrective action, testing and monitoring, and post-injection site care. EPA 

believes that the plans—which will 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 and that GS projects are permitted sited, constructed, operated, and closed in a manner 

that avoids releases of CO2 into USDWs. 

EPA is developing a number of technical guidances and implementation materials to assist 

owners or operators and Directors in the permitting process. These guidances will address how to 

perform many of the activities necessary for applying for a permit, including developing all 

required plans and conducting site characterizations that meet the requirements of §146.82. The 

guidances will be available on EPA’s website at 

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

30
Letter ID: 0156 Comment ID: 22644 Letter Lines: 716 to 728 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Much Data Is Collected; But how is it used and who has access to the data? 

o Page 43514 includes a requirement that mechanical integrity be demonstrated 

annually, but it does not say what is done with this information or what it is 

used for. How long is this data retained? 

o Page 43514 includes a requirement that owners / operators report semi-annually 

on the injection pressure, flow rate, temperature, volume and annular pressure 

and on MIT test results. What is the data collection method and who will have 

access to these data? Is it an open website like the Toxic Report Inventory 

(TRI) where any citizen could view this information, or is it a single hard copy 

report locked in a state or regional EPA office that can only be seen via a FOIA 

request by members of the public or other stakeholders? 

Individual Response: EPA has clarified the recordkeeping requirements in the final GS rule, 

which includes requirements that well plugging reports, as required at §146.92(d), post-injection 

site care data, as required at §146.93(f), and site closure reports, as required at §146.93(h), be 

kept for ten years after site closure. See the final rule and preamble for further discussion on 

EPA's final approach to post-injection site care. 

EPA will use the data to verify that the well and the site are behaving as predicted and within 

permitted guidelines to ensure that USDWs are protected from endangerment. In addition, the 

data may be used as evidence of a violation of a permit requirement that may result in an 

enforcement action under SDWA. The Agency clarifies that owners or operators may claim 

confidential business information under existing UIC regulations at §144.5. These requirements 

are applicable to all well classes. 

Letter ID: 0156 Comment ID: 22645 Letter Lines: 730 to 735 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: o Page 43514. EPA asks for "comments on the requirements for monitoring" but it 

is not clear that there are any requirements articulated here. The USEPA should 

require that data on the areal extent of the CO2 plume and the pressure front as 

well as any other relevant data from MMV be reported to EPA on an annual / semiannual basis. USEPA still must come to some consensus on how these data will be 

collected, who will have access to them, ect. 

Individual Response: EPA clarifies that the monitoring requirements for Class VI well owners 

or operators are presented in the final rule at §146.90. EPA is retaining the requirement at 

§146.91(a) for semi-annual reporting of monitoring and operational data, including data on 

31
monitoring and tracking the CO2 plume and pressure front. For additional information about 

monitoring requirements and reporting requirements see the preamble to the final rule. 

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional 

data management needs associated with Class VI activities and provides recommended 

guidelines on the types of data to be collected for tracking Class VI projects, reporting to EPA 

for compliance tracking, and transfer of data to EPA's GS data system. The recordkeeping and 

reporting guidance will be available on EPA's web site, at 

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

Letter ID: 0156 Comment ID: 22646 Letter Lines: 737 to 744 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: o Page 43514 under "Monitoring CO2 Movement and Reservoir Pressure", USEPA 

states that the owner/operator must compare the results of monitoring to 

baseline data but the text of the proposed rule does not require that this 

information be shared with the USEPA or state permitting agency. Isn’t this 

critically important information on how GS is working at a site? Isn’t that 

information needed by USEPA to understand whether the Class VI rule is effective 

in protecting USDWs and the other goals of the SDWA? There should be a 

requirement that this data and comparison be shared with regulators. 

Individual Response: EPA expects that CO2 plume and pressure front tracking data will be 

reviewed as part of the AoR reevaluation and plan update process. The final GS rule, at 

§§146.84(c), 146.90(j), and 146.94(d), requires owners or operators to review and update the 

AoR and corrective action plan, the testing and monitoring plan, and the emergency and remedial 

response plan throughout the life of the project. Owners or operators must review each plan and 

identify necessary amendments to the plan or demonstrate to the Director that no amendment is 

needed. These reviews must be performed within one year of an AoR reevaluation, following 

any significant changes to the facility (e.g., the addition of monitoring or injection wells), or 

when required by the Director. In no case can reviews occur less often than once every five 

years. Furthermore, §146.90(b) requires that the owner or operator continuously monitor 

injection pressure, rate and volume; the pressure on the annulus between the tubing and the long 

string casing; and the annulus fluid volume added. 

EPA believes that by requiring periodic reevaluations of the AoR, as required at §146.84(e), 

along with any revisions to the required plans that may be required based on the AoR 

reevaluation or other data collected during well operations, will promote an ongoing relationship 

between the permitting authority and the owner or operator, including discussion of all 

monitoring results. 

Letter ID: 0156 Comment ID: 22647 Letter Lines: 746 to 748 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

32
Comment: o Page 43517 contains a requirement to report various data on the performance of 

GS on a semi-annual basis, but again it is not clear how these data will be 

used, retained, or who has access to them. 

Individual Response: EPA has clarified the recordkeeping requirements in the final GS rule, 

which includes requirements that well plugging reports, as required at §146.92(d), post-injection 

site care data, as required at §146.93(f), and site closure reports, as required at §146.93(h), be 

kept for ten years after site closure. See the final rule and preamble for further discussion on 

EPA's final approach to post-injection site care. 

EPA will use the data to verify that the well and the site are behaving as predicted and within 

permitted guidelines to ensure that USDWs are protected from endangerment. In addition, the 

data may be used as evidence of a permit violation that would result into an enforcement action. 

The Agency clarifies that owners or operators may claim confidential business information under 

existing UIC regulations at §144.5. These requirements are applicable to all well classes. 

Letter ID: 0156 Comment ID: 22648 Letter Lines: 750 to 753 

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

Comment: o Page 43538. Owners and operators of Class VI wells are required to install 

and use continuous recording devices to monitor a number of critical performance 

variables. The rule does not specify how long these data are to be retained and 

who has access to them. 

Individual Response: The GS regulation at §146.91(f) requires injection well operators to retain 

monitoring records for ten years after the data is collected. The Director has the authority to 

request this data. 

Letter ID: 0156 Comment ID: 22649 Letter Lines: 755 to 764 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment: Who has access to reports on an ongoing GS project? 

o Page 43517. It is asserted that the requirement for "monitoring, testing, 

AOR, and corrective action" plans will help establish "an ongoing dialogue 

between the operator and the permitting authority." This reviewer just doesn’t 

see this "dialogue" in this rule. There is no discussion of how these plans are 

used and therefore this looks like a very distant and at arms length process. I 

am 100% in support of there being an ongoing dialogue between the operator and 

the regulator and I believe that these additional plans are a wise requirement 

for Class VI GS wells. 

33
Individual Response: EPA believes that the plans site-specific plans for delineating the AoR, 

performing corrective action, testing and monitoring, and post-injection site care —which will 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 and that GS projects are 

permitted sited, constructed, operated, and closed in a manner that avoids releases of CO2 into 

USDWs. 

EPA is developing a number of technical guidances and implementation materials to assist 

owners or operators and Directors, including a guidance that describes recommended approaches 

for developing, reviewing, and updating the GS project plans. The guidances will be available on 

EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0156 Comment ID: 22650 Letter Lines: 766 to 775 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: o Page 43517. Records retention of only 3 years after site closure. That seems 

incredibly short. Also it is not clear how this requirement to hold on to these 

data for three years after site closure is consistent with the owner operators 

requirement to discharge its responsibilities under the post closure period 

including establishing that non-endangerment continues to be the case. Wouldn’t 

access to baseline and data collected during the period of principal operations 

be needed to report out these findings during the period of post closure. This 

short record retention period also seems to undercut assertion of a open 

continuous dialogue being a center piece of how USEPA and any states that have 

Class VI primacy will ensure public safety. 

Individual Response: EPA has changed the recordkeeping requirement in the final rule to 

require that owners or operators retain records collected during the post-injection site care period 

for at least 10 years following site closure. EPA believes that the requirements that the owner or 

operator retain for ten years following site closure, records collected during the post-injection 

site care period at §146.93(f) and §146.93(h) are appropriate to ensure that data are available to 

support non-endangerment demonstrations and to address any concerns that may arise following 

site closure. This data will also support EPA's review of project data as part of the adaptive 

rulemaking approach. 

Letter ID: 0156 Comment ID: 22651 Letter Lines: 777 to 785 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: o Page 43517. USEPA asks for comments on electronic reporting. Yes, electronic 

reporting should be mandatory. USEPA also needs to find a way to ensure that 

electronic reports are eventually consolidated at a national level. Having the 

34
reports be submitted to a state but not having the reporting go any further will 

frustrate efforts to improve our knowledge about how CCS works in practice and 

it will frustrate efforts to cost effectively include GS in to the structure of 

a national climate policy. Page 43529. The USEPA should consider whether a 

requirement of being granted primacy for Class VI wells would be a requirement 

to share data collected at the state or Tribal area with the federal USEPA. EPA 

Individual Response: EPA retains the requirement that owners or operators submit data 

electronically to an EPA data system. EPA believes that it is prudent to provide assistance by 

developing a central framework for the electronic system that will be used by States to gather 

and track owner or operator data. This will enable owners or operators to submit data without 

having to wait for a State to develop a system. It will also provide for standardized submissions 

across the country and enable States to focus resources on reviewing and approving permit 

applications rather than building or upgrading separate, independent databases for GS 

information. EPA believes that electronic formatting is the most appropriate format for 

submitting Class VI project information to the Director, and that many GS well owners or 

operators will have the capability to report electronically. In addition to minimizing redundancy 

and streamlining reporting for GS projects, EPA intends to use the data collected to support its 

evaluation associated with the adaptive process. 

EPA is developing guidance for states that describes the record keeping, reporting, and 

additional data management needs associated with GS activities and provides recommended 

guidelines on the types of data to be collected for tracking GS projects, reporting to EPA for 

compliance tracking, and transfer of data to EPA's GS data system. The recordkeeping and 

reporting guidance will be available on EPA's web site, at 

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

Letter ID: 0156 Comment ID: 22652 Letter Lines: 787 to 809 

Comment Code: 5500 2.1 Comments on Involving the Public in Permitting Decisions 

Comment: Stakeholder Input and the Periodicity of this Involvement 

o Page 43520. The draft rule states "During this 50 year period, the owner or 

operator would be required to submit periodic reports." What’s the periodicity 

of these reports? A layperson would likely see this as a more meaningful step 

to regulate GS if the periodicity was annually as opposed to once every 15 

years. I do not intend to imply that annual reporting is the appropriate 

periodicity but by not specifying the interval the value of this as a regulatory 

tool or a means of building public trust in nascent GS technologies is largely 

gutted. 

o Page 43520. The draft rule seems to imply that the draft site closure plan 

would be made publically available. That is fine and appropriate, but the rule 

does not address what data will be made publically available when the GS project 

is being planned or during its operational phase. I do not see how the USEPA 

35
can be silent on this point. 

o Pages 43522-43523 contain an explicit discussion of public involvement in GS 

projects. This passage says that a summary of this pre-construction public 

involvement activity would become part of the public record. So the rule says 

that something at the very earliest stages of a GS project and something at the 

very end are public documents, but it is not clear what data during the 30-50 

year operational life of the project are publically available. 

Individual Response: EPA clarifies that the final GS rule does not specify a frequency for 

monitoring or reporting during the post-injection period. However, the post-injection site care 

and site closure plan submitted as part of the permit application must specify monitoring and 

reporting frequencies (See §146.93(a)(2)), and the Director must approve the plan. Additionally, 

the owner or operator must continue monitoring as specified in the post-injection site care and 

site closure plan for 50 years following the cessation of injection, unless demonstrated otherwise 

or for the duration of the alternative timeframe approved by the Director pursuant to 

requirements in §146.93(c). 

In addition to the public process during the permitting phase, EPA expects that permitting 

authorities will maintain an administrative record for the project, which at the discretion of the 

permitting authority might be available online and at the authority's office. This record should 

consist of the application materials and draft and final permits, along with public comments 

received on the draft permit as required under 40 CFR Part 124. Please note all state programs 

for purposes of Class VI wells must be at least as stringent as the federal minimum requirements 

under the UIC program, which includes permitting requirements under 40 CFR 145.11. EPA 

anticipates that permitting authorities will maintain monitoring and operational data submitted by 

owners and operators; the public could request this information from the permitting authority. 

Where EPA is the permitting authority, such data could be requested by the public under the 

Freedom of Information Act. EPA will also encourage an ongoing relationship between the 

permitting authority and the owner or operator, e.g., at the time of periodic reevaluation of the 

AoR and corrective action plan required at §146.84(e), as well as when any revisions are made to 

the testing and monitoring plan and financial responsibility demonstrations based on the AoR 

reevaluation. 

EPA notes that administrative procedure laws vary by state. States will describe their public 

participation activities in their primacy applications and must be at least as stringent as those 

provided under Parts 145 and 146. 

EPA recognizes that the AoR reevaluation process may generate significant levels of public 

interest. EPA added text to §144.39(a)(5) that permit modifications would be required if the 

Director determines that a modification is necessary based on an AoR reevaluation, amendments 

to any of the project plans, or a review of the testing and monitoring results. This would invoke 

the public notification procedures of 40 CFR Part 124. EPA clarifies that minor permit 

modifications under 40 CFR 144.41 do not require public notification. 

36
Letter ID: 0156 Comment ID: 22653 Letter Lines: 811 to 817 

Comment Code: 5700 2.12 Comments on the proposed duration of Class VI permits (seeking 

comment) 

Comment: Page 43523. EPA explicitly asserts that because it (or a state that has 

primacy) has such a rigorous on-going dialogue with owners/operators that it is 

prudent to issue injection permits "for the life of the GS project including the 

post-injection site care period." This very consequential decision hinges upon 

whether or not there truly is an ongoing dialogue that is substantive and 

happens with enough frequency to allow problems to be detected and remediated 

quickly. I am not sure that I see this dialogue as being that robust. 

Individual Response: EPA agrees with the commenters regarding the importance of continuous 

interaction between permitting authorities and owners and operators during the life of a GS 

project. In response, EPA has built periodic plan reevaluations by the Director and owners and 

operators into the GS regulation . The final rule under §144.36(a) requires that the Director 

review each Class VI permit at least every 5 years to determine whether it should be modified, 

revoked and reissued, terminated or a minor modification made as provided in §§144.39, 144.40, 

or 144.41. The Director’s review will be informed by the owners’ or operators’ iterative 

reevaluation of the project. Specifically, the final rule includes a requirement that the AoR be 

reevaluated at least every five years, and also requires owners or operators to review and update 

the AoR and corrective action plan, the testing and monitoring plan, and the emergency and 

remedial response plan throughout the life of the project (146.84(e), 146.90(j), and 146.94(d)). 

Owners or operators must review each plan and identify necessary amendments or demonstrate 

to the Director that no amendment is needed. In no case can reviews occur less often than once 

every five years. EPA believes that this process will promote rigorous on-going dialogue 

between owners and operators and the permitting authority to ensure protection of USDWs from 

endangerment. 

EPA believes that the iterative process of developing and executing the various plans required of 

GS well operators is tailored to the unique aspects of GS and is preferable to a periodic permit 

reapplication. The iterative process and subsequent plan reevaluations ensure that time and 

resources are committed to the most critical aspects of the permit in preventing endangerment to 

USDWs.. 

The Agency plans to collect and review data on GS projects every six years 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: 0156 Comment ID: 22654 Letter Lines: 819 to 825 

Comment Code: 4700 2.7 Proposed Recordkeeping and Reporting Requirements (40 CFR 

146.91) 

Comment Code: 5500 2.1 Comments on Involving the Public in Permitting Decisions 

37
Comment: Page 43528. The proposed Class VI rule states "The information gathered as a 

result of this proposed rule" allows the Agency to verify throughout the life 

of the injection project that UIC protective requirements are in place and that 

USDWs are protected. At the end of the day, this is indeed the figure of 

merit. Does this rule allow for sufficient exchange of information between the 

owners/operators of GS projects and regulators and stakeholders (?). This 

reviewer is not convinced that this metric is satisfied by the proposed rule. 

Individual Response: EPA agrees that interaction between the owner or operator and the 

Director is an important part of ensuring that GS projects are operated in a manner that protects 

USDWs from endangerment. EPA believes that the site-specific GS project plans which will 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. 

EPA encourages (but does not require) operators and permitting agencies to begin involving the 

public by providing information as early in the GS project development process as possible. 

Involving the public in the permitting process is an important aspect of both UIC Program 

requirements and EPA's overall mission. The public will also have the opportunity to submit 

written comments and, in many cases, attend hearings on proposed GS projects during formal 

public comment periods. Although permit application information will not be made available as 

it is submitted, permitting authorities must follow the public participation requirements for UIC 

permits specified in 40 CFR Part 124 which require that owners or operators publish a public 

notice that includes information about where interested parties can obtain copies of the draft 

permit and application in addition to requesting a public hearing. 

Furthermore, the Agency recognizes that the initial phases of site evaluation and site selection 

may begin in advance of permit application submission. The public may become aware of these 

activities and begin to have questions or concerns about the pending project. For this reason, 

outreach and education—which are outside of, but complementary to, the public notification 

process—can help clarify project details and avoid public misperceptions about the nature and 

safety of GS projects. This may also benefit the owner or operator by improving local acceptance 

of the site. EPA also notes that should changes to these plans require a permit modification under 

§144.39, the public must be notified according to the public comment procedures under 40 CFR 

124. 

In addition, EPA is evaluating options for a centralized data system through which the public 

could have access to public information on a GS project. EPA will also provide access to any 

required plan to the public upon request. Providing the public with information throughout the 

GS project will help clear up and avoid public misperceptions about the nature and safety of GS. 

Letter ID: 0156 Comment ID: 22655 Letter Lines: 829 to 850 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

38
Comment: - Page 43497. To the extent that EPA will revise this preamble language, please 

consider ending the section on "Potential USDW Impacts" with a new sentence that 

reaffirms that the purpose of this proposed rule is to put in place regulations, 

best practices, enforcement mechanisms, etc. to ensure that all of the 

previously mentioned bad things that could go wrong with a CO2 storage project 

do not take place. This reviewer thinks that given the negative tone of much of 

the material in this section it is appropriate for the USEPA to reinforce the 

point that the purpose of this rule is to ensure that CO2 storage is done safely 

thus significantly reducing if not eliminating the extent to which any of these 

things actually happen. 

- Page 43495 under "Why is Geologic Sequestration Under Consideration". Please 

change sentence which says in part "he capture and storage of CO2 would enable 

the continued use of coal in a manner that" The first deployments of CCS are 

not going to be at coal fired electric power plants. There is no reason for 

this rule to be overly focused on coal based CCS applications and is not 

appropriate for this Class VI UIC rule since it is bounded by the SDWA which 

means that the source of CO2 is not a critical aspect of this rule. Focusing on 

coal can also bring in a lot of ancillary (although important) issues 

surrounding the use of coal like mining practices that do not need to be 

discussed within the boundaries of a proposed Class VI UIC rule. CCS is more 

than just coal. 

Individual Response: EPA clarifies that the intent of the Class VI GS requirements are designed 

to ensure that, where deployed, GS is conducted in a manner that protects USDWs from 

endangerment. Please see the final rule and preamble for additional information on EPA's final 

approach. 

Letter ID: 0156 Comment ID: 22656 Letter Lines: 852 to 858 

Comment Code: 1320 1.1.3 General comments about GS 

Comment: - Page 43498. Second paragraph on that page. "However, some CO2 releases from 

injection activities have been documented." Crystal Geyser is not an "injection 

activity" as that term is used in the context of this Class VI rule. The text 

in that paragraph makes it clear that the CO2 which erupts from Crystal Geyser 

is from "improper well plugging." It is technically inaccurate, misleading and 

prejudicial to start off this paragraph by saying "some CO2 releases from 

injection activities have been documented." 

Individual Response: EPA agrees that the Crystal Geyser site is not associated with injection. 

However, this incident demonstrates that abandoned or improperly plugged boreholes can serve 

as conduits for migration of fluids to USDWs. It is for this reason that the final rule includes 

requirements related to performing corrective action on all deficient wells within the AoR at 

§146.84, and proper injection well construction that meets the goals of §146.86. 

39
Letter ID: 0156 Comment ID: 22657 Letter Lines: 860 to 863 

Comment Code: 1655 1.3.5.1 Concerns about Lake Nyos and Mammoth Mountain-type events 

Comment: - Page 43498. The USEPA is to be commended for the passage here on Lake Nyos 

and Lake Monoun and in particular for the forcefulness with which the draft 

Class VI rule makes it clear that these are not analogous to CO2 injected into a 

deep geologic formation. 

Individual Response: EPA acknowledges the comment. 

Letter ID: 0156 Comment ID: 22658 Letter Lines: 865 to 877 

Comment Code: 1620 1.3.2 Induced seismicity 

Comment: - Page 43498, section on "Seismic Events." The first sentence in this section 

is clearly speaking to the potential for CO2 injection to cause seismic activity 

in the future when commercial deployment of CCS becomes more common place. 

However, the second sentence and the subsequent discussion of induced seismicity 

at the Rocky Mountain Arsenal are not related to CO2 injection. To be clear, it 

was not CO2 that was being injected into deep geologic formations beneath the 

Rocky Mountain Arsenal. If this section of the preamble is retained in future 

versions of this proposed rule, this section must be rewritten to make it clear 

that the technical literature suggests that poorly managed CO2 injection could 

in the future induce small scale seismic activity. And then if there is a need 

to discuss previous instances where injection of fluids that were not CO2 

triggered seismic activity the language needs to be clear and explicit so the 

reader understands that these are not past instances of poor CO2 injection. 

Individual Response: EPA clarifies that the seismic episodes at the Rocky Mountain Arsenal, 

which occurred in the 1960s—before the original UIC regulations were developed—were due to 

poor site characterization and well operation, including high, unmonitored injection pressures 

(73 FR 43498). While EPA acknowledges that the volumes of CO2 injected at GS sites will 

likely be larger than the volumes of waste water injected at the Rocky Mountain Arsenal, 

injection volume is not the sole factor that determines induced seismicity. Induced seismicity 

also depends on other geologic variables such as pre-existing faults, porosity, and permeability 

(Sminchak & Gupta, 2003). With proper site characterization (i.e., pursuant to §146.82), these 

variables can often be quantified prior to injection (Sminchak and Gupta, 2003) and used to 

identify sites capable of safely sustaining prolonged injection of large volumes with low risk. As 

long as a site is well-characterized and monitored, and the injection volume and rate remain 

within permitted limits set forth by the Director, the injection of large volumes of fluid should 

not increase the risk of seismic activity. 

EPA does not believe that limiting GS to "stable areas" will provide certainty that seismic events 

will not occur. The Agency acknowledges that some regions of the country are at risk for 

40
infrequent, damage-causing seismic events even if such events have not been recorded in the 

recent historical record (i.e., in the past several hundred years). For this reason, EPA requires 

seismic risk to be evaluated on a site-specific basis, through an analysis of seismic history and an 

evaluation of known or suspected faults in the AoR, geomechanical information on fractures, 

stress, ductility, rock strength, and in situ fluid pressures within the confining zone as specified 

in §146.82(a)(3). In addition, if an adverse event, such as a well failure or evidence of fluid 

movement were to occur, the monitoring requirements at §146.90 and emergency and remedial 

response requirements as specified in §146.94 provide additional protection. 

Letter ID: 0156 Comment ID: 22659 Letter Lines: 879 to 895 

Comment Code: 2140 1.6.2 Depleted oil and gas reservoirs 

Comment: - Page 43503. While it is a widely held belief that much more is known about 

depleted oil and gas (DOG) fields within the US as opposed to DSFs, it is not at 

ll clear if this is true or significant in terms of the proposed Class VI rule 

or in terms of the decision making process a private firm would use to decide 

whether to utilize DOG or DSF fields in a commercial CO2 storage project. To 

the extent that there is more known about DOG fields, much of this data is 

proprietary and is in the hands of oil companies and oil field service 

companies. For more than a decade members of the CCS community have been 

seeking access to this presumed treasure trove of geologic data to build a 

national CO2 storage reservoir data base with this presumably high quality data. 

But the data have not been released, likely due to legitimate private sector 

concerns over protecting valuable proprietary information or perhaps this wealth 

of easily exploitable high quality data do not exist at these firms. So if the 

data exist but are not available, it seems immaterial to assert here that a 

significant cost savings could be had by exploiting DOG fields. This has not 

been proven in practice and I believe it might not ever be proven out in 

practice. 

Individual Response: EPA clarifies that the statement presumed that owners or operators 

planning GS in depleted oil and gas fields would be the same parties that delineated the field for 

the purpose of oil and gas exploration and would have already collected much of the necessary 

data in the course of exploration and therefore would realize a cost savings as a result of that 

previous work. 

Letter ID: 0156 Comment ID: 22660 Letter Lines: 897 to 908 

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

Comment: - Page 43509, last full paragraph on that page. The text here seems to imply 

that the cement used for CO2 storage wells will be eaten away by "acid" in one 

week. This is one example of a number of places in the rule where "perhaps 

inadvertently in the editing process" it seems as if text was deleted that 

41
would have helped a reader understand that "we are now discussing a scientific 

study that has some bearing on the topic at hand but isn’t exactly like GS" and 

"now are switching to an explicit discussion of what the USEPA will require of 

owners and operators of GS projects." If this text is retained in subsequent 

interations of the Class VI rule it would be good to explain why this study is 

germane to regulating GS in the United States and whether the same thing is 

expected to happen in practice. If cements in wells are going to fail in a 

week, then there isn’t much point in promulgating this rule. 

Individual Response: EPA clarifies that the Duguid et al. (2004) study referenced in the 

preamble to the proposed rule was only one of many studies it considered when developing the 

construction requirements for Class VI wells. The laboratory studies of Duguid et al. (2004, 

2005) found rapid degradation of cement under conditions of flowing (replenishing) CO2-

saturated brines. Other more recent laboratory studies (Barlet-Gouedard et al., 2006; Kutchko et 

al., 2007) found cement alteration, but no significant degradation (loss of integrity) in 

experiments that subjected the cement to static (non-replenishing) volumes of CO2. The 

SACROC well materials sampled and studied also likely were not exposed to flowing 

(replenishing) acidic brines (Carey et al., 2007). Cement alteration and corrosion were found to 

occur at differing rates in the various studies researched. The two studies with the most cement 

alteration were Duguid et al. (2004) (presumably due to exposure to the CO2-brine flux) and 

Barlet-Gouedard et al., (2006) (perhaps due to the higher experimental temperatures), but EPA 

notes that other important factors such as pressure, contact with CO2-saturated brine, and time 

between cement curing and contact with CO2 may have an impact on the rate of cement 

corrosion. 

Letter ID: 0156 Comment ID: 22661 Letter Lines: 910 to 918 

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

Comment: - Page 43511. The USEPA does a good job of explaining why the cost of requiring 

down hole shut off valves should not be seen as being overly burdensome for 

potential operators of GS sites. While the logic and data presented here seem 

convincing and make the point, it seems that a cost/benefit calculation might be 

a secondary issue. If the USEPA believes that these down hole shut off valves 

are needed to discharge its responsibilities under the SDWA (i.e., protect 

USDWs) then that should be the primary reason. The USEPA should not need to 

defend requirements needed to carry out its responsibilities under the SDWA with 

cost/benefit analyses. 

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

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

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

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

warrant their use. However, the Agency believes that offshore Class VI wells present unique 

42
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 clarifies that the decision not to require the use of down-hole shut-off systems for all 

onshore wells was not based on the cost of such systems, but the effect such systems would have 

on well operation and whether it was necessary to protect USDWs from endangerment in all 

cases. 

Letter ID: 0156 Comment ID: 22662 Letter Lines: 920 to 926 

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

(seeking comment) 

Comment: - Page 43513. EPA should not require that tracers be used in all GS 

applications across the very heterogeneous set of deep geologic formations that 

could be used to store CO2 in the USA. The USEPA (and in particular the Office 

of Air and Radiation) might want to consider doing full life-cycle analyses of 

the manufacture, storage, use and potential leakage of tracers to help better 

inform the technical community about the cost / benefits of using this one class 

of MMV technologies. 

Individual Response: EPA agrees that tracer use is not appropriate in all situations. 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. 

Letter ID: 0156 Comment ID: 22663 Letter Lines: 928 to 938 

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

comment) 

Comment: - Page 43515. It strikes this reviewer as odd to cite only one study (Burton et 

al, 2007) to support the statement that "current monitoring technologies are 

more than adequate for monitoring pressure in a GS project." It is not clear if 

by including this in the preamble to the draft rule whether EPA shares this 

assessment or not. This seems like an awfully broad and sweeping statement. 

Consider rewording. Consider being explicit as to whether EPA shares this view 

or if part of any NODA associated with this rule making should try to collect 

information that goes beyond this one study to confirm or refute this assertion 

that pressure monitoring technologies which exist today are sufficient to meet 

43
any GS need in any kind of formation anywhere and at any time across all regions 

of the USA. 

Individual Response: EPA clarifies that the GS rule, at §146.90(g), requires 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 recognizes that monitoring technologies will evolve and 

improve over time, and for these reasons, the Agency is using an adaptive approach to regulate 

GS injection. The Agency plans, every six years, to 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: 0156 Comment ID: 22664 Letter Lines: 940 to 957 

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

comment) 

Comment: - Page 43516. It is not clear if the USEPA is asserting that using "seismic 

crosswell methods" are "costly and time consuming" or if that is a finding of 

the GEO-SEQ (2004) report mentioned at the start of this paragraph. If it is 

the latter then it is important to clearly attribute that statement to the 

authors of the GEO-SEQ report. Otherwise, it appears that the USEPA is calling 

into question the cost effectiveness and utility of a technique that has yet to 

be robustly tested with respect to GS. That would seem to be a premature 

assumption based only on the results of the GEO-SEQ project, since crosswell 

seismic could be a preferred option for some sites where alternative options are 

impractical or economically infeasible. This section contains a number of 

implicit references to cost/benefit calculations for monitoring technologies. If 

the USEPA believes that these techniques are needed to discharge its 

responsibilities under the SDWA, then that should be stated and these techniques 

should be required. The text could say something about encouraging 

technological progress in the hopes of coming up with less costly but equally 

effective monitoring technologies, but it does not seem appropriate to try and 

justify some actions by alluding to cost benefit analyses as the basis for 

decision making. 

Individual Response: EPA does not believe that prescribing specific technologies to be used in 

all cases for GS would be appropriate given the variability in sites. Rather, EPA is developing 

guidance on testing and monitoring to assist owners or operators and Directors in evaluating 

requirements under §146.90, including proposed monitoring plans. The guidance describes 

available technologies and recommended approaches for implementing a testing and monitoring 

plan, including pre-operational geophysical logging and testing of injection wells, MITs, 

injection well testing during operation, groundwater quality monitoring, tracking the CO2 plume 

44
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. 

EPA clarifies that cost-benefit analyses are not required to be done under the SDWA to 

determine the most appropriate monitoring technologies, location, or frequency. Instead, the 

Agency believes that the flexibility afforded the owner or operator at §146.90 to develop a 

testing and monitoring plan tailored to site-specific characteristics is appropriate for GS. EPA 

estimated the costs of monitoring GS sites as part of the GS rulemaking effort, and estimates that 

the Class VI requirements will result in additional costs. The cost analysis for the final GS 

rulemaking (which is available in the docket) shows an approximate increase of 30 percent in 

comparison to Class I wells. 

Letter ID: 0156 Comment ID: 22665 Letter Lines: 959 to 969 

Comment Code: 1360 1.1.3.4 Effectiveness of trapping mechanisms 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: - Page 43519. Consider explicitly referencing the work laid out by Benson to 

support the statement that physical and geochemical trapping mechanisms will 

help to improve the integrity of storage as time moves forward. This is a 

critically important "but widely misunderstood" point about how GS will work 

in practice. It would be good to include at least one citation to technical 

work to back up this point. 

o OTC 19244. Multi-Phase Flow and Trapping of CO2 in Saline Aquifers. Sally M. 

Benson, SPE, Stanford University. Copyright 2008, Offshore Technology Conference 

This paper was prepared for presentation at the 2008 Offshore Technology 

Conference held in Houston, Texas, U.S.A., 5-8 May 2008. 

Individual Response: EPA added the Benson study to the final rule preamble (and has made it 

available in the rulemaking docket). 

Letter ID: 0156 Comment ID: 22666 Letter Lines: 971 to 988 

Comment Code: 5434 2.9.1.2 Need for additional instruments (seeking comment) 

Comment: - Page 43521. The text here briefly mentions on going analysis of "pay-in 

periods for trust funds" in the context of financial assurance. I do not 

understand the statement here that says "EPA is considering a guidance approach 

that would recommend a pay in period of three years for GS projects." "Three 

years" seems completely arbitrary. What would be the basis for the fee paid in 

those three years? Would it be a charge of $1/tonCO2 or $50/tonCO2? There is 

no way to understand the utility of a three year pay-in period without knowing 

much more about what costs this fund was supposed to cover, how the fee would be 

45
assessed, at what level would the fee be set, etc We have recently completed 

an analysis that sheds light on a number of issues specifically related to trust 

funds applied to GS and I believe it is potentially relevant to the USEPA’s 

ongoing evaluation of these issues. Please see [SEE PDF TO VIEW THIS DOCUMENT]: 

o Dooley JJ, C Trabucchi, and L Patton. 2008. "Tipping Fees Can't Save us from 

the Tipping Point: The Need to Create Rational Approaches to Risk Management 

that Motivate Geologic CO2 Storage Best Practices." To be published in the 

Proceedings of the 9th International Conference on Greenhouse Gas Technologies. 

October 2008. PNWD-SA-8349, Pacific Northwest National Laboratory, Richland, WA. 

Individual Response: EPA acknowledges that there may be several possible approaches to 

setting pay-in periods for trust funds. The three year pay-in period considered for comment in the 

proposal is not arbitrary because it is a time frame consistent with other similar programs in the 

Agency. The final rule requires that the Director approve the use and length of pay-in periods. 

EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) that describes the types of 

financial instruments that owners or operators can use to meet financial responsibility 

requirements for GS wells. Specifically, the guidance will discuss pay-in periods and provide 

guidance for Directors to use in determining an appropriate pay-in period so that the financial 

benefits to the owner or operator of a longer pay-in period are balanced with the increased 

financial risk to the public. EPA adds that owners or operators may choose from a variety of 

financial instruments to meet their financial responsibility needs. 

Letter ID: 0156 Comment ID: 22667 Letter Lines: 990 to 1000 

Comment Code: 7300 4.3 Regulatory Flexibility Act 

Comment: o Page 43530. The draft rule correctly states "Sequestering CO2 via injection 

wells is a voluntary action that would only be undertaken by an entity if it 

were in its interest compared to other alternatives it may have." This point is 

worth repeating a number of times in this proposed rule. In particular, this 

might be worth repeating in discussions of what is required for Class VI wells 

and the cost of meeting these requirements. At times, it seems as if the USEPA 

is apologizing for requiring compliance with measures designed to protect USDWs. 

The USEPA should ask for the public and other stakeholders to perform a thorough 

and rigorous review of any proposed requirements but there is no need to 

apologize. As the draft Class VI rule makes clear, no one is being required to 

use GS. That is important to remember and likely bears repeating. 

Individual Response: EPA acknowledges this comment. The GS rule does not require any 

facilities to sequester CO2. The purpose of the GS regulation is to ensure that, where deployed, 

GS is conducted in a manner that protects USDWs from endangerment. EPA discussed this in 

the preamble to the proposed rule (73 FR 43492), and further clarified this fact in the final rule 

preamble and the Cost Analysis, which is available in the docket for the rulemaking. 

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Letter ID: 0156 Comment ID: 22668 Letter Lines: 1002 to 1003 

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

Comment: o What if any are the construction requirements and mechanical integrity 

requirements for monitoring wells? 

Individual Response: Construction specifications for monitoring wells must be described in the 

testing and monitoring plan submitted with the permit application. EPA is developing guidance 

on well construction that will include recommendations for monitoring well construction. The 

guidance will be available on EPA’s website 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, 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. 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 final GS rule. 

Letter ID: 0156 Comment ID: 22669 Letter Lines: 1005 to 1018 

Comment Code: 7700 4.7 Executive Order 13045: Children's Health Protection 

Comment: o Page 43531. The USEPA invites the public to identify peer reviewed studies 

that assess the effects on infants and toddlers who are exposed to drinking 

water that has been degraded "by geologic sequestration of carbon dioxide." The 

wording here seems to assume a number of key steps that I am not sure one can 

assert given where humanity is in terms of the commercial deployment of GS. This 

request for information would be better if it requested information on studies 

that speak to the impact of drinking contaminated water by infants and toddlers 

caused by processes that could result from a poorly functioning GS project at 

some point in the future. I do not see how there can be existing studies that 

show negative impacts on children from drinking water contaminated by a 

malfunctioning GS project. It is worth comparing the language here with the far 

more balanced and accurate language on page 43532 where the USEPA forcefully 

asserts that the proposed rule will not have a disproportionate impact on 

minority and low-income populations. 

Individual Response: EPA is funding research related to the potential for USDW contamination 

associated with GS projects. In addition, the Agency is tracking external research that focuses on 

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potential exceedances of drinking water standards, which were developed by EPA and take into 

account impacts on children's health. 

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 

44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory 

(LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of 

CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, 

mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL 

estimated the amount of trace elements from native mineral species that could potentially be 

mobilized by the intrusion of CO2 and the potential ground water concentrations that could result 

to determine the potential for drinking water standards to be exceeded. EPA has also examined 

potential methods for conducting treatment of water affected by a CO2 leak; this study is 

presented in the final rulemaking docket. 

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and 

Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University 

to investigate the potential for GS to affect USDWs. This research will involve laboratory 

experiments and modeling simulations to investigate the fate of dissolved CO2 in underground 

geologic formations and to determine possible risks associated with the dissolution of CO2 in 

underground aquifers. This STAR Grant is among six such grants awarded to major universities 

and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic 

Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water." 

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through 

permitting, siting, construction, operation, injection, and post-injection site care and site closure 

requirements that are tailored to address the unique nature of GS. The Class VI requirements, 

therefore, minimize health risks to all populations, including children. The "Risk and Occurrence 

Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, 

presents a broad discussion of risks to human health and the environment associated with GS, 

including those addressed under SDWA authority and those environmental and human health 

impacts that are beyond the scope of the SDWA. 

As part of its adaptive rulemaking approach, EPA plans to collect and review available 

information such as the research described above and data every six years on early GS projects, 

including impacts to USDWs and drinking water quality that may affect the health of children, to 

determine whether the appropriate amount and types of information and documentation are being 

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

Letter ID: 0156 Comment ID: 22670 Letter Lines: 1020 to 1025 

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: o Page 43540 under "Post-injection site care and site closure." The USEPA 

should ask for a seismic image or other data that depicts the current extent and 

placement of the CO2 plume. The current language asks for "the predicted 

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position." If the EPA would like modeling of the predicted position for some 

purpose that is fine but there is no reason not to ask for data that shows where 

the plume really is. 

Individual Response: EPA clarifies that the purpose of the requirement that the PISC and site 

closure plan include a prediction of the magnitude of the pressure differential between preinjection and during post-injection at §146.93(a)(2)(i) is to support planning of the amount of 

monitoring that is necessary during PISC and planning the length of the PISC timeframe. EPA 

anticipates that this information will be provided by the computational modeling performed for 

the AoR delineation. 

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://www.epa.gov/safewater/wells_sequestration.html. 

Letter ID: 0156 Comment ID: 22671 Letter Lines: 1029 to 1033 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: - Page 43493, in the "Definitions." Consideration should be given to breaking 

the definition of EOR/EGR into two different short paragraphs. The physical 

processes as well as economic drivers involved in EOR and EGR are not strictly 

similar and it is not clear that these should be lumped together in something 

like a federal regulation. 

Individual Response: EPA disagrees with the suggested edit. The final definition of enhanced 

oil or gas recovery (EOR/EGR) remains unchanged. The Agency clarifies that the final Class VI 

GS rule does not require owners or operators to use GS technologies, nor does it impact business 

as usual for Class II owners or operators that are injecting CO2 to enhance production of oil or 

gas. Additionally, EPA clarifies that the intent of the Class VI GS rule is not to address the use of 

CO2 for EOR or EGR. Rather, the purpose of the Class VI GS regulation is to ensure that, where 

deployed, GS is conducted in a manner that protects USDWs from endangerment. 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0156 Comment ID: 22672 Letter Lines: 1035 to 1043 

Comment Code: 1320 1.1.3 General comments about GS 

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Comment: - Page 43495, third column, under "II What is EPA Proposing?" I believe the 

IPCC Special Report on Carbon Dioxide Capture and Storage (IPCC SR on CCS) 

and/or more recent peer reviewed papers can shed light on the timeframes under 

which primary and secondary trapping mechanism begin to operate. Adding some 

quantification to this point would likely help stakeholders better understand 

and be more familiar with CO2 storage. Consider adding something like "Some of 

these trapping mechanisms begin as soon as the CO2 is injected into the host 

formation while others take hundred to thousands of years to run their course." 

I believe one could cite the IPCC SR on CCS to substantiate that point. 

Individual Response: EPA agrees that the IPCC study mentioned is informative. The IPCC 

report is cited extensively in the preambles to the proposed and final rules, and is also available 

in the rulemaking docket. 

Letter ID: 0156 Comment ID: 22673 Letter Lines: 1045 to 1050 

Comment Code: 1612 1.3.1.1 Leaching and mobilization of contaminants; reactions in injection 

zone 

Comment: - Page 43497 under "What are the risks associated with CO2 GS?" I do not see 

any reason to include the modifier "likely" in the first sentence of "Potential 

USDW Impacts." Under what set of circumstances would CO2 injected into a waterbearing deep geologic formation not come into contact with formation waters? 

Delete "likely" from this sentence. It does not help readers understand CCS or 

how EPA will regulate CO2 storage. 

Individual Response: EPA acknowledges that there are potential risks associated with GS, 

including the potential that CO2 injection for GS may result in leaching of subsurface materials 

that could mobilize contaminants or compromise pore space, and therefore injectivity. The 

purpose of the Class VI requirements is to minimize and mitigate potential/identified risks 

through proper site characterization, well construction, operation, monitoring, post-injection site 

care, and site closure. To ensure USDW protection and mitigate risks, the GS regulation requires 

the owner or operator of a Class VI well to submit data about the site (during the site 

characterization process), including information on the porosity, permeability, mineralogy, and 

geochemistry of the injection and confining zones, along with information on the compatibility 

of the CO2 stream with fluids in the injection zone and minerals in both the injection and 

confining zones as specified in §146.82. This data can help identify potential geochemical 

reactions that may occur between the injected CO2 and the host geologic formation. 

Identification of potential reactions prior to injection would address concerns that formation of 

carbonic acid could dissolve potential limestone creating karst features. 

During injection operations, operators must extensively monitor ground water quality to provide 

early detection of any unacceptable movement of fluids or impurities in the subsurface as 

specified in §146.90. Operators must develop and follow an emergency and remedial response 

plan to address any adverse effects associated with the GS operation, including contamination as 

50
specified in §146.94, and provide financial responsibility to address contamination as specified 

in §146.85. 

Letter ID: 0156 Comment ID: 22674 Letter Lines: 1052 to 1074 

Comment Code: 1200 1.1 General comments about the rulemaking 

Comment: - Page 43497 under what are the "Potential USDW Impacts." Please consider adding 

at the very end of this section a sentence that reaffirms for the reader that 

the fundamental purpose of the proposed Class VI rule is to make sure that the 

bad things above enumerated do not occur. 

- Page 43502, third sentence under "How Would this Proposal Affect Existing 

Injection Wells Under the UIC Program?" Please consider being specific as to 

what kind of "production" is being discussed here. From the context of this 

sentence it would seem to be "production of oil" or perhaps "production of 

hydrocarbons" but it would not seem to cover "production of brackish waters for 

the purpose of desalination to provide potable water." The phrase "any 

production seems overly vauge. 

- Page 43505 within the discussion of CO2 storage in coal seams. It is 

incorrect to state that "the process of CO2 adsorption to the coal has not been 

proven." This is well established. I think what USEPA intended to say was 

something like "the commercial application of coal-based CO2 storage has not 

been proven." The fundamental principle of CO2 adsorbing on the coal surface is 

established. Whether this is going to work in situ and at commercial scale has 

not been established / proven. Please consider rewording. 

- Page 43516. "Simulations discussed in the manual confirm seismic and - What 

- manual"? It is not clear what is being discussed here. 

Individual Response: In response to the comment regarding production, EPA clarifies that this 

discussion refers to Class II wells, which are associated with the recovery of oil and or gas. The 

purpose of the discussion is to distinguish injection (which is regulated under the UIC 

regulations) from production (which is not). 

In response to the comment regarding CO2 adsorption to the coal, EPA clarifies that GS in 

unmineable coal seams has been the subject of less research than saline formations or depleted 

oil and gas reservoirs. EPA acknowledges that site-suitability for GS is dependent on a number 

of factors and that many formation types may be suitable for GS. The final GS rule does not 

preclude injection into unmineable coal seams (or any formation type) provided owners or 

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

endangerment. The Agency anticipates that in the near-term, most GS in unmineable coal seams 

will continue to be experimental. Such projects may be permitted as Class V experimental 

technology wells if they are of an experimental nature (i.e., to test GS technologies and collect 

data). 

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The "manual" referenced on page 43516 is the GEO-SEQ Best Practices Manual. Geologic 

Carbon Dioxide Sequestration: Site Evaluation to Implementation. Lawrence Berkeley National 

Laboratory. Paper LBNL-56623. The GEO-SEQ Best Practices Manual is available at: 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/GEO-SEQ_BestPract_Rev1-1.pdf. 

Please see the remainder of EPA's responses to this comment for further details. For additional 

information on EPA's final regulatory approach, please see the final rule and preamble as well as 

the rulemaking docket. 

Letter ID: 0156 Comment ID: 22675 Letter Lines: 1076 to 1086 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: - Page 43538. Does the USEPA (or states that have primacy for Class VI wells) 

really want to take physical possession of cores from prospective GS sites? The 

rule currently states "The owner or operator must take and submit to the 

Director whole cores or sidewall cores of the injection zone and confining 

system and formation fluid samples from the injection zone(s)." I understand 

the requirement that the Class VI permit applicant needs to take cores and needs 

to perform tests upon them but wouldn’t it be more meaningful for the "Director" 

to receive a written summary of those tests and a description of the 

methodologies used in the testing of the cores than to literally take physical 

possession of the cores themselves? The USEPA should consider rewording this 

passage. 

Individual Response: EPA clarifies that it is not the Agency's intent that physical cores be 

submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) 

to read as follows: "The owner or operator must take whole cores or sidewall cores of the 

injection zone and confining system and formation fluid samples from the injection zone(s), and 

must submit to the Director a detailed report prepared by a log analyst that includes: well log 

analyses (including well logs), core analyses, and formation fluid sample information...." 

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