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 EPA Proposed Class VI Rule 

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

Larry R Myer 

lrmyer@lbl.gov 

Lawrence Berkeley National Laboratory 

Berkeley CA 94720 

Phone 510-486-6456 

The proposed Class VI rule addresses all of the important issues which must be addressed 

in order to protect USDWs when geologic sequestration of CO2 is undertaken. Actions 

required by the rule are generally conservative, which is good, but, in three areas, 

discussed below, requirements are overly, and unnecessarily, conservative. 

A 50 year site care period is unnecessary and certainly impractical, and should be 

removed from the rule. It is unlikely that any owner/operator would, or could, provide 

assurance of its ability to take responsibility for the fate of the CO2 for 50 years. The risks 

associated with storage decrease rapidly after injection stops because of stabilization of 

the plume and dissipation of pressure, so the concept of linking post-injection site care to 

plume stabilization and pressure decrease is a good one. However, there is not sufficient 

knowledge at this time to quantify the required time. It is known that the time required 

for trapping processes, such as residual gas trapping, to immobilize the plume varies, so a 

single number for the site care period is not appropriate in any event. Given the current 

state of knowledge the rule should only state that the operator should demonstrate at 

closure that the plume has sufficiently stabilized and pressure decreased so as to not 

adversely impact the USDW. 

The requirement that injection pressure should not exceed 90 percent of fracture pressure 

is also unnecessarily conservative and restrictive because it precludes use of 

hydrofracturing as a reservoir stimulation technique. It is important that the seal not be 

fractured, but purposeful fracturing of the injection interval will likely be advantageous in 

many instances, just as it is in hydrocarbon production. Carefully engineered 

hydrofracturing operations carried out in conjunction with a monitoring program, should 

be allowed. 

Setting the interval for cementing of the casing as the entire casing lengthl seems 

arbitrary and unjustified. A conservative cementing program is justified. It is unclear, 

however, why 4000 ft of cement is sufficient for a 4000 ft deep well and insufficient for a 

10,000 ft deep well. For very deep wells the costs and difficulties in cementing the entire 

casing length go up dramatically. The risks of loosing the whole well also increase 

significantly with the increased difficulty of the operation. Of highest priority is a high 

quality cement bond through the formation(s) forming the primary seal of the storage 

reservoir. Beyond that, cementing should not be required beyond that which is practical 

in a single stage cementing program. 
Letter ID: 0149 

Commenter: Larry Myer 

Organization: Lawrence Berkeley National Laboratory (Berkeley Lab) U.S. Department of 

Energy (DOE) 

Letter ID: 0149 Comment ID: 21796 Letter Lines: 24 to 28 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment: The proposed Class VI rule addresses all of the important issues which must be 

addressed in order to protect USDWs when geologic sequestration of CO2 is 

undertaken. Actions required by the rule are generally conservative, which is 

good, but, in three areas, discussed below, requirements are overly, and 

unnecessarily, conservative. 

Individual Response: EPA acknowledges the comment. The requirements for GS projects are 

tailored to address the unique issues associated with GS, including large injection volumes, the 

relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of 

impurities in captured CO2, and its mobility within subsurface geologic formations. 

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: 0149 Comment ID: 21797 Letter Lines: 30 to 43 

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

Comment: A 50 year site care period is unnecessary and certainly impractical, and should 

be removed from the rule. It is unlikely that any owner/operator would, or 

could, provide assurance of its ability to take responsibility for the fate of 

the CO2 for 50 years. The risks associated with storage decrease rapidly after 

injection stops because of stabilization of the plume and dissipation of 

pressure, so the concept of linking post-injection site care to plume 

stabilization and pressure decrease is a good one. However, there is not 

sufficient knowledge at this time to quantify the required time. It is known 

that the time required for trapping processes, such as residual gas trapping, to 

immobilize the plume varies, so a single number for the site care period is not 

appropriate in any event. Given the current state of knowledge the rule should 

only state that the operator should demonstrate at closure that the plume has 

sufficiently stabilized and pressure decreased so as to not adversely impact the 

USDW. 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

excessive or unnecessary in most cases. EPA proposed a default post-injection site care 

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

environmental programs. This analysis was included in an EPA-prepared background document 

that is available in the federal docket, titled Computational Modeling of Underground Injection 

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

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

of research studies and evaluation of public comments. While numerous commenters suggested 

that EPA shorten the monitoring timeframe, none of the commenters provided sufficient data or 

other evidence to warrant a change in the proposed timeframe. While the 10- or 30-year 

timeframe suggested by some of these commenters may be within the timeframe suggested in 

some studies, EPA believes that the potential risks of endangering USDWs will likely not 

decline within these timeframes and available data, including data submitted by commenters, do 

not support a different default timeframe. 

EPA acknowledges that some studies indicate that trapping may begin in less than 50 years, as 

the commenter notes; however, this trapping may also take up to hundreds or thousands of years 

to be complete (IPCC, 2005). If this trapping is not complete, the potential for USDW 

endangerment still exists as CO2 may persist as a buoyant plume. EPA therefore believes that to 

ensure USDW protection from endangerment, a default timeframe for post-injection site care 

will be necessary in most cases. The default 50 year post-injection site care timeframe represents 

a reasonable and protective monitoring period based on a review of research studies, industry 

reports, and existing environmental programs, and evaluation of public comments. 

However, the GS rule offers owners or operators flexibility regarding the duration of the PISC 

timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe 

during the PISC period based on site-specific data, pursuant to requirements at §146.93(b); or (2) 

affording the Director discretion to allow a Class VI well owner or operator to demonstrate, 

based on substantial data during the permitting process, that an alternative PISC timeframe may 

be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at 

§146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

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

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

impacts. 

EPA recognizes that there are challenges associated with assuring funding for activities that will 

occur far in the future. However, the Agency believes that in order to protect USDWs from 

endangerment under the SDWA, operators must demonstrate under §146.85 that financial 

resources are available to plug the injection well and provide post-injection site care at the point 

in time that the first CO2 is injected. 

To the comment about the cost of post-injection site care, EPA does not agree that post-injection 

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site care timeframes longer than 30 years will be prohibitively expensive. In fact, EPA believes 

that post-injection site care monitoring will represent a relatively minor component of total 

project cost, and will provide an essential level of protection from endangerment for USDWs. A 

discussion of the costs attributed to monitoring technologies (used during injection and the postinjection site care timeframes) is available in the Technology and Cost Document for the GS 

rule, which is in the federal docket for this rulemaking. EPA believes that it is logical to make 

use of existing monitoring infrastructure at a GS site in order to ensure USDWs are not 

endangered. 

Letter ID: 0149 Comment ID: 21798 Letter Lines: 45 to 51 

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment) 

Comment: The requirement that injection pressure should not exceed 90 percent of fracture 

pressure is also unnecessarily conservative and restrictive because it precludes 

use of hydrofracturing as a reservoir stimulation technique. It is important 

that the seal not be fractured, but purposeful fracturing of the injection 

interval will likely be advantageous in many instances, just as it is in 

hydrocarbon production. Carefully engineered hydrofracturing operations carried 

out in conjunction with a monitoring program, should be allowed. 

Individual Response: EPA clarifies that the injection pressure limit at §146.88(a) applies only 

to the period of injection, not well stimulation. In addition, 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)). 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 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: 0149 Comment ID: 21799 Letter Lines: 53 to 62 

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

Comment: Setting the interval for cementing of the casing as the entire casing lengthl 

seems arbitrary and unjustified. A conservative cementing program is justified. 

It is unclear, however, why 4000 ft of cement is sufficient for a 4000 ft deep 

well and insufficient for a 10,000 ft deep well. For very deep wells the costs 

and difficulties in cementing the entire casing length go up dramatically. The 

risks of loosing the whole well also increase significantly with the increased 

difficulty of the operation. Of highest priority is a high quality cement bond 

through the formation(s) forming the primary seal of the storage reservoir. 

Beyond that, cementing should not be required beyond that which is practical in 

3
4

a single stage cementing program. 

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

§146.86 are arbitrary or unjustified. The final GS rule requires, at §146.86(b)(2), that the surface 

casing must extend through the base of the lowermost USDW and be cemented to the surface, 

and that at least one long string casing must be cemented to the surface in one or more stages at 

§146.86(b)(3). It does not, however, specify how cementing must be accomplished, and it allows 

the owner or operator to propose alternate methods that provide a sufficient amount of cement to 

meet the standard that USDWs are protected from endangerment. EPA notes that there are many 

potential ways to meet the requirement, such as the use of staged cementing. 

The Class VI well requirements address the unique nature of CO2 GS (including large injection 

volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential 

presence of impurities in captured CO2, and its mobility within subsurface geologic formations). 

EPA adds that cementing of deep wells has been performed successfully in the past, for example, 

by owners or operators of Class I hazardous and Class I municipal waste disposal wells. Some of 

these wells, which must meet the same cementing requirements for long-string casing as Class 

VI wells, are up to 12,000 feet deep (EPA, 2001). 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW 

is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 

includes requirements for owners or operators that seek a waiver of the injection depth 

requirements. Owners or operators of wells operating under injection depth waivers must comply 

with additional construction requirements to ensure that wells used to inject above or between 

USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS 

rule for additional information.