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.
These comments have been prepared by Battelle researchers as part of their work for MRCSP. They do not 

necessarily reflect the official view of Battelle, the U.S. DOE, or sponsors and members entities of MRCSP. 

24 December 2008 

Water Docket 

U.S. Environmental Protection Agency 

Mailcode: 2822T 

1200 Pennsylvania Ave NW 

Washington, DC 20460 

Email address: OW-Docket@epa.gov 

Subject: Docket ID No. EPA-HQ-OW-2008-390

Underground Injection Control (UIC) Class VI well rule proposed 25 July 2008 at 73 FR 43492-43541 

Enclosed please find some comments prepared by the Battelle geologic storage researchers working on 

the Midwest Regional Carbon Sequestration Partnership (MRCSP) on USEPA Proposed Rule - Federal 

Requirements under UIC Program for CO2 Geologic Sequestration Wells (Docket ID No. EPA-HQ-OW2008-390). We appreciate the opportunity to participate in formulation of these requirements for geologic 

sequestration. These comments reflect MRCSP experience in permitting and implementing three Phase II 

CO2 injection tests and the MRCSP Phase III project. While the MRCSP includes over 30 different 

members, the comments expressed herein do not necessarily reflect opinions of the individual members of 

the MRCSP. 

If you have any questions or require additional information, please contact Neeraj Gupta (614) 424-3820, 

e-mail gupta@battelle.org or Joel Sminchak (614) 424-7392, e-mail Sminchak@battelle.org. 

Sincerely, 

Dr. Neeraj Gupta 

Senior Research Leader 

Geologic Storage 

Battelle Energy Technology 
Comments on EPA-HQ-OW-2008-390 Neeraj Gupta and Joel Sminchak 

12/24/2008, Page 2 Battelle 

These comments have been prepared by Battelle researchers as part of their work for MRCSP. They do not 

necessarily reflect the official view of Battelle, the U.S. DOE, or sponsors and members entities of MRCSP. 

Review and Comments on Proposed Rule - Federal Requirements under UIC Program for 

CO2 Geologic Sequestration Wells 

Docket ID No. EPA-HQ-OW-2008-390 

Prepared by Neeraj Gupta and Joel Sminchak for Battelle/MRCSP 

December 24, 2008 

Introduction and Background 

This document summarizes review and comments from Battelle researchers’ under the regulatory work of 

Midwest Regional Carbon Sequestration Partnership’s (MRCSP) on the USEPA Proposed Rule- Federal 

Requirements under UIC Program for CO2 Geologic Sequestration Wells (Docket ID No. EPA-HQ-OW2008-390). These comments reflect our experience in permitting and implementing three Phase II CO2

injection tests and the MRCSP Phase III project, as well as work on several other research projects during 

last 12 years of CCS research at Battelle: 

Site Location Agency Permit Status Test Status 

Appalachian Basin Shadyside, 

OH 

Ohio EPA 

UIC Program Complete Injectivity testing completed 

Cincinnati Arch Rabbit Hash, 

KY USEPA Region 4 Draft permit in public comment phase Pending permit 

Michigan Basin Otsego Co., 

MI USEPA Region 5 Complete 

10,241 tons CO2

injected Feb-Mar 

2008. Additional 

injection under 

planning. 

Phase III TAME Greenville, 

OH 

Ohio EPA 

UIC Program 

Permit application in 

preparation Planning stages 

The analysis also reflects Battelle experience with the UIC permitting of the AEP Mountaineer CO2

storage project, which is targeting 4 years of injection of over 100,000 metric tons CO2/yr at the AEP 

Mountaineer plant in New Haven, WV. While the MRCSP includes over 30 different members, the 

comments expressed herein do not necessarily reflect opinions of the individual members of the 

MRCSP.

The MRCSP is one of seven partnerships in a nationwide effort to determine 

regionally-appropriate carbon sequestration options and opportunities. These 

partnerships are part of an overall effort by the U.S. Department of Energy’s 

National Energy Technology Laboratory (DOE/NETL) to develop robust 

strategies for mitigating carbon dioxide emissions. The MRCSP was formed to 

assess the technical potential, economic viability, and public acceptability of 

carbon sequestration within its Region. 

The MRCSP region consists of eight contiguous states: Indiana, Kentucky, 

Maryland, Michigan, New York, Ohio, Pennsylvania, and West Virginia. The 

MRCSP includes over 30 organizations from the research community, energy 

industry, universities, non-government, and government organizations. In the first 

phase of research, which took place over a two year period ending in September 2005, the MRCSP 

characterized carbon sequestration opportunities in the region. MRCSP is now involved in a four year 
Comments on EPA-HQ-OW-2008-390 Neeraj Gupta and Joel Sminchak 

12/24/2008, Page 3 Battelle 

These comments have been prepared by Battelle researchers as part of their work for MRCSP. They do not 

necessarily reflect the official view of Battelle, the U.S. DOE, or sponsors and members entities of MRCSP. 

Phase II effort that began in October 2005. This phase will conduct several small-scale field tests of 

sequestration in different locations around the region to evaluate various sequestration options in realworld settings. The MRCSP Phase III project will involve sequestration of more than 1 million metric 

tons CO2. 

General and Specific Comments on Proposed Regulations 

Adaptive Approach - Overall the proposed policy presents a comprehensive framework for geologic 

sequestration (GS). The adaptive approach seems especially useful for enabling early adopters to pursue 

GS while allowing flexibility for adjustments in the future based on technology development and lessons 

learned at individual sites. 

Permit Organization - The proposed regulation presents a large amount of material spread throughout 

the document. In general, it has been easier to complete the permit process with the basic UIC form with 

the simplified list of attachments (this procedure was used for Region 4 and Region 5). Thus, the 

MRCSP would encourage EPA to prepare suggested formats and a systematically organized list of 

information and documents required for the permit. 

Encouraging Innovation and Experimental Projects – We believe that USEPA recognizes that many 

facets of GS site selection, implementation, and monitoring are still under technological assessment and 

innovation phase. Many of the concepts and technological options are being evaluated under current field 

demonstration programs by Regional Partnerships and other projects across the world. The success of 

these existing and future experimental projects is heavily dependent on permitting process being as simple 

as possible. USEPA UIC Guidance 83 allowing the use of Class V experimental wells has been a very 

useful mechanism for facilitating experimental projects. In fact, if the proposed Class Vi framework was 

to be applied to smaller-scale tests currently underway, it is our belief that many projects would have 

financial, logistical, or technical difficulties in moving to field stage. With the proposed regulation in the 

public comment phase, MRCSP has already observed that the permit regulations for even small-scale 

field tests (such as MRCSP East Bend site and AEP Mountaineer Project) are becoming too onerous 

compared to similar projects permitted prior to the issuance of draft regulations. For example, the postinjection monitoring durations have become much longer with the regulators citing the draft regulation as 

a basis for requirements. Such a trend will certainly adversely affect future experimental projects and 

lead to less new data being available to all stakeholders. We strongly encourage EPA to 1) continue the 

existing option for using Class V experimental well permits option and/or specifically allow for a more 

simplified and less onerous permitting requirements for such project.

Complexity and Consistency of Regulations – We recognize that EPA has attempted to provide a great 

deal of flexibility in most aspects of the regulations, while incorporating most of currently known 

concepts and technologies in permitting, operation, and monitoring of the sites. The flexibility has 

primarily been incorporated through making the requirements subject to “directors” decision. Our 

concern is that some directors may choose to require all of the numerous requirements mentioned in the 

permit, rather then selectively requiring an appropriate portfolio of safeguards. Such an approach could 

deter operators from considering the GS as an option for CO2 mitigation. Another concern is that the 

requirements will be applied with inconsistent level of flexibility in various regions and states, making 

some regions more or less favorable for GS. We encourage EPA’s continuing oversight and guidance in 

ensuring that the regulations are applied consistently and with a reasonable selection of requirements. 

Page 48 “Grandfather” Status - It is unclear how this would affect existing MRCSP Phase II Test sites. 

These host sites have been very accommodating in supporting these small scale tests and it is unclear if 

they would be subject to long term monitoring or allowed to be closed out under the original Class V CO2
Comments on EPA-HQ-OW-2008-390 Neeraj Gupta and Joel Sminchak 

12/24/2008, Page 4 Battelle 

These comments have been prepared by Battelle researchers as part of their work for MRCSP. They do not 

necessarily reflect the official view of Battelle, the U.S. DOE, or sponsors and members entities of MRCSP. 

experimental policy the wells were permitted under. Clarification that the small scale tests would be 

allowed to continue injection under their original permit conditions be closed out under their original 

permits would be helpful to the pioneers of this technology, unless of course the site hosts wish to convert 

to a Class VI well under new regulations for longer-term.. 

Page 54 CO2 Composition Requirements and Hazardous Waste under RCRA- While we agree some 

chemical impurities may cause CO2 to be designated hazardous waste, there must be more clear guidance 

on this issue. In the MRCSP tests, each regulatory agency had different requirements on this issue 

injectate composition and analysis, even for commercial CO2. One agency required injection to cease if 

the injectate was above any maximum contaminant level (MCL) for groundwater, which is a large list of 

chemicals. Another state agency asked for some technically infeasible analyses on the CO2 stream (pH, 

Fluouride, Mercury). Some impurities like H2S and hydrocarbons are naturally occurring in most deep 

saline formations anyway, so we would discourage setting limits on these items. Another significant 

aspect is the composition of CO2 derived from various industrial, power generation, and capture 

processes. All of these are likely to result in minor differences in chemical compositions. In most cases 

the concentration of hazardous impurities is likely to be very low. The incremental environmental impact 

of these minor or trace impurities in deep formations that already have brine and will have CO2 must be 

demonstrated before these are excluded from the Class VI injection wells. EPA is encouraged to evaluate 

the range of potential impurities from various streams, their environmental impact if any, and provide 

more specific guidance on this topic. The evaluation should also assess how many of the GS projects 

could become infeasible due to this requirement. Finally, EPA should clarify whether CO2 streams with 

RCRA level of impurities can be injected under Class I permits. 

Page 61, Injection Zone and Confining Layer - Conditions under which “director” may require a 

secondary containment/buffer zone should be more clearly defined to provide regulatory certainty. In 

addition, in definition of what constitutes a secondary containment or buffer zone is highly subjective and 

a matter of individual opinions. Therefore, more clarity on how these zones should be selected is 

requested. 

Page 63, Geochemical Data- The proposed requirements ask for geochemical data on injection zone, 

confining zone, any underground source of drinking water, and any other important zone. This may be a 

burdensome amount of information for GS sites. While some indication of geochemical parameters may 

be obtained from wireline methods, it can be a challenge to collect representative brine samples, 

especially from low permeability caprocks and deep saline formations. It is very unlikely we would even 

be able to collect samples from many low permeability confining layers. In addition, no guidance on the 

list of analytes (i.e. cations, anions, metals, physical parameters) is provided. We would suggest that data 

from regional studies and other deep wells also be allowed as an alternative for defining the geochemical 

setting. 

Page 64, Area of Review Determination/Modeling - We agree that multiphase numerical models are the 

best option for determining area of review (AOR) for complex, full-scale injection sites. Simpler 

analytical models may be used for smaller-scale, short-term tests. Multiphase computer simulations, 

supported with field data, should be primary tool for managing the storage sites through out the life cycle 

from site selection, permitting, characterization, operations, to post operational monitoring and closure. 

However, modeling should not be restricted to a single code or type of code. This will stifle innovation, 

because many more modeling codes are likely to be developed and existing commercial, academic, and 

national laboratory codes are incorporating new processes and improvements based on lessons learned 

from field projects. The incorporation of multiphase processes is likely to be a key requirement for 

models. However, we do not believe that fully coupled model with CO2 flow, transport, geochemical, 

geomechanical, and other processes in a single simulation for the entire facility and life cycle is currently 
Comments on EPA-HQ-OW-2008-390 Neeraj Gupta and Joel Sminchak 

12/24/2008, Page 5 Battelle 

These comments have been prepared by Battelle researchers as part of their work for MRCSP. They do not 

necessarily reflect the official view of Battelle, the U.S. DOE, or sponsors and members entities of MRCSP. 

feasible. Such fully-coupled codes require extensive computational power and are more applicable to 

evaluating basic science questions. 

Page 64, Area of Review Determination - More clarity on determining the AOR is requested. Currently 

it is not clear whether AOR will be based on CO2 phase spreading, dissolved CO2 plume, or pressure 

footprint. Models provide a large amount of information such as CO2 gas saturation, pressure, and 

aqueous concentrations. They also involve a fair amount of uncertainty. Our experience is that small 

portion of the CO2 may extend or “finger” much further than the bulk of the injected CO2. For example 

would EPA accept an AOR with a radius containing 90% of the CO2 as supercritical gas saturation, so 

that the applicants do not have to account for small-scale fingering or heterogeneities? 

Page 72, Corrective Action/Abandoned Wells - We would appreciate more clarity on whether it will be 

required to plug and abandon wells in zones above confining layers. At our sites, it appears the regulators 

have expected all inactive wells in the AOR to be plugged, even if they are not penetrating the injection 

zones. 

Page 82, Cement and Casing Materials- We suggest that if acid resistant cement and casing are to be 

required, they should be required only in the injection interval and immediate confining layer, which are 

most likely to be affected by the CO2 storage zone. The shallower drill strings may use more common 

materials. This seems a typical practice in most CO2 applications. 

Page 84, Fracture Pressures- We would suggest using a defined equation rather than 90% fracture 

pressure for injection pressure limits. Michigan and Ohio sites have permitted using a general equation to 

determine maximum allowable surface injection pressure: 

Maximum Allowable Surface Injection Pressure = 

depth x [(FG – 0.433 x (S.G. + safety factor)] – 14.7 

Depth = depth at top of storage interval 

FG = fracture gradient 

S.G. (average specific gravity of CO2 in borehole) 

Safety factor = 0.05 

14.7 = general friction factor 

We have seen different fracture gradients: Region 5 EPA specifies 0.8 psi/ft, but Ohio specifies 0.75 

psi/ft. They also permit determination of higher fracture pressures with field tests. Also, this equation 

allows 95% of fracture pressure. Why would CO2 require adjusting to 90% of fracture pressure? 

Page 86, Downhole Shut-off valves - We would be interested in more detail on the downhole shut-off 

valves, their use in on-shore conditions in other injection wells, and suggested criteria for shut-down. It 

appears that so far such valves have mainly been applied in offshore wells. We are not aware of these in 

any of the injection wells or EOR operations we have encountered. None of the MRCSP Phase II test 

permits have required this or mentioned it. This would seem to be somewhat redundant with annular 

pressure system. 

Page 88, Corrosion Coupons- We would appreciate more clarity on where corrosion coupons would be 

necessary (i.e. only within the injection zone or spaced within the tubing). Would it be sufficient to use 

place coupons above-ground in the CO2 pipeline near the well? 
Comments on EPA-HQ-OW-2008-390 Neeraj Gupta and Joel Sminchak 

12/24/2008, Page 6 Battelle 

These comments have been prepared by Battelle researchers as part of their work for MRCSP. They do not 

necessarily reflect the official view of Battelle, the U.S. DOE, or sponsors and members entities of MRCSP. 

Page 98, External MIT Testing- We suggest review of the experience with temperature logs, radioactive 

tracer logs, and noise logs to determine which method is best for evaluating external MIT. For example, 

in our experience temperature logs do not provide much indication of corrosion. In general, we have 

found wireline cement bond logs to be the best evaluator of external mechanical integrity. However, most 

assessment of these is needed before firm conclusions can be made. 

Page 102, Pressure monitoring in overlying zones- Implicit in this monitoring requirement is that 

network of deep monitoring wells will be required with the injection well. We know of no other method 

to accurately measure deep pressures. As such, this requirement will be costly to implement and should 

be spelled out clearly for planning purposes. It may also be pertinent to make this optional depending on 

identified risks. 

Page 103, Monitoring within the confining zone- In our experience it is very difficult to measure 

parameters in confining layers like pH, salinity, minerals, heavy metals, and organic contaminants on a 

routine basis. Confining zones typically consist of very low permeability carbonates that do not produce 

water or unstable shale not suitable for sampling due to borehole stability concerns. 

Page 103, Pressure fall-off tests- In our experience, pressure fall-off tests offer more information in 

initial injection testing. After longer term injection, we’ve seen basically the same, muted response. In 

addition, the fall-off response tended to take much longer after sustained injection. A concern may be 

that you need to monitor pressure fall off for several weeks, months, or years after 5 years of continuous 

injection to obtain useful data. This would lead to the need for standby wells or emitting CO2 to the 

atmosphere during fall-off tests. We think these should be part of the initial testing sequence for new 

injection wells, but they might be a more optional rather than a mandatory part of testing. 

Page 105, Tracers- We share some of EPA’s concerns about uncertainties in the use of Tracers such as 

PFTs. At the same time these and other tracers have been used successfully in many applications in 

hydrogeology and petroleum geology. The current language appears to go too far towards discouraging 

use of tracers. Tracers should not be required for every site however, at the same time their use under 

site-specific situations should not be discouraged. 

Page 108, Seismic Monitoring- Seismic and other indirect geophysical monitoring has been used to 

evaluate CO2 movement at some sites. However, it is also well known that all of these options (threedimensional, cross well, vertical seismic profile etc) may not work in every settings where rocks are too 

thin, have unsuitable sonic properties, and/or there is too much surface infrastructure or overburden 

present. Therefore, these options should be required only based on their feasibility at individual locations. 

In addition, these technologies may be fairly cost prohibitive on a routine basis. Finally, it must be 

recognized that none of these technologies can provide a complete mass balance or accounting to CO2

movement in subsurface. 

Page 111-118, Reporting- More streamlined permit application structure and clearly defined information 

requirements should be provided in regulatory guidance. We request streamlined reporting (Monitoring 

and testing plan, AOR/Corrective action review plan, post-injection plan, annual report, monthly 

operating reports). 

Page 111, Semi-Annual Reporting- Some of our sites have required monthly operating reports. Would 

this reduce reporting to semi-annual? We would appreciate additional clarification. 
Comments on EPA-HQ-OW-2008-390 Neeraj Gupta and Joel Sminchak 

12/24/2008, Page 7 Battelle 

These comments have been prepared by Battelle researchers as part of their work for MRCSP. They do not 

necessarily reflect the official view of Battelle, the U.S. DOE, or sponsors and members entities of MRCSP. 

Page 112, Reporting - The policy suggests monitoring and testing plan, AOR/corrective action plan, and 

Post-Injection plan. We’d recommend these documents be included as supporting attachments the permit 

application. This level of reporting may result in delays to the permitting process. 

Page 115, Annual Report- Another annual report is mentioned. The overall reporting requirements are 

confusing. We would recommend monthly or quarterly operating reports and a single annual report. 

Page 118, Post-injection Site Care Plan- The post injection site care plan would seem to require 

monitoring of pressures, plume extent, and other items after injection stops. However, this would prevent 

plugging and abandoning wells. It is recommended that the post-injection site care requirements allow 

for the plugging and abandoning of wells that are not being used for monitoring. 

Page 123- 50 year Post Injection Period- We strongly encourage EPA to not include a recommendation 

for 50 years of monitoring. We are concerned that most directors will choose to apply this as a default 

value, even for shorter duration projects or at low risk sites. Instead a site-specific post injection 

monitoring plan with clearly defined performance criteria such as pressure reduction, plume stabilization, 

lack of leakage, or stable parameter values over a period of time, should be used. This approach will give 

EPA the flexibility to design site-specific requirement but will also provide a level of certainty to the 

operators in terms of performance expectations. 

Page 138, Primacy/Jurisdiction- Given the size and location of potential GS projects, many storage areas 

are likely to cross state lines. For example almost all of the major sources of CO2 emissions in the 

MRCSP region are at or near state boundaries, along Ohio River. For example, a geologic storage facility 

located near Wheeling West Virginia could have a CO2 plume and injection well locations in Ohio, West 

Virginia, and Pennsylvania. It is unclear how these projects would be implemented regarding who has 

primacy in permitting the site under a single permit, rather than three separate permits. Additional 

guidance permitting sites with multiple jurisdictions is highly desirable to prevent confusion or legal 

challenges. 

Page 193, AOR Map- It will be difficult to provide the numerous site features on a single map as required 

in the regulation. Multiple maps should be allowed. Otherwise, the map must show the number, or name 

and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep 

stratigraphic boreholes, State or EPA approved subsurface cleanup sites, surface bodies of water, springs, 

mines (surface and subsurface), quarries, water wells and other pertinent surface features including 

structures intended for human occupancy and roads, and faults. 

Cost Estimates- In general most of the estimates for hours, hourly rates, and costs required for 

implementing the requirements appear to be too low compared to our experience and the complexity of 

proposed regulatory requirements. It is recommended that EPA obtain more realistic cost estimates for all 

aspects of the regulations, deep well drilling, monitoring, expert delivery of geosciences and engineering 

professionals. 
Letter ID: 0229 

Commenter: Neeraj Gupta 

Organization: Battelle Energy Technology (BET) 

Letter ID: 0229 Comment ID: 21809 Letter Lines: 57 to 93 

Comment Code: 1000 1. General and Administrative Comments 

Comment Code: 1852 1.4.2.1 DOE Regional Carbon Sequestration Partnerships 

Comment: Introduction and Background 

This document summarizes review and comments from Battelle researchers’ under 

he regulatory work of Midwest Regional Carbon Sequestration Partnership’s 

(MRCSP) on the USEPA Proposed Rule- Federal Requirements under UIC Program for 

CO2 Geologic Sequestration Wells (Docket ID No. EPA-HQ-OW2008-390). These 

comments reflect our experience in permitting and implementing three Phase II 

CO2 injection tests and the MRCSP Phase III project, as well as work on several 

other research projects during last 12 years of CCS research at Battelle: 

Table [see PDF Docket ID EPA-HQ-OW-2008-390-0229.1] 

The analysis also reflects Battelle experience with the UIC permitting of the 

AEP Mountaineer CO2 storage project, which is targeting 4 years of injection of 

over 100,000 metric tons CO2/yr at the AEP Mountaineer plant in New Haven, WV. 

While the MRCSP includes over 30 different members, the comments expressed 

herein do not necessarily reflect opinions of the individual members of the 

MRCSP. 

The MRCSP is one of seven partnerships in a nationwide effort to determine 

regionally-appropriate carbon sequestration options and opportunities. These 

partnerships are part of an overall effort by the U.S. Department of Energy’s 

National Energy Technology Laboratory (DOE/NETL) to develop robust strategies 

for mitigating carbon dioxide emissions. The MRCSP was formed to assess the 

technical potential, economic viability, and public acceptability of carbon 

sequestration within its Region. 

The MRCSP region consists of eight contiguous states: Indiana, Kentucky, 

Maryland, Michigan, New York, Ohio, Pennsylvania, and West Virginia. The MRCSP 

includes over 30 organizations from the research community, energy industry, 

universities, non-government, and government organizations. In the first phase 

of research, which took place over a two year period ending in September 2005, 

the MRCSP characterized carbon sequestration opportunities in the region. MRCSP 

is now involved in a four year Phase II effort that began in October 2005. This 

phase will conduct several small-scale field tests of sequestration in different 

locations around the region to evaluate various sequestration options in realworld settings. The MRCSP Phase III project will involve sequestration of more 

1
than 1 million metric tons CO2. 

Individual Response: EPA acknowledges the value of the DOE pilot projects and resultant data 

and information generated by such projects. EPA has evaluated permits and reviewed operational 

data and information associated with the seven RCSPs funded by the U.S. Department of Energy 

and coordinated through the National Energy Technology Laboratory (NETL). In addition to the 

information cited in the preamble to the proposed rule, EPA published a Notice of Data 

Availability and Request for Comment on August 31, 2009 (74 FR 44802), in which the Agency 

described the results of research at three DOE partnership sites: the Escatawpa, Mississippi 

project; the Aneth Field project in Paradox Basin, Southeast Utah; and the Pump Canyon Site, 

New Mexico. The Agency will continue to track GS project developments and evaluate new and 

ongoing research and information to ensure USDW protection, including those performed by the 

MRCSP. 

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after 

finalizing the rule, the Agency plans to collect and review data every six years on GS projects, 

including data generated by the partnerships, 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: 0229 Comment ID: 21810 Letter Lines: 95 to 101 

Comment Code: 2400 1.8 Comments on EPA's adaptive rulemaking process 

Comment: General and Specific Comments on Proposed Regulations 

Adaptive Approach - Overall the proposed policy presents a comprehensive 

framework for geologic sequestration (GS). The adaptive approach seems 

especially useful for enabling early adopters to pursue GS while allowing 

flexibility for adjustments in the future based on technology development and 

lessons learned at individual sites. 

Individual Response: EPA agrees that an adaptive approach to the UIC GS rulemaking is 

appropriate. The Agency plans to use such an approach to ensure that USDWs are protected from 

endangerment and meet the potentially fast pace of GS deployment. EPA believes that an 

adaptive approach will allow regulatory development to proceed in time to meet the current and 

future demand for Class VI permits while recognizing the need to: continue to gather data from 

pilot projects and other research as it becomes available; and to enhance understanding of the 

technical and administrative aspects of GS deployment, operation, and technology developments. 

EPA 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. 

2
Letter ID: 0229 Comment ID: 21811 Letter Lines: 103 to 108 

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

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

comment) 

Comment: Permit Organization - The proposed regulation presents a large amount of 

material spread throughout the document. In general, it has been easier to 

complete the permit process with the basic UIC form with the simplified list of 

attachments (this procedure was used for Region 4 and Region 5). Thus, the 

MRCSP would encourage EPA to prepare suggested formats and a systematically 

organized list of information and documents required for the permit. 

Individual Response: EPA is developing guidance on site characterization for GS projects to 

assist owners or operators and Directors in evaluating permit requirements and applications 

under §146.82. The guidance provides recommendations regarding characterizing the regional 

geology and hydrogeology of a proposed GS site as well as performing the necessary 

geochemical, geomechanical, and geophysical analyses of the injection and confining zone. EPA 

is also developing a number of technical guidances and implementation materials to assist 

owners or operators and Directors in the permitting process. EPA expects that these guidances 

will assist permit writers in performing 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 guidance can be found on EPA’s website at 

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

Letter ID: 0229 Comment ID: 21812 Letter Lines: 110 to 132 

Comment Code: 1850 1.4.2 CO2 GS Field Research 

Comment Code: 2048 1.5.2.4 Oppose Class VI/ Support Class V experimental technology well 

Comment: Encouraging Innovation and Experimental Projects - We believe that USEPA 

recognizes that many facets of GS site selection, implementation, and monitoring 

are still under technological assessment and innovation phase. Many of the 

concepts and technological options are being evaluated under current field 

demonstration programs by Regional Partnerships and other projects across the 

world. The success of these existing and future experimental projects is 

heavily dependent on permitting process being as simple as possible. USEPA UIC 

Guidance 83 allowing the use of Class V experimental wells has been a very 

useful mechanism for facilitating experimental projects. In fact, if the 

proposed Class Vi framework was to be applied to smaller-scale tests currently 

underway, it is our belief that many projects would have financial, logistical, 

or technical difficulties in moving to field stage. With the proposed 

regulation in the public comment phase, MRCSP has already observed that the 

permit regulations for even small-scale field tests (such as MRCSP East Bend 

site and AEP Mountaineer Project) are becoming too onerous compared to similar 

projects permitted prior to the issuance of draft regulations. For example, the 

3
post-injection monitoring durations have become much longer with the regulators 

citing the draft regulation as a basis for requirements. Such a trend will 

certainly adversely affect future experimental projects and lead to less new 

data being available to all stakeholders. We strongly encourage EPA to 1) 

continue the existing option for using Class V experimental well permits option 

and/or specifically allow for a more simplified and less onerous permitting 

requirements for such project. 

Individual Response: EPA acknowledges the value of the DOE pilot projects and resultant data 

and information generated by such projects. EPA has evaluated permits and reviewed operational 

data and information associated with the seven RCSPs funded by the U.S. Department of Energy 

and coordinated through the National Energy Technology Laboratory (NETL). In addition to the 

information cited in the preamble to the proposed rule, EPA published a Notice of Data 

Availability and Request for Comment on August 31, 2009 (74 FR 44802), in which the Agency 

described the results of research at three DOE partnership sites: the Escatawpa, Mississippi 

project; the Aneth Field project in Paradox Basin, Southeast Utah; and the Pump Canyon Site, 

New Mexico. 

The GS final rule does not affect an owner or operator’s ability to apply for a Class V 

experimental technology well permit for projects that are of an experimental nature, i.e., to test 

GS technologies. 

The Agency is also tracking operation and technical developments of more than three dozen 

small- and large-scale GS injection projects in the United States and abroad. EPA meets 

regularly with DOE to discuss its research initiatives, project developments, and "best practices." 

EPA agrees with commenters that flexibility to address new research is important. Even after 

finalizing the rule, the Agency plans to collect and review data every six years on GS projects to 

determine whether the appropriate amount and types of information and appropriate 

documentation are being collected, and to determine if modifications to the requirements are 

appropriate or necessary. 

Letter ID: 0229 Comment ID: 21813 Letter Lines: 134 to 147 

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

Comment: Complexity and Consistency of Regulations - We recognize that EPA has attempted 

to provide a great deal of flexibility in most aspects of the regulations, while 

incorporating most of currently known concepts and technologies in permitting, 

operation, and monitoring of the sites. The flexibility has primarily been 

incorporated through making the requirements subject to "directors" decision. 

Our concern is that some directors may choose to require all of the numerous 

requirements mentioned in the permit, rather then selectively requiring an 

appropriate portfolio of safeguards. Such an approach could deter operators 

from considering the GS as an option for CO2 mitigation. Another concern is 

that the requirements will be applied with inconsistent level of flexibility in 

4
various regions and states, making some regions more or less favorable for GS. 

We encourage EPA’s continuing oversight and guidance in ensuring that the 

regulations are applied consistently and with a reasonable selection of 

requirements. 

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

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

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

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

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

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

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

Letter ID: 0229 Comment ID: 21814 Letter Lines: 149 to 157 

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

Comment: Page 48 "Grandfather" Status - It is unclear how this would affect existing 

MRCSP Phase II Test sites. These host sites have been very accommodating in 

supporting these small scale tests and it is unclear if they would be subject to 

long term monitoring or allowed to be closed out under the original Class V CO2 

experimental policy the wells were permitted under. Clarification that the 

small scale tests would be allowed to continue injection under their original 

permit conditions be closed out under their original permits would be helpful to 

the pioneers of this technology, unless of course the site hosts wish to convert 

to a Class VI well under new regulations for longer-term.. 

Individual Response: EPA agrees that, when the Regional Carbon Sequestration Partnership 

projects are no longer of an experimental nature, they should be re-permitted as Class VI wells 

and subject to the Class VI requirements if they are to be used for commercial-scale GS. 

EPA is providing for the construction of Class V experimental technology wells to be 

grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director 

that the wells were engineered and constructed to meet the requirements at §146.86(a) and 

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA 

understands based on reviews of several Class V pilot project permits, that many Class V 

experimental technology wells, including those used in the RCSP projects, are specifically 

designed for injection of CO2 and are being built to Class I non-hazardous well specifications, 

which should facilitate re-permitting as Class VI wells. 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. See the 

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail 

on these requirements. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental 

technology well classification to clarify permitting for Class V wells. This addendum will 

5
address shifting of Class V experimental projects to full-scale GS projects and the future use of 

the Class V experimental technology well subclass for research and testing of new GS 

technologies. 

Letter ID: 0229 Comment ID: 21827 Letter Lines: 159 to 180 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

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

Comment: Page 54 CO2 Composition Requirements and Hazardous Waste under RCRA- While 

we 

agree some chemical impurities may cause CO2 to be designated hazardous waste, 

there must be more clear guidance on this issue. In the MRCSP tests, each 

regulatory agency had different requirements on this issue injectate composition 

and analysis, even for commercial CO2. One agency required injection to cease if 

the injectate was above any maximum contaminant level (MCL) for groundwater, 

which is a large list of chemicals. Another state agency asked for some 

technically infeasible analyses on the CO2 stream (pH, Fluouride, Mercury). 

Some impurities like H2S and hydrocarbons are naturally occurring in most deep 

saline formations anyway, so we would discourage setting limits on these items. 

Another significant aspect is the composition of CO2 derived from various 

industrial, power generation, and capture processes. All of these are likely to 

result in minor differences in chemical compositions. In most cases the 

concentration of hazardous impurities is likely to be very low. The incremental 

environmental impact of these minor or trace impurities in deep formations that 

already have brine and will have CO2 must be demonstrated before these are 

excluded from the Class VI injection wells. EPA is encouraged to evaluate the 

range of potential impurities from various streams, their environmental impact 

if any, and provide more specific guidance on this topic. The evaluation should 

also assess how many of the GS projects could become infeasible due to this 

requirement. Finally, EPA should clarify whether CO2 streams with RCRA level of 

impurities can be injected under Class I permits. 

Individual Response: EPA received many comments regarding the applicability of the RCRA 

regulations and statute to CO2 streams that are geologically sequestered under the final Class VI 

UIC well requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. Finally, EPA also notes that 

the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water 

Act (SDWA), is not making any changes to the RCRA regulations 

6
EPA recognizes 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. 

Since the GS rule, at §146.81(d), prohibits the injection of CO2 streams that meet the definition 

of a hazardous waste under 40 CFR part 261, injection of a CO2 stream that is determined to be a 

hazardous waste may only occur in a Class I hazardous waste injection well. 

Letter ID: 0229 Comment ID: 21828 Letter Lines: 182 to 187 

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

(seeking comment) 

Comment: Page 61, Injection Zone and Confining Layer - Conditions under which "director" 

may require a secondary containment/buffer zone should be more clearly defined 

to provide regulatory certainty. In addition, in definition of what constitutes 

a secondary containment or buffer zone is highly subjective and a matter of 

individual opinions. Therefore, more clarity on how these zones should be 

selected is requested. 

Individual Response: EPA retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (e.g., §146.83(b)). The Agency's decision is 

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

assert that these requirements (at §146.83(b)) promote a flexible, risk-based, site-specific 

approach to characterizing and permitting a site for GS projects. 

The Agency believes that providing the Director discretion will allow consideration of a range of 

sites for GS, based on site-specific conditions and ensure USDW protection. EPA believes that 

requiring appropriate site characterization by the owner or operator (under §146.82) and 

providing an appropriate degree of flexibility to the Director to evaluate site-specific geologic 

data will afford the greatest protection of USDWs from endangerment. 

7
EPA is developing guidance on site characterization for GS projects to assist owners or operators 

and Directors in evaluating permit requirements and applications under §146.82. The guidance 

provides recommendations regarding characterizing the regional geology and hydrogeology of a 

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

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

assist permit writers in making an objective decision about requiring additional confining layers. 

The guidance can be found on EPA’s website at 

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

Letter ID: 0229 Comment ID: 21829 Letter Lines: 189 to 199 

Comment Code: 3140 2.1.4 Comments that the proposed geologic data requirements are too 

stringent 

Comment: Page 63, Geochemical Data- The proposed requirements ask for geochemical data on 

injection zone, confining zone, any underground source of drinking water, and 

any other important zone. This may be a burdensome amount of information for GS 

sites. While some indication of geochemical parameters may be obtained from 

wireline methods, it can be a challenge to collect representative brine samples, 

especially from low permeability caprocks and deep saline formations. It is 

very unlikely we would even be able to collect samples from many low 

permeability confining layers. In addition, no guidance on the list of analytes 

(i.e. cations, anions, metals, physical parameters) is provided. We would 

suggest that data from regional studies and other deep wells also be allowed as 

an alternative for defining the geochemical setting. 

Individual Response: The Agency believes that the requirement at §146.82(a)(6) to submit 

baseline geochemical data on subsurface geologic formations, including all USDWs in the AoR 

is appropriate and protective of USDWs. EPA believes that this data will support monitoring 

plan development, inform injectate fate and transport model development (e.g., by providing 

appropriate input parameters), and provide information needed to respond to any unexpected and 

unpermitted leaks outside of the injection zone. The baseline geochemical information will allow 

the owner or operator and permitting authority to evaluate monitoring data and identify any 

changes in subsurface geochemistry that may indicate fluid movement. 

The rule requires geochemical analysis of, at a minimum, the injection zone, confining zone, and 

all USDWs (§146.82(a)(6)). These geochemical tests are necessary to ensure the adequacy of the 

confining system and to serve as a baseline for future monitoring. The Director has the discretion 

to require geochemical analysis of additional subsurface zones if in the Director's opinion they 

are necessary for the protection of USDWs from endangerment. 

EPA agrees that site characterization should be site-specific, particularly in light of the variety of 

geologic settings in which GS may be employed. EPA believes that, while there is a large 

amount of required information, the owner or operator is given flexibility in determining what 

methods are used to demonstrate the suitability of a potential site. EPA envisions an ongoing 

8
dialogue between the Director and the owner or operator during the permitting process (as well 

as throughout the operation of the site). EPA clarifies that if recent information about the site 

exists (e.g., from other geologic studies of the area), the Director may, at his/her discretion, allow 

its use in the site characterization for the GS project. 

Letter ID: 0229 Comment ID: 21830 Letter Lines: 201 to 217 

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

delineate the AoR (seeking comment) 

Comment: Page 64, Area of Review Determination/Modeling - We agree that multiphase 

numerical models are the best option for determining area of review (AOR) for 

complex, full-scale injection sites. Simpler analytical models may be used for 

smaller-scale, short-term tests. Multiphase computer simulations, supported 

with field data, should be primary tool for managing the storage sites through 

out the life cycle from site selection, permitting, characterization, 

operations, to post operational monitoring and closure. However, modeling 

should not be restricted to a single code or type of code. This will stifle 

innovation, because many more modeling codes are likely to be developed and 

existing commercial, academic, and national laboratory codes are incorporating 

new processes and improvements based on lessons learned from field projects. 

The incorporation of multiphase processes is likely to be a key requirement for 

models. However, we do not believe that fully coupled model with CO2 flow, 

transport, geochemical, geomechanical, and other processes in a single 

simulation for the entire facility and life cycle is currently feasible. Such 

fully-coupled codes require extensive computational power and are more 

applicable to evaluating basic science questions. 

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

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

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

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

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

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

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

penetrations. 

EPA agrees that operators should have the flexibility to select models with which they are 

familiar and that are most appropriate to the site conditions and available data types and 

amounts. EPA has evaluated technical documents regarding several computational models that 

may be used for GS sites. Based on this review (as documented in the preamble to the proposed 

GS regulation and the background document "Computational Modeling of Underground 

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

Underground Sources of Drinking Water"), EPA believes that several models meet the minimum 

requirements for models in the GS regulation. 

9
Letter ID: 0229 Comment ID: 21831 Letter Lines: 219 to 227 

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

Comment: Page 64, Area of Review Determination -More clarity on determining the AOR is 

requested. Currently it is not clear whether AOR will be based on CO2 phase 

spreading, dissolved CO2 plume, or pressure footprint. Models provide a large 

amount of information such as CO2 gas saturation, pressure, and aqueous 

concentrations. They also involve a fair amount of uncertainty. Our experience 

is that small portion of the CO2 may extend or "finger" much further than the 

bulk of the injected CO2. For example would EPA accept an AOR with a radius 

containing 90% of the CO2 as supercritical gas saturation, so that the 

applicants do not have to account for small-scale fingering or heterogeneities? 

Individual Response: EPA disagrees with defining the AoR relative to the percentage of CO2 

saturation. The UIC regulations, including the Class VI regulations, are designed to ensure 

protection of USDWs from endangerment. The Agency believes that the AoR needs to 

incorporate not only the CO2 itself—regardless of saturation or phase—but also the area of 

increased pressure ahead of the CO2 plume, which can potentially displace saline, native fluids 

(i.e., naturally occurring salty water) into USDWs. This pressure front would typically 

encompass an area larger than the plume itself, including any areas of small scale fingering or 

heterogeneities or where CO2 saturation is less than 100 percent. The Agency has carefully 

considered all comments on the AoR definition at 146.84(a) and modified it to read as follows: 

The region surrounding the geologic sequestration project where USDWs may be endangered by 

the injection activity. The area of review is delineated using computational modeling that 

accounts for the physical and chemical properties of all phases of the injected CO2 stream and is 

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

EPA clarifies that the definition of AoR includes all areas that may potentially be endangered by 

the injection activity. EPA recognizes that modeled AoRs may involve some uncertainty or 

“fingering,” as the commenter mentions. Any needed corrective action must be done on wells in 

the modeled AoR, which would include these areas to ensure that they address any area that 

would be impacted by the CO2 plume and pressure front. 

Letter ID: 0229 Comment ID: 21832 Letter Lines: 229 to 233 

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 

CFR 146.84) 

Comment: Page 72, Corrective Action/Abandoned Wells - We would appreciate more clarity on 

whether it will be required to plug and abandon wells in zones above confining 

layers. At our sites, it appears the regulators have expected all inactive 

wells in the AOR to be plugged, even if they are not penetrating the injection 

zones. 

10
Individual Response: EPA clarifies that wells requiring corrective action are those in the AoR 

and wells that may penetrate the confining zone per 146.84(c)(2). Any well that penetrates the 

confining zone, even if it does not extend all the way through the confining formation, is to be 

included in the tabulation. EPA is issuing guidance on how to identify all wells that require 

corrective action. 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. 

Corrective action must be performed on wells determined to need corrective action in order to 

prevent movement of fluid into or between USDWs, therefore some wells above the confining 

zone may not be required to undergo corrective action; however, such a determination will be 

based on site-specific information. 

Letter ID: 0229 Comment ID: 21845 Letter Lines: 235 to 239 

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

comment) 

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

Comment: Page 82, Cement and Casing Materials- We suggest that if acid resistant cement 

and casing are to be required, they should be required only in the injection 

interval and immediate confining layer, which are most likely to be affected by 

the CO2 storage zone. The shallower drill strings may use more common materials. 

This seems a typical practice in most CO2 applications. 

Individual Response: EPA clarifies that acid-resistant cement and casing are not specifically 

required in a Class VI injection well. Rather, as stated in §146.86(b)(1), casings and cement used 

must have sufficient strength and be designed for the life of the sequestration project. Further, 

materials must meet standards listed in the rule and be compatible with fluids with which the 

materials may be expected to come into contact. Therefore, some well materials may need to be 

acid-resistant and some may not if they do not come in contact with the CO2 stream or other 

corrosive fluids and if approved by the Director. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

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

Letter ID: 0229 Comment ID: 21846 Letter Lines: 241 to 259 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: Page 84, Fracture Pressures- We would suggest using a defined equation rather 

11
than 90% fracture pressure for injection pressure limits. Michigan and Ohio 

sites have permitted using a general equation to determine maximum allowable 

surface injection pressure: 

Maximum Allowable Surface Injection Pressure = 

depth x [(FG - 0.433 x (S.G. + safety factor)] - 14.7 

Depth = depth at top of storage interval 

FG = fracture gradient 

S.G. (average specific gravity of CO2 in borehole) 

Safety factor = 0.05 

14.7 = general friction factor 

We have seen different fracture gradients: Region 5 EPA specifies 0.8 psi/ft, 

but Ohio specifies 0.75 psi/ft. They also permit determination of higher 

fracture pressures with field tests. Also, this equation allows 95% of fracture 

pressure. Why would CO2 require adjusting to 90% of fracture pressure? 

Individual Response: EPA believes that injection pressures that are based on 90 percent of the 

fracture pressure are an appropriate maximum for the federal requirements. However, the 

determination of the injection pressure for a specific project must be approved by the Director. 

Additionally, the Agency clarifies that if, in preparing any permit, if the Director determines, 

based on site-specific information, that a lower injection pressure is appropriate to ensure 

protection of USDWs from endangerment, he or she has the authority to set a lower injection 

pressure limit in the permit. The Agency clarifies that if a permitting authority wants to use an 

equation to set the injection pressure limit in a GS permit, this is acceptable. However, the safety 

factor must be based on 90 percent of the fracture pressure in order to protect USDWs from 

endangerment. 

Letter ID: 0229 Comment ID: 21847 Letter Lines: 261 to 267 

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

Comment: Page 86, Downhole Shut-off valves - We would be interested in more detail on the 

downhole shut-off valves, their use in on-shore conditions in other injection 

wells, and suggested criteria for shut-down. It appears that so far such valves 

have mainly been applied in offshore wells. We are not aware of these in any of 

the injection wells or EOR operations we have encountered. None of the MRCSP 

Phase II test permits have required this or mentioned it. This would seem to be 

somewhat redundant with annular pressure system. 

Individual Response: Down-hole shut-off systems are typically installed below the packer on a 

well and are used to stem uncontrolled flow of fluids out of the well. The devices default to the 

closed position and are opened by application of force from the surface. Pressure can be applied 

by the fluid itself or through a hydraulic signal from the surface. They are typically set to close 

12
when the pressure in the tubing drops below a pre-determined level. It is possible to set them to 

deploy based on other triggers. The devices can either be deployed on the tubing or by wire line. 

Tubing-deployed devices have the advantage of not constricting the flow in the tubing, but 

replacing them requires removal of the tubing. Wire line devices constrict the flow in the tubing, 

causing reduced pressure in the well, but these are easier to deploy and retrieve. Down-hole shut 

off valves are required in offshore oil and gas wells; however, they are considered standard on 

other wells where well damage is likely or where well failure could result in the release of toxic 

chemicals. Several types of Class II wells commonly use down-hole shut-off systems and include 

high pressure/high temperature wells, acid gas injection, and wells located in permafrost regions. 

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 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. 

Letter ID: 0229 Comment ID: 21848 Letter Lines: 269 to 272 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: Page 88, Corrosion Coupons- We would appreciate more clarity on where corrosion 

coupons would be necessary (i.e. only within the injection zone or spaced within 

the tubing). Would it be sufficient to use place coupons above-ground in the 

CO2 pipeline near the well? 

Individual Response: EPA clarifies that the requirement to monitor corrosion by placing the 

coupons in the well would provide a more accurate analogue of the conditions to which well 

materials are exposed than would surface testing (i.e., in the pipeline). Please note that the use of 

coupons is one out three methods that an owner or operator may use to monitor corrosion under 

§146.90(c). EPA adds that, under SDWA authority, the Agency cannot prescribe any testing 

methods that involve the pipeline. 

Several options are available for monitoring corrosion using coupons. For example, corrosion 

coupons may be placed in a side stream loop so they are exposed to the injectate. Valves on 

either end of the side stream loop allow the owner or operator to shut off the injectate flow, 

extract the coupons, and measure any change in thickness. Another monitoring option is to insert 

the coupons through a "T" in the flowline and directly lower this into the injection flow. The 

coupons can then be retracted into the side pipe, extracted, and measured. Finally, spool pieces 

13
of the construction material can be installed either in the injectate flow line or in a side stream; 

flanges and valves allow the spool pieces to be isolated from the injectate so they can be 

evaluated for corrosion. 

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

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

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

Letter ID: 0229 Comment ID: 21849 Letter Lines: 274 to 280 

Comment Code: 4540 2.5.2 Proposed external MIT requirements 

Comment: Page 98, External MIT Testing- We suggest review of the experience with 

temperature logs, radioactive tracer logs, and noise logs to determine which 

method is best for evaluating external MIT. For example, in our experience 

temperature logs do not provide much indication of corrosion. In general, we 

have found wireline cement bond logs to be the best evaluator of external 

mechanical integrity. However, most assessment of these is needed before firm 

conclusions can be made. 

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

approved tracer log or temperature or noise logs) are effective methods for demonstrating 

external MI. They are currently used by owners or operators of Class I and Class II wells. The 

Agency notes that the regulations do provide the Director flexibility at §146.89(e) to approve the 

use of alternative MIT methods. They have been used successfully by injection well operators 

for decades and provide an important early warning of potential problems in the injection well 

system. For additional information, please see the discussion of MITs in the final rule preamble. 

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

data every six years on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0229 Comment ID: 21850 Letter Lines: 282 to 287 

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

CFR 146.90) 

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

Comment: Page 102, Pressure monitoring in overlying zones- Implicit in this monitoring 

14
requirement is that network of deep monitoring wells will be required with the 

injection well. We know of no other method to accurately measure deep 

pressures. As such, this requirement will be costly to implement and should be 

spelled out clearly for planning purposes. It may also be pertinent to make 

this optional depending on identified risks. 

Individual Response: EPA acknowledges the commenters' concern about the cost of 

monitoring. However, EPA believes that monitoring is essential for protection of USDWs at GS 

sites. Although a significant cost in absolute terms, monitoring costs are expected to be a small 

fraction of site operating costs, according to EPA's cost analysis for the GS rulemaking (which is 

available in the docket). 

EPA believes that monitoring using wells in the injection zone, e.g., for pressure monitoring as 

required at §146.90(g)(1), can be safely performed if the wells are constructed to prevent flow 

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

construction technologies exist and have been used in the oil and gas industry for years. EPA 

believes that properly constructed monitoring wells will be a safe way to obtain the data that is 

essential to ensure that the injected CO2 remains confined in the injection zone and that pressure 

changes are not causing movement of formation or other fluids. To mitigate the risk of fluid 

movement, EPA requires owners and operators to submit a testing and monitoring plan that 

describes how the owner or operator plans to site and construct monitoring wells. 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 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, 

and tracking the CO2 plume and pressure front. 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: 0229 Comment ID: 21857 Letter Lines: 289 to 293 

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

CFR 146.90) 

Comment: Page 103, Monitoring within the confining zone- In our experience it is very 

difficult to measure parameters in confining layers like pH, salinity, minerals, 

heavy metals, and organic contaminants on a routine basis. Confining zones 

typically consist of very low permeability carbonates that do not produce water 

or unstable shale not suitable for sampling due to borehole stability concerns. 

15
Individual Response: EPA recognizes that the collection of representative ground water 

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

to preserve the integrity of such samples. EPA is developing guidance on testing and monitoring 

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

proposed monitoring plans. The guidance describes available technologies and recommended 

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

geophysical logging and testing of injection wells, MITs, injection well testing during operation, 

groundwater quality monitoring, tracking the CO2 plume and pressure front, and soil gas and 

surface air monitoring which may be required by the UIC Director for specific GS projects. The 

guidance can be found on EPA’s website at 

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

Regarding the comment about the difficulty of sampling within the confining zone, EPA clarifies 

that §146.90(d) requires owners and operators to monitor ground water quality and geochemical 

changes above the confining zone(s), rather than within the confining zone. 

Letter ID: 0229 Comment ID: 21858 Letter Lines: 295 to 304 

Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment) 

Comment: Page 103, Pressure fall-off tests- In our experience, pressure fall-off tests 

offer more information in initial injection testing. After longer term 

injection, we’ve seen basically the same, muted response. In addition, the 

fall-off response tended to take much longer after sustained injection. A 

concern may be that you need to monitor pressure fall off for several weeks, 

months, or years after 5 years of continuous injection to obtain useful data. 

This would lead to the need for standby wells or emitting CO2 to the atmosphere 

during fall-off tests. We think these should be part of the initial testing 

sequence for new injection wells, but they might be a more optional rather than 

a mandatory part of testing. 

Individual Response: EPA believes that a frequency of at least once every five years, as 

specified at §146.90(f), is an appropriate interval for pressure fall-off testing (particularly given 

the suite of tests operators will perform on the well and the site). EPA clarifies that the Director 

may require more frequent pressure fall-off tests at a specific project, if necessary based on sitespecific circumstances. Pressure fall-off tests may be conducted in conjunction with other well 

performance tests (i.e., mechanical integrity testing) to ensure safe and effective operations. All 

monitoring data collected, including information from pressure fall-off tests, will be incorporated 

in AoR reevaluations, at least every five years. 

Letter ID: 0229 Comment ID: 21859 Letter Lines: 306 to 311 

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

(seeking comment) 

16
Comment: Page 105, Tracers- We share some of EPA’s concerns about uncertainties in the 

use of Tracers such as PFTs. At the same time these and other tracers have been 

used successfully in many applications in hydrogeology and petroleum geology. 

The current language appears to go too far towards discouraging use of tracers. 

Tracers should not be required for every site however, at the same time their 

use under site-specific situations should not be discouraged. 

Individual Response: EPA agrees that tracers can be useful tools for monitoring GS projects. 

However, EPA believes 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. The Director would assess the use of tracers 

in the context of site-specific information, including risks to USDWs and other environmental 

and health risks. 

EPA will continue to track research related to tracer use, and plans to, every six years, collect 

and review data on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0229 Comment ID: 21860 Letter Lines: 313 to 322 

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

comment) 

Comment: Page 108, Seismic Monitoring- Seismic and other indirect geophysical monitoring 

has been used to evaluate CO2 movement at some sites. However, it is also well 

known that all of these options (threedimensional, cross well, vertical seismic 

profile etc) may not work in every settings where rocks are too thin, have 

unsuitable sonic properties, and/or there is too much surface infrastructure or 

overburden present. Therefore, these options should be required only based on 

their feasibility at individual locations. In addition, these technologies may 

be fairly cost prohibitive on a routine basis. Finally, it must be recognized 

that none of these technologies can provide a complete mass balance or 

accounting to CO2 movement in subsurface. 

Individual Response: EPA agrees that seismic monitoring may not be applicable or appropriate 

for all sites. The final 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 also 

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

not appropriate. 

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EPA is affording Director's discretion regarding the use of geophysical techniques at some sites 

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

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

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

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

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

with their permit application. 

There may also be interference from urban and residential infrastructure, and sites with loose 

materials such as glacial deposits may produce poor or inaccurate seismic images. But the 

laterally continuous, confined formations that that make many sites appropriate for GS will also 

render many of them suitable for seismic surveying. In fact, seismic and other geophysical and 

remote sensing methods have been used with success at GS pilot projects and are likely to be 

useful for plume tracking at many GS sites. StatOilHydro has used both time-lapse seismic and 

gravity methods to track the CO2 plume at the Sleipner site. Seismic surveys have also been used 

successfully at the Weyburn pilot project site in Saskatchewan. Although resolution on seismic 

surveys is generally accepted to be the best of the geophysical methods, gravity monitoring at 

Sleipner has also imaged the plume, and results have agreed with seismic surveys. At InSalah, 

PSInSAR satellite monitoring has been used in combination with tiltmeter data and was able to 

detect otherwise imperceptible ground displacement (i.e., at the millimeter scale) that indicates 

the presence of CO2. 

EPA acknowledges the commenters' concern about the cost of geophysical techniques. However, 

EPA believes that tracking of the plume is essential for protection of USDWs from 

endangerment at GS sites and that geophysical methods are necessary for such tracking. 

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

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

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

Letter ID: 0229 Comment ID: 21861 Letter Lines: 324 to 328 

Comment Code: 4700 2.7 Proposed Recordkeeping and Reporting Requirements (40 CFR 

146.91) 

Comment: Page 111-118, Reporting- More streamlined permit application structure and 

clearly defined information requirements should be provided in regulatory 

guidance. We request streamlined reporting (Monitoring and testing plan, 

AOR/Corrective action review plan, post-injection plan, annual report, monthly 

operating reports). 

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Individual Response: EPA disagrees with the suggestion that the permit application structure be 

more streamlined and information requirements be more clearly defined. EPA believes that 

information required to be submitted with the permit application under §146.82 is necessary and 

appropriate to provide permitting authorities sufficient basis for informed decisions about 

establishing permit conditions and granting permits. The purpose of these requirements is to 

protect USDWs from endangerment, and all operations must be permitted and operated in 

manner that is protective of USDWs. 

Furthermore, EPA’s GS Rule provides for a streamlined approach to reporting under §146.91. 

EPA is retaining the semi-annual reporting requirement in the final rule at §146.91(a) in order to 

ensure that permitting authorities can maintain proper oversight of GS projects, particularly in 

the early stages of rule implementation and deployment of GS technologies. The Agency also 

clarifies that permitting authorities may choose to require more frequent reporting, at the 

discretion of the Director. 

Letter ID: 0229 Comment ID: 21862 Letter Lines: 330 to 332 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Page 111, Semi-Annual Reporting- Some of our sites have required monthly 

operating reports. Would this reduce reporting to semi-annual? We would 

appreciate additional clarification. 

Individual Response: Existing pilot projects will continue to be regulated under their Class V 

experimental well permits and must meet the reporting requirements set forth in the individual 

permit. EPA expects that, as the permits for these Class V projects expire or if owners or 

operators of Class V projects seek to apply for a Class VI permit (provided construction 

components are grandfathered), they would be re-permitted as Class VI wells (subject to 

reporting requirements at §146.91). If the projects continue to be of an experimental nature, the 

wells may continue to be permitted as Class V experimental technology wells (subject to the 

reporting requirements in the permit). 

Letter ID: 0229 Comment ID: 21863 Letter Lines: 334 to 337 

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

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

comment) 

Comment: Page 112, Reporting - The policy suggests monitoring and testing plan, 

AOR/corrective action plan, and Post-Injection plan. We’d recommend these 

documents be included as supporting attachments the permit application. This 

level of reporting may result in delays to the permitting process. 

Individual Response: EPA believes that the requirement that owners and operators develop an 

area of review (AoR) and corrective action plan, a testing and monitoring plan, an injection well 

19
plugging plan, a post-injection site care and site closure plan, and an emergency and remedial 

response plan are necessary to protecting USDWs from endangerment and does not believe they 

will result in delays to the permitting process. EPA anticipates that these plans will be 

attachments to the permit application and also acknowledges that not all information necessary to 

develop full plans will be available at the time of the initial permit application. For this reason, 

EPA envisions an iterative process where the owner or operator and the Director will discuss the 

site data being collected and how it will inform all aspects of the project, including the plans 

under §146.82. EPA is developing guidances to assist the owner or operator in preparing the 

project plans and meeting the financial responsibility requirements for GS wells. The guidances 

can be found on EPA’s website at 

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

Letter ID: 0229 Comment ID: 21864 Letter Lines: 339 to 341 

Comment Code: 4750 2.7.5 Comments on the merit of annual reports (seeking comment) 

Comment: Page 115, Annual Report- Another annual report is mentioned. The overall 

reporting requirements are confusing. We would recommend monthly or quarterly 

operating reports and a single annual report. 

Individual Response: The final rule remains unchanged from the proposal and requires semiannual reporting of monthly average, maximum and minimum values for injection pressure, flow 

rate and volume, annular pressure, and monthly annulus fluid volume added at §146.91(a). EPA 

believes that monthly reporting of routine operational data and monitoring results would provide 

no additional protection of USDWs from endangerment. EPA adds, at §146.91(c), that it has 

included in the final rule a requirement that operators must report within 24 hours of any event 

that may endanger USDWs. EPA notes that states seeking primacy for Class VI wells are free to 

require more frequent reporting. 

Letter ID: 0229 Comment ID: 21865 Letter Lines: 343 to 347 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: Page 118, Post-injection Site Care Plan- The post injection site care plan would 

seem to require monitoring of pressures, plume extent, and other items after 

injection stops. However, this would prevent plugging and abandoning wells. It 

is recommended that the post-injection site care requirements allow for the 

plugging and abandoning of wells that are not being used for monitoring. 

Individual Response: EPA acknowledges that owners or operators may wish to use injection 

wells for monitoring purposes to meet the post-injection monitoring requirements. Nothing in the 

GS rule precludes this. EPA clarifies that Class VI injection wells must be plugged in a manner 

that protects USDWs from endangerment, as specified in 146.92(b). These requirements apply 

whether the well is plugged upon cessation of injection or at the time of site closure. 

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Letter ID: 0229 Comment ID: 21866 Letter Lines: 349 to 357 

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

Comment: Page 123- 50 year Post Injection Period- We strongly encourage EPA to not 

include a recommendation for 50 years of monitoring. We are concerned that most 

directors will choose to apply this as a default value, even for shorter 

duration projects or at low risk sites. Instead a site-specific post injection 

monitoring plan with clearly defined performance criteria such as pressure 

reduction, plume stabilization, lack of leakage, or stable parameter values over 

a period of time, should be used. This approach will give EPA the flexibility 

to design site-specific requirement but will also provide a level of certainty 

to the operators in terms of performance expectations. 

Individual Response: EPA agrees with commenters that there will be circumstances where it 

can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk 

of endangerment to USDWs. For this reason, 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 post-injection 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, during the permitting process based on substantial 

data, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of 

USDWs pursuant to requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This 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. 

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 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. The guidance describes 

recommended approaches for how an owner or operator could plug injection and monitoring 

wells; perform post-injection monitoring; demonstrate the appropriateness of an alternative postinjection site care time frame; demonstrate non endangerment; and perform site closure 

activities. Additionally, the guidance will assist Directors in evaluating proposed well plugging 

21
plans and post-injection site care and site closure plans under §146.92 and §146.93. This 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0229 Comment ID: 21867 Letter Lines: 359 to 368 

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space 

ownership 

Comment: Page 138, Primacy/Jurisdiction- Given the size and location of potential GS 

projects, many storage areas are likely to cross state lines. For example 

almost all of the major sources of CO2 emissions in the MRCSP region are at or 

near state boundaries, along Ohio River. For example, a geologic storage 

facility located near Wheeling West Virginia could have a CO2 plume and 

injection well locations in Ohio, West Virginia, and Pennsylvania. It is 

unclear how these projects would be implemented regarding who has primacy in 

permitting the site under a single permit, rather than three separate permits. 

Additional guidance permitting sites with multiple jurisdictions is highly 

desirable to prevent confusion or legal challenges. 

Individual Response: EPA acknowledges that CO2 plumes may cross jurisdictional boundaries 

and encourages cooperation and coordination among permitting authorities. The final Class VI 

GS rule, at §146.82(a)(2), requires the owner or operator to identify all State, Tribal, and 

Territorial boundaries within the AoR. Based on this information, the Director must provide 

written notification to all States, Tribes, and Territories to inform them of the permit application 

and ensure that they are involved in any necessary processes; this new requirement was added to 

the final rule at §146.82(b). The Agency encourages transparency in the permitting process and 

anticipates that State-State/State-Tribal communication on Class VI permitting will facilitate 

information sharing and encourage safe, protective projects. 

Letter ID: 0229 Comment ID: 21868 Letter Lines: 370 to 377 

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

Comment: Page 193, AOR Map- It will be difficult to provide the numerous site features on 

a single map as required in the regulation. Multiple maps should be allowed. 

Otherwise, the map must show the number, or name and location of all injection 

wells, producing wells, abandoned wells, plugged wells or dry holes, deep 

stratigraphic boreholes, State or EPA approved subsurface cleanup sites, surface 

bodies of water, springs, mines (surface and subsurface), quarries, water wells 

and other pertinent surface features including structures intended for human 

occupancy and roads, and faults. 

Individual Response: EPA acknowledges the comments and agrees that multiple maps may be 

necessary to present all of the data needed to support a determination of the suitability of a site 

for GS. Nothing in the GS rule prohibits this. 

22
Letter ID: 0229 Comment ID: 21869 Letter Lines: 379 to 384 

Comment Code: 6100 3.1 Comments on the cost estimates 

Comment: Cost Estimates- In general most of the estimates for hours, hourly rates, and 

costs required for implementing the requirements appear to be too low compared 

to our experience and the complexity of proposed regulatory requirements. It is 

recommended that EPA obtain more realistic cost estimates for all aspects of the 

regulations, deep well drilling, monitoring, expert delivery of geosciences and 

engineering professionals. 

Individual Response: The Agency increased some unit costs (e.g., for labor rates, seismic 

analysis, pipeline, etc.) for the final rule, as described in the cost analysis, to address commenter 

concerns that they were underestimated. All unit costs were reviewed and updated commensurate 

with inflation, as explained in the Geologic CO2 Sequestration Technology and Cost Analysis 

document, which is in the rulemaking docket. In addition, EPA incorporated a site selection 

factor into the final cost analysis based on the assumption that site selection will be successful 

between 25 and 100 percent of the time, depending on project type; this factor increased costs for 

geologic site characterization. 

For additional information on the final costing approach, please see the final cost analysis and 

technology and cost document in the final rule docket. 

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