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.
Colorado Ground Water Association

Comments on Federal Requirements Under the 

Underground Injection Control Program for Carbon Dioxide 

Geologic Sequestration Wells

Proposed Rule – 73 FR 43492,

Published in Federal Register: July 25, 2008
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

2

Colorado Ground Water Association

Comments on Federal Requirements Under the Underground 

Injection Control Program for Carbon Dioxide Geologic Sequestration 

Wells

Proposed Rule – 73 FR 43492, July 25, 2008

The Colorado Ground Water Association (CGWA) is a nonprofit professional 

society and trade association for the ground water industry in Colorado. Our 

members include public and private sector ground water scientists, engineers, 

water well contractors, manufacturers and suppliers of ground water related 

products and services. The CGWA’s vision is to be the leading community of 

ground water professionals in the State of Colorado and to promote the 

responsible development, use and management of ground water resources. 

While a promising technology for mitigation of CO2 emissions, geologic storage 

(GS) of CO2 also has the potential to impact underground Sources drinking 

waters (USDWs). Even though deep injection of CO2 has been used for over 20 

years to enhance oil and gas recovery and provides a foundation for large-scale 

use of geologic storage (GS), nothing on the scale of the proposed projects has 

been implemented. Full-scale projects have the potential to impact an area 

within a 50-mile radius of the injection well site.

Much of Colorado receives approximately 15 to 20 inches of precipitation yearly, 

water resources are currently stressed, and significant population increases are 

expected in the coming decades. Large portions of Colorado’s population rely on 

USDWs and a significant portion of Colorado’s agricultural economy relies on the 

freshwater aquifers for crop irrigation. The CGWA has concerns about the 

proposed CO2 GS rule, which will govern not only the injection wells needed for 

GS but also the siting, operation, monitoring, closure of GS projects and could 

also govern the post-closure liability of GS project operators. These projects will 

be implemented on a scale for which there is no analog and will have the 

potential to impair major water resources in the State of Colorado and elsewhere

if the projects are mismanaged.

In response to the U.S. EPA proposed rule on GS (72FR43492), CGWA submits 

the following comments on thirteen issues relevant to GS: 

Issue 1. The proposed regulation has no mechanism for the respective State 

authority in each state responsible for administration of water resources to 

remove certain groundwater basins and/or zones with important aquifers from

consideration as sequestration repositories. 
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

3

One of the CGWA’s concerns is the siting of CO2 sequestration projects in major 

sedimentary rock aquifers, near, or in strata underlying major sedimentary rock 

aquifers such as those which are the primary source of drinking or irrigation 

water for large segments of the population or agricultural community. Due to 

uncertainties in the effectiveness of GS at the project-scales being considered, 

siting of GS reservoirs in strata underlying “sole-source” or other “important” 

USDWs, should be avoided, at least until large scale experience validates this 

methodology. Examples of such aquifers include the Denver Basin Aquifers and 

the aquifers of the San Luis Valley. Additional examples of aquifers which may 

be subject to degradation by displaced brines include the alluvial aquifers of the 

South Platte and Arkansas River Valley where they are in contact with the 

subcrops of strata which could be used as GS reservoirs. Colorado’s reliance in 

many locations on deep bedrock aquifers should remove potential GS reservoirs 

from consideration due to the potential for degradation either by migration of CO2 

or displacement of CO2 reservoir brines into fresh water aquifers. 

Issue 2. Under the proposed rule, full-scale implementation can begin after 

finalization.

The EPA is encouraged to consider limiting the scale of projects initially in order 

to identify issues that may crop up that are currently unanticipated. The early 

large scale projects should be extensively monitored in order to validate concepts 

that can be applied to other locations. This early work should include validation of 

appropriate modeling techniques capable of reliably predicting system 

responses. This early proof of concept work should also address issues of 

heterogeneity in reservoir and confining zones.

Issue 3. The proposed regulation currently defines USDWs as zones that 

contain groundwater with a total dissolved solids (TDS) concentration of less 

than 10,000 mg/L. This limit should be revised to consider geologic strata with 

water containing higher TDS concentrations, because these zones may be 

economic in the future.

The technology for treating high TDS water for use in water supply is improving 

rapidly, and these high TDS aquifer zones may be needed in the future. In areas 

with limited water resources water providers are beginning to turn to groundwater 

sources containing in excess of 10,000 mg/L TDS (Sengebush 2008). It is 

already conceivable that in the near future sources with up to approximately 

20,000 mg/L TDS will be considered viable as water treatment technology 

advances making such water sources economical. To protect groundwater 

resources which may be economical in the foreseeable future the rule should 

evaluate the potential that currently marginal groundwater sources will be 

usable. The repository zones should be limited to strata containing very high 

TDS concentrations that siting studies and public input indicate are not likely to 

be useable in the future, as use of a zone for CO2 sequestration will likely 

preclude recovery and use of the groundwater resource in the future.
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

4

Issue 4. The proposed regulation is ambiguous on the issue of tectonic stress 

release (earthquakes).

The proposed regulation should specifically address the issue of triggering 

tectonic stress releases, to avoid problems, such as the generation of 

earthquakes that resulted from deep waste injection at the Rocky Mountain 

arsenal in the 1960s and in other locations such as the Paradox Valley, Colorado 

(Ake, et al, 2005). From 1962 through 1966 the Rocky Mountain Arsenal injected 

a volume of approximately 165 million gallons of waste, or roughly 35 million 

gallons annually. This volume would be dwarfed by the injection volumes 

proposed on the three billion gallons of supercritical CO2 annually. While the 

proposed rule states that the potential for induced seismicity is low, the 

magnitude of the volumes proposed for injection indicate that this issue has the 

potential to present a significant risk to occupants within a GS project Area of 

Review AoR.

Issue 5. The regulations should specifically address the potential for migration of 

injected CO2 in different types of groundwater reservoirs.

The proposed rule lacks specificity with respect to the manner in which a 

proposed operation will demonstrate that there is a suitable geologic trap for the 

injected CO2 and that the integrity of that trap will be perpetual. Demonstrating a 

pre-existing geologic structure capable of trapping CO2 and demonstrating that 

the complex geochemical reactions in and adjacent to the GS reservoir will not 

compromise the reservoir’s integrity are critical. However, the rule simply 

presumes such a demonstration can be made and provides no methods or 

criteria to be met in developing the demonstration.

Supercritical CO2 is essentially a light non-aqueous phase liquid (LNAPL)

capable of dissolving into water and also into which water can dissolve. A 

porous medium, such as the strata comprising a GS reservoir, is about eight 

times as permeable to supercritical CO2 as to water due to the low viscosity of 

the supercritical CO2. The supercritical CO2 will rise through a water-bearing 

reservoir as a buoyant fluid, independent of injection pressure gradients. When 

the supercritical CO2 reaches an impermeable stratum, that buoyancy will cause 

it to continue to move updip along that stratum until it encounters a stratigraphic 

or structural trap or permeability change sufficient to preclude further migration, 

i.e., a trap. The CO2 will continue to migrate into that trap, displacing the native 

water. If the injected volume is greater than the trap’s available volume the 

excess CO2 will “spill” from the trap and continue to migrate laterally and 

vertically along the upper confining stratum until it either finds another trapping 

configuration or reaches temperature and pressure where it reverts from 

supercritical to gaseous CO2.
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

5

Finding trapping structures in the subsurface is a non-trivial exercise. Every dry 

oil or gas exploration hole was drilled because a geologic investigation appeared 

to establish presence of a trap for buoyant hydrocarbons. While some dry holes 

may result from a missing source of petroleum, overwhelmingly the cause is that 

the postulated trap did not exist, either because the trapping structure was

absent or due to natural leaks through the confining units through which the oil or 

gas escaped. These technical problems associated with finding petroleum 

LNAPL traps are directly analogous to finding traps capable of holding CO2 in 

perpetuity. There are, however, major issues for CO2 sequestration not borne by 

hydrocarbon exploration. 

One issue is geologic trap integrity. Drilling can verify the postulated trapping 

geometry for either activity. If the confirmed configuration does not contain 

petroleum, the configuration is likely to be leaky. There is no corresponding way 

to establish the integrity of the seals in the case of exploration for CO2 traps. 

Another issue relating to GS reservoir siting evaluation is economics inherent in 

the process. There is significant financial incentive to find the petroleum-bearing 

trap, and that incentive can bear the burden of multiple failures. For the operator 

of a large point-source of CO2, sequestration of CO2 is a cost to be minimized as 

it does not result in a profit opportunity. Without detailed, explicit rules 

establishing how to prove a trap before attempting GS, the existence of 

functional traps will be simply presumed until lack of their existence or integrity is 

proven by failure.

The problem of finding and proving a sequestration trap for CO2 can be 

minimized by requiring sequestration in depleted petroleum traps, however there 

may not be enough depleted oilfields to contain a significant amount of CO2 and 

the presence of unsuitably constructed or abandoned wells can compromise 

integrity of a GS reservoir. 

Issue 6. Buffer Zone monitoring wells need to be addressed in the regulation. 

The regulations do not specifically identify the need for monitoring to verify 

performance of the repository. Monitoring wells to detect potential migration from 

the repository need to be incorporated into the proposed rule. Early 

implementation of GS should incorporate the concept of multiple barrier zones. 

This allows implementation of monitoring in zones below a USDW that can serve 

as a guard zone. These are critical in a zone between the repository and USDWs 

to allow for the early detection of a problem while mitigation is still an option. 

Even highly effective monitoring of GS reservoirs for failure may only inform 

operators after “the horse has left the barn.” In addition to buffer-zone 

monitoring, pressures in confining units should be monitored to provide allow 

detection of failure of the GS reservoir.

Issue 7. The fate of displaced brines is not sufficiently addressed.
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

6

The regulations need to be more specific on assessing the fate of displaced 

brines in the repository. Large volumes of CO2 will increase reservoir pressures 

and will displace brines laterally and potentially vertically. Based on 2005 CO2

production rates for Colorado power plants (CCS, 2007) and adding 30% 

additional carbon resulting from the parasitic load, power plants in Colorado can 

be expected to produce an average of 5.5 million metric tons annually. This 

production rate results in a year-round injection rate of approximately 5,500 

gallons per minute of supercritical CO2 for a medium-sized power plant. 

Assuming a reservoir thickness of 300 feet with 10% porosity available to the 

supercritical CO2, this quantity would result in displacement of the brine from 

approximately 0.5 square miles of reservoir annually, or from approximately 25 

square miles over an assumed 50-year project lifetime. A large power plant, 

such as the Craig plant, would displace brine completely from approximately 65 

square miles of such a hypothetical reservoir. Additionally, the volume 

calculations presented here assume the supercritical CO2 will occupy the entire 

thickness of the reservoir, while in reality, the supercritical CO2 can be expected 

to float to the top of the reservoir and spread laterally, migrating approximately 8 

times the velocity of groundwater flow. In the event CO2 were to migrate into 

portions of the reservoir where pressure is insufficient to maintain the 

supercritical state, substantial volume increases could occur which could drive 

brines into shallow portions of the reservoir strata used for drinking water 

sources. The applicants will need to address the fate of these displaced brines.

Issue 8. The risks associated with the presence of old wells in depleted oil and 

gas fields are not adequately addressed in the proposed regulation. 

The use of depleted petroleum reservoirs poses a significant problem. Depleted 

petroleum traps are generally the oldest oilfields and there are the problems of 

record keeping and are likely subject to outdated and inappropriate technologies 

during their development and the subsequent abandonment of the wells. Oil 

fields initially are characterized by pressures that are higher than depthequivalent water bearing zones. However, as the fields are developed, those 

excess pressures are relieved, and the field becomes hydrostatically pressured 

or even underpressured. The result is that as the field ages and the reservoir 

becomes under pressured, well construction and abandonment integrity become 

less and less critical

Undertaking CO2 sequestration in a depleted oil or natural gas field reverses the

process of depressurization in the reservoir. Pumping CO2 (or any fluid) 

increases the pressure of the reservoir substantially and every old production 

and exploration bore hole becomes a potential route of failure. Well and 

borehole abandonment configurations, even if fully compliant with requirements 

in place at the time of the abandonment, may not be capable of containing the 

pressures of the GS reservoir. Even if the reservoir is allowed to fill passively to 

the spill point, there will be excess pressure relative to formation hydrostatic 
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

7

pressures at the confining layer. The magnitude of the excess pressure will be 

directly proportional to the density contrast with the formation brine and the 

thickness of the CO2 lens. Wells appropriately sealed against hydrostatic 

pressures present in the depleted oil field may fail catastrophically when 

subjected to pressures that result from CO2 storage in the trap. Here too, the 

rule needs to add specificity to what needs be performed in the way of finding 

and recompleting the abandonment of all pre-existing wells and boreholes to 

configurations consistent with the reservoir conditions expected after CO2

sequestration, not the conditions that exist at the time the field was abandoned or 

the project is initiated. There is no discussion in the USEPA materials supporting 

this rule that acknowledges or discusses the implications of the equivalent of an 

oil-field blow out. The catastrophic failure of a plugged or abandoned well would 

create an open conduit for the expulsion of supercritical CO2 to the ground 

surface, potentially miles from any injection infrastructure.

Issue 9. Use of models to assess area of review is only briefly discussed in the 

proposed regulation. 

The regulation specifies the use of mathematical models to assess the AoR and 

potential impacts. Prior to beginning modeling to evaluate the suitability of a 

potential reservoir, applicants should be required to collect sufficient field data 

from the reservoir and over-and underlying formations to evaluate the effects of 

the project on not only the area of review but also nearby locations where 

groundwater resources are present, even if not used widely. In modeling of 

proposed GS projects, multi-phase geologic models should be used coupled with 

solute transport modeling to evaluate the anticipated impacts. Additionally, 

models which can evaluate the geomechanical stresses upon the geologic 

materials within the AoR should be used to determine the potential for induced 

seismicity. Prior to modeling, site characterization should be performed with an 

adequate number test boreholes and wells to allow a statistically-valid 

characterization of issues within the AoR. In addition, the models should 

simulate the entire project lifespan and a substantial amount of time in the postclosure phase to provide insight into, support mitigation of, potential failure 

mechanisms.

Issues to be evaluated in reservoir modeling should include but not be limited to:

· Rock mechanics and susceptibility to fracture/failure, 

· Water quality within the AoR including strata above and lateral to the 

proposed GS reservoir, 

· Reservoir and aquifer properties, 

· Potential for CO2 migration into overlying strata via faults and improperly 

sealed boreholes,

· Potential water quality impacts on USDWs due to the pressure field 

developed under project scale injection,
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

8

· Mechanical and hydraulic properties of low-permeability units anticipated 

to serve as barriers to migration of the CO2 and, 

· The effects of fluids that will be displaced from zones between the GS 

reservoir and USDWs. 

Ongoing collection of verification data for these models is important and should 

be performed on an interval that will be sufficient to allow identification and 

mitigation of potential failure mechanisms. Use of any model must be combined 

with calibration, where field observations should be replicated in the model. Any 

models that are used must be fully documented, with assumptions and 

methodology provided. A 5-year review interval is suggested over the course of 

the project life. Models alone, without sufficient field data collected prior to and 

during operation, are not protective of the public safety or resources. 

Issue 10. Well construction and well conversion issues are not adequately 

addressed in the proposed regulation. The conversion of wells from enhanced 

oil recovery (EOR) or hazardous waste injection to CO2 injection is vague.

Well construction and potential well conversion issues need to be addressed in 

the regulations. All materials with the potential to come into contact with the 

injectate and/or the formation fluids should be designed and tested to insure the 

materials’ integrity will be maintained and they will prevent movement of the 

injectate into a potential USDW zone. Materials that will not come into contact 

with the injectate and/or formation fluids in the zone of injection are not as critical, 

but sufficient design review should be performed to insure that proper materials 

are used for all well construction. All wells used for injection and monitoring 

should be operated according to a periodic maintenance schedule similar to 

other wells in the UIC program.

Conversion of existing oil and gas wells and/or EOR wells to CO2 injection wells 

should be evaluated on a detailed case-by-case basis. Review should include all 

well construction records, performance of well evaluation and mechanical 

integrity testing and cement bond logging, and in the event the well is retained, 

workover should be performed.

While detailed geologic modeling is planned, monitoring wells should be installed 

into the injection zone, and into buffer zones above the injection zone, including 

fluid bearing zones below any potential USDW zone. In addition, pressure 

sensors should be installed in the confining units above the GS reservoir. The 

data collected from the monitoring wells and pressure monitoring points can be 

used to confirm the accuracy of a model and to monitor the zone above the 

injection zone for CO2 leakage. Monitoring wells should be installed into the 

buffer zone to provide early detection in the event CO2 or the associated 

pressure front begins to migrate into zones above the proposed injection zone. 

All monitoring wells should be designed to similar standards as injection well and 

will need pressure shut-in equipment. 
Colorado Ground Water Association Comments

USEPA UIC Program Proposed Rule – 73 FR 43492

Carbon Dioxide Geologic Sequestration December 22, 2008

9

Clustered monitoring wells should be considered to allow a single borehole to be 

used to monitor several different vertically discrete zones. For example, there is 

a potential that the injection zone, one or more buffer zones, and the USDW 

zone could be monitored from clustered monitoring wells installed into a single 

borehole. In the event such technology is used, equipment should be installed, 

maintained, and tested on a designated frequency to prevent migration of fluids 

between zones.

Issue 11. The post-closure operator liability timeframe of 50 years should be 

considered a minimum and should be extended in the event monitoring and 

modeling data indicate potential failure may require mitigation.

Issue 12. The timeframe of Area of Review Reevaluation should be revised to 

require more frequent reevaluation during the beginning of a project 

implementation and then less frequent reevaluation as the GS reservoir is shown 

to maintain integrity. 

The AoR should schedule be reevaluated annually during the first five years, 

biannually during the five to 10-year period and then on a 5-year schedule 

afterwards until closure. Following closure, reevaluation should be performed on 

a 10-year frequency until the operator is released from liability.

Issue 13. The proposed rule should consider and discuss mitigation options for 

large-scale failure of a mature GS reservoir.

References:

Ake, Jon, Kenneth Mahrer, Daniel O’Connell and Lisa Block, 2005. DeepInjection and Closely Monitored Induced Seismicity at Paradox Valley, Colorado, 

Bulletin of the Seismological Society of America; April 2005; v. 95; no. 2; p. 664-

683;

CCS 2007. October 2007. Final Colorado Greenhouse Gas Inventory and 

Reference Case Projections 1990-2020. Center for Climate Strategies. 

Available from: 

http://www.coloradoclimate.org/ewebeditpro/items/O14F13894.pdf

Sengebush, R. M. 2008, INTERA, Inc. Deep Brackish Water Considered for 

New Mexico Development. Southwest Hydrology, March/April 2008, p. 8. 

Available from http://www.swhydro.arizona.edu/archive/V7_N2/deptontheground.pdf.
Letter ID: 0196 

Commenter: Andy Horn 

Organization: Colorado Ground Water Association (CGWA) 

Letter ID: 0196 Comment ID: 23920 Letter Lines: 32 to 50 

Comment Code: 1610 1.3.1 Risks to USDWs 

Comment: While a promising technology for mitigation of CO2 emissions, geologic storage 

(GS) of CO2 also has the potential to impact underground Sources drinking waters 

(USDWs). Even though deep injection of CO2 has been used for over 20 years to 

enhance oil and gas recovery and provides a foundation for large-scale use of 

geologic storage (GS), nothing on the scale of the proposed projects has been 

implemented. Full-scale projects have the potential to impact an area within a 

50-mile radius of the injection well site. 

Much of Colorado receives approximately 15 to 20 inches of precipitation yearly, 

water resources are currently stressed, and significant population increases are 

expected in the coming decades. Large portions of Colorado’s population rely on 

USDWs and a significant portion of Colorado’s agricultural economy relies on the 

freshwater aquifers for crop irrigation. The CGWA has concerns about the 

proposed CO2 GS rule, which will govern not only the injection wells needed for 

GS but also the siting, operation, monitoring, closure of GS projects and could 

also govern the post-closure liability of GS project operators. These projects 

will be implemented on a scale for which there is no analog and will have the 

potential to impair major water resources in the State of Colorado and elsewhere 

if the projects are mismanaged. 

Individual Response: The Agency agrees that drinking water is an important resource that 

needs to be protected. The primary goal of the UIC Program under the SDWA is to protect 

USDWs from endangerment. Consistent with SDWA §1422 the UIC program provides that no 

injection shall be authorized if it results in the movement of fluid containing any contaminant 

into USDWs, if the presence of that contaminant may cause a violation of any primary drinking 

water regulation or may adversely affect the health of persons as specified in §144.12. 

The GS regulation builds upon the long-standing protective framework of the UIC Program, 

which has been regulating the injection of billions of gallons of fluids for decades. The GS 

regulation enhances this framework with requirements that are tailored to address the unique 

issues associated with GS, including large injection volumes, the relative buoyancy of CO2, its 

corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its 

mobility within subsurface geologic formations. These additional protective requirements 

include more extensive geologic testing for site characterization, detailed computational 

modeling of the AoR and periodic re-evaluations, detailed requirements for monitoring and 

tracking the CO2 plume and pressure front, and extended post-injection monitoring and site care. 

EPA expects the tailored permitting, siting, construction, operation, monitoring, and post1
injection site care requirements in the GS rule will prevent leakage from injection formations and 

protect USDWs. 

Letter ID: 0196 Comment ID: 23921 Letter Lines: 55 to 74 

Comment Code: 1610 1.3.1 Risks to USDWs 

Comment Code: 2100 1.6 Target Geologic Formations for GS 

Comment: Issue 1. The proposed regulation has no mechanism for the respective State 

authority in each state responsible for administration of water resources to 

remove certain groundwater basins and/or zones with important aquifers from 

consideration as sequestration repositories. 

One of the CGWA’s concerns is the siting of CO2 sequestration projects in major 

sedimentary rock aquifers, near, or in strata underlying major sedimentary rock 

aquifers such as those which are the primary source of drinking or irrigation 

water for large segments of the population or agricultural community. Due to 

uncertainties in the effectiveness of GS at the project-scales being considered, 

siting of GS reservoirs in strata underlying "sole-source" or other "important" 

USDWs, should be avoided, at least until large scale experience validates this 

methodology. Examples of such aquifers include the Denver Basin Aquifers and 

the aquifers of the San Luis Valley. Additional examples of aquifers which may 

be subject to degradation by displaced brines include the alluvial aquifers of 

the South Platte and Arkansas River Valley where they are in contact with the 

subcrops of strata which could be used as GS reservoirs. Colorado’s reliance in 

many locations on deep bedrock aquifers should remove potential GS reservoirs 

from consideration due to the potential for degradation either by migration of 

CO2 or displacement of CO2 reservoir brines into fresh water aquifers. 

Individual Response: The Agency agrees that drinking water is an important resource that 

needs to be protected. The primary goal of the UIC Program under the SDWA is to protect 

USDWs from endangerment. Consistent with SDWA §1422 the UIC program provides that no 

injection shall be authorized if it results in the movement of fluid containing any contaminant 

into USDWs, if the presence of that contaminant may cause a violation of any primary drinking 

water regulation or may adversely affect the health of persons as specified in §144.12. 

The GS rule, at §146.82(a)(5), requires prospective owners or operators to submit information on 

all USDWs within the AoR. EPA expects that this information will include identification of any 

sole source aquifers. The GS rule also requires operators to submit extensive information about 

the site, including the geologic characteristics of the injection and confining zones, to 

demonstrate that the injected CO2 will remain within the target formation. The Director must 

consider this information when determining whether GS is acceptable at a given site. EPA 

expects that during this evaluation the Director will consider the potential impact of the GS 

project on any sole source aquifers. Additionally, EPA has added a requirement at 40 CFR 

124.10(c)(1)(xi) that requires state and local oil and gas regulatory agencies and state agencies 

regulating mineral exploration and recovery, the PWSS program director, and all agencies that 

2
oversee injection wells in the state be notified as part of the public notice process for a Class VI 

permit. 

EPA anticipates that state permitting authorities are in the best position to make determinations 

about the appropriateness of a particular site based on all available information, including 

drinking water supply needs. EPA clarifies that a state’s Class VI primacy program may be more 

stringent then the federal requirements. For example, a state has the discretion to ban GS projects 

from taking place in formations or areas that affect sole source aquifers. 

EPA agrees that, in many cases, UIC Directors will have extensive knowledge of which areas are 

suitable for GS, but clarifies that it is the responsibility of Class VI permit applicants to 

demonstrate the suitability of a particular site or formation. It is the responsibility of the Director 

to evaluate the information collected and submitted by the owner or operator to determine 

whether a permit for GS at the site is appropriate. 

Letter ID: 0196 Comment ID: 23922 Letter Lines: 76 to 85 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment Code: 1260 1.1.1.5 More certainty/stringency is needed 

Comment: Issue 2. Under the proposed rule, full-scale implementation can begin after 

finalization. 

The EPA is encouraged to consider limiting the scale of projects initially in 

order to identify issues that may crop up that are currently unanticipated. The 

early large scale projects should be extensively monitored in order to validate 

concepts that can be applied to other locations. This early work should include 

validation of appropriate modeling techniques capable of reliably predicting 

system responses. This early proof of concept work should also address issues of 

heterogeneity in reservoir and confining zones. 

Individual Response: EPA clarifies that the intent of the GS rule is not to set or control the pace 

at which GS is deployed. Rather, the purpose of the GS regulation is to ensure that GS, where 

deployed, is conducted in a manner that protects USDWs from endangerment. The Class VI GS 

requirements are one way in which the Agency can achieve this goal. EPA does not intend to 

limit the scale of initial GS projects; each project will be evaluated based on site-specific 

information about the ability of the geologic formations to safely receive and confine injected 

CO2. However, the Agency agrees that a protective initial approach is appropriate and additional 

safeguards are necessary, given the uncertainty associated with the long-term effects of CO2 GS. 

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. 

Letter ID: 0196 Comment ID: 23923 Letter Lines: 87 to 105 ; 373 to 375 

3
Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 1610 1.3.1 Risks to USDWs 

Comment Code: 4400 2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

Comment: Issue 3. The proposed regulation currently defines USDWs as zones that contain 

groundwater with a total dissolved solids (TDS) concentration of less than 

10,000 mg/L. This limit should be revised to consider geologic strata with water 

containing higher TDS concentrations, because these zones may be economic in the 

future. 

The technology for treating high TDS water for use in water supply is improving 

rapidly, and these high TDS aquifer zones may be needed in the future. In areas 

with limited water resources water providers are beginning to turn to 

groundwater sources containing in excess of 10,000 mg/L TDS (Sengebush 2008). 

It is already conceivable that in the near future sources with up to 

approximately 20,000 mg/L TDS will be considered viable as water treatment 

technology advances making such water sources economical. To protect 

groundwater resources which may be economical in the foreseeable future the rule 

should evaluate the potential that currently marginal groundwater sources will 

be usable. The repository zones should be limited to strata containing very high 

TDS concentrations that siting studies and public input indicate are not likely 

to be useable in the future, as use of a zone for CO2 sequestration will likely 

preclude recovery and use of the groundwater resource in the future. 

Sengebush, R. M. 2008, INTERA, Inc. Deep Brackish Water Considered for New 

Mexico Development. Southwest Hydrology, March/April 2008, p. 8. Available from 

http://www.swhydro.arizona.edu/archive/V7_N2/dept-ontheground.pdf. 

Individual Response: The Agency acknowledges the commenter’s concerns about water 

resources and future water resource availability. However, modifying the definition of a USDW 

is outside the scope of the GS rulemaking. USDWs are defined as aquifers currently being used 

as sources of drinking water or those capable of supplying a public water system, with a total 

dissolved solids (TDS) content of 10,000 milligrams per liter or less, as specified in §144.3. 

The primary goal of the UIC Program under the SDWA is to protect USDWs from 

endangerment in order to ensure a reliable supply of drinking water for the American public. The 

GS rule, as part of the UIC program regulations implementing the SDWA, continues the 

program’s mandate of ensuring the protection of USDWs. EPA expects that the tailored 

permitting, siting, construction, operation, monitoring, and post-injection site care requirements 

in the GS rule will prevent leakage from injection formations and protect USDWs. 

EPA recognizes that there is increasing demand for water resources and that technology 

improvements may make high TDS aquifers viable drinking water sources. EPA believes these 

potential resources should be considered when injection depth waivers are sought. Therefore, the 

final GS rule at §146.95(b) requires the Director to consider these issues in determining whether 

4
an injection depth waiver is appropriate. Specifically, the Director must consider whether 

alternative injection sites are available; community needs, demands, and supply from drinking 

water resources; planned needs, potential and/or future use of USDWs and non-USDWs in the 

area; and a plan for securing alternative resources or treating USDW formation waters in the 

event of contamination related to the Class VI injection activity. For additional information on 

the waiver approach, please see the final rule and preamble, as well as EPA's responses to 

comments on the Notice of Data Availability and Request for Comment. 

Letter ID: 0196 Comment ID: 23924 Letter Lines: 107 to 121 ; 365 to 367 

Comment Code: 1620 1.3.2 Induced seismicity 

Comment: Issue 4. The proposed regulation is ambiguous on the issue of tectonic stress 

release (earthquakes). 

The proposed regulation should specifically address the issue of triggering 

tectonic stress releases, to avoid problems, such as the generation of 

earthquakes that resulted from deep waste injection at the Rocky Mountain 

arsenal in the 1960s and in other locations such as the Paradox Valley, Colorado 

(Ake, et al, 2005). From 1962 through 1966 the Rocky Mountain Arsenal injected 

a volume of approximately 165 million gallons of waste, or roughly 35 million 

gallons annually. This volume would be dwarfed by the injection volumes 

proposed on the three billion gallons of supercritical CO2 annually. While the 

proposed rule states that the potential for induced seismicity is low, the 

magnitude of the volumes proposed for injection indicate that this issue has the 

potential to present a significant risk to occupants within a GS project Area of 

Review AoR. 

Ake, Jon, Kenneth Mahrer, Daniel O’Connell and Lisa Block, 2005. Deep-Injection 

and Closely Monitored Induced Seismicity at Paradox Valley, Colorado, Bulletin 

of the Seismological Society of America; April 2005; v. 95; no. 2; p. 664-683; 

Individual Response: EPA acknowledges that induced seismicity is a risk that may be 

associated with GS but maintains that the risk is low (IPCC, 2005). The GS rule contains several 

requirements to address seismic risk. First, as part of the site characterization process, owners or 

operators must submit information about the seismic history of and seismic sources near a 

proposed GS site, data on known or suspected faults in the AoR, geomechanical information on 

fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone as 

specified in §146.82(a)(3). This information is evaluated by the Director, who determines the 

suitability of a potential project site for GS. Any sites with the potential for reopening or 

reactivation of faults or unacceptable seismic risk that could otherwise interfere with 

containment will not be permitted as GS sites. During injection, the pressure in the injection zone 

must not exceed 90 percent of the fracture pressure of the injection zone as specified in 

§146.88(a); this requirement is intended to prevent the opening of fractures or faults through 

over pressurization of the injection zone. 

5
EPA adds that the seismic episodes at the Rocky Mountain Arsenal, which occurred in the 

1960s—before the original UIC regulations were developed—were due to poor site 

characterization and well operation, including high, unmonitored injection pressures (73 FR 

43498). While EPA acknowledges that the volumes of CO2 injected at GS sites will likely be 

larger than the volumes of waste water injected at the Rocky Mountain Arsenal, injection volume 

is not the sole factor that determines induced seismicity. Induced seismicity also depends on 

other geologic variables such as pre-existing faults, porosity, and permeability (Sminchak & 

Gupta, 2003). With proper site characterization (i.e., pursuant to §146.82), these variables can 

often be quantified prior to injection (Sminchak and Gupta, 2003) and used to identify sites 

capable of safely sustaining prolonged injection of large volumes with low risk. As long as a site 

is well-characterized and monitored, and the injection volume and rate remain within permitted 

limits set forth by the Director, the injection of large volumes of fluid should not increase the risk 

of seismic activity. 

EPA does not believe that limiting GS to "stable areas" will provide certainty that seismic events 

will not occur. The Agency acknowledges that some regions of the country are at risk for 

infrequent, damage-causing seismic events even if such events have not been recorded in the 

recent historical record (i.e., in the past several hundred years). For this reason, EPA requires 

seismic risk to be evaluated on a site-specific basis, through an analysis of seismic history and an 

evaluation of known or suspected faults in the AoR, geomechanical information on fractures, 

stress, ductility, rock strength, and in situ fluid pressures within the confining zone as specified 

in §146.82(a)(3). In addition, if an adverse event, such as a well failure or evidence of fluid 

movement were to occur, the monitoring requirements at §146.90 and emergency and remedial 

response requirements as specified in §146.94 provide additional protection. 

Letter ID: 0196 Comment ID: 23925 Letter Lines: 123 to 181 

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

trapping mechanism) 

Comment: Issue 5. The regulations should specifically address the potential for migration 

of injected CO2 in different types of groundwater reservoirs. 

The proposed rule lacks specificity with respect to the manner in which a 

proposed operation will demonstrate that there is a suitable geologic trap for 

the injected CO2 and that the integrity of that trap will be perpetual. 

Demonstrating a pre-existing geologic structure capable of trapping CO2 and 

demonstrating that the complex geochemical reactions in and adjacent to the GS 

reservoir will not compromise the reservoir’s integrity are critical. However, 

the rule simply presumes such a demonstration can be made and provides no 

methods or criteria to be met in developing the demonstration. 

Supercritical CO2 is essentially a light non-aqueous phase liquid (LNAPL) 

capable of dissolving into water and also into which water can dissolve. A 

porous medium, such as the strata comprising a GS reservoir, is about eight 

times as permeable to supercritical CO2 as to water due to the low viscosity of 

6
the supercritical CO2. The supercritical CO2 will rise through a water-bearing 

reservoir as a buoyant fluid, independent of injection pressure gradients. When 

the supercritical CO2 reaches an impermeable stratum, that buoyancy will cause 

it to continue to move updip along that stratum until it encounters a 

stratigraphic or structural trap or permeability change sufficient to preclude 

further migration, i.e., a trap. The CO2 will continue to migrate into that 

trap, displacing the native water. If the injected volume is greater than the 

trap’s available volume the excess CO2 will "spill" from the trap and continue 

to migrate laterally and vertically along the upper confining stratum until it 

either finds another trapping configuration or reaches temperature and pressure 

where it reverts from supercritical to gaseous CO2. 

Finding trapping structures in the subsurface is a non-trivial exercise. Every 

dry oil or gas exploration hole was drilled because a geologic investigation 

appeared to establish presence of a trap for buoyant hydrocarbons. While some 

dry holes may result from a missing source of petroleum, overwhelmingly the 

cause is that the postulated trap did not exist, either because the trapping 

structure was absent or due to natural leaks through the confining units through 

which the oil or gas escaped. These technical problems associated with finding 

petroleum LNAPL traps are directly analogous to finding traps capable of holding 

CO2 in perpetuity. There are, however, major issues for CO2 sequestration not 

borne by hydrocarbon exploration. 

One issue is geologic trap integrity. Drilling can verify the postulated 

trapping geometry for either activity. If the confirmed configuration does not 

contain petroleum, the configuration is likely to be leaky. There is no 

corresponding way to establish the integrity of the seals in the case of 

exploration for CO2 traps. 

Another issue relating to GS reservoir siting evaluation is economics inherent 

in the process. There is significant financial incentive to find the petroleumbearing trap, and that incentive can bear the burden of multiple failures. For 

the operator of a large point-source of CO2, sequestration of CO2 is a cost to 

be minimized as it does not result in a profit opportunity. Without detailed, 

explicit rules establishing how to prove a trap before attempting GS, the 

existence of functional traps will be simply presumed until lack of their 

existence or integrity is proven by failure. 

The problem of finding and proving a sequestration trap for CO2 can be minimized 

by requiring sequestration in depleted petroleum traps, however there may not be 

enough depleted oilfields to contain a significant amount of CO2 and the 

presence of unsuitably constructed or abandoned wells can compromise integrity 

of a GS reservoir. 

Individual Response: EPA developed the GS regulations to address the potential for migration 

of injected CO2 into different types of groundwater reservoirs to prevent endangerment of 

7
USDWs. The rule requires the owner or operator to provide extensive information to 

demonstrate to the Director (§146.82) that the CO2 will be contained within the injection 

formation. Because of the site-specific nature of GS and the variety of geologic settings in which 

GS may be employed, the regulation does not provide a specific list of information to be 

provided. 

Owners or operators seeking a permit for GS wells must provide the appropriate information, 

regardless of whether there is a cost incentive for proper site characterization. If the information 

submitted is not adequate to support a determination that sufficient traps exist to contain the CO2 

and ensure USDW protection, the Director may request additional information (under 

§146.82(a)(21)), or ultimately decline to issue a permit. 

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

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

provides recommendations regarding characterizing the regional geology and hydrogeology of a 

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

geophysical analyses of the injection and confining zone. The guidance can be found on EPA’s 

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

Letter ID: 0196 Comment ID: 23926 Letter Lines: 183 to 195 

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

CFR 146.90) 

Comment: Issue 6. Buffer Zone monitoring wells need to be addressed in the regulation. 

The regulations do not specifically identify the need for monitoring to verify 

performance of the repository. Monitoring wells to detect potential migration 

from the repository need to be incorporated into the proposed rule. Early 

implementation of GS should incorporate the concept of multiple barrier zones. 

This allows implementation of monitoring in zones below a USDW that can serve as 

a guard zone. These are critical in a zone between the repository and USDWs to 

allow for the early detection of a problem while mitigation is still an option. 

Even highly effective monitoring of GS reservoirs for failure may only inform 

operators after "the horse has left the barn." In addition to buffer-zone 

monitoring, pressures in confining units should be monitored to provide allow 

detection of failure of the GS reservoir. 

Individual Response: EPA clarifies that the final rule requires monitoring to ensure that CO2 or 

injection zone formation fluids remain in the injection zone. EPA believes that the ground water 

geochemical monitoring above the confining zone required in §146.90(d) will maximize 

protection of USDWs from endangerment at GS sites. Direct geochemical sampling is an 

important part of a monitoring program. EPA adds that the baseline geochemical data required at 

§146.82(a)(6) will provide a basis for comparison. EPA is not requiring monitoring in the 

confining zone itself. However, monitoring in additional formations, e.g., the injection zone, may 

8
also be necessary, and if the Director believes such monitoring is warranted he/she has the 

authority to require that it be included in the testing and monitoring plan. 

EPA believes that geochemical monitoring above the confining zone should not be restricted to 

areas near the plume. Research, both EPA-funded and external, has shown that the zone of 

elevated pressure may be much larger than the plume (e.g., Birkholzer, et al. 2008). This area of 

elevated pressure may cause migration of native brines from the target formation into overlying 

formations. Careful placement of monitoring wells within the delineated AoR (which includes 

areas beyond the extent of the CO2 plume) would allow for detection of changes in water quality 

related to GS activities. EPA acknowledges that very thick confining zones would reduce the 

chance that CO2 or other fluids will move from the injection zone; however, to increase 

protectiveness, a multiple-barrier approach to protecting USDWs from endangerment that 

includes both proper site characterization and a detailed monitoring regime is warranted. 

EPA believes that geochemical monitoring in and above the confining zone complements 

pressure monitoring in the injection zone. EPA believes that pressure monitoring in the injection 

zone is necessary to track the development and movement of the pressure front and CO2 plume. 

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 required unless 

the Director determines, based on site-specific geology that such methods are not appropriate. 

EPA believes that pressure monitoring within the injection zone is necessary because any such 

monitoring above the confining zone would not detect movement of the pressure front unless a 

breach of the confining zone occurs. 

Letter ID: 0196 Comment ID: 23927 Letter Lines: 197 to 221 ; 369 to 371 

Comment Code: 1616 1.3.1.3 Fluid movement 

Comment: Issue 7. The fate of displaced brines is not sufficiently addressed. 

The regulations need to be more specific on assessing the fate of displaced 

brines in the repository. Large volumes of CO2 will increase reservoir pressures 

and will displace brines laterally and potentially vertically. Based on 2005 CO2 

production rates for Colorado power plants (CCS, 2007) and adding 30% additional 

carbon resulting from the parasitic load, power plants in Colorado can be 

expected to produce an average of 5.5 million metric tons annually. This 

production rate results in a year-round injection rate of approximately 5,500 

gallons per minute of supercritical CO2 for a medium-sized power plant. 

Assuming a reservoir thickness of 300 feet with 10% porosity available to the 

supercritical CO2, this quantity would result in displacement of the brine from 

approximately 0.5 square miles of reservoir annually, or from approximately 25 

square miles over an assumed 50-year project lifetime. A large power plant, 

such as the Craig plant, would displace brine completely from approximately 65 

9
square miles of such a hypothetical reservoir. Additionally, the volume 

calculations presented here assume the supercritical CO2 will occupy the entire 

thickness of the reservoir, while in reality, the supercritical CO2 can be 

expected to float to the top of the reservoir and spread laterally, migrating 

approximately 8 times the velocity of groundwater flow. In the event CO2 were to 

migrate into portions of the reservoir where pressure is insufficient to 

maintain the supercritical state, substantial volume increases could occur which 

could drive brines into shallow portions of the reservoir strata used for 

drinking water sources. The applicants will need to address the fate of these 

displaced brines. 

CCS 2007. October 2007. Final Colorado Greenhouse Gas Inventory and Reference 

Case Projections 1990-2020. Center for Climate Strategies. Available from: 

http://www.coloradoclimate.org/ewebeditpro/items/O14F13894.pdf 

Individual Response: EPA acknowledges that there are potential risks associated with GS 

including the potential that CO2 injection for GS could cause fluid movement, which can 

endanger USDWs. EPA has funded recent research by LBNL on brine displacement affecting 

USDWs. In the August 31, 2009, NODA and Request for Comment (74 FR 44802), EPA 

described a hypothetical, future scenario of GS in a sedimentary basin that demonstrated the 

potential for basin-scale hydrologic impacts of CO2 storage (Birkholzer, et al. 2008). In addition 

to EPA-funded research, a study by Nicot (2008) modeled the effect of CO2 injection on up-dip 

aquifers in the Texas Gulf Coast Basin. The study concluded that in the Gulf Coast Basin, water 

displacement due to down-dip injection of CO2 is not likely to cause significant changes in 

salinity. EPA expects that, as research on far-field impacts of GS continues, estimates of storage 

capacity in such systems will improve. 

As part of its adaptive rulemaking approach, EPA will continue to review available research on 

fluid movement. The Agency plans, every six years, to collect and review data on GS projects to 

determine whether the appropriate amount and types of information and appropriate 

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

appropriate or necessary. 

The purpose of the Class VI requirements is to minimize and mitigate potential/identified risks 

through proper site characterization, well construction, operation, monitoring, post-injection site 

care, and site closure. Suitable GS sites must have confining zones that are free of transmissive 

faults or fractures and are of sufficient areal extent and integrity to contain the injected CO2 

stream and displaced formation fluids. The formations must allow injection at proposed 

maximum pressures and volumes without initiating or propagating fractures in the confining 

zone(s), as required at §146.83(a)(2). 

The GS rule requires owners or operators to submit extensive data about a proposed GS site to 

identify (and eliminate) sites with a potential for unacceptable fluid movement. Information to be 

submitted and evaluated at §146.82 includes data on the porosity, permeability, and other 

information regarding the suitability of the confining zone; the location of any known or 

suspected faults; subsurface geochemistry; and the location of, depth of, and other information 

10
regarding any perforations that may extend into the confining zone. EPA expects that this 

information, in conjunction with AoR modeling required at §146.84, will help identify the 

potential for brine migration as a result of pressure displacement. Based on this information, the 

Director and the owner or operator can identify ways to mitigate this risk prior to injection, or, if 

necessary, the Director can deny the permit application. During injection operations, operators 

must extensively monitor ground water quality and pressure changes to provide early detection 

of any unacceptable movement of fluids or impurities in the subsurface as specified in §146.90. 

Operators must also develop and follow an emergency and remedial response plan to address any 

adverse effects associated with the GS operation as specified in §146.94 and maintain financial 

responsibility to address contamination as specified in §146.85. 

Letter ID: 0196 Comment ID: 23928 Letter Lines: 223 to 259 

Comment Code: 2146 1.6.2.2 Comments opposing injection into depleted reservoirs 

Comment: Issue 8. The risks associated with the presence of old wells in depleted oil 

and gas fields are not adequately addressed in the proposed regulation. 

The use of depleted petroleum reservoirs poses a significant problem. Depleted 

petroleum traps are generally the oldest oilfields and there are the problems of 

record keeping and are likely subject to outdated and inappropriate technologies 

during their development and the subsequent abandonment of the wells. Oil 

fields initially are characterized by pressures that are higher than depthequivalent water bearing zones. However, as the fields are developed, those 

excess pressures are relieved, and the field becomes hydrostatically pressured 

or even underpressured. The result is that as the field ages and the reservoir 

becomes under pressured, well construction and abandonment integrity become less 

and less critical 

Undertaking CO2 sequestration in a depleted oil or natural gas field reverses 

the process of depressurization in the reservoir. Pumping CO2 (or any fluid) 

increases the pressure of the reservoir substantially and every old production 

and exploration bore hole becomes a potential route of failure. Well and 

borehole abandonment configurations, even if fully compliant with requirements 

in place at the time of the abandonment, may not be capable of containing the 

pressures of the GS reservoir. Even if the reservoir is allowed to fill 

passively to the spill point, there will be excess pressure relative to 

formation hydrostatic pressures at the confining layer. The magnitude of the 

excess pressure will be directly proportional to the density contrast with the 

formation brine and the thickness of the CO2 lens. Wells appropriately sealed 

against hydrostatic pressures present in the depleted oil field may fail 

catastrophically when subjected to pressures that result from CO2 storage in the 

trap. Here too, the rule needs to add specificity to what needs be performed in 

the way of finding and recompleting the abandonment of all pre-existing wells 

and boreholes to configurations consistent with the reservoir conditions 

expected after CO2 sequestration, not the conditions that exist at the time the 

11
field was abandoned or the project is initiated. There is no discussion in the 

USEPA materials supporting this rule that acknowledges or discusses the 

implications of the equivalent of an oil-field blow out. The catastrophic 

failure of a plugged or abandoned well would create an open conduit for the 

expulsion of supercritical CO2 to the ground surface, potentially miles from any 

injection infrastructure. 

Individual Response: EPA believes that many depleted oil and gas reservoirs may be candidate 

formations for GS, as the trapping mechanisms responsible for accumulation of the oil and gas 

are analogous to the processes that will trap CO2 in the subsurface during GS. However, EPA 

acknowledges commenters' concerns regarding GS in oil and gas reservoirs –including concerns 

about the use of older well construction technologies. EPA clarifies that §146.84 requires the 

owner or operator to identify all wells in the AoR and demonstrate to the Director's satisfaction 

that they are appropriately plugged and will not serve as conduits for fluid movement. While this 

requirement allows the owner or operator to rely on publicly available data, the Director has 

discretion to require additional research if he/she has reason to believe that existing databases are 

incomplete or out of date. 

The Agency clarifies that the final GS rule contains additional requirements at §144.19 that 

address the commenters' concerns and clarify the transition from Class II enhanced oil and gas 

recovery to GS. Furthermore, the Agency clarifies that an owner or operator of a Class II well 

that is to be re-permitted as a Class VI well must meet the grandfathering requirements at 

§146.81, the permit application requirements at §146.82, and all operational, monitoring, and 

post-injection site care and site closure requirements in Subpart H of Part 146. 

In response to the comment about subsurface depressurization, EPA acknowledges that there are 

differences between CO2 injection for ER (where oil production serves to depressurize the 

reservoir) and GS (where pressures will tend to increase, since no extraction occurs). It is for this 

reason that CO2 injection for the purpose of long-term storage may not be regulated as Class II 

wells and owners or operators of Class II wells whose primary purpose is long-term storage are 

subject to Class VI, GS requirements, including those for rigorous site characterization at 

§146.82, well construction at §146.86, and monitoring at §146.90. 

EPA acknowledges that there may be risks associated with GS into certain formation types. For 

this reason, the Agency is using an adaptive approach to regulate GS injection. EPA will collect 

and review project data on early GS projects, including those that inject into various formation 

types, to determine whether the appropriate amount and types of information and documentation 

are being collected. 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. 

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

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

plans under §146.84. The guidance describes the data to be considered in an initial AoR 

delineation, how to apply computational modeling to delineate the AoR, performing corrective 

12
action at GS sites, and, when appropriate, completing AoR reevaluations. The guidance can be 

found on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0196 Comment ID: 23929 Letter Lines: 261 to 303 

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

Comment: Issue 9. Use of models to assess area of review is only briefly discussed in 

the proposed regulation. 

The regulation specifies the use of mathematical models to assess the AoR and 

potential impacts. Prior to beginning modeling to evaluate the suitability of a 

potential reservoir, applicants should be required to collect sufficient field 

data from the reservoir and over-and underlying formations to evaluate the 

effects of the project on not only the area of review but also nearby locations 

where groundwater resources are present, even if not used widely. In modeling 

of proposed GS projects, multi-phase geologic models should be used coupled with 

solute transport modeling to evaluate the anticipated impacts. Additionally, 

models which can evaluate the geomechanical stresses upon the geologic materials 

within the AoR should be used to determine the potential for induced seismicity. 

Prior to modeling, site characterization should be performed with an adequate 

number test boreholes and wells to allow a statistically-valid characterization 

of issues within the AoR. In addition, the models should simulate the entire 

project lifespan and a substantial amount of time in the post-closure phase to 

provide insight into, support mitigation of, potential failure mechanisms. 

Issues to be evaluated in reservoir modeling should include but not be limited 

to: 

* Rock mechanics and susceptibility to fracture/failure, 

* Water quality within the AoR including strata above and lateral to the 

proposed GS reservoir, 

* Reservoir and aquifer properties, 

* Potential for CO2 migration into overlying strata via faults and improperly 

sealed boreholes, 

* Potential water quality impacts on USDWs due to the pressure field developed 

under project scale injection, 

* Mechanical and hydraulic properties of low-permeability units anticipated to 

serve as barriers to migration of the CO2 and, 

* The effects of fluids that will be displaced from zones between the GS 

reservoir and USDWs. 

Ongoing collection of verification data for these models is important and should 

be performed on an interval that will be sufficient to allow identification and 

mitigation of potential failure mechanisms. Use of any model must be combined 

13
with calibration, where field observations should be replicated in the model. 

Any models that are used must be fully documented, with assumptions and 

methodology provided. A 5-year review interval is suggested over the course of 

the project life. Models alone, without sufficient field data collected prior 

to and during operation, are not protective of the public safety or resources. 

Individual Response: EPA agrees that detailed geologic data, including the types of data to 

which the commenter refers, is invaluable to modeling an accurate AoR. The Agency believes 

that the AoR delineation requirements in 146.84 (c)(1)(i), which specify using "detailed geologic 

data collected to characterize the injection zone, confining zone and any additional zones; and 

anticipated operating data...," and (c)(iii) to "consider potential migration through faults, 

fractures and artificial penetrations," provide the necessary information needed for appropriate 

site modeling, subsequent site evaluation, and protection of USDWs from endangerment. EPA 

adds that the extensive requirements for data that is to be included in the permit application at 

146.82 incorporate these same types of information. The Director will review the AoR models in 

the context of the extensive site data submitted with the permit application. EPA recognizes that 

in some instances, the Director may require additional types of data to be included in the AoR 

delineation (146.84(c)(1)). 

Letter ID: 0196 Comment ID: 23930 Letter Lines: 305 to 318 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: Issue 10. Well construction and well conversion issues are not adequately 

addressed in the proposed regulation. The conversion of wells from enhanced oil 

recovery (EOR) or hazardous waste injection to CO2 injection is vague. 

Well construction and potential well conversion issues need to be addressed in 

the regulations. All materials with the potential to come into contact with 

the injectate and/or the formation fluids should be designed and tested to 

insure the materials’ integrity will be maintained and they will prevent 

movement of the injectate into a potential USDW zone. Materials that will not 

come into contact with the injectate and/or formation fluids in the zone of 

injection are not as critical, but sufficient design review should be performed 

to insure that proper materials are used for all well construction. All wells 

used for injection and monitoring should be operated according to a periodic 

maintenance schedule similar to other wells in the UIC program. 

Individual Response: EPA agrees that well materials need to be compatible with injected fluids 

and formation fluids. The GS rule at §146.86(b)(1) requires that all injection well materials be 

compatible with fluids with which the materials may be expected to come into contact. Further, 

the rule, at §146.82(a)(7), requires owners or operators to submit information on planned 

injection pressures, that the Director will use in evaluating the proposed casing, tubing, and 

packer design. EPA adds that, in determining the suitability of well materials and the design of 

the well, the Director must consider various aspects of the injection project, including injection 

pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness 

14
of the CO2 stream, and formation fluids in §146.86(b)(1)(v). 

Owners or operators seeking to convert existing wells for GS must demonstrate to the Director's 

satisfaction that the converted well can conduct GS operations in a manner that does not 

endanger USDWs. The final GS rule, at §146.81(c), allows the construction of these wells to be 

grandfathered, 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 is developing guidance on transitioning from Class II to Class VI. The guidance will assist 

Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI 

transition. The guidance describes the methods available for the Director to determine the risk 

posed to USDWs from a GS/ER project, and how the Director may determine if a project should 

be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's 

web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Regarding operation of monitoring wells, EPA requires under §146.90 that owners or operators 

submit proposed testing and monitoring plans to the Director at the time of the permit 

application. The operator will need to demonstrate that the monitoring wells will be constructed 

and operated in a manner that will be sufficiently protective of USDWs from endangerment. 

Letter ID: 0196 Comment ID: 23931 Letter Lines: 320 to 324 

Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment) 

Comment: Conversion of existing oil and gas wells and/or EOR wells to CO2 injection wells 

should be evaluated on a detailed case-by-case basis. Review should include all 

well construction records, performance of well evaluation and mechanical 

integrity testing and cement bond logging, and in the event the well is 

retained, workover should be performed. 

Individual Response: EPA agrees that any decision to convert a well for long term storage of 

CO2 should be made in the context of all available information about the site and history of 

injection. The final GS rule provides for the construction of these wells to be grandfathered per 

§146.81(c), provided the owner or operator can demonstrate to the Director that the wells were 

engineered and constructed to meet the requirements at §146.86(a) and ensure protection of 

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

EPA clarifies that other requirements (i.e., beyond the construction requirements) will not be 

grandfathered. Following conversion of the project to Class VI, many of the unique factors of GS 

sites (e.g., increased reservoir pressures associated with large volumes of stored CO2 and the 

corrosivity of CO2 in the presence of water) warrant the specific operational, MIT, monitoring, 

reporting, plugging, post-injection site care, and site closure requirements in the final GS rule. 

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Letter ID: 0196 Comment ID: 23932 Letter Lines: 326 to 344 

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

CFR 146.90) 

Comment: While detailed geologic modeling is planned, monitoring wells should be 

installed into the injection zone, and into buffer zones above the injection 

zone, including fluid bearing zones below any potential USDW zone. In addition, 

pressure sensors should be installed in the confining units above the GS 

reservoir. The data collected from the monitoring wells and pressure monitoring 

points can be used to confirm the accuracy of a model and to monitor the zone 

above the injection zone for CO2 leakage. Monitoring wells should be installed 

into the buffer zone to provide early detection in the event CO2 or the 

associated pressure front begins to migrate into zones above the proposed 

injection zone. All monitoring wells should be designed to similar standards as 

injection well and will need pressure shut-in equipment. 

Clustered monitoring wells should be considered to allow a single borehole to be 

used to monitor several different vertically discrete zones. For example, there 

is a potential that the injection zone, one or more buffer zones, and the USDW 

zone could be monitored from clustered monitoring wells installed into a single 

borehole. In the event such technology is used, equipment should be installed, 

maintained, and tested on a designated frequency to prevent migration of fluids 

between zones. 

Individual Response: EPA agrees that pressure monitoring in the injection zone is appropriate. 

The final GS regulation, at §146.90(g)(1), requires all GS project owners or operators to monitor 

for pressure changes in the injection zone. EPA believes that pressure monitoring in the injection 

zone is necessary to track the development and movement of the pressure front and CO2 plume. 

Pressure monitoring within the injection zone is necessary because any such monitoring above 

the confining zone would not detect movement of the pressure front unless a breach of the 

confining zone occurs. 

EPA adds that, although it is not required in the GS rule, owners or operators may consider 

performing additional pressure monitoring in wells that are above the confining zone (e.g., in the 

same wells used to perform ground water quality monitoring required at §146.90(d)) to provide 

additional verification that no pressure changes are occurring above the confining zone. 

Monitoring also identifies needed remedial actions, provides inputs for AoR reevaluation 

modeling, and targets additional geochemical and surface monitoring needs. Knowledge of the 

location of the CO2 plume and the associated pressure front will assure the public that GS 

projects are proceeding according to plan, provide sufficient information to the owner or operator 

and Director, or allow for appropriate actions to address any indication that USDWs may be 

endangered. 

EPA acknowledges that, at certain sites, there may be a need for more or different monitoring 

schemes (which may include monitoring in the confining or buffer zones), and adds that it is 

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important to balance the need for adequate monitoring that ensures USDW protection from 

endangerment against too many artificial penetrations which could serve as conduits for fluid 

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

monitoring regime, which must be approved by the Director. EPA recognizes that wells with 

multiple completions (i.e., what the commenter refers to as "clustered monitoring wells") may 

offer benefits; nothing in the rule precludes their use. 

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, 

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 also be found on 

EPA’s website. 

Letter ID: 0196 Comment ID: 23933 Letter Lines: 346 to 348 

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

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: Issue 11. The post-closure operator liability timeframe of 50 years should be 

considered a minimum and should be extended in the event monitoring and modeling 

data indicate potential failure may require mitigation. 

Individual Response: EPA agrees with commenters that a 50 year post-injection site care 

timeframe represents a reasonable and protective monitoring period for most cases. EPA bases 

this on a review of research studies, industry reports, existing environmental programs, and 

evaluation of public comments. Furthermore, EPA believes that a 50-year default post-injection 

site care timeframe is not overly burdensome, does not exaggerate the risks associated with GS, 

is consistent with other environmental programs, and sufficiently protects USDWs from 

endangerment. For this reason, the final GS regulation retains the 50 year post-injection site care 

timeframe, as specified in §146.93(b)(1). 

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However, EPA disagrees that a 50-year post-injection site care timeframe should be an absolute 

minimum. Rather, EPA recognizes that there may be sites where the 50 year post injection site 

care timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. 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). 

Such a demonstration will be site-specific, and based on pressure monitoring and USDW 

impacts. EPA clarifies that in no cases will site closure be authorized until the owner or operator 

demonstrates to the satisfaction of the Director that the site no longer poses a risk of 

endangerment to USDWs. 

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

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

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

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

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

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

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

impacts. 

Letter ID: 0196 Comment ID: 23934 Letter Lines: 350 to 358 

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

Comment: Issue 12. The timeframe of Area of Review Reevaluation should be revised to 

require more frequent reevaluation during the beginning of a project 

implementation and then less frequent reevaluation as the GS reservoir is shown 

to maintain integrity. 

The AoR should schedule be reevaluated annually during the first five years, 

biannually during the five to 10-year period and then on a 5-year schedule 

afterwards until closure. Following closure, reevaluation should be performed on 

a 10-year frequency until the operator is released from liability. 

Individual Response: EPA agrees with commenters that reevaluations of the AoR every ten 

years may not be sufficient to appropriately model plume and pressure front movement, establish 

conditions for corrective action, and ensure protection of USDWs from endangerment. For these 

reasons, the Agency changed the minimum frequency for the AoR reevaluation at §146.84(e) 

from 10 years to at least every five years in the final GS rule. EPA believes that this revised 

frequency addresses commenters' concerns about the inherent uncertainties in modeling CO2 

movement, the emerging nature of GS technology, risk-based targeting of monitoring activities, 

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and the unique nature of CO2 GS. In addition, the Director has discretion to require more 

frequent AoR reevaluation if he or she has reason to believe, based on site-specific information, 

that a five-year reevaluation schedule is not sufficiently protective of USDWs. 

To the comment regarding post closure reevaluations, EPA presumes the commenter is referring 

to the post-injection site care period. (EPA clarifies that site closure occurs after a demonstration 

that the GS project no longer poses a risk to USDWs.) 

Letter ID: 0196 Comment ID: 23935 Letter Lines: 360 to 361 

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: Issue 13. The proposed rule should consider and discuss mitigation options for 

large- scale failure of a mature GS reservoir. 

Individual Response: EPA clarifies that determining appropriate remedial actions and 

mitigation technologies that may be employed at a GS site is site- and event-specific and will 

depend on a variety of factors, including the nature of any movement of CO2 or other fluids, the 

presence of USDWs, and what, if any, impacts may have resulted. EPA is developing guidance 

on the development and implementation of emergency and remedial response plans for GS sites. 

EPA clarifies that, if the owner or operator obtains evidence that USDWs may be endangered or 

that leakage is occurring, he or she must cease injection, take all steps reasonably necessary to 

identify and characterize any release, notify the Director, and implement the approved 

emergency and remedial response plan (§146.94(b)). 

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