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, 2008Colorado Ground W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 2008

2 

## Colorado Grou nd 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 Wa ter Association (CGW A) is a nonprofit pr ofessional 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 CG WA ’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.

Wh ile a promising technology for mitigation of C O 2 emissions, geologic storage (GS) of CO 2 also has the potential to impact underground Sources drinking

waters ( USD Ws ) . Even though deep injection of CO 2 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

USD Ws and a significant portion of Colorado’s agricul tural economy reli es on the freshwater aquifers for crop irrigation

. The CGW A 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 c ould also govern the post

- closure liability of GS project operator s. 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 proje cts are mismanaged

.

In response to the U.S. EPA proposed rule on GS (72FR43492), CGW A 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 fr om consideration as sequestration repositories.Colorado Ground W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 2008

3 One of the CG WA ’s concerns is the siting of CO 2 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 o r agricultural community

. Due to

uncertainties in the effectiveness of GS at the project

- scale s being considered

, siting of GS reservoirs in strata underlying “sole

- source” or other “important”

USD Ws , should be avoided , at least until large scale experience validates this methodology

. Examples of such aquif ers include the Denver Basin Aquifers and the aquifers of the San Luis Valley. A dditional 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 ar e 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 CO 2 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 appropriat e 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 define s USD Ws as zones that

c ontain 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 containin g 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 mak ing such water sources economical. T o protect ground water resources which may be economical in the for eseeable 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 c oncentrations that siting studies and public input indicate are not likely to be useable in the future, as use of a zone for CO 2 sequestration will likely preclude recovery and use of the groundwater resource in the future.Colorado Ground W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 2008

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

release (earthquakes)

.

The proposed regulation should specifically address the issue of triggering

tectonic stress release s , to avoid problems, such as the generation of earthquakes that resulted from deep w aste 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 t he Rocky Mountain Arsenal inject ed

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 CO 2 annually

. Wh ile the proposed rule states that the potential for induced seismicity is low, the magnitud e of the volumes proposed for injection indicate that this issue has the potential to present a significant risk to occupants within a GS project A rea of

R eview A o R

.

Issue 5 . The regulations should specifically address the potential for migration of injec ted CO 2 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 CO 2 and that the integrity of that trap will be perpetual. Demonstrating a

pre

- existing geologic structure capable of trapping CO 2 and demonstrating that the complex geochemical reactions in and adjacent to the GS reservoir will not compromise the reservoir’s integrity are critical. Howev er, the rule simply presumes such a demonstration can be made and provides no method s or criteria to be met in developing the demonstration.

Supercritical CO 2 is essentially a light non

- aqueous phase liquid ( LNAPL ) capable of dissolving into water and als o into which water can dissolve . A porous medium , such as the strata comprising a GS reservoir, is about eight

times as permeable to supercritical CO 2 as to water due to the low viscosity of the supercritical CO 2 . The supercritical CO 2 will rise through a water

- bearing reservoir as a buoyant fluid, independent of injection pressure gradients. Wh en the supercritical CO 2 reaches an impermeable stratum, that buoyancy will cause it to continue to move updip along that stratum until it encounters a stratigrap hic or structural trap or permeability change sufficient to preclude further migration, i.e., a trap. The CO 2 will continue to migrate into that trap, displacing the native water. If the injected volume is greater than the trap’s available volume the

exc ess CO 2 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 CO 2

.Colorado Ground W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 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. Wh ile 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 CO 2 in perpetuity. There are, however, major issues for CO 2 sequestration not borne by hydrocarbon exploration.

One issue is ge ologic 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 CO 2 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 b ear the burden of multiple failures. For the operator of a large point

- source of CO 2 , sequestration of CO 2 is a cost to be minimized as it does not result in a profit opportunity. W ithout detailed, explicit rules establishing how to prove a trap before a ttempting 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 CO 2 can be minimized by requiring sequestration in deplete d petroleum traps , however there may not be enough depleted oilfields to contain a significant amount of CO 2 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 p roposed rule

. Early implementation of GS should incorporate the concept of multiple barrier zones. This allows implementation of monitoring in zones below a USD W t hat can serve as a guard zone. These are critical in a zone between the repository and USD W s 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, pressur es in confining units should be monitored to provide allow

detection of failure of the GS reservoir.

Issue 7

. T he fate of displaced brines is not sufficiently addressed

.Colorado Ground W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 2008

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

brines in the repository. Large volumes of CO 2 will increase reservoir pressures and will displace brines laterally and potentially vertically. Based on 2005 CO 2 production rates for Colorado power plants (CCS, 2007) and adding 30% additional carbon resulting fr om 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 CO 2 for a med ium

- sized power plant. Assuming a reservoir thickness of 300 feet with 10% porosity available to the supercritical CO 2 , this quantity would result in displacement of the brine from approximately 0.5 square mile s of reservoir annually, or from approximatel y 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 CO 2 will occupy the entire

thickness of the reservoir

, while in reality, the supercritical CO 2 can be expected to float to the top of the reservoir and spread laterally

, migrating approximately 8 times the velocity of ground w ater flow. In the event CO 2 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 u sed for drinking water sources. The applicants will need to address the fate of these displaced brines.

Issue 8

. The r isks 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 depth

equivalent water bearing zones. However, as the fields are developed, those excess pressures are relieved, and the fi eld 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 CO 2 sequestration in a dep leted oil or natural gas field reverses the

process of depressurization in the reservoir . Pumping CO 2 (or any fluid ) increases the pressure of the reservoir substantially and every old production and exploration bore hole becomes a potential route of fail ure. W ell 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 t o the spill point, there will be excess pressure relative to formation hydrostaticColorado Ground W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 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 t he CO 2 lens. We lls appropriately sealed against hydrostatic pressures present in the depleted oil field may fail catastrophically when subjected to pressures that result from CO 2 storage in the trap. Here too, the rule needs to add specificity to what ne eds 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 CO 2 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 . T he catastrophic failure of a plugged or abandoned well would create an open conduit for the expulsion of supercritical CO 2 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

.

T he 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 reserv oir 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 geolo gic models should be used coupled with solute transport modeling to evaluate the anticipated impacts. Additionally,

models which can evaluate the geo mechanical stresses upon the geologic

materials within the AoR should be used to determine the potential f or 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 A o R

. In addition, the models should

simulate the ent ire 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 mechanic s and susceptibility to fracture/ failure,

· Wa ter quality within the AoR including strata above and lateral to the proposed GS reservoir,

· Reservoir and aquifer properties,

· Potential for CO 2 migration into overlying strata via faults and improperly

sealed boreholes,

· Potential water quality impacts on USD Ws due to the pressure field developed under project scale injection,Colorado Ground W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 2008

8 · Mechanical and hydraulic properties of low

- permeability units anticipated to serve as barriers to migration of the CO 2 and,

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

reservoir and USD Ws

.

Ongoing c ollection of verification data for these models is important and should be perfo r med 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 . W ell construction and well conversion issues are not adequately addressed in the proposed regulation

. Th e conversion of wells from enhanced oil recovery ( EOR ) or hazardous waste injection to CO2 injection is vague

.

We ll construction and potential well conversion issues need to be addressed in

the regulations. A ll 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 USD W z one. 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 u s ed 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 CO 2 i njection wells

should b e 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

.

Wh ile 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 CO 2 leakage. M onit oring wells should be installed into the

buffer zone to provide early detection in the event CO 2 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 W ater Association Comments

USEPA UIC Program Proposed Rule

– 73 FR 43492 Carbon Dioxide Geologic Sequestration December 2 2, 2008

9 C lustered monitoring wells should be consider ed to allow a single borehole to be

used to monitor several different vertically discrete zones. For example, there is a potential that the injecti on zone, one or more buffer zone s , and the USD W 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 mitig ation.

Issue 1 2. 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.

Reference s :

Ake, Jon, Kenneth Mahrer, Daniel O’Connell and Lisa Block, 2005. De ep

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;

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 W ater Considered for New Mexico Development. Southwest Hydr ology, Mar ch/April 2008, p. 8.

Available from http://www.swhydro.arizona.edu/archive/V7_N2/dept

ontheground.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 undergr ound Sources drinking waters (USDWs). Even though deep injection of CO 2 has been used for over 20 years to enhance oil and gas recovery and provid es a foundation for large-scale use of geologic storage (GS), nothing on the scal e 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 por tions of Colorado’s population rely on USDWs and a significant portion of Colo rado’s agricultural ec onomy 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, monitori ng, 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 wa ter is an important resource that needs to be protected. The primary goal of th e 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 vi olation of any primary drinking water regulation or may adversely affect th e 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 billio ns of gallons of fluids for decades. The GS regulation enhances this framew ork with requirements that ar e tailored to a ddress the unique issues associated with GS, in cluding large injection volumes, th e 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 formati ons. These additional protective requirements include more extensive geologic testing for si te characterization, detailed computational modeling of the AoR and periodic re-evaluations , detailed requirements for monitoring and tracking the CO2 plume and pressu re front, and extended post-inject ion monitoring and site care. EPA expects the tailored permitting, siting, construction, operation, monitoring, and post1injection site care requirements in the GS rule wi ll 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 ba sins and/or zones with im portant 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 underlyi ng major sedimentary rock aquifers such as those which are the pr imary source of drinking or irrigation water for large segments of the populati on 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-sour ce" or other "important" USDWs, should be avoided, at least until large scale experience validates this methodology. Examples of such aquifers in clude the Denver Basin Aquifers and the aquifers of the San Luis Valley. Add itional examples of aquifers which may be subject to degradation by displaced brines include th e alluvial aquifers of

the South Platte and Arkansas River Valle y where they are in contact with the subcrops of strata which could be used as GS reservoirs. Colo rado’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 wa ter is an important resource that needs to be protected. The primary goal of th e 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 vi olation of any primary drinking water regulation or may adversely affect th e health of persons as specified in §144.12.

The GS rule, at §146.82(a)(5), requires prospectiv e 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 inject ion and confining zones, to demonstrate that the injected CO2 will remain w ithin the target formation. The Director must consider this information when determining wh ether 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. Additiona lly, 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 a nd recovery, the PWSS program dir ector, and all agencies that

2oversee 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 ar e 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 cl arifies that a state’s Class VI primacy program may be more stringent then the federal requirements. For exampl e, 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 res ponsibility of Class VI permit applicants to demonstrate the suitability of a particular site or formation. It is the respon sibility of the Director

to evaluate the information collected and s ubmitted 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 limiti ng the scale of projects initially in order to identify issues th at may crop up that are currently unanticipated. The early large scale proj ects should be extensively mon itored in order to validate concepts that can be applied to other lo cations. This early work should include validation of appropriate modeling tec hniques capable of reliably predicting system responses. This early proof of con cept 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 manne r 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 pr oject will be evaluated based on site-specific information about the ability of the geologic form ations to safely receiv e and confine injected CO2. However, the Agency agrees that a protective initial approach is ap propriate and additional safeguards are necessary, given the uncertainty asso ciated 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 a nd appropriate documentation are being collected,

and to determine if modifications to the re quirements are appropr iate or necessary.

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

3Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 1240 1.1.1.3 Suggested changes/ed its 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 di ssolved solids (TDS) concen tration of less than 10,000 mg/L. This limit should be revised to co nsider 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 ma y be needed in the future. In areas with limited water resources water pr oviders are beginning to turn to groundwater sources containing in exce ss of 10,000 mg/L TDS (Sengebush 2008). It is already conceivable that in th e near future sources with up to approximately 20,000 mg/L TDS will be cons idered viable as water treatment technology advances making such wate r sources economical. To protect groundwater resources which may be economical in the foreseeable future the rule should evaluate the potential that curren tly marginal groundwater sources will be usable. The repository zones should be limited to strata c ontaining very high

TDS concentrations that s iting 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 gr oundwater 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/arch ive/V7_N2/dept-ontheground.pdf.

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

resources and future water resource availabilit y. 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 regul ations 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 re sources and that technology improvements may make high TDS aquifers viable drinking water sources. EPA believes these potential resources should be c onsidered when injection depth wa ivers are sought. Therefore, the final GS rule at §146.95(b) requires the Director to consider thes e issues in determining whether

4an injection depth waiver is appropriate. Spec ifically, the Director must consider whether alternative injection si tes 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 resour ces 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 Availa bility 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 ambi guous on the issue of tectonic stress release (earthquakes).

The proposed regulation should specifically address the issue of triggering tectonic stress releases, to avoid pr oblems, 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 th e Paradox Valley, Colorado (Ake, et al, 2005). From 1962 through 1966 th e Rocky Mountain Arsenal injected a volume of approximately 165 million gall ons of waste, or roughly 35 million gallons annually. This volume would be dwarfed by the injection volumes proposed on the three billi on gallons of supercritical CO2 annually. While the proposed rule states that the potential for induced se ismicity is low, the magnitude of the volumes proposed for inj ection indicate that th is 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’Conne ll 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 seismi city 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 characteriza tion process, owners or operators must submit information about the se ismic history of and seismic sources near a proposed GS site, data on known or suspected fa ults in the AoR, geomechanical information on fractures, stress, ductility, rock strength, and in si tu 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 poten tial for reopening or

reactivation of faults or un acceptable seismic risk that co uld otherwise interfere with containment will not be permitted as GS sites. Duri ng injection, the pressure in the injection zone must not exceed 90 percent of the fracture pre ssure of the injection zone as specified in §146.88(a); this requirement is inte nded to prevent the opening of fractures or faults through over pressurization of the injection zone.

5EPA adds that the seismic episodes at the Ro cky 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 Ar senal, injection volume

is not the sole factor that de termines induced seismicity. Induced seismicity also depends on other geologic variables such as pre-existi ng faults, porosity, and permeability (Sminchak & Gupta, 2003). With proper site characterizati on (i.e., pursuant to §146.82), these variables can often be quantified prior to in jection (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 fl uid should not increase the risk of seismic activity.

EPA does not believe that limiting GS to "stable ar eas" 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 seve ral hundred years). For this reason, EPA requires seismic risk to be evaluated on a site-specific basi s, through an analysis of seismic history and an evaluation of known or suspected faults in th e 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 requ irements at §146.90 and emergency and remedial response requirements as specified in §146.94 provide addi tional 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 shoul d specifically address the potential for migration of injected CO2 in different t ypes of groundwater reservoirs.

The proposed rule lacks specificity with respect to the manner in which a proposed operation will dem onstrate that there is a su itable geologic trap for the injected CO2 and that the integrit y of that trap will be perpetual. Demonstrating a pre-existing geologic st ructure capable of trapping CO2 and demonstrating that the complex geochemical reactions in and adjacent to the GS reservoir will not compromise the reser voir’s integrity are critical. However, the rule simply presumes such a dem onstration can be made and provides no

methods or criteria to be met in developing the demonstration.

Supercritical CO2 is esse ntially a light non-aqueous phase liquid (LNAPL) capable of dissolving into water and al so into which water can dissolve. A porous medium, such as the strata compri sing a GS reservoir, is about eight times as permeable to supercritical CO2 as to water due to the low viscosity of

6the supercritical CO2. The supercritical CO 2 will rise through a water-bearing reservoir as a buoyant fluid, independent of injection pressure gradients. When the supercritical CO2 reaches an impermeab le 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 trappi ng configuration or reaches temperature and pressure where it reverts from superc ritical to gaseous CO2.

Finding trapping structures in the subsur face is a non-trivial exercise. Every dry oil or gas exploration hole was drilled because a geolog ic investigation appeared to establish presence of a tr ap for buoyant hydrocarbons. While some dry holes may result from a missing sour ce of petroleum, overwhelmingly the cause is that the postulated trap did no t exist, either because the trapping

structure was absent or due to natural leaks through the conf ining units through which the oil or gas escaped. These techni cal problems associated with finding petroleum LNAPL traps are directly anal ogous to finding traps capable of holding CO2 in perpetuity. There are, however, ma jor 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 l eaky. There is no corresponding way to establ ish the integrity of the seals in the case of exploration for CO2 traps.

Another issue relating to GS reservoir siting evaluation is economics inherentin 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 CO 2, 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 sequest ration 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 ab andoned wells can comp romise 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

7USDWs. The rule requires the owner or opera tor 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 provi de a specific list of information to be provided.

Owners or operators seeking a permit for GS we lls must provide the appropriate information, regardless of whether there is a cost incentive for proper site ch aracterization. If the information submitted is not adequate to support a determinati on 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 regard ing characterizing the region al geology and hydrogeology of a proposed GS site as well as performing th e necessary geochemical, geomechanical, and geophysical analyses of the injection and conf ining zone. The guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/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 identif y the need for monitoring to verify performance of the repository. Monitoring wells to detect potential migration from the repository need to be incorp orated 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 z one between the reposito ry and USDWs to allow for the early detection of a problem while mitigation is still an option. Even highly effective monitoring of GS re servoirs for failure may only inform operators after "the horse has left th e barn." In addition to buffer-zone monitoring, pressures in confining units s hould 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 confini ng 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 pr ogram. EPA adds that the baselin e 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 ad ditional formations, e.g., the injection zone, may

8also be necessary, and if the Di rector believes such monitoring is warranted he/she has the authority to require that it be include d in the testing and monitoring plan.

EPA believes that geochemical monitoring above th e confining zone should not be restricted to areas near the plume. Researc h, 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 we lls 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 c onfining zones would reduce the chance that CO2 or other fluids will move from the injec tion zone; however, to increase protectiveness, a multiple-barrier approach to protecting USDWs from endangerment that includes both proper site charac terization 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 be lieves 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 met hods (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 th e injection zone is necessary because any such monitoring above the confining z one 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 brin es is not sufficiently addressed.

The regulations need to be more speci fic on assessing the fate of displaced brines in the repository. Large volumes of CO2 will increase reservoir pressures and will displace brines laterally and pot entially vertically. Based on 2005 CO2 production rates for Colorado power plants (CCS, 2007) and addi ng 30% additional carbon resulting from the parasitic loa d, 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 CO 2 for a medium-sized power plant. Assuming a reservoir thickness of 300 feet with 10% porosity available to the supercritical CO2, this quantity would resu lt in displacement of the brine from approximately 0.5 square miles of reservoi r annually, or from approximately 25 square miles over an assumed 50-year pr oject lifetime. A large power plant, such as the Craig plant, would displace brine completely from approximately 65

9square miles of such a hypothetical reservoir. Additionally, the volume calculations presented here assume the supercritical CO2 w ill occupy the entire thickness of the reservoir, while in re ality, the supercritical CO2 can be expected to float to the top of the re servoir and spread laterally, migrating approximately 8 times the velocity of groundw ater 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 Green house Gas Inventory and Reference Case Projections 1990-2020. Ce nter for Climate Strategies. Available from: http://www.coloradoclimate.org/ ewebeditpro/items/O14F13894.pdf

Individual Response: EPA acknowledges that there are pote ntial 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 hydrologi c impacts of CO2 storage (Birkholze r, et al. 2008). In addition to EPA-funded research, a study by Nicot (2008) modeled the eff ect of CO2 injection on up-dip aquifers in the Texas Gulf Coast Basin. The stud y concluded that in the Gulf Coast Basin, water displacement due to down-dip injection of CO2 is not likely to cause si gnificant changes in salinity. EPA expects that, as rese arch on far-field impacts of GS continues, estimates of storage capacity in such systems will improve.

As part of its adaptive rulemaking approach, EP A 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 a nd types of information and appropriate documentation are being collected, and to determ ine 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 cons truction, operation, monitoring, post-injection site care, and site closure. Suitable GS sites must ha ve confining zones that are free of transmissive

faults or fractures and are of su fficient areal extent and integr ity to contain the injected CO2 stream and displaced formation fluids. The formations must allow injection at proposed maximum pressures and volumes without initiati ng or propagating fractures in the confining zone(s), as required at §146.83(a)(2).

The GS rule requires owners or operators to su bmit 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 suit ability of the confining zone ; the location of any known or suspected faults; subsurface geochemistry; and th e location of, depth of, and other information

10regarding any perforatio ns that may extend into the confin ing zone. EPA expects that this information, in conjunction with AoR modeli ng required at §146.84, will help identify the potential for brine migration as a result of pressu re displacement. Based on this information, the Director and the owner or operator can identify ways to mitigate this risk pr ior to injection, or, if necessary, the Director can deny the permit appl ication. During injecti on operations, operators must extensively monitor ground water quality and pressure changes to provide early detection of any unacceptable movement of fluids or im purities in the subsurf ace as specified in §146.90. Operators must also develop and follow an emer gency and remedial respons e plan to address any adverse effects associated with the GS operati on as specified in §146.94 and maintain financial responsibility to address contam ination 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 ol d wells in depleted oil and gas fields are not adequately a ddressed in the proposed regulation.

The use of depleted petroleum reservoirs poses a significant problem. Depleted petroleum traps are generally the oldest oi lfields and there are the problems of record keeping and are likely subject to outdated and inappropri ate technologies during their development and the subseque nt abandonment of the wells. Oil fields initially are characterized by pre ssures that are high er than depthequivalent water bearing zones. However, as the fields are developed, those excess pressures are relieved, and the fi eld 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 depressurizat ion in the reservoir. Pump ing CO2 (or any fluid) increases the pressure of the reservoi r substantially and every old production and exploration bore hole becomes a pot ential route of failure. Well and borehole abandonment configurat ions, 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 c onfining layer. The magnitude of the excess pressure will be directly proportio nal 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 pressure s that result from CO2 storage in the trap. Here too, the rule need s to add specificity to what needs be performed in the way of finding and recompleting the ab andonment of all pre-existing wells and boreholes to configurations consis tent with the reservoir conditions expected after CO2 sequestra tion, not the conditions that exist at the time the

11field was abandoned or the project is in itiated. 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 w ould 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 a nd 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 techno logies. EPA clarifies that §146.84 requires the owner or operator to identify all wells in the Ao R and demonstrate to the Director's satisfaction that they are appropriately plugge d and will not serve as conduits for fluid movement. While this requirement allows the owner or operator to re ly on publicly available data, the Director has discretion to require addi tional research if he/she has reason to believe th at 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 th e transition from Class II enhanced oil and gas recovery to GS. Furthermore, the Agency clarifie s 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 car e and site closure requirements in Subpart H of Part 146.

In response to the comment about subsurface de pressurization, EPA acknowledges that there are differences between CO2 injection for ER (whe re oil production serves to depressurize the reservoir) and GS (where pressures will tend to incr ease, since no extraction occurs). It is for this reason that CO2 injection for th e 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 appr oach 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 am ount 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 a nd types of information and appropriate documentation are being collected, and to determ ine if modifications to the requirements are appropriate or necessary.

EPA is developing guidance on AoR and corrective act ion at GS Class VI s ites to assist owners or operators and Directors in evaluating requi rements 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

12action at GS sites, and, when appropriate, co mpleting 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/M odeling CO2 movement

Comment: Issue 9. Use of models to assess area of review is only brie fly discussed in the proposed regulation.

The regulation specifies the use of mathem atical models to assess the AoR and potential impacts. Prior to beginning mode ling to evaluate the suitability of a potential reservoir, appli cants should be required to collect sufficient field

data from the reservoir and over-and unde rlying 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 geologi c models should be used coupled with solute transport modeling to evaluate the anticipated impacts. Additionally, models which can evaluate the geomecha nical stresses upon the geologic materials

within the AoR should be used to determin e the potential for induced seismicity. Prior to modeling, site char acterization should be perfor med with an adequate

number test boreholes and wells to allow a statistica lly-valid characterization of issues within the AoR. In addition, the models should simulate the entire project lifespan and a subs tantial amount of time in th e post-closure phase to provide insight into, support mitigati on of, potential failure mechanisms.

Issues to be evaluated in reservoir m odeling 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 overly ing 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

13with calibration, where field observations should be replicated in the model. Any models that are used must be fu lly documented, with assumptions and methodology provided. A 5-year review interv al 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 da ta, 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...," a nd (c)(iii) to "consi der potential migration through faults, fractures and artificial penetra tions," provide the necessary info rmation 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 a pplication. EPA recognizes that in some instances, the Director may require add itional 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 conve rsion issues are not adequately addressed in the proposed regulation. The conversion of wells from enhanced oil recovery (EOR) or hazardous waste in jection to CO2 injection is vague.

Well construction and potential well conversi on issues need to be addressed in the regulations. All materials with the potential to come into contact with the injectate and/or the formation flui ds should be designed and tested to insure the materials’ integrity will be maintained and they will prevent movement of the injectate into a potentia l 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 suffici ent design review should be performed to insure that proper materials are us ed for all well cons truction. All wells used for injection and monitoring should be operated according to a periodic

maintenance schedule similar to ot her 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) re quires that all injec tion 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 consid er various aspects of the injec tion project, including injection pressure, external pressure, internal pressure and axial loading in §146.86(b)(1)(ii), corrosiveness

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

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

satisfaction that the converte d 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 re quirements 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 ava ilable for the Director to determine the risk posed to USDWs from a GS/ER project, and how th e 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/g roundwater/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 suffici ently 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 a nd 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 loggi ng, and in the event the well is retained, workover shou ld be performed.

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

CO2 should be made in the context of all availa ble information about the site and history of injection. The final GS rule prov ides for the construction of thes e wells to be grandfathered per §146.81(c), provided the owner or oper ator can demonstrate to the Director that the wells were engineered and constructed to meet the requi rements at §146.86(a) and ensure protection of USDWs, in lieu of requirem ents at §146.86(b) and §146.87(a).

EPA clarifies that other require ments (i.e., beyond the constructi on requirements) will not be grandfathered. Following conversion of the project to Class VI, ma ny of the unique factors of GS sites (e.g., increased reservoir pr essures 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 require ments in the final GS rule.

15Letter 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 beari ng 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 monitori ng wells should be designed to similar standards as injection well and will need pr essure shut-in equipment.

Clustered monitoring wells should be consid ered to allow a single borehole to be

used to monitor several different vertica lly discrete zones. For example, there is a potential that the inje ction 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, equipm ent should be installed, maintained, and tested on a designated fre quency 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 ow ners or operators to monitor for pressure changes in the injection zone. EPA be lieves 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 de tect 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, owne rs 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 qualit y monitoring required at §146.90(d)) to provide

additional verification that no pressure changes are occurrin g above the confining zone. Monitoring also identifies needed remedial actions, provides inputs for AoR reevaluation modeling, and targets additional geochemical a nd surface monitoring needs. Knowledge of the location of the CO2 plume and the associated pr essure 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 appr opriate actions to address any indication that USDWs may be endangered.

EPA acknowledges that, at certain sites, there ma y be a need for more or different monitoring schemes (which may include monitoring in the c onfining or buffer zones) , and adds that it is

16important to balance the need for adequate monitoring that ensures USDW protection from endangerment against too many artificial penetra tions which could serve as conduits for fluid migration. EPA expects site-speci fic testing and monitoring plan s to describe the proposed monitoring regime, which must be approved by th e Director. EPA recogni zes that wells with multiple completions (i.e., what the commenter re fers 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 a nd USDWs or other layers above the confining zone. Such construction technologies exist and have been us ed 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 inje cted 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 constr uction that will include reco mmendations for monitoring well construction. The guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e 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-injecti on timeframe (seeking comment)

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

considered a minimum and should be extende d in the event mon itoring 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 reasona ble and protective monitoring pe riod for most cases. EPA bases

this on a review of research studies, industry repo rts, 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 progr ams, and sufficiently protects USDWs from endangerment. For this reason, the final GS regula tion retains the 50 year pos t-injection site care timeframe, as specified in §146.93(b)(1).

17However, EPA disagrees that a 50- year post-injection s ite care timeframe should be an absolute minimum. Rather, EPA recognizes that there may be sites where the 50 y ear post injection site care timeframe may be either not appropriate ormore burdensome than necessary based on sitespecific conditions. For this reason, the GS rule o ffers owners or operators flexibility regarding

the duration of the PISC timefra me by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the post-in jection 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 ensu res 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 Direct or that the site no longer poses a risk of endangerment to USDWs.

EPA believes that a default post-injection site car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-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 fre quency (seeking comment)

Comment: Issue 12. The timeframe of Ar ea 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 re servoir is shown to maintain integrity.

The AoR should schedule be reevaluated annually during the fi rst 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 operato r 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 prot ection of USDWs from endangerment. For these reasons, the Agency changed the minimum freq uency 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,

18and the unique nature of CO2 GS. In addition, the Director has discre tion 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 reevaluati ons, EPA presumes the commenter is referring to the post-injection site care period. (EPA clarifie s 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 re medial 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, in cluding the nature of any moveme nt 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 emergenc y and remedial response plans for GS sites. EPA clarifies that, if the owner or operator obtains evidence th at 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, notif y the Director, and implement the approved emergency and remedial response plan (§146.94(b)).

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