This comment letter response contains two parts:

(1) The original submittal from the commenter. (2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA

‐ assigned comment code; and an

individual response. These are described and explained below.

• The data base contains Comment text from the letters submitted by commenters.

Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues. However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and

appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID. Additionally, one or more Comment Codes (i.e., unique topic area ID) was assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).

• Following decisions on the final rule requirements, Individual responses were drafted

by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments. Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response, compiled in the order of the original comment letter. As a result of this process, there is

repetition in the response text. The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.

Responses on each topic area are compiled and are also available in the rulemaking docket.Comments on Proposed Class VI UIC Rules Docket ID No. EPA-HQ-OW-2008-0390

Prepared by: Philip W. Papadeas, PG Sandia Technologies, LLC

6731 Theall Road

Houston, TX 77066

Tel: 832 286-0471 Phil.Papadeas@sandiatech.com

General Comments

Sandia Technologies, LLC provides the followi ng comments to U.S. EPA regarding the proposed Class VI UIC regulations, which in our judgment offer an excellent basis for regulating Geologic Sequestration projects and their anticipated large injectate volumes.

The foundation of these rules has been derive d from EPA’s highly successful Class I, Class II and Class V programs, which have a proven record of protecting groundwater and the near surface environment while managing large volumes of industrial aqueous waste. There are considerable areas in the rules which are vague in meaning and intent within portions of the proposed regulations.

A sub-category of wells may be considered for pure long-term disposal, without having to consider recovery of the injectate, and late r purification, etc. The direct line from stack gas to geologic reservoir should be considered as the total injectate, and if adequate well and surface materials are present then ther e should be no problem to dispose of the scrubber effluent, or gases direct into suitable geologic formations.

For long term disposal, or storage, well tubular requirements s hould be robust and manage potential impurities in the injection stream, with no limitations so long as proper injection pressures and well materials ar e sufficiently followed during operations.

Well Conversion An operator can potentially use a Class I permit to inject CO 2 , H 2 S, and NO 2 and utilize an established program which is considered more stringent and successful to not endanger USDWs or the public.

For Class I well operators who might want to convert an abandoned injection well to a Class VI well, should have an easier path to such due to the more stringent permit and diligence performed to obtain regulatory appr oval and permits. Historical operations have not endangered USDWs, therefore there is a direct connection to a ‘grandfather’ approach.

For grandfathering of Class II wells to Class VI designation, in my judgment Class II wells are not constructed very stringently si nce they are typically converted oil and gas

Sandia Technologies, LLC December 24, 2008 1wells which have outlived their useful live s in hydrocarbon production. Cement bond in the annulus and isolation is typically not as good as Class I we lls where continuous cement bond must be present allowing for

Geologic Characterization

EPA should allow an applicant to drill a site stratigraphic test well, convertible later to a Class VI injection well. All information should be provided, and utilized for modeling

the reservoir, with conserva tive model inputs and predicti ons for determining future operations.

§146.82 Re: Collection of detailed geologic data. The collection of this data is the operato r’s burden, and should be built on accumulation of all known geologic material in the area. Sandia believes this information is valuable for modeling, site characterization and geolog ic profile of the in jection-confinement system. If none is present, then the operato r must demonstrate via stratigraphic test or an information well all pertinent formation core s, not only of proposed permeable injection intervals, but overlying buffer intervals, confining zone cores, and formations that will act as hydraulic seals.

One proposed approach is for the Agency to make the first Pe rmitted injection well conditional, collecting th e required data and pr oviding this to the EPA under an adjusted permit to demonstrate that the data matches conservative assumptions used in reservoir and geologic modeling. The follow-up we lls should collect in -fill well data on geomechanics and confirm data obtained from the first well. Reduced data collection should be employed for all subsequent wells on the site, since adequate will exit from these early wells for the storage operator an d EPA to make a detailed assessment of the capability of the site.

This idea is similar to many approaches on ‘greenfield’ sites followed via Class I well Permitting by EPA. A secondary approach is for the operator to include this data acquisition into their project costs for strati graphic test data, cores, logs, pressures, reservoir testing to demonstrate the suitabili ty of the injection and confining horizons.

The burden

§146.82 (d) (2) Re: Faults transmissive or sealing? Whether faults are transmissive or sealing in the injection interval, or zone is immaterial, if the reservoir and injection interval can pass modeling scenarios using conservative assumptions successfully preventing fluid mi gration to the USDW, then these operational considerations should be used as the key threshold and benchmark for EPA’s geological evaluation. Class I operators are required to model both scenario s if data is not known or exists and this similar ap proach should be followed.

§146.82 (h) (i, j)

Sandia Technologies, LLC December 24, 2008 2Re: Compatibility testing should be perf ormed from cores and either native or synthesized formation fluid and injectate to determine and demonstrate potential reactivity of the injectate with formations, t ubular materials, and other waste or injectate mixtures. This is presently performed fo r all Class I hazardous wastes, and should be employed as a one-time initial testing progr am for new well operations and injection constituents, composition and properties.

§146.83 (a)(2) Re: Confining Zone free of transmissive faults This remains very difficult to prove or de monstrate in the subsurface unless detailed seismic and geologic data exists in the area to define such. One suggested approach may involve including a secondary buffer confin ing zone, as a redundancy to the first confining zone. The key may also be if there is connection from the Injection Zone to the Confining Zone, then additional modeling or reduction in injecti on rate/pressure and more of a margin of safety built in un less more detailed geological modeling demonstrates the lack of transmissive faulting.

§146.87 (f) Re: 30-day testing notification The requirements for 30-day notification should remain as such, the nature of drilling, workover, and testing is such that notification will not cover all testing. EPA or Agency notification of testing requireme nts, representative can witness the testing or be sent the data electronically with a summary fo r review, evaluation and concurrence.

§146.88 (a)(e)

Re: Fracture Pressure Fracture pressure determination should be key to EPA’s rule s, via geophysical measurements, physical rock cores sampli ng and determination, and openhole logs. There are sufficient tools and methods pres ent to evaluate the Confining Zone and Injection interval fracture gradients and de termine an appropriate operating range with safeguards present for operation pressure and injection rate.

Downhole shut off systems or valves are c onsidered necessary fo r Class I wells which operate with large volumes and in some cases greater pressures. The Agency should not specify the type of tubular and well operations system.

§146.90 (f) Re: Pressure Falloff testing of at least once every 5 years. This is of concern, since annual pressure test s are required for Class I operators, then why is the EPA diluting this requirement. As a cons ultant, I believe that for the first 5 years of established operation on the well, it should be installed as an annual requirement for Pressure Falloff testing, and thereafter, the operator can requ est from the Agency for once per 5-years. The behavior of buoyant carbon dioxide suggests more testing and monitoring and not less than Class I wells which have more safeguards present during operations.

Sandia Technologies, LLC December 24, 2008 3§146.90 (g) Re: Monitoring saline interval s above the Confining Zone. This monitoring approach may provide risk to USDWs, if monitor wells are drilled and

installed, and adds si gnificant burden, cost to the operator and uncertainties to the geologic system. One key question is however, what if no permeable intervals are present

to monitor? Does one monitor saline interv als, or shallow fresh water wells? The UIC program has worked well for many years with a stringent continuous cemented wellbore, and no migration of fluid as determined fr om annual testing, and operational pressure monitoring of the injection interval.

Close monitoring of injection pressure, and annual pressure falloff data will supercede a dedicated monitor well where pressure anom alies may exist due to pressure or some distant fluid injection or withdrawal in the shallow subsurface. In areas of depleted reservoirs or drawn down aquifers the pr essure effects monitoring may not indicate anything significant.

Calibrated reservoir and flow and containment models can predict the current and future pressure front as a result of the injectate. As with Class I modeling, a proper formation pressure gradient is required to assess a ba seline, which can determine all future storage capacity of the reservoir in the subsurface. By bounding the injectate via conservative assumptions offers the best chance to define the pressure front, and assess how large the potential area of revi ew may be necessary.

The CO 2 plume is likely to be highly variable in saturation and depends on the distance, location and depth considerations as well as original salinity and residual hydrocarbon

saturation. Seismic and or vertical seismi c profiling may offer the best approach to identifying where the highest satu ration is present. Pressure remains the better indicator,

distance from the wellbore.

§146.93 (a)(4)(b)(1) Re:Monitoring for 50 years How is the operator going to monitor for 50 years, when their facility is closed, bankrupt, or remains insolvent, while other sites adjacen t and in direct influence may remain active and operational? This time is not work-able, and should be consiste nt with EPA’s best analog, the 30-year post-closure rule fr om UIC Class I wells. Monitoring should continue only to the point when pressure dissipates to below minimum driving force pressures required to move fluid to a USDW.

50-year monitoring is severe, and has no basi s in other EPA operational considerations. No site continuity would be present, well operational records lost , and personnel retired with expertise dissipated.

Sandia Technologies, LLC December 24, 2008 4Letter ID: 0238 Commenter: Philip Papadeas Organization: Sandia Technologies, LLC

Letter ID: 0238 Comment ID: 23343 Letter Lines: 30 to 38

Comment Code: 1410 1.2.1 Comments in support of EPA/rulemaking

Comment: Sandia Technologies, LLC provides the followi ng comments to U.S. EPA regarding the proposed Class VI UIC regulations, whic h in our judgment offer an excellent basis for regulating Geologic Sequestration projects and their anticipated large injectate volumes. The foundation of these rules has been derived from EPA’s highly successful Class I, Class II and Class V programs, which have a proven record of protecting groundwater and the near surface environment while managing large volumes of industrial aqueous waste. There are considerable areas in the rules which are vague in m eaning and intent within portions of the proposed regulations.

Individual Response: EPA agrees that the UIC Program, under the authority of the SDWA, provides a strong framework for regulating injec tion of CO2 for GS and adds that the GS regulation tailors the UIC requireme nts to address the unique issues associated with large-scale GS including large injection volumes, the re lative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impu rities in captured CO2, and its mobility within subsurface geologic formations.

Letter ID: 0238 Comment ID: 23344 Letter Lines: 40 to 45

Comment Code: 1614 1.3.1.2 Impurities in captured CO 2; purity standards for CO2

Comment: A sub-category of wells may be considered for pure long-term disposal, without having to consider recovery of the inj ectate, and later puri fication, etc. The direct line from stack gas to geologic reservoir should be considered as the total injectate, and if adequate well and surface materials are present then there should be no problem to dispose of the scrubber effluent, or gases direct into suitable geologic formations.

Individual Response: The GS rule does not set generic purity standards for CO2 injectate streams (e.g., a percent CO2). Instead, the GS rule addresse s the quality and quantity of impurities by requiring owners or operators to submit information on the source of the CO2 and its physical and chemical propertie s. Specifically, the GS rule re quires the owner or operator to submit data about the site, including an analysis of the chemical and physi cal characteristics of the CO2 stream, as required at §146.82(a)(7)(iv), and informati on on the compatibility of the CO2 stream with fluids in the injection zone a nd minerals in both the in jection and the confining

zones and the materials used to construct the well, per §146.82(c)(3). This information can help the Director determine the potential for geoche mical reactions between the injectate (CO2) and

1the host geologic formations, which could result in the plugging of pore spaces or the dissolution

of formation minerals.

EPA clarifies that the GS rule applies only to wells injecting CO2 for the purpose of long-term

storage.

Letter ID: 0238 Comment ID: 23345 Letter Lines: 47 to 50

Comment Code: 3820 2.3.1 Well construction procedures

Comment: For long term disposal, or storage, we ll tubular requirements should be robust and manage potential impurit ies in the injection stream, with no limitations so long as proper injection pr essures and well materials are sufficiently followed during operations.

Individual Response: EPA agrees that tubular materials in Class VI wells must be suitable for handling the CO2 stream. The final GS rule at §146.86(c)(1), requires that tubing materials used

in Class VI wells meet or exceed standards developed by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. This requirement invokes the expertise of these bodies without the added burden of a certification program. The GS rule, at §146.86(c)(3)(ii), also requires the Director to consid er the characteristics of the CO2 stream (i.e., chemical content, corrosiveness, te mperature, and density) and formation fluids in approving the construction of a Class VI well.

Letter ID: 0238 Comment ID: 23346 Letter Lines: 52 to 62

Comment Code: 2062 1.5.3.1 Grandfathering construction of Class I wells (seeking comment)

Comment: Well Conversion

An operator can potentially us e a Class I permit to inject CO2, H2S, and NO2 and utilize an established program which is c onsidered more stringent and successful to not endanger USDWs or the public.

For Class I well operators who might want to convert an abandoned injection well to a Class VI well, should have an easier path to such due to the more stringent permit and diligence performed to obtain regulatory approval and permits. Historical operations have not endangered USDWs, therefore there is a direct connection to a ‘grandfather’ approach.

Individual Response: EPA agrees that many Class I wells are designed and constructed to withstand exposure to CO2. The final GS rule provi des for the construction of these wells to be grandfathered per §146.81(c), provid ed the owner or operator can demonstrate to the Director that the wells were engineered and constructed to meet th e requirements at §146.86(a) and

2ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). However, EPA clarifies that only the construction requirem ents are grandfathered a nd that all other Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a determination under §146.81(c).

Letter ID: 0238 Comment ID: 23347 Letter Lines: 64 to 69

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

Comment: For grandfathering of Class II wells to Class VI designation, in my judgment Class II wells are not constructed very stringently since they are typically converted oil and gas wells which have outlived their useful lives in hydrocarbon production. Cement bond in the an nulus and isolation is typically not as good as Class I wells where c ontinuous cement bond must be present allowing for

Individual Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given that the convert ed well will be used for a substa ntially different process, which involves increased reservoir pre ssures associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water. Th e final GS rule provides for the construction of these wells to be grandf athered (per 146.81(c)).

The final GS rule provides that the construction of these wells 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 protec tion of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are grandfathered and that all ot her Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following a determination under §146.81(c).

Letter ID: 0238 Comment ID: 23348 Letter Lines: 71 to 76

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

Comment: Geologic Characterization

EPA should allow an applicant to dril l a site stratigraphic test well, convertible later to a Class VI injec tion well. All information should be provided, and utilized for modeling the reservoir, with conservative model inputs and predictions for dete rmining future operations.

Individual Response: EPA anticipates that test wells will be drilled to support geologic site characterization of the proposed GS sites and can be used to collect subsurface samples, e.g. for laboratory determination of capillary pressure , and take other necessary measurements.

EPA believes that the requirements for geol ogic site characteri zation (at §146.82), AoR

3evaluation (§146.84), and testing of the well during drilling (§146.87) are appropriate to ensure that permitting authorities have the necessary inform ation to evaluate whether a specific site will allow safe injection of CO2.

Letter ID: 0238 Comment ID: 23349 Letter Lines: 78 to 103

Comment Code: 3130 2.1.3 Comments that operators s hould submit more (or different) geologic data than proposed

Comment: §146.82

Re: Collection of detailed geologic data. The collection of this data is the ope rator’s burden, and should be built on accumulation of all known geologic material in the area. Sandia believes this information is valuable for modeling, site characterization an d geologic profile of the injection- confinement system. If none is present, then the operator must demonstrate via stratig raphic test or an informa tion well all pertinent formation cores, not only of proposed permeable injection intervals, but overlying buffer intervals, confining zone cores, and formations that will act as hydraulic seals.

One proposed approach is for the Agency to make the first Permitted injection well conditional, collecting the required data and providing this to the EPA under an adjusted permit to demonstrate that the data matc hes conservative assumptions used in reservoir and geol ogic modeling. The follow-up wells should collect in-fill well data on geomechanic s and confirm data obtained from the

first well. Reduced data co llection should be employed fo r all subsequent wells on the site, since adequate will exit fro m these early wells for the storage operator and EPA to make a detailed assessment of the capability of the site.

This idea is similar to many approaches on ‘greenfield’ sites followed via Class I well Permitting by EPA. A secondary approach is for the operator to include this data acquisition into their project costs for stratigraphic test data, cores, logs, pressures, reservoir testing to demonstrate the suitability of the injection and confini ng horizons. The burden

Individual Response: EPA agrees and believes that the ex tensive requirements for geologic site characterization (at §146.82), AoR evaluation (§1 46.84), and testing of the well during drilling (§146.87) are appropriate to ensure that permitting authorities have the necessary information to evaluate whether a specific site will allow safe injection of CO2. EPA adds that submittal and review of monitoring data (as required at §146.90) and the AoR reevaluation process (§146.84(e)) will provide an opportunity for an ongoing review of the site and a dialogue

between the Director and the owne r or operator to ensure that th e project is being operated in a manner that protects USDWs from endangerment.

4EPA acknowledges that early pilot projects ma y focus on gathering data to inform GS technology. However, EPA believes that a detailed geological site characte rization of every GS site (as required under §146.82) is essential to evaluating the presence and adequacy of the various geologic features necessary to rece ive and confine injected CO2 for GS. The requirements for geologic site characterizati on are based on a long standing UIC regulatory framework developed to address specific risks to USDWs posed by injection. The Class VI GS requirements are tailored so that they are appr opriate for the unique natu re of injecting large volumes of CO2 into a variety of geological forma tions for long-term storage. EPA adds that, if

data on a formation or site collected in connect ion with an earlier proj ect can support a geologic characterization, the Director has discretion to accept this data, provi ded it is sufficient to demonstrate site suitability.

Letter ID: 0238 Comment ID: 23350 Letter Lines: 105 to 114

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

Comment: §146.82 (d) (2)

Re: Faults transmissive or sealing? Whether faults are transmissive or sealing in the injection interval, or zone is immaterial, if the reservoir and injecti on interval can pass modeling scenarios using conservative assumptions successfu lly preventing fluid migration to the USDW, then these operational considerations should be us ed as the key threshold and benchmark for EPA’s geological evaluati on. Class I operators are required to

model both scenarios if data is not known or exists and this similar approach

should be followed.

Individual Response: The Agency believes that the re quirement at §146.83(a)(2) that the confining zone to be free of transmissive faults or fractures is appropriate for Class VI wells and is necessary to ensure containment of the inject ate and that requiring the confining zone to be free of transmissive faults maximizes protec tion of USDWs from endang erment. EPA clarifies that geological data collected during site characterization, in cluding information on faults, will be used as inputs for AoR modeling. Modeling results , in concert with othe r site characterization information, will be used to determine if a site is appropriate for GS and will ensure protection of USDWs from endangerment.

Letter ID: 0238 Comment ID: 23351 Letter Lines: 116 to 122

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83)

Comment Code: 3860 2.3.3 Well component degradation

Comment: §146.82 (h) (i, j) Re: Compatibility testing should be perfor med from cores and either native or synthesized formation fluid and injectate to determine and demonstrate potential

5reactivity of the injectate with formations, tubular ma terials, and other waste or injectate mixtures. This is presentl y performed for all Class I hazardous wastes, and should be employed as a one-t ime initial testing program for new well operations and injection constitu ents, composition and properties.

Individual Response: EPA has revised subpart §146.82 so that the final regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and in formation to be submitted before operation of the well is authorized (at §146.82(c)).

Letter ID: 0238 Comment ID: 23352 Letter Lines: 124 to 133

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones (seeking comment)

Comment: §146.83 (a)(2) Re: Confining Zone free of transmissive faults This remains very difficult to prove or demonstrate in the subsurface unless detailed seismic and geologic data exis ts in the area to define such. One suggested approach may involve including a secondary buffer confining zone, as a redundancy to the first confining zone. The key may also be if there is connection from the Injection Zone to the Confining Zone, then additional modeling or reduction in injec tion rate/pressure and more of a margin of safety built in unless more detailed geological modeling demonstrates the lack of transmissive faulting.

Individual Response: EPA acknowledges that some smaller fractures may not be detectable during the site characterization pr ocess. Other requirements for GS injection wells and sites can mitigate the potential impacts of unidentified frac tures. These include limitations on injection pressures to avoid propagation of existing fractu res in the confining z one (§146.88(a)), collection and assessments of CO2 monitoring data at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through high-permeab ility regions (i.e., faults and/or fractures)

not detected in the initia l site characterization.

Letter ID: 0238 Comment ID: 23353 Letter Lines: 135 to 141

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: §146.87 (f) Re: 30-day testing notification The requirements for 30-day notification s hould remain as such, the nature of drilling, workover, and testing is such that notification wi ll not cover all testing. EPA or Agency notification of te sting requirements, re presentative can witness the testing or be sent the da ta electronically with a summary for review, evaluation and concurrence.

6Individual Response: EPA acknowledges the comment; the final rule retains this provision.

Letter ID: 0238 Comment ID: 23354 Letter Lines: 143 to 149

Comment Code: 4110 2.4.1.1 Injection pressure limitations

Comment: §146.88 (a)(e)

Re: Fracture Pressure Fracture pressure determinat ion should be key to EPA’ s rules, via geophysical measurements, physical rock cores sampli ng and determination, and openhole logs. There are sufficient tools and methods pres ent to evaluate th e Confining Zone and Injection interval fract ure gradients and determine an appropriate operating range with safeguards present for oper ation pressure and injection rate.

Individual Response: EPA agrees it is important to accura tely determine fracture pressure in setting permit limits for Class VI wells. The injec tion pressure limit for each GS project will be based on site-specific conditions and will be informed by data on the injection zone. During injection, the pressure in the injection zone must not exceed 90 percent of the fracture pressure of the injection zone, as specified at §146.88(a). The fracture pressure (and, therefore, the injection pressure) are based on site-speci fic geologic and geomechanical da ta collected during the site characterization process required at §146.82. Tests are available and have been used by injection well operators, e.g., Class I operators, to measure fracture pressure. Examples include the steprate test, in-situ stress tests, and a combina tion of a long spaced soni c log with laboratory measurement of the mechanical properties of cores. To meet the GS requirements, the permitting authority must set the injection pressure limit at no more than 90 percent of this value.

The Director will also review geologic, hydrogeologic, and geomechanical information submitted by the owner or operator in setting pe rmit conditions. If, based on this information, a lower pressure limitation is appropriate, the Director has the authority to set a lower limit in the operating permit. EPA clarifies that fracturing of the confining zone dur ing injection and/or stimulation is also prohibited at §146.88(a).

EPA is developing guidance on site characterization for GS projects to assist owners or operators in meeting the requirements of §146.82 and to assist directors in evaluating permit applications. The guidance will describe recommended approach es for characterizing the regional geology and hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and geophysical analyses of the injection and confin ing zone. EPA is also developing guidance for primacy agencies that will include recommended a pproaches for evaluating owner or operatorsubmitted data in setting permit conditions. The gu idance will be available on EPA's web site, at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0238 Comment ID: 23355 Letter Lines: 151 to 153

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

7Comment: Downhole shut off systems or valves are considered necessary for Class I wells which operate with large volumes and in some cases greater pressures. The Agency should not specify the type of tubular and well operations system.

Individual Response: After evaluating the risks and benefi ts of down-hole shut-off systems and considering additional research, EPA will not re quire automatic down-hole shut-off devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, the final rule, at §146.88(e)(2 ), requires that owne rs or operators of

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's

discretion to mandate automatic down-hole shut -off devices in onshore situations that may warrant their use. However, the Agency believ es that offshore Class VI wells present unique construction and operational conditi ons, including isolation from shorelines and the need to construct wells through the water column and the subsurface, which may delay response time in

the event of well difficulties. Th e rule requires, at §146.88(e)(3), that owners or operators of

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent subsurface fluid movement and ensure protection of USDWs.

Letter ID: 0238 Comment ID: 23356 Letter Lines: 155 to 163

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

Comment: §146.90 (f) Re: Pressure Falloff testing of at least once every 5 years. This is of concern, sin ce annual pressure tests ar e required for Class I operators, then why is the EPA diluting this requirement. As a consultant, I believe that for the first 5 years of established operati on on the well, it

should be installed as an annual requirement for Pressure Falloff testing, and thereafter, the operator can request from the Agency for once per 5-years. The behavior of buoyant carbon di oxide suggests more testing and monitoring and not

less than Class I wells which have more safeguards present during operations.

Individual Response: EPA believes that a frequency of at least once every five years, as specified at §146.90(f), is an appropr iate interval for pressure fall- off testing (particularly given the suite of tests operators will perform on the well and the site). EPA clarifies that the Director may require more frequent pressure fall-off tests at a specific proj ect, if necessary based on sitespecific circumstances. Pressure fall-off tests ma y be conducted in conjunction with other well performance tests (i.e., mechanical integrity testing) to ensure sa fe and effective operations. All monitoring data collected, including information from pressure fall-off tests, will be incorporated in AoR reevaluations, at l east every five years.

Letter ID: 0238 Comment ID: 23357 Letter Lines: 165 to 194

Comment Code: 4650 2.6.5 CO2 plume and pressure fr ont tracking (seeking comment)

8Comment: §146.90 (g) Re: Monitoring saline interval s above the Confining Zone. This monitoring approach may provide risk to USDWs, if monitor wells are drilled and installed, and adds significant burden, cost to the operator and uncertainties to the geologic system. On e key question is however, what if no permeable intervals are present to monitor? Does one monitor saline intervals, or shallow fresh water wells? The UIC program has worked well for many years with a stringent continuous cemented we llbore, and no migration of fluid as determined from annual testing, and oper ational pressure monitoring of the injection interval.

Close monitoring of injection pressure, and annual pressure falloff data will supercede a dedicated monitor well where pressure anomalies may exist due to pressure or some distant fluid inject ion or withdrawal in the shallow subsurface. In areas of depl eted reservoirs or drawn dow n aquifers the pressure effects monitoring may not indi cate anything significant.

Calibrated reservoir and flow and containm ent models can predict the current and future pressure front as a result of the injectate. As with Class I modeling, a proper formation pressure gradient is re quired to assess a baseline, which can determine all future storage capacity of the reservoir in the subsurface. By bounding the injectate via conservative assu mptions offers the best chance to define the pressure front, and assess how large the potential area of review may be necessary.

The CO2 plume is likely to be highly va riable in saturation and depends on the distance, location and depth considerati ons as well as original salinity and residual hydrocarbon saturation. Seismic and or vertical seismic profiling may offer the best approach to identifying wh ere the highest satura tion is present.

Pressure remains the better indicat or, distance from the wellbore.

Individual Response: EPA agrees that good site selec tion, modeling, and management are crucial elements of a successful GS project, but disagrees that this is an effective substitute for rigorous site monitoring. EPA disa grees that pressure fall-off test s are an appropriate substitute for monitoring pressure changes in the injection zone. Pressure fall-off tests provide information in the vicinity of the injection well(s) and meas ure pressure conditions wi thin the injection zone. Direct monitoring of pressure changes in the injection zone can provi de advance warning of

movement of CO2 or brine that mi ght ultimately endanger a USDW.

The Agency recognizes that while there are simila rities between injection of wastes for disposal (Class I) and GS (Class VI), there are signifi cant differences as well. Important unique considerations for GS include the buoyancy of CO2, its corrosivity when in contact with water, its low viscosity (i.e., high mobility), and the very large injection volumes that are anticipated. There is also a degree of uncertainty regarding the behavior of large volumes of CO2 in the subsurface after injection. Given these characteris tics of anticipated GS projects, EPA believes

9that plume and pressure front m onitoring at §146.90(g) are justifie d to provide early warning of any unforeseen fluid movement that might endanger USDWs.

The final rule (at §146.90(g)) requi res owners or operators to pe rform 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 tool s) are also required unless the Director determines, based on site-s pecific geology, that such methods are not appropriate.

EPA believes that pressure monitoring is necessa ry and for this reason, all GS well owners or operators must monitor pressure in the injec tion zone using direct methods (§146.90(g)(1)) to track the development and movement of the pressure front and CO2 plume. Monitoring can also identify needed remedial actions, provide i nputs for AoR reevaluation modeling, evaluate predictions of plume movement, and target additional geochemical and surface monitoring

needs.

Letter ID: 0238 Comment ID: 23358 Letter Lines: 196 to 202

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

Comment: §146.93 (a)(4)(b)(1) Re:Monitoring for 50 years How is the operator going to monitor fo r 50 years, when their facility is closed, bankrupt, or remains insolvent, wh ile other sites adjacent and in direct influence may remain active and operationa l? This time is not work-able, and

should be consistent with EPA’s best an alog, the 30-year post-cl osure rule from UIC Class I wells. Monitoring should continue only to the point when pressure

Individual Response: EPA disagrees that a post-injection si te care timeframe of 50 years is excessive. EPA proposed a default post-injectio n site care timeframe of 50 years based on a review of research studies, indus try reports, and existing environm ental programs. This analysis was included in an EPA-prepared background docume nt that is available in the federal docket, titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determination

of Area-of-Review and Potential Risk to Underground Sources of Drinking Water." EPA

assessed various default timeframes based on additional review of research studies and evaluation of public comments. While numerous commenters suggested th at EPA shorten the monitoring timeframe, none of the commenters provided sufficie nt data or other evidence to warrant a change in the proposed timeframe. Wh ile the 10- or 30-year timeframe suggested by some of these commenters may be within the timeframe suggested in some studies, there are circumstances (e.g., little development of mine ral trapping of CO2) under which the potential risks of endangering USDWs will likely not declin e within these timeframes. EPA believes that a 50 year post-injection site care timeframe repr esents a reasonable and protective monitoring period and available data do not support a different timeframe. Furthermore, EPA believes that a 50-year default post-injection s ite care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not exaggerate the risks asso ciated with GS, is consistent with other

10environmental programs, and sufficiently protects USDWs from endangerment.

EPA acknowledges the concerns of some commenters that there will be circumstances where it can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to USDWs. For this reason, the final GS regulation includes a provision that the Director may, at his/her discreti on, shorten the post-injection site care timeframe if the owner or operator can demonstrate that the GS project does not pose a risk to USDWs, as specified in §146.93(b)(2). Such a demonstration will be site-s pecific, and based on pressure monitoring and USDW impacts.

To the comment expressing concern about financia l responsibility, EPA rec ognizes that there are challenges associated with assuring funding for activities that will occur far in the future. However, the Agency believes that in order to protect USDWs from endangerment under the SDWA operators must demonstrate under §146.85 that financial resources are available to plug the injection well and provide post-injection site care at the point in time that the first CO2 is injected.. EPA is developing guidance on financial re sponsibility to assist owners or operators in evaluating the requirements of §146.85 and to as sist Directors in evaluating financial responsibility demonstrations. The guidance descri bes the types of financial mechanisms that operators may choose to use when evaluating th e financial responsibility requirements for GS

wells and it will also include a section on how to estimate costs to support accurate financial responsibility demonstrations. http://www.epa .gov/safewater/uic/well s_sequestration.htm.

EPA adds that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

Letter ID: 0238 Comment ID: 23359 Letter Lines: 202 to 204

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

Comment: UIC Class I wells. Monitoring should continue only to the point when pressure dissipates to below minimum dr iving force pressures required to move fluid to a

USDW.

Individual Response: EPA agrees that determinations abou t when post-injection site monitoring may be discontinued will be based on pressure observations. However, EPA clarifies that the non-endangerment demonstration s hould address more than changes in pressure; for example,

fluid movement within the subsurface must also be considered. EPA expects that the Director would consider the types of information the co mmenter describes in determining whether the plume and pressure front no longer pose a risk of endangerment to US DWs and post-injection site care monitoring may be discontinued.

Under the combined fixed timeframe and performance standard approach for Class VI wells, the post-injection site care timeframe may be reduced by the Director if the owner or operator can demonstrate that the remaining pressure front and plume no longer pose a risk of endangerment

11to USDWs. The non-endangerment finding is left to the discretion of the Director, based on sitespecific information such as plume movement, pressure decay, and the location of potential leakage pathways.

EPA adds that the final GS rule at §146.93(c), also allows the Director to approve an alternative post-injection site care timeframe where an owner or operator can demonstrate during the permitting process that an alternative post-injecti on site care timeframe, other than the 50 year default, is appropriate and ensu res non-endangerment of USDWs.

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the guidance will assist Directors in evaluating propo sed well plugging plans a nd post-injection site care and site closure plans under §146.92 a nd §146.93. The guidance describes recommended approaches for how an owner or operator coul d plug injection and m onitoring wells; perform post-injection monitoring; demonstrate the appropriateness of an alternative post-injection site care time frame; demonstrate non endangerment; and perform site closure activities. The guidance will be available at h ttp://water.epa.gov/type /groundwater/uic/wells_sequestration.cfm.

Letter ID: 0238 Comment ID: 23360 Letter Lines: 206 to 208

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

Comment: 50-year monitoring is severe, and ha s no basis in other EPA operational considerations. No site continuity would be present, well operational records lost, and personnel retired with expertise dissipated.

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

excessive and clarifies that th e record supports EPA’s final ap proach. EPA proposed a default post-injection site care timeframe of 50 years based on a revi ew of research studies, industry reports, and existing environmental programs. This analysis was included in an EPA-prepared background document that is available in the fe deral docket, titled "Com putational Modeling of Underground Injection of Carbon Dioxide for De termination of Area-of-Review and Potential Risk to Underground Sources of Drinking Water. " EPA assessed various default timeframes

based on additional review of research studi es and evaluation of public comments. While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the commenters provided sufficient da ta or other evidence to warra nt a change in the proposed timeframe. While the 10- or 30-year timeframe suggested by some of these commenters may be within the timeframe suggested in some studies, there are circumstances (e.g., little development of mineral trapping of CO2) under which the po tential risks of endangering USDWs will likely

not decline within these timef rames. EPA believes that a 50 year post-injection site care timeframe represents a reasona ble and protective monitoring pe riod and available data do not support a different timeframe. Furthermore, EPA believes that a 50-year default post-injection site care timeframe, as required at §146.93(b)(1), is not overly bur densome, does not exaggerate the risks associated with GS, is consistent with other environmental programs, and sufficiently protects USDWs from endangerment.

1213 EPA acknowledges that there will be circumstances where it can be demonstrated in less than 50 years that the plume and pressure front no longe r pose a risk of endangerment to USDWs. For this reason, the final GS regula tion includes a provision that the Director may, at his/her discretion, shorten the post-inj ection site care timeframe if the owner or operator can demonstrate that the GS project does not pose a risk to USDWs, as sp ecified in §146.93(b)(2). Such a demonstration will be site-specific, and based on pressure monitoring and USDW impacts.

EPA disagrees that a 50 year post- injection site care period would contribute to lack of site continuity or loss of operational records or staff expertise. EPA understands that changes in staff or ownership occur associated w ith all injection operations that operate over timeframes of several years or decades, and believes that ow ners and operators granted UIC permits have a responsibility to maintain con tinuity in expertise and data associated with the project.