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.1 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

73 FR 43497 1. EPA seeks comment on any aspects of the ongoing State efforts to regulate the GS of CO2 and how these efforts might be used to better inform a final Federal rulemaking. EPA

Notice 43497. APC supports the implementation of partial primacy for Class VI separately from other classes of wells.

73 FR 43502 2. Injection of CO2 for the purposes of enhanced oil and gas recovery (EOR/EGR), as long as any production is occurring, will continue to be permitted under the Class II program. EPA seeks comment on the merits of this approach since owners or operators of some Class II EOR/EGR wells may wish to use wells for the purposes of production and GS prior to the field being completely depleted.

EPA Notice 43502. While it was apparent in the preamble that the EPA intended to allow EOR operations to continue under current Class II regulations, the rules left some ambiguity to that distinction. In order to operate a successful recovery project it is imperative that the oil and gas regulators continue to govern EOR operations. APC offers language in our comments that would make this more explicit.

APC strongly supports the proposed approach and the absence of an economic test for oil and gas reservoir “depletion.” Recognizing though that EPA may face pressure to change its approach, APC offers language in our comments on the proposed rule for EPA’s consideration for differentiating between wells for EOR/EGR and sequestration.

Additionally, APC, along with the Multi-Stakeholder Discussion Group, supports the creation of a subclass under Class II (e.g “Class IIB”) for storage operations in hydrocarbon formations. See proposed section 146.25. By utilizing this approach operators avoid the potential complexity of switching agencies in the middle of a project (this is especially important given the sometimes conflicting jurisdiction shown between various regulating agencies within a state). Also, this allows for the different risk-profile of sequestration in an oil and gas reservoir to be taken into account and a different set of regulating requirements to be utilized.

146.81(c) 3. EPA seeks co mment on the approach to grandfather construction requirements at the

Director’s discretion fo r existing Class I, Class II, and Class V wells seeking to convert to Class

VI wells, and whether additional construction requirements would be necessary to prevent endangerment to USDWs from the GS of CO2.

EPA Notice 43502. APC strongly supports this provision. Candidate Class I and Class V wells for grandfathering will have a demonstrated record of performance under their existing operations and MIT programs to demonstrate sound performance and adequacy of well integrity that can be used as a basis for conversion to the Class VI program.

For Class II wells, APC, along with the MultiStakeholder Discussion Group, propose that they remain under the Class II program when transitioning from EOR to GS. Through the approach of two forms of sequestration, Class VI and Class II GS, the EPA

would eliminate some of the future confusion regarding grandfathering of requirements. EOR wells will have proven their inte grity and protection of USDWs during the operational phases of the flood through sound performance and MIT programs; and, therefore, the construction requirements proposed will not be necessary.2 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

In addition, many of the required well construction requirements, such as cement to surface, are truly not necessary. Industry has proven the successfulness of current well cement practices in 35 plus years of CO2 injection for EOR with an excellent environmental, health, and safety record. Through keeping these projects in the same regulating agency that governed the EOR opera tions it ensures that those regulators the most knowledgeable for working in oil and gas reservoirs are overseeing the regulatory requirements.

146.81(c) 4. Additionally , EPA seeks comment on how the grandfathering approach for existing wells may affect compliance with the other requirements in its proposal. EPA Notice

43502. All components of the existing wells with a proven record of performance should be grandfathered unless there are specific USDW endangerment concerns identified by the Director. Projects that are being converted to sequestr ation projects will have a significantly larger base-line data set than those pure sequestration projects. This should be taken into account when considering grandfathering provisions and plan requirements. See Comment above.

144.6(f)

146.5

146.81 5. EPA is proposing to preclude the injection of CO2 for long-term storage into coal seams where they are above the lowermost USDW. EPA requests comment on this proposed prohibition. EPA Notice 43503. APC opposes this restriction. Qualification of a formation for storage should be based on performance-based standards and site-specific considerations. It is more important to recognize that for those first pilot projects the Class V experimental well regulations may be better suited. However, if the data can be shown that USDW protection can be achieved through proper conf ining units and reservoir trapping mechanisms, injection into coal seams

above the lowermost USDW should be allowed.

144.6(f)

146.5

146.81 6. The location and proximity of other formations to USDWs may preclude their use for GS. EPA seeks comment on prohibiting injection into such formations if they are above

the lowermost USDW. EPA Notice 43503. Restricting injection to formations below the lowermost underground source of drinking water or USDW is not necessary fo r the protection of USDWs

and would remove a vast number of viable formations from consideration. Industry has shown that it can operate CO 2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone. Moreover, under the proposed rule, there ar e other measures that would provide real assurance of formation integrity and require operators to demonstrate that their project will not endanger USDWs, making the lowermost USDW restriction unnecessary.3 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

146.81(b)

146.81(d) 7. By defining “carbon dioxide stream” to

exclude hazar dous wastes ( 146.81(d)), EPA’s rule, if finalized, assures that it would apply only

to CO2 streams that are not hazardous wastes as defined in 40 CFR Part 261. As a result, EPA’s proposed rule would preclude the injection of hazardous wastes in Class VI injection wells. EPA seeks comment on this approach and other considerations associated with the presence of “impurities” in the CO2

stream. EPA Notice 43503. APC agrees with the concept that Class VI wells should not be injecting hazardous wastes but is proposing some modifications to EPA’s definition of

CO2 stream in the rule. The modifications reflect the

fact that the source of CO2 should not be a factor in the context of defining the CO2 stream. The rule applies to the injection of CO2 and should not address the origins of the materials since that is beyond the scope of this regulation. The original text would have precluded injection of CO2 from some sources. The question of how CO2 should be accounted for in a GHG management and accounting system is beyond the scope of this regulation.

More to the issue of “impur ities”, APC objects to any mandated purity standards for CO2. The inclusion of impurities in stored CO2 should not be arbitrarily prohibited; however, it is recognized that the presence of those impurities at sufficient concentrations may trigger the applicability of other statutory limits or requirem ents. Determining the type and levels of impurities in the CO2 stream is – absent a compelling public or environmental health risk – best left to contractual negotiations between partners in a CCS value chain as opposed to an arbitrary regulatory determination. The contracting parties are best able to evaluate the types of impurities, their compatibility with the reservoir and equipment, and determine the acceptable levels of those impurities in

the stored CO2. To the extent that there is an overriding public interest in limiting either the type or level of contaminants, prin ciples of cost-effectiveness and risk-management should guide the decision making process.

73 FR 43504 8. Cl ass VI requirements and permits will need to be carefully structured to ensure that they do not “authorize” inappropriate hazardous releases. This would include clarifying if there are potential releases from the well which are outside the scope of the Class VI permit. EPA requests comment on particular situations where this might occur. EPA notice 43504. Well chosen sites should prevent these conditions from occurring. At the same time, permit writers should not write permits so restrictive as to make the undertaking of a GS project untenable. EPA should remember that CERCLA liability will not only impact owners and operators of GS projects, but also hundreds, thousands, and even more numerous pore space owners. EPA should co nsider the threat of subjecting these pore space owners to CERCLA liability. Their property interests in the CO 2 GS project injection zones could subject them to strict, joint, and several liability under CERCLA pursuant to whatever liability theories might be conjured up by future litigants seeking compensation for response and remediation costs incurred in the cleanup of releases from geologic sequestration injection zones. EPA should recognize the significant chilling effect CERCLA liability concerns will have on GS projects, and seize the opportunity in this rulemaking to alleviate any CERCLA liability concerns to the greatest extent possible.4 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

73 FR 43504 9. EPA also re quests comment on other considerations associated with the presence of impurities in the CO2 stream related to

CERCLA. EPA Notice 43504. APC is concerned that potential CERCLA liabilities will have the potential to chill enthusiasm for undertaking GS projects. EPA needs to respond clearly and positively to this concern by developing appropriate language to provide the clarity and assurance needed to promote continued research and development for GS projects.

73 FR 43506 10. EPA’s prop osal would provide the Director the discretion to require the owner or operator to identify and characterize additional confining and containment zones above the primary (i.e., lowermost) confining zone that could further impede vertical fluid movement and allow for pressure dissipation. EPA says that these layers could provide additional sites for monitoring, mitigation, and remediation. EPA’s proposal would not require that these

additional zones be identified for all GS sites because their absence does not necessarily indicate inappropriateness of a GS site. However, if such zones are present, information

about their characteristic s can provide inputs for predictive models, identify appropriate monitoring locations, and improve public confidence in and acceptance of a proposed GS site. EPA specifically seeks comment on the merits of requiring the identification of these

additional zones. EPA Notice 43506. By utilizing the definiti on of confining zone (a geologic formation, group of formations, or part of a formation stratigraphically overlying the injection zone that acts as a barrier to fluid movement) the EPA has provided necessary guidance to prevent movement of fluids from the injection zone which may potentially endanger a USDW. The director discretion does not provide for any additional protection level of USDWs but does create issues and uncertainty by allowing the director to require

additional zones without scientific basis.

146.82(c)

146.84

146.90(d)(2) 11. EPA believes that predicting the complex multi-phase buoyant flow of the CO2, “co-injectates,” and compounds that may be mobilized due to injection requires the sophistication of computational models. EPA proposes that the owners or operators of GS wells be required to delineate the AoR for CO2 GS sites using computational fluid flow models designed for the specific site conditions and injection regime. EPA seeks comment on the use of modeling for AoR delineation. EPA

Notice 43506. Modeling is a well developed technology that can readily simulate complex behavior of injected CO2. It should be one of the techniques used to delineate the AoR. Modeling alone though should not be the sole basis for determining the AoR. Other technologies such as seismic and/or use of off-set wells, should also be considered when delineating the proposed AoR.

The oil and gas industry has a great deal of experience that can be generally applied in the

delineation of the AoR.

The most complex model is not always necessary to adequately delineate the AoR. Nor is it necessary to specify only one model as this would hinder the development of future models and techniques. Therefore, APC recomm ends that EPA provide flexibility in the rule to accommodate the use of future technologies and refrain from unnecessarily prescriptive measures.

146.84 12. In some cases, owners or operators may choose to use proprietary models (i.e., not available for free to the general public). EPA says it is aware that the use of proprietary codes may prevent full evaluation of model results (e.g., NRC, 2007). Several popular It is critical to allow proprietary models to be used.

EPA’s Confidential Business Information requirements should apply to any proprietary model

used. APC recommends EPA allow the use of proprietary models and clearly state that CBI5 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

codes in the petroleum-reservoir engineering discipline are proprietary and owners or operators of particular sites may prefer to use these codes as they have previous experiencewith them, and they have been used in peerreviewed studies to model CO2 sequestration. When using a proprietary model, owners or operators should clearly disclose the code assumptions, relevant equations, and scientific basis. EPA seeks comment on allowing the use of proprietary models for GS sites. EPA Notice

43507. requirements will apply.

While there has been concern raised on the current model’s ability to predict fluid flow in saline reservoirs, the development of technologies in this area will only progress when there is an economic driver that proprietary mo dels will provide. In addition, being able to see the assumptions and equations of the model will provide the regulating authority the ability to assess the models accuracy. The currently proposed regulations also contain requirements to revisit these models when the actual site data no longer supports the models conclusions, or at a minimum of every 10 years, which APC believes is sufficient to ensure the viability of the models and data generated from their use.

146.84 13. EPA seeks comment on the applicability of computational fluid flow models for delineating the AoR of GS sites. EPA Notice

43507. While computational fluid flow models can inform the delineation of the AoR, modeling shouldn’t be the sole criteria for determining AoR. (See Comments to

EPA Notice 43506 and 43507 above also.)

146.84 14. EPA seeks comment on requiring the reevaluation of the site AoR on a periodic basis,

under what conditions the AoR should be reevaluated, and the appropriateness of a 10- year minimum fixed frequency for AoR

reevaluation. EPA Notice 43507. Ten years is acceptable as long as reevaluation at this frequency is coupled with the ongoing duty to monitor for changes that would trigger an earlier

reevaluation of the AoR.

146.84(f) 15. EPA propose s to allow a phased approach to corrective action but says this may not be appropriate in all situations; therefore EPA is proposing that the Director have the discretion to decide to allow this approach, based on the understanding of relevant geologic and site conditions. EPA invites public comment on the merits and frequency of reevaluation of the AoR as well as the phased corrective action approach for GS wells. EPA

Notice 43508. APC supports the EPA proposal. The phased approach allows the sound economic execution of the project over time without endangering USDWs. This approach prevents an operator from remediating wells in an area that ultimately may not be affected by the storage project.

Allowing a phased approach for corrective action is also imperative for economic success of many projects. The upfront capital cost for sequestration will be extensive, and requiring corrective action upfront may be economically unfeasible. For instance Anadarko has spent over $10 million addressing historic wells at one of our EOR operations; this site is significantly smaller than those that may be involved in large sequestration projects. Therefore, allowing corrective actions in a phased manner will provide the flexibility needed to address operational and economic issues. Beyond the potential for significant economic expenditure, the availability of work-over rigs may also provide a difficult time-delay for starting sequestration projects.

Frequency of reevaluation should be based on site performance as noted in the prior comment.6 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

146.86(b) 16. EPA seeks co mment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a

cemented interval. EPA Notice 43509. Generally the surface casing is set below the lower USDW but it should be recognized that this is not appropriate in all geologic settings. In some areas USDWs can extend much greater depths than would be appropriate for setting of surface casing. Regulations should recognize these situations and allow for other methods of protecting USDWs

APC opposes the requirement for cementing the long string casing back to surface. Cementing requirements should focus on ensuring competent isolation and seal across the confining zone(s). Sealing the annulus between the long string and surface casing could limit an operators ability to monitor for leakage or conduct remedial operations.

Regarding packer setting depth, the director should retain discretion for allowing variation from this requirement.

146.81(c) 17. EPA also se eks comment on how the proposed grandfathering provisions for existing wells (construction requirements) may affect compliance with the above, proposed construction requirements. EPA Notice 43509. Anadarko does not believe the construction requirements above current Class II standards are necessary (in particular cement to surface). The purpose of grandfathering is to recognize that some wells may not meet construction requirements of Class VI wells, but the performance of Class II CO2 injection wells justifies their use as Class II CO2 Storage wells (“Class IIb”) or Class VI wells if EPA does not adopt a special subclass for storage under the Class II program. Class II EOR has proven successful at preventing co ntamination of USDWs. As mentioned in response to EPA Notice 43502, utilizing a sub-class of Cl ass II (Class II GS) would provide a means to handle the additional monitoring requirements from sequestration applications.

Grandfathering should be handled on a case-by-case basis. The standard for grandfathering should be demonstrated performance of the well at protecting

USDWs. Because the act of injection would be the same for CO2 EOR and CO2 storage, Class II CO2

EOR wells should be deemed to meet the requirements of 146.86 and 146.87 upon notification.

146.86 18. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicability of well construction requirements discussed in this proposal. EPA

Notice 43509. Drilling of directional and horizontal wells is a well established technology that can significantly reduce surface impacts of a GS project as well as improve injection rate of a well. Horizontal wells are currently being utilized in EOR operations and CO2 storage operations successfully.7 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

146.86

73 FR 43510 19. EPA seeks comment regarding requirements for degradation-resistant well

construction materials, such as acid-resistant cements and corrosion resistant casing. EPA

Notice 43510. The well should be looked at as a system such that not each individual component needs to be CO2 resistant as long as the entire system provides an

effective barrier under the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and

cements. Wells cemented with basic cement that have been exposed to CO2 for several decades have demonstrated minimal degradation and have been protective of USDWs (Reference: Crow. CO2 Capture Project Field Study of a Wellbore from a Natural CO2 Reservoir).

Industry experience over the past 35 years has led to the development of corrosion mitigation measures (e.g. plastic or epoxy lined tubing, use of corrosion inhibitors, and proper dehydration of CO2) that provide a high degree of protection and mitigate any corrosive effects of injected CO2.

146.88(a) 20. EPA is reque sting comment on the extent and scope to which hydraulic fracturing should be allowed during GS injection, and whether the use of fracturing for the purposes of well stimulation is ap propriate. EPA Notice

43511. The use of fracturing for stimulation should be allowed provided that t here is no damage to the confining unit that would result in endangerment of USDWs. Industry has de monstrated the ability to fracture injection zones without jeopardizing the integrity of the confining unit. There are computer simulators to predict fracture behavior so the impact on the confining zone can be anticipated and accounted for in designing any proposed operations involving fracturing.

73 FR 43511 21. EPA is also requesting information to better qualify the use of fracturing for GS injection in specific g eologic settings and rock formation lithologies. EPA Notice 43511. See response to EPA Notice 43511.

146.88(e) 22. EPA seeks comm ent on the merits of requiring down-hole shut-off valves in GS wells.

EPA Notice 43511. Over-pressure protection is best achieved by ensuring compatibility of th e casing/tubing material design strength with the surface injection (compression) system. Do wn-hole shut-in devices are not appropriate for this application. These

devises are installed in the tubing string and are typically near the surface of the well. They’re intended to seal the tubing in the event of catastrophic failure of the wellhead. These devises would provide little if any protection to USDWs. It is not practicable to install these devises deep within the well (e.g. shortly above the packer). Additionally these devises create a restriction on running other tools like logging tools in the well and therefore could limit an operator’s ability to perform required monitoring and diagnostic work. Lastly, these devises require periodic testing and maintenance which could require either pulling the devise by wireline or by pulling the entire tubing string depending on the type of devise installed. Either of these activities would be disruptive and costly to the8 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

overall project operations.

To address EPA’s concerns while maintaining the necessary operational fl exibility, APC recommends EPA allow for the installation of landing nipples at appropriate points in the tubing string which would allow use of wireline retrievable plugs when needed.

144.6(f)

146.5

146.81 23. EPA is aware that the proposed requirement of injecting CO2 below the lowermost USDW may preclude injection into certain targeted geologic formations, which may be storage sites currently under consideration for GS. As a result, the Agency is considering and requesting comment on alternative approaches that would allow injection between and/or above the lowermost USDW, and thus potentially allow for more areas to be available for GS while preventing USDW endangerment.

EPA Notice 43512. Injection above the lowest USDW should be allowed but the operator must de monstrate confinement above and below the injection formation. Retaining

the restriction would remove a vast number of viable formations from consideration. Industry has shown that it can operate CO 2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone. Moreover, under the proposed rule, there ar e other measures that would provide assurance regarding formation integrity and require operators to demonstrate that their project will not endan ger USDWs, making the lowermost USDW restriction unnecessary.

144.6(f)

146.5

146.81 24. EPA is soliciting comment on whether CO2 injection should be allowed into an injection zone above the lowermost USDW, when the Director determines that geologic conditions (e.g., thousands of feet of intervening formations between the injection zone and the overlying and/or underlying USDWs) exist that will prevent fluid move ment into adjacent

USDWs. EPA Notice 43512. See above response to EPA Notice 43512.

73 FR 43512 25. EPA is also requesting comments on whether aquifer exemptions should be allowed for the purpose of Class VI injection, and under what conditions should such aquifer exemptions be approved. EPA Notice 43512. There should be no changes to the aquifer exemption requirements in the UIC program as it exists today. Each aquifer exemption should be considered on a case-specific basis. However, there should also be no requirement that sequestration be below the lowest USDW (see comment to EPA Notice 43512 above).

73 FR 43512 26. EPA seeks comment on whether the Agency should set a minimum injection depth requirement for CO2 GS, rather than require that such injection take place below the

lowermost USDW. EPA Notice 43512. There should be no minimum depth for injection of CO2. The primary consideration should be protection of USDWs. A requirement for a minimum depth suggests an intent ion by EPA to require injection of CO2 in a supercritical phase. Such a requirement is not appropriate since there may be areas where injection of CO2 in other phases may be the only option. Again, site-specific evaluation and protection of USDWs should be the basis for determining depth of injection.9 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

73 FR 43513-

15 27. EPA’s proposal allows Directors’ discretion on whether to require the use of tracers, and if so, what types of tracers. EPA

seeks comment on the use of tracers in CO2 GS operations, and any potential impact of tracers on human health or ecosystems as they

relate to USDWs. EPA Notice 43513. EPA should not mandate the use of tracers. The value of tracers has been questioned by numerous members of the scientific community. Further

research of their use needs to be conducted before any final language is approved. Modeling and monitoring are much more reliable techniques for tracking a plume.

Tracers, in general, provide minimal diagnostic abilities and currently have few practical applications. This technology is still under development and as such should not be required. Currently, most tracers have the issue of providin g false positives, have a significant supply time-delay, have greater environmental impacts than CO2 (PFCs for instance), and are very expensive. Radioactive tracers are utilized the most in operations and prove the most useful, but again, only for a limited radius of investigation. Other monitoring techniques are more reliable and operational-friendly for tracking the plume and determining CO2 migration. While certain tracers can be useful for near-well trouble-shooting application this technology on a whole is not ready for field-wide deployment and any regulation mandating their use shoul d not be instituted.

146.89(b) 28. EPA’s proposal would require owners or operators of Class VI GS projects to monitor internal mechanical integrity of their injection wells by continuously monitoring injection pressure, flow rate, and injected volumes, as well as the annular pressure and fluid volume to assure that no anomalies occur that may indicate an internal leak. EPA requests comment on the practicability of this requirement. EPA Notice 43513. There is concern regarding what constitutes continuous monitoring. Anadarko agrees that regular monitoring of the parameters identified by EPA is appropriate. Our experienc e with CO2 EOR strongly shows that daily monitoring of most of these parameters is adequate (exceptions to this would be on a site-specific basis). Recording should generallybe done on a daily basis and reporting on a semiannual basis. As a guiding principle, the frequency of monitoring should be determined by the level of risk posed by the injection operation and should be set on a case-by-case basis at the permit approval stage taking into consideration the site-specific characteristics of the proposed project.

146,89(c)

146,90(e) 29. EPA seeks comment on the appropriate frequency of internal and external MITs for GS injection wells, the appropriate types of MITs, and how to optimize MIT methods for GS. EPA

Notice 43514. Timing for conducting MITs, should be based on risk and performance factors. Industry experience with CO2 EOR Class II program requires MITs every 5 years. This frequency has proven protective of

USDWs. Given the similarities between CO2 EOR wells and GS wells, APC recommends 5-year frequency in this case as we ll. The MIT should test integrity of the long string casing, packer, and tubing and to the extent practicable, should test the integrity of the cement isolating the injection zone. There are many methods for condu cting MITs. EPA should allow operators ad equate flexibility in selecting the appropriate methods for their specific situation. API RP90 provides good examples of methods for detecting mechanical failures, managing those risks, and conducting MITs.10 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

146.90 30. EPA seeks comment on the requirement for monitoring of GS sites for the purpose of tracking the location of the CO2 plume and associated pressure front over time.

EPA Notice 43514 The frequency of monitoring should be dictated by site-specific operational and geologic conditions combined with the results of monitoring with model predictions and should be set at the permit approval stage. The guiding principle for monitoring is to verify proper confinement of the CO2 and ensure protection of USDWs. EPA should recognize that use of modeling and other monitoring techniques are relatively qualitative proces ses that can have varying degrees of accuracy that wi ll improve over time in an iterative process, and EPA s hould provide regulatory flexibility to account for this.

146.90(f) 31. EPA’s proposal would require that owners or operators perform a pressure fall-off test at least once every five years. EPA seeks comment on the use and frequency of pressure fall-off testing for GS wells. EPA Notice 43515. We recommend that an initial falloff test be conducted upon completion of the well prior to any operational injection and after the first year of operational injection. Following the first year, the frequency should be at the discretion of the Director but the frequency should be aligned with the

reevaluation of the AoR.

146.90(g) 32. Based on information evaluated to date, EPA believes that tracking the plume and pressure front is an important companion step to address any uncertainties associated with initial AoR modeling and requests comment on this approach and more efficient alternatives that may be used to track the plume and pressure front. EPA Notice 43516. Plume and pressure front are different concepts and should not be confused. They yield information on two different metrics. The former tells you about the remaining capacity of the storage formation and the

latter describes the direction and movement of the CO2 plume. Based on experience to date, CO2 plume can be monitored using surface or wellbore seismic and possibly some remote satellite techniques. Monitoring of the pressure front will be more difficult since that requires data from the injection formation which can only be obtained by drilling a well. Modeling can estimate the movement of a pressure front. Those estimations are limited by the accuracy of the model and its iterative adjustments as previously mentioned.

73 FR 43517 33. EPA seeks comment on the appropriate amount and types of monitoring that should be conducted at a GS site. Specifically, EPA seeks comment regarding the usefulness of indirect geophysical monitoring and surface air and soil gas monitoring. In addition, EPA seekscomment regarding the use of a Directorapproved monitoring plan for GS sites. EPA

Notice 43517. Monitoring techniques and frequency should be determined on a site-specific basis. Selection of monitoring types and frequency should balance the potential risks posed by the project with the cost of monitoring.

Surface and soil gas monitoring does not add value to the protection of USDWs. Many of the surface and soil gas monitoring techniques currently being evaluated lack the track record necessary for use in a regulatory compliance setting. Moreover, the potential for false-positives could undermine public

confidence in GS technol ogies. EPA should defer on using surface and soil gas monitoring technologies

until their effectiveness can be demonstrated.11 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

146.90

146.93(a)

146.94(a) 34. EPA is proposing that permit applications for GS sites include several plans not currently required under existing UIC regulations. These plans include a monitoring and testing plan, an AoR and corrective action plan, and a post-injection site care and site closure plan. EPA seeks comment on the meritsof requiring plans for monitoring, AoR, and postinjection site care as part of a permit application. EPA Notice 43517. The development of plans is a good idea because it negates prescriptive regulati on of the process. APC is concerned that every modification of a plan may trigger a major permit modification. Although actual monitoring of injection formation is most effective, there is still the unintended consequence of penetrating the confining zone to gain that data. The number of monitoring wells should not be established in advance. It is unclear how monitoring well construction, operation, and closure will be regulated since these are not actual injection wells.

Timing of development of plans should be linked to the actual activity being addressed. It should not be necessary to prepare and s ubmit a site closure plan or the post-closure monitoring plan at the start of the project, particularly considering that these activities will not occur for many year s after the project starts.

146.91 35. EPA seeks comment on the frequency of all proposed report ing requirements. EPA

Notice 43517 Frequency should reflect the level of risk associated with the activity. Semi-annual reporting is adequate. Reporting should be on a project basis as opposed to a well basis consistent with 146.23(c).

146.91(c) 36. EPA seek s comment on the requirement for electronic reporting in its proposed rule. EPA Notice 43518. APC strongly supports the concept of electronic reporting. Industry’s objections to prior proposals for electronic reporting have been with the scope and breadth of information (incremental over written reports) that the Agency has previously proposed. Electronic reporting equivalent to existing written reports would be supported by APC. Until these concerns related to electronic reporting are resolved, such reporting may be encouraged but should not be required.

73 FR 43518 37. In addition to the above recordkeeping and reporting requireme nts, EPA considered a requirement for owners or operators of GS sites to provide an annual report during the lifetime of the project, including the post-injection period, regarding the GS operation. Although EPA has not included a requirement for this report in its proposal, EPA seeks comment regarding the necessity for such an annual report. EPA

Notice 43518. An Annual report is not necessary given the other reporting requirements in the Rule. The addition of this report would not produce any new pertinent information to the regulatin g agency; and, therefore, only increases their administrative burden on the agency and requires the g eneration of needless documents. In keeping with the provisions of the Paperwork Reduction Act, EPA should not require an annual report. Alternatively, if this report was to replace the other reporting requirements, there would be value to the proposal.12 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

73 FR 43519-

20

146.93(b) 38. EPA is proposing using a combination of fixed timeframe and a performance standard as described above. EPA is tentatively proposing a post-injection site care (monitoring) period of 50 years with Director’s discretion to change that period to lengthen or shorten the 50 year period if appr opriate. EPA requests comment on the proposed use of a tentative 50 year fixed timeframe that could be modified at the Director’s discretion based on monitoring and modeling data. EPA Notice 43519. APC strongly objects to the use of a 50-year default monitoring period. EPA offers no rationale for this arbitrarily-selected period of 50 years. Establishing a fixed and unusually long time period may create a significant barrier for operators considering entry into CCS operations. Criteria for determining the periodfor post-injection site care should be performancebased and a function of the site specific characteristics of a project such as project size, geologic factors, and relative risk of the project. (APC offers such criteria in the edits to §146.93(b)(3).)

Clear guidelines also need to be established regarding when operators have met the performance standards that determine site closure. Specifically, the standard that the project no longer poses an endangerment to USDWs needs to be defined using

reasonable risk-based criteria.

146.93 39. EPA is request ing comments on theproposed requirements for well plugging, postinjection site care, and site closure, including the proposed requirements for the post-injection time period. EPA Notice 43520. It is inappropriate to utilize a fixed period as this does not provide the flexibility to address site-specific issues; instead EPA should adopt a standard that is based on a demonstration of non-endangerment to determine when monitoring is no longer needed. Please see response to EPA 43519.

146.93(b)(2) 40. In additi on, EPA seeks comment on

whether the Director should be allowed to shorten the timeframe based on performance information, and whether EPA should require a shorter or longer post injection period if data suggests the time frame should be adjusted.

EPA Notice 43520. It is inappropriate to utilize a fixed period; instead a demonstration of non endangerment is an appropriate means of deciding when monitoring is no longer needed. Please see response to EPA 43519.

144.36 41. Current UIC guidance describes trust

funds as a form of financial assurance. The owner or operator may deposit funds into the trust fund in phases; that is, either over the term of the initial permit or over the remaining operating life of the injection well, as estimated in the well plugging plan, whichever period is

shorter. Because of t he possibility that the owner or operator may face financial distress prior to the trust being fully funded, EPA is considering a guidance approach that would recommend adopting a pay in period of three years for GS projects, consistent with other similar programs in the Agency. EPA Notice

43521. Industry should have a variety of options for meeting financial assurance based upon the companies’ discretion. Options should include self-insurance, insurance, surety bonds or other appropriate financial

instruments.13 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

73 FR 43521 42. Current UIC regulations for Class I hazardous waste injection allow for the use of insurance for purposes of demonstrating financial responsibility. However, insurance was not included as part of the guidance provided for Class II injection because this insurance mechanism was and still is, rarely used for the purpose of demonstrating financial assurance for injection wells. EPA is assessing whether to provide guidance on the use of insurance providers and, if so, whether to update eligibility requirements for insurers for GS wells consistent with other current Federal agency practices. EPA Notice 43521. See response to EPA Notice 43521.

73 FR 43522 43. EPA is assessing whether a financialratings threshold for all companies using a selfguarantee, similar to those used by other Federal agencies, is appropriate. The Agency also is considering what constitutes an appropriate financial rating threshold, and whether a financial rating greater than BBB or Baa (i.e., the current rating threshold established under the UIC regulations) is appropriate for GS well s. EPA Notice 43522. See response to EPA Notice 43521.

146.85 44. EPA is requesting comments on whether financial responsibility mechanisms to be recommended in EPA guidance should be adjusted in the manner described, whether additional instruments should be included, and whether other adjustments to the financial responsibility mechanisms should be considered, all subjec t to EPA’s authority under

the SDWA. EPA Notice 43522. See response to EPA Notice 43521.

73 FR 43522 45. The Agency is also requesting comment on allowing separate financial demonstrations to be submitted for the plugging of the injection well and for the post-injection site care requirements. EPA Notice 43522. See response to EPA Notice 43521.14 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

73 FR 43523 46. EPA request s comment on adopting the existing requirements for public participation at

40 CFR Part 25 and 40 CFR Part 124 and whether additional requirements should be included to reflect the availability of new tools for disseminating and gathering information. Such tools include cable networks, the Internet, and other new technology. EPA Notice 43523. The current provisions in Parts 25 and 124 are sufficient to inform the public. The EPA should not require new technology for involving the public. As technological advancements happen at an ever increasing rate, current po ssibilities may be obsolete in a few years. In addition, there is still a vast population in the country that are not comfortable with the newer technologies. While in some areas of the country these may be beneficial, in other areas they may not provide enough public engagement (or more importantly not enough local engagement). The Class VI program should involve public participation but should not dictate the method in which that is performed.

Public participation should be consistent across programs. If EPA believes the public participation requirements should be expanded, it should be done in a holistic manner across programs.

73 FR 43522-

23 47. EPA also requests comment on ways to enhance the public participation process, including engaging communities in the site characterization process as soon as candidate

locations are identified. EPA Notice 43523. While public participation is critical, bringing in public review before the project details are worked out can create unnecessary complications. APC does not believe that the public participation process should be extended to the site characterization stage of a GS project, particularly given that many sites might be characterized in the process of winnowing down the portfolio of potential sites.

73 FR 43523 48. To gain authority for Class VI wells, States, Territories, and Tribes will be required to show that their regulations are at least as stringent as, and may be more stringent than, the proposed minimum Federal requirements (e.g., inspection, operation, monitoring, and recordkeeping requirements that well owners or operators must meet). Such Primacy States,

Territories, and Tribes are authorized under

Section 1422 of the SDWA. EPA Notice 43523. Primacy should be granted for Class VI and Class IIGS well classifications. In addition, the primacy for Class VI should be granted independently of other well classes allowing the states to determine the appropriate regulating agency (Class II-GS will obviously be part of the current Class II program).

EPA should ensure that ad equate funding is provided for the delegated program.

73 FR 43523

73 FR 43529 49. There may be benefits to parsing out primacy for Class VI wells, however EPA has not made a decision on this. Allowing States, Territories, and Tribes to acquire primacy for only Class VI wells may encourage them to assume the responsib ility of implementation and provide for a more comprehensive approach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). EPA is seeking comment on the merits and possible disadvantages of allowing primacy approval for Class VI wells independent of other well classes. EPA Notice

43523. APC supports the implementation of partial primacy for Class VI separately from other classes of wells. The geologic variation across the country justifies partial primacy.15 Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response

144.36(a) 50. EPA pr oposes that Cla ss VI injection well permits would be issued for the operating life of the GS project including the post-injection site care period. EPA seeks comment on the merits of this approach. EPA Notice 43523. A permit for the life of the project would ensure the continuity of operations. Shorter time periods would yield administrative bur den without commensurate

benefits.

73 FR 43527 51. The Agency assumes three monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a signifi cant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption. EPA Notice 43527. It is difficult to select a realistic ratio since each site

will have its own charac teristics that would significantly affect the number of monitoring wells

necessary.

Please see the report submitted by API and prepared by ARI that discusses the cost modeling in greater

detail.

73 FR 43531 52. The public is invited to submit comments or identify peer -reviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration

of carbon dioxide. EPA Notice 43531. APC is not aware of anything unique about CO2 injection or its potential impacts on drinking water quality that would not be addressed within the existing drinking water program. The data EPA has on developing drinking water standards and MCLs

can be used in this situation.1RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalePart 144 1. The authority citation for part 144continues to read as follows:Authority: 42 U.S.C. 300f et seq.;Resource Conservation and RecoveryAct, 42 U.S.C. 6901 et seq.144.1 2. Section 144.1 is amended as follows:Adding new paragraph (f)(1)(viii); andb. Revising the first two sentencesin paragraph (g) introductory text.* * * * *(f) * * *(1) * * *(viii) Subpart H of this part sets forthrequirements for owners or operators ofClass VI injection wells.* * * * *(g)Scope of the permit or rulerequirement.The UIC Permit Programregulates underground injections by sixclasses of wells (see definition of ‘‘wellinjection,’’ § 144.3). The six classes ofwells are set forth in § 144.6. All ownersor operators of these injection wells mustbe authorized either by permit or rule bythe Director. * * *144.3Enhanced Oil Recovery (EOR) or enhanced gasrecovery (EGR) means any activity that usesfluids, gases or other means to improve orincrease extraction of hydrocarbons.The definition of EOR is necessary to supportfurther comments and discussion below.2RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale144.6 3. Section 144.6 is amended as follows:Revising paragraph (e); andb. Adding new paragraph (f).* * * * *(e)Class V.Injection wells not includedin Class I, II, III, IV, or VI. Specific typesof Class V injection wells are describedin § 144.81.(f)Class VI.Wells used for geologicsequestration of carbon dioxide beneaththe lowermost formation containing aUSDW.Sections 144.6, and 146.5 – Classification ofWells:(b) Class II. Wells which inject fluids:....(4) For enhanced recovery of oil or natural gaswhere geologic sequestration is occurring duringor in connection with enhanced recovery of oil ornatural gasprovided(i) there is reasonableexpectation of more than insignificant futureproduction volumes or rates as a result of carbondioxide injection and (ii) operating pressures areno higher than reasonably necessary to producesuch volumes or rates; and(5) For geologic sequestration in subsurfacegeologic formations in which extraction ofhydrocarbons has occurred,is occurring or isreasonably expected to occur and where thecriteria of paragraph (b)(4) are not met.(f) Class VI. Wells usedexclusivelyfor geologicsequestration of carbon dioxidestreams.beneath the lowermost formation containing aUSDWWells where geologic sequestration ofCO2 streams occurs during or in connection withEOR or EGR are regulated under Class II.The changes to (b) and (f) are to recognizethat EOR can have storage component, whichis consistent with EPA’s intent as expressedin the preamble and API’s October 27thmeeting with EPA. It is widely recognized thatCO2 based EOR can provide a significantearly opportunity for carbon storage. As EPAcorrectly recognizes, CO2 EOR operationscan have a significant storage componentthrough capillarytrapping or othermechanisms.Additionally, there should not be a blanketprohibition concerning injection aboveUSDW’s or at specific depths. This isespecially true given the possibility of changesin the definition of a USDW to includeformations greater than 10,000 parts permillion Total Dissolved Solids. Thisrequirement is not necessary for theprotection of USDWs and would remove avast number of viable formations fromconsideration. Industry has shown that it canoperate CO2 injection wells in an EORcontext without endangering USDWs that arelocated below the injection zone. An excellentexample is the Salt Creek EOR project inWyoming, which has a USDW below theinjection zone. Moreover, under the proposedrule, there are other measures that wouldprovide real assurance of formation integrityand require operators to demonstrate thattheir project will not endanger USDWs,making the lowermost USDW restrictionunnecessary.3RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale144.15 4. Adding § 144.15 to read as follows.§ 144.15 Prohibition of nonexperimental Class V wells forgeologic sequestration.The construction, operation ormaintenance of any non-experimentalClass V geologic sequestration well isprohibited.144.18 5. Adding § 144.18 to read as follows.§ 144.18 Requirements for classVI wells.Owners or operators of Class VIwells must obtain a permit. Class VIwells are not authorized by rule to inject.144.36 6. Section 144.36 is amended byrevising the first two sentences inparagraph (a) to read as follows:§ 144.36 Duration of permits.(a) Permits for Class I and Vwells shall be effective for a fixed termnot to exceed 10 years. UIC Permits forClass II, III and VI wells shall be issuedfor a period up to the operating life of thefacility. * * ** * * * *(a) Permits for Class I and V wells shall beeffective for a fixed termnot to exceed 10 years.UIC Permits for Class IIandIIIand VIwells shallbeissuedeffectivefor a period up to theoperating life of the facility.Permits for Class VIwells shall be effective for the period through siteclosure.Permits are necessary for Class VI wellsthrough the end of the post closure monitoringphase, which is consistent with the term siteclosure in the amended requirement.7. Section 144.39 is amendedby revising the second sentence inparagraph (a) introductory text and byrevising the second sentence inparagraph (a)(3) introductory text to readas follows:§ 144.39 Modification or revocationand reissuance of permits.* * * * *144.39 (a) * * * For Class I hazardouswaste injection wells, Class II, Class III or4RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleClass VI wells the following may becauses for revocation and reissuance aswell as modification; and for all otherwells the following may be cause forrevocation or reissuance as well asmodification when the permittee requestsor agrees. * * ** * * * *(3) * * * Permits other than forClass I hazardous waste injection wells,Class II, Class III or Class VI wells maybe modified during their terms for thiscause only as follows: * * ** * * * *144.51 8. Section 144.51 is amendedby revising the first sentence inparagraph (q)(1) and the first sentence inparagraph (q)(2) to read as follows:§ 144.51 Conditions applicable to allpermits.* * * * *(q) * * *(1) The owner or operator of aClass I, II, III or VI well permitted underthis part shall establish mechanicalintegrity prior to commencing injection oron a schedule determined by theDirector. Thereafter the owner oroperator of Class I, II, and III wells mustmaintain mechanical integrity as definedin § 146.8 and the owner or operator ofClass VI wells must maintain mechanicalintegrity as defined in § 146.89 of thischapter. * * *(2) When the Directordetermines thata Class I, II, III or VI welllacks mechanical integrity pursuant to §146.8 or § 146.89 for Class VI of thischapter, he/she shall give written noticeof his/ her determination to the owner or5RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleoperator. * * ** * * * *144.52 9. Section 144.52 is amendedby revising paragraph (a)(8) to read asfollows:§ 144.52 Establishing permitconditions.(a) * * *(8)Mechanical integrity. Apermit for any Class I, II, III or VI well orinjection project which lacks mechanicalintegrity shall include, and for any ClassV well may include, a conditionprohibiting injection operations until thepermittee shows to the satisfaction of theDirector under § 146.08 or § 146.89 forClass VI that the well has mechanicalintegrity.* * * * *144.55§ 144.55 Corrective action.(a)Coverage.Applicants forClass I, II, (other than existing), III or VIinjection well permits shall identify thelocation of all known wells within theinjection well’s area of review whichpenetrate the injection zone, or in thecase of Class II wells operating over thefracture pressure of the injectionformation, all known wells within the areaof review penetrating formations affectedby the increase in pressure. Applicantsfor Class VI shall perform correctiveaction as specified in § 146.84.* * ** * * * *6RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale144.80 11. Section 144.80 is amendedby revising the first sentence inparagraph (e) and by addingparagraph (f) to read as follows:§ 144.80 What is a Class V injectionwell?* * * * *(e)Class V. Injection wells notincluded in Class I, II, III, IV or VI. * * *(f)Class VI. Wells used forgeologic sequestration of carbon dioxide.(b) Class II. Wells whichinject fluids:......(2) forenhanced recovery of oil or natural gas; (3) ForEOR or EGR, and where geologic sequestrationof a carbon dioxide stream is occurring during orin connection with EOR or EGR operations oractivities;and (4) For storage of hydrocarbons....(f) Class VI. Wells usedexclusivelyfor geologicsequestration of carbon dioxidestreams.Wellswhere geologic sequestration of CO2 streamsoccurs during or in connection with EOR or EGRare regulated under Class II.See 144.6Part 146 12. The authority citation for part146 continues to read as follows:Authority: Safe Drinking WaterAct 42, U.S.C. 300fet seq.; ResourceConservation and Recovery Act, 42U.S.C. 6901et seq.146.5 13. Section 146.5 is amendedas follows:a. Revising the first sentence inparagraph (e) introductory text; andb. Adding paragraph (f).(f) Class VI. Wells used for geologicsequestration of carbon dioxide beneaththe lowermost formation containing anunderground source of drinking water(USDW).b) Class II. Wells which inject fluids:..... (4) Forenhanced recovery of oil or natural gas wheregeologic sequestration is occurring during or inconnection with enhanced recovery of oil ornatural gasprovided(i) there is reasonableexpectation of more than insignificant futureproduction volumes or rates as a result of carbondioxide injection and (ii) operating pressures areno higher than reasonably necessary to producesuch volumes or rates; and(5) For geologic sequestration in subsurfacegeologic formations in which extraction ofhydrocarbons has occurred,is occurring or isreasonably expected to occur and where thecriteria of paragraph (b)(4) are not met.(f) Class VI. Wells usedexclusivelyfor geologicsequestration of carbon dioxidestreams.Beneath the lowermost formation containing anunderground source of drinking water (USDW).Wells where geologic sequestration of CO2streams occurs during or in connection with EORSee 144.67RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleor EGR are regulated under Class II.146.23(a)(3) When, on an annual basis, the field-wideaverage CO2 injection to withdrawal ratio isgreater than 5.0 in an injection zone and theaverage reservoir pressurein the injection zonebecomes greater than (a) the average originalreservoir pressure in the injection zone at thetime of discovery of the reservoir, or (b) theaverage design operating pressure during CO2EOR or EGR, whichever is greater, the Directormay require the operator of a CO2 EOR or EGRproject permitted under Class II to provideadditional information and data to the Directorexplaining the necessity to increase or maintainsuch pressure.If the Director determines, based on site-specificcharacteristics that theinformation provided failsto support the need to increase or maintain theaverage reservoir pressurein the injection zoneabove the average original reservoir pressure, orthe average design operating pressure duringCO2 EOR or EGR, the Director may require theoperator to:(i) reduce or maintain the CO2 EOR or EGRproject’s field-wide average injection towithdrawal ratio to a value such that the averagereservoir pressure or average design operatingpressure during CO2 EOR or EGR within theinjection zone essentiallyremains constant; or(ii) apply to reclassify the CO2 EOR or EGRinjection wells and injection zone covered underthe Class II permit as a Geologic Sequestrationproject regulated under the applicable well class.If the operator fails to comply with any of theabove requirements, the Director may revoke ormodify the applicable Class II injection permit.A carbon dioxide stream or carbon dioxidemay be injected into a reservoir for EOR orEGR. When CO2 comes in contact with oil itdissolves into the oil, the oil swells, becomesless viscous and the surface tension betweenthe oil and the formation is reduced to such apoint that the oil becomes mobile. Theinjection of CO2 also raises the pressure inthe formation to a desired or designedoperating pressure. If achievable, the desiredoperating pressure will be above themiscibility pressure of the oil and CO2.Achieving sustained pressures at or above themiscibility pressure will generally allow themost efficient and effective recovery of theresidual oil remaining in the formation.Miscibility pressures are dependent on the oilproperties, carbon dioxide stream propertiesand the reservoir temperature. Thus,miscibility pressure may be less than theaverage original discovery pressure of thereservoir, or may be equal to or greater thanthe average original discovery pressure of thereservoir. The properties of some oils(generally heavier crudes) are such that themiscibility pressure of the oil and CO2 is far inexcess of the average original discoverypressure of the reservoir and can even begreater than the fracture pressure of thereservoir and/or the confining zone.Once the reservoir pressure reaches thedesigned or desired average reservoirpressure for the CO2 EOR project, theinjections of CO2 (or CO2 and water in wateralternating gas CO2 EOR projects) aremanaged such that the volumes of CO2 (orCO2 and water) being injected into thereservoir are generally equal to, or slightlygreater than, the volumes of fluids beingwithdrawn from the reservoir such that theaverage designed or desired operating8RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalereservoir pressure remains relatively constant.The desired or designed operating reservoirpressure may be altered from time to time, butthe process of raising the average reservoirpressure, and then holding the averagereservoir pressure relatively constant, is thesame.Therefore, except during periods of reservoirre-pressurization (i.e. the beginning of a CO2EOR project, or for a period of time when thedesigned or desired average reservoiroperating pressure is being raised), the ratioof the injected volumes (CO2 + water) to thewithdrawal volumes (CO2, oil, associatednatural gas and water) will most likely be lessthan 1.5. All volumes should be determinedat average reservoir conditions, or, at aminimum, at the same conditions (i.e. sameaverage pressures and temperatures).In contrast, a GS project whether occurringafter a CO2 EOR project or as a standaloneGS project is a project in which the primary,but not necessarily only, purpose is to injectand store a CO2 stream. Therefore, the ratioof injected volumes (CO2) to the withdrawalvolumes (CO2 + other formation fluids) shouldbe greatly in excess of 1.5 and more thanlikely an order of magnitude greater.In order to allow for reasonable fluctuationsand variations within CO2-EOR projects aninjection-withdrawal ratio of 5.0 (3 to 4 timesmultiple of typical injection-withdrawal ratios)is recommended to distinguish between CO2-EOR and Geologic Storage projects. Theinjection-withdrawal ratio should be measuredover the applicable reporting period requiredunder the applicable permit and will beevaluated on a field-wide basis compared to awell-by-well basis (which will allow for phaseddevelopment).9RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.25Geologicsequestrationin oil or gasreservoirswithoutenhancedrecovery ofoil or naturalgasWells used for geologic sequestration andmeeting the classification criteria of section146.5(b)(5) shall be subject to the followingrequirements:(a) Existing wells that meet or exceed theconstruction requirements of § 146.22 shall besubject to Part 146, Subpart H except sections146.86 and 146.87.(b) New wells must met the constructionrequirements of section 146.22 and are subjectto Part 146, Subpart H except sections 146.86and 146.87Details of what would be required of “ClassIIB” wells are to be worked out during futurediscussions of the Multi-StakeholderDiscussion Group (MSDG). However, APCoffers this language which is consistent withchanges APC had suggested beforediscussions with the MSDG began (seeSection 146.81(c)).Part 146Subpart H14. Subpart H is added to read asfollows:Subpart H—Criteria and StandardsApplicable to Class VI WellsSec.146.82 Required Class VI permitinformation.146.83 Minimum criteria for siting.146.84 Area of review and correctiveaction.146.85 Financial responsibility.146.86 Injection well constructionrequirements.146.87 Logging, sampling, andtesting prior to injection welloperation.146.81Applicability.(a) This subpart establishescriteria and standards for undergroundinjection control programs to regulateClass VI carbon dioxide geologicsequestration injection wells.10RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(b) This subpart applies to wellsused to inject carbon dioxide specificallyfor the purpose of geologicsequestration, i.e., the long-termcontainment of a gaseous, liquid orsupercritical carbon dioxide stream insubsurface geologic formations.(b) This subpart applies towells used to injectcarbon dioxideexclusivelyfor the purpose ofgeologic sequestration, i.e., the long-termcontainment of agaseous, liquid or supercriticalcarbon dioxide stream in subsurface geologicformations.It is recognized that some activitiesconducted under Class II, including CO2 basedEOR or EGR may sequester a portion of thecarbon dioxide stream used for EOR or EGR.This subpart does not apply to injection of acarbon dioxide stream for purposes of EOR orEGR even though geologic sequestration ofcarbon dioxide may occur during or in connectionwith EOR or EGR operations and/or activities.See 144.6Deleted “gaseous, liquid or supercritical”because it was added to the definition of CO2stream.(c) This subpart applies toowners and operators of permit or ruleauthorized Class I industrial, Class II, orClass V experimental carbon dioxideinjection projects who seek to apply for aClass VI geologic sequestration permitfor their well or wells. If the Directordetermines that USDWs will not beendangered, such wells are exempt, atthe Director’s discretion, from the casingand cementing requirements at §§146.86(b) and 146.87(a)(1) through (3).(c) ) This subpart applies to owners andoperators of permit or rule-authorized Class Iindustrial, Class II,or Class V experimentalcarbon dioxide injection projects who seek toapply for a Class VI geologic sequestrationpermit for their well or wells. If the Directordetermines that USDWs will not be endangered,such wells are exempt, at the Director’sdiscretion, from the casing and cementingrequirements at §§ 146.86(b) and 146.87(a)(1)through (3).The reference to Class II wells in section146.81(c) is no longer needed due to additionof 146.25.However, if EPA were not to adopt section146.25, APC would suggest the followingrevisions:(c) This subpart applies to owners andoperators of permit or rule-authorized Class Iindustrial, Class IIwho have ceased and willno longer continue EOR or EGR operations oractivities, or Class V experimental carbondioxide injection projects who seek to applyfor a Class VI geologic sequestration permitfor their well or wells. If the Directordetermines that USDWs will not beendangered, such wells are exempt, at theDirector’s discretion, from thecasing andcementing requirements at §§ 146.86(b) and146.87(a)(1) through (3).Class VIrequirements. Class II wells permitted for CO2injection and that have demonstrated MIT areexempt from the requirements at §§146.86and 146.87.The language allows for the transition of ClassII wells to Class VI operations. These wellsshould be allowed to inject CO2 for storagebased on their history of sound performanceunder the Class II program as demonstratedby MIT results. The language also allows the11RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleDirector to exercise discretion to exempt otherClass VI requirements.146.81(d)Definitions(d)Definitions.The followingdefinitions apply to this subpart. To theextent that these definitions conflict withthose in § 146.3 these definitions govern:Area of reviewmeans the regionsurrounding the geologic sequestrationproject that may be impacted by theinjection activity. The area of review isbased on computational modeling thataccounts for the physical and chemicalproperties of all phases of the injectedcarbon dioxide stream.Area of review means theregion surrounding thegeologic sequestration project that may beimpacted by the injection activity. The area ofreview is based on computational modeling thataccounts for the physical and chemicalproperties of all phases of the injected carbondioxide stream.subsurface three-dimensionalextent of the carbon dioxide plume, associatedpressure front, as well as the overlyingformations and surface area above thatdelineated region.Defining the AOR based on the extent of theCO2 plume and its associated pressure frontis a more direct approach, rather than theapproach offered by the EPA. The EPAdefinition suggests that the computationalapproach defines the AOR rather than thepotential risks of the injection activity.Carbon dioxide plumemeans theunderground extent, in three dimensions,of an injected carbon dioxide stream.Carbon dioxide streammeans carbondioxide that has been captured from anemission source (e.g., a power plant),plus incidental associated substancesderived from the source materials andthe capture process, and any substancesadded to the stream to enable or improvethe injection process. This subpart doesnot apply to any carbon dioxide streamthat meets the definition of a hazardouswaste under 40 CFR part 261.Carbon dioxide stream means carbon dioxide,which will be injected inany physical state ordissolved,and any associatedsubstancesderived from thethat has been captured from anemissionsource(e.g., a power plant), plusincidental associated substances derived fromthe source materials and the capture process,and any,its processing, orsubstances added toenable or improve the injection process. Thissubpart does not apply to any carbon dioxidestream that meets the definition of a hazardouswaste under 40 CFR part 261.Source of CO2 is not an issue in the contextof defining the CO2 stream. The rule appliesto the injection of CO2 and should notaddress the origins of the materials since thatis beyond the scope of this regulation.Original text would have precluded injection ofCO2 from some sources.12RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleConfining zonemeans a geologicformation, group of formations, or part ofa formation stratigraphically overlying theinjection zone that acts as a barrier tofluid movement.Corrective actionmeans the use ofDirector approved methods to assurethat wells within the area of review do notserve as conduits for the movement offluids into underground sources ofdrinking water (USDW).Geologic sequestrationmeans the longterm containment of a gaseous, liquid orsupercritical carbon dioxide stream insubsurface geologic formations. Thisterm does not apply to its capture ortransport.Geologic sequestrationmeans the long-termcontainment of agaseous, liquid or supercriticalcarbon dioxide stream in subsurface geologicformations. This term does not apply to itscapture or transport.Suggest removing "gaseous, liquid, orsupercritical" as these terms are included inthe term "carbon dioxide stream" as proposedto be modified by APC.Geologic sequestration projectmeans aninjection well or wells used to emplace acarbon dioxide stream beneath thelowermost formation containing a USDW.It includes the subsurface threedimensional extent of the carbon dioxideplume, associated pressure front, anddisplaced brine, as well as the surfacearea above that delineated region.Geologic sequestration projectmeans aninjection well or wellsused to emplace a carbondioxide streambeneath the lowermost formationcontaining a USDWinto an injection zoneexclusively for the purpose of geologicsequestration.It includes the subsurface threedimensional extent of the carbon dioxide plume,associated pressure front, and displaced brine,as well as the surface area above that delineatedregion.There should not be a blanket prohibitionconcerning injection above USDW’s or atspecific depths. This requirement is notnecessary for the protection of USDWs andwould remove a vast number of viableformations from consideration. Industry hasshown that it can operate CO2 injection wellsin an EOR context without endangeringUSDWs that are located below the injectionzone. An excellent example is the Salt CreekEOR project in Wyoming, which has a USDWbelow the injection zone. Moreover, under theproposed rule, there are other measures thatwould provide real assurance of formationintegrity and require operators to demonstratethat their project will not endanger USDWs,making the lowermost USDW restrictionunnecessary.Injection zonemeans a geologicformation, group of formations, or part ofa formation that is of sufficient a realInjection zonemeans a geologic formation, groupof formations, or part of a formationthat is ofsufficient a real extent, thickness, porosity, andExisting definition in the CFR is sufficient anddoes not need to be changed. Furthermore,adding the sufficiency requirement is not a13RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleextent, thickness, porosity, andpermeability to receive carbon dioxidethrough a well or wells associated with ageologic sequestration project.permeability to receivecarbon dioxidereceivingfluidsthrough a wellor wells associated with ageologic sequestration projectdefinitional issue and should be dealt withelsewhere.Post-injection site caremeansappropriate monitoring and other actions(including corrective action) neededfollowing cessation of injection to assurethat USDWs are not endangered asrequired under § 146.93.Post-injection site caremeansappropriatemonitoring and other actions (including correctiveaction)neededfollowing cessation of injectiontoassure that USDWs are not endangered, asrequired under §146.93.Deleted “appropriate” because the definitionof it is not clear.Deleted USDW phrase because it isincorporated in 146 requirements.Pressure frontmeans the zone ofelevated pressure thatis created by theinjection of carbon dioxide into thesubsurface. For the purposes of thissubpart, the pressure front of a carbondioxide plume refers to a zone wherethere is a pressure differential sufficientto cause the movement of injected fluidsor formation fluids into a USDW.Pressure frontmeans the zone of elevatedpressure that is created by the injection of thecarbon dioxidestreaminto the subsurface,Forthe purposes of this subpart, the pressure front ofa carbon dioxide plume refers to a zonewherethere is a pressure differential sufficient to causemovement ofinjected fluidsthe carbon dioxidestreamor formation fluidsfrom the injection zoneinto a USDW.Clarification.Site closurethe point/time, asdetermined by the Director following therequirements under § 146.93, at whichthe owner or operator of a GS site isreleased from post-injection site careresponsibilities.Site closuremeansthe point/time, as determinedby the Director following the requirements under§146.93, at which the owner or operator of a GSsiteprojectis released from post-injection sitecare responsibilities.“GS project” is consistent with otherdefinitions.Transmissive fault or fracturemeans afault or fracture that has sufficientpermeability and vertical extent to allowfluids to move between formations.Transmissive fault or fracturemeans a fault orfracture that has sufficient permeability andvertical extent to allow fluids to movebetweenformationsbeyond the confining zone.The term "between formations" is inaccuratesince there can be multiple formations within ainjection zone. The critical factor fortransmissivity is movement of injected ordisplaced fluids beyond the confining zone.146.82 Required Class VI permit informationThis section sets forth the informationwhich the owner or operator must submitto the Director in order to be permitted asa Class VI well. The application for apermit for construction and operation of aClass VI well must include the following:14RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.82(a) (a) Information required in 40 CFR144.31(e)(1) through (6);(b) A map showing the injectionwell(s) for which a permit is sought andthe applicable area of review. Within thearea of review, the map must show thenumber, or name and location of allinjection wells, producing wells,abandoned wells, plugged wells or dryholes, deep stratigraphic boreholes,State or EPA approved subsurfacecleanup sites, surface bodies of water,springs, mines (surface and subsurface),quarries, water wells and other pertinentsurface features including structuresintended for human occupancy androads. The map should also show faults,if known or suspected. Only informationof public record is required to be includedon this map;(b) A surface map showing theproposedlocations forthe injection well(s) for which apermit is sought and the applicable area ofreview. Within the area of review, the map mustshow the number, or name and location of allknowninjection wells, producing wells,abandoned wells, plugged wells or dry holes,deepstratagraphicboreholes, State or EPAapproved subsurface cleanup sites, surfacebodies of water, springs, mines (surface andsubsurface), quarries, water wells and otherpertinent surface features including structuresintended for human occupancy and roads.Themap should also show faults, if known orsuspected.Only information of public record isrequired to be included on this map;Faults are not shown on maps unless there isa surface expression of the fault. Also, faultsare detailed in (d) below and this languageappears redundant.Known needs to be added to remove anyimplication that an applicant has to conductstuides to determine wells that are notcurrently documented in some fashion.(c) The area of review based onmodeling, using data obtained duringlogging and testing of the well and theformation as required by paragraphs (l),(r), and (s) of this section;(c)A map delineatingthe area of review basedonuponmodeling, usingall availabledataincluding dataobtained during logging andtesting ofthe well and the formation as requiredby paragraphs (l), (r),and (s) of this sectionanywells in the area of reviewThis appears to be related to a conditionwhere a well is already drilled. This does notalign with requesting information to receive apermit.(d) Information on the geologic structureand hydrogeologic properties of theproposed storage site and overlyingformations, including:(1) Maps and cross sections of the areaof review;(2) Location, orientation, and propertiesof known or suspected faults andfractures that may transect the confiningzone(s) in the area of review and adetermination that they would not(d)Knowninformation on the geologic structureandhydrogeologicreservoirproperties of theproposed storage site and overlying formations,including:(1)Isopachmapsandof the proposed injectionand confining zone(s), astructural contour maphung on the top of the proposed injection zone,and at least two geologiccross sections of thearea of reviewshowing the geologic formationsfrom the surface to total depth.(2) Location, orientation,and properties of knownor suspectedsubsurfacefaultsand fracturesthatIf the information is not known, it cannot bereported.“Reservoir” and changes to (1) and (2) aretechnical corrections.Fractures generally can’t be identified until awell is drilled and evaluated. Even then, onlyfractures in the immediate vicinity of thewellbore can be identified.15RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleinterfere with containment; may transectthe confining zone(s) in the area ofreview and a determination that they would notinterfere with containment;(3) Information on seismichistory including the presence and depthof seismic sources and a determinationthat the seismicity would not interferewith containment;(4) Data on the depth, arealextent, thickness, mineralogy, porosity,permeability and capillary pressure of theinjection and confining zone(s); includinggeology/facies changes based on fielddata which may include geologic cores,outcrop data, seismic surveys, well logs,and names and lithologic descriptions;(5) Geomechanical informationon fractures, stress, ductility, rockstrength, and in situ fluid pressureswithin the confining zone; and(6) Geologic and topographicmaps and cross sections illustratingregional geology, hydrogeology, and thegeologic structure of the local area.(3) Information on seismic historythathave affected the proposed area of reviewincluding knowledge of previous seismic eventsand history of these events,including thepresence and depth of seismic sources and adetermination that the seismicity would notinterfere with containment;(4) Data on the depth, areal extent,thickness, mineralogy, porosity, permeability andcapillaryreservoirpressure of the injection andconfining zone(s)within the area of review;including geologic/facieschanges based on fielddata which may include geologic cores, outcropdata, seismic surveys, well logs, and names andlithologic descriptions;(5)Knowngeomechanical information onfractures, stress, ductility, rock strength, and insitu fluid pressures withinthe confining zone(s)within the area of review; andInformation on seismic history should havesome degree of relevance to the project.Deleted capillary pressure because it is toohard to measure outside of the lab. Usingsidewall cores, it may be difficult to determinecapillary pressure. Additionally, full cores arenot available until after the well beingpermitted is drilled.146.82(e) (e) A tabulation of all wells withinthe area of review which penetrate theinjection or confining zone(s). Such datamust includea description of each well’stype, construction, date drilled, location,depth, record of plugging and/ orcompletion, and any additionalinformation the Director may require;(e) A tabulation of allwellsartificialpenetrationswithin the area of review whichpenetrate the injection or confining zone(s).Such data must include a description of eachwell’s type, construction, date drilled, location,depth, record of plugging and/ or completion, andany additional information the Director mayrequire;Artificial penetrations is a more inclusive term.(f) Maps and stratigraphic crosssections indicating the general verticaland lateral limits of all USDWs, waterwells and springs within the area ofreview, their positions relative to theinjection zone(s) and the direction ofwater movement, where known;(f)Maps and stratigraphic cross sectionsindicating the general vertical and lateral limits ofall USDWs, water wells and springs within thearea of review, their positions relative to theinjection zone(s) and the direction of watermovement, where known;Potentiometric (waterlevel) surface map(s) of existing aquifers beingutilized as private or public water supplies andthe direction of groundwater flow in these16RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleaquifers within the area of review. At least twogeologic cross sections showing the thicknessand general vertical and lateral limits of allUSDWs within the area of review.(g) Baseline geochemical data onsubsurface formations, including allUSDWs in the area of review;(g)Baseline geochemical data on subsurfaceformations, including all USDWs in the area ofreviewCompilation of available geochemicaldata on the proposed injection zone and nearestporous and permeable formation above theconfining zone.Limits the data submitted to availableinformation and to the injection zone and thezone immediately above the confining zonewhich is the zones most likely to be monitoredfor potential CO2leakage.(h) Proposed operating data:(1) Average and maximum dailyrate and volume of the carbon dioxidestream;(2) Average and maximuminjection pressure;(3) The source of the carbondioxide stream; and(4) An analysis of the chemicaland physical characteristics of thecarbon dioxide stream;(h) Proposed operating data:(1) Average and maximum dailyinjectionrate and volume of the carbon dioxide stream;(2) Average and maximumsurfaceinjection pressure;Technical clarifications.146.82(i) (i) The compatibility of thecarbon dioxide stream with fluids in theinjection zone and minerals in both theinjection and the confining zone(s),based on the results of the formationtesting program, and with the materialsused to construct the well;(j) Proposed formation testingprogram to obtain an analysis of thechemical and physical characteristics ofthe injection zone and confining zone;17RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(k) Proposed stimulationprogram and a determination thatstimulation will not interfere withcontainment;(l) The results of the formationtesting program as required in paragraph(j) of this section;(m) Proposed procedure tooutline steps necessary to conductinjection operation;(n) Schematic or otherappropriate drawings of the surface andsubsurface construction details of thewell;(o) Injection well constructionprocedures that meet the requirementsof § 146.86;(n)A wellboreschematicor otherappropriate drawings of the surface andof thesubsurface construction detailsof the wellandsurface wellhead construction.Technical clarification.(p) Proposed area of review andcorrective action plan that meets therequirements under § 146.84;(q) The status of correctiveaction on wells in the area of review;(r) All available logging andtesting program data on the well requiredby § 146.87;(s) A demonstration ofmechanical integrity pursuant to§ 146.89;(t) A demonstration, satisfactoryto the Director, that the applicant has metthe financial responsibility requirementsunder § 146.85;q)TheAnystatus of corrective action on wells inthe area of review;Clarifies that wells not needing correctiveaction will not have a corrective action status.146.82(u) (u) Proposed testing andmonitoring plan required by§ 146.90;(v) Proposed injection wellplugging plan required by§ 146.92(b);18RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(w) Proposed post-injection sitecare and site closure plan required by §146.93(a);(x) Proposed emergency andremedial response plan required by §146.94; and(y) Any other informationrequested by the Director.146.83 Minimum criteria for siting(a) Owners or operators of ClassVI wells must demonstrate to thesatisfaction of the Director that the wellswill be sited in areas with a suitablegeologic system. The geologic systemmust be comprised of:(1) An injection zone of sufficientareal extent, thickness, porosity, andpermeability to receive the totalanticipated volume of the carbon dioxidestream;(2) A confining zone(s) that isfree of transmissive faults or fracturesand of sufficient areal extent and integrityto contain the injected carbon dioxidestream and displaced formation fluidsand allow injection at proposedmaximum pressures and volumeswithout initiating or propagating fracturesin the confining zone(s); and(2) A confining zone(s) that islaterally continuousandfree ofknown transecting,transmissive faultsor fracturesand of sufficient areal extent andintegrity to contain the injected carbon dioxidestream and displaced formation fluids and allowinjection at proposed maximum pressures andvolumes without initiating or propagatingfractures in the confining zone(s); andover anarea sufficient to prevent the movement ofinjected or displaced fluids into a USDW;The proposed clarification keeps theemphasis on the non-endangerment ofUSDWs and limits the requirements to thatwhich is known or can be readily determined.(b) At the Director’s discretion,owners or operators of Class VI wellsmust identify and characterize additionalzones that will impede vertical fluidmovement, are free of faults andfractures that may interfere withcontainment, allow for pressuredissipation, and provide additionalopportunities for monitoring, mitigationand remediation.(b) At the Director’s discretion, owners oroperators of Class VI wells must identify andcharacterize additional zones that will impedevertical fluid movement, are free of faults andfractures that may interfere with containment,allow for pressure dissipation, and provideadditional opportunities for monitoring, mitigationand remediation.This paragraph creates a presumption thatadditional confining zones WILL be required.It is also redundant given the previoussections.19RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.84 146.84. Area of review and correctiveaction(a) The area of review is theregion surrounding the geologicsequestration project that may beimpacted by the injection activity. Thearea of review is based on computationalmodeling that accounts for the physicaland chemical properties of all phases ofthe injected carbon dioxide stream.(a) The area of review is theregion surroundingthe geologic sequestration project that may beimpacted by the injection activity. The area ofreview isbased on computational modeling thataccounts for the physical and chemicalproperties of all phases of the injected carbondioxide stream.subsurface three-dimensionalextent of the carbon dioxide plume, associatedpressure front, as well as the overlyingformations and surface area above thatdelineated region.Edits make this provision consistent with thedefinition of “Area of Review”, which wasrevised.(b) The owner or operator of aClass VI well must prepare, maintain,and comply with a plan to delineate thearea of review for a proposed geologicsequestration project, periodicallyreevaluate the delineation, and performcorrective action that meets therequirements of this section and isacceptable to the Director. As a part ofthe permit application for approval by theDirector, the owner or operator mustsubmit an area of review and correctiveaction plan that includes the followinginformation:(1) The method for delineatingthe area of review that meets therequirements of paragraph (c) of thissection, including the model to be used,assumptions that will be made, and thesite characterization data on which themodel will be based;(b) The owner or operator of a Class VI well mustprepare, maintain, and comply with a plan todelineate the area of review for a proposedgeologic sequestration project,periodicallyreevaluate the delineation, and performcorrective action that meets the requirements ofthis sectionand isin a manner and at afrequencyacceptable to the Director. As a part ofthe permit application,for approval by theDirectorthe owner or operator must submit anarea of review and corrective action plan thatincludes the following information:Clarification.146.84(b)(2) (2) A description of:(i) The minimum fixed frequency,not to exceed 10 years, the owner oroperator proposes to reevaluate the areaof review;(ii) The monitoring andoperational conditions that would warranta reevaluation of the area of review priorto the next scheduled reevaluation asdetermined by the minimum fixed(i) The minimum fixed frequency, not to exceed10 years, the owner or operator proposes toreevaluate the area of review;(ii) The monitoring and operationalconditions that would warrant a reevaluation ofthe area of review prior to the next scheduledreevaluation as determined by the minimum fixedfrequency established in paragraph (b)(2)(i) ofthis section.20RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalefrequency established in paragraph(b)(2)(i) of this section.(iii) How monitoring andoperational data (e.g., injection rate andpressure) will be used to inform an areaof review reevaluation; and(iii)(i)How monitoring and operational data (e.g.,injection rate and pressure) will be used to informan area of review reevaluation; and(iv) How corrective action will beconducted to meet the requirements ofparagraph (d) of this section, includingwhat corrective action will be performedprior to injection and what, if any,portions of the area of review will havecorrective action addressed on a phasedbasis and how the phasing will bedetermined; how corrective action will beadjusted if there are changes in the areaof review; and how site access will beguaranteed for future corrective action.(ivii) How corrective actionwill be conducted tomeet the requirements of paragraph (d) of thissection, including whatcorrective action will beperformed prior to injection and what, if any,portions of the area of review will have correctiveaction addressed on a phased basis and how thephasing will be determined; how corrective actionwill be adjusted if there are changes in the areaof review; and how site access will beguaranteedarrangedfor future corrective action.Future access cannot be guaranteed for anarea in advance that may not even be withinthe boundaries of the AOR/ project.146.84(c) (c) Owners or operators of ClassVI wells must perform the followingactions to delineate the area of review,identify all wells that require correctiveaction, and perform corrective action onthose wells:(1) Predict, using computationalmodeling, the projected lateral andvertical migration of the carbon dioxideplume and formation fluids in thesubsurface from the commencement ofinjection activities until the plumemovement ceases, pressure differentialssufficient to cause the movement ofinjected fluids or formation fluids into aUSDW are no longer present, or after afixed time period as determined by theDirector. The model must:(1) Predict, using computational modeling, theprojected lateral and vertical migration of thecarbon dioxide plume and formation fluids in thesubsurface from the commencement of injectionactivities until the plume movement ceases,pressure differentials sufficient to cause themovement of injected fluids or formation fluidsinto a USDW are no longer present, orafterforafixed time period as determined by the Director.Themodelmodelingmust:Clarification146.84(c)(i) (i) Be based on detailed geologicdata collected to characterize theinjection zone, confining zone and anyadditional zones; and anticipatedoperating data, including injectionpressures, rates and total volumes over(i) Be based on detailed geologic data collectedto characterize the injection zone, confining zoneand any additional zones; and anticipatedoperating data, including injection pressures,rates and total volumes overthe proposed life ofthe geological sequestration projectthe durationClarification.21RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalethe proposed life of the geologicalsequestration project;(ii) Take into account anygeologic heterogeneities, data quality,and their possible impact on modelpredictions; and(iii) Consider potential migrationthrough faults, fractures, and artificialpenetrations.of injection;(ii) Take into accountanyrelevantgeologicheterogeneities,anddata quality, and theirpossible impact on model predictions; and(2) Using methods approved bythe Director, identify all penetrations,including active and abandoned wellsand underground mines, in the area ofreview that may penetrate the confiningzone. Provide a description of eachwell’s type, construction, date drilled,location, depth, record of plugging and/orcompletion, and any additionalinformation the Director may require; and.(2) Using methods approved by the Director,identify allknown artificialpenetrationsinto theconfining zone, including active and abandonedwells and underground mines, in the area ofreview that may penetrate the confining zone.Provide a description of each well’s type,construction, date drilled, location, depth, recordof plugging and/or completion, and any additionalinformation the Director may require; andChanged for consistency with earlierlanguage.(3) Determine which abandonedwells in the area of review have beenplugged (as required by § 146.92) in amanner that prevents the movement ofcarbon dioxide or associated fluids thatmay endanger USDWs(3) Determine which abandoned wellsidentifiedin 146.84 (c) (2)in the area of reviewhave beenplugged (as required by §146.92) in a mannerthat prevents the movementof carbon dioxide orassociatedformationfluids that may endangerUSDWs.Remove as redundant.146.84(d) (d) Owners or operators of ClassVI wells must perform corrective actionon all wells in the area of review that aredetermined to need corrective actionusing methods necessary to prevent themovement of fluid into or betweenUSDWs including use of corrosionresistant materials, where appropriate.(d) Owners or operators of Class VI wells mustperform corrective actionusing materials suitablefor use with the carbon dioxide stream andformation fluids,on all wellsin the area of reviewidentified in 146.84(c)(2)that are determined toneed corrective action”.using methodsnecessary to prevent the movement of fluid intoor between USDWs including use of corrosionresistant materials, where appropriate.Experience with CO2 based EOR stronglysupports the use of many conventionalmaterials that might not meet the technicaldefinition of “corrosion resistant”.(e) If monitoring data indicate anendangerment to USDWs, the owner oroperator must notify the Director andcease operations as required by §146.94.(e) If monitoring data indicate an endangermentto USDWs, the owner or operator must notify theDirector and cease operations as required by §146.94.This is not needed if §146.94 alreadyspecifies the notification and cessation ofinjection. APC suggests the removal of thislanguage as unnecessarily duplicative.22RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(f) At the minimum fixedfrequency, not to exceed 10 years, asspecified in the area of review andcorrective action plan, or whenmonitoring and operational conditionswarrant, owners or operators must:(1) Reevaluate the area ofreview in the same manner specified inparagraph (c)(1) of this section;(2) Identify all wells in thereevaluated area of review that requirecorrective action in the same mannerspecified in paragraph (c)(2) of thissection;(f) At the minimum fixed frequency, not to exceed10 years, as specified in theapprovedarea ofreview and corrective action plan, or whenmonitoring and operational conditions warrant,owners or operators must:Clarification.(3) Perform corrective action onwells requiring corrective action in thereevaluated area of review in the samemanner specified in paragraph (c)(3) ofthis section; and(4) Submit an amended area ofreview and corrective action plan ordemonstrate to the Director throughmonitoring data and modeling resultsthat no amendment to the area of reviewand corrective action plan is needed.(4) Submit an amended area of review andcorrective action plan or demonstrate to theDirector through monitoring data and modelingresults that noamendmentchangeto the area ofreview and corrective action plan is needed.Clarification.146.84(g) (g) The emergency and remedialresponse plan (as required by § 146.94)and a demonstration of financialresponsibility (as described by § 146.85)must account for the entire area ofreview, regardless of whether or notcorrective action in the area of review isphased.146.85 146.85 Financial responsibility(a) The owner or operator mustdemonstrate and maintain financialresponsibility and resources forcorrective action (that meets therequirements of § 146.84), injection wellplugging (that meets the requirements of§ 146.92), post-injection site care and23RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalesite closure (that meets the requirementsof § 146.93), and emergency andremedial response (that meets therequirements of§ 146.94) in a manner prescribed by theDirector until:(1) The Director receives andapproves the completed post-injectionsite care and site closure plan; and(2) The Director determines thatthe site has reached the end of the postinjection site care period.(1) The Director receiveswell plugging reportidentified in 146.92(d) and approvesorcompletion ofthecompletedpost-injection sitecare and site closure planas appropriate; andMaintenance of the well plugging financialobligation until site closure is not necessary.The Director should have the authority torelease the obligation once the well isplugged.(b) The owner or operator mustprovide to the Director, at a frequencydetermined by the Director, writtenupdates of adjustments to the costestimate to account for any amendmentsto the area of review and correctiveaction plan (§ 146.84), the injection wellplugging plan (§ 146.92), and the postinjection site care and site closure plan(§ 146.93).(b) The owner or operator must provide to theDirector, at a frequency determined by theDirector,but no more than annually, writtenupdates of adjustments to the cost estimate toaccount for anyamendmentschangeto the areaof review and corrective action plan (§146.84),the injection well plugging plan (§146.92), andthe post-injection site care and site closure plan(§146.93).Updates more frequent than annual is notjustified.146.85(c) (c) The owner or operator mustnotify the Director of adverse financialconditions such as bankruptcy, that mayaffect the ability to carry out injection wellplugging and post-injection site care andsite closure.(c) The owner or operator must notify the Directorof adverse financial conditionssuch asbankruptcy, that may affect the ability to carry outinjection well plugging and post-injection sitecare and site closure.Clarification.(d) The operator must provide anadjustment of the cost estimate to theDirector if the Director has reason tobelieve that the original demonstration isno longer adequate to cover the cost ofinjection well plugging (as required by §146.92) and post-injection site care andsite closure (as required by § 146.93).(d) The operator must provide an adjustment ofthe cost estimate to theDirector if the Directorhas reason to believe thatoriginalthe mostrecentdemonstration is no longer adequate tocover the cost of injection well plugging (asrequired by §146.92) and post-injection site careand site closure (as required by §146.93)Clarification.24RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.86 6. Injection well constructionrequirements(a) General. The owner oroperator must ensure that all Class VIwells are constructed and completed to:(1) Prevent the movement offluids into or between USDWs or into anyunauthorized zones;(2) Permit the use of appropriatetesting devices and workover tools; and(3) Permit continuous monitoringof the annulus space between theinjection tubing and long string casing.(1) Prevent the movement of fluidinto orbetween USDWs or into any unauthorized zones;containing any contaminant into undergroundsources of drinking water,if the presence of thatcontaminant may cause a violation of anyprimary drinking water regulation under 40 CFRpart 142 or may otherwise adversely affect thehealth of persons.;The proposed changes reflect the nonendangerment standard that is the basis ofthe UIC program.(b) Casing and Cementing ofClass VI Wells.(1) Casing and cement or othermaterials used in the construction ofeach Class VI well must have sufficientstructural strength and be designed forthe life of the geologic sequestrationproject. All well materials must becompatible with fluids with which thematerials may be expected to come intocontact and meet or exceed standardsdeveloped for such materials by theAmerican Petroleum Institute, ASTMInternational, or comparable standardsacceptable to the Director. The casingand cementing program must bedesigned to prevent the movement offluids into or between USDWs. In orderto allow the Director to determine andspecify casing and cementingrequirements, the owner or operatormust provide the following information:(1) Casing and cement or other materials used inthe construction of each Class VI well must havesufficient structural strength and be designed forthe operatinglife of thegeologic sequestrationprojectwell. All well materials must becompatiblesuitable for usewith the fluids withwhich the materials may be expected to comeinto contact and meet or exceedteststandardsor practicesdeveloped for such materials by theAmerican Petroleum Institute, ASTMInternational, or comparable standardsacceptable to the Director. The casing andcementing program must be designed to preventthe movement of fluids into or between USDWs.In order to allow the Director to determine andspecify casing and cementing requirements, theowner or operator must provide the followinginformation:The life of a geologic sequestration projectcould be different than the life of the well.Class VI well design should be based on thelife of the well.146.86(b)(1) (i) Depth to the injection zone;(ii) Injection pressure, externalpressure, internal pressure and axialloading;25RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(iii) Hole size;(iv) Size and grade of all casingstrings (wall thickness, external diameter,nominal weight, length, joint specificationand construction material);(v) Corrosiveness of the carbondioxide stream, and formation fluids;(vi) Down-hole temperatures;(vii) Lithology of injection andconfining zones;(v)CorrosivenessCompositionof thecarbon dioxide stream and formation fluids;(vi) Down-hole temperaturesandpressures;There is no method for measurement of“corrosiveness” of a CO2 stream. Therelevant information is the composition of theCO2 stream.Technical clarification(viii) Type or grade of cement;and(ix) Quantity, chemicalcomposition, and temperature of thecarbon dioxide stream.(viii) Type or grade of cementand additives; and Technical clarification.(2) Surface casing must extendthrough the base of the lowermostUSDW and be cemented to the surface.(2) Surface casing must extend through the baseof the lowermost USDWabove the injection zoneand be cemented to the surface.In some parts of the US the USDW is verydeep and this standard may preclude geologicsequestration in these areas.(3) At least one long stringcasing, using a sufficient number ofcentralizers, must extend to the injectionzone and must be cemented bycirculating cement to the surface in oneor more stages.(3) At least one long string casing, using asufficient number of centralizersto create acement bond through the injection and confiningzone(s), must extend to the injection zone andmust becementedisolatedbycirculatingcement to the surface in one or more stages.placing cement and/or other isolationtechnologies as necessary to provide adequateisolation of the injection zone and provide forprotection of USDWs.Cementing to surface is not necessary toprotect USDWS, and may have negativeconsequences, as follows. Cement to surfacewould eliminate the ability to monitorpressures in this annulus and would limitflexibility of remedial options. As revised, theproposal would allow for application anddevelopment of alternative technologies. SeeAPI RP90 for description of risk-basedapproach for managing situations involvingannular casing pressure.Industry experiencewith CO2 EOR under the class II programdemonstrates the effectiveness of existingcementing procedures.26RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.86(b) (4) Circulation of cement may beaccomplished by staging. The Directormay approve an alternative method ofcementing in cases where the cementcannot be recirculated to the surface,provided the owner or operator candemonstrate by using logs that thecement does not allow fluid movementbehind the well bore.(4) Circulation of cement may be accomplishedby staging. The Director may approve analternative method of cementing in cases wherethe cementcannot be recirculated to the surface,provided the owner or operator can demonstrateby using logs that the cement does not allow fluidmovement behind the well bore.Same as above(5) Cement and cementadditives must be compatible with thecarbon dioxide stream and formationfluids and of sufficient quality andquantity to maintain integrity over thedesign life of the geologic sequestrationproject. The integrity and location of thecement shall be verified using technologycapable of evaluating cement qualityradially and identifying the location ofchannels to ensure that USDWs are notendangered.(5) Cement and cement additives must becompatiblesuitable for usewith the carbondioxide stream and formation fluids and ofsufficient quality and quantity to maintain integrityover thedesignoperatinglife of thegeologicsequestration projectwell.The integrity andlocation of the cement shall be verified usingtechnology capable of evaluating cement qualityradially and identifying the location of channels toensure that USDWs are not endangered.Experience with CO2 EOR under the class IIprogram demonstrates the effectiveness ofexisting cementing materials and procedures.Standard API cements have been used innumerous CO2 EOR operations with noadverse consequences. Refer to the citationswithin EPA’s proposed rule 73 FR 43532-43533: Carey et al., (2007), Crow et al.,(2008), and Meyer, J.P (2007).146.86(c) (c) Tubing and packer.(1) All owner and operators ofClass VI wells must inject fluids throughtubing with a packer set at a depthopposite a cemented interval at thelocation approved by the Director.(2) In order for the Director todetermine and specify requirements fortubing and packer, the owner or operatormust submit the following information:(i) Depth of setting;(ii) Characteristics of the carbondioxide stream (chemical content,corrosiveness, temperature, anddensity);(ii) Composition of the carbon dioxide stream.(chemical content, corrosiveness, temperature,and density);There is no method for measurement of“corrosiveness” of a CO2 stream. Therelevant information is the composition of theCO2 stream. The composition of the CO2stream is more relevant to the design of atubing and packer system.27RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.86(c)(2) (iii) Injection pressure;(iv) Annular pressure;(v) Injection rate (intermittent orcontinuous) and volume of the carbondioxide stream;(vi) Size of casing; and(vii) Tubing tensile, burst, andcollapse strengths.(iii)MaximumproposedInjectiontemperature and pressure;(iv)MaximumproposedAnnularpressure;(v)MaximumproposedInjection rate(intermittent or continuous) and volume of thecarbon dioxide stream;Technical corrections.146.87 7. Logging, sampling, and testing priorto injection well operation(a) During the drilling andconstruction of a Class VI injection well,the owner or operator must runappropriate logs, surveys and tests todetermine or verify the depth, thickness,porosity, permeability,and lithology of,and the salinity of any formation fluids in,all relevant geologic formations to assureconformance with the injection wellconstruction requirements under §146.86, and to establish accuratebaseline data against which futuremeasurements may be compared. Theowner or operator must submit to theDirector a descriptive report prepared bya knowledgeable log analyst thatincludes an interpretation of the results ofsuch logs and tests. At a minimum, suchlogs and tests must include:(a) During the drilling and construction of a ClassVI injection well, the owner or operator must runappropriate logs, surveys and tests to determineor verify the depth, thickness, porosity,permeability, and lithology of, and the salinity ofany formation fluids in, all relevant geologicformations to assure conformance with theinjection well construction requirements under§146.86, and to establish accurate baseline dataagainst which future measurements may becompared. The owner or operator must submit tothe Director a descriptive report prepared by aknowledgeable log analyst that includes aninterpretation of the results of such logs andtests.At a minimum, such logs and tests mustinclude:The Director may require such logs andtests as may be needed after taking into accountthe availability of similar data in the area of thedrilling site, the construction plan, and the needfor additional information that may arise fromtime to time as the construction of the wellprogresses and these may include the following:In well defined areas, these evaluations arefrequently unnecessary. The director shouldhave discretion to select the appropriaterequirements necessary to ensure sufficientbaseline data and information are available.For example, in an area where a number ofwells are being drilled, the logging of surfacehole yields little useful additional information.In particular, this change would allow theDirector to reduce the requirements whenmultiple wells are installed for a project.28RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(1) Deviation checks duringdrilling on all holes constructed by drillinga pilot hole which are enlarged byreaming or another method. Suchchecks must be at sufficiently frequentintervals to determine the location of theborehole and to assure that verticalavenues for fluid movement in the formof diverging holes are not created duringdrilling; and146.87(a) (2) Before and upon installationof the surface casing:(i) Resistivity, spontaneouspotential, and caliper logs before thecasing is installed; and(i) Resistivity, spontaneous potential, and caliperlogs before the casing is installed; andAfter a few wells are drilled in an area, theseevaluations are frequently unnecessary andyield little new information. This is an exampleof where Director discretion may beappropriate.(ii) A cement bond and variabledensity log, and a temperature log afterthe casing is set and cemented.(ii)ACementbond and variable density log, anda temperature logevaluation log(s) after thecasing is set and cemented.Unusual to run these logs in a surface holedue to uniformity of shallow geology. This isan example of where Director discretion maybe appropriate.The proposed change provides more flexibilityto select the appropriate log to demonstrateadequate cement bond.(3) Before and upon installationof the long string casing:(i) Resistivity, spontaneouspotential, porosity, caliper, gamma ray,fracture finder logs, and any other logsthe Director requires for the givengeology before the casing is installed;andResistivity, spontaneous potential, porosity,caliper, gamma ray,fracture finder logsand anyother logs the Director requiresbased on sitespecific conditions and risk-based factorsfor thegiven geology before the casing is installed; andIt is acceptable to specify basic loggingrequirements, however, special logs shouldnot be specified. Any other information fromthe area should be drawn on.(ii) A cement bond and variabledensity log, and a temperature log afterthe casing is set and cemented.(ii)ACementbond and variable density log, anda temperature logevaluation log(s)after thecasing is set and cemented.The proposed change provides more flexibilityto select the appropriate log to demonstrateadequate cement bond.29RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.87(a)(4) (4) A series of tests designed todemonstrate the internal and externalmechanical integrity of injection wells,which may include:(i) A pressure test with liquid orgas;(ii) A tracer survey such asoxygen-activation logging;(iii) A temperature or noise log;(iv) A casing inspection log, ifrequired by the Director; and(5) Any alternative methods thatprovide equivalent or better informationand that are required ofand/or approvedof by the Director.(4)A series of testsTest(s)designed todemonstrate the internal and externalmechanical integrity of injection wells, which mayinclude:(i) A pressure test with liquid or gas;(ii)A tracer surveyDiagnostic toolssuch asoxygen-activation logging;(iii) A temperature or noise log;and(iv) A casing inspection log.if required by theDirector; and(5) Any alternative methods that provideequivalent or better information and that arerequired of and/or approved of by the Director.Technical and grammatical correctionsIn (iv), “if required by the Director” isunnecessary.146.87(b) (b) The owner or operator musttake and submit to the Director wholecores or sidewall cores of the injectionzone and confining system and formationfluid samples from the injection zone(s).The Director may accept cores fromnearby wells if the owner or operator candemonstrate that core retrieval is notpossible and that such cores arerepresentative of conditions at the well.The Director may require the owner oroperator to core other formations in theborehole.(b) The owner or operator must submit to theDirectora report describingwhole cores orsidewall coresrepresentativeof the injectionzone and confining system and formation fluidsamples from the injection zone(s). The Directormay acceptdatafrom coresand fluid samplesfrom nearby wells if the owner or operator candemonstrate that suchdataare representative ofconditions in the wellbore.The information required should be sufficientto properly describe the injection andconfining zones.(c) The owner or operator mustrecord the fluid temperature, pH,conductivity, reservoir pressure and thestatic fluid level of the injection zone(s).(c)Prior to injection well operation,the owner oroperator must record thefluidformationtemperature,formation fluidpH and conductivity,and reservoir pressureand the static fluid levelofthe injection zone(s).Technical corrections. Reservoir pressureand static fluid level are redundantparameters.30RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(d) At a minimum, the owner oroperator must determine or calculate thefollowing information concerning theinjection and confining zone(s):(1) Fracture pressure;(2) Other physical and chemicalcharacteristics of the injection andconfining zones; and(3) Physical and chemicalcharacteristics of the formation fluids inthe injection zone.(d) At a minimum, the owner or operatormust determine or calculate the followinginformation concerning the injection andconfining zone(s):(1) Fracture pressure;(2) Other physical and chemicalcharacteristics of the injection and confiningzones; and(3) Physical and chemical characteristicsof the formation fluids in the injection zone.With the exception of calculating fracturepressure, the requirements of this sectionappear redundant to other requirements ofprior sections. The fracture pressurerequirement has been added to section146.87(e) below.(2) and (3) are too vague.(e) Upon completion, but prior tooperation, the owner or operator mustconduct the following tests to verifyhydrogeologic characteristics of theinjection zone:(1) A pump test; or(2) Injectivity tests.(e)(d)Upon completionbutPriortoinjectionwelloperation, the owner or operator mustestimate fracture pressures of the injection andconfining zonesandconductthe followingteststo verify hydrogeologicandgeomechanicalcharacteristics of the injection zone,e.g.,injectivity tests, estimates based on open-holelogging tools (e.g. mechanical properties logs),and other appropriate methods.(1) A pump test; or(2) Injectivity tests.Allows the use of information such as leak offtests conducted duringthe drilling operation.The results of a pump test (pumping fluid fromthe well) have no relevance for an injectionwell.Deletion of the injectivity test would allow theuse of non-destructive methods to calculatefracture pressure.146.87(f) (f) The owner or operator mustprovide the Director with the opportunityto witness all logging and testing by thissubpart. The owner or operator mustsubmit a schedule of such activities tothe Director 30 days prior to conductingthe first test and submit any changes tothe schedule 30 days prior to the nextscheduled test.(f) The owner or operator must provide theDirector with the opportunity to witness alllogging and testing by this subpart. The owner oroperator must submit a schedule of suchactivities to the Director30 days prior toconducting the first testupon spudding the welland submit any changes to the schedule30days48 hoursprior to thenextscheduled test.The changes reflect the realities of flexible rigschedules and operations. In addition, theyare fully consistent with current Class IIrequirements and practices, which deal withthese issues on a daily basis.31RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.88 Injection well operating requirements(a) Except during stimulation, theowner or operator must ensure thatinjection pressure does not exceed 90percent of the fracture pressure of theinjection zone so as to assure that theinjection does not initiate new fracturesor propagate existing fractures in theinjection zone. In no case may injectionpressure initiate fractures in the confiningzone(s) or cause the movement ofinjection or formation fluids thatendangers a USDW.(a) Except during stimulation, the owner oroperator must ensure that injection pressuredoes not exceed 90 percent of the fracturepressure of the injection zone so as to assurethat the injection does not initiate new fracturesor propagate existing fractures in the injectionzone. In no case mayinjection pressure initiatefractures in the confining zone(s) or cause themovement of injection or formation fluids thatendangers a USDW.(a) The owner or operator must comply with amaximum injection pressure limit approved bythe Director and specified in the permit. Inapproving a maximum injection pressure limit,the Director shall consider the results of welltests. The Director shall approve limits that, witha reasonable degree of certainty, will avoidinitiation or propagation of fractures in theconfining zone or cause otherwise nontransmissive faults transecting the confining zoneto become transmissive. In no case may injectionpressure cause movement of injection orformation fluids in a manner prohibited by 40CFR Part 144.12(a)Maintaining the integrity of the confining zoneis the critical parameter.(b) Injection between the outermost casing protecting USDWs and thewell bore is prohibited.(b) Injectionof the CO2 streambetween theoutermost casing protecting USDWs and the wellbore is prohibited.Routine injection into zones other than thetarget interval(s) should be prohibited,however, wording of this requirement is notclear as to which interval is being addressed.An absolute prohibition on injection into thisannulus may also limit diagnostic options thatcould be useful.(c) The owner or operator mustfill the annulus between the tubing andthe long string casing with a noncorrosive fluid approved by the Director.The owner or operator must maintain onthe annulus a pressure that exceeds theoperating injection pressure, unless theDirector determines that suchrequirement might harm the integrity ofthe well.(c) The owner or operator must fill the annulusbetween the tubing and the long string casingwith a non-corrosive fluid approved by theDirector. The owner or operator must maintainon the annulus a pressure that exceeds theoperating injection pressure, unless the Directordetermines that such requirement might harm theintegrity of the well.a positive pressure on theannulus.Industry experience with the Class II UICprogram does not support this requirement.Positive annular pressure that exceeds theoperating injection pressure is not necessarybecause a leak from tubing to annulus doesnot have the same implications as in a Class Ihazardous situation.32RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.88(d) (d) Other than during periods ofwell workover (maintenance) approvedby the Director in which the sealedtubing-casing annulus is of necessitydisassembled for maintenance orcorrective procedures, the owner oroperator must maintain mechanicalintegrity of the injection well at all times.146.88 (e) The owner or operator mustinstall and use continuous recordingdevices to monitor: The injectionpressure; the rate, volume, andtemperature of the carbon dioxidestream; and the pressure on the annulusbetween the tubing and the long stringcasing and annulus fluid volume; andmust install and use alarms andautomatic down-hole shut-off systems,designed to alert the operator and shut-inthe well when operating parameters suchas annulus pressure, injection rate orother parameters approved by theDirector diverge beyond permittedranges and/or gradients specified in thepermit;(e) The owner or operator must install and usecontinuous recording devices to monitor: theinjection pressure; the rate, volume, andtemperature of the carbon dioxide streamand.The owner or operator must regularly monitorthepressure on the annulus between the tubing andthe long string casingand annulus fluid volumeand.The owner or operatormust install and usealarms and automaticdown-holeshut-offsystems, designed to alert the operator and shutin the well when operating parameters such asinjection rate, injection pressure, or otherparameters approved by the Director divergebeyond ranges and/or gradients specified in thepermit;Over-pressure protection is best achieved byensuring compatibility ofthe casing/tubingmaterial design strength with the surfaceinjection (compression) system. Down-holeshut-in devices are notappropriate for thisapplication. These devises are installed in thetubing string and are typically near the surfaceof the well. They’re intended to seal thetubing in the event of catastrophic failure ofthe wellhead. These devises would providelittle if any protection to USDWs. Is notpracticable to install these devises deep withinthe well (e.g. shortly above the packer).Additionally these devisescreate a restrictionon running other tools like logging tools in thewell and therefore could limit an operatorsability to do required monitoring anddiagnostic work. Lastly, these devises requireperiodic testing and maintenance which couldrequire either pulling the devise by wireline orby pulling the entire tubing string dependingon the type of devise installed. Either of theseactivities would be disruptive and costly to theoverall project operations.A more appropriate approach would beinstallation of landing nipples at appropriatepoints in the tubing string which would allowuse of wireline retrievable plugs whenneeded.146.88 (f) If a down-hole automaticshutdown is triggered or a loss ofmechanical integrity is discovered, the(f) If andown-holeautomatic shutdown istriggered or a loss of mechanical integrity isdiscovered, the owner or operator mustTechnical clarification given changes above.33RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleowner or operator must immediatelyinvestigate and identify as expeditiouslyas possible the cause of the shutoff. If,upon such investigation, the well appearsto be lacking mechanical integrity, or ifmonitoring required under paragraph (e)of this section otherwise indicates thatthe well may be lacking mechanicalintegrity, the owner or operator must:immediately investigate and identify asexpeditiously as possible the causeof theshutoff. If, upon such investigation, the wellappears to be lacking mechanical integrity, or ifmonitoring required under paragraph (e) of thissection otherwise indicates that the well may belacking mechanical integrity, the owner oroperator must:146.88(f) (1) Immediately cease injection;(2) Take all steps reasonablynecessary to determine whether theremay have been a release of the injectedcarbon dioxide stream into anyunauthorized zone;(3) Notify the Director within 24hours;(4) Restore and demonstratemechanical integrity to the satisfaction ofthe Director prior to resuming injection;and(5) Notify the Director wheninjection can be expected to resume.(3) Notify the Director within 24 hoursofdiscovery;146.89 9. Mechanical integrity(a) A Class VI well hasmechanical integrity if:(1) There is no significant leak inthe casing, tubing or packer; and(2) There is no significant fluidmovement into a USDW throughchannels adjacent to the injection wellbore.(b) To evaluate the absence ofsignificant leaks under paragraph (a)(1)of this section, owners or operators must,following an initial annulus pressure test,continuously monitor injection pressure,rate, injected volumes, and pressure on(b) To evaluate the absence of significant leaksunder paragraph (a)(1) of this section, owners oroperators must, following an initial annuluspressure test, continuously monitorand record atleast daily, annulus pressure and volumes ofpacker fluid injected or removed frominjectionTechnical clarification.34RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalethe annulus between tubing and longstem casing and annulus fluid volume asspecified in § 146.88(e);pressure, rate, injected volumes, and pressureonthe annulus betweenthetubing and longstemstringcasingand annulus fluid volumeasspecified in §146.88 (e);146.89(c) (c) At least once per year, theowner or operator must use one of thefollowing methods to determine theabsence of significant fluid movementunder paragraph (a)(2) of this section:(1) A tracer survey such asoxygen-activation logging;(2) A temperature or noise log;or(3) A casing inspection log, ifrequired by the Director.(c) At least once per year, the owner or operatormust confirm the absence of significant fluidmovement under paragraph (a)(2) of this sectionusing a method acceptable to the Director(e.g.including diagnostic surveys such as oxygenactivation logging or temperature or noise logs).(1) A tracer survey such as oxygen-activationlogging;(2) A temperature or noise log; or(3) A casing inspection log, if required by theDirector.Revised text supports a performance-basedapproach and allows the development anduse of new technologies as they becomeavailable. Cement circulation to the surface isnot necessary because having the openannulus above the top of cement allowsregular monitoring of annular pressure whichcould indicate leakage.Number 3 was deleted because it requires thetubing to be pulled at significant cost and riskof uncontrolled releases.(d) The Director may require anyother test to evaluate mechanicalintegrity under paragraph (a)(1) or (a)(2)of this section. Also, the Director mayallow the use of a test to demonstratemechanical integrity other than thoselisted above with the written approval ofthe Administrator. To obtain approval,the Director must submit a writtenrequest to the Administrator, which mustset forth the proposed test and alltechnical data supporting its use. TheAdministrator must approve the request ifit will reliably demonstrate themechanical integrity of wells for which itsuse is proposed. Any alternate methodapproved by the Administrator will bepublished in the Federal Register andmay be used in all States in accordancewith applicable State law unless its use isrestricted at the time of approval by theAdministrator.35RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.89(e) (e) In conducting and evaluatingthe tests enumerated inthis section orothers to be allowed by the Director, theowner or operator and the Director mustapply methods and standards generallyaccepted in the industry. When theowner or operator reports the results ofmechanical integrity tests to the Director,he/she shall include a description of thetest(s) and the method(s) used. Inmaking his/her evaluation, the Directormust review monitoring and other testdata submitted since the previousevaluation.(f) The Director may requireadditional or alternative tests if theresults presented by the owner oroperator under paragraph (d) of thissection are not satisfactory to theDirector to demonstrate that there is nosignificant leak in the casing, tubing orpacker or significant movement of fluidinto or between USDWs resulting fromthe injection activity as stated inparagraphs (a)(1) and (2) of this section.36RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.90 10. Testing and monitoring requirementsThe owner or operator of a Class VI wellmust prepare, maintain, and comply witha testing and monitoring plan to verifythat the geologic sequestration project isoperating as permitted and is notendangering USDWs. The testing andmonitoring plan must be submitted withthe permit application, for Directorapproval, and must include a descriptionof how the owner oroperator will meetthe requirements of this section. Testingand monitoring associated with geologicsequestration projects must, at aminimum, include:Testing and monitoring requirementsThe owner or operator of a Class VI well mustprepare,maintain, and comply with a testing andmonitoring plan to verify that the geologicsequestration project is operating as permittedand is not endangering USDWs. The testing andmonitoring plan must be submitted with thepermit application, for Director approval, andmust include a description of how the owner oroperator will meet the requirements of thissection. Testing and monitoring associated withgeologic sequestration projects must, at aminimum, include:(a) Based on a site-specific assessment of thepotential for fluid movement from the injectionwell or injection zone, and on the potential valueof monitoring wells to detect such movement, theowner or operator of a Class VI well mustprepare, maintain, and comply with a testing andmonitoring plan to verify that the geologicsequestration project is operating as permittedand is not endangering USDWs. The testing andmonitoring plan must be submitted with thepermit application, for Director approval andinclude a description of how the owner oroperator will meet the requirements of thissection;146.90 (a) Analysis of the carbondioxide stream with sufficient frequencyto yield data representative of itschemical and physical characteristics;(b) Installation and use, exceptduring well workovers as defined in §146.86(d), of continuous recordingdevices to monitor injection pressure,rate and volume; the pressure on theannulus between the tubing and the longstring casing; and the annulus fluidvolume;(b) The testing and monitoring plan must, at aminimum, include:(a1)Analysis of the carbon dioxide stream withsufficient frequency to yield data representativeof its chemical and physical characteristics;(b2) Installation and use, except during wellworkovers as defined in § 146.86(d), ofcontinuousrecordingmonitoring devices(including digital devices capturing periodic data)to monitor injection pressure, rate and volume;and to record at least dailythe pressure on theannulus between the tubing and the long string§146.86(d) does not exist; perhaps§146.88(d) is what was apparently intended.There is concern regarding what constitutescontinuous monitoring.Industry agrees thatregular monitoring of the parameters identifiedby EPA is appropriate.Our experience withCO2 EOR strongly shows that dailymonitoring of most of these parameters isadequate (exceptions to this would be on asite-specific basis). Recording shouldgenerally be done on a daily basis andreporting on a semi-annually basis. As a37RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalecasing; and the annulus fluid volume;(3) a demonstration of external mechanicalintegrity pursuant to §146.89(c) until the well isplugged;(4) monitoring of the pressure buildup in theinjection zone annually, including at a minimum,a shutdown of the well for a time sufficient toconduct a valid observation of the pressure falloff curve at least once every five years; and(5) a quality assurance plan for all testing andmonitoring requirements.(b) Installation and use, except during wellworkovers as defined in §146.88(d), ofcontinuous monitoring devices (including digitaldevices capturing periodic data) to monitorinjection pressure, rate and volume; andrecordat least dailythe pressure on the annulusbetween the tubing and the long string casing;guiding principle, the frequency of monitoringshould be determined by the level of riskposed by the injection operation.(c) Where appropriate, the testing and monitoringplan shall also include:(1) Continuous monitoring for pressure changesin an appropriately porous and permeableformation overlying the confining zone. When awell is installed to enable such monitoring, theowner or operator shall, on a specified frequencyor at specified times, sample the formation andanalyze for constituents specified in the plan;(2) The use of indirect, geophysical techniques todetermine the position of the CO2 stream front,the water quality in a designated formation, or toprovide other site specific data;(3) Periodic monitoring of water quality in anappropriately porous and permeable formationoverlying the injection zone;(4) Periodic monitoring of water quality in one ormore USDWs;Drilling monitoring wells should be carefullyconsidered since each well introduces apotential pathway for movement. In additionthe cost of adding multiple wells could createa barrier to CCS development, while providinglimited information on actual movement of theCO2 stream.38RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(5) Corrosion monitoring of the well materials forloss of mass, thickness, cracking, pitting andother signs of corrosion performed and recordedat least quarterly which may be modified to beless frequent as approved by the Director basedon construction materials, operating conditions,and monitoring history to ensure that the wellcomponents meet the minimum standards formaterial strength and performance set forth in§146.86(b) by:(i) Analyzing coupons of the well constructionmaterials placed in contact with the carbondioxide stream; or(ii) Routing the carbon dioxide stream through aloop constructed with the material used in thewell and inspecting the materials in the loop; or(iii) Using an alternative method, materials, ortime period approved by the Director;(6) Any additional testing and monitoringappropriate to support modeling the extent of thecarbon dioxide plume and the position of thepressure front; and(7) Any additional testing and monitoringnecessary to determine whether fluid movementis occurring into or between USDWs that wouldendanger a USDW.APC questions the need for corrosionmonitoring of most injected CO2 streamssince they will typically be nearly pure and drythus having no corrosive properties. Industryexperience with production, transportation,and injection of dry CO2 strongly illustratesthe non-corrosive nature of this type of CO2stream.146.90 (c) Corrosion monitoring of thewell materials for loss of mass,thickness, cracking, pitting and othersigns of corrosion must be performed ona quarterly basis to ensure that the wellcomponents meet the minimumstandards for material strength andperformance set forth in § 146.86(b) by:(c) Corrosion monitoring of the well materials forloss of mass, thickness, cracking, pitting andother signs of corrosion must be performed on aquarterly basis to ensure that the wellcomponents meet the minimum standards formaterial strength and performance set forth in §146.86(b) by:See 146.90(5)39RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.90(c) (1) Placing coupons of the wellconstruction materials in contact with thecarbon dioxide stream; or(2) Routing the carbon dioxidestream through a loop constructed withthe material used in the well; or(3) Using an alternative methodapproved by the Director;(1) Placing coupons of the well constructionmaterials in contact with the carbon dioxidestream; or(2) Routing the carbon dioxide streamthrough a loop constructed with the material usedin the well; or(3) Using an alternative methodapproved by the Director;See 146.90(5)(i-iii)146.90(d) (d) Periodic monitoring of theground water quality and geochemicalchanges above the confining zone(s) thatmay be a result of carbon dioxidemovement through the confining zone oradditional identified zones:(1) The location and number ofmonitoring wells must be based onspecific information about the geologicsequestration project, including injectionrate and volume, geology, the presenceof artificial penetrations and otherfactors;(2) The monitoring frequencyand spatial distribution of monitoringwells must be based on baselinegeochemical data that has beencollected under § 146.82(a)(6) and anymodeling results in the area of reviewevaluation required by § 146.84(b);(d) Periodic monitoring of the ground waterquality and geochemical changes above theconfining zone(s) that may be a result of carbondioxide movement through the confining zone oradditional identified zones:(1) The location and number ofmonitoring wells must be based on specificinformation about the geologic sequestrationproject, including injection rate and volume,geology, the presence of artificial penetrationsand other factors;(2) The monitoring frequency and spatialdistribution of monitoring wells must be based onbaseline geochemical data that has beencollected under § 146.82(a)(6) and any modelingresults in the area of review evaluation requiredby § 146.84(b);See 146.90(c)(1 thru 4 and 7)146.90 (e) A demonstration of externalmechanical integrity pursuant to §146.89(c) at least once per yearthroughout the duration of the geologicsequestration project;(f) A pressure fall-off test at leastonce every five years unless morefrequent testing is required by theDirector based on site specificinformation;(e) A demonstration of external mechanicalintegrity pursuant to § 146.89(c) at least once peryear throughout the duration of the geologicsequestration project;(f) A pressure fall-off test at least onceevery five years unless more frequent testing isrequired by the Director based on site specificinformation;See 146.90(b)(3)See 146.90(b)(4)40RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(g) Testing and monitoring totrack the extent of the carbon dioxideplume and the position of the pressurefront by either monitoring for pressurechanges in the first formation overlyingthe confining zone or using indirect,geophysical techniques (e.g., seismic,electrical, gravity, or electromagneticsurveys and/or down-hole carbon dioxidedetection tools);(g) Testing and monitoring to track the extent ofthe carbon dioxide plume and the position of thepressure front by either monitoring for pressurechanges in the first formation overlying theconfining zone or using indirect, geophysicaltechniques (e.g., seismic, electrical, gravity, orelectromagnetic surveys and/or down-holecarbon dioxide detection tools);See 146.90(c)(1 thru 4 and 7)Monitoring outside of the injection zoneprovides little information of value for trackingand monitoring the injected plume. Examplesof how to test and monitor could be includedin the Preamble but need not be included inthe rule itself.146.90 (h) At the Director’s discretion,surface air monitoring and/or soil gasmonitoring to detect movement of carbondioxide that could endanger a USDW.(h) At the Director’s discretion, surface airmonitoring and/or soil gas monitoring to detectmovement of carbon dioxide that could endangera USDW.In most situations soil and air monitoring doesnot provide an effective method of protectingUSDWs.146.90(h) (1) The testing and monitoringplan must be based on potentialvulnerabilities within the area of review;(2) The monitoring frequencyand spatial distribution of surface airmonitoring and/or soil gas monitoringmust reflect baseline data and themonitoring plan must include how theproposed monitoring will yield usefulinformation on the area of reviewdelineation and/or compliance withstandards under 40 CFR 144.12;(1) The testing and monitoring plan mustbe based on potential vulnerabilities within thearea of review;(2) The monitoring frequency and spatialdistribution of surface air monitoring and/or soilgas monitoring must reflect baseline data and themonitoring plan must include how the proposedmonitoring will yield useful information on thearea of review delineation and/or compliancewith standards under 40 CFR 144.12;146.90(i) (i) Any additional monitoring, asrequired by the Director, necessary tosupport, upgrade, and improvecomputational modeling of the area ofreview evaluation required under §146.84(b) and to determine compliancewith standards under 40 CFR 144.12;and(j) A quality assurance andsurveillance plan for all testing andmonitoring requirements.(i) Any additional monitoring, as requiredby the Director, necessary to support, upgrade,and improve computational modeling of the areaof review evaluation required under § 146.84(b)and to determine compliance with standardsunder 40 CFR 144.12; and(j) A quality assurance and surveillanceplan for all testing and monitoring requirements.See 146.90(c)(6)See 146.90(b)(5)41RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale146.91 11. Reporting requirements.The owner or operator must, at aminimum, provide the following reports tothe Director, for each permitted Class VIwell:(a) Semi-annual reportscontaining:(1) Any changes to the physical,chemical and other relevantcharacteristics of the carbon dioxidestream from the proposed operatingdata;(2) Monthly average, maximumand minimum values for injectionpressure, flow rate and volume, andannular pressure;(a) Semi-annualor less frequent at the discretionof the Directorreports containing:(1) Anysignificantchanges to the physical,chemical and other relevant characteristics of thecarbon dioxide stream from the proposedoperating data;Over the life of the project, the Director maydecide that less reporting is acceptable(1) Technical clarification. Significance canbe determined by a statistical analysis of thedata. Rules should recognize that there willbe minor variations in many data sets overtime.146.91(a) (3) A description of any eventthat exceeds operating parameters forannulus pressure or injection pressure asspecified in the permit;(4) A description of any eventwhich triggers a shutdown devicerequired pursuant to § 146.88(e) and theresponse taken;(5) The monthly volume of thecarbon dioxide stream injected over thereporting period and project cumulatively;(6) Monthly annulus fluid volumeadded; and(7) The results of monitoringprescribed under § 146.90.(3) A description of anysignificantevent thatexceeds operating parameters for annuluspressure or injection pressure as specified in thepermit;(4) A description of anysignificantevent whichtriggers a shutdown device required pursuant to§146.88(e) and the response taken;EPA should consider some significancethreshold on reporting these events to avoidreporting events that would be of limitedinterest or consequence.(b) Report, within 30 days theresults of:(1) Periodic tests of mechanicalintegrity;(2) Any other test of the injectionwell conducted by the permittee ifrequired by the Director; and42RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationale(3) Any well workover.(c) Owners or operators mustsubmit reports in an electronic formatacceptable to the Director. At thediscretion of the Director, other formatsmay be accepted.146.92 12. Injection well plugging.(a) Prior to the well plugging, theowner or operator must flush each ClassVI injection well with a buffer fluid,determine bottomhole reservoir pressure,and perform a final mechanical integritytest.(a) Prior to the well plugging, the owner oroperator must flush each Class VI injection wellwith a buffer fluid, determine bottomholereservoir pressure, and perform a finalexternalmechanical integrity testof any relevant wellborematerials remaining.Many of the components that would be testedby an internal MIT are removed or testedduring the plugging process.146.92(b) (b) Well Plugging Plan. Theowner or operator of a Class VI well mustprepare, maintain, and comply with aplan that is acceptable to the Director.The requirement to maintain andimplement an approved plan is directlyenforceable regardless of whether therequirement is a condition of the permit.The well plugging plan must besubmitted as part of the permitapplication and must include thefollowing information:(1) Appropriate test or measureto determine bottomhole reservoirpressure;(2) Appropriate testing methodsto ensure mechanical integrity asspecified in § 146.89;(3) The type and number ofplugs to be used;(4) The placement of each plugincluding the elevation of the top andbottom of each plug;(5) The type and grade andquantity of material to be used inplugging. The material must becompatible with the carbon dioxide(2) Appropriate testing methods to ensurefinalexternalmechanical integrity as specified in§146.89(c);(5) The type and grade and quantity of materialto be used in plugging. The material must besuitable for usewith the carbon dioxide stream;andMany of the components that would be testedby an internal MIT are removed or testedduring the plugging process.43RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalestream; and(6) The method of placement ofthe plugs.(c) Notice of intent to plug. Theowner or operator must notify theDirector at least 60 days before pluggingof a well. At this time, if any changeshave been made to the original wellplugging plan, the owner or operatormust also provide the revised wellplugging plan. At the discretion of theDirector, a shorter notice period may beallowed.146.92(d) (d) Plugging report. Within 60days after plugging or at the time of thenext semi-annual report (whicheveroccurs earlier) the owner or operatormust submit a plugging report to theDirector. If the semi-annual report is dueless than 15 days after completion ofplugging, then the report must besubmitted within 60 days after plugging.The report must be certified as accurateby the owner or operator and by theperson who performed the pluggingoperation (if other than the owner oroperator.)(d) Plugging report. Within 60 days after pluggingthe owner or operator must submit a pluggingreport to the Director.If the semi-annual report isdue less than 15 days after completion ofplugging, then the report must be submittedwithin 60 days after plugging.The report mustbe certified as accurateby the owner or operatorand by the person who performed the pluggingoperation (if other than the owner or operator.)The proposed changes are suggested tosimplify and clarify a provision that APCbelieves is needlessly complicated.146.93 13. Post-injection site care and siteclosure(a) The owner or operator of aClass VI well must prepare, maintain,and comply with a plan for post-injectionsite care and site closure that meets therequirements of paragraph (a)(2) of thissection and is acceptable to the Director.(1) The owner or operator mustsubmit the post-injection site care andsite closure plan as a part of the permitapplication to be approved by theDirector.(1) The owner or operatormust submit thepostinjection site care and site closure plan as a partof the permit application to be approved by theDirector.shall continue to conduct monitoring asspecified in the Director-approved post-injectionsite care and site closure plan, pursuant to theRevisions here reflect changes to§146.93(b)(3)44RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleperformance based criteria described in146.93(3).(2) The post-injection site careand site closure plan must include thefollowing information:(i) The pressure differentialbetween pre-injection and predictedpost-injection pressures in the injectionzone;(ii) The predicted position of thecarbon dioxide plume and associatedpressure front at site closure asdemonstrated in the area of reviewevaluation required under § 146.84(b);(2) The post-injection site care and site closureplan must include the following information:(i) The pressure differential between preinjection and predicted post-injection pressuresin the injection zone;(ii) The predicted position of the carbondioxide plume and associated pressure front atsite closure as demonstrated in the area ofreview evaluation required under § 146.84(b);Revisions here reflect changes to§146.93(b)(3)146.93(a)(2) (iii) A description of post-injectionmonitoring location, methods, andproposed frequency; and(iv) A proposed schedule forsubmitting post-injection site caremonitoring results to the Director.(iii) A description of post-injection monitoringlocation, methods, and proposed frequency; and(iv) A proposed schedule for submittingpost-injection site care monitoring results to theDirector.(3) Upon cessation of injection,owners or operators of Class VI wellsmust either submit an amended postinjection site care and site closure planor demonstrate to the Director throughmonitoring data and modeling resultsthat no amendment to the plan isneeded.(4) The owner or operator maymodify and resubmit the post-injectionsite care and site closure plan for theDirector’s approval within 30 days ofsuch change.(4)At any time during the post-injection site carephase, the owner or operator may modify andresubmit the post-injection site care and siteclosure plan for the Director’s approval within 30days of such change.Technical Clarification.146.93(b) (b) The owner or operator shallmonitor the site following the cessation ofinjection to show the position of thecarbon dioxide plume and pressure frontand demonstrate that USDWs are not45RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalebeing endangered.(1) The owner or operator shallcontinue to conduct monitoring asspecified in the Director-approved postinjection site care and site closure planfor at least 50 years following thecessation of injection. At the Director’sdiscretion, the monitoring will continueuntil the geologic sequestration projectno longer poses an endangerment toUSDWs.(1) The owner or operator shall continue toconduct monitoring as specified in the Directorapproved post-injection sitecare and site closureplan,for at least 50 years following the cessationof injection. At the Director’s discretion, themonitoring will continue until the geologicsequestration project no longer poses anendangerment to USDWs.pursuant to theperformance based criteria described in§146.93(b)(3).EPA should also reconsider its proposed 50-year default period for post-injection site care.EPA offers no rationale for this arbitrarilyselected period of 50 years. Establishing afixed and unusually long time period maycreate a significant barrier for operatorsconsidering entry into CCS operations.Criteria for determining the period for postinjection site care should be performancebased and a function of the site specificcharacteristics of a project such as projectsize, geologic factors, and relative risk of theproject. APC offers such criteria in our editsto §146.93(b)(3).146.93(b) (2) If the owner or operator candemonstrate to the satisfaction of theDirector before 50 years, based onmonitoring and other site-specific data,that the geologic sequestration project nolonger poses an endangerment toUSDWs, the Director may approve anamendment to the post-injection site careand site closure plan to reduce thefrequency of monitoring or may authorizesite closure before the end of the 50-yearperiod.(2) If the owner or operator can request anddemonstrate to the satisfaction of the Directorbefore 50 years, based on monitoring and othersite-specific data, that the geologic sequestrationproject no longer poses an endangerment toUSDWs, the Director may approve anamendment tothatthe post-injection site careand site closure planshould be revisedto reducethe frequency of monitoring.or may authorizesite closure before the end of the 50-year period.(See above)(3) Prior to authorization for siteclosure, the owner or operator mustsubmit to the Director a demonstration,based on monitoring and other sitespecific data, that the carbon dioxideplume and pressure front have stabilizedand that no additional monitoring isneeded to assure that the geologicsequestration project does not pose anendangerment to USDWs.(3) Prior to authorization for site closure,the owner or operatormustsubmit to the Directora demonstration, demonstrate to the Director,based on monitoring, andother site-specific data,and modeling that is reasonably consistent withsite performance that the carbon dioxide plumeand pressure front have stabilized and thatnoadditional monitoring is needed to assure that thegeologic sequestration project does not pose anendangerment to USDWs.The owner or operator must demonstrate, basedon the current understanding of the site,including monitoring data and/or modeling, all ofthe following: (i) the estimated magnitude andextent of the project footprint (CO2 plume andthe area of elevated pressure); (ii) the estimatedAPC edits establish the performance basedcriteria for selecting the monitoring period.EPA should recognize that under any givenset of site specific conditions some of thesecriteria may not be fully satisfied. EPA shouldretain the ability to waive individual monitoringcriteria described here to reflect that situation.46RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalelocation of the detectable CO2 plume ; (iii) thatthere is no significant leakage of either CO2 ordisplaced formation fluids that is endangeringUSDWs; (iv) that the injected or displaced fluidsare not expected to migrate in the future in amanner that encounters a potential leakagepathway into a USDW; (v)that the injection wellsat the site completed into or through the injectionzone or confining zone are plugged andabandoned in accordance with theserequirements; and (vi) any remaining projectmonitoring wells at the site are being managedby a person and in a manner acceptable to theDirector.(4) If such a demonstrationcannot be made (i.e., if the carbondioxide plume and pressure front havenot stabilized) after the 50-year period,the owner or operator must submit to theDirector a plan to continue post-injectionsite care.(4) If such a demonstration cannot be made (i.e.,if the carbon dioxide plume and pressure fronthave not stabilized) after the 50-year period, theowner or operator must submit to the Director aplanto continue post-injection site care.No longer necessary given changes above.146.93(c) (c) Notice of intent for siteclosure. The owner or operator mustnotify the Director at least 120 daysbefore site closure. At this time, if anychanges have been made to the originalpost-injection site care and site closureplan, the owner or operator must alsoprovide the revised plan. At thediscretion of the Director, a shorter noticeperiod may be allowed.146.93(d) (d) After the Director hasauthorized site closure, the owner oroperator must plug all monitoring wells ina manner which will not allow movementof injection or formation fluids thatendangers a USDW.(e) Once the Director hasauthorized site closure, the owner oroperator must submit a site closurereport within 90 days that must thereafterbe retained at a location designated by(e) Once the Director has authorized site closure,the owner or operator must submit a site closurereport within 90 daysthat must thereafter beretained at a location designated by the Director.after completion of all closure operations. TheOnce the site closure report is submitted tothe Director, the operator cease to bearresponsibility for any further record retention.At this point, EPA becomes the steward ofinformation for the project.47RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalethe Director. The report must include:(1) Documentation of appropriateinjection and monitoring well plugging asspecified in § 146.92 and paragraph (c)of this section. The owner or operatormust provide a copy of a survey platwhich has been submitted to the localzoning authority designated by theDirector. The plat must indicate thelocation of the injection well relative topermanently surveyed benchmarks. Theowner or operator must also submit acopy of the plat to the RegionalAdministrator of the appropriate EPARegional Office;report must include:(1) Documentation of appropriate injection andmonitoring well plugging as specified in §146.92and paragraph (c) of this section. The owner oroperator must provide a copy of a survey platwhich has been submitted to the local zoningauthority designated by the Director. The platmust indicate the location of the injection well(s)relative to permanently surveyed benchmarks.The owner or operator must also submit a copyof the plat to the Regional Administrator of theappropriate EPA Regional Office;(2) Documentation of appropriatenotification and information to suchState, local and tribal authorities as haveauthority over drilling activities to enablesuch State and local authorities toimpose appropriate conditions onsubsequent drilling activities that maypenetrate the injection and confiningzone(s); and(3) Records reflecting the nature,composition and volume of the carbondioxide stream.146.93 (f) Each owner or operator of aClass VI injection well must record anotation on the deed to the facilityproperty or any other document that isnormally examined during title searchthat will in perpetuity provide anypotential purchaser of the property thefollowing information:(1) The fact that land has beenused to sequester carbon dioxide;(2) The name of the Stateagency, local authority, and/or tribe withwhich the survey plat was filed, as wellas the address of the RegionalEnvironmental Protection Agency Office48RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationaleto which it was submitted; and(3) The volume of fluid injected,the injection zone or zones into which itwas injected, and the period over whichinjectionoccurred.(g) The owner or operator mustretain for three years following siteclosure, records collected during thepost-injection site care period. Theowner or operator must deliver therecords to the Director at the conclusionof the retention period, and the recordsmust thereafter be retained at a locationdesignated by the Director for thatpurpose.146.94 14. Emergency and remedial response.(a) As part of the permitapplication, the owner or operator mustprovide the Director with an emergencyand remedial response plan thatdescribes actions to be taken to addressmovement of the injection or formationfluids that may cause an endangermentto a USDW during construction,operation, closure and post-closureperiods.146.94(b) (b) If the owner or operatorobtains evidence that the injected carbondioxide stream and associated pressurefront may cause an endangerment to aUSDW, the owner or operator must:(1) Immediately cease injection;(2) Take all steps reasonablynecessary to identify and characterizeany release;(3) Notify the Director within 24(b) If the owner or operator obtains evidence thatthe injected carbon dioxide stream,displacedformation fluids orandassociated pressure frontmay cause an endangerment toendangersaUSDW, the owner or operator must:(1)Immediatelycease injectionin a prudentmanner considering circumstances.(2) Take all steps reasonably necessary toidentify and characterizethe endangermentposed;Technical clarifications.There is a slight change that immediatelyceasing injection could have adverse impactson other aspects of the operation.49RuleProvisionEPA ProposalAnadarko Petroleum Corporation (APC)CommentsRationalehours; and(4) Implement the emergencyand remedial response plan approved bythe Director.(3) Notify the Director or the designatedrepresentative within 24 hoursof becomingaware of the endangerment; and(c) The Director may allow theoperator to resume injection prior toremediation if the owner or operatordemonstrates that the injection operationwill not endanger USDWs.(d) The owner or operator mustnotify the Director and obtain hisapproval prior to conducting any wellworkover.(d) The owner or operator must notify theDirectorprior to conducting any well workoverinresponse to any case of endangerment.In critical situations, time spent obtainingapproval could adverselyaffect the ability toconduct operations or increase the level ofendangerment.Letter ID: 0200 Commenter: Craig R. Walters Organization: Anadarko Petroleum Corporation

Letter ID: 0200 Comment ID: 24563 Letter Lines: 23 to 30

Comment Code: 1420 1.2.1.1 Support the GS rulemaking

Comment: Anadarko Petroleum Corporation appreciates the opportunity to submit comments on the EPA's proposed regulations governing underground injection of carbon dioxide for geologic sequestration. Anadarko feel s the EPA has done a very good job on many critical aspects of this very impo rtant rule including the ability to sequester CO2 under current Class II regul ations during enhanced recovery and the protective nature of the current Cla ss II operations. In addition, we would

like to recommend several modifications ba sed on our experiences with conducting Enhanced Oil Recovery (EOR). Currently, Anadarko operates two EOR projects that

Individual Response: EPA believes that the creation of a new injection well class (VI) under the existing UIC Program is necessary to enable the use of GS as a climate change mitigation technology in a manner that protects USDWs from endangerment. EPA agrees that the UIC Program, under the authority of the SDWA, provides a strong fram ework for regulating injection of CO2 for GS and adds that the GS regulati on tailors the UIC requirements to address the unique issues associated with large-scale GS including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potenti al presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

EPA recognizes that the oil and gas industry has decades of e xperience injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS sites. EPA also recognizes that a by-product of ER activities is that a cer tain percentage of the CO2 is trapped in the receiving formation.

Also, since field experience and well constr uction, injection, and m onitoring information relevant to GS comes from operations that inject acid gas or inject CO2 for ER, the Agency has conducted evaluations regarding these commercial field operations and c ontinues to track GSrelevant developments in these commercial operations. Some of the research that informs the

final GS rule was conducted at ER sites.

Letter ID: 0200 Comment ID: 24564 Letter Lines: 47 to 55

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Injection below the lowermost USDW:

A prohibition on injection above the lowe rmost USDW is not necessary for the

1protection of USDWs. Injection operations currently take place above a USDW in multiple classes, including current EOR projects. This regulation would eliminate many excellent sequestration form ation candidates, especially in the western region of the United States. In addition, the regulations already provide for protection of USDWs both above and below the injection zone. Through proper siting and well design, risks to any USDW can be minimized.

Individual Response: EPA acknowledges that there are lim ited circumstances where injection above the lowermost USDW can be performe d in a manner that protects USDWs from endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which owne rs or operators can seek a waiv er of the Class VI injection depth requirements for inject ion into non-USDW formations above and/or between USDWs. Additionally, the final GS rule doe s not categorically preclude or prohibit injection into any type

of formation.

EPA believes that these requirements will ensure USDW protection while providing flexibility to UIC program Directors and owne rs or operators who undertak e CO2 injection for GS. The Agency believes this approach: 1) responds to co ncerns about local and re gional geologic storage capacity limitations imposed by th e proposed injection depth require ments; 2) allows for a more site-specific assessment of injection depth for GS projects; 3) accommodates injection into different formation types; 4) a llows for injection of CO2 for GS into non-USDWs above and/or between USDWs when appropriate and where it can be demonstrated that USDWs will be protected; and 5) responds to concerns about the use of aqui fer exemptions for GS. Finally, EPA’s approach to addressing injection depth va riability through a waiver process responds to concerns about future drinking wa ter resource availability and the need to ensure that high quality water remains available in sufficient quantities to supply dr inking water needs.

For additional information on the waiver approach, please see the final rule and preamble as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0200 Comment ID: 24565 Letter Lines: 57 to 66

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Injection Well Class (Class II vs. Class VI):

Anadarko was very pleased to see the EPA ma intain the integrity of the Class II program by excluding injecti on operations for the purpose of enhanced recovery. Also, Anadarko is in full support of deve loping two classes of wells to better address the associated risks with seques tration. By creating a Class II-B for the exclusive purpose of sequestration in oil and gas bearing formations, many of the complications with grandfathe ring and regulatory jurisdiction are resolved. The details of this separate class will be further worked out during

discussions with the Multi-S takeholder Discussion Group.

2Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should remain under the Class II Program. However, EPA believes that injection for the primary purpose of long-term stor age is sufficiently different from Class II ER operations and warrants tailored re quirements. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly great er than for Class II wells. Reservoir pressure

conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressure s within their storage formations than Class II ER projects.

EPA believes that there are significant differences between how projects are operated, as well as the risks posed by these different injection activi ties. The new tailored approach of the GS rule was designed to address the gene ral risks deep injection may pos e to USDWs and was tailored specifically to address the risk s posed by long-term storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

EPA believes that many Class I, Class II, a nd Class V experimental technology wells are designed and constructed to withstand exposur e to CO2. The final GS rule allows the construction of these wells to be grandfathe red per §146.81(c), provided th e owner or operator

can demonstrate to the Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and ensu re protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

The final Class VI regulations re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility. For more information, please see the discussion on transition of Class II wells in the preamble to the final GS rule.

Letter ID: 0200 Comment ID: 24566 Letter Lines: 70 to 75

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)

Comment: The majority of the well construction a nd operating requirements appear to be built on the Class I Hazardous Waste progr am. Based on industry's excellent environmental and safety record with CO2 injection practices, Anadarko recommends the EPA reconsider the propos ed regulations. Several misconceptions on well design have been recently addresse d as further. research has been completed in the field. One of thes e misconceptions is the cementing

Individual Response: Although the requirements are based on the existing regulatory framework for deep wells, includi ng Class I wells, EPA believes that GS is sufficiently different

3from other injection operations to warrant the ta ilored requirements for Class VI wells at §146.86 in order to protect USDWs from endangerment.

EPA clarifies that the requirements for Class VI wells are not necessarily more stringent than those for Class I hazardous waste injection wells, rather they are different. For example, Class I hazardous well owners or operators are subject to requirements that are not applicable to Class VI wells, such as no migration petitions.

Letter ID: 0200 Comment ID: 24567 Letter Lines: 75 to 83

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment)

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

Comment: completed in the field. One of thes e misconceptions is the cementing requirements; both the requirement to cement to surface as well as the use of

corrosion-resistant cement. It has been de monstrated that a good cement job is more important than a resistant cement, and in certain cases, the resistant cements proved more susceptible to degrad ation than a basic well cement. Also, research performed at SACROC has demonstr ated the effectivene ss of the current Class II program's cementing requirements. Many of the requirements currently proposed do not afford any extra protection to USDWs and in many cases may actually present greater risk.

Individual Response: EPA agrees that proper cement instal lation is critical to maintaining injection well integrity and clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. It should be noted that in Carey et al. ( 2007), their research on the ER- CO 2 injection well at SACROC was unable to determine whether CO2 in the presence of water, dry CO2, or a CO2-brine mixture had

caused the cement alteration observed. In Crow et al. (2008), the well ma terials studied were from a production well producing from a natural CO2 deposit that also produced associated water, so well materials were presumably expos ed to CO2 in the pres ence of water. Meyer (2007) acknowledges the Carey study found no loss of hydraulic integrity after 30 years, but also

mentions the use of acid-resistant cements in wells used for acid gas injection and where brine is

encountered.

EPA is unaware of studies showing that the resistant cements proved more susceptible to degradation than basic well cement. However, the Ag ency clarifies that the final rule requires at §146.86(b)(5) that cement and cement additives be compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the GS project. If certain cements have been show n to degrade, they may not be used in Class VI

wells.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at

4http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA anticipates further findings in the use of acid -resistant cements, in particular the physical integrity of such modified cements in place. Th e Agency plans to, every six years, collect and review data on GS projects to determine wh ether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0200 Comment ID: 24568 Letter Lines: 106 to 112

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment)

Comment: Rule Provisions: 73 FR 43497

EPA Rule Issue: 1. EPA seeks comment on any aspects of the ongoing State efforts to regulate the GS of CO2 and how these e fforts might be used to better inform a final Federal rulemaking. EPA Notice 43497.

Anadarko Petroleum Corporation (APC) Res ponse: APC supports the implementation of partial primacy for Class VI separa tely from other classes of wells.

Individual Response: EPA agrees with commenters that states should be allowed to obtain primacy for Class VI wells independently of other well classes, and will allow independent primacy for Class VI wells under §145.1(i) of th e final GS rule. Given the potential for CCS (encompassing capture, transportation, and geologic sequestration) to be an important part of a national priority to address clim ate change, EPA believes that provi ding states the flexibility to obtain primacy for Class VI wells independently of other well cla sses can help foster effective management of CCS. EPA believes that allowing independent Class VI primacy may encourage states to take responsibility for implementation of Class VI regulations and provide for a more comprehensive approach to managing CCS projects by promoting the integrat ion of GS activities

under SDWA into a broader framework for mana ging CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeli ne operations, pore space ownership, land use rights, and surface access) for which states can call upon other authorit ies that exist at the state level (but outside UIC authority) to provide a more comp rehensive CCS management approach.

The Agency believes that it is important for stat es to use their unique e fficiencies to promote adoption of this burgeoning and important tec hnology, while assuring that USDWs are protected from endangerment through the UIC regulatory framework. EPA believe s that, due to the importance of implementing an effective, comprehensive, and seamless CCS program, States should be provided the flexibility to obtain primacy for Class VI only.

EPA also believes that allowing states to apply only for Class VI primacy will shorten the primacy approval process for states. EPA's willingness to accept independent primacy applications for Class VI wells represents a shift in its longstandi ng policy of discouraging "partial primacy." It is very important to note that this shift in policy allowing for Class VI primacy does not apply to any other well Cl ass under Section 1422. EPA will continue to discourage applications for pa rtial primacy for all other well types under Section 1422.

5EPA clarifies that states should be able to obtain primacy for Cla ss VI wells independent of other well classes provided they devel op regulations that are at leas t as stringent as the minimum Federal requirements (e.g., permitting, inspec tion, operation, monitoring, and recordkeeping requirements) provided in the final GS rule. EPA believes that existing programs can adapt their expertise to the new requirements for Class VI wells and will be able to develop a primacy application for Class VI wells under section 1422 of SDWA and en sure that their GS programs integrate into national climate change priori ties and protect USDWs from endangerment.

Letter ID: 0200 Comment ID: 24569 Letter Lines: 114 to 143

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Rule Provisions: 73 FR 43502 EPA Rule Issue: 2. Injection of CO2 for the purposes of enhanced oil and gas recovery (EOR/EGR), as long as any producti on is occurring, will continue to be permitted under the Class II program. EPA seeks comment on the merits of this approach since owners or operators of some Class II EOR/EGR wells may wish to use wells for the purposes of production and GS prior to the field being completely depleted. EPA Notice 43502.

Anadarko Petroleum Corporation (APC) Res ponse: While it was apparent in the preamble that the EPA intended to allow EOR operations to continue under current Class II regulations, the rules left some ambiguity to that distinction. In order to operate a successful recovery proj ect it is imperative that the oil and gas regulators continue to govern EOR ope rations. APC offers language in our comments that would make this more explicit.

APC strongly supports the propos ed approach and the absenc e of an economic test for oil and gas reservoir "depletion." Recognizing though that EPA may face pressure to change its approach, APC of fers language in our comments on the proposed rule for EPA’s consideration for differentiating between wells for EOR/EGR and sequestration.

Additionally, APC, along with the Multi-Stakeholder Di scussion Group, supports

the creation of a subclass under Clas s II (e.g "Class IIB") for storage operations in hydrocarbon formations. S ee proposed section 146.25. By utilizing this approach operators avoid the potentia l complexity of switching agencies in the middle of a project (this is especi ally important given the sometimes conflicting jurisdiction shown between va rious regulating agencies within a state). Also, this allows for the different risk-profile of sequestration in an oil and gas reservoir to be taken into account and a different set of regulating requirements to be utilized.

6Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas recovery should remain under the Class II Program. However, EPA believes that injection for the primary purpose of long-term stor age is sufficiently different from Class II ER operations and warrants tailored re quirements. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly great er than for Class II wells. Reservoir pressure

conditions will also be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressure s within their storage formations than Class II ER projects.

EPA believes that there are significant differen ces between how projects are operated, as well as the risks posed by these different injection activi ties. The new tailored approach of the GS rule was designed to address the gene ral risks deep injection may pos e to USDWs and was tailored specifically to address the risk s posed by long-term storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions).

EPA believes that many Class I, Class II, a nd Class V experimental technology wells are designed and constructed to withstand exposur e to CO2. The final GS rule allows the construction of these wells to be grandfathe red per §146.81(c), provided th e owner or operator

can demonstrate to the Director that the wells were engineered and constructed to meet the requirements at §146.86(a) and ensu re protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA is developing guidance on transitioning perm its from Class II to Class VI. The guidance will assist Directors in determining whether an injection project should be transitioned from Class II, where the primary purpos e is oil and gas production, to Class VI, where the primary purpose is long-term storage of large volumes of CO2. The guidance describes recommended methods the Director may use to evaluate change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s in the preamble to the final GS rule.

Letter ID: 0200 Comment ID: 24570 Letter Lines: 145 to 173

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment)

Comment: Rule Provisions: 146.81(c)

EPA Rule Issue: 3. EPA seeks comment on th e approach to grandf ather construction requirements at the Director’s discreti on for existing Class I, Class II, and Class V wells seeking to convert to Class VI wells , and whether additional construction requirements would be necessa ry to prevent endangerment to USDWs

from the GS of CO2. EPA Notice 43502.

Anadarko Petroleum Corporation (APC) Re sponse: APC strongly supports this provision. Candidate Class I and Class V we lls for grandfathering will have a demonstrated record of performance under their existing operations and MIT programs to demonstrate sound performance and adequacy of well integrity that

7can be used as a basis for conversion to the Class VI program.

For Class II wells, APC, along with th e Multi- Stakeholder Discussion Group, propose that they remain under the Class II program when tr ansitioning from EOR to GS. Through the approach of two forms of sequestration, Class VI and Class II

GS, the EPA would eliminate some of the future confusion regarding grandfathering of requirements. EOR wells will have proven their integrity and protection of USDWs during the operational phases of the flood through sound performance and MIT programs; and, theref ore, the construction requirements proposed will not be necessary.

In addition, many of the required well constr uction requirements, such as cement to surface, are truly not necessary. Industry has proven the successfulness of current well cement practices in 35 plus y ears of CO2 injection for EOR with an

excellent environmental, health, and safety record. Through keeping these projects in the same regulating agency that governed the EOR operations it ensures that those regulato rs the most knowledgeable for working in oil and gas reservoirs are overseeing the regulatory requirements.

Individual Response: EPA agrees that many Class I, Cl ass II, and Class V experimental technology wells are designed and constructed to withstand exposure to CO2. The final GS rule provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director that the wells were en gineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR requirements) should also be grandfathered. Following re-permitting of the project as GS, many of the unique factors of GS s ites (e.g., increased reservoir pr essures associated with large volumes of stored CO2 and the corrosivity of CO 2 in the presence of water) will result in an increased risk profile, warranti ng the specific requirements in the final GS rule. Therefore, following re-permitting as Class VI wells, these proj ects must be subject to the operational, MIT, monitoring, reporting, plugging, and post- injection site care and site closure requirements in the

final GS rule. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Letter ID: 0200 Comment ID: 24571 Letter Lines: 175 to 186

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment)

Comment: Rule Provisions: 146.81(c) EPA Rule Issue: 4. Additionally, EPA s eeks comment on how the grandfathering approach for existing wells may affect compliance with the other requirements in its proposal. EPA Notice 43502.

Anadarko Petroleum Corporation (APC) Res ponse: All components of the existing

8wells with a proven record of performan ce should be grandfathered unless there are specific USDW endangerment concerns identified by the Director. Projects that are being converted to sequestra tion projects will have a significantly larger base-line data set than those pure sequestration projects. This should be taken into account when considering grandfathering provisions and plan requirements. See Comment above.

Individual Response: EPA agrees that many Class I, Cl ass II, and Class V experimental technology wells are designed and constructed to withstand exposure to CO2. The final GS rule provides for the construction of these wells to be grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director that the wells were en gineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

As described above, EPA disagrees that ot her requirements (e.g., MITs, siting, monitoring, operational, and AoR requirements) should also be grandfathered. Following re-permitting, these projects must be subject to the operationa l, MIT, monitoring, reporting, plugging, and postinjection site care and site closur e requirements in the final GS ru le. See the discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail on these requirements.

Letter ID: 0200 Comment ID: 24572 Letter Lines: 188 to 199

Comment Code: 4430 2.4.4.3.3 Injection into coal seams above USDWs (seeking comment)

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 EPA Rule Issue: 5. EPA is proposing to pr eclude the injection of CO2 for longterm storage into coal seams where th ey are above the lowermost USDW. EPA requests comment on this propos ed prohibition. EPA Notice 43503.

Anadarko Petroleum Corporation (APC) Re sponse: APC opposes this restriction. Qualification of a formation for storag e should be based on performance-based standards and site-specific considerations. It is more important to recognize that for those first pilot projects the Class V experimental well regulations may be better suited. However, if the data can be shown that USDW protection can be achieved through proper confining units and reservoir trapping mechanisms, injection into coal seams above the lowermost USDW should be allowed.

Individual Response: The final GS rule does not categorica lly preclude or prohibit injection into any type of formation, including coal se ams. Instead, the requirements are designed to ensure protection of USDWs from endange rment through proper siting, well construction, operation, monitoring, and PISC at all sites selected for GS.

EPA recognizes that some types of formations, such as coal s eams and basalts, are typically shallow and above the lowermost USDW. EPA exp ects that most injection wells conducting GS in these shallow formations will be permitted as Class VI wells and such wells will be issued

9waivers, provided that their owners or operators can meet all of the requirements for an injection depth waiver at §146.95 and demonstr ate that such injection can be performed in a manner that protects USDWs, as long as appropriate protec tions are in place. The Class V experimental technology well classification, may, in some instan ces be an appropriate permitting alternative. This decision should be informed through a di scussion between the injection well owner or operator and the Director to determine the purpose and proper design of the well.

Regarding the suggestion to allow experimental GS wells to continue to operate under Class V, EPA anticipates that some owners or operators will apply for Class V experimental technology permits for injection into formations including shallow basalts, coal se ams, salt caverns, and shales. These formations may or may not be located above the lowermost USDW or between USDWs. To facilitate experime ntal injection for GS and to increase understanding of injection into these formation types, the Agency is amending the Class V experimental technology guidance. The guidance will be available on EPA's web site at http://water.epa.gov/type/groundw ater/uic/wells_sequestration.cfm. EPA acknowledges that the Class V experimental technology we ll sub-classification may be a ppropriate for these projects, provided they are experimental in nature. EPA e xpects that, following the final GS rule, a limited number of experimental injection projects tes ting GS technology will continue. EPA anticipates that these projects will be small-scale and i nvolve limited CO2 volumes. However, if these projects become larger scale a nd are no longer experimental, they will need to be permitted as Class VI wells. The construction, operation, or ma intenance of any non-expe rimental Class V GS well is prohibited, at §144.15.

For additional information on the waiver approa ch and aquifer exemptions for Class VI wells, please see the final rule and pr eamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0200 Comment ID: 24573 Letter Lines: 201 to 215

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 EPA Rule Issue: 6. The location and proxim ity of other formations to USDWs may preclude their use for GS. EPA seeks commen t on prohibiting inje ction into such formations if they are above th e lowermost USDW. EPA Notice 43503.

Anadarko Petroleum Corporation (APC) Re sponse: Restricting injection to formations below the lowermost underground source of drinking water or USDW is not necessary for the protection of USDWs and would remove a vast number of

viable formations from consideration. I ndustry has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent exam ple is the Salt Cree k EOR project in Wyoming, which has a USDW below the inject ion zone. Moreover, under the proposed

rule, there are other measures that woul d provide real assura nce of formation integrity and require operators to dem onstrate that their project will not

10endanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: EPA agrees that it is not appropriate to set a mi nimum injection depth for GS projects and the Agency believes that a determ ination of site-suitabili ty for GS (i.e., that

subsurface formations will receiv e and confine injected CO2) s hould be made on a site-specific basis. The GS rule, at §146.82, requires the owne r or operator to provide extensive site- and project-specific information to the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contai ned within the injection formation, and that USDWs will be protected from endangerment.

Letter ID: 0200 Comment ID: 24574 Letter Lines: 217 to 248

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

Comment: Rule Provisions: 146.81(b), 146.81(d) EPA Rule Issue: 7. By defining "carbon di oxide stream" to exclude hazardous wastes (146.81(d)), EPA’s rule, if finaliz ed, assures that it would apply only

to CO2 streams that are not hazardous wast es as defined in 40 CFR Part 261. As a result, EPA’s proposed rule would preclude the injection of hazardous wastes in Class VI injection wells. EPA seeks co mment on this approach and other considerations associated with the pres ence of "impurities" in the CO2 stream.

EPA Notice 43503.

Anadarko Petroleum Corporation (APC) Respons e: APC agrees with the concept that Class VI wells should not be injecting hazardous wastes but is proposing some

modifications to EPA’s definition of CO2 stream in the rule. The modifications

reflect the fact that the so urce of CO2 should not be a f actor in the context of defining the CO2 stream. The rule applies to the injection of CO2 and should not address the origins of the materials si nce that is beyond the scope of this regulation. The original text would have precluded inje ction of CO2 from some sources. The question of how CO2 should be accounted for in a GHG management and accounting system is beyond the scope of this regulation.

More to the issue of "impurities", APC objects to any mandated purity standards for CO2. The inclusion of impurities in st ored CO2 should not be arbitrarily prohibited; however, it is recognized that the presence of those impurities at sufficient concentrations may trigger th e applicability of other statutory limits or requirements. Determining the t ype and levels of impurities in the CO2 stream is " absent a compelling public or environmental health risk " best left to contractual negotiations between partners in a CCS value chain as opposed to an arbitrary regulatory determination. The contracting parties are best able to evaluate the types of impu rities, their compatibility with the reservoir and equipment, and determine the acceptable leve ls of those impurities in the stored

CO2. To the extent that there is an overriding public interest in limiting either the type or level of contaminants , principles of cost-effectiveness and risk-management should guide the decision making process.

11Individual Response: EPA understands that many CO2 str eams may be relatively pure, and

research indicates that the estimated amounts of impurities in a CO2 stream are likely to be low.

However, these estimates are based on limited in formation, and uncertainties remain about the expected concentrations of impurities from the va rious types of CO2 streams. The concentrations

of minor and trace elements in CO2 streams for GS projects are likely to vary by facility, coal composition, plant operating conditions, and pollution removal technologies.

The GS rule does not set generic purity standa rds for CO2 injectate streams (e.g., a percent CO2). Instead, the GS rule addresses the quality and quantity of impurities by requiring owners or operators to submit information on the sour ce of the CO2 and its physical and chemical properties. Specifically, the GS rule requires the owner or operator to subm it data about the site, including an analysis of the chemical and physical characteristics of the CO2 stream, as required at §146.82(a)(7)(iv), and information on the compatib ility of the CO2 stream with fluids in the injection zone and minerals in both the injection and the confini ng zones and the materials used to construct the well, per §146.82(c)(3). This info rmation can help the Director determine the potential for geochemical reactions between the injectate (CO2) and the host geologic

formations, which could result in the plugging of pore spaces or the dissolution of formation

minerals.

Since the GS rule, at §146.81(d), prohibits CO2 st reams that meet the definition of a hazardous waste under 40 CFR part 261, injection of a CO2 str eam that is determined to be a hazardous waste may only occur in a Class I hazardous waste injection well.

Letter ID: 0200 Comment ID: 24575 Letter Lines: 250 to 270

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: Rule Provisions: 73 FR 43504 EPA Rule Issue: 8. Class VI requirements and permits will need to be carefully structured to ensure that they do not "authorize" inappropriate hazardous releases. This would include clarifying if there are potential releases from the well which are outside the scope of the Cl ass VI permit. EPA requests comment on particular situations where this might occur. EPA notice 43504.

Anadarko Petroleum Corporation (APC) Respons e: Well chosen sites should prevent these conditions from occurring. At the same time, permit writers should not write permits so restrictive as to ma ke the undertaking of a GS project

untenable. EPA should remember that CERCLA liability will not only impact owners and operators of GS projects, but also hundreds, thousands, and even more numerous pore space owners. EPA should cons ider the threat of subjecting these pore space owners to CERCLA liability. Th eir property interest s in the CO2 GS project injection zones c ould subject them to stri ct, joint, and several liability under CERCLA pursuant to whatever liability theories mi ght be conjured up by future litigants seeking compensati on for response and remediation costs incurred in the cleanup of releases from geologic sequestration injection zones.

12EPA should recognize the significant chilli ng effect CERCLA liability concerns will have on GS projects, and seize the opportunity in this rulemaking to alleviate any CERCLA liability concerns to the greatest extent possible.

Individual Response: CO2 itself is not listed as a hazardous substance under CERCLA; however, the CO2 stream may contain a listed hazardous substance (such as mercury) or may

mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances (such as sulf uric acid). Whether such subs tances may result in CERCLA liability from a sequestration f acility depends entirely on the composition of the specific CO2

stream and the environmental media in which it is stored (e.g., soil or ground water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain “federally permitted releases” (FPR) as defined in CERCLA, 42 U.S. C. 9601(10). Class VI permits will need to be carefully structured to ensure that they prevent potential releases from the well which are outside the scope of the Class VI permit.

Furthermore, EPA is promulgating the GS rule un der the authority of th e SDWA. To the extent the commenter is seeking interpretations of CE RCLA and its related pr ovisions, such as the definition of a federally permitted release, such interpretations are beyond the scope of this rulemaking.

EPA agrees that proper site characterization a nd operation of a GS project is important for protecting USDWs from endangerment. The UIC pr ogram Director also has authority under the SDWA to address potential compliance issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in the unlikely even t that a remedial response is necessary. Although EPA anticipates that the need fo r emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that emergency and remedial response plans be developed and updated to address such events an d that owners or operators demonstrate that financial resources are set aside to imp lement the plans if necessary, per §146.85.

EPA adds that promoting the use of GS is outsi de the scope of the GS rule. Rather, the purpose of the GS regulation is to ensu re that, where deployed, GS is c onducted in a manner that protects USDWs from endangerment.

Letter ID: 0200 Comment ID: 24576 Letter Lines: 272 to 281

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment)

Comment: Rule Provisions: 73 FR 43504 EPA Rule Issue: 9. EPA also requests comm ent on other consider ations associated with the presence of impurities in the CO 2 stream related to CERCLA. EPA Notice

43504.

Anadarko Petroleum Corporation (APC) Res ponse: APC is concer ned that potential CERCLA liabilities will have the potentia l to chill enthusia sm for undertaking GS projects. EPA needs to respond clearly and positively to this concern by developing appropriate language to provide the clarity a nd assurance needed to

13promote continued research and development for GS projects.

Individual Response: As described above, promoting the use of GS is outside the scope of the GS rule. Rather, the purpose of the GS regula tion is to ensure that, where deployed, GS is conducted in a manner that protect s USDWs from endangerment.

Letter ID: 0200 Comment ID: 24577 Letter Lines: 283 to 305

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

Comment: Rule Provisions: 73 FR 43506 EPA Rule Issue: 10. EPA’s proposal would pr ovide the Director the discretion to require the owner or operator to identify and characterize additional confining and containment zones above the primary (i .e., lowermost) confining zone that could further impede vertical fluid moveme nt and allow for pressure dissipation. EPA says that these layers could pr ovide additional site s for monitoring, mitigation, and remediation. EPA’s propos al would not require that these

additional zones be identifie d for all GS sites because their absence does not necessarily indicate inappropria teness of a GS site. Howe ver, if such zones are present, information about their ch aracteristics can pr ovide inputs for predictive models, identify appropriate m onitoring locations, and improve public confidence in and acceptance of a proposed GS site. EPA specifically seeks comment on the merits of requiring the iden tification of these additional zones.

EPA Notice 43506.

Anadarko Petroleum Corporation (APC) Res ponse: By utilizing the definition of confining zone (a geologic formation, group of formations, or part of a formation stratigraphically overlying the in jection zone that acts as a barrier to fluid movement) the EPA has provided n ecessary guidance to prevent movement of fluids from the injection zone wh ich may potentially endanger a USDW. The

director discretion does not provide for any additiona l protection level of

USDWs but does create issues and uncertain ty by allowing the dire ctor to require

dditional zones without scientific basis.

Individual Response: EPA retains the requirement to iden tify additional containment/confining zones, if required by the Di rector, as proposed (§146.83(b)). EPA acknowledges that such additional zones may not be needed in all circumst ances, and clarifies that this requirement is at

the Director's discretion, based on his or her understanding of a part icular site. EPA believes that, in some situations, the presence of additional confining and containment zones above the primary (i.e., lowermost) confining zone can improve USDW protecti on. These layers could further impede vertical fluid movement and al low for pressure dissipation, and also provide additional sites for monitoring, mitigation, and re mediation. The Agency's decision is supported by commenters representing states, water associati ons, and an electric utility who assert that these requirements promote a flexible, risk-base d, site-specific approach to characterizing and

14permitting a site for GS projects, and are intende d to improve understanding of the project as a whole and promote better modeling of the site.

Letter ID: 0200 Comment ID: 24578 Letter Lines: 307 to 330

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking comment)

Comment: Rule Provisions: 146.82( c), 146.84, 146.90(d)(2) EPA Rule Issue: 11. EPA believes that pr edicting the complex multi-phase buoyant flow of the CO2, "co-injectates," and co mpounds that may be mobilized due to injection requires the sophistication of computational models. EPA proposes that the owners or operators of GS wells be required to delineate the AoR for CO2 GS sites using computational fluid flow m odels designed for the specific site conditions and injection regime. EPA seek s comment on the use of modeling for

AoR delineation. EPA Notice 43506.

Anadarko Petroleum Corporation (APC) Res ponse: Modeling is a well developed technology that can readily si mulate complex behavior of injected CO2. It should be one of the techniques used to delin eate the AoR. Modeling alone though should not be the sole basis for determining the AoR. Other technologies such as

seismic and/or use of off-set wells, shoul d also be considered when delineating the proposed AoR.

The oil and gas industry has a great deal of experience that can be generally applied in the delineation of the AoR.

The most complex model is not always nece ssary to adequately delineate the AoR. Nor is it necessary to specify only on e model as this would hinder the development of future models and technique s. Therefore, APC recommends that EPA provide flexibility in the rule to accomm odate the use of future technologies and refrain from unnecessarily prescriptive measures.

Individual Response: EPA agrees that the oil and gas indus try has contributed to the state of modeling science, and anticipat es that some industry-developed modeling products will be acceptable for models in the AoR for GS sites, as long as GS well operators clearly disclose, to

the Director's satisfaction, the code assumptions, relevant equa tions, and scientific basis.

EPA clarifies that the model i nputs must include act ual geologic information, data collected during the site characterization process (e.g., information about artificial penetrations), and anticipated operating parameters (e.g., injection rates) submitted with the permit application under §146.82. Models will be revised and recalibr ated during subsequent AoR reevaluations,

which must account for all avai lable monitoring and operational data, as required at §146.84(e).

EPA encourages and expects owners or operato rs to use the most appropriate multiphase computational models available to determine th e AoR. However, EPA doe s not believe that the

15most "complex" model will, in all cases, be the best available AoR delineation model. The requirements at §146.84(c)(1) are designed to allow the owner or operator to choose, in consultation with the Director, the modeling platform that is most appropri ate for a particular GS project.

EPA anticipates that modeling technology will con tinue to improve, and encourages and expects owners or operators to use the best available multiphase computational models to determine the AoR. Reliance on improved models will likely increase the accuracy and quality of the AoR

characterization, resu lting in increased protection of USDWs from endangerment.

Letter ID: 0200 Comment ID: 24579 Letter Lines: 332 to 359

Comment Code: 3350 2.2.1.5 Use of proprietary models for GS sites (seeking comment)

Comment: Rule Provisions: 146.84

EPA Rule Issue: 12. In some cases, owne rs or operators may choose to use proprietary models (i.e., not available for free to the general public). EPA says it is aware that the use of proprietary codes ma y prevent full evaluation of model results (e.g., NRC, 2007). Severa l popular codes in the petroleumreservoir engineering discipline are propr ietary and owners or operators of particular sites may prefer to use these codes as they have previous experience with them, and they have been used in peerreviewed studies to model CO2 sequestration. When using a proprietary model, owners or operators should clearly disclose the code assumptions, rele vant equations, and sc ientific basis. EPA seeks comment on allowing the use of pr oprietary models for GS sites. EPA

Notice 43507.

Anadarko Petroleum Corporation (APC) Re sponse: It is crit ical to allow proprietary models to be used. EPA’ s Confidential Business Information requirements should apply to any propriet ary model used. APC recommends EPA allow the use of proprietary models and clearly state that CBI requirements will apply.

While there has been concern raised on th e current model’s ability to predict

fluid flow in saline reservoirs, the deve lopment of technologies in this area will only progress when there is an economic driver that proprietary models will provide. In addition, being able to see the assumptions and equations of the model will provide the regulating authority the ability to assess the models accuracy. The currently propos ed regulations also contain requirements to

revisit these models when the actual site data no l onger supports the models conclusions, or at a minimum of every 10 years, which APC believes is sufficient to ensure the viability of the models and data generated from their use.

Individual Response: EPA agrees that some of the availa ble proprietary models may meet the needs for calculating the AoRs of GS sites. EPA will allow their use in meeting the requirements

16for the GS regulation, but clarifies that GS well operators using proprietary models are required

to disclose, to the Director's sa tisfaction, the code assumptions, re levant equations, and scientific basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir engineering professionals as we ll as in peer-reviewed studies to model CO2 sequestration. EPA

adds that its Confidential Business Informati on requirements at 40 CFR 144.5 will apply to the use of proprietary models. Information includin g model assumptions and equations are used by

the Director to inform his/her decision to issu e the permit and ensure that the requirements are met and the GS well will not endanger USDWs. EPA adds that its Confidential Business Information requirements at 40 CFR 144.5 will apply to the use of proprietary models.

EPA clarifies that the GS rule re quires that the AoR be reevaluate d (§146.84(e)) to verify that the CO2 plume is moving as predicted and to al low for necessary revisions to the AoR and corrective action plan. This process will also serve to validate the modeling approach, as the

commenter suggests.

Regarding the commenter’s concern about current m odeling ability to predict fluid flow in saline reservoirs, EPA adds that throughout devel opment of the proposed GS regulation, EPA conducted a number of technical workshops i nviting expert advice regarding modeling, and evaluated peer-reviewed journal articles and performed critical reviews pertaining to computational modeling of CO2 injection. Informa tion collected from these efforts assured the Agency that available complex computational m odels can effectively simulate CO2 transport, fate and changes in formation pressure in three dimensions as a function of time. However, EPA agrees with the commenter that modeling technology will evolve and improve over the coming years. The Agency plans, every six years, to co llect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modificatio ns to the requirements are appropriate or

necessary.

Letter ID: 0200 Comment ID: 24580 Letter Lines: 361 to 368

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking comment)

Comment: Rule Provisions: 146.84

EPA Rule Issue: 13. EPA seeks comment on the applicability of computational fluid flow models for delineating th e AoR of GS sites. EPA Notice 43507.

Anadarko Petroleum Corporation (APC) Res ponse: While computational fluid flow

models can inform the delineation of the AoR, modeling shouldn’t be the sole criteria for determining AoR. (See Co mments to EPA Notice 43506 and 43507 above also.)

Individual Response: EPA agrees that the AoR should not be based exclusively on modeling. EPA has clarified the AoR modeling requirement in §146.84(c)(1) for the final rule. It now reads, “Predict, using existing site characte rization, monitoring a nd operational data, and

17computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, until pressure differentials sufficient to cause the movement of injected

fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time period as determined by the Director.”

EPA clarifies that the model i nputs must include act ual geologic information, data collected during the site characterization process (e.g., information about artificial penetrations), and anticipated operating parameters (e.g., injection rates) submitted with the permit application under §146.82. This would include any seismic or off-set well data collected to meet the requirements of §146.82(a). Models will be revise d and recalibrated during subsequent AoR

reevaluations, which must account for all availa ble monitoring and operational data, as required at §146.84(e).

Letter ID: 0200 Comment ID: 24581 Letter Lines: 370 to 378

Comment Code: 3530 2.2.3.1 AoR reevaluation fre quency (seeking comment)

Comment: Rule Provisions: 146.84

EPA Rule Issue: 14. EPA seeks comment on requiring the reevaluation of the site AoR on a periodic basis, under what condi tions the AoR should be reevaluated, and the appropriateness of a 10- year minimum fixed frequency for AoR

reevaluation. EPA Notice 43507.

Anadarko Petroleum Corporation (APC) Res ponse: Ten years is acceptable as long as reevaluation at this frequency is coupled with the ongoing duty to monitor for changes that would trigger an earlier reevaluation of the AoR.

Individual Response: Based on evaluation of the public comments on this topic, EPA has changed the minimum frequency for the AoR re evaluation at §146.84(e) from ten years to at least every five years. EPA believes that this revised frequency addre sses concerns raised by commenters representing water a ssociations, an energy company, a ssociations, industries, states, and environmental groups about the inherent uncertainties in modeling CO2 movement, the emerging nature of GS technology, risk-based targeting of monitoring activities, and the unique

nature of CO2 GS.

The five-year reevaluation frequency, particular ly during early stages of GS deployment, will also support EPA's adaptive approach to the GS rulemaking. EPA is using an adaptive approach to regulating GS. The Agency plan s, every six years, to collect a nd 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.

18Letter ID: 0200 Comment ID: 24582 Letter Lines: 380 to 406

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action

Comment: Rule Provisions: 146.84(f) EPA Rule Issue: 15. EPA proposes to allow a phased approach to corrective action but says this may not be appropriate in all situations; therefore EPA is proposing that the Director have the discretion to decide to allow this approach, based on the unders tanding of relevant geol ogic and site conditions. EPA invites public comment on the merits and frequency of reevaluation of the AoR as well as the phased corrective acti on approach for GS wells. EPA Notice

43508.

Anadarko Petroleum Corporation (APC) Re sponse: APC supports the EPA proposal. The phased approach allows the sound ec onomic execution of the project over time without endangering USDWs. This approach prevents an operator from remediating wells in an area that ultimately may not be affected by the storage project.

Allowing a phased approach for corrective ac tion is also imperative for economic success of many projects. The upfront cap ital cost for sequestration will be extensive, and requiring corrective action upfront may be economically unfeasible. For instance Anadarko has spen t over $10 million addressing historic wells at one of our EOR ope rations; this site is significantly smaller than those that may be involved in large seque stration projects. Th erefore, allowing corrective actions in a phased manner wi ll provide the flexibility needed to address operational and economic issues . Beyond the potential for significant economic expenditure, the availability of work-over rigs may also provide a difficult time-delay for starti ng sequestration projects.

Frequency of reevaluation should be based on site performance as noted in the prior comment.

Individual Response: EPA acknowledges the commenter’s s upport of phased corrective action and agrees that phased corrective action may provide many benefits to a project including, but not limited to, spreading the burden of cost, avoi ding delays in project start-up, allowing for use of future, improved corrective act ion techniques, and addressing unanticipated changes in the movement of the CO2 plume or pressure front . EPA believes that the phased corrective action approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS regulation.

Regarding the comment that AoR reevaluation fre quency should be based on site performance,

as described above, EPA believes that periodic AoR reevaluation at a set frequency of at least every five years is necessary to ensure protec tion of USDWs from endang erment and address the uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a deliberate effort is made to verify, base d on monitoring and operational data, that the CO2

19plume is moving within the subsurface as predicted.

Letter ID: 0200 Comment ID: 24587 Letter Lines: 429 to 450

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

Comment: Rule Provisions: 146.81(c)

EPA Rule Issue: 17. EPA also seeks comme nt on how the proposed grandfathering provisions for existing wells (construction requirements) may affect compliance with the above, proposed construc tion requirements. EPA Notice 43509.

Anadarko Petroleum Corporation (APC) Res ponse: Anadarko does not believe the construction requirements above current Class II standards are necessary (in particular cement to surface). The pur pose of grandfatheri ng is to recognize that some wells may not meet constructi on requirements of Class VI wells, but the performance of Class II CO2 injection wells justifies their use as Class II CO2 Storage wells ("Class IIb") or Cla ss VI wells if EPA does not adopt a special subclass for storage under the Cla ss II program. Class II EOR has proven successful at preventing contamination of US DWs. As mentioned in response to EPA Notice 43502, utilizing a sub-class of Cl ass II (Class II GS) would provide a

means to handle the additional monitori ng requirements from sequestration applications.

Grandfathering should be handled on a cas e-by-case basis. The standard for grandfathering should be demonstrated performance of the well at protecting

USDWs. Because the act of injection would be the sa me for CO2 EOR and CO2 storage, Class II CO2 EOR wells should be deemed to meet the requirements of 146.86 and 146.87 upon notification.

Individual Response: EPA agrees that many Class II well s 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 ensure protection of USDWs, in lieu of re quirements at §146.86(b) and §146.87(a). The final Class VI regulations require that any owner or operator injecting CO2 for the primary purpose of long term storage obtain a Class VI permit with some special consideration for the fact that they are transitioning from a well not originally designed to meet Class VI requirements. The Director has the authority to determine at what point a Cl ass VI permit is required for those projects that are transitioning from the primary purpose of EOR to long term storage of CO2. The final regulation provides a set of tec hnical factors for the Director to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility. EPA adds that, following re-permitting as Class VI wells, these projects would be subject to the operational, MIT, monitoring, reporting, plugging, and post-injection site care and site clos ure requirements in the final GS rule.

20Letter ID: 0200 Comment ID: 24588 Letter Lines: 452 to 461

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment)

Comment: Rule Provisions: 146.86

EPA Rule Issue: 18. EPA seeks comment on the merits of horizontal well drilling techniques for GS wells and the applicab ility of well construction requirements discussed in this proposal. EPA Notice 43509.

Anadarko Petroleum Corporation (APC) Re sponse: Drilling of directional and

horizontal wells is a well established technology that can significantly reduce surface impacts of a GS project as well as improve injection rate of a well. Horizontal wells are currently being util ized in EOR operations and CO2 storage operations successfully.

Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In the proposed rule, EPA sought comment on the appr opriateness of horizontal drilling techniques

for Class VI wells, and commenters representing energy companies, el ectric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously suppo rted the concept and provided many reasons why horizonta l wells could be beneficial at GS sites. Based on an evaluation of these comments and additional research by EPA, the Agency has concluded that horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to meet the requirements of the GS rule) can ensu re the protection of USDW s from endangerment.

Letter ID: 0200 Comment ID: 24589 Letter Lines: 463 to 480

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

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

Comment: Rule Provisions: 146.86, 73 FR 43510

EPA Rule Issue: 19. EPA seeks comment re garding requirements for degradationresistant well construction materials, such as acid-resistant cements and corrosion resistant casing. EPA Notice 43510.

Anadarko Petroleum Corporation (APC) Respons e: The well should be looked at as a system such that not each individual com ponent needs to be CO2 resistant as long as the entire system provides an e ffective barrier unde r the subsurface conditions. Industry experience with CO2 EOR strongly supports the use of conventional oil field tubing, casing, and cements. Wells cemented with basic cement that have been exposed to CO2 fo r several decades have demonstrated minimal degradation and have been prot ective of USDWs (Ref erence: Crow. CO2 Capture Project Field Study of a Well bore from a Natural CO2 Reservoir).

Industry experience over the past 35 year s has led to the development of

21corrosion mitigation measures (e.g. plasti c or epoxy lined tubing, use of corrosion inhibitors, and proper dehydrati on of CO2) that provide a high degree of protection and mitigate any corro sive effects of injected CO2.

Individual Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of enhanced reco very, and that this practice has led to the development of many corrosion mitigation measures that would be appropriate for the design of

Class VI wells.

EPA believes that the GS rule provides flexibil ity: it does not specify materials to be used. Rather, it provides owners or operators with the flexibility to choose, as long as the materials used in Class VI wells are compatible with flui ds with which they may come into contact and meet or exceed standards developed for such materials by API or ASTM International, or comparable standards approved by the Director , as provided at §146.86(b)(1). However, EPA

clarifies that each individual co mponent of the well system must be described by the owner or operator and will be evaluated by the Director and must meet the requirements of the GS rule.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24590 Letter Lines: 482 to 494

Comment Code: 4130 2.4.1.3 Appropriateness of using fractur ing for well stimulation (seeking comment)

Comment: Rule Provisions: 146.88(a) EPA Rule Issue: 20. EPA is requesting comme nt on the extent and scope to which hydraulic fracturing should be allowed dur ing GS injection, and whether the use of fracturing for the purposes of well s timulation is appropriate. EPA Notice

43511.

Anadarko Petroleum Corporation (APC) Re sponse: The use of fracturing for stimulation should be allowed provided that there is no damage to the confining

unit that would result in endangerment of USDWs. Industry has demonstrated the ability to fracture injection zones wit hout jeopardizing the integrity of the confining unit. There are computer simula tors to predict fracture behavior so the impact on the confining zone can be anticipated and accounted for in designing any proposed operati ons involving fracturing.

Individual Response: EPA agrees that hydraulic fractur ing may be appropriate in some

situations, and the final rule a llows the use of hydraulic fracturi ng at GS sites, where approved by the Director. Hydraulic fractur ing is one of several stimula tion technologies available to improve wellbore and formation injectivity. EPA clarifies that fracturing is permitted during stimulation, but not during injec tion. During injection, the injection pressure must not exceed 90

22percent of the fracture pressu re, as specified in §146.88(a).

All stimulation, including hydraulic fracturing, must be approved by th e Director. Owners or operators must submit a proposed stimulation program as part of the permit application under §146.82(a)(9); the plan must demonstrate that any stimulation activities will not compromise the integrity of the confining zone. The Director wi ll evaluate the owner or operator's proposed stimulation plan in the context of all information about the site , and the owner or operator must perform stimulation only as approved. It is possi ble that computer simulations may support this

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit application, including modeling of the AoR, w ill inform the Director's decision on whether hydraulic fracturing is accep table at a GS site.

Letter ID: 0200 Comment ID: 24591 Letter Lines: 496 to 501

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

Comment: Rule Provisions: 73 FR 43511 EPA Rule Issue: 21. EPA is also requesti ng information to better qualify the use of fracturing for GS injection in specific geologic settings and rock formation lithologies. EPA Notice 43511.

Anadarko Petroleum Corporation (APC) Res ponse: See response to EPA Notice 43511.

Individual Response: As described above, the final ru le allows fracturing only during

stimulation and where the Direct or approves such action. At §146.88(a) , the rule language states that the injection pressure may not exceed 90 per cent of the fracture pressure of the injection zone, except during stimulation.

Letter ID: 0200 Comment ID: 24592 Letter Lines: 503 to 526

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

Comment: Rule Provisions: 146.88(e)

EPA Rule Issue: 22. EPA seeks comment on the merits of requiring down-hole shutoff valves in GS wells. EPA Notice 43511.

Anadarko Petroleum Corporation (APC) Respons e: Over-pressure pr otection is best achieved by ensuring compatibility of the casing/tubing material design strength with the surface injection (compression) system. Down-hole shut-in devices are not appropriate for this application. Thes e devises are installed in the tubing string and are typically near the surface of the well. They’re intended to seal the tubing in the event of catastrophic failure of the wellhead. These devises would provide little if any protection to USDWs. It is not practicable to install these devises deep within the well (e.g. shor tly above the packer). Additionally these devises create a restriction on r unning other tools like

23logging tools in the well and therefore c ould limit an operator’s ability to perform required monitoring and diagnostic work. Lastly, these devises require periodic testing and maintenance which c ould require either pulling the devise by wireline or by pulling the entire tubing string de pending on the type of

devise installed. Either of these activi ties would be disruptiv e and costly to the overall project operations.

To address EPA’s concerns while ma intaining the necessary operational flexibility, APC recommends EPA allow for the installation of landing nipples at appropriate points in the tubing string which would allow use of wireline retrievable plugs when needed.

Individual Response: EPA acknowledges that proper design of the well, including appropriate materials and emplacement of casing and tubing, is essential to proper operation of the well. Such design, however, does not eliminate the possi bility of failure, e.g., due to overpressurization as suggested by the commenter. EP A believes that a multiple-barrier approach, which includes appropriate well design as required at §146.86, suitable injection pressure limits as required at §146.88(a), and automatic shut-off sy stems, as required at §146.88(e), is necessary to ensure protection of USDWs from endangerm ent from the risks asso ciated with CO2 GS.

Landing nipples, which are machined portions of the tubing that allow the seating of components–such as safety valves—at a later time, can be used to deploy safety valves after the initial well completion. EPA believe s, however, that if the shut-off system is not deployed until

the failure occurs, CO2 will be free to flow out of the well until the shut-off valve is deployed. Since installing the new shut-off system will requ ire getting the device to the site, setting up a rig, and deploying the device down the well, a si gnificant amount of time could elapse following

an adverse event before the well is sealed. EPA believes that the risks of uncontrolled CO2 flow are too great to be allowed for such a length of time.

After evaluating the risk s and benefits of down-hole shut-off systems and considering additional research, EPA will not require automatic down-ho le 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), re quires that owners or operato rs of onshore Class VI wells

install automatic surface shut-off devices. The ru le affords Director's discretion to mandate

automatic down-hole shut-off devices in onshore situ ations that may warrant their use. However, the Agency believes that offshore Class VI we lls present unique construction and operational conditions, including isolation from shorelines and the need to c onstruct wells th rough the water column and the subsurface, which may delay res ponse time in the event of well difficulties. The rule requires, at §146.88(e)(3), that owners or oper ators of offshore wells w ithin State territorial waters install automatic down-hole shut-off system s. EPA believes that these requirements at §146.88(e) ensure that proper precautions are take n to prevent subsurface fluid movement and ensure protection of USDWs.

Letter ID: 0200 Comment ID: 24593 Letter Lines: 528 to 546

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between

24USDWs in certain circumstances

Comment: Rule Provisions: 144.6(f), 146.5, 146.81

EPA Rule Issue: 23. EPA is aware that the proposed requirement of injecting CO2 below the lowermost USDW may preclude inje ction into certain targeted geologic formations, which may be storage sites cu rrently under consideration for GS. As a result, the Agency is considering and requesting comment on alternative approaches that would allow injection be tween and/or above the lowermost USDW, and thus potentially allow for more areas to be available for GS while preventing USDW endangerment. EPA Notice 43512.

Anadarko Petroleum Corporation (APC) Respons e: Injection above the lowest USDW should be allowed but the operator must de monstrate confinement above and below the injection formation. Retain ing the restriction would re move a vast number of

viable formations from consideration. I ndustry has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent exam ple is the Salt Cree k EOR project in Wyoming, which has a USDW below the inject ion zone. Moreover, under the proposed

rule, there are other measures that woul d provide assurance regarding formation integrity and require operators to dem onstrate that their project will not ndanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: EPA acknowledges that there are lim ited circumstances where injection above the lowermost USDW can be performed in a manner that protects USDWs, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the Cl ass VI injection depth requirements for injection

into non-USDW formations above and/or between USDWs. The waiver approach requires the submission of extensive, site-specific informa tion (in conjunction with the permit application submission) to demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be done in a manner that is protectiv e of USDWs. The requirements are designed to ensure that the owner or operato r, the Director, and the Region al Administrator consider, on a site specific basis, the implications, benefits, and challenges associated with GS and ensuring water availability and USDW protection. For additional information on the waiver approach, please see the final rule and pr eamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0200 Comment ID: 24594 Letter Lines: 548 to 556

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between

USDWs in certain circumstances

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 EPA Rule Issue: 24. EPA is soliciting comme nt on whether CO2 injection should be allowed into an injection zone above th e lowermost USDW, when the Director determines that geologic conditions (e .g., thousands of feet of intervening formations between the injection zone and the overlying and/or underlying USDWs)

25exist that will prevent fluid movement into adjacent USDWs. EPA Notice 43512.

Anadarko Petroleum Corporation (APC) Res ponse: See above response to EPA Notice

43512.

Individual Response: As described above, EPA acknowledges that there are limited circumstances where injection above the lowerm ost USDW can be performed in a manner that protects USDWs from endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a pr ocess by which owners or operato rs can seek a waiver of the Class VI injection depth requirements for inje ction into non-USDW form ations above and/or

between USDWs.

Letter ID: 0200 Comment ID: 24595 Letter Lines: 558 to 567

Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain

circumstances

Comment: Rule Provisions: 73 FR 43512 EPA Rule Issue: 25. EPA is also requ esting comments on whether aquifer exemptions should be allowed for the pur pose of Class VI injection, and under what conditions should such aquifer ex emptions be approved. EPA Notice 43512.

Anadarko Petroleum Corporation (APC) Respons e: There should be no changes to the aquifer exemption requirements in the UIC program as it exists today. Each aquifer exemption should be considered on a case-specific basis. However, there should also be no requirement that sequestration be below the lowest USDW (see comment to EPA Notice 43512 above).

Individual Response: EPA acknowledges that there are lim ited circumstances where aquifer exemptions for GS may be warranted. The final rule allows for the expansion of the areal extent of existing aquifer exemptions for Class II EOR/ EGR wells transitioning to Class VI injection for GS pursuant to requirements at §§146.4 and 144.7( d). Class VI owners or operators granted expansions of existing Class II EO R/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that is, aquifer exemptions will only be granted for projects that are transitioning from Class II

EOR/EGR wells to Class VI.

EPA clarifies that all decisions regarding expansi on of existing aquifer exemptions will be at the

Director's discretion and based on site-specific information. If an owner or operator applies for a Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that is located above and/or between USDWs, the permit applicant must also apply for a waiver of the injection depth requirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the injection zone are pr otected from endangerment.

26For additional information on aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EPA's responses to comments on the Notice of Da ta Availability and Request for Comment.

Letter ID: 0200 Comment ID: 24596 Letter Lines: 569 to 580

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth

Comment: Rule Provisions: 73 FR 43512

EPA Rule Issue: 26. EPA seeks comment on wh ether the Agency should set a minimum injection depth requirement for CO2 GS, rath er than require that such injection take place below the lowermost USDW. EPA Notice 43512.

Anadarko Petroleum Corporation (APC) Res ponse: There should be no minimum depth for injection of CO2. The primary consider ation should be protect ion of USDWs. A requirement for a minimum depth suggest s an intention by EPA to require injection of CO2 in a supercritical phase. Such a requirement is not appropriate since there may be areas where injection of CO2 in other phases may be the only option. Again, site-specific evaluation a nd protection of USDWs should be the basis for determining depth of injection.

Individual Response: EPA agrees that it is not appropriate to set a mi nimum injection depth for GS projects or require that the CO2 be injected in a supercriti cal state. EPA believes that a determination of site-suitability for GS (i.e., th at subsurface formations will receive and confine injected CO2) should be made on a site-speci fic basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific information to the Director to

demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, and that USDWs will be protected from endangerment.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that protec ts USDWs, as long as appropriate protections are in place. The final GS rule at §146.95 establis hes a process by which owners or operators can seek a waiver of the Class VI injection de pth requirements for in jection into non-USDW

formations above and/or between USDWs. The waiver approach requires the submission of extensive, site-specific information (in conjunc tion with the permit appl ication submission) to demonstrate that injection of CO2 into a non-US DW that is above or between USDWs can be done in a manner that is protective of USDWs. Th e requirements are designed to ensure that the owner or operator, the Director, and the Regional Administrator cons ider, on a site specific basis, the implications, benefits, and challenges associat ed with GS and ensuring water availability and USDW protection. For additional information on the waiver approach, please see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0200 Comment ID: 24597 Letter Lines: 582 to 604

27Comment Code: 4490 2.4.5 Use of tracers and potential im pact on human health or ecosystems (seeking comment)

Comment: Rule Provisions: 73 FR 43513- 15 EPA Rule Issue: 27. EPA’s proposal allows Directors’ discre tion on whether to require the use of tracers, and if so, what types of tracers. EPA seeks comment on the use of tracers in CO2 GS operations, and any potential impact of tracers on human health or ecosystems as they relate to USDWs. EPA Notice 43513.

Anadarko Petroleum Corporation (APC) Response: EPA should not mandate the use of

tracers. The value of trace rs has been questioned by numerous members of the scientific community. Further research of their use need s to be conducted before any final language is approved. Modeling and monitoring are much more reliable techniques for tracking a plume.

Tracers, in general, provide minimal dia gnostic abilities and currently have few practical applications. This technology is still under development and as such should not be required. Currently, most tr acers have the issue of providing false positives, have a significant supply time-delay, have greater environmental impacts than CO2 (PFCs fo r instance), and are very expensive.

Radioactive tracers are utilized the mo st in operations and prove the most useful, but again, only for a limited radius of investigation. Other monitoring techniques are more reliable and operationa l-friendly for tracking the plume and determining CO2 migration. While certain tracers can be useful for near-well trouble-shooting application this technology on a whole is not ready for fieldwide deployment and any regulation mandati ng their use should not be instituted.

Individual Response: EPA agrees that tracer use is not appropriate in all situations. Some tracers may have the potential to cause harm to people or the environmen t. Nevertheless, there are many different types of tr acers and not all are problematic ; research is being done to overcome problems with existing tracers. EPA belie ves that tracers have been used safely and successfully in other applications. For this reason , EPA does not require the use of tracers at all

GS sites; rather, the Director ha s discretion to require their use if he/she determines that the use of tracers could improve monitoring of the site and enhance USDW protection from endangerment. The rule will also allow their use if proposed by the owner or operator and approved by the Director.

EPA has been following new and ongoing research on the safety and efficacy of tracers, and believes that, in some circumstances, tracers can be an effective part of monitoring GS projects.

EPA will continue to track research related to tra cer use and plans to, every six years, collect and review data on GS projects to determine wh ether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0200 Comment ID: 24598 Letter Lines: 606 to 623

28Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment: Rule Provisions: 146.89(b) EPA Rule Issue: 28. EPA’s proposal would requ ire owners or operators of Class VI GS projects to monitor internal mechanical integrity of their injection wells by continuously monitoring injection pressure , flow rate, and injected volumes, as well as the annular pressure and fluid volume to assure that no anomalies occur that may indicate an internal leak. EPA requests comment on the practicability of this requirement. EPA Notice 43513.

Anadarko Petroleum Corporation (APC) Respons e: There is concern regarding what constitutes continuous monitoring. Anadarko agrees that regula r monitoring of the parameters identified by EPA is appr opriate. Our experience with CO2 EOR strongly shows that daily m onitoring of most of these parameters is adequate (exceptions to this would be on a s ite-specific basis). Recording should generally be done on a daily basis and reporting on a semiannual basis. As a guiding principle, the freque ncy of monitoring should be determined by the level of risk posed by the injection operati on and should be set on a case-by-case basis at the permit approval stage taking into consideration the site-specific characteristics of the proposed project.

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal mechanical integrity of Class VI wells (146.89(b)), instead of periodic test ing (which is required for most other types of deep in jection wells) is importa nt given the potential corrosive impact of CO2 and impurities on well materials, the potentia l geomechanical impacts to well integrity due to CO2 phase changes, and the temperature and pressure effects associated with injecting supercritical CO2. EPA also believes that the technology fo r continuous monitoring is practicable, available, and is currently in fairly wide use. At least one commenter indicated that the technology required for conti nuous monitoring is currently available and should not present

an undue cost burden. Continuous annulus monito ring is also conducted at the commercialscaled carbon capture and geologic sequestration operation at the In Salah, Algeria natural gas plant where more than 3 million tons of CO2 have been sequestered since 2004.

Class VI injection wells must be equipped with dedicated computer-based continuous pressure monitoring devices in concert with the shut-off systems required for GS wells, which typically take readings several times per second (i.e., more frequently than daily) and record them electronically in a computer system. 40 CFR §146.91( a)(2) requires that mont hly averages of the continuous annulus monitoring be reported on a semiannual basis. For additional information, please see the discussion of MITs in the final rule preamble.

Letter ID: 0200 Comment ID: 24599

Comment: Individual Response:

29Letter ID: 0200 Comment ID: 24600 Letter Lines: 642 to 655

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

Comment: Rule Provisions: 146.90

EPA Rule Issue: 30. EPA seeks comment on the requirement for monitoring of GS sites for the purpose of track ing the location of the CO 2 plume and associated pressure front over time. EPA Notice 43514

Anadarko Petroleum Corporation (APC) Response: The frequency of monitoring should be dictated by site-specific operat ional and geologic c onditions combined with the results of monitoring with mode l predictions and should be set at the permit approval stage. The guiding principl e for monitoring is to verify proper confinement of the CO2 and ensure protec tion of USDWs. EPA s hould recognize that use of modeling and other monitoring t echniques are relativ ely qualitative processes that can have varying degrees of accuracy that will improve over time in an iterative process, and EPA shou ld provide regulatory flexibility to

account for this.

Individual Response: EPA clarifies that all of the monitoring requirements in the GS rule are for the purpose of ensuring containment so that USDWs are protected from endangerment. EPA believes that knowing the extent of the CO2 plume and pressure front is necessary to make such a determination. Monitoring can also identify n eeded remedial actions, provide inputs for AoR reevaluation modeling, evaluate predictions of plume move ment, and target additional geochemical and surface monitoring needs. Knowledge of the location of the CO2 plume and the associated pressure front will assure the public th at GS projects are proceeding according to plan, provide sufficient information to the owner or op erator and Director, or allow for appropriate actions to address any indication that USDWs may be endangered.

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 believes that monitori ng using wells in the inje ction zone (i.e., that penetrate the confining zone) 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 the benefits of monitoring in the injection formation outweigh the manageable risk of those monitoring wells serving as conduits for fluid movement. EPA adds that owners or operators may consider performi ng additional pressure monitoring in wells that are above the confining zone (e.g., in the same wells used to perform ground water quality monitoring required at §146.90(d)) to provide additional verification that no pressure ch anges are occurr ing above the confining zone due to CO2 leakage.

EPA adds that all monitoring will be conducted pursuant to the approve d testing and monitoring plan, which should be based on site-specific info rmation about the site and planned operations.

30Letter ID: 0200 Comment ID: 24601 Letter Lines: 657 to 667

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

Comment: Rule Provisions: 146.90(f) EPA Rule Issue: 31. EPA’s proposal would require that owners or operators perform a pressure fall-off test at le ast once every five years. EPA seeks comment on the use and frequency of pressu re fall-off testing for GS wells. EPA

Notice 43515.

Anadarko Petroleum Corporation (APC) Res ponse: We recommend that an initial falloff test be conducted upon completion of the well prior to any operational injection and after the first year of ope rational injection. Fo llowing the first year, the frequency should be at the discretion of the Director but the frequency should be aligned with the reevaluation of the AoR.

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 conducted at least every five years.

Letter ID: 0200 Comment ID: 24602 Letter Lines: 669 to 685

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

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

Comment: Rule Provisions: 146.90(g)

EPA Rule Issue: 32. Based on information evaluated to date, EPA believes that tracking the plume and pressure front is an important companion step to address any uncertainties associated with initia l AoR modeling and requests comment on this approach and more efficient alternat ives that may be us ed to track the plume and pressure front. EPA Notice 43516.

Anadarko Petroleum Corporation (APC) Res ponse: Plume and pressure front are different concepts and should not be c onfused. They yield information on two different metrics. The former tells yo u about the remaining capacity of the storage formation and the latter describes the direction and movement of the CO2 plume. Based on experience to date, CO2 pl ume can be monitored using surface or wellbore seismic and possibly some remote satellite techniqu es. Monitoring of the pressure front will be more difficult since that requires data from the injection formation which can only be obt ained by drilling a well. Modeling can

31estimate the movement of a pressure front . Those estimations are limited by the accuracy of the model and its iterative adjustments as previously mentioned.

Individual Response: EPA acknowledges that monitoring th e plume and pressure front are different issues and believes that direct pressure measurements are appropriate and that direct pressure monitoring will be feasible at all GS sites. The final rule (at §146.90(g)) requires owners or operators to perform monitoring to tr ack the extent of the CO2 plume and pressure front. The owner or operator must use direct me thods to monitor for pressure changes in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys

and/or down-hole CO2 detection to ols) are also required unless the Director determines, based on site-specific geology, that such methods are not appropriate.

EPA believes that pressure monitoring in th e injection zone is n ecessary to track the development and movement of the pressure front and CO2 plume. Monitoring can also identify needed remedial actions, provide inputs for AoR reevaluation m odeling, evaluate predictions of plume movement, and target additional geoche mical and surface monitoring needs. Knowledge of the location of the CO2 plume and the associated pressure front will assure the public that GS projects are proceeding according to plan, provide sufficient information to the owner or operator and Director, or allow for appr opriate actions to address any indication that USDWs may be endangered.

Letter ID: 0200 Comment ID: 24603 Letter Lines: 687 to 704

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking comment)

Comment: Rule Provisions: 73 FR 43517

EPA Rule Issue: 33. EPA seeks comment on the appropriate amount and types of monitoring that should be conducted at a GS site. Specifically, EPA seeks comment regarding the usefulness of indi rect geophysical monitoring and surface air and soil gas monitoring. In addition, EPA seeks commen t regarding the use of a Directorapproved monitoring plan for GS sites. EPA Notice 43517.

Anadarko Petroleum Corporation (APC) Re sponse: Monitoring techniques and frequency should be determined on a site-s pecific basis. Selec tion of monitoring types and frequency should balance the poten tial risks posed by the project with the cost of monitoring.

Surface and soil gas monitoring does not add value to the protection of USDWs. Many of the surface and soil gas monitoring techniques currently being evaluated lack the track record necessary for us e in a regulatory compliance setting. Moreover, the potential for false-positives could undermine public confidence in GS technologies. EPA should defer on us ing surface and soil gas monitoring technologies until their effectiv eness can be demonstrated.

Individual Response: EPA acknowledges that air and soil gas monitoring to ensure USDW

32protection is not necessary at a ll GS sites and agrees that the decision to use surface monitoring and the selection of monitoring methods for th e purpose of USDW protection will be sitespecific.

The Agency believes that surface air and soil ga s monitoring, when coupled with subsurface monitoring, may be appropriate at some GS projects to ensu re USDW protection. EPA also acknowledges that surface air a nd soil gas measurements are subj ect to variabili ty and may not be suitable in all settings as a method to ensure USDW protection. However, EPA does not believe that this should entirely preclude thei r use. The decision to use surface monitoring and

the selection of monito ring methods will be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on poten tial risks to USDWs

within the AoR.

In the final rule, at §146.90(h), the decision to re quire such monitoring as an additional measure to ensure USDW protection rests with the Direct or as a means of identif ying leaks that may pose a risk to USDWs and informing emergency notifi cation of a Class VI owner or operator and UIC Director in the event of a USDW endangerm ent, pursuant to requirements at §146.91(c).

Letter ID: 0200 Comment ID: 24604 Letter Lines: 706 to 728

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

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

Comment: Rule Provisions: 146.90, 146.93(a), 146.94(a) EPA Rule Issue: 34. EPA is proposing that permit applic ations for GS sites include several plans not currently re quired under existing UIC regulations. These plans include a monitoring and test ing plan, an AoR a nd corrective action plan, and a post-injection site care and s ite closure plan. EPA seeks comment on the merits of requiring plans for monito ring, AoR, and postinje ction site care as part of a permit appl ication. EPA Notice 43517.

Anadarko Petroleum Corporation (APC) Res ponse: The development of plans is a good idea because it negates prescriptive regulation of the process. APC is concerned that every modification of a plan may trigger a major permit modification. Although actual monitoring of injection formation is most

effective, there is still the unintende d consequence of penetrating the confining zone to gain that data. The number of mon itoring wells should not be

established in advance. It is uncle ar how monitoring well construction, operation, and closure will be regulated since these are not actual injection

wells.

Timing of development of plans should be linked to the actual activity being addressed. It should not be necessary to prepare and submit a site closure plan or the post-closure monitoring plan at th e start of the project, particularly considering that these activities will not occur for many years after the

33project starts.

Individual Response: EPA agrees with commenters that developing and following testing and monitoring plans is an important pa rt of assuring that a GS projec t is operating properly and is crucial for the early detection of potential endangerment to USDWs. EPA expects that the number of monitoring wells needed will be determined based on site-specific information. EPA also agrees that periodic updates to the plan are appropriate. EP A clarifies that the final GS regulation includes a requirement th at the AoR be reevaluated at least every five years, and it specifies at §146.90(j) that the oper ator revise the testing and mon itoring plan to incorporate the

results of the most recent AoR reevaluati on and recent operational and monitoring data.

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. The testing and monitoring plan must describe how th e owner or operator plans to site and construct monitoring wells. EPA is developing guidan ce on well construction that will include recommendations for monitoring well constructi on. The guidance will be available on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_sequestration.cfm.

EPA clarifies that every revision to the testing and monitoring plan will not necessarily trigger a major permit modification. The existing regulat ion at 40 CFR 144.39(a) identifies causes for modification of permits that would invoke the pu blic notification procedures at 40 CFR 124. In

the final rule, EPA added text to §144.39(a)(5) that permit modifica tions would be required if the

Director determines that a modification is nece ssary based on an AoR reevaluation, amendments to any of the project plans, or a review of the testing and monitoring results.

In addition, 40 CFR Part 144.41 identifies causes fo r minor modifications of permits (which do not require following the procedur es of Part 124). In the final rule, EPA added a subparagraph (h) to §144.41 that would include minor amendments (e.g., to clarify, correct , or update) to the testing and monitoring plan, plugg ing plan, post-injection site ca re and site closure plan, or emergency and remedial response plan for a GS well (i.e., amendments that are not included under 144.39(a)(5) and that do not require additional permit requirements).

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating re quirements under §146.90. The guida nce can be found on EPA’s website at http://water.epa.gov/type/groundwater/u ic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices ma nual entitled "Monitoring, Verification, and Accounting of CO2 Stored in Deep Geol ogic Formations" (DOE /NETL-311/081508); this

manual is included in the docket for the final GS rule. EPA notes that closure of monitoring wells should be addressed in the post-inj ection site care and site closure plan.

EPA also believes that it is appropriate to re quire owners and operators to submit all plans, including the injection well pluggin g and post-injection site care a nd site closure plans, at the time of permit application. EPA belie ves that the Director needs a satisfactory level of assurance that the owner or operator has pl anned for these events before injection commences and that the

34owner or operator has ensured that appropriate financial reso urces are available to fund all required activities, as required at §146.85. The final rule retains requirements for submitting these plans with the permit application at §146.82(a).

Letter ID: 0200 Comment ID: 24605 Letter Lines: 730 to 737

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment)

Comment: Rule Provisions: 146.91

EPA Rule Issue: 35. EPA seeks comment on the frequency of all proposed reporting requirements. EPA Notice 43517

Anadarko Petroleum Corporation (APC) Re sponse: Frequency should reflect the

level of risk associated with the activ ity. Semi- annual reporting is adequate. Reporting should be on a project basis as opposed to a well basis consistent with 146.23(c).

Individual Response: EPA is retaining the semi-annual repo rting requirements as proposed at §146.91(a). These requirements ensure the Direct or has the information needed to take preventive action in a timely manner to protec t USDWs from endangerment. EPA notes that operators who want to streamline their reporting schedules can negotiate with the permitting authority to establish a schedule that allows repo rting on all wells in a GS project at the same time; however, data for each well must be report ed separately and at least as frequently as required at §146.91. For additional information, pleas e see the final rule and the preamble for a discussion of EPA's final approach to recordkeeping and reporting.

EPA agrees that some monitoring types and fr equencies (e.g., associated with ground water monitoring and plume tracking) will be site-specific. These activities must be established in the approved testing and monitoring plan, which will be incorporated as a condition of the Class VI permit.

Letter ID: 0200 Comment ID: 24606 Letter Lines: 739 to 749

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment)

Comment: Rule Provisions: 146.91(c) EPA Rule Issue: 36. EPA seeks comment on the requirement for electronic reporting in its proposed rule. EPA Notice 43518.

Anadarko Petroleum Corporation (APC) Res ponse: APC strongly supports the concept of electronic reporting. Industry’s objecti ons to prior proposals for electronic reporting have been with the scope and br eadth of information (incremental over written reports) that the Agency has pr eviously proposed. Electronic reporting equivalent to existing written reports would be supported by APC. Until these

35concerns related to electronic reporting are resolved, such reporting may be encouraged but should not be required.

Individual Response: EPA believes that electronic formatting is the most appropriate format for submitting Class VI project information to the Director and requires th is at §146.91(e). Based on comments received on the proposed rule, the majority of Class VI well owners or operators will have the capability to report electronically.

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional data management needs associated with GS act ivities and provides recommended guidelines on the types of data to be collected for tracki ng GS projects, reporti ng to EPA for compliance tracking, and transfer of data to EPA's data system. The recordkeeping and reporting guidance

will be available on EPA's web site, at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24607 Letter Lines: 751 to 766

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

Comment: Rule Provisions: 73 FR 43518

EPA Rule Issue: 37. In addition to th e above recordkeeping and reporting requirements, EPA considered a requirement for owners or operators of GS sites to provide an annual report during the lifetime of the proj ect, including the post-injection period, regarding the GS operation. Although EPA has not included a requirement for this report in its pr oposal, EPA seeks comment regarding the necessity for such an annual report. EPA Notice 43518.

Anadarko Petroleum Corporation (APC) Respons e: An Annual report is not necessary given the other reporting requirements in the Rule. The addition of this report would not produce any new pertinent inform ation to the regula ting agency; and, therefore, only increases their administra tive burden on the agency and requires the generation of needless documents. In keeping with the provisions of the Paperwork Reduction Act, EPA should not re quire an annual report. Alternatively, if this report was to replace the other reporting requirements, there would be value to the proposal.

Individual Response: The final GS regulation retains the reporting requirements as proposed and does not include a requirement for an annua l report. Instead, EPA believes that periodic

reevaluation of the AoR, as re quired at §146.84(e), along with any re visions to the required plans that may be necessary based on the AoR reevaluation, will promote an ongoing relationship between the permitting authority and the owner or operator. The final GS rule, at §§146.84(c), 146.90(j), and 146.94(d), requires owners or oper ators to review and update the AoR and corrective action plan, the testi ng and monitoring plan, and the emergency and remedial response plan throughout the life of the project. Owners or operators mu st review each plan and identify necessary amendments to the plan or demonstrat e to the Director that no amendment is needed. These reviews must be performed within one year of an AoR reevaluation, following any

36significant changes to the facility (e.g., the additi on of monitoring or injection wells), or when required by the Director. In no cas e can reviews occur less often than once every five years. For additional information, please see the final rule an d the preamble for a discussion of EPA's final approach to recordk eeping and reporting.

While the Agency recognizes some concerns expressed by commenters about the burden associated with an annual report, the Agency 's decision to retain the semi-annual reporting requirement at §146.91(a) is because the semi-annua l report in conjunction with the continued dialogue associated with AoR r eevaluations and periodic updates to the plans is a preferred approach to an annual report.

Letter ID: 0200 Comment ID: 24608 Letter Lines: 768 to 790

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

Comment: Rule Provisions: 73 FR 43519-20, 146.93(b) EPA Rule Issue: 38. EPA is proposing using a combination of fixed timeframe and a performance standard as described above. EPA is tent atively proposing a postinjection site care (monitoring) period of 50 years with Director’s discretion to change that period to le ngthen or shorten the 50 year period if appropriate. EPA requests comment on the proposed use of a tentative 50 year fixed timeframe

that could be modified at the Direct or’s discretion base d on monitoring and modeling data. EPA Notice 43519.

Anadarko Petroleum Corporation (APC) Res ponse: APC strongly obj ects to the use of a 50-year default monitoring perio d. EPA offers no rationale for this arbitrarily-selected period of 50 years. Establishing a fixed and unusually long time period may create a significant barrier for operators considering entry into CCS operations. Criteria for determin ing the period for post-injection site care should be performancebased an d a function of th e site specific characteristics of a project such as project size, geologi c factors, and relative risk of the projec t. (APC offers such criteria in the edits to §146.93(b)(3).)

Clear guidelines also need to be establis hed regarding when operators have met the performance standards that determ ine site closure. Specifically, the standard that the project no longer poses an endangerment to USDWs needs to be defined using reasonable risk-based criteria.

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

excessive in most cases or arbi trary. EPA proposed a default post-in jection site car e timeframe of 50 years based on a review of research studies , industry reports, and existing environmental programs. This analysis was included in an EPA- prepared background document that is available in the federal docket, titled "Computationa l Modeling of Underground Injection of Carbon

Dioxide for Determination of Area-of-Review a nd Potential Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes based on additional review of

37research studies and evaluation of public commen ts. While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the commenters provided suffi cient data or other evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe suggested by some of these commenters may be within the timeframe suggested in some studies, EPA believes that the potential risks of endange ring USDWs will likely no t decline within these timeframes and available data, including da ta submitted by commenters, do not support a

different default timeframe. However, EPA r ecognizes that alternative timeframes may be appropriate under limited, specific circumstances.

For this reason, the GS rule offers owners or op erators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, 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).

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.

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in al l but a limited number of cases. This default 50 year post-injection site care ti meframe represents a reasonable and protective monitoring period

based on a review of research studies, industr y reports, and existing environmental programs, and evaluation of public comments.

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requi rements of §146.92 and §146.93. The guidance describes recommended approaches for how an owner or operator could plug injection and monitoring wells, perform post-injection monitoring, demonstr ate the appropriateness ofan alternative postinjection site care time frame, demonstrate non-endangerment, and perform site closure activities. Additionally, the guidance will assist Directors in evalua ting proposed well plugging plans and post-injection s ite care and site closure plans under §146.92 and §146.93. This guidance will be available at h ttp://water.epa.gov/type /groundwater/uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24609 Letter Lines: 792 to 801

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

Comment: Rule Provisions: 146.93

38EPA Rule Issue: 39. EPA is requesting co mments on the proposed requirements for well plugging, postinjection site care, and site closure, including the proposed requirements for the post-injection time period. EPA Notice 43520.

Anadarko Petroleum Corporation (APC) Respons e: It is inappropria te to utilize a fixed period as this does not provide the flexibility to address site-specific issues; instead EPA should adopt a standard that is based on a demonstration of non-endangerment to determine when monito ring is no longer needed. Please see response to EPA 43519.

Individual Response: EPA agrees with commenters that th ere 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 or her disc retion, shorten the post-injection site care timeframe if the owner or operator can demonstrate that the GS project does not pose an endangerment to USDWs, as specified in §146.93(b)(2). Alternativ ely, the final rule at §146.93(c), also allows the Director to approve an alternative post-i njection site care timeframe wh ere an owner or operator can demonstrate during the permitting process that an a lternative post-injection site care timeframe, other than the 50 year default, is appropria te and ensures non-endangerment of USDWs. The demonstration must be based on site-specific in formation, including the results of site-specific computational modeling; the predicted timeframe for pressure decline; the predicted rate of carbon dioxide plume migration; s ite-specific chemical processes that will result in carbon dioxide trapping; the predicted ra te of carbon dioxide trapping; characterization of the confining zone(s); laboratory analyses or studies to veri fy the information on trapping; the presence of potential conduits for fluid movement and the qu ality of abandoned well plugs within the AoR; the distance between the injection zone and the USDWs above and/or below the injection zone; and any additional site-specific f actors determined by the Director . The demonstration must meet the criteria at §146.93(c)(2) for en suring the quality and accuracy of the data and models on which the demonstration is based. This demonstration would be submitted as part of the permit application, per §146.82(a)(18), in addition to th e PISC and site closure plan required at §146.82(a)(17).

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.

EPA believes, however, that to ensure USDW protection from endangerment, a default timeframe for post-injection site care is necessary in most cases. A 50-year post-injection site care timeframe represents a reasonable and protec tive monitoring period fo r most GS projects and available data, including data submitted by commenters, do not support a different default

timeframe. This determination is based on a review of research studies, i ndustry reports, existing

39environmental programs, and ev aluation of public comments.

Letter ID: 0200 Comment ID: 24610 Letter Lines: 803 to 812

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

Comment: Rule Provisions: 146.93(b)(2)

EPA Rule Issue: 40. In addition, EPA s eeks comment on whether the Director

should be allowed to shorten the timefram e based on performance information, and whether EPA should require a shorter or longer post injection period if data suggests the time frame should be adjusted. EPA Notice 43520.

Anadarko Petroleum Corporation (APC) Respons e: It is inappropria te to utilize a fixed period; instead a demonstration of non endangerment is an appropriate means of deciding when monitoring is no l onger needed. Please see response to

EPA 43519.

Individual Response: EPA agrees that there will be circumst ances where it can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to

USDWs. For this reason, the GS ru le offers owners or operators flexibility regard ing the duration of the PISC timeframe by: (1) allowing the Direct or discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, 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).

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in most cases. The default 50 year post-injection site care timeframe represents a reasonable and prot ective monitoring period based on a review of research studies, industry reports, and existing environmental programs, and evaluation of public

comments.

EPA believes that a default post-injection site 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: 0200 Comment ID: 24611 Letter Lines: 814 to 828

40Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: Rule Provisions: 144.36 EPA Rule Issue: 41. Current UIC guidance describes trust funds as a form of financial assurance. The owner or operat or may deposit funds into the trust fund in phases; that is, either over the te rm of the initial permit or over the remaining operating life of the injection well, as estimated in the well plugging plan, whichever period is shorter. Because of th e possibility that the owner or operator may face financial di stress prior to the trust being fully funded, EPA is considering a guidance appr oach that would recommend adopting a pay in period of three years for GS pr ojects, consistent with other similar programs in the Agency. EPA Notice 43521.

Anadarko Petroleum Corporation (APC) Respons e: Industry should ha ve a variety of options for meeting financial assurance based upon the companies’ discretion. Options should include self-insurance , insurance, surety bonds or other appropriate financial instruments.

Individual Response: Owners or operators have the flexib ility to choose from a variety of

financial instruments to meet their financial re sponsibility obligations. Ow ners or operators may use one or multiple financial responsibil ity instruments for well plugging and PISC (§146.85(a)(6)). However EPA will not allow for a separate financial responsibility demonstration for well plugging and PISC (i.e., a demonstration submitted prior to well plugging and the beginning of the post-injec tion site care period rather than with the permit application). A demonstration of financial responsibility for all ph ases of the GS project will be required prior to

the issuance of a Class VI permit (§146.85(a)(5)(i)). The allowable instruments are identified at §146. 85(a). See the final ru le and preamble for further discussion of EPA's final appr oach to financial responsibility.

EPA has clarified the financial responsibility requirements in the final GS rule, and has included at §146.85(a) a list of qualifying financial responsibility inst ruments, including trust funds, surety bonds, letters of credit, insurance, se lf insurance, escrow accounts, or any other instrument(s) satisfactor y to the Director.

Given that the practice of GS is fairly ne w and EPA does not have enough information in supporting future prediction, EPA plans, every six years, to collect and review data on GS projects to determine whether the appropriate amount and types of information and appropriate documentation are being collected, and to determ ine if modifications to the requirements are appropriate or necessary.

Letter ID: 0200 Comment ID: 24612 Letter Lines: 830 to 841

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

41Comment: Rule Provisions: 73 FR 43521 EPA Rule Issue: 42. Current UIC regu lations for Class I hazardous waste injection allow for the use of insurance for purposes of demons trating financial responsibility. However, insurance was not included as part of the guidance provided for Class II injection because th is insurance mechanism was and still is, rarely used for the purpose of de monstrating financia l assurance for injection wells. EPA is assessing whethe r to provide guidance on the use of insurance providers and, if so, whether to update eligibility requirements for

insurers for GS wells consistent with other current Federal agency practices.

EPA Notice 43521.

Anadarko Petroleum Corporation (APC) Res ponse: See response to EPA Notice 43521.

Individual Response: As described above, owners or opera tors may choose from a variety of

financial instruments to meet their financial re sponsibility obligations under the rule, provided the Director determines that the operator's pr oposed financial responsib ility demonstration is adequate to protect USDWs from endangerment, which means the abili ty of the owner or operator to pay for each activity for which fina ncial responsibility must be demonstrated, including corrective acti on on wells in the AoR, injection we ll plugging, PISC and site closure, and emergency and remedial response throughout the life of the project. The final GS rule specifies at §146.85(a)(1) the permitted types of fi nancial responsibility instruments. See the final rule and preamble for further discussion of EP A's final approach to financial responsibility.

Letter ID: 0200 Comment ID: 24613 Letter Lines: 843 to 851

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment: Rule Provisions: 73 FR 43522 EPA Rule Issue: 43. EPA is assessing whet her a financial ratings threshold for all companies using a selfguarantee, sim ilar to those used by other Federal agencies, is appropriate. The Agency also is considering what constitutes an appropriate financial rating threshold, and whether a financial rating greater than BBB or Baa (i.e., the current rati ng threshold established under the UIC regulations) is appropriate for GS wells. EPA Notice 43522.

Anadarko Petroleum Corporation (APC) Res ponse: See response to EPA Notice 43521.

Individual Response: As described above, owners or opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to pay for each activ ity for which financial responsibility must be demonstrated, including correctiv e action on wells in the AoR, in jection well plugging, PISC and site closure, and emergenc y and remedial response.

42Letter ID: 0200 Comment ID: 24614 Letter Lines: 853 to 860

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment: Rule Provisions: 146.85 EPA Rule Issue: 44. EPA is request ing comments on whether financial responsibility mechanisms to be recommended in EPA gui dance should be adjusted

in the manner described, whether additional instruments should be included, and whether other adjustments to the financia l responsibility mechanisms should be considered, all subject to EPA’s aut hority under the SDWA. EPA Notice 43522.

Anadarko Petroleum Corporation (APC) Res ponse: See response to EPA Notice 43521.

Individual Response: As described above, owners or opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to pay for each activ ity for which financial responsibility must be demonstrated, including correctiv e action on wells in the AoR, in jection well plugging, PISC and site closure, and emergenc y and remedial response.

Letter ID: 0200 Comment ID: 24615 Letter Lines: 862 to 867

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and abandonment and post-injection si te care (seeking comment)

Comment: Rule Provisions: 73 FR 43522 EPA Rule Issue: 45. The Agency is also requesting comment on allowing separate

financial demonstrations to be submitted for the plugging of the injection well and for the post-injection site care requirements. EPA Notice 43522.

Anadarko Petroleum Corporation (APC) Res ponse: See response to EPA Notice 43521.

Individual Response: As described above, owners or opera tors may choose from a variety of financial instruments listed in §146.85(a) to m eet their financial responsibility obligations, provided the Director determines that the operator's proposed financial responsibility demonstration is adequate to prevent endangerm ent of USDWs by demonstrating the ability to pay for each activity for which financial res ponsibility must be demonstrated, including corrective action on wells in the AoR, injecti on well plugging, PISC a nd site closure, and emergency and remedial response.

EPA agrees that it is appropriate to allow a flexible approach for financial res ponsibility. Under the final GS rule, owners or opera tors may choose from a variety of financial instruments to meet their financial responsibility needs, provided the Di rector determines that the owner or operator's proposed financial responsibility demonstration is adequate to pay for each activity for which financial responsibility must be demonstrated, including corrective action on wells in the AoR,

43injection well plugging, PISC a nd site closure, and emergenc y and remedial response. The permitted methods are specified at §146.85(a)(1). EP A is developing guidance to help owners or operators, permitting authorities, and third par ties choose and evaluate appropriate financial methods, and states may set more specific financial responsibility requirements if they so choose. This guidance will be available on EPA's website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24617 Letter Lines: 869 to 889

Comment Code: 5540 2.10.2 Need for additional public partic ipation requirements/ use of new information technology (seeking comment)

Comment: Rule Provisions: 73 FR 43523 EPA Rule Issue: 46. EPA requests comment on adopting the existing requirements for public participation at 40 CFR Part 25 and 40 CFR Part 124 and whether additional requirements should be included to reflect the ava ilability of new tools for disseminating and gathering in formation. Such tools include cable

networks, the Internet, and othe r new technology. EPA Notice 43523.

Anadarko Petroleum Corporation (APC) Response: The current prov isions in Parts 25 and 124 are sufficient to inform the public. The EPA should not require new technology for involving the public. As tec hnological advancements happen at an ever increasing rate, curren t possibilities may be obsolete in a few years. In addition, there is still a vast populat ion in the country that are not

comfortable with the newer technologies. While in some areas of the country these may be beneficial, in other ar eas they may not provide enough public engagement (or more importantly not e nough local engagement). The Class VI program should involve public participati on but should not dictate the method in which that is performed.

Public participation should be consistent across progr ams. If EPA believes the public participation requirements should be expanded, it should be done in a holistic manner across programs.

Individual Response: EPA agrees that the existing UIC pub lic participation requirements as specified in 40 CFR 25 and 40 CFR 124 are ap propriate for GS projects. GS permitting authorities must follow the existing public part icipation requirements for UIC permits as specified in 40 CFR Part 124. Thes e regulations lay out the pro cedures for decision making and include requirements such as requiring the Direct or to notify the public re garding the availability of the draft permit and allow him or her to require a public hearing on the draft permit.

In addition, because of the unique nature of GS projects, and the anticipated level of public interest in GS projects, EPA encourages early pu blic involvement in GS projects. Providing the public with accurate, project specifi c information in the early stages of each GS project can help clarify project details and avoid public misper ceptions about the nature and safety of GS projects, and will allow a potential GS owner or operator and the permitting agency to address

44the public's concerns before the permitting process is complete.

EPA is not requiring the use of new information technologies. EPA encourages GS operators to use new information technologies whenever possible to keep the public informed of GS projects. The Agency believes that flexibility is importa nt and does not want to limit use of public participation and notification tec hnologies developed in the future.

Letter ID: 0200 Comment ID: 24618 Letter Lines: 891 to 902

Comment Code: 5560 2.10.3 Enhancing the public particip ation process (seeking comment)

Comment: Rule Provisions: 73 FR 43522- 23 EPA Rule Issue: 47. EPA also requests co mment on ways to enhance the public participation process, including e ngaging communities in the site characterization process as soon as ca ndidate locations are identified. EPA

Notice 43523.

Anadarko Petroleum Corporation (APC) Res ponse: While public participation is critical, bringing in public review before the project details are worked out can create unnecessary complications. APC does not believe that the public participation process should be extended to the site character ization stage of a GS project, particularly gi ven that many sites might be characterized in the process of winnowing down the por tfolio of poten tial sites.

Individual Response: The Agency believes that public particip ation is an important part of the UIC permitting process and wants to ensure wi de access to decision-making processes and information on projects that may affect the pub lic. GS permitting authorities must follow the existing public participat ion requirements for UIC permits as specified in 40 CFR Part 124. Generally, these regulations require the Director to notify the public regarding the availability of the draft permit and allow him or her to requ ire a public hearing on the draft permit. EPA encourages operators and permitting agencies to begin involving the public by providing information as early in the process as possible. Such information exchange can affect how the local community and surrounding communities percei ve potential environmental, economic, or

health effects.

Furthermore, the Agency recognizes that the ini tial phases of site evalua tion and site selection may begin in advance of permit application s ubmission. The public may become aware of these activities and begin to have questions or conc erns about the pending project. For this reason,

outreach and education—which are outside of, but complementary to, the public notification process—can help clarify project details and a void public misperceptions about the nature and safety of GS projects. This may also benefit the owner or operator by improving local acceptance

of the site.

45Letter ID: 0200 Comment ID: 24619 Letter Lines: 904 to 919

Comment Code: 5600 2.11 Comments related to UIC Program primacy for Class VI wells

Comment: Rule Provisions: 73 FR 43523 EPA Rule Issue: 48. To gain authority fo r Class VI wells, States, Territories, and Tribes will be required to show that their regulations are at least as stringent as, and may be more stringent than, the proposed minimum Federal requirements (e.g., inspection, operati on, monitoring, and recordkeeping requirements that well owners or operator s must meet). Such Primacy States,

Territories, and Tribes are authorized under Section 1422 of the SDWA. EPA

Notice 43523.

Anadarko Petroleum Corporation (APC) Res ponse: Primacy should be granted for

Class VI and Class II GS well classificati ons. In addition, the primacy for Class VI should be granted independently of other well classes allowi ng the states to determine the appropriate regulating agency (Class II-GS will obviously be part of the current Class II program).

EPA should ensure that adequate funding is provided for the delegated program.

Individual Response: EPA agrees that states should be al lowed to obtain primacy for Class VI wells independently of other well classes, and wi ll allow independent primacy for Class VI wells under §145.1(i) of the final GS rule. In the past , EPA has not accepted UIC primacy applications

for individual well classes unde r Section 1422 of SDWA. In other words, if a State wanted primacy for Class I wells, the State also had to accept responsibility fo r Class III, IV, and V wells. This policy has been in place since the initiation of the UIC Program in the early 1980s and was intended to encourage states to take full responsibility fo r UIC programs, avoid duplication of efforts, and provide for administrative efficiencies.

However, given the potential for CCS (encom passing capture, transportation, and geologic sequestration) to be an important part of a na tional priority to address climate change, EPA believes that providing states the flexibility to obtain primacy for Class VI wells independently of other well classes can help foster effective management of CCS. EPA believes that allowing independent Class VI primacy may encourage states to take res ponsibility for implementation of Class VI regulations and provide for a more co mprehensive approach to managing CCS projects by promoting the integration of GS activities under SDWA in to a broader framework for managing CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeline operations, pore space ownership, land use rights, and surface access) for which states can call upon other authorities that exist at the state leve l (but outside UIC author ity) to provide a more comprehensive CCS management approach.

EPA also believes that allowing states to apply only for Class VI primacy will shorten the primacy approval process for states. EPA's willingness to accept independent primacy applications for Class VI wells represents a shift in its longstandi ng policy of discouraging

46"partial primacy." It is very important to note that this shift in policy allowing for Class VI primacy does not apply to any other well Cl ass under Section 1422. EPA will continue to discourage applications for pa rtial primacy for all other well types under Section 1422.

EPA clarifies that states should be able to obtain primacy for Cla ss VI wells independent of other well classes provided they devel op regulations that are at leas t as stringent as the minimum Federal requirements (e.g., permitting, inspec tion, operation, monitoring, and recordkeeping requirements) provided in the final GS rule. EPA believes that existing programs can adapt their expertise to the new requirements for Class VI wells and will be able to develop a primacy application for Class VI wells under section 1422 of SDWA and en sure that their GS programs integrate into national climate change priori ties and protect USDWs from endangerment.

EPA acknowledges that there may be technical and administrative challenges including resource concerns, and will work closely w ith the states to assist them in resolving funding issues or acquiring the resources, personnel, and traini ng needed to address the unique technical challenges associated with GS.

EPA will also incorporate Class VI wells into the UIC Program's grant allocation process. The

States/Tribes/Territories must also demonstrate th at they have adequate resources to implement the program through matching resources against those allocated by the UIC Program's grant allocation formula. Currently, primacy programs ar e required to meet a minimum of 25 percent matching requirement.

Letter ID: 0200 Comment ID: 24620 Letter Lines: 921 to 933

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment)

Comment: Rule Provisions: 73 FR 43523, 73 FR 43529 EPA Rule Issue: 49. There may be benefits to parsing out primacy for Class VI

wells, however EPA has not made a d ecision on this. Allowing States, Territories, and Tribes to acquire primacy for only Class VI wells may encourage them to assume the responsibility of implementation and provide for a more comprehensive approach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). EPA is seeki ng comment on the merits and possible disadvantages of allowing primacy approva l for Class VI wells independent of

other well classes. EPA Notice 43523.

Anadarko Petroleum Corporation (APC) Res ponse: APC supports the implementation of partial primacy for Class VI separate ly from other classes of wells. The geologic variation across the count ry justifies partial primacy.

Individual Response: As described above, EPA agrees that states should be allowed to obtain primacy for Class VI wells independently of other well classes, and will allow independent primacy for Class VI wells under §1 45.1(i) of the final GS rule.

47Letter ID: 0200 Comment ID: 24621 Letter Lines: 935 to 943

Comment Code: 5700 2.12 Comments on the proposed durati on of Class VI permits (seeking comment)

Comment: Rule Provisions: 144.36(a) EPA Rule Issue: 50. EPA proposes that Class VI injection well permits would be issued for the operating life of the GS project including the post-injection site care period. EPA seeks comment on the merits of this approach. EPA Notice

43523.

Anadarko Petroleum Corporation (APC) Re sponse: A permit for the life of the project would ensure the c ontinuity of operations. S horter time periods would yield administrative bu rden without commensurate benefits.

Individual Response: EPA agrees with commenters that Cl ass VI permits should be issued for the operating life of the GS proj ect. The final rule maintains the lifetime permit provision and clarifies that the permit extends through the post-injection site care period (144.36(a)). However, it also adds a requirement that the Director revi ew each Class VI permit at least every five years

to determine whether it should be modified, revoked and reissued, terminated, or a minor modification made as provided in §§144.39, 144.40, or 144.41. The Director’s review will be informed by the owners’ or operato rs’ iterative reev aluation of the project. Specifically, the final rule includes a requirement that the AoR be reev aluated at least every five years, and also requires owners or operators to review and update the AoR and corrective action plan, the testing and monitoring plan, and the emergency and reme dial response plan th roughout the life of the project (146.84(e), 146.90(j), and 146.94(d)). Owners or operators must review each plan and identify necessary amendments or demonstrate to the Director that no amendment is needed. In no case can reviews occur less often than once every five years.

EPA adds that the required reviews of the Ao R and corrective action plan, the testing and monitoring plan, and the emergency and remedial re sponse plan throughout the life of the project are preferable to a periodic permit reapplication. The iterative process and subsequent plan

reevaluations ensure that time and resources are committed to the most critical aspects of the permit in preventing enda ngerment to USDWs.

Letter ID: 0200 Comment ID: 24622 Letter Lines: 945 to 961

Comment Code: 6220 3.2.2 Assumptions about the number of monitoring wells (seeking comment)

Comment: Rule Provisions: 73 FR 43527 EPA Rule Issue: 51. The Agency assumes th ree monitoring wells per injection well for the purpose of estimating national co sts; however, the Agency recognizes that operators and primacy agency Direct ors may choose more or fewer monitoring wells depending on project site character istics. Because the monitoring wells

48and associated costs represent a significan t component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EP A requests comment on whether three monitoring wells per injection well is an appropriate costing assumption. EPA

Notice 43527.

Anadarko Petroleum Corporation (APC) Res ponse: It is difficult to select a

realistic ratio since each site will have its own characteristics that would significantly affect the number of monitoring we lls necessary.

Please see the report submitted by API and prepared by ARI that discusses the cost modeling in greater detail.

Individual Response: EPA recognizes that the number of m onitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis descri bed the number of monitori ng wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefor e, the number of monitori ng wells was indirectly based on the size of the AoR. Because ER projec t sites have injection wells that are more

clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project si te compared to a saline formation project. EPA retained this assumption regarding the density of injection wells fo r the final rule analysis, but it changed its assumption on the number of monitori ng wells at each site. For the final rule, the Agency assumes one monitoring well above the inj ection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into th e injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is

uncertain, EPA tested the sensitiv ity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in a nnualized incremental rule costs approximately 16 percent less and 16 percent greate r than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis).

For additional information on EPA's final regula tory approach, includi ng testing and monitoring requirements, please see the final rule and preamble.

Letter ID: 0200 Comment ID: 24623 Letter Lines: 963 to 973

Comment Code: 7700 4.7 Executive Order 13045: Child ren's Health Protection

Comment: Rule Provisions: 73 FR 43531 EPA Rule Issue: 52. The public is invited to submit comments or identify peer49reviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration

of carbon dioxide. EPA Notice 43531.

Anadarko Petroleum Corporation (APC) Res ponse: APC is not aware of anything unique about CO2 injection or its potentia l impacts on drinking water quality

that would not be addressed within the existing drinking water program. The data EPA has on developing drinking water standards and MCLs can be used in this

situation.

Individual Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agen cy is tracking external research that focuses on potential exceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.

In the August 31, 2009 Notice of Data Availabi lity (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory (LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL

estimated the amount of trace elements from na tive mineral species that could potentially be mobilized by the intrusion of CO 2 and the potential ground water con centrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of wa ter affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to invest igate the fate of dissolved CO2 in underground geologic formations and to determine possible ri sks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated De sign, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protec t USDWs from endangerment through permitting, siting, construction, operation, injection, a nd post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements,

therefore, minimize health risk s to all populations, including ch ildren. The "Risk and Occurrence Document for the Geologic Sequestration Rule making," available in the rulemaking docket, presents a broad discussion of risks to human h ealth and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approac h, EPA plans to collect and review available

information such as the research described abov e and data every six year s on early GS projects,

50including impacts to USDWs and dr inking water quality that may aff ect the health of children, to determine whether the appropriate amount and t ypes of information and documentation are being

collected, and to determine if modifications to the requirements are a ppropriate or necessary.

Letter ID: 0200 Comment ID: 24624 Letter Lines: 984 to 991

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Rule Provision: 144.3

Anadarko Petroleum Corporation (APC) Comm ents: ENHANCED OIL RECOVERY (EOR) OR ENHANCED GAS RECOVERY (EGR) MEANS ANY ACTIVITY THAT USES FLUIDS,

GASES OR OTHER

MEANS TO IMPROVE OR INCREASE EXTRACTION OF HYDROCARBONS.

Rationale: The definition of EOR is nece ssary to support further comments and

discussion below.

Individual Response: EPA includes the following definition of Enhanced Oil or Gas Recovery in the preamble to the rule: typical ly, the process of injecting a fl uid (e.g., water, brine, or CO2) into an oil or gas bearing formation to recover re sidual oil or natural gas. The injected fluid thins (decreases the viscosity) and/or displaces small am ounts of extractable oil a nd gas, which is then available for recovery. This is also known as secondary or tertiary recovery.

Letter ID: 0200 Comment ID: 24625 Letter Lines: 993 to 1032

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

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

Comment: Rule Provision: 144.6 and 146.5

Anadarko Petroleum Corporation (APC) Commen ts: (b) Class II. Wells which inject

fluids:....

(4) FOR ENHANCED RECOVERY OF OIL OR NATURAL GAS WHERE GEOLOGIC SEQUESTRATION IS

OCCURRING DURING OR IN CONNECTION WITH ENHANCED RECOVERY OF OIL

OR NATURAL GAS PROVIDED (I) THERE IS REASONABLE EXPECTATION OF MORE THAN

INSIGNIFICANT FUTURE

51PRODUCTION VOLUMES OR RATES AS A RESULT OF CARBON DIOXIDE INJECTION AND (II)

OPERATING PRESSURES ARE NO HIGHE R THAN REASONABLY NECESSARY TO

PRODUCE SUCH

VOLUMES OR RATES; AND

(5) FOR GEOLOGIC SEQUESTRATION IN SU BSURFACE GEOLOGIC FORMATIONS IN

WHICH

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS

REASONABLY EXPECTED

TO OCCUR AND WHERE THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET.

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon

dioxide STREAMS. beneath the lowermost formation c ontaining a USDW WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS OCCURS DURING OR IN

CONNECTION WITH

EOR OR EGR ARE REGULATED UNDER CLASS II.

Rationale: The changes to (b) and (f) are to recognize that EOR can have storage component, which is consistent with EPA’s intent as expressed in the preamble and API’s October 27th meeting with EPA. It is widely recogni zed that CO2 based EOR can provide a significant early oppor tunity for carbon storage. As EPA correctly recognizes, CO2 EOR operations can have a significant storage component through capillary trapping or other mechanisms.

Additionally, there should not be a bl anket prohibition con cerning injection above USDW’s or at specific depths. Th is is especially true given the possibility of changes in th e definition of a USDW to in clude formations greater than 10,000 parts per million Total Dissolved Solids. This requirement is not necessary for the protection of USDWs and would remove a vast number of viable

formations from consideration. Industr y has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent exam ple is the Salt Cree k EOR project in Wyoming, which has a USDW below the inject ion zone. Moreover, under the proposed

rule, there are other measures that woul d provide real assura nce of formation integrity and require operators to dem onstrate that their project will not endanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: EPA did not make the suggested edits. EPA believes that the nature and risks of CO2 injection for the primary purpose of long-term storage pose different risks than injection for the primary purpose of ER, and has developed new Class VI regulations to address these unique risks. For example, the volume of CO2 an ticipated to be injected for long-term storage is significantly greater than for ER. Rese rvoir pressure conditions will also be different, with Class VI injection opera tions involving large volumes of CO2 and likely having higher pressures within their storage formations than Class II ER projects. EPA also recognizes that a by-product of ER activities is that a certain percentage of the CO2 is trapped in the receiving

52formation.

The final Class VI regulations re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility.

Regarding injection into basalts, coal seams, a nd salt domes, EPA clarifies that the GS rule does not preclude injection of CO2 into any non-USDW formation types. The purpose of the GS rule is to ensure protection of USDWs from endange rment, and the rule requires that owners or operators demonstrate that wells are sited in suitab le systems with geologic formations to receive and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, well construction and operation, monitori ng and testing, and post-injecti on site care and site closure requirements are designed to ensure that injected CO2 remains with in the target formation. If an owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt domes, or shales can be accomplished in a ma nner that protects USDW s and meets all of the requirements of the GS rule, the project may be permitted as a Class VI well.

EPA acknowledges that there may be unknown risks a ssociated with GS, pa rticularly regarding

GS into formations such as coal seams, basalts , and salt domes, which have been the subject of limited experimental projects in the past. EPA anti cipates that in the short-term, GS into these types of formations will continue to be experimental (i.e., to test GS tech nologies and collect data), and will likely be permitted as Class V experimental technology wells subject to UIC Program Guidance #83.

EPA is preparing an addendum to UICPG #83 that describes the use of th e Class V experimental technology well classification to clarify perm itting for Class V wells. This addendum will address shifting of Class V experi mental projects to full-scale GS projects and the future use of the Class V experimental technology well s ubclass for research a nd testing of new GS technologies.

EPA acknowledges that there are limited circum stances where injectio n above the lowermost USDW can be performed in a manner that pr otects USDWs. The final GS rule at §146.95 establishes a process by which owne rs or operators can seek a waiv er of the Class VI injection depth requirements. The waiver approach requir es the submission of extensive, site-specific information (in conjunction with the permit appli cation submittal) to dem onstrate that injection

of CO2 into a formation that is above or be tween USDWs can be done in a manner that is protective of USDWs. The requirements are desi gned to ensure the owner or operator, the Director, and the Regional Administrator consider, on a site-specific basis, the implications, benefits, and challenges associated with GS and ensuring water availability and USDW protection.

53Letter ID: 0200 Comment ID: 24626 Letter Lines: 1021 to 1032

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Additionally, there should not be a bl anket prohibition con cerning injection above USDW’s or at specific depths. Th is is especially true given the possibility of changes in th e definition of a USDW to in clude formations greater than 10,000 parts per million Total Dissolved Solids. This requirement is not necessary for the protection of USDWs and would remove a vast number of viable

formations from consideration. Industr y has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent exam ple is the Salt Cree k EOR project in Wyoming, which has a USDW below the inject ion zone. Moreover, under the proposed

rule, there are other measures that woul d provide real assura nce of formation integrity and require operators to dem onstrate that their project will not endanger USDWs, making the lowermos t USDW restriction unnecessary.

Individual Response: As described above, EPA agrees that it is not appropriate to set aminimum injection depth for GS projects and the Agency believes that a determination of sitesuitability for GS (i.e., that subsurface formati ons will receive and confine injected CO2) should be made on a site-specific basis. The GS rule , at §146.82, requires the owner or operator to provide extensive site- a nd project-specific information to the Director to demonstrate that the site meets the minimum site criteria at §146.83, that the CO2 will be contained within the injection formation, and that USDWs will be protected from endangerment.

Letter ID: 0200 Comment ID: 24627 Letter Lines: 1034 to 1044

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5700 2.12 Comments on the proposed durati on of Class VI permits (seeking comment)

Comment: Rule Provision: 144.36(a)

Anadarko Petroleum Corporation (APC) Comm ents: (a) Permits for Class I and V

wells shall be effective for a fixed term not to exceed 10 years. UIC Permits

for Class II AND III and VI wells shall be issued EFFECTIVE for a period up to the operating life of the facility . PERMITS FOR CLASS VI WELLS SHALL BE

EFFECTIVE FOR THE PERIOD THROUGH SITE CLOSURE.

Rationale: Permits are necessary for Cla ss VI wells through the end of the post closure monitoring phase, which is consistent with the term site closure in the amended requirement.

Individual Response: EPA clarifies that the final GS rule sp ecifies that Class VI permits will be

54issued for the operating life of the facility and the post-injection site car e period (144.36(a)). However, it also adds a requirement that the Dire ctor review each Class VI permit at least every five years to determine whether it should be mo dified, revoked and reissued, terminated, or a minor modification made as provided in §§144.39, 144.40, or 144.41. The Director’s review will be informed by the owners’ or op erators’ iterative reevaluation of the project. Sp ecifically, the final rule includes a requirement that the AoR be reevaluated at least ever y five years, and also requires owners or operators to review and update the AoR and corrective action plan, the testing and monitoring plan, and the emergency and reme dial response plan th roughout the life of the project (146.84(e), 146.90(j), and 146.94(d)). Owners or operators must review each plan and identify necessary amendments or demonstrate to the Director that no amendment is needed. In

no case can reviews occur less often than once ev ery five years. The iterative process and subsequent plan reevaluations ensure that time and resources are committed to the most critical aspects of the permit in preven ting endangerment to USDWs.

EPA believes that the iterative process of develo ping and executing the va rious plans required of GS well operators in the final rule (e.g., for AoR and corrective action, testing and monitoring, well plugging, and post-injection site care, and emergency and remedi al response) is tailored to the unique aspects of—and is more appropriate fo r–GS than establishing a finite permit duration (e.g., five years as suggested by some commenters ). This is preferable to a periodic permit reapplication.

Letter ID: 0200 Comment ID: 24628 Letter Lines: 1046 to 1080

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

Comment: Rule Provision: 144.80

Anadarko Petroleum Corporation (APC) Commen ts: (b) Class II. Wells which inject fluids:........(2) for enhanced recovery of oil or natural gas; (3) FOR EOR OR

EGR, AND WHERE GEOLOGIC SEQUESTRA TION OF A CARBON DIOXIDE STREAM

IS OCCURRING

DURING OR IN CONNECTION WI TH EOR OR EGR OPERATIO NS OR ACTIVITIES; and (4) For storage of hydrocarbons....

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon

dioxide STREAMS. WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2 STREAMS

OCCURS DURING

OR IN CONNECTION WITH EOR OR EGR ARE REGULA TED UNDER CLASS II.

Rationale: See 144.6

55Rule Provision: 146.5

Anadarko Petroleum Corporation (APC) Commen ts: b) Class II. Wells which inject fluids:..... (4) FOR ENHANCED RECOVE RY OF OIL OR NA TURAL GAS WHERE

GEOLOGIC SEQUESTRATION IS OCCURRING DURING OR IN CONNECTION WITH ENHANCED

RECOVERY OF OIL OR NATURAL GAS PROVIDED (I) THERE IS REASONABLE EXPECT ATION OF MORE

THAN

INSIGNIFICANT FUTURE PRODUCTION VO LUMES OR RATES AS A RESULT OF

CARBON DIOXIDE INJECTION AND (II) OPERATING PRESSURE S ARE NO HIGHER THAN REASONABLY

NECESSARY

TO PRODUCE SUCH VOLUMES OR RATES; AND

(5) FOR GEOLOGIC SEQUESTRATION IN SU BSURFACE GEOLOGIC FORMATIONS IN

WHICH

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS

REASONABLY EXPECTED

TO OCCUR AND WHERE THE CRITERIA OF PARAGRAPH (B)(4) ARE NOT MET.

(f) Class VI. Wells used EXCLUSIVELY for geologic sequestration of carbon

dioxide STREAMS. Beneath the lowerm ost formation containing an underground source of drinking water (USDW). WELLS WHERE GEOLOGIC SEQUESTRATION OF CO2

STREAMS OCCURS DURING OR IN CO NNECTION WITH EOR OR EGR ARE

REGULATED UNDER CLASS

II.

Rationale: See 144.6

Individual Response: As described above in the response to comment 24625 regarding the suggested edit at 144.6, EPA did not make the su ggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

As described above, the final GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the Class VI in jection depth requirement s for injection into nonUSDW formations above and/or between USDWs.

56Letter ID: 0200 Comment ID: 24629 Letter Lines: 1082 to 1163

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Rule Provision: 146.23(a)

Anadarko Petroleum Corporation (APC) Co mments: (3) WHEN, ON AN ANNUAL BASIS,

THE

FIELD-WIDE AVERAGE CO2 INJECTION TO WITHDRAWAL RATIO IS GREATER

THAN 5.0 IN AN

INJECTION ZONE AND THE AVERAGE RESE RVOIR PRESSURE IN THE INJECTION

ZONE BECOMES GREATER THAN (A) THE AVERAGE ORIGI NAL RESERVOIR PRESSURE IN THE

INJECTION ZONE

AT THE TIME OF DISCOVERY OF THE RE SERVOIR, OR (B) THE AVERAGE DESIGN

OPERATING

PRESSURE DURING CO2 EOR OR EGR, WH ICHEVER IS GREATER, THE DIRECTOR MAY REQUIRE

THE OPERATOR OF A CO2 EOR OR EGR PROJECT PERMITTED UNDER CLASS II TO

PROVIDE

ADDITIONAL INFORMATION AND DATA TO THE DIRECTOR EXPLAINING THE

NECESSITY TO

INCREASE OR MAINTAIN SUCH PRESSURE.

IF THE DIRECTOR DETERMINES, BASED ON SITE-SPECIFIC CHARACTERISTICS

THAT THE

INFORMATION PROVIDED FAILS TO SU PPORT THE NEED TO INCREASE OR

MAINTAIN THE

AVERAGE RESERVOIR PRESSURE IN THE INJECTION ZONE ABOVE THE AVERAGE

ORIGINAL

RESERVOIR PRESSURE, OR THE AVERA GE DESIGN OPERATING PRESSURE

DURING CO2 EOR OR

EGR, THE DIRECTOR MAY RE QUIRE THE OPERATOR TO:

(I) REDUCE OR MAINTAIN THE CO2 EO R OR EGR PROJECT’S FIELD-WIDE

AVERAGE INJECTION

TO WITHDRAWAL RATIO TO A VALUE SUCH THAT THE AVERAGE RESERVOIR

PRESSURE OR

AVERAGE DESIGN OPERATING PRESSURE DURING CO2 EOR OR EGR WITHIN THE

INJECTION

ZONE ESSENTIALLY REMAINS CONSTANT; OR

(II) APPLY TO RECLASSIFY THE CO2 EOR OR EGR INJE CTION WELLS AND

INJECTION ZONE

57COVERED UNDER THE CLASS II PERMIT AS A GEOLOGIC SEQUESTRATION

PROJECT REGULATED

UNDER THE APPLICABLE WELL CLASS.

IF THE OPERATOR FAILS TO COMPLY WI TH ANY OF THE ABOVE REQUIREMENTS,

THE DIRECTOR

MAY REVOKE OR MODIFY THE APPLICABLE CLASS II INJECTION PERMIT.

Rationale: A carbon dioxide stream or carbon dioxide may be injected into a

reservoir for EOR or EGR. When CO2 comes in contact with oil it dissolves into

the oil, the oil swells, becomes less vi scous and the surface tension between the oil and the formation is reduced to such a point that the oil becomes mobile. The injection of CO 2 also raises the pressure in the formation to a desired or designed operating pressure. If achievable, the desired operating pressure will be above the miscibility pressure of the oil and CO2. Achieving sustained pressures at or above the mi scibility pressure will generally allow the most efficient and effective recovery of the residual oil remaining in the formation. Miscibility pressures are de pendent on the oil properties, carbon dioxide stream properties and the reservoir temperature. Thus, miscibility pressure may be less than the average original discovery pressure of the reservoir, or may be equal to or greate r than the average original discovery pressure of the reservoir. The propertie s of some oils (generally heavier crudes) are such that the miscibility pre ssure of the oil and CO2 is far in excess of the average original discovery pr essure of the reservoir and can even be greater than the fracture pressure of the reservoir and/or the confining

zone.

Once the reservoir pressure reaches the designed or desired average reservoir pressure for the CO2 EOR project, the inje ctions of CO2 (or CO2 and water in water alternating gas CO2 EOR projects) are managed such that the volumes of CO2 (or CO2 and water) being injected into th e reservoir are genera lly equal to, or slightly greater than, the vol umes of fluids being wit hdrawn from the reservoir such that the average designed or desire d operating reservoir pressure remains relatively constant. The desired or designe d operating reservoir pressure may be altered from time to time, but the pro cess of raising the average reservoir pressure, and then holding the average re servoir pressure re latively constant,

is the same.

Therefore, except during periods of re servoir re-pressurization (i.e. the beginning of a CO2 EOR project, or for a period of time when the designed or desired average reservoir operating pressure is being raised), the ratio of the injected volumes (CO2 + water) to the wit hdrawal volumes (CO2, oil, associated natural gas and water) will most likely be less than 1.5. All volumes should be determined at average reservoir conditi ons, or, at a minimum, at the same conditions (i.e. same average pr essures and temperatures).

58In contrast, a GS project whether occu rring after a CO2 EOR project or as a standalone GS project is a project in which the prim ary, but not necessarily only, purpose is to inject and store a CO2 stream. Therefore, the ratio of injected volumes (CO2) to the withdrawal volumes (CO2 + other formation fluids) should be greatly in excess of 1.5 and more than likely an order of magnitude

greater.

In order to allow for reasonable fluctua tions and variations within CO2-EOR projects an injection-withdr awal ratio of 5.0 (3 to 4 times multiple of typical injection-withdrawal ratios) is recommende d to distinguish betw een CO2- EOR and Geologic Storage projects. The injection- withdrawal ratio should be measured over the applicable reporti ng period required under the applicable permit and will be evaluated on a field-wide basis compared to a well-by-well basis (which will allow for phased development).

Individual Response: As described above in the response to comment 24625 regarding the suggested edit at 144.6, EPA did not make the su ggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements because Class II requireme nts do not address the unique risks posed by GS to ensure protection of US DWs from endangerment.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

Letter ID: 0200 Comment ID: 24630 Letter Lines: 1165 to 1181

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Rule Provision: 146.25 GEOLOGIC SE QUESTRATION IN OIL OR GAS

RESERVOIRS WITHOUT

ENHANCED RECOVERY OF OIL OR NATURAL GAS

Anadarko Petroleum Corporation (APC) Comments: WELLS USED FOR GEOLOGIC SEQUESTRATION AND MEETING THE CLA SSIFICATION CRITERI A OF SECTION 146.5(B)(5)

SHALL BE SUBJECT TO THE FOLLOWING REQUIREMENTS:

(A) EXISTING WELLS THAT MEET OR EXCEED THE CONSTRUCTION REQUIREMENTS OF § 146.22

SHALL BE SUBJECT TO PART 146, SU BPART H EXCEPT SECTIONS 146.86 AND

146.87. (B) NEW WELLS MUST MET THE CONS TRUCTION REQUIREMENTS OF SECTION

59146.22 AND ARE

SUBJECT TO PART 146, SUBPART H EXCEPT SECTIONS 146.86 AND 146.87

Rationale: Details of what would be re quired of "Class IIB" wells are to be worked out during future discussions of the Multi-Stakeholder Discussion Group (MSDG). However, APC offers this language which is consistent with changes APC had suggested before discussions with th e MSDG began (see Section 146.81(c)).

Individual Response: As described above in the response to comment 24625 regarding the suggested edit at 144.6, EPA did not make the su ggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements because Class II requireme nts do not address the unique risks posed by GS while ensuring protection of USDWs from endangerment.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

Letter ID: 0200 Comment ID: 24631 Letter Lines: 1182 to 1197

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Rule Provision: 146.81(b)

Anadarko Petroleum Corporation (APC) Commen ts: (b) This subpart applies to wells used to inject carbon dioxide EXCLUS IVELY for the purpo se of geologic sequestration, i.e., the long-term c ontainment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. IT IS

RECOGNIZED THAT SOME ACTIVITIES CONDUCTED UNDER CLASS II, INCLUDING

CO2 BASED EOR OR EGR MAY SEQUESTER A PORTIO N OF THE CARBON DIOXIDE STREAM

USED FOR EOR OR

EGR. THIS SUBPART DOES NOT APPLY TO INJECTION OF A CARBON DIOXIDE

STREAM FOR

PURPOSES OF EOR OR EGR EVEN TH OUGH GEOLOGIC SEQUESTRATION OF

CARBON DIOXIDE MAY

OCCUR DURING OR IN CONNECTION WITH EOR OR EGR OPERATIONS AND/OR

ACTIVITIES.

Rationale: See 144.6

Deleted "gaseous, liquid or supercri tical" because it was added to the

60definition of CO2 stream.

Individual Response: As described above in the response to comment 24625 regarding the suggested edit at 144.6, EPA did not make the su ggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements because Class II requireme nts do not address the unique risks posed by GS while ensuring protection of USDWs from endangerment.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

Letter ID: 0200 Comment ID: 24632 Letter Lines: 1199 to 1230

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: Rule Provision: 146.81(c)

Anadarko Petroleum Corporation (APC) Comm ents: (c) ) This subpart applies to owners and operators of permit or rule -authorized Class I industrial, Class

II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestrati on permit for their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s discretion, from the casing and cementing requirements at §§ 146.86(b) and 146.87( a)(1) through (3).

Rationale: The reference to Class II we lls in section 146.81(c) is no longer

needed due to addition of 146.25.

However, if EPA were not to adopt section 146.25, APC would suggest the following revisions:

(c) This subpart applies to owners and operators of permit or rule-authorized

Class I industrial, Class II WHO HAVE CE ASED AND WILL NO LONGER CONTINUE EOR

OR EGR OPERATIONS OR ACTIVITIES, or Class V experimental carbon dioxide injection projects who seek to apply for a Cla ss VI geologic sequestration permit for

their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s disc retion, from the casing and cementing requirements at §§ 146.86(b) and 146.87(a)(1) through (3). CLASS VI REQUIREMENTS. CLASS II WELLS PERMITTED FOR CO2 INJECTION

AND THAT HAVE DEMONSTRATED MIT ARE EXEMPT FROM THE REQUIREMENTS AT

61§§146.86 AND

146.87.

The language allows for the transition of Class II wells to Class VI operations. These wells should be allowed to inject CO2 for storage based on their history of sound performance under the Class II prog ram as demonstrated by MIT results. The language also allows the Director to exercise discretion to exempt other Class VI requirements.

Individual Response: As described above in the response to comment 24625 regarding the suggested edit at 144.6, EPA did not make the su ggested change. The Agency disagrees that wells injecting CO2 for the primary purpose of long-term storage should be regulated under Class II requirements because Class II requireme nts do not address the unique risks posed by GS while ensuring protection of USDWs from endangerment.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS Rule. S ee the final rule and preamble for further discussion on EPA's final appr oach to transitioning from Class II to Class

VI.

EPA is developing guidance on transitioning perm its from Class II to Class VI. The guidance will assist Directors in determining whether an injection project should be transitioned from Class II where the primary purpose is oil and gas production to Class VI where the primary purpose is long-term storage of large volumes of CO2. The guidance describes recommended methods the Director may use to evaluate change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s in the preamble to the final GS rule.

Letter ID: 0200 Comment ID: 24633 Letter Lines: 1232 to 1245

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 CFR 146.84)

Comment: Rule Provision: 146.81(d) [Definition - Area of review]

Anadarko Petroleum Corporation (APC) Comm ents: Area of review means the region surrounding the geologic sequestration pr oject that may be impacted by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of a ll phases of the injected

carbon dioxide stream. SUBSURFACE THREE-DIMENSIONAL EXTENT OF THE CARBON

DIOXIDE PLUME, ASSOCIATED PRESSURE FRONT, AS WELL AS THE OVERLYING

FORMATIONS

AND SURFACE AREA ABOVE THAT DELINEATED REGION.

62Rationale: Defining the AOR based on the extent of the CO2 plume and its associated pressure front is a more dir ect approach, rather than the approach offered by the EPA. The EPA definition sugg ests that the computational approach defines the AOR rather than the potential risks of the injection activity.

Individual Response: EPA disagrees that the AoR definition needs to specifically include the overlying formations and surface area above the delineated region. The intent of the AoR, a long-standing concept within the UIC Program, is to delineate the surf ace area and all subsurface formations below it that may potentially be impacted by injecti on activity. Acceptable delineation models will provide predictions of CO 2 fate and transport, as well as changes in formation pressure, in three dime nsions as a function of time that can be used to delineate the subsurface storage site and the AoR. Although EP A disagrees with the commenter's suggested change, the Agency has carefully considered all comments on the AoR definition at 146.84(a) and modified it to read as follows: The regi on surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The ar ea of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected CO2 stream and is base d on available site characterization, monitoring, and operational data. EPA believes that this defi nition is sufficiently broad and describes both the intent of the computational modeling and the relationship of th e AoR to areas that are subject

to the risks associat ed with injection.

Letter ID: 0200 Comment ID: 24634 Letter Lines: 1247 to 1261

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: Rule Provision: 146.81(d) [Definitio n - Carbon dioxide stream]

Anadarko Petroleum Corporation (APC) Comments: Carbon dioxide stream means

carbon dioxide, WHICH WILL BE INJECTED IN ANY PHYSICAL STATE OR DISSOLVED,

AND

ANY ASSOCIATED substances derived from the that has been captured from an

emission source (e.g., a power plant), plus in cidental associated substances

derived from the source materials and the capture process, and any , ITS PROCESSING, OR substances added to enable or improve the injection process. This subpart does not apply to a ny carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.

Rationale: Source of CO2 is not an issu e in the context of defining the CO2 stream. The rule applies to the inject ion of CO2 and should not address the origins of the materials since that is beyond the scope of this regulation. Original text would have precluded in jection of CO2 from some sources.

Individual Response: The final GS rule retains the defini tion of a CO2 stream as proposed. The GS regulation applies to injecti on of CO2 for the purpose of GS, regardless of the source of the

63CO2. It is beyond the scope of the GS rule and the UIC Program’s authority to require or set standards for upstream generators of CO2 or purification facilities . For purposes of GS, the UIC program’s authority under the SDWA is limited to ensuring that GS projects are sited, constructed, operated, and closed in a manner that protects USDWs.

Although the GS regulation does not apply to th e source of CO2 streams, the GS rule, at §146.82(a)(7)(iv), requires the owner or operator to submit data about the site, including an analysis of the chemical and physical char acteristics of the CO2 stream because the

concentrations of minor and tra ce elements in CO2 streams for GS projects are likely to vary by facility, coal composition, plant operating cond itions, and pollution removal technologies.

With respect to RCRA, EPA has decided to initi ate a separate proposed rulemaking specifically

to examine the issue of RCRA a pplicability to CO2 streams be ing geologically sequestered, including the possible option of a conditional exemption from the RCRA requirements for CO2

GS in Class VI wells. EPA will consider these comments as part of its development of that proposal. The Agency will consider issues particular to RCRA in the context of that separate rulemaking, and recommends that the commenter r ead that proposed rule when it is published. The Agency notes that commenters who wish to submit comments on the RCRA proposal will need to do so during the comment period for that rule. Finally, EPA also not es that the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any changes to the RCRA regulations.

Letter ID: 0200 Comment ID: 24635 Letter Lines: 1263 to 1282

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost

USDW

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

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration]

Anadarko Petroleum Corporation (APC) Comm ents: Geologic seque stration project means an injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation containing a USDW INTO AN INJECTION ZONE

EXCLUSIVELY FOR THE PURPOSE OF GEOL OGIC SEQUESTRATION. It includes the

subsurface three-dimensional extent of the carbon dioxide plume, associated pressure front, and displaced brine, as well as the surface area above that delineated region.

Rationale: There should not be a blanket prohibition concerning injection above USDW’s or at specific depths. This requirement is not necessary for the protection of USDWs and would remove a vast number of viable formations from consideration. Industry has shown that it can operate CO2 injection wells in an EOR context without endangering USDWs that are located below the injection zone. An excellent example is the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone. Moreover, unde r the proposed rule, there are other

64measures that would provide real assura nce of formation integrity and require operators to demonstrate that their proj ect will not endanger USDWs, making the lowermost USDW restriction unnecessary.

Individual Response: EPA has revised the definition of a geologic sequestra tion project to account for the new requirements to include “w ells used for geologic sequestration of carbon dioxide that have been granted a waiver of the injection depth requirements pursuant to requirements at §146.95.”

Letter ID: 0200 Comment ID: 24636 Letter Lines: 1284 to 1294

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment: Rule Provision: 146.81(d) [Definition - Injection zone]

Anadarko Petroleum Corporation (APC) Commen ts: Injection zone means a geologic formation, group of formations, or part of a formation that is of sufficient a real extent, thickness, porosity, a nd permeability to receive carbon dioxide RECEIVING FLUIDS through a well or wells associated with a geologic sequestration project

Rationale: Existing definition in the CFR is sufficient and does not need to be changed. Furthermore, adding the sufficien cy requirement is not a definitional

issue and should be dealt with elsewhere.

Individual Response: EPA disagrees with the suggested edit . The final definition of injection zone at §146.81(d) is unchanged and reads as follows: “[A] geologic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic sequestration project.”

Based on its evaluation of all public comments and input on the proposed rule and the NODA and Request for Comment, EPA has made many revisions to the Cla ss VI GS rule. Please see the final rule and preamble for additional information.

Letter ID: 0200 Comment ID: 24637 Letter Lines: 1296 to 1304

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: Rule Provision: 146.81(d) [Definition - Post-injection site care]

Anadarko Petroleum Corporation (APC) Comm ents: Post-injection site care means appropriate monitoring and other actions (including corrective action)

needed following cessation of injection to assure that USDWs are not

65endangered , as required under §146.93.

Rationale: Deleted "appropriate" because the definition of it is not clear. Deleted USDW phrase because it is incorporated in 146 requirements.

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and preamble for further discussi on on EPA's final approach. EPA adds that all post-injection site care must be pe rformed pursuant to the post-injec tion site care and site closure plan, which must be approved by the Director and demonstrated to include monitoring activities that protect USDWs from endangerment.

Letter ID: 0200 Comment ID: 24638 Letter Lines: 1306 to 1315

Comment Code: 1220 1.1.1.1 Terminology and definitions

Comment: Rule Provision: 146.81(d) [Definition - Pressure front]

Anadarko Petroleum Corporation (APC) Commen ts: Pressure front means the zone of elevated pressure that is created by the injection of the carbon dioxide STREAM into the subsurface, For the purposes of this subpart, the pressure front of a carbon dioxide plume refers to a zon e where there is a pressure differential sufficient to cause movement of injected fluids THE CARBON DIOXIDE STREAM or

formation fluids FROM THE INJECTION ZONE into a USDW.

Rationale: Clarification.

Individual Response: EPA disagrees with the suggested edit . The final definition of pressure front at §146.81(d) is unchanged and reads as follows : “[T]he zone of elevat ed pressure that is created by the injection of carbon dioxide into the subsurface. Fo r the purposes of this subpart, the pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential sufficient to cause the movement of injected fluids or formation fluids into a USDW.”

Based on its evaluation of all public comments and input on the proposed rule and the NODA and Request for Comment, EPA has made many revisions to the Cla ss VI GS rule. Please see the final rule and preamble for additional information.

Letter ID: 0200 Comment ID: 24639 Letter Lines: 1317 to 1324

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: Rule Provision: 146.81(d) [Definition - Site closure]

Anadarko Petroleum Corporation (APC) Comments: Site closure MEANS the

66point/time, as determined by the Dir ector following the requirements under §146.93, at which the owner or operator of a GS site PROJECT is released from post-injection site care responsibilities.

Rationale: "GS project" is consistent with other definitions.

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

Letter ID: 0200 Comment ID: 24640 Letter Lines: 1326 to 1335

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: Rule Provision: 146.81(d) [Definition - Transmissive fault or fracture]

Anadarko Petroleum Corporation (APC) Commen ts: Transmissive fault or fracture

means a fault or fracture that has suffic ient permeability and vertical extent

to allow fluids to move between formations BEYOND THE CONFINING ZONE.

Rationale: The term "between formations " is inaccurate since there can be multiple formations within a injection zone. The critical factor for transmissivity is movement of injected or displaced fluids beyond the confining

zone.

Individual Response: EPA has retained the proposed definition, which is the same as the existing definition at §148.2, to a ddress transmissive faults and fractures that extend beyond the confining zone.

Letter ID: 0200 Comment ID: 24641 Letter Lines: 1337 to 1356

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(b)

Anadarko Petroleum Corporation (APC) Co mments: (b) A surface map showing the PROPOSED LOCATIONS FOR the injection we ll(s) for which a permit is sought and the applicable area of review . Within the area of review , the map must show the

67number, or name and location of all KNO WN injection wells, producing wells, abandoned wells, plugged wells or dry holes , deep STRATAGRAPHI C boreholes, State or EPA approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structures inte nded for human occupancy and roads. The map should also show faults, if kno wn or suspected. Only information of public record is required to be included on this map;

Rationale: Faults are not shown on maps unless there is a surface expression of

the fault. Also, faults are detailed in (d) below and this language appears

redundant.

Known needs to be added to remove any implication that an applicant has to

conduct stuides to determine wells that are not currently documented in some

fashion.

Individual Response: Regarding the comment that EPA delete mention of faults on surface maps, EPA believes that if faults have surface ex pressions, they should be presented on maps submitted; this information would complement the required cross section data. EPA is developing guidance on site charac terization for GS projects to a ssist owners or operators and Directors in evaluating permit requirement s 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_se questration.cfm.

EPA disagrees that the information that is s ubmitted to support a Class VI permit application should be limited to known/available data. The Agen cy believes that the site characterization requirements at §146.82, including geomechanical information and geologic and topographic maps and cross sections, are essential to proper siting of a GS well and are the foundation for a detailed understanding of the lo cal and regional geology, and that the owner or operator should collect this information, regardless of whether it is known in advance of the siting process. Collecting and evaluating th is data supports important evaluations regarding the suitability of the site to receive and contain injected CO2. Please see the final rule and th e discussion of geologic site characterization in the pr eamble for additional information.

EPA acknowledges that some smaller fractures may not be detectable during the site characterization process, and cl arifies that §146.82(a)(3 )(ii) requires the ow ner or operator to submit data on known or suspected faults and fractures (i.e., not al l fractures). Other requirements for GS injection wells and sites can mitigate the potential impacts of unidentified fractures. These include limitations on injec tion pressures to avoid propagation of existing fractures in the confining zone (§146.88(a)), co llection and assessments of CO2 monitoring data at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through highpermeability regions (i.e., faults and/or fractures) not detected in the initia l site characterization.

EPA also believes that a determination about whether or what information may be necessary (for

68a specific GS project) is outside of the public record will be site-specific and based on knowledge of the site, data availability, and data quality. For inst ance, in meeting the requirement to tabulate information on wells in the AoR, the Director has the discretion to require the owner or operator to supplement a data records search if ther e is reason to believe that the incompleteness of available informa tion could compromise USDW protection from endangerment.

Letter ID: 0200 Comment ID: 24642 Letter Lines: 1358 to 1367

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(c)

Anadarko Petroleum Corporation (APC) Commen ts: (c) A MAP DELINEATING the area of

review based on UPON modeling, using ALL AVAI LABLE data INCLUDING DATA obtained during logging and testing of th e well and the formation as required by paragraphs (l), (r), and (s) of this section ANY WELLS IN THE AREA OF

REVIEW

Rationale: This appears to be related to a condition where a well is already drilled. This does not align with reques ting information to receive a permit.

Individual Response: EPA recognizes that this informati on may not be available until after a well has been drilled. EPA revised §146.82 so th at 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 informa tion to be submitted before operation of the well is authorized (at §146.82(c)).

Final information on injection zone pressures would be required. EPA recognizes that this information may not be available until after a we ll has been drilled. EPA revised §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 information to be submitted before operation of the well is auth orized (at §146.82(c)). Final information on injection zone pressures woul d be required following drilling of the well, at §146.82(c)(4).

In the final rule, the requirement for the fi nal AoR based on modeling, including data obtained during logging and testing, can be found at §146.82(c)(1). Please see the final rule and the discussion of geologic site characterization in the preamble for additional information.

Letter ID: 0200 Comment ID: 24643 Letter Lines: 1369 to 1390

69Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(d)

Anadarko Petroleum Corporation (APC) Co mments: (d) KNOWN information on the geologic structure and hydrogeologic RESERVOIR properties of the proposed storage site and overlying formations, including:

(1) ISOPACH maps and OF THE PROPOSED INJECTI ON AND CONFINING ZONE(S), A

STRUCTURAL CONTOUR MAP HUNG ON TH E TOP OF THE PROPOSED INJECTION

ZONE, AND AT

LEAST TWO GEOLOGIC cross sections of th e area of review SHOWING THE GEOLOGIC

FORMATIONS FROM THE SURFACE TO TOTAL DEPTH.

(2) Location, orientation, and propertie s of known or suspec ted SUBSURFACE

faults a nd fractures that may transect the confin ing zone(s) in the area of review and a determination that they would not interfere with containment;

Rationale: If the information is not known, it cannot be reported.

"Reservoir" and changes to (1) a nd (2) are technical corrections.

Fractures generally can’t be identified until a well is drilled and evaluated. Even then, only fractures in the immedi ate vicinity of the wellbore can be

identified.

Individual Response: EPA believes that all of the site characterization requirements at 146.82, including information on faults and fractures, are essential to proper siting of a GS well and are

the foundation for a detailed unders tanding of the local and regional geology, and that the owner or operator should collect this in formation, regardless of whether it is known in advance of the siting process. Collecting and evaluating this da ta supports important ev aluations regarding the suitability of the site to recei ve and contain injected CO2.

EPA recognizes that this information may not be available until after a well has been drilled. EPA revised §146.82 so that the fina l regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and information to be submitted before operation of the well is authorized (at §146.82(c)). Final information on injection zone pr essures would be required following drilling of the well, at §146.82(c)(4).

EPA acknowledges that some smaller fractures may not be detectable during the site characterization process, and cl arifies that §146.82(a)(3 )(ii) requires the ow ner or operator to

70submit data on known or suspected faults and fractures (i.e., not al l fractures). Other requirements for GS injection wells and sites can mitigate the potential impacts of unidentified fractures. These include limitations on injec tion pressures to avoid propagation of existing fractures in the confining zone (§146.88(a)), co llection and assessments of CO2 monitoring data at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through highpermeability regions (i.e., faults and/or fractures) not detected in the initia l site characterization.

Letter ID: 0200 Comment ID: 24644 Letter Lines: 1392 to 1401

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision:146.82(d)(3)

Anadarko Petroleum Corporation (APC) Co mments: (3) Information on seismic history THAT HAVE AFFECTED THE PROP OSED AREA OF REVIEW INCLUDING

KNOWLEDGE OF

PREVIOUS SEISMIC EVENTS AND HISTORY OF THESE EVENTS, incl uding the presence

and depth of seismic sources and a determin ation that the seismicity would not

interfere with containment;

Rationale: Information on seismic history should have some degree of relevance to the project.

Individual Response: EPA believes that consideration of local and regional seismicity is important and this type of review is relevant to every project. The site characterization provisions in the GS rule, including a review of the loca l and regional geology, and detailed review of any known or potential seismically activ e terrain in the vicinity of a proposed GS site are necessary to minimize the potential for induced seismic even ts or the reactivation of faults, which are a known potential risk associated with injection and are addresse d in all aspects of the UIC regulations.

Letter ID: 0200 Comment ID: 24645 Letter Lines: 1403 to 1419

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

71Comment: Rule Provision: 146.82(d)(4) & (5)

Anadarko Petroleum Corporation (APC) Co mments: (4) Data on the depth, areal extent, thickness, mineralogy, porosity, permeability and capillary RESERVOIR pressure of the injection and confining zone(s) WITH IN THE AREA OF REVIEW; including geologic/f acies changes based on field data which may include geologic cores, outcrop data, seis mic surveys, well logs, and names and lithologic descriptions;

(5) KNOWN geomechanical information on fractures, stre ss, ductility, rock strength, and in situ fluid pressures within the confining zone (s) WITHIN THE

AREA OF REVIEW; and

Rationale: Deleted capillary pressure becau se it is too hard to measure outside of the lab. Using sidewall cores, it ma y be difficult to determine capillary pressure. Additionally, full cores are not available until after the well being permitted is drilled.

Individual Response: EPA acknowledges the comment but did not make the suggested edits. The Agency believes that the site charact erization requirements at §146.82, including geomechanical information and geologic and topogr aphic maps and cross sections, are essential to proper siting of a GS well and are the foundation for a detailed understa nding of the local and regional geology, and that the owner or operator should collect this information, regardless of whether it is known in advance of the siting proc ess. Collecting and evaluating this data supports important evaluations regarding the suitability of the site to receive and contain injected CO2.

EPA acknowledges that laboratory methods are st andard for determining capillary pressures regardless of formation permeability and that in situ measurements would require drilling of a well. However, EPA also 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 (for laboratory determination of capillary pressure ) and take other necessary measurements.

EPA recognizes that this information may not be available until after a well has been drilled. EPA revised §146.82 so that the fina l regulation specifies separate requirements for information to be submitted with the permit application and before well construction is approved (at §146.82(a)) and information to be submitted before operation of the well is authorized (at §146.82(c)). Final information on injection zone pr essures would be required following drilling of the well, at §146.82(c)(4).

EPA believes that information on capillary entry pr essure is necessary and appropriate. Capillary entry pressure measurements on core sample s can quantify the amount of buoyant force the confining zone can maintain before failure (World Resources Institute, 2008).

Letter ID: 0200 Comment ID: 24646 Letter Lines: 1421 to 1429

72Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(e)

Anadarko Petroleum Corporation (APC) Co mments: (e) A tabulation of all wells

ARTIFICIAL PENETRATIONS within the area of review which penetrate the injection or confining zone(s). Such data must in clude a description of each well’s type,

construction, date drilled, location, depth, record of plugging and/ or completion, and any additional inform ation the Director may require;

Rationale: Artificial penetrations is a more inclusive term.

Individual Response: EPA agrees that all artificial penetrat ions must be identified and evaluated during site characterization. However the final rule retains the proposed text to be consistent with similar requirements for other well classes a nd to support the correctiv e action requirements. 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 can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24647 Letter Lines: 1431 to 1443

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(f)

Anadarko Petroleum Corporation (APC) Co mments: (f) Maps and stratigraphic

cross sections indi cating the general vertical and lateral limits of all USDWs, water wells and springs within the area of review, their pos itions relative to the injection zone(s) and the direct ion of water movement, where known; POTENTIOMETRIC (WATER LEVEL) SURF ACE MAP(S) OF EXISTING AQUIFERS

BEING UTILIZED

AS PRIVATE OR PUBLIC WATER SU PPLIES AND THE DIRECTION OF

GROUNDWATER FLOW IN THESE AQUIFERS WITHIN THE AREA OF REVIEW. AT LEAST TWO GEOLOGIC

CROSS SECTIONS

SHOWING THE THICKNESS AND GENERAL VE RTICAL AND LATERAL LIMITS OF

ALL USDWS

WITHIN THE AREA OF REVIEW.

73No rationale provided

Individual Response: The Agency acknowledges the suggest ed edits but has retained the language as proposed. EPA believes that a thorough understanding of the hydrogeologic

conditions of all USDWs in the AoR is necessa ry to protect USDWs from endangerment, and disagrees with the suggested edits because the GS rule, as written, a ffords flexibility to owners or operators and Directors to tailor the site characte rization process to the un ique geologic features of the site. The final requirements will allow for submittal of information similar to or the same as that which was suggested by the commenter. EPA encourages owners or operators and Directors to consult during site characterization to discuss information needs and ensure that all appropriate data necessary to assess the suitabil ity of the site are collected. The Director may request additional hydrogeologic data or other data on USDWs as well, as provided in §146.82(a)(21).

Letter ID: 0200 Comment ID: 24648 Letter Lines: 1445 to 1454

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(g)

Anadarko Petroleum Corporation (APC) Co mments: (g) Baseline geochemical data

on subsurface formations, includi ng all USDWs in the area of review

COMPILATION OF AVAILABLE GEOC HEMICAL DATA ON THE PROPOSED

INJECTION ZONE AND

NEAREST POROUS AND PERMEABLE FORM ATION ABOVE THE CONFINING ZONE.

Rationale: Limits the data submitted to available information and to the injection zone and the zone immediately above the confining zone which is the zones most likely to be monito red for potential CO2 leakage.

Individual Response: The Agency acknowledges the suggest ed edits but has retained the language as proposed. EPA believes that a thorough understanding of the hydrogeologic conditions of all USDWs in the AoR is necessary, and disagrees with the suggested edits because the GS rule, as written, affords flexibility to owne rs or operators and Dir ectors to tailor the site characterization process to the uni que features of the site. EPA en courages owners or operators and Directors to consult during si te characterization to discuss in formation needs and ensure that all appropriate data necessary to assess the suitability of the site are collected. The Director has the authority to request additional hydrogeologic data or other data on USDWs as well.

The Agency believes that the requirement at §146.82(a)(6) to submit baseline geochemical data on subsurface geologic formations, including a ll USDWs in the AoR, is appropriate and protective of USDWs. EPA believe s that this data will support monitoring plan development, inform injectate fate and transport model de velopment (e.g., by providing appropriate input

74parameters), and provide information needed to respond to any unexpected and unpermitted leaks outside of the injection zone. The baseli ne geochemical information will allow the owner or operator and permitting authority to evaluate monitoring data and identify any changes in subsurface geochemistry that may indicate fluid movement.

The rule requires geochemical analysis of, at a minimum, the injection zone, confining zone, and all USDWs (§146.82(a)(6)). These geochemical tests ar e necessary to ensure the adequacy of the confining system and to serve as a baseline for future monitoring. The Director has the discretion to require geochemical analysis of additional s ubsurface zones if, in the Director's opinion, they are necessary for the protection of USDWs from endangerment.

Letter ID: 0200 Comment ID: 24649 Letter Lines: 1456 to 1463

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(h)

Anadarko Petroleum Corporation (APC) Co mments: (h) Proposed operating data: (1) Average and maximum daily INJECTION rate and volume of the carbon dioxide

stream; (2) Average and maximum SURF ACE injection pressure;

Rationale: Technical clarifications.

Individual Response: EPA disagrees that the suggested tec hnical clarifications are necessary. EPA adds that it is developing guidance fo r owners or operators on the geologic site characterization process. The guidance will provi de recommendations for owners and operators to consider when completing a permit applica tion. The guidance can be found on EPA’s website at http://water.epa.gov /type/groundwater/uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24650 Letter Lines: 1465 to 1471

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(n)

Anadarko Petroleum Corporation (APC) Co mments: (n) A WELLBORE schematic or other appropriate drawings of the surface and of the subsurface construction

75details of the well AND SURFACE WELLHEAD CONSTRUCTION.

Rationale: Technica l clarification.

Individual Response: EPA disagrees that the suggested tec hnical clarifications are necessary. EPA adds that it is developing guidance fo r owners or operators on the geologic site characterization process. The guidance will provi de recommendations for owners and operators to consider when completing a permit applica tion. The guidance can be found on EPA’s website at http://water.epa.gov /type/groundwater/uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24651 Letter Lines: 1473 to 1479

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

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

Comment: Rule Provision: 146.82(q)

Anadarko Petroleum Corporati on (APC) Comments: q) The ANY status of

corrective action on wells inthe area of review;

Rationale: Clarifies that wells not needing corrective action will not have a

corrective action status.

Individual Response: EPA disagrees that the suggested tec hnical clarifications are necessary. EPA adds that it is developing guidance fo r owners or operators on the geologic site characterization and AoR and corrective action process. The guidance documents will provide recommendations for owners and operators to consider when completing a permit application. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24652 Letter Lines: 1481 to 1493

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.83(a)(2)

Anadarko Petroleum Corporation (APC) Commen ts: (2) A confining zone(s) that is

LATERALLY CONTINUOUS AND fr ee of KNOWN TRANSECTING, tr ansmissive faults or

fractures and of suffic ient areal extent a nd integrity to contain the injected carbon dioxide stream and displaced form ation fluids and allow injection at proposed maximum pressures and volumes without initiating or propagating

76fractures in the confining zone(s); and OVER AN AREA SUFFICIE NT TO PREVENT THE

MOVEMENT OF INJECTED OR DISPLACED FLUIDS INTO A USDW;

Rationale: The proposed clarification k eeps the emphasis on the non-endangerment of USDWs and limits the requirements to th at which is known or can be readily

determined.

Individual Response: The Agency believes that the re quirement at §146.83(a)(2) that the confining zone be free of transmissive faults or fractures is appropriate fo r Class VI wells and is necessary to ensure containment of the injectate and that requiring the confining zone to be free of transmissive faults maximizes protection of USDWs from endangerment. EPA believes that the text regarding propagation of faults and fractu res is important to avoi d the potential for fluid movement and to ensure that injection is at appropriate pressures. Class I hazardous waste injection well operators must also meet a similar re quirement that the site is free of transmissive faults or fractures; they have successfully made such demonstrations in the past. While core samples obtained through drilling and hydraulic testing are direct methods to obtain such information, geophysical techniques such as seismic or electromagnetic surveys can also be used in many geologic settings to demonstrate the absen ce of or identify and characterize the presence

of faults or fractures. EPA adds that the Director must evaluate all geologic data on the site to ensure protection of USDWs from endangerment before approving a site for a GS project.

Letter ID: 0200 Comment ID: 24653 Letter Lines: 1495 to 1505

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.83(b)

Anadarko Petroleum Corporation (APC) Comments: (b) At the Director’s discretion, owners or operators of Class VI wells must identify and characterize additional zones that will impede vertic al fluid movement, are free of faults and fractures that may interfere with containment, allo w for pressure dissipation, and provide additional oppor tunities for monitoring, mitigation and

remediation.

Rationale: This paragraph creates a presum ption that additional confining zones WILL be required. It is also redundan t given the previous sections.

Individual Response: EPA clarifies that secondary confini ng zones are not required for all GS sites. Rather, secondary confini ng zones are required when the Di rector determines that these zones are needed to maximize the protection of USDWs from endangerment. EPA retains the requirement to identify additional containment/confining zones, if required by the Director, as proposed (e.g., §146.83(b)). EPA believes that, in some situations, the presence of additional confining and containment zones above the pr imary (i.e., lowermost) confining zone can improve USDW protection. These layers could fu rther impede vertical fluid movement and

77allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and

remediation.

Letter ID: 0200 Comment ID: 24654 Letter Lines: 1507 to 1518

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(a)

Anadarko Petroleum Corporation (APC) Comm ents: (a) The area of review is the region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of revi ew is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. SUBSURFACE THREE-DIMENS IONAL EXTENT OF THE

CARBON DIOXIDE PLUME, ASSOCIATED PRESSURE FRONT, AS WELL AS THE

OVERLYING

FORMATIONS AND SURFACE AREA ABOV E THAT DELINEATED REGION.

Rationale: Edits make this provision consis tent with the definition of "Area of

Review", which was revised.

Individual Response: EPA disagrees that the AoR definition needs to specifically include the overlying formations and surface area above the delineated region. The intent of the AoR, a long-standing concept within the UIC Program, is to delineate the surface area and all subsurface formations below it that may potentially be impacted by injecti on activity. Acceptable delineation models will provide predictions of CO 2 fate and transport, as well as changes in formation pressure, in three dime nsions as a function of time that can be used to delineate the subsurface storage site and the AoR. Although EP A disagrees with the commenter's suggested change, the Agency has carefully considered all comments on the AoR definition at 146.84(a) and modified it to read as follows: The regi on surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The ar ea of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected CO2 stream and is base d on available site characterization, monitoring, and operational data. EPA believes that this defi nition is sufficiently broad and describes both the intent of the computational modeling and the relationship of th e AoR to areas that are subject

to the risks associat ed with injection.

Letter ID: 0200 Comment ID: 24655 Letter Lines: 1520 to 1531

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: Rule Provision: 146.84(b)

78Anadarko Petroleum Corporation (APC) Commen ts: (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequestration proj ect, periodically reevaluate the delineation, and perfor m corrective action that meets the requirements of this section and is IN A MANNER AND AT A FREQUENCY acceptable to the Director. As a part of the permit application, for approval by the Director the owner or operator must s ubmit an area of review and corrective action plan that includes the following information:

Rationale: Clarification.

Individual Response: EPA disagrees with the suggested changes and believes the proposed text

is clear as written. EPA believes that review a nd approval of the AoR and corrective action plan, including the reevaluation frequenc y of at least every five years, by the Director (and in the context of all information submitted by the owner or operator with the permit application) is important to ensuring USDW protection.

Letter ID: 0200 Comment ID: 24656 Letter Lines: 1533 to 1547

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment)

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: Rule Provision: 146.84(b)(2)

Anadarko Petroleum Corporation (APC ) Comments: (i) The minimum fixed frequency, not to exceed 10 years, the ow ner or operator proposes to reevaluate

the area of review;

(ii) The monitoring and operati onal conditions that would war rant a reevaluation of the area of review prior to the next scheduled reevaluati on as determined by the minimum fixed frequency established in paragraph (b)(2)(i) of this

section.

(iii) (i) How monitoring and operational da ta (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; and

No rationale provided

Individual Response: EPA believes that periodic AoR reevalua tion at a set frequency of at least every five years is necessary to ensure protec tion of USDWs from endang erment and address the uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a deliberate effort is made to verify, base d on monitoring and operational data, that the CO2 plume is moving within the subsurface as predicted. EPA believes that less frequent

79reevaluations may not be sufficient to appropria tely model plume and pressure front movement,

establish conditions for corrective action, and ensure protec tion of USDWs from endangerment.

EPA clarifies that if site m onitoring data agrees with the existing AoR delin eation, a model recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration

that the current AoR delineation is ad equate based on site monitoring data.

Letter ID: 0200 Comment ID: 24657 Letter Lines: 1549 to 1560

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3400 2.2.2 Corrective Action

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: Rule Provision: 146.84(b)(2)(iv)

Anadarko Petroleum Corporat ion (APC) Comments: (iv II) How corrective action will be conducted to meet the requirements of paragraph (d) of this section, including what corrective action will be performed prior to in jection and what, if any, portions of the area of review will have corrective action addressed on a phased basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be guaranteed ARRANGED for future corrective action.

Rationale: Future access cannot be guarant eed for an area in advance that may

not even be within the bounda ries of the AOR/ project.

Individual Response: The purpose of the corrective action requirement at §146.84(d) is to

ensure that all wells in the AoR that have the potential to cause the m ovement of CO2 or other fluids into or between USDWs receive appropriate corrective action. In general, to meet this requirement, the owner or operator will most likel y need to obtain the right of access to wells that may require corrective action, and demonstrat e they have done this in their proposed AoR and corrective action plan. The final rule retains the requirement as proposed.

Letter ID: 0200 Comment ID: 24658 Letter Lines: 1562 to 1572

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(c)(1)

Anadarko Petroleum Corporation (APC) Commen ts: (1) Predict, using computational modeling, the projected lateral and verti cal migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection

80activities until the plume movement ceases, pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or after FOR a fixed time period as determined by the

Director. The model MODELING must:

Rationale: Clarification

Individual Response: Based on an evaluation of all comment s received, EPA has clarified this language in the final rule at 146.84(c)(1). It now reads, “Predict, using existing site characterization, monitoring and operational data , and computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, until pressure

differentials sufficient to cause th e movement of injected fluids or formation fluids into a USDW are no longer present, or until the end of a fixe d time period as determined by the Director.”

Letter ID: 0200 Comment ID: 24659 Letter Lines: 1574 to 1585

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3300 2.2.1 Delineating the AoR/M odeling CO2 movement

Comment: Rule Provision: 146.84(c )(1)(i) & (ii)

Anadarko Petroleum Corporation (APC) Comm ents: (i) Be based on detailed geologic

data collected to characterize the in jection zone, confining zone and any

additional zones ; and anticipated operating data, including injection pressures, rates and total volumes ove r the proposed life of the geological

sequestra tion project THE DURATION OF INJECTION;

(ii) Take into account any RELEVANT geologic heterogeneities, AND data quality, and their possible imp act on model predictions; and

Rationale: Clarification.

Individual Response: EPA agrees that detailed geologic da ta is invaluable to modeling an accurate AoR. EPA clarifies that owners or opera tors may use existing data as well as data collected during site characterizat ion to predict the AoR. The final rule retains the language in §146.84(c)(1)(i) as proposed, and modifies §146.84(c )(1)(ii) slightly to require owners or operators to take into account “o ther discontinuities” in additi on to geologic heterogeneities when predicting the AoR.

EPA disagrees that only the injection and conf ining zones should be included in AoR modeling of GS sites. EPA believes that the modeling shou ld also take into acc ount the possibility of displaced fluids or brines caused by a lateral and/ or vertical pressure plume, and therefore it may be necessary to include additional zones along with the confining/injection zones to ensure the integrity of the confining zone and ultimat ely protect a USDW from endangerment.

81Letter ID: 0200 Comment ID: 24660 Letter Lines: 1587 to 1596

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3420 2.2.2.1 Scope of the inventory pr ocess (e.g., reliance on publicly available information, depth of wells)

Comment: Rule Provision: 146.84(c)(2)

Anadarko Petroleum Corporation (APC) Comm ents: (2) Using methods approved by the Director, identify all KNOWN ARTIFICIAL pe netrations INTO THE CONFINING ZONE, including active and aba ndoned wells and underground mines, in the area of review that may penetrate the confining zone. Provide a description of each well’s type, construction, date drille d, location, depth, record of plugging and/or completion, and any additional info rmation the Director may require; and

Rationale: Changed for consis tency with earlier language.

Individual Response: EPA is retaining the requirement as proposed. EPA agrees with commenters that, for most GS sites, relying on da tabase and other public records searches (i.e., of "known" artificial penetrati ons) will be sufficient to meet the requirements at §146.84(c)(2). However, the Agency recognizes that there ma y be situations where additional surveys or research to locate wells may be appropriate. For example, there may be cases where the Director may determine that ground or airborne surveys for wells are appropriate, e.g., if there is reason to believe, based on knowledge of the site or of available data, that the incompleteness of information on known wells could compromise US DW protection from endangerment. In order to preserve the Director's disc retion to require an operator to supplement a records search, EPA did not make the suggested change. EPA adds th at all corrective action must be performed pursuant to the approved AoR and corrective ac tion plan, which affords the Director the discretion to require any additi onal information needed (inclu ding information that is not publically available) to ensure that all necessary corrective action is performed.

Letter ID: 0200 Comment ID: 24661 Letter Lines: 1598 to 1605

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3400 2.2.2 Corrective Action

Comment: Rule Provision: 146.84(c)(3)

Anadarko Petroleum Corporation (APC) Co mments: (3) Determine which abandoned wells IDENTIFIED IN 146.84 (C) (2) in the area of review have been plugged (as required by §146.92) in a manner that prevents the movement of carbon

dioxide or associated FORMATION fluids that may endanger USDWs.

Rationale: Remove as redundant.

82Individual Response: EPA clarifies that the term "asso ciated fluids" as proposed in §146.84(c)(3) refers to formation fluids, other in jectates, etc. that may be present in the

subsurface and affect movement of the CO2 plume and/or pre ssure front. EPA believes this terminology would incorporate any fluids in the subsurface that could potentially move through artificial penetrations and affect USDWs. EPA has revise d the language at §146.84(c)(3) to read,

"... carbon dioxide or other fluids that may endanger USDWs..." EP A disagrees that deleting the term area of review is necessary and has reta ined the term in the final rule language.

Letter ID: 0200 Comment ID: 24662 Letter Lines: 1607 to 1619

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3460 2.2.2.3 Acceptable corrective action techniques for GS sites (e.g., cements)

Comment: Rule Provision: 146.84(d)

Anadarko Petroleum Corporation (APC) Commen ts: (d) Owners or ope rators of Class VI wells must perform corrective action USING MATERIALS SUIT ABLE FOR USE WITH

THE CARBON DIOXIDE STREAM AND FORMATION FLUIDS, on all wells in the area of

review IDENTIFIED IN 146.84(C)(2) that are determined to need corrective action". using methods necessary to prev ent the movement of fluid into or between USDWs including use of corro sion resistant materials, where appropriate.

Rationale: Experience with CO2 based EO R strongly supports the use of many conventional materials that might not meet the technical definition of

"corrosion resistant".

Individual Response: EPA revised the text at §146.84(d) to re quire the use of materials that are "compatible with the carbon dioxide stream." EPA believes this language change addresses

commenters' concerns and is also consiste nt with other language regarding materials requirements in the GS rule.

Letter ID: 0200 Comment ID: 24663 Letter Lines: 1621 to 1629

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3400 2.2.2 Corrective Action

Comment: Rule Provision: 146.84(e)

Anadarko Petroleum Corporation (APC) Comm ents: (e) If monitoring data indicate

an e ndangerment to USDWs, the owner or operator must notify the Director and cease operations as required by § 146.94.

Rationale: This is not needed if §146.94 al ready specifies the notification and

83cessation of injection. APC suggests th e removal of this language as unnecessarily duplicative.

Individual Response: Based on consideration of all public comments and other information, EPA deleted this provision from §146.84. The fina l rule now contains a provision in §146.91(c) that requires the owner or opera tor to report within 24 hours any evidence that the carbon dioxide stream or associated pressure front may cause an endangerment to a USDW. EPA believes this change consolidates reporting requirements in one place and provides additional clarity.

Letter ID: 0200 Comment ID: 24664 Letter Lines: 1631 to 1638

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3530 2.2.3.1 AoR reevaluation fre quency (seeking comment)

Comment: Rule Provision: 146.84(f)

Anadarko Petroleum Corporation (APC) Co mments: (f) At the minimum fixed frequency, not to exceed 10 years, as speci fied in the APPROVED area of review and corrective action plan, or when monitoring and opera tional conditions

warrant, owners or operators must:

Rationale: Clarification.

Individual Response: EPA did not make the suggested change, but agrees that AoR reevaluations must take place as specified in approved AoR and corrective action plan. EPA clarifies that owners or operators must deve lop, implement, and update a Director-approved AoR and corrective action plan as required under §14 6.84(b). EPA is developing guidance for owners or operators on how to prepare the required GS project plans. The guidance will be available on EPA's web site, at http://water.epa.gov/type /groundwater/uic/wells _sequestration.cfm.

Letter ID: 0200 Comment ID: 24665 Letter Lines: 1640 to 1647

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: Rule Provision: 146.84(f)(4)

Anadarko Petroleum Corporation (APC) Comm ents: (4) Submit an amended area of review and corrective action plan or demonstrate to the Director through monitoring data and modeling results that no amendment CHANGE to the area of

review and corrective act ion plan is needed.

Rationale: Clarification.

84Individual Response: EPA disagrees with the suggested cha nge and believes the proposed text

is clear as written. For additional information on EPA's approach to AoR and corrective action, please see the final rule and preamble.

Letter ID: 0200 Comment ID: 24666 Letter Lines: 1649 to 1658

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: Rule Provision: 146.85(a)(1)

Anadarko Petroleum Corporation (APC) Commen ts: (1) The Director receives WELL

PLUGGING REPORT IDENTIFI ED IN 146.92(D) and approves OR COMPLETION OF the completed post-injection site care and site closure plan as appropriate ; and

Rationale: Maintenance of the well pl ugging financial obligation until site closure is not necessary. The Director s hould have the authority to release the obligation once the well is plugged.

Individual Response: EPA will allow owners or operators to use separate financial responsibility instruments for differe nt GS activities as long as they are able to demonstrate that their instruments will protect USDWs from endange rment. This means that owners or operators must demonstrate adequate financial responsibi lity for all required activities, including well plugging, with their permit application, per §146.82(a )(14). In addition, on an annual basis, the owner or operator must adjust the cost estimate for inflation, increa se or decrease the value of the

financial instrument to match the cost estimate , and provide any updated information related to their financial responsibility instrument(s), or at any other time deemed appropriate by the Director. These annual reviews provide a mechan ism for revising cost estimates up or down to account for changes in the proj ect, including the execution of environmental obligations as phases of a GS project are completed.

Regarding the suggested edit at §146.85(a)(1), EPA clarifies that the owner or operator may be released from a financial instrument when the phase of the project for which the instrument was required is complete and all financial obligations fo r that instrument have been met, as specified in §146.85(b)(2). For example, when the injection well is plugged to the Director's satisfaction, the owner or operator's financial instrument will be released if it was not used.

EPA is developing guidance on financial responsibility for Class VI wells. The guidance will

include a discussion on how best to estimate costs to assist GS well owners or operators, third party insurers or providers of financial inst ruments, and permitting authorities in developing

estimates of the costs associated with various GS activities. The guidance is available on EPA's website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

85Letter ID: 0200 Comment ID: 24667 Letter Lines: 1660 to 1669

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: Rule Provision: 146.85(b)

Anadarko Petroleum Corporation (APC) Commen ts: (b) The owner or operator must provide to the Director, at a frequency determined by the Director, BUT NO MORE THAN ANNUALLY, written updates of adjustme nts to the cost estimate to account for any amendments CHANGE to the area of review and corrective action plan (§146.84), the injection well plugging plan (§146.92), and the post-injection

site care and site cl osure plan (§146.93).

Rationale: Updates more frequent than annual is not justified.

Individual Response: Cost estimates must be reevaluate d after amendments to the area of review and corrective action plan, prior to well pl ugging or site closure, after amendments to the emergency and remedial response plan, or at a ny other time deemed appropriate by the Director. The rule will also require annual adjustments to the cost estimates for inflation, as specified in §146.85(c)(2). These annual reviews provide a m echanism for revising cost estimates up or down to account for changes in the project, includ ing the execution of en vironmental obligations as phases of a GS project are completed.

EPA did not make the proposed edits at §146.85(b), but did extensively revise and clarify the financial responsibility requirements. See th e final GS rule and preamble for additional information on EPA's final approach.

Letter ID: 0200 Comment ID: 24668 Letter Lines: 1671 to 1678

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: Rule Provision: 146.85(c)

Anadarko Petroleum Corporation (APC) Commen ts: (c) The owner or operator must notify the Director of adverse fina ncial conditions such as bankruptcy , that may affect the ability to carry out injec tion well plugging and post-injection

site care and site closure.

Rationale: Clarification.

Individual Response: EPA did not make the proposed edit s at §146.85(c), but did extensively revise and clarify the financial responsibility requirements. EPA believes that the Director must

86be notified of bankruptcy specifically, among ot her adverse financial conditions, because it

affects the use of financial instruments. See the final GS rule and preamble for additional information on EPA's final approach.

Letter ID: 0200 Comment ID: 24669 Letter Lines: 1680 to 1688

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking comment)

Comment: Rule Provision: 146.85(d)

Anadarko Petroleum Corporation (APC) Commen ts: (d) The operator must provide an adjustment of the cost estimate to the Di rector if the Director has reason to believe that original THE MOST RECENT demonstrati on is no longer adequate to cover the cost of injec tion well plugging (as requi red by §146.92) and postinjection site care and site closure (as required by §146.93)

Rationale: Clarification.

Individual Response: EPA agrees that it is important to periodically update cost estimates that support financial responsibility determinations. EPA clarifies th at the GS rule, at §146.85(e), requires the owner or operator to provide annua l updates to the cost es timate to account for any amendments to the AoR and corrective action plan, the injection well plugging plan, and the PISC and site closure plan.

Letter ID: 0200 Comment ID: 24670 Letter Lines: 1690 to 1699

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 146.86)

Comment: Rule Provision: 146.86(a)(1)

Anadarko Petroleum Corporation (APC) Commen ts: (1) Prevent the m ovement of fluid into or between USDWs or into any unauthorized zones; CONTAINING ANY

CONTAMINANT INTO UNDERGROUND SOUR CES OF DRINKING WATER, IF THE

PRESENCE OF THAT

CONTAMINANT MAY CAUSE A VIOLATI ON OF ANY PRIMARY DRINKING WATER

REGULATION UNDER

40 CFR PART 142 OR MAY OTHERWISE A DVERSELY AFFECT THE HEALTH OF

PERSONS.;

Rationale: The proposed changes reflect th e nonendangerment standard that is the basis of the UIC program.

87Individual Response: EPA disagrees that the language provid ed in § 146.86(a)(1) does not meet the non-endangerment standard provided under the SDWA. In fact, EPA be lieves that protection of USDWs from endangerment a nd prevention of fluid movement between formations is paramount and believes that the language as proposed meets the non-endangerment standard. Appropriately designed and constructed wells ar e necessary to prevent endangerment to USDWs and maintain integrity of the well throughout the lifetime of a GS project . This is the foundation of the requirements for construction and pre-op erational testing of Class VI wells at §§146.86

and 146.87.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. Please see the final rule and preamble for additional information.

Letter ID: 0200 Comment ID: 24671 Letter Lines: 1701 to 1717

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3860 2.3.3 Well component degradation

Comment: Rule Provision: 146.86(b)(1)

Anadarko Petroleum Corporation (APC) Comm ents: (1) Casing and cement or other

materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the operating life of the geologic sequestration projectWELL. All well materials must be compatible SUITABLE

FOR USE with the fluids with which the ma terials may be expected to come into

contact and meet or exceed TEST standard s OR PRACTICES developed for such materials by the American Petroleum Institu te, ASTM International, or comparable standards acceptable to the Director. Th e casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and sp ecify casing and cementing requirements, the owner or operator must provi de the following information:

Rationale: The life of a geologic sequestra tion project could be different than

the life of the well. Class VI well de sign should be based on the life of the

well.

Individual Response: EPA disagrees that the casing, cement, or other materials should only be designed for the period of the injection process, ra ther than the life of the sequestration project. GS projects are anticipated to ha ve long life spans in comparison to other types of deep injection wells. Not only must Class VI wells be able to function safely and properly over the lifespan of the GS project, but they must be constructe d such that USDWs remain protected after well plugging. The requirements at §146.86 will ensure that the well can maintain integrity throughout the proposed life span of the project, including after the injection well is plugged and through the post-injec tion site care period and beyond. While th e risk profile of a GS site will decrease following cessation of in jection, EPA believes that Class VI wells must be designed to

88protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and cementing help ensure that the Class VI well will not serve as a conduit fo r movement of fluids

associated with future injection operations.

Letter ID: 0200 Comment ID: 24672 Letter Lines: 1719 to 1725

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.86(b)(1)(v)

Anadarko Petroleum Corporation (APC) Comments: (v) Corrosiveness COMPOSITION

of the carbon dioxide stream and formation fluids;

Rationale: There is no method for measurement of "corrosiveness" of a CO2

stream. The relevant information is the composition of the CO2 stream.

Individual Response: The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifies that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and described. Pr ocedures that can identify corrosion (or the absence of corrosion) in a Cla ss VI well provide valuable operational information that the Director needs to determine appropriat e standards for the tubing and packer.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24673 Letter Lines: 1727 to 1732

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3860 2.3.3 Well component degradation

Comment: Rule Provision: 146.86(b)(1)(vi)

Anadarko Petroleum Corporation (APC) Commen ts: (vi) Down-hole temperatures AND

PRESSURES;

Rationale: Technica l clarification

Individual Response: EPA clarifies that information on do wn-hole pressures is required at §146.86(b)(1)(ii).

89Letter ID: 0200 Comment ID: 24674 Letter Lines: 1734 to 1739

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3860 2.3.3 Well component degradation

Comment: Rule Provision: 146.86(b)(1)(viii)

Anadarko Petroleum Corporation (APC) Commen ts: (viii) Type or grade of cement

AND ADDITIVES; and

Rationale: Technica l clarification.

Individual Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also

address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade

of cement and cement additives."

Letter ID: 0200 Comment ID: 24675 Letter Lines: 1741 to 1748

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment)

Comment: Rule Provision: 146.86(b)(2)

Anadarko Petroleum Corporation (APC) Co mments: (2) Surface casing must extend through the base of the lowermost USDW ABOV E THE INJECTION ZONE and be cemented

to the surface.

Rationale: In some parts of the US the USDW is very deep and this standard may preclude geologic sequestra tion in these areas.

Individual Response: EPA disagrees with the suggested edit. As described above, EPA disagrees that the surface casing requirements in the GS rule preclude injection below deep USDWs. EPA also recognizes concerns regard ing construction of Class VI wells where the lowermost USDW is very deep. To further addre ss comments on deep injection wells, the final GS rule at §146.95 includes requirements for owne rs or operators that seek a waiver of the injection depth requirements. Ow ners or operators of wells operating under injection depth waivers must comply with additional constructio n requirements to ensure that wells used to inject above or between USDWs are protective.

Letter ID: 0200 Comment ID: 24676 Letter Lines: 1750 to 1767

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.86(b)(3)

90Anadarko Petroleum Corporation (APC) Co mments: (3) At least one long string casing, using a sufficient num ber of centralizers TO CREATE A CEMENT BOND THROUGH THE INJECTION AND CONFINING ZONE(S ), must extend to the injection zone

and must be cemented ISOLATED by circulating cement to the surface in one

or more stages. PLACING CEMENT AND/OR OTHER ISOLATION TECHNOLOGIES AS

NECESSARY TO PROVIDE ADEQUATE ISOL ATION OF THE INJECTION ZONE AND

PROVIDE FOR

PROTECTION OF USDWS.

Rationale: Cementing to surface is not neces sary to protect USDWS, and may have negative consequences, as follows. Cement to surface would elim inate the ability to monitor pressures in this annulus a nd would limit flexibility of remedial options. As revised, the propos al would allow for application and development of alternative technologies. See API RP90 for description of risk-based approach for managing situations involving annular casing pressure. Industry experience with CO2 EOR under the class II program demonstrates the effectiveness of existing cementing procedures.

Individual Response: EPA disagrees with the suggested edits. EPA believes that the requirements for long-string casing are approp riate and offer appropriate flexibility: §146.86(b)(3) requires that the long- string casing extend to the inje ction zone and be cemented by circulating cement to the surface in one or mo re stages. It does not, however, specify how cementing would be accomplished, and gives flexib ility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are protected from endangerment, subject to the approval of the Director.

EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program and the purpose of all requirements for inject ion wells. Any injection activity must be demonstrated to not endanger USDWs, regardle ss of their depth, and if such non-endangerment cannot be shown, then the activity will not be allowed under UIC requirements or the SDWA.

EPA does not believe that the cementing re quirements at §146.86 would prevent monitoring, operation, and remediation of Class VI wells. Cementing of deep wells has been performed successfully in the past by owne rs or operators of Class I hazar dous and Class I municipal waste disposal wells. Some of these wells, whic h must meet the same cementing and casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and remediation (EPA, 2001). See the discussion of Cl ass VI well construction requirements in the preamble to the final GS rule for additiona l information. Additionally, EPA is developing guidance on the construction of Class VI wells . This guidance will be available on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.cfm.

Letter ID: 0200 Comment ID: 24677 Letter Lines: 1769 to 1777

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

91Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)

Comment: Rule Provision: 146.86(b)(4)

Anadarko Petroleum Corporation (APC) Co mments: (4) Circulation of cement may

be a ccomplished by staging. The Director ma y approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can dem onstrate by using logs that the cement

does not allow fluid moveme nt behind the well bore.

Rationale: Same as above

Individual Response: EPA disagrees that the requireme nt should be deleted. Section 146.86(b)(4) of the final rule allows alternate methods of staging the cement, at the Director's discretion, provided the owner or operator can demonstrate using logs that the cement does not

allow fluid movement behind the wellbore.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EP A is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24678 Letter Lines: 1779 to 1793

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.86(b)(5)

Anadarko Petroleum Corporation (APC) Comments: (5) Cement and cement additives must be compatible SUITABLE FOR USE with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design OPERATING life of the geol ogic sequestration project WELL. The integrity and location of th e cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.

Rationale: Experience with CO2 EOR under th e class II program demonstrates the effectiveness of existing cementing mate rials and procedures. Standard API

cements have been used in numerous CO2 EOR operations with no adverse consequences. Refer to the citations w ithin EPA’s proposed rule 73 FR 43532- 43533: Carey et al., (2007), Crow et al., (2008), and Meyer, J.P (2007).

Individual Response: EPA disagrees with the suggested ed its. EPA disagrees that the casing, cement or other materials should only be designed for the period of the injection process, rather than the life of the seque stration project. GS projects are antici pated to have long life spans in

92comparison to other types of deep injection we lls. Not only must Class VI wells be able to function safely and properly over the lifespan of the GS project, but they must be constructed such that USDWs remain protected after well plugging. The requirements at §146.86 will ensure that the well can maintain integrity throughout the proposed life span of the project, including after the injection well is plugged and through the post-inject ion site care period and beyond. While the risk profile of a GS site will decrease following cessation of injection, EPA believes that Class VI wells must be designed to protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and cementing help ensure that the Class VI well will not

serve as a conduit for movement of fluids a ssociated with future injection operations.

EPA recognizes that the oil and gas industry has decades of e xperience injecting CO2 and has demonstrated the effectiveness of existing cem enting materials and procedures. The final GS rule, at §146.86(b)(1), specifies that all casing and cementing or other materials used in the

construction of Class VI wells must meet or exceed standards developed for such materials by

the American Petroleum Institute, ASTM Internat ional, or comparable standards acceptable to the Director. This requirement invokes the expe rtise of these bodies to ensure that the requirements for construction of Class VI wells re flect the state of the art in well construction technology. See the discussion of Cl ass VI well construction requirements in the preamble to the

final GS rule for additional information. A dditionally, EPA is developing guidance on the construction of Class VI wells. This guida nce will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA also believes that GS is sufficiently differe nt from Class II ER operations to warrant the tailored construction requirements for Class VI wells at §146.86. For exam ple, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions wi ll be different, with Class VI injection operations involving large volumes of CO2 and likely having higher pressures within th eir storage formations than Class II ER projects. Therefore, Class VI GS reservoir pressures will increase during the injection phase of the GS project.

Letter ID: 0200 Comment ID: 24679 Letter Lines: 1795 to 1803

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment)

Comment: Rule Provision: 146.86(c)(2)(ii)

Anadarko Petroleum Corporation (APC) Co mments: (ii) Composition of the carbon dioxide stream. (chemical content, co rrosiveness, temperature, and density);

Rationale: There is no method for measurement of "corrosiveness" of a CO2

stream. The relevant information is th e composition of the CO2 stream. The composition of the CO2 stream is more re levant to the design of a tubing and packer system.

Individual Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of

93the CO2 that could affect the performance of the tubing and packer, including the chemical content, corrosiveness, temperature, and de nsity. The suggested revision to refer to CO2 "composition" would be less precise. EPA clarifie s that, although corrosiveness does not have a unit of measure, corrosiveness can be technically measured and describe d. Procedures that can identify corrosion (or the absence of corrosion) in a Class VI well provid e valuable operational

information that the Director needs to determine appropriate standards for the tubing and packer.

The final GS rule at §146.86(c)(1) also requires that tubing materials used in Class VI wells must meet or exceed standards developed by the Amer ican Petroleum Institute, ASTM International, or comparable standards acceptable to the Direct or. EPA believes that this requirement invokes the expertise of these bodies without the a dded burden of a certification program.

See the discussion of Class VI well construction requirements in the preamble to the final GS rule for additional information. Additionally, EP A is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24680 Letter Lines: 1805 to 1813

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment)

Comment: Rule Provision: 146.86(c)(2)(iii) - (v)

Anadarko Petroleum Corporation (APC) Commen ts: (iii) MAXIMUM PROPOSED Injection temperature and pressure; (iv) MAXIMUM PROPOSED Annular pressure; (v) MAXIMUM PROPOSED Injection rate (int ermittent or continuous) and volume of

the carbon dioxide stream;

Rationale: Technical corrections.

Individual Response: EPA has revised §146.86(c)(3 )(iii) and (iv) to reference the maximum proposed injection pressure and maximum propos ed annular pressure, respectively. EPA has revised §146.86(c)(3)(v) to read "proposed injec tion rate (intermittent or continuous), and

volume and/or mass of the carbon dioxide stream." EPA believes that refere nce to the continuous injection rate would be duplica tive of the maximum rate. EPA believes that considering the maximum injection and annular pressu re would be more protective.

Letter ID: 0200 Comment ID: 24681 Letter Lines: 1815 to 1838

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(a)

94Anadarko Petroleum Corporation (APC) Co mments: (a) During the drilling and construction of a Class VI injection we ll, the owner or operator must run appropriate logs, surveys and tests to dete rmine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formati ons to assure conf ormance with the injection well construction requireme nts under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Dire ctor a descriptive re port prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, su ch logs and tests must include: THE DIRECTOR MAY REQUIRE SUCH LOGS AND TESTS AS MAY BE N EEDED AFTER TAKING INTO

ACCOUNT THE

AVAILABILITY OF SIMILAR DATA IN TH E AREA OF THE DRILLING SITE, THE

CONSTRUCTION

PLAN, AND THE NEED FOR ADDITIONAL INFORMATION THAT MAY ARISE FROM

TIME TO TIME

AS THE CONSTRUCTION OF THE WELL PROGRESSES AND THESE MAY INCLUDE

THE FOLLOWING:

Rationale: In well defined areas, these evaluations are frequently unnecessary.

The director should have discretion to select the appropriate requirements necessary to ensure sufficient baseline da ta and information are available. For example, in an area where a number of we lls are being drilled , the logging of surface hole yields little us eful additional informati on. In particular, this change would allow the Director to redu ce the requirements when multiple wells are installed for a project.

Individual Response: EPA disagrees that the requirements for logs, surveys, and tests are unnecessary. All logs, surveys, a nd tests listed at §146.87( a) are necessary to verify information about the injection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. This inform ation is needed to demonstrate that the well can be operated and tested in a manner that pr otects USDWs from endangerment. While the tests do provide information on some of the same items, each test provides unique pieces of information that build on each other and allow for interpretations not possi ble with a single test.

EPA notes that the Director ha s the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information, and the Dire ctor may accept information on cores of the injection and confining zones from nearby wells if the owner or operator can demonstrate that such cores are representative of conditions at the well in qu estion and core retrieval is not possible, as specified at §146.87(b) . EPA believes that logs and te sts must be performed on each well drilled regardless of existing information a bout the area to account for the complexity of CO2 injection well construction and the buoyanc y of CO2. Existing lithologic and geologic information may lack the details needed for site -specific well design a nd the geology needed to support protection of USDWs from endangerment.

95Letter ID: 0200 Comment ID: 24682 Letter Lines: 1840 to 1847

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(a)(2)(i)

Anadarko Petroleum Corporation (APC) Co mments: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and

Rationale: After a few wells are drilled in an area, these evaluations are frequently unnecessary and yield little new information. This is an example of

where Director discretio n may be appropriate.

Individual Response: As described above, EPA disagrees that the requirements for logs, surveys, and tests are excessive or duplicative. All logs, survey s, and tests listed at §146.87(a) are necessary to verify information about the in jection and confining zones and ensure that the well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods that provide equivalent or better information.

Letter ID: 0200 Comment ID: 24683 Letter Lines: 1849 to 1860

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(a)(2)(ii)

Anadarko Petroleum Corporati on (APC) Comments: (ii) A Cement bond and variable density log, and a temperature log evaluation log(s) after the casing

is set and cemented.

Rationale: Unusual to run these logs in a surface hole due to uniformity of shallow geology. This is an example of where Director discretion may be appropriate.

The proposed change provides more flexibil ity to select the appropriate log to demonstrate adequate cement bond.

Individual Response: EPA clarifies at §146.87(a)(2)( ii) that owners or operators must perform a cement bond (i.e., cement evaluation) log af ter the casing is set and cemented.

Letter ID: 0200 Comment ID: 24684 Letter Lines: 1862 to 1871

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

96Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87)

Comment: Rule Provision: 146.87(a)(3)(i)

Anadarko Petroleum Corporation (APC) Comments: Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs and any other logs the Director requires BASED ON SITE SPECIFIC COND ITIONS AND RISK-BASED FACTORS for the given geology before the casing is installed; and

Rationale: It is acceptable to specify basic logging requirements, however, special logs should not be specified. Any other informa tion from the area should

be drawn on.

Individual Response: EPA believes that a minimum suite of logs and tests is necessary at all Class VI wells. All logs, surveys, and test s listed at §146.87(a) are necessary to verify information about the injection and confining zone s and ensure that the well is being drilled and cased as approved and has mechanical integrity.

EPA notes that owners or operators will descri be in their permit applications how they will

construct and test the well, and will also subm it site-specific information about the subsurface geology. The Director will evaluate the proposed logging activities al ong with site-specific geologic information to identify geologic data of interest.

EPA adds that, should alternative methods be show n to provide equivalent or better information or if site-specific conditions and risk factors dictate that other l ogs are necessary, the Director has the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve alternative methods that provide eq uivalent or better information.

Letter ID: 0200 Comment ID: 24685 Letter Lines: 1873 to 1880

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(a)(3)(ii)

Anadarko Petroleum Corporati on (APC) Comments: (ii) A Cement bond and variable density log , and a temperature log EVALUATION LOG(S) after the casing

is set and cemented.

Rationale: The proposed change provides more flexibility to select the appropriate log to demonstrate adequate cement bond.

Individual Response: EPA clarifies at 146.87(a)(3)(ii) that ow ners or operators must perform a cement bond (i.e., cement evaluation) log af ter the casing is set and cemented.

97Letter ID: 0200 Comment ID: 24686 Letter Lines: 1882 to 1894

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(a)(4)

Anadarko Petroleum Corporation (APC) Comments: (4) A series of tests TEST(S) designed to demonstrate the internal a nd external mechani cal integrity of injection wells, which may include: (i) A pressure test w ith liquid or gas; (ii) A tracer survey DIAGNOSTIC TOOLS such as oxygen-activation logging; (iii) A temperature or noise log; AND (iv) A casing inspection log. if required by the Director; and

Rationale: Technical and grammatical corrections

In (iv), "if required by the Director" is unnecessary.

Individual Response: EPA disagrees that allowing the use of unspecified "diagnostic tools" would provide the same amount of information as the requirement to perform a tracer survey.

The track record for tracer surv eys in evaluating mechanical inte grity has been proven over time. The Agency clarifies that a tracer survey is one of the mechanical integrity tests that may be required by the Director or us ed by the owner or operator.

EPA agrees with the commenter about the wording of the casing inspection log requirement at §146.87(a)(4) and made the suggested change to improve clarity. In the final regulation, §146.87(a)(iv) does not include the phrase , “if required by th e Director.”

Letter ID: 0200 Comment ID: 24687 Letter Lines: 1896 to 1906

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(b)

Anadarko Petroleum Corporation (APC) Commen ts: (b) The owner or operator must

submit to the Director A REPORT DESCRI BING whole cores or sidewall cores REPRESENTATIVE of the injection zone a nd confining system and formation fluid samples from the injection zone(s). Th e Director may accept DATA from cores AND FLUID SAMPLES from nearby wells if the ow ner or operator can demonstrate that such DATA are representative of conditions in the wellbore.

Rationale: The information required should be sufficient to properly describe the injection and confining zones.

98Individual Response: EPA clarifies that it is not the Agency's intent that physical cores be submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) to read as follows: "The owner or operator mu st take whole cores or sidewall cores of the injection zone and confining system and formati on fluid samples from the injection zone(s), and must submit to the Director a detailed report pr epared by a log analyst that includes: well log analyses (including well logs), core analyses, and formation fluid sample information...."

Letter ID: 0200 Comment ID: 24688 Letter Lines: 1908 to 1916

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(c)

Anadarko Petroleum Corporation (APC) Co mments: (c) PRIOR TO INJECTION WELL OPERATION, the owner or opera tor must record the fluid FORMATION temperature, FORMATION FL UID pH and conductivity, and reservoir pressure and

the static fluid level of the injec tion zone(s).

Rationale: Technical corrections. Reservoir pressure and static fluid level are redundant parameters.

Individual Response: EPA disagrees that "reservoir pressu re" and "static fluid level" are redundant parameters. Although the st atic fluid level is equal to the bottom hole pressure, this may not always be identical to the reservoir pr essure. Additionally, measuring the static fluid level provides additional assurance that the r eading is accurate (or, provides the needed information in cases where a good reading is no t obtained). In addition, a static fluid level measurement provides information regarding th e proximity to USDWs that need protection

afforded to them.

Letter ID: 0200 Comment ID: 24689 Letter Lines: 1918 to 1933

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(d)

Anadarko Petroleum Corporation (APC) Comm ents: (d) At a minimum, the owner or operator must determine or calculate the following inf ormation concerning the injection and confining zone(s): (1) Fracture pressure; (2) Other physical and chemical characteristics of the injection and confining

zones; and (3) Physical and chemical characteris tics of the formation fluids in the injecti on zone.

99Rationale: With the exception of calculati ng fracture pressure, the requirements of this section appear red undant to other requirements of prior sections. The fracture pressure requirement has been added to section 146.87(e) below.

(2) and (3) are too vague.

Individual Response: EPA believes that the requirement to provide information on the injection and confining zones in §146.87(d) is warranted, and that the rule provides flexibility to account for the variety of geologic conditions that may be encountered at GS sites.

Letter ID: 0200 Comment ID: 24690 Letter Lines: 1935 to 1953

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(e)

Anadarko Petroleum Corporat ion (APC) Comments: (e) (D) Upon completion

but Prior to INJECTION WELL operation, th e owner or operator must ESTIMATE

FRACTURE PRESSURES OF THE INJECT ION AND CONFINING ZONES AND conduct

the

followin g tests to verify hydrogeologic AND GE OMECHANICAL characteristics of the injection zone, E.G., INJECTIVITY TESTS, ESTIMATES BASED ON OPEN-HOLE LOGGING TOOLS (E.G. MECHANICAL PROPERTIES LOGS), AND OTHER

APPROPRIATE METHODS. (1) A pump test; or (2) Injec tivity tests.

Rationale: Allows the use of information such as leak off te sts conducted during the drilling operation.

The results of a pump test (pumping flui d from the well) have no relevance for an injection well.

Deletion of the injectivity test would a llow the use of non-destructive methods to calculate fracture pressure.

Individual Response: EPA clarifies that the owner or opera tor has the option of using the pump tests or injectivity tests specified at §146.87( e) depending on which w ould provide the most valuable information based on site-specific cond itions. Further, EPA disa grees that pump tests are irrelevant to determining injection zone prope rties. Depending on the ch aracteristics or depth of knowledge of the confining a nd injection zone formations, pu mp tests may be necessary to prove that no hydraulic connection exists between the injection zone and a USDW.

EPA disagrees that the wording at §146.87(d) w ould lead the owner or operator to employ

100destructive testing methods for determination of fracture pressure. The wording "determined or

calculated" allows for calculations to be performed based on non-destructive methods.

Letter ID: 0200 Comment ID: 24691 Letter Lines: 1955 to 1966

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.87(f)

Anadarko Petroleum Corporation (APC) Commen ts: (f) The owner or operator must provide the Director with the opportunity to witness al l logging and testing by this subpart. The owner or operator must submit a schedule of su ch activities to the Director 30 days prior to conducting the first test UPON SPUDDING THE WELL and submit any changes to the schedule 30 days 48 HOURS prior to the

next scheduled test.

Rationale: The changes reflect the reali ties of flexible rig schedules and operations. In addition, they are fully consistent with current Class II requirements and practices, which deal w ith these issues on a daily basis.

Individual Response: EPA disagrees that the 30-day notif ication requirement is unreasonable. Acknowledging the developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each project will provide mu ch needed field data for assurance of USDW protection from endangerment and will help update and refine the permitting process. Adequate timing of notification will ensure the Director's ab ility to be involved.

Letter ID: 0200 Comment ID: 24692 Letter Lines: 1968 to 1988

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4110 2.4.1.1 Injection pressure limitations

Comment: Rule Provision: 146.88(a)

Anadarko Petroleum Corporat ion (APC) Comments: (a) E xcept during stimulation, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the injection zone so as to assure that the injection does not initiate new fract ures or propagate existing fractu res in the injection zone. In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injection or formation fluids that endangers a USDW.

(A) THE OWNER OR OPERATOR MUST COMPLY WITH A MAXIMUM INJECTION

PRESSURE LIMIT

APPROVED BY THE DIRECTOR AND SPECIFI ED IN THE PERMIT. IN APPROVING A

101MAXIMUM

INJECTION PRESSURE LIMIT, THE DIRECT OR SHALL CONSIDER THE RESULTS OF

WELL TESTS.

THE DIRECTOR SHALL APPROVE LIMITS THAT, WITH A REASONABLE DEGREE OF

CERTAINTY,

WILL AVOID INITIATION OR PROPAGATION OF FRACTURES IN THE CONFINING

ZONE OR CAUSE

OTHERWISE NONTRANSMISSIVE FAULTS TRANSECTING THE CONFINING ZONE

TO BECOME

TRANSMISSIVE. IN NO CASE MAY INJECTION PRESSURE CAUSE MOVEMENT OF

INJECTION OR

FORMATION FLUIDS IN A MANNER PROH IBITED BY 40 CFR PART 144.12(A)

Rationale: Maintaining the integrity of the confining zone is the critical

parameter.

Individual Response: EPA notes that because determination of the injection pressure limit is based on the fracture pressure of the injection zo ne, the limit is site-sp ecific and not arbitrary. EPA emphasizes that injection pressure limits ar e important to protect against fracturing of the confining zone, and that the requ irement at §146.88(a) that the pressure in th e injection zone not exceed 90 percent of the fracture pressure provides a margin of safety in the well operation and protects USDWs from endangerment. If the Dire ctor determines, based on a review of the information collected as part of site characterization, th at a lower injection pr essure limitation is appropriate, the Director has the authority to set a lower limit in the operating permit than the

limit established in the rule.

EPA notes that during the site characterization pr ocess, owners or operators must submit data about the geology of the site, as specified at §146.82(a), includ ing data on known or suspected faults and fractures and geomechanical informati on on fractures, stress, du ctility, rock strength, and in situ fluid pressures w ithin the confining zone. The Di rector will use these data to determine appropriate limits on injection.

In response to the concern about reopening of faults at lower pressures than 90 percent of fracture pressure, EPA believes that the requireme nt for the owner or operator to submit data on known or suspected faults and fractures and inform ation on the seismic history of the site will inform the determination of an appropriate pressu re limitation in the permit. Any sites with the potential for reopening or reactivation of faults or unacceptable seismic risk that could otherwise interfere with containment will not be permitted as GS sites.

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 operator102submitted 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: 0200 Comment ID: 24693 Letter Lines: 1990 to 1998

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4100 2.4.1 Injection parameters

Comment: Rule Provision: 146.88(b)

Anadarko Petroleum Corporation (APC) Commen ts: (b) Injection OF THE CO2 STREAM between the outermost casing protecting US DWs and the well bore is prohibited.

Rationale: Routine injection into zones othe r than the target interval(s) should be prohibited, however, wording of this re quirement is not clear as to which interval is being addressed. An absolute prohibition on injection into this annulus may also limit diagnostic options that could be useful.

Individual Response: EPA retains the provision as propos ed, and clarifies that injection between the casing and the well bore is prohibited. This is consistent with requirements for other injection well classes.

Letter ID: 0200 Comment ID: 24694 Letter Lines: 2000 to 2014

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4100 2.4.1 Injection parameters

Comment: Rule Provision: 146.88(c)

Anadarko Petroleum Corporation (APC) Commen ts: (c) The owner or operator must fill the annulus between the tubing an d the long string casing with a noncorrosive fluid approved by th e Director. The owner or operator must maintain on the annulus a pressure that excee ds the operating injection pressure,

unles s the Director determines that such re quirement might harm the integrity of

the well. A POSITIVE PRESSU RE ON THE ANNULUS.

Rationale: Industry experience with the Class II UIC program does not support this requirement.

Positive annular pressure that exceeds th e operating injection pressure is not necessary because a leak from tubing to annulus does not have the same implications as in a Clas s I hazardous situation.

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the injection pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the

103annulus fluid will move into the tubing, rather than the injectate moving out of the tubing and potentially along the outside of the well. EPA belie ves this requirement is appropriate for Class VI wells given the potential high volumes and superc ritical nature of the CO2 injectate, potential geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event of a mechanical integrity loss.

Letter ID: 0200 Comment ID: 24695 Letter Lines: 2016 to 2046

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.88(e)

Anadarko Petroleum Corporation (APC) Commen ts: (e) The owner or operator must

install and use continuous r ecording devices to monitor: the injection pressure; the rate, volume, and temperature of the carbon dioxide stream and . THE

OWNER OR OPERATOR MUST REGULARLY MONITOR the pressure on the annulus

between the tubing and the long string casi ng and annulus fluid volume and . THE OWNER OR

OPERATOR must install and us e alarms and automatic down

- hole shut-off systems, designed to alert the operato r and shutin the well when operating parameters such as injection rate, inje ction pressure, or other parameters approved by the Director diverge beyond ra nges and/or gradients specified in the permit;

Rationale: Over-pressure protection is be st achieved by ensuring compatibility of the casing/tubing material design strength with the surface injection (compression) system. Down-hole shut-in devices are not appropriate for this application. These devises are installed in the tubing string and are typically near the surface of the well. They’re inte nded to seal the tubing in the event of catastrophic failure of the wellhead. These devises would provide little if any protection to USDWs. Is not practicable to install these devises deep within the well (e.g. shortly above the packer). Additionally these devises create a restriction on running other tools like logging tools in the well and therefore could limit an operators ability to do required monitoring and diagnostic work. Lastly, these devises require periodic testing and maintenance which could require either pulling the devise by wire line or by pulling th e entire tubing string depending on the type of devise installed. Either of these activities would be disruptive and costly to the overall project operations.

A more appropriate approach would be installation of landi ng nipples at appropriate points in the tubing string which would allow use of wireline retrievable plugs when needed.

Individual Response: As described above, EPA will not require automatic down-hole shut-off

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of

104USDWs from endangerment. Instead, the final rule , at §146.88(e)(2), requires that owners or operators of onshore Class VI wells install auto matic surface shut-off devices. The rule affords

Director's discretion to mandate automatic down-hole shut-off devi ces in onshore situations that may warrant their use. The rule requires, at §146. 88(e)(3), that owners or operators of offshore

wells within State territorial waters install auto matic down-hole shut-off systems. Please see the final rule and preamble for additional information on EPA's final approach.

Letter ID: 0200 Comment ID: 24696 Letter Lines: 2048 to 2058

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.88(f)

Anadarko Petroleum Corporation (A PC) Comments: (f) If aN down

- hole automatic shutdown is triggered or a loss of mechan ical integrity is di scovered, the owner or operator must immediat ely investigate and identif y as expeditiously as possible the cause of the shutoff . If, upon such investigation, the well appears to be lacking mechanical inte grity, or if monitoring required under paragraph (e) of this sect ion otherwise indicates that the well may be lacking mechanical integrity, the ow ner or operator must:

Rationale: Technical clarifi cation given changes above.

Individual Response: As described above, EPA will not require automatic down-hole shut-off

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, the final rule , at §146.88(e)(2), requires that owners or operators of onshore Class VI wells install auto matic surface shut-off devices. The rule affords

Director's discretion to mandate automatic down-hole shut-off devi ces in onshore situations that may warrant their use. The rule requires, at §146. 88(e)(3), that owners or operators of offshore

wells within State territorial waters install auto matic down-hole shut-off systems. Please see the final rule and preamble for additional information on EPA's final approach.

Letter ID: 0200 Comment ID: 24697 Letter Lines: 2060 to 2065

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4000 2.4 Proposed Injection Well Operat ing Requirements (40 CFR 146.88)

Comment: Rule Provision: 146.88(f)(3)

Anadarko Petroleum Corporation (APC) Comments : (3) Notify the Director within 24

hours OF DISCOVERY;

No rationale provided

105Individual Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., downhole or at the surface) is triggere d or a loss of mechanical integr ity is discovered." Therefore the notice required at §146.88(f)(3) must be provide d within 24 hours of an automatic shut-off device being triggered or a loss of mechanical integrity being discovered. EPA believes this provision is necessary to ensure timely re sponse to potential USDW endangerment.

Letter ID: 0200 Comment ID: 24698 Letter Lines: 2067 to 2077

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4520 2.5.1 Continuous internal mechani cal integrity monitoring (seeking comment)

Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.89(b)

Anadarko Petroleum Corporation (APC) Comments: (b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners or operators must, following an initial annulus pre ssure test, continuously monitor AND

RECORD AT LEAST DAILY, ANNULUS PRESSURE AND VOLUMES OF PACKER

FLUID INJECTED OR REMOVED FROM injection pressu re, rate, injected volumes, and pressure on the annulus between THE tubing and long stem STRING casing and annulus fluid volume as specified in §146.88 (e);

Rationale: Technica l clarification.

Individual Response: EPA agrees with the commenter regarding the importance of demonstrating internal mechanical integrity (M I), but disagrees with the suggested changes. Class VI injection wells will be equipped with dedicated computer-based continuous pressure monitoring devices in concert with the shut-off systems required for GS wells, which typically take readings several times per second (i.e., more frequently than daily) and record them electronically in a computer system. 40 CFR §146.91( a)(2) requires that mont hly averages of the continuous annulus monitoring be reported on a semiannual basis.

40 CFR §146.91(a)(2) requires that monthly averages of the con tinuous annulus monitoring be reported on a semiannual basis. EPA agrees with the commenter that r ecording annulus fluid volume may not be appropriate. EPA believes that annulus fluid volume (146.88(e)) is a necessary component of monitori ng well mechanical integrity, but believes that knowing the

annulus fluid volume added is sufficient to meet th e intent of the requirem ent. The final GS rule requires that owners or operator s use continuous recording devices to monitor injection pressure, rate, and volume, as well as the pressure on the annulus between the tubing and the long string casing. It also modifies the re quirement in the proposed rule to continuously monitor annulus fluid volume; it now requir es recording of annulus fl uid volume added. See §§146.88(e), 146.89(b), and 146.90 (b). The final rule implements the suggested change from “long-stem” to “long-string” casing.

106Letter ID: 0200 Comment ID: 24699 Letter Lines: 2079 to 2097

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4540 2.5.2 Proposed external MIT requirements

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment)

Comment: Rule Provision: 146.89(c)

Anadarko Petroleum Corporation (APC) Comm ents: (c) At least once per year, the owner or operator must confirm the abse nce of significant fluid movement under paragraph (a)(2) of this section USIN G A METHOD ACCEPTABLE TO THE DIRECTOR (E.G.

INCLUDING DIAGNOSTIC SURVEYS SUCH AS OXYGENACTIVATION LOGGING OR

TEMPERATURE OR NOISE LOGS).

(1) A tracer survey such as oxygen

- activation logging; (2 ) A temperature or noise log; or (3) A casing inspecti on log, if required by the Director.

Rationale: Revised text supports a perfor mance-based approach and allows the development and use of new technologies as they become av ailable. Cement

circulation to the surface is not neces sary because having the open annulus above the top of cement allows regular monitoring of annular pressure which could indicate leakage.

Number 3 was deleted because it requires the tubing to be pulled at significant

cost and risk of unc ontrolled releases.

Individual Response: EPA believes that the MITs descri bed in 146.89(c) of the rule (an approved tracer log or temperatur e or noise logs) are effective me thods to demonstrate external MI, provide an important early warning of potenti al problems in the injection well system, and represent standard techniques that have been used successfully by the drilling industry and for the UIC Program for decades. The Agency notes that the regulations do provide the Director flexibility at §146.89(e) to approve th e use of alternative MIT methods.

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement behind the casing, but clarifies that it is appropriate for determin ing the presence or absence of corrosion of the long-string casing, a nd is required if the Director determines that it is necessary based on site-specific information. EPA has revi sed the final GS rule to require that the frequency of the casing inspection log must be specified in the approve d testing and monitoring plan. See §146.89(d).

Letter ID: 0200 Comment ID: 24700 Letter Lines: 2099 to 2118

107Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.90 Anadarko Petroleum Corporation (APC) Comments: The owner or operator of a Class VI well must prepare, maintain, a nd comply with a testing and monitoring plan to verify that the geologic sequestration project is operating as permitted and is not endangering USDWs. The testing and monitor ing plan must be submitted with the permit application, for Director approval, and must include a description of how the owner or operato r will meet the requirements of this section. Testing and monitoring associated with geologic sequ estration projects

must, at a minimum, include:

(A) BASED ON A SITE-SPECIFIC ASSESSM ENT OF THE POTENTIAL FOR FLUID

MOVEMENT FROM

THE INJECTION WELL OR INJECTION ZO NE, AND ON THE POTENTIAL VALUE OF

MONITORING

WELLS TO DETECT SUCH MOVEMENT, THE OWNER OR OPERATOR OF A CLASS VI

WELL MUST

PREPARE, MAINTAIN, AND COMPLY WITH A TESTING AND MONITORING PLAN TO

VERIFY THAT THE GEOLOGIC SEQUESTRATION PROJECT IS OPERATING AS PERMITTED AND IS

NOT

ENDANGERING USDWS. THE TESTING AND MONITORING PLAN MUST BE

SUBMITTED WITH THE

PERMIT APPLICATION, FOR DIRECTOR APPROVAL AND INCLUDE A DESCRIPTION

OF HOW THE

OWNER OR OPERATOR WILL MEET THE REQUIREMENTS OF THIS SECTION;

No rationale provided

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

EPA anticipates that the testing and monitoring plan will address site-specific geologic factors, modeling, and risk-assessment. EPA is developing guidance on how best to develop the various required project plans, includi ng the testing and monitoring pl an. The guidance can be found on EPA’s website at http://water.epa.gov/type /groundwater/uic/wells _sequestration.cfm.

Letter ID: 0200 Comment ID: 24701 Letter Lines: 2120 to 2154

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

108Comment: Rule Provision: 146.90(b)

Anadarko Petroleum Corporation (APC) Comm ents: (b) The testi ng and monitoring plan must, at a minimum, include:

(a 1) Analysis of the carbon dioxide st ream with sufficient frequency to yield data representative of its chem ical and physical ch aracteristics; (b 2) Installation and use, except during well workove rs as defined in § 146.86(d), of continuous recording MONITORING DEVICES (INCLUDING DIGITAL DEVICES CAPTURING PERIODIC DATA) to monito r injection pressure, rate and volume; AND TO RECORD AT LEAST DAILY the pressure on the annulus between the tubing and the long string casing; and the annulus fluid volume; (3) A DEMONSTRATION OF EXTERNAL MECHANICAL INTEGRITY PURSUANT TO §146.89(C)

UNTIL THE WELL IS PLUGGED; (4) MONITORING OF THE PRESSURE BUILDUP IN THE INJECTION ZONE

ANNUALLY, INCLUDING

AT A MINIMUM, A SHUTDOWN OF TH E WELL FOR A TIME SUFFICIENT TO

CONDUCT A VALID

OBSERVATION OF THE PRESSURE FALLOFF CURVE AT LEAST ONCE EVERY FIVE

YEARS; AND (5) A QUALITY ASSURANCE PLAN FO R ALL TESTING AND MONITORING REQUIREMENTS.

(b) Installation and use, except during well workovers as defined in §146.88(d), of continuous monitoring devices (includi ng digital devices ca pturing periodic data) to monitor injection pressure, rate and volume; and RECORD AT LEAST DAILY the pressure on the annulus between th e tubing and the long string casing;

Rationale: §146.86(d) does not exist; perh aps §146.88(d) is what was apparently

intended.

There is concern regarding what cons titutes continuous monitoring. Industry agrees that regular monitoring of th e parameters identified by EPA is appropriate. Our experience with CO2 EOR st rongly shows that daily monitoring of most of these parameters is adequate (e xceptions to this would be on a sitespecific basis). Recording should genera lly be done on a daily basis and reporting on a semi-annually basis. As a guiding principle, the frequency of monitoring should be determined by the le vel of risk posed by the injection operation.

Individual Response: EPA believes that continuous pressu re monitoring of GS wells, as required at §146.88(e), is important and appropriate because the potentially corrosive nature of CO2 streams in the presence of water makes it cr itical to immediately identify corrosion-related well mechanical integrity loss. Class VI inje ction wells must be equipped with dedicated computer-based continuous pre ssure monitoring devices (in con cert with the Director-approved

109shut-off systems required for GS wells), which t ypically take readings several times per second and record them electronically in a computer system..

EPA believes that a frequency of at least once every five years, as specified at §146.90(f), is an appropriate interval for pressure fall-off testing (particularly gi ven 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 sp ecific project, if necessary base d on site-specific circumstances. Pressure fall-off tests may be conducted in conj unction with other well performance tests (i.e., mechanical integrity testing) to ensure safe and effective operations . All monitoring data collected, including information from pressure fall-off tests, will be incorporated in AoR reevaluations, at least every five years. EPA disagrees that the ru le should provide specifics of the testing at the degr ee suggested, however.

EPA clarifies that periodic MITs are not be required fo llowing plugging of the well.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS rule. See the final rule and preamble for further discussi on on EPA's final approach.

Letter ID: 0200 Comment ID: 24702 Letter Lines: 2156 to 2204

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4630 2.6.3 Corrosion monitoring

Comment: Rule Provision: 146.86(c)

Anadarko Petroleum Corporation (APC) Co mments: (C) WHERE APPROPRIATE, THE

TESTING AND MONITORING PLAN S HALL ALSO INCLUDE:

(1) CONTINUOUS MONITORING FOR PR ESSURE CHANGES IN AN APPROPRIATELY

POROUS AND

PERMEABLE FORMATION OVERLYING THE CONFINING ZONE. WHEN A WELL IS

INSTALLED TO

ENABLE SUCH MONITORING, THE OWNER OR OPERATOR SHALL, ON A SPECIFIED FREQUENCY OR

AT SPECIFIED TIMES, SAMPLE TH E FORMATION AND ANALYZE FOR

CONSTITUENTS SPECIFIED

IN THE PLAN;

(2) THE USE OF INDIRECT, GEOPHYSIC AL TECHNIQUES TO DETERMINE THE

POSITION OF THE CO2 STREAM FRONT, THE WATER QUALITY IN A DESIGNATED FORMATION, OR

TO PROVIDE

OTHER SITE SPECIFIC DATA;

(3) PERIODIC MONITORING OF WATER Q UALITY IN AN APPROPRIATELY POROUS

110AND

PERMEABLE FORMATION OVERLY ING THE INJECTION ZONE;

(4) PERIODIC MONITORING OF WATER Q UALITY IN ONE OR MORE USDWS;

(5) CORROSION MONITORING OF THE WE LL MATERIALS FOR LOSS OF MASS,

THICKNESS,

CRACKING, PITTING AND OTHER SIGNS OF CORROSION PERFORMED AND

RECORDED AT LEAST QUARTERLY WHICH MAY BE M ODIFIED TO BE LESS FREQUENT AS APPROVED BY

THE DIRECTOR

BASED ON CONSTRUCTION MATERIA LS, OPERATING CONDITIONS, AND

MONITORING HISTORY TO

ENSURE THAT THE WELL COMPONENTS MEET THE MI NIMUM STANDARDS FOR

MATERIAL STRENGTH

AND PERFORMANCE SET FO RTH IN §146.86(B) BY: (I) ANALYZING COUPONS OF THE WELL C ONSTRUCTION MATERIALS PLACED IN

CONTACT WITH

THE CARBON DIOXIDE STREAM; OR (II) ROUTING THE CARBON DIOXIDE STRE AM THROUGH A LOOP CONSTRUCTED

WITH THE

MATERIAL USED IN THE WELL AND INSP ECTING THE MATERIALS IN THE LOOP;

OR (III) USING AN ALTERNATIVE METHOD, MA TERIALS, OR TIME PERIOD APPROVED

BY THE

DIRECTOR;

(6) ANY ADDITIONAL TESTING AND MONI TORING APPROPRIATE TO SUPPORT

MODELING THE

EXTENT OF THE CARBON DIOXIDE PLUME AND THE POSITION OF THE PRESSURE

FRONT; AND

(7) ANY ADDITIONAL TESTING AND MONITORING NECESSARY TO DETERMINE

WHETHER FLUID

MOVEMENT IS OCCURRING INTO OR BETWEEN USDWS THAT WOULD ENDANGER

A USDW.

Rationale: Drilling monitoring wells should be carefully considered since each well introduces a potential pathway for movement. In addition the cost of adding multiple wells could create a barrier to CCS development, while providing

limited information on actual movement of the CO2 stream.

APC questions the need for corrosion mon itoring of most inje cted CO2 streams since they will typically be nearly pu re and dry thus having no corrosive properties. Industry experi ence with production, transp ortation, and injection of dry CO2 strongly illustra tes the non-corrosive nature of this type of CO2

111stream.

Individual Response: EPA believes that quarterly corros ion monitoring of GS wells is necessary. CO2 in the presence of water (incl uding water with NOx, SOx, and H2S impurities)

can be corrosive to well materials and cements . Thus, although a CO2 stream may be dry, the potential for corrosion of well materials down-hole , where the injectate can potentially mix with water in the target formation, must be considered.

Several laboratory studies a nd a limited number of field studies have investigated and

characterized the effects of carbonic acid on well materials. La boratory studies (e.g., Kutchko et al., 2007; Kutchko et al., 2008) cons istently identify al terations (typically carbonation) of cement

as the result of interactions betw een cement and CO2-saturated brine.

Currently, there are only a few analyses of cemen t from wells that have been in prolonged

contact with CO2 in actual fiel d (down-hole) conditions. Evaluati on of cement from a well at the Scurry Area Canyon Reef Operator s Committee (SACROC) site s howed alteration, but did not show degradation that compromise d the structural integrity of th e cement (Carey et al., 2007). In another study, cement samples were collected and analyzed from a CO2 production well in a natural CO2 reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years (Crow et al., 2008). The study found evidence of reaction between the CO2-rich water and the

cement.

Oil industry research also addre sses the effects of corrosion of st eel tubing and pipes. Lopez et al. (2003) noted that 60 percent of oilfield failures are related to the effect s of carbonic acid from produced brines on carbon and low alloy steels.

Laboratory investigation of cement alteration/de gradation is an ongoing re search area. Few fieldbased studies have been completed to date. The laboratory and field stud ies currently available suggest that corrosion problems can be managed; however, there is no t a large enough body of research to rule out potentia l corrosion problems of steel co mponents of injection wells. The IPCC (2005) report on carbon dioxide capture an d storage reviewed oil and gas industry experience with gas injection we lls, close industry analogues to CO2 injection wells. The report stated that while the design of CO2 injection we lls will be very similar to gas injection wells, most down-hole components of the CO2 injecti on wells will “need to be upgraded for higher pressure ratings and corrosion resistance.” Give n the pressure and corrosion considerations, anticipated long lifespan of a GS well and the difficulties that would be associated with a

corrosion-related well failure, EPA believes th at corrosion monitoring in the down-hole environment is justified. For thes e reasons, the final ru le requires quarterly corrosion monitoring at §146.90(c).

EPA maintains that plume tracking and pressure monitoring are key components of monitoring at GS sites. A rigorous plume tracking and pressu re monitoring scheme, such as one that meets the requirements at §146.90(g), is imperative for ensuring that the CO2 plume is contained within the injection zone. Pressure monitoring in the injection zone is necessary to track the development and movement of the pressure front and CO2 plume. When combined with information on temperature, pressure data pr ovide an indication of the phase (e.g., gas,

112supercritical) and distribution of the injected CO2. Monitoring ca n also identify needed remedial actions, provide inputs for AoR reevaluation mode ling, evaluate predictions of plume movement, and target additional geochemical and surface monitoring needs.

EPA also believes that the ground water geoc hemical monitoring outlined in §146.90(d) will maximize protection of USDWs from endangerment at GS sites. Direct geochemical sampling is an important part of a monitoring program. See the final rule and preamble for further discussion on EPA's final approach.

Letter ID: 0200 Comment ID: 24703 Letter Lines: 2206 to 2220

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4630 2.6.3 Corrosion monitoring

Comment: Rule Provision: 146.90(c)

Anadarko Petroleum Corporation (APC) Comm ents: (c) Corrosion monitoring of the

well materials for loss of mass, thickne ss, cracking, pitting and other signs of corrosion must be performed on a quarte rly basis to ensure that the well components meet the minimu m standards for material strength and performance set forth in § 146.86(b) by:

(1) Placing coupons of the well construc tion materials in contact with the

carbon dioxide stream; or (2) Routing the carbon dioxide stream through a loop constructed with t he

material used in the well; or (3) Using an alternative me thod approved by the Director;

Rationale: See 146.90(5)(i-iii)

Individual Response: EPA believes that corrosion monitoring is necessary for all Class VI wells to prevent endangerment of USDW s. CO2 in the presence of wa ter (including water with NOx, SOx, and H2S impurities) can be corrosive to we ll materials and cements. Thus, although a CO2 stream may be dry, the potential for corrosion of well materials down-hole, where the injectate can potentially mix with water in the ta rget formation, must be considered.

Based on its evaluation of all public comment s and input on the proposed rule and NODA and Request for Comment, EPA has made many revisi ons to the GS rule. See the final rule and preamble for further discussi on on EPA's final approach.

Letter ID: 0200 Comment ID: 24704 Letter Lines: 2222 to 2238

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4660 2.6.6 Geochemical monitoring

113Comment: Rule Provision: 146.90(d)

Anadarko Petroleum Corporation (APC) Comments: (d) Periodic monitoring of the ground water quality and geochemical cha nges above the confining zone(s) that may be a result of carbon dioxide movement through the confining zone or

additio nal identified zones:

(1) The location and number of monitoring wells must be based on specific information about the geologic sequestra tion project, including injection rate and volume, geology, the presence of artif icial penetrations and other factor s;

(2) The monitoring frequency and spatial distribution of monitoring wells must be based on baseline geochemical data that has been collected under § 146.82(a) (6) and any modeling results in the area of review evaluation required by § 146.84(b);

Rationale: See 146.90(c)(1 thru 4 and 7)

Individual Response: EPA did not make the suggested cha nges, but agrees that monitoring plans and methods need to be site-specific a nd based on baseline data and data collected throughout operations. EPA believe s that the monitoring requirements for GS sites at §146.90 provide an appropriate level of flexibility in structuring a te sting and monitoring plan that protects USDWs from endangerment.

The final regulation provides for flexibility in: 1) methodologies used to co llect these data, 2) the spatial resolution at which the data should be co llected, and 3) how often the data should be collected. The number and placement of monitoring wells will be based on site-specific information such as the calculated AoR, inject ion rate and volume, site geology, baseline data, and the presence of artificial penetrations within the AoR. In some instances, there may be a limited number of options for complying with EPA's minimum requirements. For example, monitoring for geochemical changes will require use of monitoring wells and collection of groundwater samples for chemical analysis. Many options currently exis t for complying with other requirements, such as tracking the positio n of the plume and pressure front within the injection zone.

Flexibility is also provided re garding how to monitor for the sp ecific data required by the final rule. The testing and monitoring plan is develope d by the owner or operato r in consultation with the Director and is designed to ensure that a detailed, Director-approved document describing how monitoring will be conducted during the lifetime of the project exists. EPA is developing guidance on testing and monitoring to assist owners or operators and Directors in evaluating requirements under §146.90, including proposed monitoring plans. The guidance describes available technologies and reco mmended approaches for implem enting a testing and monitoring plan, including pre-operational geophysical logging and testin g of injection wells, MITs, injection well testing during ope ration, groundwater quali ty monitoring, tracking the CO2 plume and pressure front, and soil gas and surface ai r monitoring which may be required by the UIC

114Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0200 Comment ID: 24705 Letter Lines: 2240 to 2246

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

Comment: Rule Provision: 146.90(e)

Anadarko Petroleum Corporation (APC) Comm ents: (e) A demonstration of external mechanical integrity pursuant to § 146.89( c) at least once per year throughout the duration of the geolog ic sequestration project;

Rationale: See 146.90(b)(3)

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for further discussi on on EPA's final approach. EPA adds that the purpose of including all testing and monitoring requirements in §146.90 is to clarify and to specify the content of the required testing and monitoring plan.

Letter ID: 0200 Comment ID: 24706 Letter Lines: 2248 to 2254

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

Comment: Rule Provision: 146.90(f)

Anadarko Petroleum Corporation (APC) Comments: (f) A pressure fall

- off test at least once every five years unless more frequent testing is required by the

Director based on site specific information;

Rationale: See 146.90(b)(4)

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for further discussi on on EPA's final approach. EPA adds that the purpose of including all testing and monitoring requirements in §146.90 is to clarify and to specify the content of the required testing and monitoring plan.

115Letter ID: 0200 Comment ID: 24707 Letter Lines: 2256 to 2270

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.90(g)

Anadarko Petroleum Corporation (APC) Co mments: (g) Testing and monitoring to

track the extent of the carbon dioxide plume and the position of the pre ssure front by either monitoring for pressure changes in the first formation overlying the confining zone or using indirect , geophysical techniques (e.g., seismic, electrical, gravity, or electr omagnetic surveys and/or down

- hole carbon dioxide

detectio n tools);

Rationale: See 146.90(c)(1 thru 4 and 7)

Monitoring outside of the in jection zone provides littl e information of value for tracking and monitoring the injected pl ume. Examples of how to test and

monitor could be included in the Preamble but need not be included in the rule

itself.

Individual Response: EPA believes that direct pressure me asurements are appropriate and the final rule (at §146.90(g)) requires owners or operato rs 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. Indire ct methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) are also required unless the Director determines, based on si te-specific geology, that such methods are not appropriate.

EPA believes that pressure monitoring in th e injection zone is n ecessary to track the development and movement of the pressure front and CO2 plume. Monitoring can also identify needed remedial actions, provide inputs for AoR reevaluation m odeling, evaluate predictions of plume movement, and target additional geoche mical and surface monitoring needs. Knowledge of the location of the CO2 plume and the associated pressure front will assure the public that GS projects are proceeding according to plan, provide sufficient information to the owner or operator and Director, or allow for 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 conf ining zone), and adds that it is important to balance the need for adequate monitoring that ensures USDW protection from endangermentagainst too many artificial penetrations which could serve as conduits for fluid migration. Sitespecific testing and monitoring plans should desc ribe the proposed monitoring regime, which must be approved by the Director. Flexibility is also provided re garding how to monitor for the sp ecific data required by the final rule. The testing and monitoring plan is develope d by the owner or operato r in consultation with the Director and is designed to ensure that a detailed, Director-approved document describing

116how monitoring will be conducted during the lifetime of the project exists.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requirements under §146.90, which will include discussion of identifying the extent of the CO2 plume and pressure front . The guidance describes available technologies and recommended approaches for implementing a testing and monitoring plan, including preoperational geophysical logging and testing of injection wells, MI Ts, injection well testing during operation, groundwater qualit y monitoring, tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm. In addition, in January 2009, DOE published a best practices manual entitled "Monitoring, Verificat ion, and Accounting of CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this manual is included in

the docket for the final GS rule.

Letter ID: 0200 Comment ID: 24708 Letter Lines: 2272 to 2288

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking comment)

Comment: Rule Provision: 146.90(h)

Anadarko Petroleum Corporation (APC) Comments: (h) At the Director’s discretion, surface air monitoring and/or so il gas monitoring to detect movement of carbon dioxide that could endanger a USDW.

(1) The testing and monitoring plan must be based on potential vulnerabilities

within the area of review;

(2) The monitoring frequency and spatial distribution of surface air monitoring and/or soil gas mo nitoring must reflect baseline data and the monitoring plan must include how the proposed monitoring will yield useful information on the

area of review delineation and/or co mpliance with standards under 40 CFR

144.12;

Rationale: In most situations soil an d air monitoring does not provide an effective method of protecting USDWs.

Individual Response: As described above, EPA acknowledges that air and soil gas monitoring to ensure USDW protection is no t necessary at all GS sites and agrees that the decision to use surface monitoring and the selecti on of monitoring methods for th e purpose of USDW protection will be site-specific.

In the final rule, at §146.90(h), the decision to re quire such monitoring as an additional measure to ensure USDW protection rests with the Direct or as a means of identif ying leaks that may pose

117a risk to USDWs and informing emergency notifi cation of a Class VI owner or operator and UIC Director in the event of a USDW endangerm ent, pursuant to requirements at §146.91(c).

The Agency agrees with the comm enter that, if air and soil gas monitoring is performed, baseline

soil CO2 levels need to be determined befo re monitoring. This would be considered and described in the site-specific testing and monitoring plan.

Letter ID: 0200 Comment ID: 24709 Letter Lines: 2290 to 2297

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.90(i)

Anadarko Petroleum Corporation (APC) Co mments: (i) Any additional monitoring, as required by the Director, necessary to support, upgrade, and improve computational modeling of the area of review evaluation required under § 146.84(b) and to determine compliance with stand ards under 40 CFR 144.12; and

Rationale: See 146.90(c)(6)

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

Letter ID: 0200 Comment ID: 24710 Letter Lines: 2299 to 2304

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.90(j)

Anadarko Petroleum Corporation (APC) Co mments: (j) A quality assurance and surveillance plan for all tes ting and monitoring requirements.

Rationale: See 146.90(b)(5)

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

Letter ID: 0200 Comment ID: 24711 Letter Lines: 2306 to 2319

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

118Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.91(a)

Anadarko Petroleum Corporation (APC) Comm ents: (a) Semi-annual OR LESS FREQUENT

AT THE DISCRETION OF THE DIRE CTOR reports containing:

(1) Any SIGNIFICANT changes to the phys ical, chemical and other relevant

characteristics of the carbon dioxide str eam from the proposed operating data;

Rationale: Over the life of the project, the Director may decide that less reporting is acceptable

(1) Technical clarification. Significance can be determined by a statistical analysis of the data. Rules should recogni ze that there will be minor variations in many data sets over time.

Individual Response: EPA retained this provision as pr oposed. The final rule at §146.91(a)(3) requires reporting of all exceedances of operating parameters. EPA disagrees with the suggestion to report only "significant" exceedances. Making a determination as to whether an exceedance is "significant" is not the purpose of the requirement. EPA believes that the ability of an operator toconsistently meet operating requirements and avoid exceedances provides evidence of a wellmanaged GS project that is in compliance with the Class VI permit. If multiple exceedances

occur, the Director should be aware of such o ccurrences, and that information will aid in his/her

determination of whether these indi cate problems at the site, and what is the appropriate course of action (e.g., a well workover, modification of operating parameters, or imposition of a penalty) to remediate such problem(s).

Letter ID: 0200 Comment ID: 24712 Letter Lines: 2321 to 2332

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4720 2.7.2 Operational record keeping and reporting

Comment: Rule Provision: 146.91(3) & (4)

Anadarko Petroleum Corporation (APC) Co mments: (3) A desc ription of any SIGNIFICANT event that exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;

(4) A description of any SIGNIFICANT ev ent which triggers a shutdown device required pursuant to §146.88(e) and the response taken;

Rationale: EPA should consider some signi ficance threshold on reporting these events to avoid reporting events that would be of limited interest or

consequence.

119Individual Response: EPA retained this provision as pr oposed. The final rule at §146.91(a)(3) requires reporting of all exceedances of operating parameters. EPA disagrees with the suggestion to report only "significant" exceedances. Making a determination as to whether an exceedance is "significant" is not the purpose of the requirement. EPA believes that the ability of an operator toconsistently meet operating requirements and avoid exceedances provides evidence of a wellmanaged GS project that is in compliance with the Class VI permit. If multiple exceedances

occur, the Director should be aware of such o ccurrences, and that information will aid in his/her

determination of whether these indi cate problems at the site, and what is the appropriate course of action (e.g., a well workover, modification of operating parameters, or imposition of a penalty) to remediate such problem(s).

Letter ID: 0200 Comment ID: 24713 Letter Lines: 2334 to 2342

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: Rule Provision: 146.92(a)

Anadarko Petroleum Corporation (APC) Comm ents: (a) Prior to the well plugging, the owner or operator must flush each Cl ass VI injection well with a buffer fluid, determine bottomhole reservoir pr essure, and perform a final EXTERNAL mechanical integrity test OF ANY RELEV ANT WELLBORE MATERIALS REMAINING.

Rationale: Many of the components that woul d be tested by an internal MIT are removed or tested during the plugging process.

Individual Response: EPA agrees that only an external MIT is required, and has modified the GS rule at §146.92(a) to require owners or opera tors to perform a final external mechanical integrity test prior to the well plugging.

Letter ID: 0200 Comment ID: 24714 Letter Lines: 2344 to 2353

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: Rule Provision: 146.92(b)(2)

Anadarko Petroleum Corporation (APC) Comments: (2) Appropriate testing methods

to ensure FINAL EXTERNAL mechanical integrity as specif ied in §146.89(C); ...

(5) The type and grade and quantity of material to be used in plugging. The

material must be SUITABLE FOR USE with the carbon dioxide stream; and

120Rationale: Many of the components that woul d be tested by an internal MIT are removed or tested during the plugging process.

Individual Response: Regarding the suggested edit at 146.92(b)(2), EPA agrees that only an external MIT is required, and has modified th e GS rule at §146.92(a) to require owners or operators to perform a final external mechani cal integrity test prior to the well plugging.

Regarding the edit at 146.92(b)(5), EPA believes, considering the pot entially corrosive nature of

CO2 when it is in contact with water, that the re quirement that the material must be compatible with the CO2 stream is appropriate. Th e final rule retains this requirement.

Letter ID: 0200 Comment ID: 24715 Letter Lines: 2355 to 2366

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

Comment Code: 5100 2.8.1 Injection well plugging activ ities (seeking comment) (40 CFR 146.92)

Comment: Rule Provision: 146.92(d)

Anadarko Petroleum Corporation (APC) Comm ents: (d) Plugging report. Within 60 days after plugging the owner or operator must submit a pluggi ng report to the

Director. If the semi

- annual report is due less th an 15 days after completion of plugging, then the report must be submitted within 60 days afte r plugging. The report must be certified as accura te by the owner or operator and by the person who performed the plugging operati on (if other than the owner or operator.)

Rationale: The proposed changes are s uggested to simplify and clarify a provision that APC believes is needlessly complicated.

Individual Response: EPA has revised the text at §146.92(d) to reduce confusion. The final rule text reads, "Within 60 days afte r plugging the owner or operator must submit a plugging report to

the Director."

Letter ID: 0200 Comment ID: 24716 Letter Lines: 2368 to 2377

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities

Comment: Rule Provision: 146.93(a)(1)

Anadarko Petroleum Corporation (APC) Comm ents: (1) The owner or operator must submit the postinjection site care and site closure plan as a part of the permit

121application to be approved by the Director. SHALL CONTINUE TO CONDUCT

MONITORING AS SPECIFIED IN THE DI RECTOR-APPROVED POST-INJECTION SITE

CARE AND

SITE CLOSURE PLAN, PURSUANT TO THE PERFORMANCE BASED CRITERIA

DESCRIBED IN 146.93(3).

Rationale: Revisions here refl ect changes to §146.93(b)(3)

Individual Response: EPA disagrees with the suggested ch anges, and disagrees that the postinjection monitoring period should be strictly pe rformance-based. The Agency agrees that there

will be limited circumstances where it can be dem onstrated in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to USDWs. For this reason, the GS rule offers owners or op erators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, 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).

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in most cases. The default 50 year post-injection site care timeframe represents a reasonable and prot ective monitoring period based on a review of research studies, industry reports, and existing environmental programs, and evaluation of public

comments. EPA believes that a default post-injection site 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. The GS rule requires owners or operators to submit a post-injection site care and site closure plan as part of the permit application, as specified in §146.82(a), in order to outline how these activities will be performed and how non-enda ngerment of USDWs will be demonstrated throughout the post-injec tion site care period.

Letter ID: 0200 Comment ID: 24717 Letter Lines: 2379 to 2397

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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

Comment: Rule Provision: 146.93(a)(2)

122Anadarko Petroleum Corporation (APC) Comments: (2) The post

- injection site care and site closure plan must include the following information:

(i) The pressure differential betw een preinjection and predicted post

- injection pressures in the injection zone;

(ii) The predicted position of the carbon dioxide plume and associated pressure

front at site closure as de monstrated in the area of review evaluation required under § 146.84(b);

(iii) A description of post

- injection monitoring locati on, methods, and proposed frequency; and

(iv) A proposed schedule for submitting post

- injection site care monitoring

results to the Director.

Rationale: Revisions here refl ect changes to §146.93(b)(3)

Individual Response: Based on its evaluation of all public comments and input on the proposed rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and preamble for furthe r discussion on EPA's final approach.

Letter ID: 0200 Comment ID: 24718 Letter Lines: 2399 to 2406

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

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

Comment: Rule Provision: 146.93(a)(4)

Anadarko Petroleum Corporation (APC) Comm ents: (4) AT ANY TIME DURING THE POSTINJECTION SITE CARE PHASE, The owner or operator may modify and resubmit the post-injection site care and site closur e plan for the Director’s approval within 30 days of such change.

Rationale: Technical Clarification.

Individual Response: EPA agrees that a post-injection site care monitoring plan is an important tool for GS and anticipates that, in some cases , the appropriate post-injection monitoring strategy may end up being different than initially projected and there may be a need to amend the postinjection site care and site clos ure plan. EPA is requiring that upon the cessation of injection, the owner or operator submit an amended post-inje ction site care and si te closure plan or demonstrate to the Director that no changes to the original post-injection site care and site closure plan are necessary (146.93(a)(3)). EPA is not requiring formal periodic review and updates to the PISC and site cl osure plan throughout the injec tion phase. EPA does not expect

123that changes to this plan would be implemente d until injection operations cease. EPA envisions that owners or operators would take into accoun t similar considerations that guide updates to other project plans, e.g., monito ring and operational data and resu lts of AoR reevaluations. EPA adds that, if any monitoring or other site data indicate a need for amending the post-injection site care plan, the owner or operator is expected to amend the plan accordingly. EPA is issuing guidance with recommended approaches for deve lopment and updating of the GS project plans, including the post-injection site care and site closure plan. The guidance will be available on EPA's web site at http://water.epa.gov/t ype/groundwater/uic/we lls_sequestration.cfm.

EPA adds that, in the final rule, it has revise d the text at §146.93(a)(4) as follows: "At any time during the life of the geologic sequestration pr oject, the owner or ope rator may modify and resubmit the post-injection site car e and site closure plan for th e Director’s approval within 30 days of such change."

Letter ID: 0200 Comment ID: 24719 Letter Lines: 2408 to 2425

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities

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

Comment: Rule Provision: 146.93(b)(1)

Anadarko Petroleum Corporation (APC) Commen ts: (1) The owner or operator shall continue to conduct monitoring as speci fied in the Direct or-approved postinjection site care and site closure pl an, for at least 50 years following the cessation of injection. At the Director ’s discretion, the monitoring will continue until the geologic seque stration project no longer poses an endangerment to USDWs. PURSUANT TO THE PERFORMANCE BASED CRITERIA

DESCRIBED IN §146.93(B)(3).

Rationale: EPA should also reconsider its proposed 50- year default period for post-injection site care. EPA offers no ra tionale for this arbitrarily selected period of 50 years. Establishing a fixe d and unusually long time period may create a significant barrier for operators considering entry into CCS operations. Criteria for determining th e period for postinjection site care should be performance based and a function of the site specific characteristics of a project such as project size, geol ogic factors, and relative risk of the project. APC offers such criter ia in our edits to §146.93(b)(3).

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

excessive in most cases or arbi trary. EPA proposed a default post-in jection site car e timeframe of 50 years based on a review of research studies , industry reports, and existing environmental programs. This analysis was included in an EPA- prepared background document that is available in the federal docket, titled "Computationa l Modeling of Underground Injection of Carbon

124Dioxide for Determination of Area-of-Review a nd Potential Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes based on additional review of research studies and evaluation of public commen ts. While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the commenters provided suffi cient data or other evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe suggested by some of these commenters may be within the timeframe suggested in some studies, EPA believes that the potential risks of endange ring USDWs will likely no t decline within these timeframes and available data, including da ta submitted by commenters, do not support a

different default timeframe. However, EPA r ecognizes that alternative timeframes may be appropriate under limited, specific circumstances.

For this reason, the GS rule offers owners or op erators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, 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).

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.

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in al l but a limited number of cases. This default 50 year post-injection site care ti meframe represents a reasonable and protective monitoring period

based on a review of research studies, industr y reports, and existing environmental programs, and evaluation of public comments.

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: 0200 Comment ID: 24720 Letter Lines: 2427 to 2437

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities

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

Comment: Rule Provision: 146.93(b)(2)

125Anadarko Petroleum Corporation (APC) Commen ts: (2) If the owner or operator can request and demonstrate to the satisfac tion of the Director before 50 years, based on monitoring and other site

- specific data, that the geologic sequestration project no longer poses an e ndangerment to USDWs, the Director may

app rove an amendment to THAT the post-injection s ite care and site closure plan SHOULD BE REVISED to reduce the fr equency of monitoring. or may authorize

site closure before the end of the 50

- year period.

Rationale: (See above)

Individual Response: As described above, EPA disagrees that a post-injection site care timeframe of 50 years is excessive in most cases or arbitrary, and reta ins the default 50-year post-injection site care timeframe in the final rule.

Letter ID: 0200 Comment ID: 24721 Letter Lines: 2439 to 2467

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations

Comment: Rule Provision: 146.93(b)(3)

Anadarko Petroleum Corporation (APC) Comm ents: (3) Prior to authorization for site closure, the owner or operato r must submit to the Director a

demonstration , DEMONSTRATE TO THE DIRECT OR, based on monitoring, and other site-specific data, AND MODELING THAT IS REASONABLY CONSISTENT WITH SITE PERFORMANCE that the carbon dioxide plume and pressure front have stabilized

and that no additional monitoring is needed to assure that the geologic sequestration project does not pos e an endangerment to USDWs.

THE OWNER OR OPERATOR MUST DEMO NSTRATE, BASED ON THE CURRENT

UNDERSTANDING OF

THE SITE, INCLUDING MONITORING DATA AND/OR MODELING, ALL OF THE FOLLOWING: (I) THE ESTIMATED MAGNITUDE AND EXTENT OF THE PROJECT FOOTPRINT (CO2

PLUME AND THE AREA OF ELEVATED PRESSURE); ( II) THE ESTIMATED LOCATION OF THE

DETECTABLE CO2 PLUME ; (III) THAT THERE IS NO SIGNI FICANT LEAKAGE OF EITHER CO2 OR

DISPLACED

FORMATION FLUIDS THAT IS ENDANGERING USDWS; (IV) THAT THE INJECTED OR

DISPLACED

FLUIDS ARE NOT EXPECTED TO MIGRATE IN THE FUTURE IN A MANNER THAT

ENCOUNTERS A

POTENTIAL LEAKAGE PATHWAY INTO A US DW; (V) THAT THE INJECTION WELLS

AT THE SITE

COMPLETED INTO OR THRO UGH THE INJECTION ZONE OR CONFINING ZONE ARE

126PLUGGED AND

ABANDONED IN ACCORDANCE WITH THESE REQUIREMENTS; AND (VI) ANY

REMAINING PROJECT

MONITORING WELLS AT THE SITE ARE BEING MANAGED BY A PERSON AND IN A

MANNER

ACCEPTABLE TO THE DIRECTOR.

Rationale: APC edits establish the performance based criteria for selecting the monitoring period.

EPA should recognize that under any given se t of site specific conditions some of these criteria may not be fully satis fied. EPA should retain the ability to waive individual monitoring criteria descri bed here to reflect that situation.

Individual Response: EPA disagrees that the rule should specify the criteria for setting the monitoring timeframe. Instead, EPA believes that such determinations are site-specific and should be described in a project- specific post-injection site care and site cl osure plan. EPA also believes that periodic reviews and updates, wh ere necessary, to the plan are important to ensuring that the site continues to be managed effectively and to determine whether shortening the monitoring timeframe is appropri ate. The post-injection site care requirements in the final GS rule incorporate a combination of a fixed time frame and a performance standard approach. The final GS rule offer owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injection period based on si te-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Cl ass VI well owner or operator to demonstrate, during the permitting process based on substantial da ta, that an alternative PISC timeframe may be appropriate if it ensures non-endangermen t of USDWs pursuant to requirements at §146.93(c). 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. 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 monitoring wells, perform post-injection monitorin g, demonstrate the appropr iateness 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.

127Letter ID: 0200 Comment ID: 24722 Letter Lines: 2469 to 2476

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

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: Rule Provision: 146.93(b)(4)

Anadarko Petroleum Corporation (APC) Co mments: (4) If such a demonstration cannot be made (i.e., if the carbon dioxide plume and pressure front have not stabilized) after the 50

- year period, the owner or ope rator must submit to the Director a plan to continue post

- injection site care.

Rationale: No longer necessary given changes above.

Individual Response: As described above, EPA disagrees that a post-injection site care timeframe of 50 years is excessive in most cases or arbitrary, and reta ins the default 50-year post-injection site care timeframe in the final rule. .

Letter ID: 0200 Comment ID: 24723 Letter Lines: 2478 to 2496

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 4730 2.7.3 Reporting associated with closur e and post-injection site care

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93)

Comment: Rule Provision: 146.93(e)

Anadarko Petroleum Corporation (APC) Co mments: (e) Once the Director has authorized site closure, the owner or ope rator must submit a site closure report within 90 days that must thereafter be retained at a location designated by

the Director. AFTER COMPLETION OF ALL CLOSUR E OPERATIONS. The report must

include:

(1) Documentation of appropriate inj ection and monitoring well plugging as specified in §146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat mu st indicate the location of the injection well(S) relative to perm anently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA Regional Office;

Rationale: Once the site closure report is submitted to the Director, the operator cease to bear responsibility for any further record retention. At this point, EPA becomes the steward of information for the project.

Individual Response: EPA disagrees that the owner or opera tor should not be responsible for

128record retention such as site closure reports. EPA believes that the requirements that the owner or operator retain for ten years following site closure, records collected during the post-injection site care period at §146.93(f) and §146.93(h) are a ppropriate for the post-injection and site closure period to ensure that data are availabl e to support non-endangerment demonstrations and to address any concerns that may arise following site closure. This data will also support EPA's review of project data as part of the adaptive rulemaking approach.

Letter ID: 0200 Comment ID: 24724 Letter Lines: 2498 to 2517

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5800 2.13 Comments on emergency and re medial response (40 CFR 146.94)

Comment: Rule Provision: 146.94(b)

Anadarko Petroleum Corporation (APC) Comm ents: (b) If the ow ner or operator obtains evidence that the injected carbon dioxide stream, DISPLACED FORMATION

FLUIDS OR and associated pressure front may cause an endangerment to ENDANGERS a USDW, the owner or operator must:

(1) Immediately cease injection IN A PR UDENT MANNER CONSIDERING

CIRCUMSTANCES.

(2) Take all steps reasonably necessa ry to identify and characterize THE

ENDANGERMENT POSED;

(3) Notify the Director or the designa ted representative within 24 hours OF

BECOMING AWARE OF TH E ENDANGERMENT; and

Rationale: Technical clarifications.

There is a slight change that immediat ely ceasing injection could have adverse impacts on other aspects of the operation.

Individual Response: After consideration of comments, EPA has finalized the rule language in §146.94(b) as proposed. In the introductory section of §146.94(b), EPA clarifie s that the pressure front, as defined in §146.81, is a zone where the pr essure differential is sufficient to cause the movement of injected fluids or formation flui ds into a USDW. Therefor e, displaced formation fluids are implicitly included in the requirements for §146.94. EPA al so clarifies that owners or operators must take action when the CO2 stream or pressure front may cause endangerment. In order to prevent the endangerment of USDW s, as required under §1421 of the SDWA, EPA expects the owner or operator to act preemptiv ely and not wait until endangerment has occurred. This language is consistent w ith existing UIC requirements fo r other well classes and EPA’s authority under the SDWA.

EPA clarifies that the Agency e xpects that owners or operators should take care not to damage the well when ceasing injection under §146.94(b)(1). At §146.94(b)(2), EPA is maintaining the

129requirement to “characterize the release.” In or der to prevent the enda ngerment of USDWs, as required under §1421 of the SDWA, EPA expects th e owner or operator to act preemptively and not wait until endangerment has occurred. This language is co nsistent with existing UIC requirements for other well classes and EPA’s authority under the SDWA.

In response to commenters’ suggestions regard ing §146.94(b)(3), EPA clarifies that the 24 hours begins when the owner or operator obtains evid ence of possible endangerment. EPA believes the rule language is clear on this requirement.

Letter ID: 0200 Comment ID: 24725 Letter Lines: 2519 to 2526

Comment Code: 1240 1.1.1.3 Suggested changes/ed its to rule language

Comment Code: 5800 2.13 Comments on emergency and re medial response (40 CFR 146.94)

Comment: Rule Provision: 146.94(d)

Anadarko Petroleum Corporation (APC) Commen ts: (d) The owner or operator must notify the Director prior to conducting a ny well workover IN RESPONSE TO ANY

CASE OF ENDANGERMENT.

Rationale: In critical situations, time sp ent obtaining approval could adversely affect the ability to conduct operations or increase the level of endangerment.

Individual Response: Since proposal, EPA has modified the final regulatory language at §146.94(d) to clarify what constitutes a workover to address a well failure (which invokes remedial actions) and what constitutes a mainte nance-type workover. For maintenance-type workovers (i.e., those that are scheduled in adva nce), the owner or operato r must notify and gain approval from the Director prior to beginning the workover. In th e final GS regulation, EPA has moved this requirement to the reporting requi rements at §146.91(d) to clarify its intent.

Regarding concerns that notifica tion could delay responses, EPA clarifies that the GS rule (at §146.94(b)) describes procedures owners or opera tors must take in emergency situations. Specifically, upon determining that there is a problem with the we ll that may endanger a USDW, the owner or operator must firs t cease injection, then take all steps reasonably necessary to identify and characterize any release, notif y the Director, and implement the approved emergency and remedial response plan, which ma y include a well workover. EPA believes that ceasing injection (which the ow ner or operator would do immediately and before notifying the Director) is the immediate action necessary to pr event or mitigate endangerment of USDWs, as required under the SDWA.

Letter ID: 0200 Comment ID: 24967 Letter Lines: 625 to 634

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment)

130Comment: Rule Provisions: 146.89(c), 146.90(e)

EPA Rule Issue: 29. EPA seeks comment on th e appropriate freque ncy of internal and external MITs for GS injection wells, the appropriate types of MITs, and how to optimize MIT methods for GS. EPA Notice 43514.

Anadarko Petroleum Corporation (APC) Re sponse: Timing for conducting MITs, should be based on risk and performance factors. Industry ex perience with CO2 EOR Class II program requires MITs every 5 years. This frequency has proven protective of USDWs. Given the similariti es between CO2 EOR wells and GS wells, APC recommends 5-year frequency in this case as well. The MIT should test

Individual Response: EPA disagrees that a five-year extern al MIT is appropriate. The final GS regulation retains the requirement that owners or operators of Class VI wells must demonstrate injection well external mechan ical integrity at least once annually under §146.89(c). While EPA acknowledges the successful history of the Class II injection program, the Agency believes that CO2 injection for GS is substantially different fr om Class II ER operations in that: 1) the purpose of CO2 injection for GS is permanent storage, whereas for ER operations injected CO2 is often recovered (pumped from the sub- surface) relatively soon after inje ction, 2) typically there is minimal formation pressure build-up during ER operations because withdrawals from oil recovery wells reduce reservoir pressure, which is not the case in GS reservoirs, and 3) the volumes of CO2 anticipated for in jection for GS are significantly larger than the volumes of CO2 injected for ER operations. These conditions illustrate that frequent internal MITs for Class VI wells are critically important in ensuring that USDWs are protected. EPA believes that continuous pressure monitoring to demonstrate inte rnal mechanical integrity of GS wells, instead of periodic testing, which is requir ed for most other types of deep injection wells, is important.

In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT

failure and, for this reason, EPA be lieves that the tailored MIT requi rements in the final GS rule are appropriate.

Because of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial approach in the early stages of deployment for GS. EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT data, to determine wh ether the appropriate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0200 Comment ID: 24968 Letter Lines: 634 to 640

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment)

131Comment: APC recommends 5-year frequency in this case as well. The MIT should test integrity of the long string casing, pa cker, and tubing and to the extent practicable, should test th e integrity of the cement isolating the injection zone. There are many methods for conducti ng MITs. EPA should allow operators adequate flexibility in selecting the a ppropriate methods fo r their specific situation. API RP90 provides good examples of methods for detecting mechanical failures, managing those ri sks, and conducting MITs.

Individual Response: EPA disagrees that a five-year extern al MIT is appropriate. The final GS regulation retains the requirement that owners or operators of Class VI wells must demonstrate injection well external mech anical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the protecti on of USDWs from endangerment given the unique nature of CO2 GS relative to other injection operations, including the pote ntial corrosive impact of CO2 in the presence of water and impurities on well materials, the potential geomechanical impacts to well integrity due to CO2 phase ch anges, the temperature and pressure effects associated with injecting superc ritical CO2, and the buoyant nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more cons ervative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT

failure and, for this reason, EPA be lieves that the tailored MIT requi rements in the final GS rule are appropriate.

EPA also believes that the MITs described in the rule at §146.89 are effective methods and have been used successfully by injection well operato rs for decades and provide an important early warning of potential problems in the injection we ll system. EPA agrees with the commenter that flexibility to choose appropriate MITs is important, and the GS rule affords this flexibility by requiring the owner or operator to prepare and gain approval for a proj ect-specific testing and monitoring plan that includes MITs under §146.90. EPA clarifies that the regulations provides the Director discretion to require additional methods or, with the Administrator's approval, to approve the use of alte rnative MIT methods based on specific information about the site or the well. See §146.89(e).

In addition, EPA is using an adaptive approach to regulating GS. The Ag ency plans to collect and review data every six years on GS projects to determine whether the appropriate amount and types of information and appropriate documenta tion are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Letter ID: 0200 Comment ID: 29318 Letter Lines: 408 to 427

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment)

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

132Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment)

Comment: Rule Provisions: 146.86(b) EPA Rule Issue: 16. EPA seeks comment on the proposed GS well requirements for depth of surface casing, the cementing of long-string casing, and construction with a packer set opposite a cemented interval. EPA Notice 43509.

Anadarko Petroleum Corporation (APC) Res ponse: Generally the surface casing is

set below the lower USDW but it should be recognized that this is not appropriate in all geologic settings. In some areas USDWs can extend much greater depths than would be appropr iate for setting of surface casing. Regulations should recognize these situations and allo w for other methods of protecting USDWs

APC opposes the requirement for cementing the long string casing back to surface. Cementing requirements should focu s on ensuring competent isolation and seal across the confining zone(s). Sea ling the annulus between the long string and surface casing could limit an operators ability to monitor for leakage or conduct remedial operations.

Regarding packer setting depth, the dire ctor should retain discretion for allowing variation from this requirement.

Individual Response: Section 146.86(b)(3) requires that th e long-string casing extend to the injection zone and be cemented by circulating ce ment to the surface in one or more stages. It does not, however, specify how cementing would be accomplished, and gives flexibility to the owner or operator to propose alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are pr otected from endangerment, s ubject to the approval of the

Director. EPA does not believe that the cem enting requirements at §146.86 would prevent monitoring, operation, and remediation of GS we lls. EPA notes that there are many potential ways to meet the requirement in deep wells, such as the use of staged cementing. See the

discussion of Class VI well constr uction requirements in the preamble to the final GS rule for additional information. Additionally, EPA is de veloping guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

EPA adds that cementing of deep wells has been performed successfully in the past, for example, by owners or operators of Class I hazardous and Cl ass I municipal waste disposal wells. Some of

these wells, which must meet the same cemen ting requirements for long-string casing as Class VI wells, are up to 12,000 feet deep (EPA, 2001) and have been successfully cemented in a manner that maintains integrity and allows for all required well testing, operation, and

remediation. EPA also received comments from stakeholders representing states, a water association, and industry supporting this provision, saying that it pr ovides, at a reasonable cost, corrosion protection of the casing; prevents undesi rable migration of fluids behind the casing; provides support to the casing; and provides multiple barriers against endangerm ent of USDWs.

133134 EPA recognizes concerns regardi ng construction of Class VI wells where the lowermost USDW is very deep. To further address comments on d eep injection wells, the final GS rule at §146.95 includes requirements for owners or operators that seek a waiver of the injection depth requirements. Owners or operators of wells opera ting under injection depth waivers must comply with additional construction require ments to ensure that wells used to inject above or between USDWs are protective. See the discussion of the wa iver approach in the preamble to the final GS

rule for additional information.

EPA clarifies that the rule allows discretion in some areas when UIC Directors evaluate and approve the owners or operators proposed well construction plan. Th e Director will evaluate the appropriateness of the proposed construction based on site-specific information about the injection project. EPA believes th at the use of tubing and packer in accordance with §146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance will be available on EPA’s website at http://water.epa.gov/type /groundwater/uic/wells _sequestration.cfm.