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.EPA-HQ-OW-2008-0390-0122 Document ID: EPA-HQ-OW-2008-0390-0122 Last Name: Savage First Name: Leslie Title: Organization: Railroad Commission of Texas (RRC) City: State: Zip Code: Phone Number: Fax Number: Country Code: Email Address: Current Category Code:

Comment: November 12, 2008

Water Docket, Environmental Protection Agency 1200 Pennsylvania Ave., NW Mailcode: 2822T Washington, DC 20460

Re: Docket ID No. EPA-HQ-OW-2008-0390 Comments From the Railroad Commission of
Texas

The Railroad Commission of Texas (RRC) appreciates the opportunity to comment on the referenced docket, related to the United States Environmental Protection Agency’s (EPA) proposal for Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells (the Proposal). The RRC appreciates the extensive preparatory work performed by EPA as well as other federal entities, including the United States Department of Energy (DOE). We share the EPA’s belief that CO2 sequestration has the potential to improve air quality. We further believe that the best way to promote economical geosequestration of CO2 initially is to link captured CO2 with oil reserves, producing increased petroleum recovery efficiencies.

Texas is a leader in enhanced oil recovery using CO2. Texas possesses an extensive oil and gas pipeline infrastructure capable of transporting CO2 to various sequestration sites. The first CO2 flood occurred in 1972 in West Texas. In 2005, over 160,000 barrels of oil per day were produced with CO2 EOR in Texas. The RRC has permitted over 11,200 CO2 injection wells, with over 5,400 of those being currently active. The 50 active CO2 enhanced oil recovery projects in West Texas represent about 50 percent of total CO2 flooding activity worldwide. CO2-driven EOR has grown steadily since 1985 and now accounts for over 15 percent of the average yearly oil production in Texas. The oil industry has experienced a supply shortage of CO2 over the past few years. Finding new sources of CO2 will alleviate that shortfall and result in an increase in oil production. The current shortage is about 0.5 billion cubic feet per day, with industry consuming the available 1.5 billion cubic feet per day. Increased availability of anthropogenic CO2 could accelerate this production. In April of 2004, the University of Texas Bureau of Economic Geology identified at least 31 billion barrels of oil in Texas that are recoverable using CO2-driven EOR.

The RRC has primacy over Class II wells and Class III brine mining wells in Texas. Texas has been regulating injection wells since the 1930s. With nearly a century of institutional experience regulating activities related to the integrity of underground geologic zones, and decades of regulating CO2 injection for EOR, the RRC respectfully offers the following comments in two main parts: (1) general comments and recommendations related to the key areas of concern; and (2) comments and recommendations on specific rule provisions (attached).

GENERAL COMMENTS

The Proposal fails to promote and encourage geosequestration of CO2. EPA’s stated goals for this proposal are to protect Underground Sources of Drinking Page 1EPA-HQ-OW-2008-0390-0122 Water (USDWs) while promoting carbon capture and storage. As the proposal stands, the regulations would succeed in protecting USDWs, but would fail to successfully promote carbon capture and storage in any significant way. Therefore, under the current regulatory scenario, CO2 will continue to be released to the atmosphere in greater amounts than would ever leak from a properly sited, constructed, and operated CO2 storage facility. One reason for the failure is that the proposal overestimates the risk of CO2 sequestration and, as a result, creates an overestimated implied liability. Another reason is that the Proposal taints the technology by implying that CO2 is a waste. Finally, the proposal includes insufficient flexibility to account for the geographic variability of potential sites across the country. In summary, the RRC is concerned that the Proposal overestimates the risks of CO2 geologic sequestration, and creating barriers to rapid implementation of the technology rather than encouraging or providing incentives to mobilize large-scale projects.

The Proposal treats CO2 as a waste. The EPA states in the preamble that it has not classified CO2 as a waste or a commodity. However, by using the Class I waste injection well requirements as the framework for the Class VI requirements, the Proposal implies that the CO2 stream is a waste. This implication increases not only the potential liability for carbon dioxide sequestration, but also the potential liability for anthropogenic CO2 injection for the purpose of enhanced recovery of oil and/or natural gas.

Many provisions of the Proposal address Class VI wells from a waste based perspective. With respect to construction, area of review (AoR) and monitoring, the Proposal begins with the regulatory framework for Class I non-hazardous industrial waste injection well requirements and then adds numerous layers of requirements to prevent or detect the escape of CO2 from the injection zone.

The Proposal excludes CO2 that is a hazardous waste from regulation under the Class VI program, but has proposed requirements for Class VI injection wells that are more stringent than those for wells used for the injection of hazardous waste. RRC strongly disagrees that CO2 buoyancy, corrosivity, and high injection volumes for a Class VI project justify a Class I approach.

The Proposal overestimates the risks of CO2 injection and sequestration. As noted in the preamble, naturally occurring CO2 has been trapped in subsurface formations for eons. Texas and numerous other states have over 35 years of experience in injection of large amounts of CO2 into geologic formations to enhanced oil recovery. Over 35 million tons of CO2 are injected annually in more than 70 projects in the United States.

In most cases, with appropriate site selection, construction, monitoring, and testing, the risks of CO2 geologic sequestration would be comparable to the risks of current activities such as natural gas storage, EOR and deep underground disposal of acid gas. In those instances any regulations for Class VI wells should reflect more closely UIC Class II standards instead of the more stringent Class I well standards.

Both the Class VI and the Class II programs have the same goals - protection of USDWs. Yet, EPA’s proposal implies that when the purpose of the injection switches from enhanced recovery to sequestration, the risks to USDWs are significantly magnified. The RRC does not agree that the volume and duration of CO2 injection and placement are sufficiently different in measurable effect on the underground to justify the extra layers of requirements.

However, rather than beginning its CO2 geologic sequestration framework with the Class II well program, EPA begins with the framework of Class I non-hazardous industrial waste injection well requirements and adds then numerous layers of overly redundant requirements to prevent or detect the escape of CO2 from the injection zone. The implication seems to be that EPA believes that the Class II program is not sufficiently stringent. This implication is a major concern for Page 2EPA-HQ-OW-2008-0390-0122 the RRC.

In addition, the heightened stringency in the proposed requirements for Class VI injection wells suggests that geological sequestration of CO2 is as much or more dangerous than underground injection of other substances. The Proposal includes numerous examples of this heightened stringency:

- The implied recommendation that a geologic sequestration project have more than one confining zone is much more stringent than the requirements for Class I hazardous waste injection wells.

- The requirement that the long-string casing be cemented to the surface is equally as stringent as the Class I hazardous waste well requirements. - Annulus liquid level indicator and a down-hole shut-off valve are not required for a Class I hazardous waste injection well.

- The requirement for annual external mechanical integrity testing for Class VI wells, such testing is only required once every five years for a Class I hazardous waste well.

- The Proposal’s default 50-year post-injection monitoring period, while groundwater monitoring for a Class I hazardous waste injection well is required only until the injection zone pressure is such that USDWs cannot be impacted.

In nearly every instance where EPA indicates that additional safe-guards are necessary, it cites as the reason the chemical characteristics of the CO2 stream to be injected and the interaction of the CO2 stream with formation waters and strata, the buoyant nature of CO2, and the pressure increases caused by injection of very large volumes of CO2. However, buoyancy and chemical characteristics of CO2 have been successfully addressed in enhanced recovery injection projects using CO2 under the Class II UIC program. Pressure increases can be handled by selecting formations that have been depleted and have reduced pressures. In those formations for which the pressure has not been reduced as a result of production or other activity, the issue of the pressure increase resulting from injection of large amounts of CO2 can be addressed by limiting the surface injection pressure and adequate monitoring.

The Proposal does not include sufficient flexibility. Congress mandated, through Section 1421(b)(3)(A) of the SDWA, that UIC regulations developed by EPA permit or provide consideration of varying geologic, hydrological, or historical conditions in different States and in different areas within a State. Thus, Congress cautioned EPA against a ‘one-size-fits-all’ regulatory scheme, and mandated consideration of local conditions and practices. However, the Proposal does not allow State directors to use their expertise and knowledge to account for these varying conditions.

EPA states in the preamble that its reason for selecting Alternative #3 is because it ‘provides flexibility while creating a framework of minimum requirements to ensure consistency across the nation.’ However, by selecting Alternative #3, EPA selected as a starting point the requirements for Class I industrial non-hazardous wells. Because of this, the flexibility is restrained at the very outset.

Using as the reason the unknowns and the unique characteristics of CO2 geosequestration (buoyancy, corrosivity, high injection volumes, etc.), the Proposal seems to include the entire slate of possible technologies available to complete, operate, monitor and close a UIC well and the injection/confining formations. In a few areas, the Proposal provides the Director with discretion to set certain application, permit, and monitoring criteria that are appropriate to local geologic settings. However, because EPA began with an unnecessarily stringent Class I framework, and added numerous other nondiscretionary requirements, the flexibility is insufficient. The result is that the Proposal is unnecessarily prescriptive and costly. Page 3EPA-HQ-OW-2008-0390-0122

The proposal does not seem to consider CO2 to be sequestered during injection for EOR. The first economic CO2 sequestration projects will be associated with oil and gas operations, yet the Proposal states that sequestration (and thus, Class VI injection) begins only after enhanced recovery of oil or gas has stopped. The implication is that the CO2 injected for enhanced recovery is not ultimately sequestered upon cessation of injection and production activity. The proposal grandfathers the construction of wells permitted as Class V and Class II, but requires that the wells comply with all other requirements of Class VI wells before injecting CO2 for sequestration.

Delegation of Primacy Congress mandated, through Section 1421(b)(3)(B)(i) of the Safe Drinking Water Act (SDWA), that, to the extent feasible, EPA avoid promulgating requirements that would unnecessarily disrupt State UIC programs already in effect and being enforced in a substantial number of States.

The EPA has indicated that it will delegate the program under Section 1422 of the SDWA. The RRC agrees with EPA that it is in the best interest of protecting groundwater resources for the geologic sequestration of CO2 to be regulated at the state level. However, any requirement by EPA that states accept primacy for Class I, III and V wells as a condition for obtaining primacy for Class VI wells will create an unreasonable burden upon states. This matter needs to be clarified in the rule. In addition, any requirement by EPA that states with primacy for Class I, III, and V wells also accept primacy for Class VI wells will unnecessarily disrupt the states’ existing UIC programs and will compromise the states’ ability to decide how best to administer the state’s program. In addition, EPA should allow for split delegation in the Class VI program, as it has in Texas for the Class III program, to allow the state to best determine how to implement the Class VI program. Furthermore, EPA should not be allowed to reopen any state’s primacy over other well classes in order for a state to obtain primacy for the Class VI well program.

RECOMMENDATIONS

1. EPA should consider creating a subclass within the Class II well classification for operators who wish to sequester CO2 in association with enhanced recovery of oil or natural gas (with appropriate and necessary additional requirements to address any CO2 issues) and allow the Class VI injection well program to govern those injection wells used to sequester CO2 in formations that are non-productive.

2. EPA should begin with a reasonable framework (Class II injection wells); assure that the rules are flexible enough to consider site-specific characteristics and knowledge gained from CO2 history and the ongoing demonstration and pilot projects; and that include performance-based requirements. Because of Texas’ and other States’ long experience with injection operations, the States are in an excellent position to perceive and act upon similarities in fluids injected, construction depth, design, operating techniques and purposes between its Class II and potential Class VI wells.

3. EPA should provide more flexibility in the siting requirements: a. acknowledge that some sites offer very good protection when compared to others and ease regulatory burden on those sites; b. promote transfer of EOR to storage; c. delete the requirement that the confining zone be free of all transmissive faults or fractures; d. delete references to multiple confining zones; and e. revise the Proposal to allow for site-specific characteristics and performance- based determinations.

4. EPA should provide more flexibiilty in construction, for example, delete the requirement that the long string casing be cemented to the surface.

5. EPA should provide more flexibiilty in operation. For example, allow an EOR operator to demonstrate that CO2 is sequestered, and instead of a 10-year Page 4EPA-HQ-OW-2008-0390-0122 default period for reevaluation of the area of review, allow the timing for suchreevaluation to be determined based on site-specific characteristics and sitespecific monitoring of the CO2 plume and pressure front.

6. EPA should provide more flexibility in the requirements for monitoring, testing and reporting. For example,

a. revisit the requirement for an need annulus liquid level indicator;

b. delete the requierment for the down hole shut off valve;

b. allow the Director to determine the frequency of mechnical integrity tests, with a minimum of 5 years;

c. delete references to air and soil gas monitoring, since such monitoring is a case of too little too late - and can result in false positives due to ambient variability; and

d. delete references to tracers, because of the numerous problems discussed in the preamble.

7. EPA should provide for performance-based requirements for Closure and Post Closure Care. For example, the appropriate length of time for post-injection site care should be determined by specific conditions and characteristics of the site, and monitoring of the pressure to determine the point at which the injection zone pressure is such that USDWs cannot be impacted.

The RRC appreciates the opportunity and is available to answer questions at any time. If you have any questions, please contact staff members David Cooney at david.cooney@rrc.state.tx.us or (512)463-6977, or Leslie Savage at leslie.savage@rrc.state.tx or (512)463-7308.

SPECIFIC RULE PROVISIONS

[SEE EPA-HQ-OW-2008-0390-0122.PDF FOR A FORMATTED VERSION OF THE COMMENTS BELOW.]

[Note: Additions to rule language are shown in upper case text. Stricken text is shown in << >>. RRC comments are shown in { }.]

Proposed Subpart A - General Provisions

§144.6 Classification of wells.

{The proposal includes in the definition of "Class VI" the restriction that injection into such wells must be "beneath the lowermost formation containing a USDW." RRC suggests either removing the restriction or adding "or another formation, if the Director determines that injection into the other formation will be protective of USDWs." }

Proposed Subpart D - Authorization by Permit

§144.36 Duration of permits.

{We agree with the proposal to issue permits for UIC wells associated with sequestration of CO2 "for the period up to the operating life of the facility." The substantial financial investment in a project makes a permit for the operating like of the facility imperitive. }

Part 146 UIC Program Criteria and Standards

Page 5EPA-HQ-OW-2008-0390-0122 §146.5 Classification of injection wells. (f) Class VI.

{The proposal includes in the definition of "Class VI" the restriction that injection into such wells must be "beneath the lowermost formation containing a USDW."}

Subpart H--Criteria and Standards Applicable to Class VI Wells

§146.81 Applicability.

(a) This subpart establishes criteria and standards for UIC programs to regulate Class VI CO2 GS injection wells. (b) This subpart applies to wells used to inject CO2 specifically for the purpose of GS, i.e., the long-term containment of a gaseous, liquid or supercritical CO2 stream in subsurface geologicformations. (c) This subpart applies to owners and operators of permit or ruleauthorized Class I industrial, Class II, or Class V experimental CO2 injection projects who seek to apply for a Class 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 discretion, from the casing and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3).

{RRC agrees that the Director evaluating a permit application to use existing injection wells for geologic sequestration should have the discretion to exempt wells from Class I industrial, Class II or Class V wells from the proposed casing and cementing requirements of Class VI wells. }

(d) Definitions. The following definitions apply to this subpart. To the extent that these definitions conflict with those in §146.3 these definitions govern:

Area of review means the region surrounding the GS project that may be impacted by the injection activity. The AOR is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected CO2 stream.

Carbon dioxide plume means the underground extent, in 3-D, of an injected CO2 stream.

Carbon dioxide stream means CO2 that has been captured from an emission source (e.g., a power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This subpart does not apply to any CO2 stream that meets the definition of a hazardous waste under 40 CFR part 261.

Confining zone means a geologic formation, group of formations, or part of a formation stratigraphically overlying the injection zone that acts as a barrier to fluid movement.

Corrective action means the use of Director approved methods to assure that wells within the AOR do not serve as conduits for the movement of fluids into USDWs.

Geologic sequestration means the long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply to its capture or transport.

Geologic sequestration project means an injection well or wells used to emplace a CO2 stream beneath the lowermost formation containing a USDW, OR ANOTHER FORMATION, IF THE DIRECTOR DETERMINES THAT INJECTION INTO THE OTHER FORMATION WILL NOT ENDANGER USDWS. It includes the subsurface 3-D extent of the carbon dioxide plume, associated pressure front, and displaced brine, as well as the surface area above that delineated region.

Page 6EPA-HQ-OW-2008-0390-0122 {RRC suggests adding to the end of the first sentence of the definition of Geologic sequestration project, "or another formation, if the Director determines that injection into the other formation will not endanger USDWs." }

Injection zone means a geologic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive CO2 through a well or wells associated with a GS project.

Post-injection site care means appropriate monitoring and other actions (including corrective action) needed following cessation of injection to assure that USDWs are not endangered as required under §146.93.

Pressure front means the zone of elevated pressure that is created by the injection of carbon dioxide into the subsurface. For 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.

{Why does this definition need to be different?}

Site closure the point/time, as determined by the Director following the requirements under §146.93, at which the owner or operator of a GS site is released from post-injection site care responsibilities.

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between formations.

{Recommend that the fault or fracture be "known."}

§146.82 Required Class VI permit information.

This section sets forth the information which the owner or operator must submit to the Director in order to be permitted as a Class VI well. The application for a permit for construction and operation of a Class VI well must include the following:

(a) Information required in 40 CFR 144.31(e)(1) - (6);

(b) A map showing the injection well(s) for which a permit is sought and the applicable AOR. Within the AOR, the map must show the number, or name and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structures intended for human occupancy and roads. The map should also show faults, if known or suspected. Only information of public record is required to be included on this map;

(c) The AOR based on modeling, using data obtained during logging and testing of the well and the formation as required by paragraphs (l), (r), and (s) of this section;

(d) Information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, including:

(1) Maps and cross sections of the area of review; (2) Location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone<<(s)>> in the area of review and a determination that they would not interfere with containment; (3) Information on seismic history including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment; Page 7EPA-HQ-OW-2008-0390-0122 (4) Data on the depth, areal extent, thickness, mineralogy, porosity, permeability and capillary pressure of the injection and confining zone<<(s)>>; including geology/facies changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions; (5) Geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone; and (6) Geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the local area.

(e) A tabulation of all wells within the AOR which penetrate the injection or confining zone<<(s)>>. Such data must include a description of each well's type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require;

{Definition of confining zone includes multiple formations. Do not imply that multiple confining zones are preferable to one (good) confining zone.}

(f) Maps and stratigraphic cross sections indicating the general vertical and lateral limits of all USDWs, water wells and springs within the area of review, their positions relative to the injection zone<<(s)>> and the direction of water movement, where known;

{Consistency with definition and use of term in other areas of the rules.}

(g) Baseline geochemical data on subsurface formations, including all USDWs in the AOR;

(h) Proposed operating data:

(1) Average and maximum daily rate and volume of the CO2 stream; (2) Average and maximum injection pressure; (3) The source of the CO2 stream; and (4) An analysis of the chemical and physical characteristics of the CO2 stream;

(i) The compatibility of the CO2 stream with fluids in the injection zone and minerals in both the injection and the confining zone<<(s)>>, based on the results of the formation testing program, and with the materials used to construct the well;

{See comment above.}

(j) Proposed formation testing program to obtain an analysis of the chemical and physical characteristics of the injection zone and confining zone; (k) Proposed stimulation program and a determination that stimulation will not interfere with containment; (l) The results of the formation testing program as required in paragraph (j) of this section; (m) Proposed procedure to outline steps necessary to conduct injection operation;

{"Proposed procedure to outline steps" does not make sense. Recommend "Outline of steps ...."}

(n) Schematic or other appropriate drawings of the surface and subsurface construction details of the well; (o) Injection well construction procedures that meet the requirements of §146.86; (p) Proposed AOR and corrective action plan that meets the requirements under §146.84; (q) The status of corrective action on wells in the AOR; (r) All available logging and testing program data on the well required by Page 8EPA-HQ-OW-2008-0390-0122 §146.87; (s) A demonstration of mechanical integrity pursuant to §146.89; (t) A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under §146.85; (u) Proposed testing and monitoring plan required by §146.90; (v) Proposed injection well plugging plan required by §146.92(b); (w) Proposed post-injection site care and site closure plan required by §146.93(a); (x) Proposed emergency and remedial response plan required by §146.94; and (y) Any other information requested by the Director.

§146.83 Minimum criteria for siting.

(a) Owners and operators of Class VI wells must demonstrate to the satisfaction of the Director that the wells will be sited in areas with a suitable geologic system. The geologic system must be comprised of:

(1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the carbon dioxide stream;

{Redundant - simply repeats the definition of "injection zone." Either take this language out of the definition or take it out of here.}

(2) A confining zone<<(s)>> that is free of transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected carbon dioxide stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone<<(s)>>; and

{Redundant. Repeats definition of "confining zone." Also, implies that the confining zone cannot have a single fracture, no matter how small. Much more stringent than for Class I hazardous wells.}

<<(b) At the Director's discretion, owners or operators of Class VI wells must identify and characterize additional zones that will impede vertical fluid movement, are free of faults and fractures that may interfere with containment, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation and remediation.>>

{Redundant and unnecessary. Language in definition of "confining zone."}

§146.84 Area of review and corrective action.

(a) The area of review is the region surrounding the geologic sequestration project 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 all phases of the injected carbon dioxide stream.

{Redundant - same as the definition of "area of review."}

(b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the AOR for a proposed geologic sequestration project, <<periodically>> reevaluate the delineation, and perform corrective action that meets the requirements of this section AT A FREQUENCY AND IN A MANNER THAT <<and>> is acceptable to the Director. As a part of the permit application<< for approval by the Director>>, the owner or operator must submit an area of review and corrective action plan that includes the following information:

(1) The method for delineating the area of review that meets the requirements of paragraph (c) of this section, including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based; Page 9EPA-HQ-OW-2008-0390-0122

(2) A description of: (i) <<The minimum fixed frequency, not to exceed 10 years, the owner or operator proposes to reevaluate the area of review; (ii) >>The monitoring and operational conditions that would warrant a reevaluation of the area of review <<prior to the next scheduled reevaluation as determined by the minimum fixed frequency established in paragraph (b)(2)(i) of this section.>>

{Suggest that there be no minimum fixed frequency for reevaluation of the AoR, but that such review be based on site-specific circumstances. }

(II)<<(iii)>> How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; and

(iv) 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 injection 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 THE site WILL BE accessed <<will be guaranteed >>for future corrective action.

{Word Choice. Secure rather than guarantee. }

(c) Owners or operators of Class VI wells must perform the following actions to delineate the area of review, identify all wells that require corrective action, and perform corrective action on those wells:

(1) Predict, using 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, pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or FOR <<after>> a fixed time period as determined by the Director. The modelINGmust:

(i) Be based on detailed geologic data collected to characterize the injection zone AND<<,>> confining zone<< and any additional zones>>; and anticipated operating data, including injection pressures, rates and total volumes over the proposed life of the geologic sequestration project; (ii) Take into account RELEVANT <<any>> geologic heterogeneities AND<<,>> data quality, and their possible impact on model predictions; and (iii) Consider potential migration through KNOWN faults, fractures, and artificial penetrations.

(2) Using methods approved by the Director, identify all KNOWN ARTIFICIAL penetrations THROUGH THE CONFINING ZONE, including active and abandoned 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 drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require; and

(3) Determine which abandoned wells in the AOR have been plugged in a manner that prevents the movement of CO2 or FORMATION <<associated>> fluids that may endanger USDWs.

(d) Owners or operators of Class VI wells must perform corrective action USING CORROSION RESISTANT MATERIAL, WHEN APPROPRIATE, on all wells IDENTIFIED IN §146.84(C)(2) <<in the AOR that are determined to need corrective action using methods necessary to prevent the movement of fluid into or between USDWs including use of corrosion resistant materials, where appropriate.>>

(e) If monitoring data indicate an endangerment to USDWs, the owner or operator must notify the Director and cease operations as required by §146.94.

Page 10EPA-HQ-OW-2008-0390-0122 (f) <<At the minimum fixed frequency, not to exceed 10 years, as>> AS specified in the AOR and corrective action plan, or when monitoring and operational conditions warrant, the owner or operator must:

(1) Reevaluate the AOR in the same manner specified in paragraph (c)(1) of this section; (2) Identify all wells in the reevaluated AOR that require corrective action in the same manner specified in paragraph (c)(2) of this section; (3) Perform corrective action on wells requiring corrective action in the reevaluated AOR in the same manner specified in paragraph (c)(3) of this section; and (4) Submit an amended AOR and corrective action plan or demonstrate to the Director through monitoring data and modeling results that no CHANGE <<amendment >>to the AOR and corrective action plan is needed.

{Appropriate frequency of determining AoR might not be "fixed." Owner or operator might need to reevaluate AoR frequently at first, particularly with deep brine formations about which there is little history, and then at expanding intervals as more information is known.}

(g) The emergency and remedial response plan (as required by §146.94) and a demonstration of financial responsibility (as described by §146.85) must account for the entire AOR, regardless of whether or not corrective action in the area of review is phased.

§146.85 Financial responsibility. (a) The owner or operator must demonstrate and maintain financial responsibility and resources for corrective action (that meets the requirements of §146.84), injection well plugging (that meets the requirements of §146.92), post-injection site care and site closure (that meets the requirements of §146.93), and emergency and remedial response (that meets the requirements of §146.94) in a manner prescribed by the Director until:

(1) The Director receives and approves the completed post-injection site care and site closure plan; and(2) The Director determines that the site has reached the end of the postinjection site care period.

(b) The owner or operator must provide to the Director, at a frequency determined by the Director, written updates of adjustments to the cost estimate to account for any amendments to the AOR and corrective action plan (§146.84), the injection well plugging plan (§146.92), and the post-injection site care and site closure plan (§146.93).

(c) The owner or operator must notify the Director of adverse financial conditions such as bankruptcy, that may affect the ability to carry out injection well plugging and post-injection site care and site closure.

(d) The operator must provide an adjustment of the cost estimate to the Director if the Director has reason to believe that the original demonstration is no longer adequate to cover the cost of injection well plugging (as required by §146.92) and post-injection site care and site closure (as required by §146.93).

§146.86 Injection well construction requirements. (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:

(1) Prevent the ENDANGERMENT OF USDWs <<movement of fluids into or between USDWs or into any unauthorized zones>>; (2) Permit the use of appropriate testing devices and workover tools; and (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

(b) Casing and Cementing of Class VI Wells.

Page 11EPA-HQ-OW-2008-0390-0122 (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 WELL<<geologic sequestration project>>. All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the API, ASTM International, or comparable standards acceptable to the Director. <<The 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 specify casing and cementing requirements, the owner or operator must provide the following information:

{The threat to the integrity of the casing and cement and other materials is greatest during injection, and quickly decreases as the pressure dissipates after cessation of injection. }

(i) Depth to the injection zone; (ii) Injection pressure, external pressure, internal pressure and axial loading; (iii) Hole size; (iv) Size and grade of all casing strings (E.G., wall thickness, external diameter, nominal weight, length, joint specification and construction material); (v) Corrosiveness of the carbon dioxide stream, and formation fluids; (vi) Down-hole temperatures AND PRESSURES; (vii) Lithology of injection and confining zones; (viii) Type or grade of cement, INCLUDING ADDITIVES; and (ix) Quantity, chemical composition, and temperature of the CO2 stream.

{Redundant - look at application requirements.}

(2) Surface casing must extend through the base of the lowermost USDW ABOVE THE
INJECTION ZONE and be cemented to the surface.

(3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

{Circulation of cement unnecessary and more stringent that requirement for Class I hazardous waste wells. RRC suggests that it may not be technically feasible to cement the full column of one long string casing because the formations you likely want to inject into are low-pressure, and typically won't hold a full column of cement, making circulation impossible. RRC suggests a certain footage of cement, such as 600 ft, and require a bond log to verify it. }

(4) Circulation of cement may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind the well bore.

(5) 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 WELL <<geologic sequestration project>>. The integrity and location of the 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.

{See comment above.}

(c) Tubing and packer.

(1) All owners or operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director. (2) In order for the Director to determine and specify requirements for tubing Page 12EPA-HQ-OW-2008-0390-0122 and packer, the owners or operators must submit the following information:

(i) Depth of setting; (ii) Characteristics of the CO2 stream (chemical content, corrosiveness, temperature, and density); (iii) Injection pressure; (iv) Annular pressure; (v) Injection rate (intermittent or continuous) and volume of the CO2 stream; (vi) Size of casing; and (vii) Tubing tensile, burst, and collapse strengths.

{Repetitive - See application requirements}

§146.87 Logging, sampling, and testing prior to injection well operation.

(a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include:

(1) Deviation checks during drilling on all holes constructed by drilling a pilot hole which are enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine the location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling; and (2) Before and upon installation of the surface casing: (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. (3) Before and upon installation of the long string casing:

(i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed; and (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented.

(4) A series of tests designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:

(i) A pressure test with liquid or gas; (ii) A tracer survey such as oxygen-activation logging; (iii) A temperature or noise log; (iv) A casing inspection log, if required by the Director; and

(5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

(b) The owner or operator must take and submit to the Director whole cores or sidewall cores of the injection zone and confining zone system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the borehole. Rule language should be consistent with definitions.

Page 13EPA-HQ-OW-2008-0390-0122 (c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure and the static fluid level of the injection zone<<(s).>>

(d) At a minimum, the owner or operator must determine or calculate the following information 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 characteristics of the formation fluids in the injection zone.

(e) Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection

zone:

(1) A pump test; or (2) Injectivity tests.

(f) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 days prior to the next scheduled test.

§146.88 Injection well operating requirements.

(a) Except during stimulation, the owner or operator must ensure that injection pressure does not exceed 90% of the fracture pressure of the injection zone so as to assure that the injection does not initiate new fractures or propagate existing fractures 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.

(b) Injection between the outermost casing protecting USDWs and the well bore is prohibited.

(c) The owner or operator must fill the annulus between the tubing and the long string casing with a non-corrosive fluid approved by the Director. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines that such requirement might harm the integrity of the well.

(d) Other than during periods of well workover (maintenance) approved by the Director in which the sealed tubing-casing annulus is of necessity disassembled for maintenance or corrective procedures, the owner or operator must maintain mechanical integrity of the injection well at all times.

(e) The owner or operator must install and use continuous recording devices to monitor: The injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and must install and use alarms and automatic <<down-hole>> shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge beyond permitted ranges and/or gradients specified in the permit;

{RRC suggests that the rule not require automatic shutdown. Experience in the field has been that ESDs are notorious for high maintenance, and continuous monitoring will sufficiently alert the operator of a need to shut down operations. In addition, such a requirement is more stringent than that required for Class I hazardous waste wells.}

(f) If <<a down-hole automatic shutdown is triggered or>> a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and Page 14EPA-HQ-OW-2008-0390-0122 identify as expeditiously as possible the cause <<of the shutoff>>. If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) of this section otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must:

(1) Immediately cease injection; (2) Take all steps reasonably necessary to determine whether there may have been a release of the injected carbon dioxide into any unauthorized zone; (3) Notify the Director within 24 hours; (4) Restore and demonstrate mechanical integrity to the satisfaction of the Director prior to resuming injection; and (5) Notify the Director when injection can be expected to resume.

§146.89 Mechanical integrity.

(a) A Class VI well has mechanical integrity if:

(1) There is no significant leak in the casing, tubing or packer; and (2) There is no significant fluid movement into a USDW through channels adjacent to the injection well bore.

<<(b) To evaluate the absence of significant 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 the annulus between tubing and long stem casing and annulus fluid volume as specified in §146.88(e);>>

{Redundant language.}

(c) At least once per year, the owner or operator must use one of the following methods to determine the absence of significant fluid movement under paragraph (a)(2) of this section:

(1) A tracer survey such as oxygen-activation logging; (2) A temperature or noise log; or (3) A casing inspection log, if required by the Director.

(d) The Director may require any other test to evaluate mechanical integrity under paragraph (a)(1) or (a)(2) of this section. Also, the Director may allow the use of a test to demonstrate mechanical integrity other than those listed above with the written approval of the Administrator. To obtain approval, the Director must submit a written request to the Administrator, which must set forth the proposed test and all technical data supporting its use. The Administrator must approve the request if it will reliably demonstrate the mechanical integrity of wells for which its use is proposed. Any alternate method approved by the Administrator will be published in the Federal Register and may be used in all States in accordance with applicable State law unless its use is restricted at the time of approval by the Administrator.

(e) In conducting and evaluating the tests enumerated in this section or others to be allowed by the Director, the owner or operator and the Director must apply methods and standards generally accepted in the industry. When the owner or operator reports the results of mechanical integrity tests to the Director, he/she shall include a description of the test(s) and the method(s) used. In making his/her evaluation, the Director must review monitoring and other test data submitted since the previous evaluation.

(f) The Director may require additional or alternative tests if the results presented by the owner or operator under paragraph (d) of this section are not satisfactory to the Director to demonstrate that there is no significant leak in the casing, tubing or packer or significant movement of fluid into or between USDWs resulting from the injection activity as stated in paragraphs (a)(1) and (2) of this section. Page 15EPA-HQ-OW-2008-0390-0122

§146.90 Testing and monitoring requirements. 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 must include a description of how the owner or operator will meet the requirements of this section. Testing and monitoring associated with geologic sequestration projects must, at a minimum, include:

(a) Analysis of the carbon dioxide stream with sufficient frequency to yield data representative of its chemical and physical characteristics;

(b) Installation and use, except during well workovers as defined in §146.86(d), of continuous recording devices to monitor injection pressure, rate and volume; the pressure on the annulus between the tubing and the long string casing; and the annulus fluid volume;

(c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed on a quarterly basis to ensure that the well components meet the minimum standards for material strength and performance set forth in §146.86(b) by:

(1) Placing coupons of the well construction materials in contact with the carbon dioxide stream; or (2) Routing the carbon dioxide stream through a loop constructed with the material used in the well; or (3) Using an alternative method approved by the Director;

(d) Periodic monitoring of the ground water quality and geochemical changes above the confining zone<<(s)>> that may be a result of carbon dioxide movement through the confining zone or additional identified zones:

(1) The location and number of monitoring wells must be based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence of artificial penetrations and other factors; (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 AOR evaluation required by §146.84(b);

(e) A demonstration of external mechanical integrity pursuant to §146.89(c) at least once per year throughout the duration of INJECTION <<the geologic sequestration project;>>

{Demonstration of external mechanical integrity should not be necessary after cessation of injection and (relatively immediate) dissipation of pressure near the wellbore resulting from injection.}

(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;

(g) Testing and monitoring to track the extent of the carbon dioxide plume and the position of the pressure 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 electromagnetic surveys and/or down-hole CO2 detection tools);

{If there are changes in the first formation overlying the confining zone, the carbon dioxide stream has not been confined.}

<<(h) At the Director's discretion, surface air monitoring and/or soil 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 Page 16EPA-HQ-OW-2008-0390-0122 within the area of review; (2) The monitoring frequency and spatial distribution of surface air monitoring and/or soil gas monitoring 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 compliance with standards under 40 CFR 144.12;>>

{Any requirement for surface air monitoring and/or soil gas monitoring is not warranted. If the purpose is to detect "movement of carbon dioxide that could endanger a USDW, it would be too late if carbon dioxide were detected in the air or soil. In addition, levels of ambient carbon dioxide are too variable for this to be useful. RRC suggests eliminating any potential requirement for surface air or soil gas monitoring, because formation monitoring should catch whatever condition might reasonably be expected to be caught by surface or soil gas monitoring. }

(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 standards under 40 CFR 144.12; and

(j) A quality assurance and surveillance plan for all testing and monitoring requirements.

§146.91 Reporting requirements.

The owner or operator must, at a minimum, provide the following reports to the Director, for each permitted Class VI well:

(a) Semi-annual reports containing:

(1) Any changes to the physical, chemical and other relevant characteristics of the carbon dioxide stream from the proposed operating data; (2) Monthly average, maximum and minimum values for injection pressure, flow rate and volume, and annular pressure; (3) A description of any event that exceeds operating parameters for annulus pressure or injection pressure as specified in the permit; (4) A description of any event which triggers a shutdown device required pursuant to §146.88(e) and the response taken; (5) The monthly volume of carbon dioxide stream injected over the reporting period and project cumulatively; (6) Monthly annulus fluid volume added; and (7) The results of monitoring prescribed under §146.90.

(b) Report, within 30 days the results of: (1) Periodic tests of mechanical integrity; (2) Any other test of the injection well conducted by the permittee if required by the Director; and (3) Any well workover.

(c) Owners or operators must submit reports in an electronic format acceptable to the Director. At the discretion of the Director, other formats may be accepted.

§146.92 Injection well plugging.

(a) Prior to the well plugging, the owner or operator must flush each Class VI injection well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final mechanical integrity test.

(b) Well Plugging Plan. The owner or operator of a Class VI well must prepare, maintain, and comply with a plan that is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The well plugging plan must be submitted as part of the permit application and must include the following information: Page 17EPA-HQ-OW-2008-0390-0122

(1) Appropriate test or measure to determine bottomhole reservoir pressure; (2) Appropriate testing methods to ensure mechanical integrity as specified in §146.89; (3) The type and number of plugs to be used; (4) The placement of each plug including the elevation of the top and bottom of each plug; (5) The type and grade and quantity of material to be used in plugging. The material must be compatible with the carbon dioxide stream; and (6) The method of placement of the plugs.

(c) Notice of intent to plug. The owner or operator must notify the Director at least 60 days before plugging of a well. At this time, if any changes have been made to the original well plugging plan, the owner or operator must also provide the revised well plugging plan. At the discretion of the Director, a shorter notice period may be allowed.

(d) Plugging report. Within 60 days after plugging or at the time of the next semi-annual report (whichever occurs earlier) the owner or operator must submit a plugging report to the Director. If the semi-annual report is due less than 15 days after completion of plugging, then the report must be submitted within 60 days after plugging. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operator.)

§146.93 Post-injection site care and site closure. (a) The owner or operator ofa Class VI well must prepare, maintain, and comply with a plan for postinjection site care and site closure that meets the requirements of paragraph (a)(2) of this section and is acceptable to the Director.

(1) <<The owner or operator must submit the post-injection site care and site closure plan as a part of the permit application to be approved by the Director.>>

{Redundant - See 146.82(w).}

(2) The post-injection site care and site closure plan must include the following information:

(i) The pressure differential between pre-injection 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 demonstrated inthe AOR evaluation required under §146.84(b); (iii) A description of postinjection monitoring location, methods, and proposed frequency; and (iv) A proposed schedule for submitting post-injection site care monitoring results to the Director.

{This should be referenced in 146.82(w).}

(3) Upon cessation of injection, THE OWNER OR OPERATOR MUST either submit an amended post-injection site care and site closure plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the plan is needed.

(4) THE OWNER OR OPERATOR MAY <<May>> modify and resubmit the post-injection site care and site closure plan for the Director's approval within 30 days of such change.

(b) THE OWNER OR OPERATOR MUST <<Must>> monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate that USDWs are not being endangered.

(1) THE OWNER OR OPERATOR MUST <<Must>> continue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan for THE PERIOD OF TIME <<at least 50 years>> following the cessation of Page 18EPA-HQ-OW-2008-0390-0122 injection <<. At the Director's discretion, the monitoring will continue>> until THE DIRECTOR DETERMINES THAT the geologic sequestration project no longer poses an endangerment to USDWs.

<<(2) If the owner or operator can demonstrate to the satisfaction of the Director before 50 years, based on monitoring and other site-specific data, that the GS project no longer poses an endangerment to USDWs, the Director may approve an amendment to the post-injection site care and site closure plan to reduce the frequency of monitoring or may authorize site closure before the end of the 50-year period.>>

{The period of time an owner or operator is required to conduct post-closure care monitoring should be based on the ability of the pressure to cause endangerment of USDWs. A 50-year post-closure care monitoring period is unprecedented and implies that CO2 presents a greater risk than it does. RRC suggests that EPA strike the phrase "for at least 50 years" and make the time for continued monitoring be based on site specific data. }

(3) Prior to authorization for site closure, must submit to the Director a demonstration, based on monitoring and other site-specific data, that the <<carbon dioxide plume and >> pressure front have stabilized and that no additional monitoring is needed to assure that the GS project does not pose an endangerment to USDWs.

{The carbon dioxide plume will continue to move with other formation fluids - they are never static. The real test should be whether or not the pressure has dissipated and the pressure front stabilized to the point that there is no threat of endangering USDWs.}

<<(4) If such a demonstration cannot be made after the 50-year period, must submit to the Director a plan to continue post-injection site care.>>

{See comment above.}

(c) Notice of intent for site closure. Must notify the Director at least 120 days before site closure. At this time, if any changes have been made to the original post-injection site care and site closure plan, THE OWNER OR OPERATOR must also provide the revised plan. At the discretion of the Director, a shorter notice period may be allowed.

(d) After the Director has authorized site closure, THE OWNER OR OPERATOR must plug all monitoring wells in a manner which will not allow movement of injection or formation fluids that endangers a USDW.

(e) Once the Director has authorized site closure, THE OWNER OR OPERATOR must submit a site closure report within 90 days that must thereafter be retained at a location designated by the Director. The report must include:

(1) Documentation of appropriate injection and monitoring well plugging as specified in §146.92 and paragraph (c) of this section. Must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director, which indicates the location of the injection well relative to permanently surveyed benchmarks. <<Must also submit a copy of the plat to the regional administrator of the appropriate EPA Regional Office>>;

{Why is this necessary? The EPA regional office will have access to all records at the State. }

(2) Documentation of appropriate notification and information to such State, local and tribal authorities as have authority over drilling activities to enable such State and local authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s); and (3) Records reflecting the nature, composition and volume of the Page 19EPA-HQ-OW-2008-0390-0122 carbon dioxide stream.

(f) THE OWNER OR OPERATOR MUST<<Must>> record a notation on the deed to the facility property or any other document that is normally examined during title search that will in perpetuity provide any potential purchaser of the property the following information:

(1) The fact that land has been used to sequester carbon dioxide; (2) The name of the State agency, local authority, and/or tribe with which the survey plat was filed<<, as well as the address of the Regional EPA Office to which it was submitted>>; and (3) The volume of fluid injected, the injection zone <<or zones>> into which it was injected, and the period over which injection occurred.

(g) Must retain for three years following site closure, records collected during the post-injection site care period. THE OWNER OR OPERATOR MUST <<Must>> deliver the records to the Director at the conclusion of the retention period, and the records must thereafter be retained at a location designated by the Director for that purpose.

§146.94 Emergency and remedial response.

(a) As part of the permit application, THE OWNER OR OPERATOR must provide the Director with an emergency and remedial response plan that describes actions to be taken to address movement of the injection or formation fluids that may causean endangerment to a USDW during construction, operation, closure and postclosure periods.

{Redundant - See 146.82(X)}

(b) If the owner or operator obtains evidence that the injected carbon dioxide stream and associated pressure front may cause an endangerment to a USDW, the owner or operator must:

(1) Immediately cease injection; (2) Take all steps reasonably necessary to identify and characterize any release; (3) Notify the Director within 24 hours; and (4) Implement the emergency and remedial response plan approved by the
Director.

(c) The Director may allow the operator to resume injection prior to remediation if the owner or operator demonstrates that the injection operation will not endanger USDWs.

(d) Must notify the Director and obtain his approval prior to conducting any
well workover.

Page 20EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 1 of 16

SPECIFIC RULE PROVISIONS

Proposed Subpart A

- General Provisions

§144.6 Classification of wells. The proposal includes in the definition of “Class VI” the restriction that injection into such wells must be “beneath the lowermost formation containing a USDW.” RRC suggests either removing the restriction or adding ” or another formation, if the Director determines that injection into the other formation will be protective of

USDWs.”

Proposed Subpart D

- Au thorization by Permit

§144.36 Duration of per mits. We agree with the proposal to issue permits for UIC wells associated with sequestration of CO 2 “for the period up to the operating life of the facility.” The substantial financial investment in a project makes a permit for the operating like of

th e facility imperitive

.

Part 146 UIC Program Criteria and Standards

§146.5 Classification of injection wells. (f) Class VI. The proposal includes in the definition of “Class VI” the restriction that injection into
such wells must be “beneath the lower most formation containing a USDW .”

Subpart H

-- Criteria and Standards A pplicable to Class VI Wells

§146.81 A pplicability. (a) This subpart establishes criteria and standards for UIC programs to regulate Class VI

CO 2 GS injection wells.

(b) This subpart applies to wells used to inject CO 2 specifically for the purpose of GS, i.e., the long

- term containment of a gaseous, liquid or supercritical CO 2 stream in subsurface geologic formations.

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

- authorized Class I industrial, Class II, or Class V experimental CO 2 injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells. If the Director determines that

USDW s will not be endangered, such wells are ex empt, at the Director's discretion, from the casing and cementing requirements at §§146.86(b) and 146.87(a)(1) through (3).

RRC agrees that the Director evaluating a permit application to use existing injection wells for geologic sequestration should have the discretion to exempt wells from Class I industrial, Class II or Class V wells from the proposed casing and cementing requirements of Class VI wells.EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 2 of 16

(d) Definitions. The following definitions apply to this subpart. To the extent that these
definiti ons conflict with those in §146.3 these definitions govern:

Area of review means the region surrounding the GS project that may be impacted by the injection activity . The AOR is based on computational modeling that accounts for the phy sical and chemic al properties of all phases of the injected CO 2 stream. Carbon dioxide plume means the underground extent, in 3

- D, of an injected CO 2 stream.
Carbon dioxide stream means CO 2 that has been captured from an emission source (e.g., a power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This subpart does not apply to any CO 2 stream that meets the definition of

a haz ardous waste under 40 CFR part 261. Confining zone means a geologic formation, group of formations, or part of a formation stratigraphically overly ing the injection zone that acts as a barrier to fluid movement.

Corrective action means the use of D irector approved methods to assure that wells within
the AOR do not serve as conduits for the movement of fluids into USDW s. Geologic sequestration means the long

- term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurfac e geologic formations. This term does not apply to its capture or transport. Geologic sequestration project means an injection well or wells used to emplace a CO 2 stream beneath the lowermost formation containing a USDW , or another formation, if the

Di rector determines that injection into the other formation w ill not endanger USDWs . It
includes the subsurface 3

- D extent of the carbon dioxide plume, associated pressure front, and displaced brine, as well as the surface area above that delineated region. RRC suggests adding to the end of the first sentence of the definition of Geologic sequestration project, “or another formation, if the Director determines that injection into the other formation w ill not endanger

USDWs.”

Injection zone means a geolo gic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity , and permeability to receive CO 2 through a well or wells associated with a GS project.

Post

- injection site care means appropriate monitor ing and other actions (including corrective action) needed following cessation of injection to assure that USDW s are not endangered as required under §146.93.

Pressure front means the zone of elevated pressure that is created by the injection of

carbon dioxide into the subsurface. For 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

. Why does this definition need to be different?

Site closure the point/time, as determined by the Director following the requirements under §146.93, at which the owner or operator of a GS site is released from post

- injection site care responsibilities.

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and
vertical extent to allow fluids to move between formations.

Recommend that the fault or fracture be “known.”

§146.82 Required Class VI permit information.EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 3 of 16

Th is section sets forth the information which the owner or operator must submit to the Director in order to be permitted as a Class VI well. The application for a permit for construction and operation of a Class VI well must include the following: (a) Inform ation required in 40 CFR 144.31(e)(1)

- (6); (b) A map showing the injection well(s) for which a permit is sought and the applicable AOR.

Wi thin the AOR, the map must show the number, or name and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structur es intended for human occupancy and roads. The map should also show faults, if known or suspected. Only information of public record is required to be included on this map; (c) The AOR based on modeling, using data obtained during logging and testing of the well and the formation as required by paragraphs (l), (r), and (s) of this section; (d) Information on the geologic structure and hy drogeologic properties of the proposed storage site and overly ing formations, including: (1) Maps and cross sections of the area of review; (2) Location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone (s) in the area of review and a determination that they would not interfere with containment; (3) Information on se ismic history including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment; (4) Data on the depth, areal extent, thickness, mineralogy , porosity , permeability and capillary pressure of the injection and confining zone (s ); including geology /facies changes based on field data which may include geologic cores, outcrop data, seismic survey s, well logs, and names and lithologic descriptions; (5) Geomechanical information on fractures, stress, du ctility , rock strength, and in situ fluid pressures within the confining zone; and (6) Geologic and topographic maps and cross sections illustrating regional geology

, hy drogeology , and the geologic structure of the local area. (e) A tabulation of all wells within the AOR which penetrate the injection or confining z one (s)

. Such data must include a description of each well's ty pe, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require; Definition of confining zone includes multiple formations. Do not imply that multiple confining zones are preferable to one (good) confining zone.

(f) Maps and stratigraphic cross sections indicating the general vertical and lateral limits of

all USDW s, water wells and springs within the area of review, their positions relative to the injection zone (s) and the direction of water movement, where known; Consistency with definition and use of term in other areas of the rules.

(g) Baseline geochem ical data on subsurface formations, including all USDW s in the AOR; (h) Proposed operating data: (1) Average and maximum daily rate and volume of the CO 2 stream; (2) Average and maximum injection pressure; (3) The source of the CO 2 stream; and (4) An analy sis of the chemical and phy sical characteristics of the CO 2 stream;EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

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(i) The compatibility of the CO 2 stream with fluids in the injection zone and minerals in both the injection and the confining zone (s) , based on the results of the formation testing

progra m, and with the materials used to construct the well;

See comment above.

(j) Proposed formation testing program to obtain an analy sis of the chemical and phy sical characteristics of the injection zone and confining zone; (k) Proposed stimulation program and a determination that stimulation will not interfere with containment; (l) The results of the formation testing program as required in paragraph (j) of this section; (m) Proposed procedure to outline steps necessary to conduct injection operation; “Prop osed procedure to outline steps” does not make sense. Recommend “Outline of steps ....”

(n) Schematic or other appropriate drawings of the surface and subsurface construction details of the well; (o) Injection well construction procedures that meet the req uirements of §146.86; (p) Proposed AOR and corrective action plan that meets the requirements under §146.84; (q) The status of corrective action on wells in the AOR; (r) All available logging and testing program data on the well required by §146.87; (s) A demonstration of mechanical integrity pursuant to §146.89; (t) A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under §146.85; (u) Proposed testing and monitoring plan required by §146.90; (v) Proposed injection well plugging plan required by §146.92(b); (w) Proposed post

- injection site care and site closure plan required by §146.93(a); (x) Proposed emergency and remedial response plan required by §146.94; and (y ) Any other information reque sted by the Director.

§146.83 Minimum criteria for siting. (a) Owners and operators of Class VI wells must demonstrate to the satisfaction of the Director that the wells will be sited in areas with a suitable geologic sy stem. The geologic

sy stem must be comprised of: (1) An injection zone of sufficient areal extent, thickness, porosity , and permeability to receive the total anticipated volume of the carbon dioxide stream;

Redundant

- simply repeats the definition of “injection zone.” Either take this

la nguage out of the definition or take it out of here.

(2) A confining zone (s) that is free of transmissive faults or fractures and of sufficient areal extent and integrity to contain the injected carbon dioxide stream and displaced
formation fluids and all ow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone (s) ; and Redundant. Repeats definition of “confining zone.” Also, implies that the confining zone cannot have a single fracture, no ma tter how small. M uch more stringent than for Class I hazardous wells.

(b) At the Director's discretion, owners or operators of Class VI wells must identify and characterize additional zones that will impede vertical fluid movement, are free of faults an dEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

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fractures that may interfere with containment, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation and remediation

. Redundant and unnecessary. Language in definition of “confining zone.”

§146.84 A rea of revi ew and corrective action. (a) The area of review is the region surrounding the geologic sequestration project that may be impacted by the injection activity . The area of review is based on computational modeling that accounts for the phy sical and chemical properties of all phases of the injected carbon

dioxide stream.

Redundant

- same as the definition of “area of review.”

(b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the AOR for a proposed geolog ic sequestration project, periodically reevaluate the delineation, and perform corrective action that meets the requirements of this section at a frequency and in a manner that and is acceptable to the Director. As a part of the permit application for ap proval by the Director , the owner or operator must submit an area of review and corrective action plan that includes the following information: (1) The method for delineating the area of review that meets the requirements of paragraph (c) of this section, including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based; (2) A description of: (i) The minimum fixed frequency , not to exceed 10 y ears, the owner or operator proposes to reevaluate the area of review;

(ii) The monitoring and operational conditions that would warrant a
reevaluation of the area of review prior to the next scheduled reevaluation as determined by the minimum fixed frequency established in paragraph (b)(2)(i) of this sect ion

. Suggest that there be no minimum fixed frequency for reevaluation of the

Ao R, but that such review be based on site

- specific circumstances.

(II) (iii) How monitoring and operational data (e.g., injection rate and pressure)

will be used to inform an area of review reevaluation; and

(iv) 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 injection 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 the site will be access ed will be guaranteed for future corrective a ction. Word Choice. Secure rather than guarantee.

(c) Owners or operators of Class VI wells must perform the following actions to delineate the area of review, identify all wells that require corrective action, and perform corrective action

on those we lls: (1) Predict, using 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, pressure differen tials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or for after a fixed time period as determined by the Director. The model ing must:

(i) Be based on detailed geologic data collected to charact erize the injection

zone and

, confining zone and any additional zones ; and anticipated operating data,EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

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including injection pressures, rates and total volumes over the proposed life of the geologic sequestration project;

(ii) Take into account relevant any geologic heterogeneities and

, data quality

, and their possible impact on model predictions; and

(iii) Consider potential migration through known faults, fractures, and artificial penetrations. (2) Using methods approved by the Director, identify all know n artificial penetrations through the confining zone , including active and abandoned wells and underground mines, in the area of review that may penetrate the confining zone . Provide a description of each well's ty pe, construction, date drilled, location, d epth, record of plugging and/or completion, and any additional information the Director may require; and (3) Determine which abandoned wells in the AOR have been plugged in a manner that prevents the movement of CO 2 or formation associated fluids that may endanger
USDW s.

(d) Owners or operators of Class VI wells must perform corrective action using corrosion resistant material, w hen appropriate, on all wells identified in §146.84(c)(2) in the A OR that are determined to need corrective action using methods necessary to prevent the

movement of fluid into or betw een USDWs including use of corrosion resistant materials, w here appropriate

.

(e) If monitoring data indicate an endangerment to USDW s, the owner or operator must notify the Director and cease operatio ns as required by §146.94.

(f) At the minimum fixed frequency, not to exceed 10 years, as As specified in the AOR and corrective action plan, or when monitoring and operational conditions warrant, the owner or operator must: (1) Reevaluate the AOR in the same manner specified in paragraph (c)(1) of this section; (2) Identify all wells in the reevaluated AOR that require corrective action in the same manner specified in paragraph (c)(2) of this section; (3) Perform corrective action on wells requiring corre ctive action in the reevaluated AOR in the same manner specified in paragraph (c)(3) of this section; and (4) Submit an amended AOR and corrective action plan or demonstrate to the Director through monitoring data and modeling results that no change amendm ent to the AOR and corrective action plan is needed. Appropriate frequency of determining AoR might not be “fixed.” Owner or operator might need to reevaluate AoR frequently at first, particularly with deep brine formations about which there is little his tory, and then at expanding

intervals as more information is known.

(g) The emergency and remedial response plan (as required by §146.94) and a demonstration of financial responsibility (as described by §146.85) must account for the entire AOR, regardless of whether or not corrective action in the area of review is phased.

§146.85 Financial responsibility. (a) The owner or operator must demonstrate and maintain financial responsibility and resources for corrective action (that meets the requirements of § 146.84), injection well plugging (that meets the requirements of §146.92), post

- injection site care and site closureEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

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(that meets the requirements of §146.93), and emergency and remedial response (that meets the requirements of §146.94) in a manner prescrib ed by the Director until: (1) The Director receives and approves the completed post

- injection site care and site closure plan; and (2) The Director determines that the site has reached the end of the post

- injection site care period. (b) The owner or operat or must provide to the Director, at a frequency determined by the Director, written updates of adjustments to the cost estimate to account for any amendments to the AOR and corrective action plan (§146.84), the injection well plugging plan (§146.92),

and t he post

- injection site care and site closure plan (§146.93). (c) The owner or operator must notify the Director of adverse financial conditions such as bankruptcy , that may affect the ability to carry out injection well plugging and post

- injection

site car e and site closure. (d) The operator must provide an adjustment of the cost estimate to the Director if the Director has reason to believe that the original demonstration is no longer adequate to cover the cost of injection well plugging (as required by §1 46.92) and post

- injection site care and site closure (as required by §146.93).

§146.86 Injection w ell construction requirements. (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to: (1) Prevent the enda ngerment of USDWs movement of fluids into or betw een USDWs or into any unauthorized zones ; (2) Permit the use of appropriate testing devices and workover tools; and (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

(b) Casing and Cementing of Class VI W ells. (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

we ll geologic sequest ration project . All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the API, ASTM International, or comparable standards acceptable t o the Director. The casing and cementing program must be designed to prevent
the movement of fluids into or between USDW s. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the

f ollowing information: The threat to the integrity of the casing and cement and other materials is greatest during injection, and quickly decreases as the pressure dissipates after cessation of injection.

(i) Depth to the injection zone; (ii) Injection pr essure, external pressure, internal pressure and axial loading; (iii) Hole size; (iv) Size and grade of all casing strings ( e.g., wall thickness, external diameter, nominal weight, length, joint specification and construction material);

(v) Corrosiveness o f the carbon dioxide stream, and formation fluids; (vi) Down

- hole temperatures and pressures ; (vii) Lithology of injection and confining zones; (viii) Ty pe or grade of cement , including additives ; andEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

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(ix) Quantity , chemical composition, and temperature of the CO2 stream.

Redundant

- look at application requirements.

(2) Surface casing must extend through the base of the lowermost USDW above the injection zone and be cemented to the surface. (3) At least one long string casing, using a sufficient number o f centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages

. Circulation of cement unnecessary and more stringent that requirement for

Class I hazardous w aste w ells. RRC suggests that i t may not be technically feasible to cement the full column of one long string casing because t he formations you likely w ant to inject into are low

- pressure, and typically

wo n't hold a full column of cement, making circulation impossible. RRC suggests a c ertain footage of cement, such as 600 ft, and require a bond log to verify it.

(4) Circulation of cement may be accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be

recirculated to the surface, provided the owner or operator can demonstrate by using logs
that the cement does not allow fluid movement behind the well bore. (5) Cement and cement additives must be compatible with the CO 2 stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life

of the we ll geologic sequestration project . The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identify ing the
location of c hannels to ensure that USDW s are not endangered.

See comment above.

(c) Tubing and packer. (1) All owners or operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director. (2) In order for the Director to determine and specify requirements for tubing and packer, the owners or operators must submit the following information:

(i) Depth of setting; (ii) Characteristics of the CO2 stream (chemical content, corro siveness, temperature, and density );

(iii) Injection pressure; (iv) Annular pressure; (v) Injection rate (intermittent or continuous) and volume of the CO2 stream; (vi) Size of casing; and (vii) Tubing tensile, burst, and collapse strengths. Repetitive

- See application requirements

§146.87 Logging, sampling, and testing prior to injection w ell operation. (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, survey s and tests to determine or verify the depth, thickness, porosity , permeability , and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements

may be compared. The owner or operator must submit to the Director a descriptive reportEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

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prepared by a knowledgeable log analy st that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include: (1) Deviation checks during drilling on all holes constructed by drilling a pilot hole which are enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine t he location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling; and (2) Before and upon installation of the surface casing: (i) Resistivity , spontaneous potential, and calip er logs before the casing is installed; and (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. (3) Before and upon installation of the long string casing: (i) Resistivity , spontaneous potential, porosit y, caliper, gamma ray , fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed; and

(ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. (4) A s eries of tests designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:

(i) A pressure test with liquid or gas; (ii) A tracer survey such as oxy gen

- activation logging; (iii) A temperature or noise log; ( iv) A casing inspection log, if required by the Director; and (5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director.

(b) The owner or operator must take and submit to the Dire ctor whole cores or sidewall cores of the injection zone and confining zone sy stem and formation fluid samples from the injection zone (s) . The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not p ossible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other
formations in the borehole. Rule language should be consistent with definitions.

(c) The owner or operator must record the fluid temperature, pH, conductivity , reservoir pressure and the static fluid level of the injection zone (s)

. (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone (s ) : ( 1) Fracture pressure; (2) Other phy sical and chemical characteristics of the injection and confining zone s ; and (3) Phy sical and chemical characteristics of the formation fluids in the injection z one. (e) Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hy drogeologic characteristics of the injection zone: (1) A pump test; or (2) Injectivity tests. (f) The owner or operator must provide the Director with the opportunity to witness all logging

and testi ng by this subpart. The owner or operator must submit a schedule of such activitiesEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 10 of 16

to the Director 30 day s prior to conducting the first test and submit any changes to the schedule 30 day s prior to the next scheduled test.

§146.88 Injection w ell operat ing requirements. (a) Except during stimulation, the owner or operator must ensure that injection pressure does not exceed 90% of the fracture pressure of the injection zone so as to assure that the injection does not initiate new fractures or propagate ex isting fractures in the injection z one. 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

. (b) Injection between the outermost casing protecting USDW s and the well bore is prohibited. (c) The owner or operator must fill the annulus between the tubing and the long string casing

with a non

- corrosive fluid approved by the Director. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines that such requirement might harm the integrity of the well. (d) Other than during periods of well workover (maintenance) approved by the Director in which the sealed tubing

- casing annulus is of necessity disassembled for maintenance or corrective procedures, the owner or operator must maintain mechanical integrity of the injection well at all times. (e) The owner or operator must install and use continuous recording devices to monitor:

The in jection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and must install and use alarms and automatic dow n
- hole shut

- off sy ste ms, designed to alert the operator and shut

- in the well when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge bey ond permitted ranges and/or gradients specified in the permit; RRC suggests t hat the rule not require automatic shutdow n. Experience in the field has been that ESDs are notorious for high maintenance, and continuous monitoring w ill sufficiently alert the operator of a need to shut dow n operations. In addition, such a requirement is more stringent than that required for Class I hazardous w aste w ells.

(f) If a dow n
- hole automatic shutdow n is triggered or a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and identify as expeditiously

as possible the cause of the shutoff . If, upon such investigation, the well appears to be lacking mechanical integrity , or if monitoring required under paragraph (e) of this section otherwise indicates that the well may be lacking mechanical integrity , the o wner or operator

must: (1) Immediately cease injection; (2) Take all steps reasonably necessary to determine whether there may have been a release of the injected carbon dioxide into any unauthorized zone; (3) Notify the Director within 24 hours; (4) Resto re and demonstrate mechanical integrity to the satisfaction of the Director prior to resuming injection; and (5) Notify the Director when injection can be expected to resume.

§146.89 Mechanical integrity. (a) A Class VI well has mechanical integrity if: (1) There is no significant leak in the casing, tubing or packer; andEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 11 of 16

(2) There is no significant fluid movement into a USDW through channels adjacent to the injection well bore. (b) To evaluate the absence of significant leaks under paragraph (a)(1) of th is section,

ow ners or operators must, follow ing an initial annulus pressure test, continuously monitor injection pressure, rate, injected volumes, and pressure on the annulus

betw een tubing and long stem casing and annulus fluid volume as specified in §146 .88(e); Redundant language. (c) At least once per y ear , the owner or operator must use one of the following methods to determine the absence of significant fluid movement under paragraph (a)(2) of this section: (1) A tracer survey such as oxy gen

- activatio n logging; (2) A temperature or noise log; or (3) A casing inspection log, if required by the Director. (d) The Director may require any other test to evaluate mechanical integrity under paragraph (a)(1) or (a)(2) of this section. Also, the Director may al low the use of a test to demonstrate mechanical integrity other than those listed above with the written approval of the Administrator. To obtain approval, the Director must submit a written request to the Administrator, which must set forth the proposed test and all technical data supporting its use. The Administrator must approve the request if it will reliably demonstrate the mechanical integrity of wells for which its use is proposed. Any alternate method approved by the Administrator will be publish ed in the Federal Register and may be used in all States in accordance with applicable State law unless its use is restricted at the time of approval by

the Administrator. (e) In conducting and evaluating the tests enumerated in this section or others to b e allowed by the Director, the owner or operator and the Director must apply methods and standards generally accepted in the industry . W hen the owner or operator reports the results of mechanical integrity tests to the Director, he/she shall include a des cription of the test(s) and the method(s) used. In making his/her evaluation, the Director must review monitoring and other test data submitted since the previous evaluation. (f) The Director may require additional or alternative tests if the results pres ented by the owner or operator under paragraph (d) of this section are not satisfactory to the Director to demonstrate that there is no significant leak in the casing, tubing or packer or significant

movement of fluid into or between USDW s resulting from t he injection activity as stated in paragraphs (a)(1) and (2) of this section.

§146.90 Testing and monitoring requirements. The owner or operator of a Class VI well must prepare, maintain, and comply with a testing and monitoring plan to verify that the g eologic sequestration project is operating as permitted and is not endangering USDW s. The testing and monitoring plan must be submitted with the permit application, for Director approval, and must include a description of how the owner or operator will me et the requirements of this section. Testing and monitoring associated with geologic sequestration projects must, at a minimum, include: (a) Analy sis of the carbon dioxide stream with sufficient frequency to y ield data representative of its chemical and p hy sical characteristics; (b) Installation and use, except during well workovers as defined in §146.86(d), of continuous recording devices to monitor injection pressure, rate and volume; the pressure on the annulus between the tubing and the long string cas ing; and the annulus fluid volume; (c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed on a quarterly basis to ensure that the wellEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 12 of 16

components meet the minimum standar ds for material strength and performance set forth in §146.86(b) by : (1) Placing coupons of the well construction materials in contact with the carbon dioxide stream; or (2) Routing the carbon dioxide stream through a loop constructed with the material

use d in the well; or (3) Using an alternative method approved by the Director;

(d) Periodic monitoring of the ground water quality and geochemical changes above the confining zone (s) that may be a result of carbon dioxide movement through the confining

zone or additional identified zones: (1) The location and number of monitoring wells must be based on specific information about the geologic sequestration project, including injection rate and volume, geology , the presence of artificial penetrations and other factors; (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 AOR evaluation required by §146.84(b); (e) A demonstra tion of external mechanical integrity pursuant to §146.89(c) at least once per

ye ar throughout the duration of injection the geologic sequestration project ; Demonstration of external mechanical integrity should not be necessary after cessation of injection and (relatively immediate) dissipation of pressure near the wellbore resulting from injection.

(f) A pressure fall

- off test at least once every five y ears unless more frequent testing is required by the Director based on site specific information;

(g) T esting and monitoring to track the extent of the carbon dioxide plume and the position of the pressure front by either monitoring for pressure changes in the first formation overlying the confining zone or using indirect, geophy sical techniques (e.g., seis mic, electrical, gravity , or electromagnetic survey s and/or down

- hole CO2 detection tools); If there are changes in the first formation overlying the confining zone, the

carbon dioxide stream has not been confined.

(h) At the Director's discretion, surfa ce air monitoring and/or soil 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 monitoring must reflect baseline data and the monitoring plan must include how the proposed monitoring will y ield useful information on the area of review delineation and/or compliance with standards under 40 CFR 144.12; Any requirement for surface air monitoring and/or soil gas monitoring is not warranted. If the purpose is to detect “movement of carbon dioxide that could endanger a USDW, it would be too late if carbon dioxide were detected in the

ai r or soil. In addition, levels of ambient carbon dioxide are too variable for

this to be useful. RRC suggests eliminating any potential requirement for surface air or soil gas monitoring, because formation monitoring should catch whatever condition might reasonably be expected to be caught by surface or soil gas monitoring.EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

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(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 standards under 40 CFR 144.12; and (j) A quality assurance and surveillance plan for all testing and monitoring requirements.

§146.91 Reporting requirements. The owner or operator must, at a minimum, provide the follo wing reports to the Director, for each permitted Class VI well: (a) Semi

- annual reports containing: (1) Any changes to the phy sical, chemical and other relevant characteristics of the carbon dioxide stream from the proposed operating data; (2) Monthly aver age, maximum and minimum values for injection pressure, flow rate and volume, and annular pressure; (3) A description of any event that exceeds operating parameters for annulus pressure or injection pressure as specified in the permit; (4) A description of any event which triggers a shutdown device required pursuant to §146.88(e) and the response taken; (5) The monthly volume of carbon dioxide stream injected over the reporting period and project cumulatively ; (6) Monthly annulus fluid volume added; and (7) The results of monitoring prescribed under §146.90. (b) Report, within 30 day s the results of: (1) Periodic tests of mechanical integrity ; (2) Any other test of the injection well conducted by the permittee if required by the Director; and (3) Any well wo rkover. (c) Owners or operators must submit reports in an electronic format acceptable to the Director. At the discretion of the Director, other formats may be accepted.

§146.92 Injection w ell plugging. (a) Prior to the well plugging, the owner or operat or must flush each Class VI injection well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final mechanical integrity test. (b) W ell Plugging Plan. The owner or operator of a Class VI well must prepare, maintain, and comply with a plan that is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The well plugging plan must be submitted as part of the per mit application and must include the following information: (1) Appropriate test or measure to determine bottomhole reservoir pressure; (2) Appropriate testing methods to ensure mechanical integrity as specified in §146.89; (3) The ty pe and number of plugs to be used; (4) The placement of each plug including the elevation of the top and bottom of each plug; (5) The ty pe and grade and quantity of material to be used in plugging. The material must be compatible with the carbon dioxide stream; and (6) The meth od of placement of the plugs.EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 14 of 16

(c) Notice of intent to plug. The owner or operator must notify the Director at least 60 day s before plugging of a well. At this time, if any changes have been made to the original well plugging plan, the owner or operator m ust also provide the revised well plugging plan. At the discretion of the Director, a shorter notice period may be allowed.

(d) Plugging report. W ithin 60 day s after plugging or at the time of the next semi

- annual report (whichever occurs earlier) the ow ner or operator must submit a plugging report to the
Director. If the semi

- annual report is due less than 15 day s after completion of plugging, then the report must be submitted within 60 day s after plugging. The report must be certified as accurate by th e owner or operator and by the person who performed the plugging operation (if other than the owner or operator.)

§146.93 Post

- injection site care and site closure. (a) The owner or operator of a Class VI well must prepare, maintain, and comply with a pl an for post

- injection site care and site closure that meets the requirements of paragraph (a)(2) of this section and is acceptable to the Director. (1) The ow ner or operator must submit the post

- injection site care and site closure plan as a part of the pe rmit application to be approved by the Director.

Redundant

- See 146.82(w).

(2) The post

- injection site care and site closure plan must include the following

information: (i) The pressure differential between pre

- injection and predicted post

- injection

pre ssures in the injection zone;

(ii) The predicted position of the carbon dioxide plume and associated pressure front at site closure as demonstrated in the AOR evaluation required under §146.84(b); (iii) A description of post

- injection monitoring location, methods, and proposed frequency ; and

(iv) A proposed schedule for submitting post

- injection site care monitoring

results to the Director. This should be referenced in 146.82(w).

(3) Upon cessation of injection, the ow ner or operator must either submit an amended post

- injection site care and site closure plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the plan is needed. (4) The ow ner or operator may May modify and resubmit the post

- injection site care

a nd site closure plan for the Director's approval within 30 day s of such change.

(b) The ow ner or operator must Must monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate th at
USDW s are not being endangered. (1) The ow ner or operator must Must continue to conduct monitoring as specified in

the Director

- approved post

- injection site care and site closure plan for the period of time at least 50 years following the cessation of in jection . A t the Director's discretion, the monitoring w ill continue until the Director determines that the geologic sequestration project no longer poses an endangerment to USDW s. (2) If the ow ner or operator can demonstrate to the satisfaction of the Dire ctor before 50 years, based on monitoring and other site

- specific data, that the GS projectEPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 15 of 16

no longer poses an endangerment to USDWs, the Director may approve an amendment to the post

- injection site care and site closure plan to reduce the frequency of mon itoring or may authorize site closure before the end of the 50

- year period. The period of time an owner or operator is required to conduct post

- closure care monitoring should be based on the ability of the pressure to cause endangerment of USDWs. A 50

- yea r post

- closure care monitoring period is unprecedented and implies that CO2 presents a greater risk than it does. RRC suggests that EPA strike the phrase “for at least 50 years” and make the time for continued monitoring be based on site specific data.

(3) Prior to authorization for site closure, must submit to the Director a demonstration, based on monitoring and other site

- specific data, that the carbon dioxide plume and pressure front have stabilized and that no additional monitoring is needed to as sure that the GS project does not pose an endangerment to USDW s. The carbon dioxide plume will continue to move with other formation fluids

- they are never static. The real test should be whether or not the pressure has dissipated and the pressure front stabilized to the point that there is no threat of endangering USDWs.

(4) If such a demonstration cannot be made after the 50

- year period, must submit to the Director a plan to continue post

- injection site care.

See comment above.

(c) Notice of intent f or site closure. Must notify the Director at least 120 day s before site closure. At this time, if any changes have been made to the original post

- injection site care and site closure plan, the ow ner or operator must also provide the revised plan. At the discretion of the Director, a shorter notice period may be allowed. (d) After the Director has authorized site closure, the ow ner or operator must plug all monitoring wells in a manner which will not allow movement of injection or formation fluids

that end angers a USDW

. (e) Once the Director has authorized site closure, the ow ner or operator must submit a site closure report within 90 day s that must thereafter be retained at a location designated by the Director. The report must include: (1) Documentation of appropriate injection and monitoring well plugging as specified in §146.92 and paragraph (c) of this section. Must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director, which indicates the

lo cation of the injection well relative to permanently survey ed benchmarks. Must also submit a copy of the plat to the regional administrator of the appropriate EPA Regional Office ; Why is this necessary? The EPA regional office will have access to all rec ords

at the State.

(2) Documentation of appropriate notification and information to such State, local and tribal authorities as have authority over drilling activities to enable such State and local authorities to impose appropriate conditions on subsequ ent drilling activities that may penetrate the injection and confining zone(s); and (3) Records reflecting the nature, composition and volume of the carbon dioxide

stream.EPA Proposed Carbon Dioxide Geologic Sequestration Regulations

Com ments of the Railroad Commission of Texas

Attachment Page 16 of 16

(f) The ow ner or operator must Must record a notation on the deed to the facility pro perty

or any other document that is normally examined during title search that will in perpetuity provide any potential purchaser of the property the following information: (1) The fact that land has been used to sequester carbon dioxide; (2) The name of t he State agency , local authority , and/or tribe with which the survey plat was filed , as w ell as the address of the Regional EPA Office to w hich it w as submitted ; and (3) The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.

(g) Must retain for three y ears following site closure, records collected during the post

injection site care period. The ow ner or operator must Must deliver the records to the
Director at the conclusion of t he retention period, and the records must thereafter be retained at a location designated by the Director for that purpose.

§146.94 Emergency and remedial response. (a) As part of the permit application, the ow ner or operator must provide the Director wi th

an emergency and remedial response plan that describes actions to be taken to address movement of the injection or formation fluids that may cause an endangerment to a USDW during construction, operation, closure and post

- closure periods.

Redundant

- S ee 146.82(X)

(b) If the owner or operator obtains evidence that the injected carbon dioxide stream and associated pressure front may cause an endangerment to a USDW , the owner or operator

must: (1) Immediately cease injection; (2) Take all steps reasonabl y n ecessary to identify and characterize any release; (3) Notify the Director within 24 hours; and (4) Implement the emergency and remedial response plan approved by the Director. (c) The Director may allow the operator to resume injection prior to remedia tion if the owner or operator demonstrates that the injection operation will not endanger USDW s. (d) Must notify the Director and obtain his approval prior to conducting any well workover.Letter ID: 0122 Commenter: Leslie Savage Organization: Railroad Co mmission of Texas (RRC)

Letter ID: 0122 Comment ID: 24730 Letter Lines: 29 to 52

Comment Code: 1330 1.1.3.1 Support use of GS in general

Comment: Energy (DOE). We share the EPA’s belief th at CO2 sequestration has the potential to improve air quality. We further beli eve that the best way to promote economical geosequestration of CO2 initia lly is to link captu red CO2 with oil reserves, producing increased petr oleum recovery efficiencies.

Texas is a leader in e nhanced oil recovery usi ng CO2. Texas possesses an extensive oil and gas pipeline infrastruc ture capable of transporting CO2 to various sequestration sites. The first CO2 flood occurred in 1972 in West Texas. In 2005, over 160,000 barrels of oil per day were produced with CO2 EOR in Texas. The RRC has permitted over 11,200 CO2 injection wells, with over 5,400 of those being currently active. The 50 activ e CO2 enhanced oil recovery projects in West Texas represent about 50 per cent of total CO2 flooding activity worldwide. CO2-driven EOR has grown steadily since 1985 and now accounts for over 15 percent of the averag e yearly oil production in Texas. The oil industry has experienced a supply shor tage of CO2 over the past few years. Finding new

sources of CO2 will alleviate that shortf all and result in an increase in oil production. The current shortage is about 0.5 billion cubic feet per day, with industry consuming the available 1.5 bill ion cubic feet per day. Increased availability of anthropogenic CO2 could acce lerate this production. In April of 2004, the University of Texas Bureau of Ec onomic Geology identi fied at least 31

billion barrels of oil in Texas that ar e recoverable using CO2-driven EOR.

The RRC has primacy over Class II wells a nd Class III brine mining wells in Texas. Texas has been regulating injecti on wells since the 1930s . With nearly a

Individual Response: EPA clarifies that injection of CO2 for the purposes of enhanced oil and gas recovery will continue to be permitted under the Class II program, as long as any oil or gas production is occurring. The UIC GS requirements will apply to wells used for the purpose of long-term GS.

Please see the remainder of EPA’s responses to this comment for further details.

For additional information on EPA’s approach to wells that are transitioning from ER to GS, see

the discussion of Class II wells under “How Does This Rule Affect Existing Injection Wells Under the UIC Program?” in the preamble to the final GS rule.

1Letter ID: 0122 Comment ID: 24731 Letter Lines: 62 to 98

Comment Code: 1680 1.3.8 Don't overstate ris k, don't stigmatize CO2

Comment: The Proposal fails to promote and encour age geosequestration of CO2. EPA’s stated goals for this proposal are to protect Underground Sources of Drinking Water (USDWs) while promoting carbon captu re and storage. As the proposal stands, the regulations would succeed in protecting USDWs, but would fail to successfully promote carbon capture a nd storage in any significant way. Therefore, under the current regulatory scenario, CO2 will continue to be released to the atmosphere in greater amounts than would ever leak from a properly sited, constructed, and operated CO2 storage f acility. One reason for the failure is that the proposal overes timates the risk of CO2 sequestration and, as a result, creates an overestimated implied liability. A nother reason is that the Proposal taints the technolo gy by implying that CO2 is a waste. Finally, the proposal includes insuffici ent flexibility to account for the geographic variability of potential sites across the c ountry. In summary, the RRC is concerned that the Proposal over estimates the risks of CO2 geologic sequestration, and creating barriers to rapid implementation of the technology rather than encouraging or providing incentives to mobilize large-scale projects.

The Proposal treats CO2 as a waste. The EP A states in the preamble that it has

not classified CO2 as a waste or a co mmodity. However, by using the Class I waste injection well requirements as the framework for the Class VI requirements, the Proposal implies that the CO2 stream is a waste. This implication increases not only the pote ntial liability for carbon dioxide sequestration, but also the potential liability for an thropogenic CO2 injection for the purpose of enhanced recovery of oil and/or natural gas.

Many provisions of the Proposal address Class VI wells from a waste based perspective. With respect to constructi on, area of review (AoR) and monitoring, the Proposal begins with the regulatory framework for Class I non-hazardous industrial waste injection we ll requirements and then adds numerous layers of requirements to prevent or detect the es cape of CO2 from the injection zone.

The Proposal excludes CO2 that is a h azardous waste from regulation under the Class VI program, but has proposed requi rements for Class VI injection wells that are more stringent than those for we lls used for the inj ection of hazardous waste. RRC strongly disagrees that CO2 buoyancy, corrosivi ty, and high injection volumes for a Class VI project justify a Class I approach.

Individual Response: EPA clarifies that the purpose of the GS rule is not to promote GS in specific settings, nor does it limit injection ac tivities to any specific type of formation, geographic region, or depth. The focus of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that is protective of USDWs.

2EPA disagrees that the GS regulation overstates the risk of CO2 injec tion. EPA recognizes that injecting large volumes of CO2 for GS poses uni que challenges that, if not properly managed, could endanger drinking water sources and have other adverse impacts. However, with proper site selection, the final, tailored, Class VI requirements address the large volumes of CO2 injected, its buoyancy, potential corr osivity in the presence of wate r, and potential impurities in the CO2 stream. In addition, EPA expects the tailored permitting, siting, construction, operation, monitoring, and post-injection site care requirements in the GS rule to prevent leakage from injection formations and protect USDWs. EPA ad ds that the requirements of the GS rule are tailored to the nature of the CO2 itself, and do not address or imply anything regarding the status of CO2 as a pollutant, commodity, or waste. EPA does not believe the GS rule creates any implication for an increase in potential liabilit y for GS or CO2 injection related to EOR.

EPA disagrees that the GS rule has “tainted” technology by using the Cla ss I regulations as a baseline for the Class VI regulations. Additiona lly, EPA disagrees that the GS rule provides insufficient flexibility to account for geographic variability. EPA ha s taken a regulatory approach that promotes USDW protection, incorporates flexibility or the discretion of the permitting authority when appropriate, seeks to limit burden on owners or operators and permitting agencies, and provides a foundation for national c onsistency in permitting of GS projects. For example, under the final rule, many of the permit requirements must be established through sitespecific plans (e.g., AoR and corrective action plan, testing and monitoring plan, etc.) developed by the owner or operator and approved by the Director.

Furthermore, EPA recognizes that technologies will evolve and improve over time, and for these reasons, the Agency is using an adaptive approach to regulate GS injection. The Agency plans, every six years, to collect and review data on GS projects to determine whether the appropriate amount and types of information and appropria te documentation are being collected, and to determine if modifications to the requir ements are appropriate or necessary.

Letter ID: 0122 Comment ID: 24733 Letter Lines: 80 to 98

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

Comment: The Proposal treats CO2 as a waste. The EP A states in the preamble that it has

not classified CO2 as a waste or a co mmodity. However, by using the Class I waste injection well requirements as the framework for the Class VI requirements, the Proposal implies that the CO2 stream is a waste. This implication increases not only the pote ntial liability for carbon dioxide sequestration, but also the potential liability for an thropogenic CO2 injection for the purpose of enhanced recovery of oil and/or natural gas.

Many provisions of the Proposal address Class VI wells from a waste based perspective. With respect to constructi on, area of review (AoR) and monitoring, the Proposal begins with the regulatory framework for Class I non-hazardous industrial waste injection we ll requirements and then adds numerous layers of requirements to prevent or detect the es cape of CO2 from the injection zone.

3The Proposal excludes CO2 that is a h azardous waste from regulation under the Class VI program, but has proposed requi rements for Class VI injection wells that are more stringent than those for we lls used for the inj ection of hazardous waste. RRC strongly disagrees that CO2 buoyancy, corrosivi ty, and high injection volumes for a Class VI project justify a Class I approach.

Individual Response: EPA disagrees that the requirements in the GS rule are too stringent or overstate the risk associated with GS. The require ments for Class VI wells are tailored to address the unique nature of full-scale CO2 GS, includi ng the injection volumes anticipated for longterm storage, the buoyant and viscous nature of th e injectate, and its corro sivity in the presence of water. While the Class I requirements formed the basis of many of the specific requirements for GS wells, EPA clarifies that the GS rule is tailored to the unique nature of GS. EPA based many of the GS requirements on the Class I regu lations because, like Class VI wells, Class I wells are typically deep and involve waste stre ams that, if not properly managed, can harm the

well and lead to contamination.

EPA also disagrees that the Cl ass VI requirements themselves, or EPA’s consideration of the Class I requirements, necessarily have any impli cations for whether a particular material is a RCRA “solid waste” or implicat es CERCLA liability, as EPA understands the comment to suggest. EPA notes that the GS rule is not promulgated under either of those statutes, and further, the applicability of those statutes will not be determined under the SDWA or the terms of the GS rule, but rather according to those statutes themselves and any implementing regulations that may apply. EPA also notes that the commenter provides no legal analys is explaining why the Class VI rule’s requirements alleged implication th at CO2 is a waste “increases . . . the potential liability for carbon dioxide sequestration [or] for anthropoge nic CO2 injection for the purpose of enhanced recovery of oil and/or natural gas.” EPA adds that liability fo r Class II wells is outside the scope of this rulemaking.

Letter ID: 0122 Comment ID: 24734 Letter Lines: 100 to 132

Comment Code: 1680 1.3.8 Don't overstate ris k, don't stigmatize CO2

Comment: The Proposal overestimates the risks of CO2 injection and sequestration. As noted in the preamble, naturally occurri ng CO2 has been trapped in subsurface

formations for eons. Texas and numerous other states have over 35 years of experience in injection of large amounts of CO2 into geologic formations to enhanced oil recovery. Over 35 million tons of CO2 are injected annually in more than 70 projects in the United States.

In most cases, with appropriate site selection, construction, monitoring, and testing, the risks of CO2 geologic seques tration would be comparable to the

risks of current activities such as natural gas storage, EOR and deep underground disposal of acid gas. In thos e instances any regulations for Class VI wells should reflect more closely UIC Class II standards in stead of the more

4stringent Class I well standards.

Both the Class VI and the Class II program s have the same goals - protection of USDWs. Yet, EPA’s proposal implies th at when the purpose of the injection switches from enhanced recovery to se questration, the risks to USDWs are significantly magnified. The RRC does not ag ree that the volume and duration of CO2 injection and placement are sufficientl y different in meas urable effect on the underground to justify the extr a layers of requirements.

However, rather than beginning its CO2 ge ologic sequestration framework with the Class II well program, EPA begins with the framework of Class I non-hazardous industrial waste injection we ll requirements and adds then numerous layers of overly redundant requirements to prevent or detect the escape of CO2 from the injection zone. The implication seems to be that EPA believes that the Class II program is not sufficiently stringent. Th is implication is a major concern for

the RRC.

In addition, the heightened stringency in the proposed requirements for Class VI injection wells suggests that geological sequestration of CO 2 is as much or more dangerous than underground injection of ot her substances. The Proposal includes numerous examples of this heightened stringency:

Individual Response: As described above, EPA disagrees that the GS rule overstates the risk of CO2 injection. While EPA recognizes that industr y has decades of experience injecting CO2 for EOR and EGR, EPA believes that injection for the primary purpose of long term storage is sufficiently different from Cla ss II ER operations and warrants tailored requirements, which is why the GS rule used the Class I regulations as its baseline. For exam ple, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater th an for Class II wells. Reservoir pressure conditions wi ll also be different, with Cla ss VI injection operations involving large volumes of CO2 and likely having higher pressures within th eir storage formations than Class II ER projects.

EPA disagrees that the tailored requirements of th e GS rule suggest that GS of CO2 is any more risky or dangerous than underground injection of other substances. EPA expe cts that the tailored permitting, siting, construction, operation, monitoring, and post-injection site care requirements in the GS rule will prevent leakage from injection formations and protect USDWs.

Letter ID: 0122 Comment ID: 24735 Letter Lines: 134 to 136

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

Comment: - The implied recommendation that a geol ogic sequestration proj ect have more than one confining zone is much more stri ngent than the requirements for Class I hazardous waste injection wells.

5Individual 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 permitting 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: 0122 Comment ID: 24736 Letter Lines: 138 to 139

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)

Comment: - The requirement that the long-string casing be cemented to the surface is equally as stringent as the Class I haza rdous waste well requirements. - Annulus

Individual Response: EPA clarifies that the requirements fo r Class VI wells are not necessarily more stringent than those for Cl ass I hazardous waste injection wells; rather, they are different. For example, Class I hazardous well owner or oper ators are subject to requ irements that are not applicable to Class VI wells, su ch as no migration petitions.

Letter ID: 0122 Comment ID: 24737 Letter Lines: 139 to 141

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

Comment: equally as stringent as the Class I haza rdous waste well requirements. - Annulus liquid level indicator and a down-hole s hut-off valve are not required for a Class I hazardous waste injection well.

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

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

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

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

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

6subsurface fluid movement and ensure protection of USDWs.

Regarding annulus fluid volume, EPA believes that knowing annulus fluid volume, as required at §146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that monitoring the annulus fluid volume added is su fficient to meet the intent of continuous monitoring of the pressure on th e annulus. The final GS rule at §146.90 (b), requires that owners or operators use continuous reco rding devices to monitor injecti on pressure, rate and volume; the pressure on the annulus between the tubing and the long string casing; and the annulus fluid

volume added.

Letter ID: 0122 Comment ID: 24738 Letter Lines: 143 to 145

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment)

Comment: - The requirement for annual external mechanical integrity testing for Class VI wells, such testing is only required on ce every five years for a Class I

hazardous waste well.

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 supercritical CO2, and the buoyant nature of th e 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.

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

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

Letter ID: 0122 Comment ID: 24739 Letter Lines: 147 to 149

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

Comment: - The Proposal’s default 50-year post- injection monitoring period, while groundwater monitoring for a Class I hazardous waste injection well is required only until the injection zone pressure is such that USDWs cannot be impacted.

Individual Response: The GS regulations have been tailore d to these unique characteristics of GS injection wells. EPA develope d the Class VI regulations in recognition that the risks posed by GS to USDWs are fundamentally different th an those associated w ith current injection

7practices regulated by the UIC program, includi ng Class I hazardous waste injection wells. For example, CO2 is more buoyant, less viscous (i .e., more mobile), and in some cases more corrosive than fluids injected into Class I haza rdous waste wells. In add ition, the large injection volumes anticipated for GS will likely be much gr eater than current injection practices. Lastly,

CO2 movement in the subsurface is not as well understood as fluids currently injected under the Class I program.

In combination, these unique char acteristics result in CO2 plumes that may be highly mobile in the subsurface and move vertically upwards. Th ere will also be some unavoidable levels of uncertainty as to the direction and speed of plume movement during an d after injection. EPAfunded research by Lawrence Berkeley National Laboratory has shown in preliminary modeling studies of ideal basins for GS that pressure pert urbations great enough to force saline fluids into USDWs may cover large areas comp ared to current injection proj ects (10s to 100s km2). This research report, entitled "Research Projec t on CO2 Geological Storage and Groundwater Resources: Large-Scale Hydrological Evaluation and Modeling of the Impact on Groundwater Systems," is available in the rulemaking doc ket. EPA developed regulations that would appropriately address the larger the area influen ced by a GS project, and the resultant, higher likelihood that there may be potential faults, fr actures, or abandoned well s that could act as a conduit for USDW contamination. Furthermore, a le vel of site-characteri zation typical for Class I hazardous waste injection wells will be ex tremely difficult over these vast areas.

Letter ID: 0122 Comment ID: 24740 Letter Lines: 151 to 162

Comment Code: 1610 1.3.1 Risks to USDWs

Comment: In nearly every instance where EPA indi cates that additional safe-guards are necessary, it cites as the reason the chemi cal characteristics of the CO2 stream to be injected and the interaction of th e CO2 stream with formation waters and strata, the buoyant nature of CO2, and the pressure increases caused by injection of very large volumes of CO2. However, buoyancy and chemical

characteristics of CO2 have been successf ully addressed in enhanced recovery injection projects using CO2 under the Cla ss II UIC program. Pr essure increases can be handled by selecting formations that have been depleted and have reduced pressures. In those formations for which the pressure has not been reduced as a result of production or other activity, the issue of the pr essure increase resulting from injection of large amount s of CO2 can be addressed by limiting the surface injection pressure and adequate monitoring.

Individual Response: As stated above, EPA acknowledges that industry has decades of experience in addressing many of the issues pr esent in GS operations. However, EPA reasonably believes that injecting large volumes of CO2 for GS poses unique challenges that, if not properly managed, could endanger drinking water sources or have other adverse impacts. EPA believes

that caution is warranted and ha s, as a result, developed a ne w well class with requirements tailored to address the unique challenges posed by GS and potenti al risks associated long-term injection of CO2. These requirements include the tailored AoR delineation process per §146.84,

8monitoring that is appropriate to GS projects per §146.90, and extended post-injection site care per §146.93.

Letter ID: 0122 Comment ID: 24741 Letter Lines: 164 to 189

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

Comment: The Proposal does not include sufficient flexibility. Congress mandated, through Section 1421(b)(3)(A) of the SDWA, that UIC regulations developed by EPA permit or provide consideration of varying ge ologic, hydrological, or historical

conditions in different Stat es and in different areas within a State. Thus, Congress cautioned EPA against a ‘one-s ize-fits-all’ regulatory scheme, and

mandated consideration of local conditions and practices. However, the Proposal

does not allow State director s to use their expertise and knowledge to account for these varying conditions.

EPA states in the preamble that its reason for selecting Alternative #3 is because it ‘provides flexibility while creating a framework of minimum requirements to ensure consistency acro ss the nation.’ However, by selecting Alternative #3, EPA selected as a starti ng point the requirements for Class I industrial non-hazardous wells. Because of this, the flexibility is restrained at the very outset.

Using as the reason the unknowns and the unique characte ristics of CO2 geosequestration (buoyancy, corrosivity, high injection volumes, etc.), the Proposal seems to include the entire slate of possible technologies available to complete, operate, monitor and close a UIC well and the injection/confining formations. In a few areas, the Proposal provides the Director with discretion to set certain application, permit, and m onitoring criteria that are appropriate to local geologic settings. However, becau se EPA began with an unnecessarily stringent Class I framework, and adde d numerous other nondiscretionary requirements, the flexibility is insuffici ent. The result is that the Proposal is unnecessarily prescriptive and costly.

Individual Response: EPA agrees that flexibility is im portant to accommodate the varied conditions that may be encountered at GS s ites while ensuring the protection of USDWs.

The technical requirements in Al ternative 3 (and the final GS ru le) build upon th e long-standing UIC regulatory framework for deep wells and ar e appropriately tailored to address the unique nature of full-scale CO2 GS, including the vol umes of CO2 to be injected, the buoyant and mobile nature of the injectate, and its corrosivity in the presence of water.

The regulation provides flexibility for selection of appropriate site s and target formations (under §146.82), well construction specifics (under §146.86), and testing and monitoring regimes (under §146.90), provided the owner or operator can demonstr ate that the injecti on and storage will not endanger USDWs and that minimum requirements for the site are met.

9Letter ID: 0122 Comment ID: 24742 Letter Lines: 191 to 199

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: The proposal does not seem to consider CO 2 to be sequestered during injection for EOR. The first economic CO2 sequestrati on projects will be associated with oil and gas operations, yet the Proposal states that sequestration (and thus, Class VI injection) begins only after e nhanced recovery of oil or gas has stopped. The implication is that the CO2 in jected for enhanced recovery is not ultimately sequestered upon cessation of injection and production activity. The proposal grandfathers the construction of wells permitted as Class V and Class II, but requires that the wells comply w ith all other requirements of Class VI wells before injecting CO2 for sequestration.

Individual Response: EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose of EOR, and that s ites used for ER may be suitable for GS and may be among the first GS sites. EPA also recogn izes that a by-product of ER activities is that a certain percentage of the CO2 is trapped in th e receiving formation. 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 requirements in order to protect USDWs from endangerment. For example, the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure conditions will also be di fferent, with Class VI injection operations involving large volumes of CO2 and likely having hi gher pressures within their storage formations than Class II EOR projects.

EPA clarifies that the final Cla ss VI regulations require that any owner or operator injecting CO2 for the primary purpose of long term storage ob tain 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 auth ority to determine at what point a Class VI permit is required for those projects that are transitioning from the primary purpose of EOR to long term storage of CO2. The fina l regulation provides a set of tec hnical factors for the Director to evaluate in making this determination, at §144.19. EPA believes that th is approach provides sufficient protection of USDWs when there is an increased risk to USDWs as compared to traditional Class II operations while allowing for site-specific flexibility. For more information, please see the discussion on transiti on of Class II wells in the pr eamble to the final GS rule.

Letter ID: 0122 Comment ID: 24743 Letter Lines: 201 to 220

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

Comment: Delegation of Primacy Congress mandated, through Section 1421(b)(3 )(B)(i) of the Safe Drinking Water Act (SDWA), that, to the extent feasible, EPA avoid promulgating requirements that would unn ecessarily disrupt State UIC programs already in effect and being enforced in a substantial number of States.

10The EPA has indicated that it will delegate the program under Section 1422 of the SDWA. The RRC agrees with EPA that it is in the best inte rest of protecting groundwater resources for the geologic seque stration of CO2 to be regulated at the state level. However, any requirement by EPA that states accept primacy for Class I, III and V wells as a condition fo r obtaining primacy for Class VI wells will create an unreasonable burden upon states. This matter needs to be clarified in the rule. In addition, any requirement by EPA that states with primacy for Class I, III, and V wells al so accept primacy for Class VI wells will unnecessarily disrupt the states’ exis ting UIC programs and will compromise the states’ ability to decide how best to administer the state’s program. In addition, EPA should allow for split delega tion in the Class VI program, as it has in Texas for the Class III program, to allow the state to best determine how to implement the Class VI program. Furthe rmore, EPA should not be allowed to reopen any state’s primacy over other we ll classes in order for a state to obtain primacy for the Class VI well program.

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.

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

11Federal 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.

In addition, EPA recognizes that some states may not have appr opriate geology for sequestering CO2, and these states should be able to retain primacy for other well classes without incurring the cost and burden of adopting primacy changes to address the new Class VI well requirements.

EPA also clarifies that a state’ s application for primacy for Class VI wells will not affect the status of that state’s primacy for other well classes under the UIC program.

Letter ID: 0122 Comment ID: 24744 Letter Lines: 224 to 238

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: 1. EPA should consider creating a subclass within the Class II well classification for operators who wish to sequester CO2 in association with enhanced recovery of oil or natural gas (with appropriate and necessary additional requirements to address any CO2 issues) and allow the Class VI injection well program to govern those inj ection wells used to sequester CO2 in formations that are non-productive.

2. EPA should begin with a reasonable framework (Class II injection wells);

assure that the rules are flexible enough to consider site-specific characteristics and knowledge gained from CO2 history and the ongoing demonstration and pilot projects; an d that include performance-based requirements. Because of Texas’ and othe r States’ long experien ce with injection operations, the States are in an excell ent position to perceive and act upon similarities in fluids injected, construction depth, design, operating techniques and purposes between its Cl ass II and potential Class VI wells.

Individual Response: The Agency disagrees that wells inje cting CO2 for the primary purpose of long term storage should be regulated under Class II requirements or be classified as a sub-class

of Class II well classification. EPA recognizes that the oil a nd gas industry has decades of experience injecting CO2 for the purpose of EOR, and that sites used fo r EOR may be suitable for GS and may be among the first GS sites. EPA also recognizes th at a by-product of EOR activities is that a certain pe rcentage of the CO2 is trappe d in the receiving formation.

However, the Agency believes that the nature an d risks of CO2 injection for the primary purpose of long term storage poses different risks than injection for the prim ary purpose of ER, and therefore has developed new Cla ss VI regulations to address th ese unique risks in order to protect USDWs from endangerment. For example, the volume of CO2 anticip ated to be injected for long term storage is signifi cantly greater th an for EOR operations. Reservoir pressure conditions will also be different, with Class VI injection operations involving large volumes of

12CO2 and likely having higher pressures within th eir storage formations than Class II EOR projects. EPA believes that inj ection of CO2 for the primary pur pose of enhancing oil and gas recovery should remain unde r the Class II Program.

EPA has taken a regulatory approach which prom otes USDW protection, incorporates flexibility or the discretion of the permitting authority when appropriate, seeks to limit burden on owners or operators and permitting agencies, and provides a foundation for national consistency in permitting of GS projects. For example, under th e final rule, many of the permit requirements must be established through site -specific plans (e.g., AOR and corre ctive action plan, testing and monitoring plan, etc.) developed by the owne r or operator and appr oved by the Director. Consequently EPA expects that owners or opera tors will consult with the Director as they develop, implement, and update these plans. Ad ditionally, the Director has the discretion to approve alternatives to the requirements in some cases. For example, the Director may in certain situations modify the length of the post-injecti on site care period or appr ove an alternative postinjection site care timeframe as part of th e permitting process under §146.93, allow the use of alternate methods for mechanical integrity testing under §146.89, or gr ant waivers from the requirement to inject below the lowermost USDW under §146.95.

Letter ID: 0122 Comment ID: 24745 Letter Lines: 240 to 246

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

Comment: 3. EPA should provide more flexibility in the siting requirements: a. acknowledge that some sites offer very good protection when compared to others and ease regulatory burden on those site s; b. promote transfer of EOR to storage; c. delete the requirement that the confining zone be free of all transmissive faults or fractures; d. delete references to multiple confining zones; and e. revise the Proposal to allo w for site-specific ch aracteristics and performance- based determinations.

Individual Response: The Agency believes that the Class VI requirements balance site-specific flexibility with USDW protection. Rather than setting performance or technology-based standards for GS projects, EPA is adopting a flex ible approach, where operators of GS projects would develop and implement site-specific plans for delineating the AoR, testing and monitoring the site, performing corrective actio n, and post-injection site care . EPA believes that the plans— which would be reviewed and approved by the Director and periodical ly updated throughout the life of the project—promote an ongoing dialogue between the operato r and the Director that will encourage use of the most appropriate t echnologies for a particular project.

Please see the remainder of EPA’s responses to this comment for further details related to transitioning of ER projects for GS and confining zone requirements.

Letter ID: 0122 Comment ID: 24746 Letter Lines: 248 to 249

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

13Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)

Comment: 4. EPA should provide more flexibiilty in construction, for example, delete the requirement that the long string cas ing be cemented to the surface.

Individual Response: EPA believes that the requirements fo r long-string casing are appropriate and offer appropriate flexibility : §146.86(b)(3) requires th at the 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 notes that there are many potential ways to meet the requirement, such as the use of staged cementing. See the discussion of Class VI well cons truction 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 adds that other aspects of the rule allow flexibility based on site-s pecific considerations: with their permit applications, owners or operators must submit proposed well construction procedures, as specified at §146.82(a)(12), that address the specific drilling and injection environment and the chemical and physical nature of the CO2 injected stream. The Director must evaluate the appropriateness of the proposed c onstruction based on site-specific information about the injection project, including injection pressures, injection a nd confining zone lithology,

and information about the carbon dioxide stream , as provided in the final GS rule at §146.86(b)(1).

Letter ID: 0122 Comment ID: 24747 Letter Lines: 251 to 251

Comment Code: 4000 2.4 Proposed Injection Well Operat ing Requirements (40 CFR 146.88)

Comment: 5. EPA should provide more flexibiilty in operation. For example, allow an EOR

Individual Response: EPA believes the operating requirements for Class VI wells are necessary in order to protect USDWs from endangerment by providing multiple safeguards to ensure that well integrity, containment of flui ds within the injection zone, and that the integrity of the confining zone is not compromi sed. Some of the operating requirements in the GS regulation (e.g., pressure limitations or annulus pressure re quirements) are consistent with those for other injection well types, while other requirements (e .g., use of automatic shut-off systems or tracers at the Director's discretion) are tailored to directly address the potential for large volumes of CO2 to be injected, am ong other factors.

Letter ID: 0122 Comment ID: 24748 Letter Lines: 251 to 255

14Comment Code: 1250 1.1.1.4 Flexibility is needed (p erformance-based standards)

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

Comment: 5. EPA should provide more flexibiilty in operation. For example, allow an EOR operator to demonstrate that CO2 is se questered, and instead of a 10-year default period for reevaluation of the ar ea of review, allow the timing for such

reevaluation to be determined based on site-specific characteristics and sitespecific monitoring of the CO2 plume and pressure front.

Individual Response: EPA disagrees that the GS regulati on should include performance-based standards for AoR calculation. However, EPA be lieves that considera tion of site-specific conditions is appropriate for th e AoR calculation and reevaluation process. EPA believes that the flexibility incorporated into the AoR and co rrective action plans and the provision for AoR reevaluation as required at §146.84( e) provide for an ongoing review of the site and a dialogue

between the Director and the owne r or operator to ensure that th e most appropriate modeling and corrective action technologies are used to protect USDWs from endangerment.

However, EPA believes that setting a minimum reevaluation frequency is appropriate. In the final rule, the Agency changed the minimum fr equency for the AoR reevaluation at §146.84(e) from 10 years to at least every 5 years in the final GS rule. EPA belie ves that this revised frequency addresses commenters' concerns about the inherent uncertainties in modeling CO2 movement, the emerging nature of GS technology, risk-based targeting of monitoring activities, and the unique nature of CO2 GS.

Letter ID: 0122 Comment ID: 24749 Letter Lines: 257 to 258

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 CFR 146.90)

Comment: 6. EPA should provide more flexibility in the requirements for monitoring, testing and reporting. For example,

Individual Response: EPA agrees that monitoring plans and methods need to be site-specific and believes that the monitoring requirements for GS sites at §146.90 provide an appropriate level of flexibility in structuring a testing 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

15injection 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 Director for specific GS projects.

Letter ID: 0122 Comment ID: 24750 Letter Lines: 258 to 262

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

Comment: testing and reporting. For example,

a. revisit the requirement for an n eed annulus liquid level indicator;

b. delete the requierment for th e down hole shut off valve;

Individual Response: EPA believes that knowing annulus fluid volume, as required at §146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that monitoring the annulus fluid volume added is su fficient to meet the intent of continuous monitoring of the pressure on th e annulus. The final GS rule at §146.90 (b), requires that owners or operators use continuous reco rding devices to monitor injecti on pressure, rate and volume; the pressure on the annulus between the tubing and the long string casing; and the annulus fluid

volume added.

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.

16Letter ID: 0122 Comment ID: 24751 Letter Lines: 264 to 265

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment)

Comment: b. allow the Director to determine the fr equency of mechnical integrity tests, with a minimum of 5 years;

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 supercritical CO2, and the buoyant nature of th e 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.

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd appropriate documentation are being collected,

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

Letter ID: 0122 Comment ID: 24752 Letter Lines: 267 to 269

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

Comment: c. delete references to air and soil ga s monitoring, since such monitoring is a

case of too little too late - and can re sult in false positives due to ambient variability; and

Individual Response: EPA acknowledges that air and soil gas monitoring are subject to variability and may not be suitable in all se ttings as a method to ensure USDW protection. However, EPA does not believe that this should en tirely preclude their use. For example, if a leak to the surface is suspected, surface monito ring could provide vital information on its location and magnitude to assist owners and operators in identifying what USDWs may have been impacted by a leak. EPA clarifies that the various air and soil gas monitoring methods (e.g., chambers, eddy covariance, hyperspectral imaging) all have different capab ilities that may prove useful in specific GS project s (Miles et al., 2005; Pickles and Cover, 2005; IPCC, 2005; Menzies et al., 2001). The occurrence of false positives will be reduced by comparing monitoring data to baseline data collected prior to injection or from a nearby area away from the GS project.

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the

discretion of the Director as a means of identif ying leaks that may pose a risk to USDWs and

17informing emergency notification of a Class VI ow ner or operator and UIC Director in the event of a USDW endangerment, pursu ant to requirements at §146.91(c). EPA cl arifies that the decision to use surface monitoring and the selecti on of monitoring methods will be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on potential risks to USDWs within the AoR.

Letter ID: 0122 Comment ID: 24753 Letter Lines: 271 to 272

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

Comment: d. delete references to tracers, because of the numerous problems discussed in the preamble.

Individual Response: EPA agrees that tracer use is not appropriate in all situations, and recognizes that some factors (e.g., the potential to contribute GHGs to the atmosphere, cost, and difficulties associated with monitoring for trace rs) may make other methods of tracking CO2 movement more practical. For this reason, EPA does not require the use of tr acers at all GS sites. Rather, the Director has discretion to require their use if he/she de termines that the use of tracers could improve monitoring of the site and e nhance USDW protection from endangerment.

EPA clarifies that there are many different types of tracers and not all are problematic; research is being done to overcome problems with existing tracers. EPA believes that tracers have been used safely and successfully in other applic ations. 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 project s. EPA will continue to track research related to tracer use and plans to, every si x years, collect and review da ta 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: 0122 Comment ID: 24754 Letter Lines: 274 to 278

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

Comment: 7. EPA should provide for performance-ba sed requirements for Closure and Post Closure Care. For example, the appropria te length of time for post-injection site care should be determined by specific conditions and characteristics of the site, and monitoring of the pressure to determine the point at which the injection zone pressure is such that USDWs cannot be impacted.

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 rule offers owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion

18to shorten or lengthen the PISC timeframe durin g the PISC period based on site-specific data, pursuant to requirements at §146.93(b) ; or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, based on substantial data during the permitting process, that an alternative PISC timeframe may be appropriate if it ensures 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.

Letter ID: 0122 Comment ID: 24755 Letter Lines: 297 to 303

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

USDW

Comment: §144.6 Classification of wells.

{The proposal includes in the definition of "Class VI" the re striction that injection into such wells must be "ben eath the lowermost formation containing a USDW." RRC suggests either removing th e restriction or ad ding "or another formation, if the Director determines th at injection into th e other formation will be protective of USDWs." }

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 injecti on into non-USDW formations above and/or between USDWs. The

final rule also establishes limited circumstances under which expansions of the areal extent of aquifer exemptions may be granted for owne rs or operators of Class II EOR/EGR wells transitioning to Class VI injec tion for GS. Additionally, the final GS rule does not categorically preclude or prohibit in jection 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

19protected; 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 qua ntities to supply drinking water needs. For additional information on the waiver approach and aquifer exemptions for Class VI wells, please see the final rule and preamble, as well as EP A's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 0122 Comment ID: 24756 Letter Lines: 307 to 312

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

Comment: §144.36 Duration of permits.

{We agree with the proposal to issue pe rmits for UIC wells associated with sequestration of CO2 "for the period up to the operating life of the facility."

The substantial financial investment in a project makes a permit for the operating like of the facility imperitive. }

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)). The rule also requires the Director to review the permit at least once every 5 years to determine whether it should be modified, revoked and reissued, termin ated or a minor modification made as provided in §§144.39, 144.40, or 144.41. EPA believes that the iterative process of developing and executing the various plans required of GS well ope rators under the final rule (e.g., for AoR and corrective action, te sting and monitoring, injection well pl ugging, post-injection site care, and emergency and remedial response) is tailored to the unique aspect s of—and is more appropriate for–GS than establishing a finite permit dur ation (e.g., five years as suggested by some commenters). EPA adds that the required revi ews of the AoR and corrective action plan, the testing and monitoring plan, and the emergency and remedial res ponse plan thr oughout the life of the project (at least every 5 years) are preferable to a pe riodic permit reapplication. The iterative process and subsequent plan reevaluati ons ensure that time and resources are committed to the most critical aspects of the perm it in preventing endangerment to USDWs.

Letter ID: 0122 Comment ID: 24757 Letter Lines: 314 to 320

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

USDW

Comment: Part 146 UIC Program Cr iteria and Standards

§146.5 Classification of injec tion wells. (f) Class VI.

20{The proposal includes in the definition of "Class VI" the re striction that injection into such wells must be "ben eath the lowermost formation containing a USDW."}

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. The final rule also establishes limited circum stances under which expansions

of the areal extent of aquifer exemptions may be granted fo r owners or operators of Class II

EOR/EGR wells transitioni ng to Class VI injection for GS. A dditionally, the final GS rule does not categorically preclude or prohibit injection into any type of formation.

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: 0122 Comment ID: 24758 Letter Lines: 322 to 340

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

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

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

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

Comment: Subpart H--Criteria and Standards Applicable to Class VI Wells

§146.81 Applicability.

(a) This subpart establishes criteria a nd standards for UIC programs to regulate Class VI CO2 GS injection wells. (b) This subpart applies to wells used to inject CO2 specifically for the purpose of GS, i.e., the long-term containment of a gaseous, liquid or supercritical CO2 stream in subsurface geologic formations. (c) This subpart applies to ow ners and operators ofpermit or ruleauthorized Class I industri al, Class II, or Class V e xperimental CO2 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 discretion, from the casing and cementing requirements at §§146.86( b) and 146.87(a)(1) through (3).

{RRC agrees that the Director evaluati ng a permit applicatio n to use existing injection wells for geologic sequestration should have the discretion to exempt wells from Class I industrial, Class II or Class V wells from the proposed casing and cementing requireme nts of Class VI wells. }

Individual Response: EPA agrees that many Class I, Cl ass II, and Class V experimental

21technology 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 clarifies that only the construction requirements are grandfathered and that all other Class VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met fo llowing a determination under §146.81(c).

Letter ID: 0122 Comment ID: 24759 Letter Lines: 372 to 381

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: Geologic sequestration project means an injection well or wells used to emplace a CO2 stream beneath the lowerm ost formation containing a USDW, OR ANOTHER FORMATION, IF THE DIRECTOR DETERMINES THAT INJECTION INTO

THE OTHER

FORMATION WILL NOT ENDANGER USDWS. It in cludes the subsurface 3-D extent of the carbon dioxide plume, associated pressure front, and displaced brine, as

well as the surface area above that delineated region.

{RRC suggests adding to the end of the first sentence of the definition of Geologic sequestration proj ect, "or another forma tion, if the Director determines that injection into the other formation will not endanger USDWs." }

Individual Response: EPA disagrees with the suggested edit. However, the Agency has

modified the final definition of geologic sequestration project at §146.81(d) to read as follows: “[A]n injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation containing a USDW; or, wells used for geologic sequestration of carbon dioxide that have been granted a waiver of the injection depth requirement s pursuant to requirements at §146.95; or, wells used for geolog ic sequestration of carbon dioxi de that have received an aquifer exemption expansion. It includes the su bsurface three-dimensional extent of the carbon dioxide plume, associated pressure front, and di splaced brine, as well as the surface area above that delineated region.”

EPA adds that the final rule contains a new provi sion for owners or operato rs to seek a waiver from the injection depth requirements, at §146.95. Based on its evaluation of all public comments and input on the proposed rule and the Notice of Data Availability 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: 0122 Comment ID: 24760 Letter Lines: 392 to 398

Comment Code: 1220 1.1.1.1 Terminology and definitions

22Comment: Pressure front means the zone of elevat ed pressure that is created by the injection of carbon dioxide into the s ubsurface. For the purposes of this subpart, the pressure front of a carbon di oxide plume refers to a zone where there is a pressure differential suffi cient to cause the movement of injected fluids or formation fluids into a USDW.

{Why does this definition need to be different?}

Individual Response: The definition of a pressure front is unique to the Class VI GS requirements and Subpart H to address the unique nature of CO2 injection for GS, including the potential impact a pressure front may have on USDWs. The final de finition of pressure front at §146.81(d) is unchanged, and reads as follows: “[T]he zone of elevated pre ssure that is created by the injection of carbon dioxide into the subs urface. For 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: 0122 Comment ID: 24761 Letter Lines: 404 to 407

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: Transmissive fault or fracture means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between formations.

{Recommend that the fault or fracture be "known."}

Individual Response: EPA disagrees with the suggested edit. The final definition of transmissive fault or fracture at §146.81(d) is unchanged and reads as follows: “[A] fault or fracture that has sufficient permeability and vertic al extent to allow fl uids to move between

formations.”

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: 0122 Comment ID: 24762 Letter Lines: 436 to 438 ; 442 to 446

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

23comment)

Comment: (2) Location, orientation, and propertie s of known or suspected faults and fractures that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment;

(4) Data on the depth, areal extent , thickness, mineralogy, porosity, permeability and capillary pressure of the injection and confining zone(s) ; including geology/facies changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions;

Individual Response: EPA believes that the plural for injection zone(s) s hould be retained in the Final Rule in recognition of the f act that more than one injection zone may be used at some GS sites. EPA believes that in some geologic settings, the presence and identification of additional confining and containment zones above the pr imary (i.e., lowermost) confining zone can improve USDW protection. These formations c ould further impede vertical fluid movement, allow for pressure dissipation, and provide a dditional sites for monitoring, mitigation, and remediation, while also affording the greatest protection of USDWs from endangerment. While other countries may not require such additi onal protection, EPA believes that providing the Director this additional discretion is an important element of assuring that GS activities will not endanger USDWs.

Please see the final rule and the discussion of geologic site charact erization in the preamble for

additional information.

Letter ID: 0122 Comment ID: 24763 Letter Lines: 452 to 459

Comment Code: 1220 1.1.1.1 Terminology and definitions

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

Comment: (e) A tabulation of all wells within the AOR which penetrate the injection or confining zone(s) . Such data must include a desc ription of each well's type, construction, date drilled, locati on, depth, record of plugging and/or completion, and any additional inform ation the Director may require;

{Definition of confining zone includes multiple formations. Do not imply that multiple confining zones are preferable to one (good) confining zone.}

Individual Response: EPA disagrees with the suggested ed it. The final language in §146.82 is unchanged. EPA retains the requirement to identi fy additional containment/confining zones, if required by the Director, as proposed in §146.83(b). EPA acknowle dges that such additional zones may not be needed in all circumstances, a nd clarifies that this requirement is at the Director's discretion, based on his or her understanding of a particul ar site. EPA believes that, in some situations, the presence of additional confining and containment zones above the primary

24(i.e., lowermost) confin ing zone can improve USDW protection. These layers could further impede vertical fluid movement and allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and remedia tion. The Agency's decision is supported by commenters representing states, water associations, and an electric utility who assert that these requirements promote a flexible, risk-based, s ite-specific approach to characterizing and permitting a site for GS projects, and would impr ove understanding of the pr oject as a whole and promote better modeling of the site.

Additionally, the Agency has modified the final de finition of confining zone to read as follows: “[A] geologic formation, group of formations, or part of a formation stratigraphically overlying the injection zone that acts as barrier to fluid movement. For Class VI wells operating under an injection depth waiver, confini ng zone means a geologic formation, group of formations, or part of a formation stratigraphically overlyi ng and underlying the injection zone.”

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: 0122 Comment ID: 24764 Letter Lines: 461 to 466

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: (f) Maps and stratigraphic cross sections indicating th e general vertical and lateral limits of all USDWs, water wells and springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known;

{Consistency with definition and use of term in other areas of the rules.}

Individual Response: EPA believes that the plural for injection zone(s) s hould be retained in the Final Rule in recognition of the fact that characterizing more th an one injection zone may be necessary at some GS sites. EPA believes th at in some geologic settings, the presence and identification of additional confining and contai nment zones above the primary (i.e., lowermost) confining zone can improve USDW protection. These formations co uld further impede vertical fluid movement, allow for pressure dissipati on, and provide additional sites for monitoring, mitigation, and remediation, while also afford ing the greatest prot ection of USDWs from endangerment. EPA believes that providing the Dire ctor this additional discretion is an important element of assuring that GS ac tivities will not endanger USDWs.

Please see the final rule and the discussion of geologic site charact erization in the preamble for

additional information.

25Letter ID: 0122 Comment ID: 24765 Letter Lines: 478 to 483

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: (i) The compatibility of the CO2 stream w ith fluids in the injection zone and minerals in both the injecti on and the confining zone(s) , based on the results of the formation testing progra m, and with the materials used to construct the well;

{See comment above.}

Individual Response: The final rule will allow the Director to require more than one confining zone; therefore, EPA did not make the suggested change.

Please see the final rule and the discussion of geologic site charact erization in the preamble for

additional information.

Letter ID: 0122 Comment ID: 24766 Letter Lines: 491 to 495

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: (m) Proposed procedure to outline st eps necessary to conduct injection operation;

{"Proposed procedure to outline steps" doe s not make sense. Recommend "Outline of steps ...."}

Individual Response: EPA disagrees that the suggested ed it provides more clarity to the requirements and has retained the language as proposed. Additionally, similar language is used for other UIC well classes and the regulated comm unity and permitting officials are familiar with

the terms.

Please see the final rule and the discussion of geologic site charact erization in the preamble for

additional information.

Letter ID: 0122 Comment ID: 24767 Letter Lines: 522 to 527

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)

26Comment: (1) An injection zone of sufficient ar eal extent, thickness, porosity, and permeability to receive the total antic ipated volume of the carbon dioxide

stream;

{Redundant - simply repeats the definiti on of "injection zone." Either take this language out of the definition or take it out of here.}

Individual Response: EPA acknowledges the comment. For consistency, §146.83(a)(1) includes the definition of injection zone . EPA clarifies that §146.83 identifies the specific criteria that owners or operators must meet to demonstr ate that a GS site is suitable for GS.

Letter ID: 0122 Comment ID: 24768 Letter Lines: 529 to 537

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: (2) A confining zone(s) that is free of transmissi ve faults or fractures and

of sufficient areal extent and integrity to contain the injected carbon dioxide stream and displaced formation fluids a nd allow injection at proposed maximum pressures and volumes without initiati ng or propagating fr actures in the confining zone(s) ; and

{Redundant. Repeats definition of "confin ing zone." Also, implies that the confining zone cannot have a single fract ure, no matter how small. Much more stringent than for Class I hazardous wells.}

Individual Response: EPA believes that the plural for injection zone(s) s hould be retained in the Final Rule in recognition of the fact that characterizing more th an one injection zone may be necessary at some GS sites. EPA believes th at in some geologic settings, the presence and identification of additional confining and contai nment zones above the primary (i.e., lowermost) confining zone can improve USDW protection. These formations co uld further impede vertical fluid movement, allow for pressure dissipati on, and provide additional sites for monitoring, mitigation, and remediation, while also afford ing the greatest prot ection of USDWs from endangerment. While other countries may not re quire such additional protection, EPA believes that providing the Director this additional discretion is an importa nt element of assuring that GS activities will not endanger USDWs.

Letter ID: 0122 Comment ID: 24769 Letter Lines: 539 to 545

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)

27Comment: (b) At the Director' s discretion, owners or operato rs of Class VI wells must identify and characterize additional zone s that will impede vertical fluid movement, are free of faults and fracture s that may interfere with containment, allow for pressure dissipation, and provi de additional opportunities for monitoring, mitigation and remediation.

{Redundant and unnecessary. Language in definition of "confining zone."}

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 permitting 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: 0122 Comment ID: 24770 Letter Lines: 547 to 554

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: §146.84 Area of review and corrective action.

(a) The area of review is the region surrounding the geologic sequestration project that may be impacted by the inje ction activity. The area of review is based on computational mode ling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream.

{Redundant - same as the defini tion of "area of review."}

Individual Response: Based on review of all public comments on the AoR definition at 146.84(a), the Agency has modified it to read as follows: The region surrounding the geologic sequestration project where USDWs may be e ndangered by the injecti on activity. The area of review is delineated using computational mode ling that accounts for the physical and chemical properties of all phases of the injected CO 2 stream and is based on available site characterization, monitori ng, and operational data.

Letter ID: 0122 Comment ID: 24771 Letter Lines: 556 to 562

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

28Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the AOR for a proposed geologic seques tration project, periodically reevaluate the delineation, and perform corrective action that meets the requirements of this section AT A FREQUENCY AND IN A MANNER THAT

and is acceptable to the Director. As a part of the permit application for approval by the Director , the owner or operator mu st submit an area of review and corrective action plan that includes the following information:

Individual Response: EPA disagrees with the suggested cha nge, and is retaining the approach of setting a minimum fixed frequency for reeval uating the AoR but has, based on commenters' input, changed the frequency from 10 years to at least every 5 years, as specified in §146.84(e). EPA agrees with commenters that site-specific in formation is an important factor in determining an appropriate AoR reevaluation frequency, and adds that the owner or operator's AoR and corrective action plan must describe the minimu m fixed frequency for reevaluating the AoR and the site-specific conditions on which this freque ncy is based. EPA adds that the Director will evaluate the proposed plan in connection with a review of a vast amount of geologic and proposed operating data in determining whether to approve the plan. EPA is developing guidance on recommended approaches for preparing all of the required GS project plans, which will address considerations for determining an appr opriate AoR reevaluation schedule. The guidance will be available on EPA's web site, at http://water.epa.gov/type/groundwater /uic/wells_sequestration.cfm.

Letter ID: 0122 Comment ID: 24772 Letter Lines: 569 to 576

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 Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action plan

Comment: (2) A description of: (i) The minimum fi xed frequency, not to exceed 10 years, the owner or operator proposes to re evaluate the area of review; (ii) The monitoring and operational c onditions that would warrant a reevaluation of the area of review prior to the next scheduled reevaluation as determined by the minimum fixed frequency established in paragraph (b)(2)(i) of this section.

{Suggest that there be no minimum fixed frequency for reevaluation of the AoR,

but that such review be based on site-specific circumstances. }

Individual Response: EPA believes that periodic AoR reevalua tion at a set frequency of at least every 5 years is necessary to ensure protecti on of USDWs from endangerment 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

29reevaluations 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: 0122 Comment ID: 24773 Letter Lines: 578 to 589

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: (II)(iii) How monitoring and operational da ta (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; and

(iv) How corrective action will be conduc ted to meet the requirements of paragraph (d) of this section, includi ng what corrective action will be performed prior to injection 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 THE site WILL BE accessed will be guaranteed for

future corrective action.

{Word Choice. Secure rath er than guarantee. }

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 mostly like ly 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. For this reason, the ow ner or operator must describe in the AoR and corrective action plan how site access will be guaran teed for future corrective action, as specified in §146.84(b)(2)(iv). The final rule re tains the requirement as proposed.

Letter ID: 0122 Comment ID: 24774 Letter Lines: 595 to 600

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: (1) Predict, using computational modeli ng, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activ ities until the plume movement ceases, pressure differentials sufficient to cause the movement of injected fluids or

30formation fluids into a USDW ar e no longer present, or FOR after a fixed time period as determined by the Director. The modelINGmust:

Individual Response: EPA has clarified this language in the final rule. It now reads, “Predict, using existing site character ization, monitoring and operati onal data, and computational modeling, the projected lateral and vertical migr ation of the carbon dioxide plume and formation

fluids in the subsurface from the commence ment of injection ac tivities until the plume movement ceases, until pressure diffe rentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer pres ent, or until the end of a fixed time period as determined by the Director.”

Letter ID: 0122 Comment ID: 24775 Letter Lines: 602 to 609

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: (i) Be based on detailed ge ologic data collected to ch aracterize the injection zone AND, confining zone and any additional zones ; and anticipated operating data, including injection pressu res, rates and total volumes over the proposed life of the geol ogic sequestration project; (ii) Take into account RELEVANT any geologic heterogeneities AND, data quality, and their possible imp act on model predictions; and (iii) Consider potential migration through KNOWN fa ults, fractures, and artificial penetrations.

Individual Response: The final rule retains this requi rement as proposed, except that 146.84(c)(1)(ii) also requires owners or operators to take into account other discontinuities in addition to geologic heterogeneities.

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.

Letter ID: 0122 Comment ID: 24776 Letter Lines: 611 to 616

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: (2) Using methods approved by the Direct or, identify all KNOWN ARTIFICIAL penetrations THROUGH THE CONFINING ZONE, including act ive and abandoned 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 drilled,

31location, depth, record of plugging and/ or completion, and any additional information the Director may require; and

Individual Response: EPA is retaining this requiremen t 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.

Letter ID: 0122 Comment ID: 24777 Letter Lines: 618 to 620

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

Comment Code: 3400 2.2.2 Corrective Action

Comment: (3) Determine which abandoned wells in th e AOR have been plugged in a manner that prevents the movement of CO2 or FORMATION associated fluids that may endanger USDWs.

Individual 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..."

Letter ID: 0122 Comment ID: 24778 Letter Lines: 622 to 626

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: (d) Owners or operators of Class VI wells must perform corrective action USING CORROSION RESISTANT MATERIAL, WHEN AP PROPRIATE, on all wells IDENTIFIED

IN §146.84(C)(2) in the AOR t hat are determined to n eed corrective action using methods necessary to prevent the moveme nt of fluid into or between USDWs including use of corrosion resist ant materials, where appropriate.

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

32commenters' concerns and is also consiste nt with other language regarding materials requirements in the GS rule.

Letter ID: 0122 Comment ID: 24779 Letter Lines: 631 to 633

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: (f) At the minimum fixed frequency, not to exceed 10 years, as AS specified in the AOR and corrective action plan, or when monitori ng and operational conditions warrant, the owne r or operator must:

Individual Response: EPA believes that periodic AoR r eevaluation at a set frequency is necessary to ensure protecti on of USDWs from endangerment and address the uncertainties inherent in predictive modeling. Periodic Ao R reevaluations at §146.84( e) ensure that a deliberate effort is made to verify, based on m onitoring and operational da ta, that the CO2 plume is moving within the subsurface as predicted. EP A believes that less frequent reevaluations may not be sufficient to appropriately model plume a nd pressure front moveme nt, establish conditions for corrective action, and ensure prot ection 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.

Based on the comments received (including those by water associati ons, an energy company, associations, industries, states, and envir onmental groups), EPA has changed the minimum frequency for the AoR reevaluation from 10 years to at least every 5 year s. EPA believes that this revised frequency addresse s commenters' concerns about th e inherent uncertainties in modeling CO2 movement, the emerging nature of GS technology, risk-b ased targeting of monitoring activities, and the unique nature of CO2 GS.

Letter ID: 0122 Comment ID: 24780 Letter Lines: 642 to 649

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: (4) Submit an amended AOR and corrective action plan or demonstrate to the Director through monitoring da ta and modeling results that no CHANGE amendment to the AOR and corrective action plan is needed.

{Appropriate frequency of determining Ao R might not be "fixed." Owner or operator might need to reevaluate AoR fre quently at first, particularly with deep brine formations about which there is little history, and then at expanding

intervals as more in formation is known.}

33Individual Response: EPA agrees that site-specific fact ors should be considered in the reevaluation schedule, and notes that the AoR and corrective acti on plan must specify the sitespecific monitoring and operationa l conditions that warrant r eevaluation, as specified in §146.84(b)(2)(ii). In addition, the Director has discretion to require more frequent AoR

reevaluation if he or she has r eason to believe, based on site-speci fic information, that a five-year

reevaluation schedule is not su fficiently protective of USDWs. However, EPA believes that setting a minimum reevaluation frequency is appr opriate. In the final rule, the Agency changed the minimum frequency for the AoR reevaluation at §146.84(e) from 10 years to at least every 5 years in the final GS rule. EPA believes that this revised frequency addresses commenters'

concerns about the inherent unc ertainties in modeling CO2 move ment, the emerging nature of GS technology, risk-based targeti ng of monitoring activ ities, and the unique nature of CO2 GS.

Letter ID: 0122 Comment ID: 24781 Letter Lines: 683 to 690

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: §146.86 Injection well construction requireme nts. (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:

(1) Prevent the ENDANGERMENT OF USDWs movement of flui ds into or between USDWs or into any unauthorized zones ; (2) Permit the use of appropriate tes ting devices and wor kover tools; and (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing.

Individual Response: EPA disagrees with the suggested ed it. EPA believes that protection of USDWs from endangerment and prevention of fluid movement between formations is paramount, and believes that the language as pr oposed regarding preventing fluid movement is more specific and protective. A ppropriately designed and constr ucted wells are necessary to prevent endangerment to USDWs and maintain in tegrity of the well thro ughout the lifetime of a GS project. This is the foundation of the requ irements for construc tion and pre-operational testing of Class VI wells at §§146.86 and 146.87.

Letter ID: 0122 Comment ID: 24782 Letter Lines: 692 to 707

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

Comment Code: 3860 2.3.3 Well component degradation

Comment: (b) Casing and Cementing of Class VI Wells.

(1) Casing and cement or other materials us ed in the construction of each Class

VI well must have sufficient structural strength and be designed for the OPERATING life of the WELLgeologic sequestration project . All well

34materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the API, ASTM International, or comparable standa rds acceptable to the Director. The casing and cementing pr ogram must be designed to prevent

the movement of fluids into or between USDWs. In order to allo w the Director to determine and specify casing and ce menting requirements, the owner or operator must provide the following information:

{The threat to the integrity of the cas ing and cement and other materials is greatest during injection, and quickly decreases as the pressure dissipates after cessation of injection. }

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 post-injection site care period and beyond. While the risk profile of a GS site will decrease following cessation of in jection, 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 fo r movement of fluids

associated with future injection operations.

Letter ID: 0122 Comment ID: 24783 Letter Lines: 709 to 721

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: (i) Depth to the injection zone; (ii) Injection pressure, exte rnal pressure, internal pre ssure and axial loading; (iii) Hole size; (iv) Size and grade of all casing stri ngs (E.G., wall thickness, external diameter, nominal weight, length, joint specification and construction material); (v) Corrosiveness of the carbon dioxid e stream, and formation fluids; (vi) Down-hole temperatures AND PRESSURES; (vii) Lithology of injecti on and confining zones; (viii) Type or grade of ceme nt, INCLUDING ADDI TIVES; and (ix) Quantity, chemical composition, and temperature of the CO2 stream.

{Redundant - look at app lication requirements.}

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

35of cement and cement additives."

EPA clarifies that informati on on down-hole pressures is re quired at §146.86(b)(1)(ii).

Letter ID: 0122 Comment ID: 24784 Letter Lines: 723 to 724

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: (2) Surface casing must extend through th e base of the lowermost USDW ABOVE

THE

INJECTION ZONE and be cemented to the surface.

Individual Response: EPA disagrees with the suggested edit . The final GS rule at §146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and be cemented to the surface through the use of a single string or multiple strings of casing and cement.

EPA stresses that protection of USDWs from en dangerment, regardless of their depth or the number of USDWs in an area, is the primary mission and mandate of the UIC program and the purpose of all requirements for injection wells. A ny injection activity must be demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, the activity will not be allowed unde r UIC requirements or the SDWA.

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 Class VI wells operating under in jection depth waivers must comply with additional cons truction requirements to ensure th at wells used to inject above or between USDWs are protective. EPA believes that, given the possi bility for Class VI wells to operate under injection depth waivers, the requi rement that surface casing must extend through

the base of the lowermost USDW is important for USDW protection.

Letter ID: 0122 Comment ID: 24785 Letter Lines: 726 to 735

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: (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

{Circulation of cement unnece ssary and more stringent th at requirement for Class I hazardous waste wells. RRC suggests that it may not be technically feasible to cement the full column of one long st ring casing because the formations you likely want to inject into are low-pr essure, and typically won't hold a full

36column of cement, making circulation im possible. RRC suggests a certain footage of cement, such as 600 ft, and require a bond log to verify it. }

Individual Response: EPA believes that the construc tion requirements at §146.86 offer flexibility to the owner or opera tor to propose well construction procedures that are appropriate to the site-specific cond itions of the project. Section 146.86( b)(3) requires that the long-string casing extend to the injection zone and be cemen ted by circulating cement 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 ope rator to propose alternate methods to provide a sufficient amount

of cement to meet the standard that USDWs ar e protected from endangerment, subject to the approval of the Director. EPA notes that there are many potential ways to meet the requirement, such as the use of staged cementing.

EPA believes that current cemen ting technology can address deep well cement columns or lowpressure bottom-of-hole formations. The oil and gas industry has e xperience drilling and cementing wells in very deep formations and in formations with low pressures. Less dense, lighter weight cement slurries th at include nitrogen foam or lightweight microspheres (Sabins 2002; Kulakofsky et al. 2005) are used to preven t breakdown of the low pressure formation and loss of circulation. Another way to approach low formation pressure conditions is with reverse cementing (pumping the cement into the annulus and returning it thr ough the casing). This method uses gravity to place the cement and bypass lost circulation zones. Reverse cementing

can be combined with other methods such as foam cement. Ten successful reverse-cemented wells have been completed in a variety of onshore/offshore environments (Chase 2008).

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: 0122 Comment ID: 24786 Letter Lines: 742 to 749

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: (5) 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 W ELL geologic sequestration project . The integrity and location of the cement sha ll be verified using technology capable of evaluating cement quality radially and identifying th e location of channels to ensure that USDWs are not endangered.

{See comment above.}

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

37wells. 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 post-injection site care period and beyond. While the risk profile of a GS site will decrease following cessation of in jection, 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 fo r movement of fluids

associated with future injection operations.

Letter ID: 0122 Comment ID: 24787 Letter Lines: 759 to 768

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: (i) Depth of setting; (ii) Characteristics of the CO2 stream (chemical content, corrosiveness, temperature, and density); (iii) Injection pressure; (iv) Annular pressure; (v) Injection rate (intermittent or c ontinuous) and volume of the CO2 stream; (vi) Size of casing; and (vii) Tubing tensile, burst, and collapse strengths.

{Repetitive - See applic ation requirements}

Individual Response: EPA acknowledges that some of the information required under §146.86(c)(3) is also required under §146.82(a)(7 ) as part of the proposed operating requirements. However, EPA notes that the Direct or needs to consider all of the data required under §146.86(c) in order to properly determin e the tubing and packer specifications, and

believes this information s hould be provided together.

Letter ID: 0122 Comment ID: 24788 Letter Lines: 820 to 821

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: (c) The owner or operator must record th e fluid temperature, pH, conductivity, reservoir pressure and the static fluid level of the injection zone(s).

Individual Response: The text at §146.87(d) as written requ ires data on the injection zone and confining zone or zones. This is to ensure that, if the Dire ctor requires characterization of

additional containment/confini ng zones (§146.83(b)), appropri ate data are collected.

38Letter ID: 0122 Comment ID: 24789 Letter Lines: 823 to 824

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: (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s) :

Individual Response: The text at §146.87(d) as written requ ires data on the injection zone and confining zone or zones. This is to ensure that, if the Dire ctor requires characterization of

additional containment/confini ng zones (§146.83(b)), appropri ate data are collected.

Letter ID: 0122 Comment ID: 24790 Letter Lines: 845 to 850

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: (a) Except during stimulation, the owner or operator must ensure that injection pressure does not exceed 90% of the fractur e pressure of the injection zone so as to assure that the injection does no t initiate new fractur es or propagate existing fractures 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.

Individual Response: EPA disagrees with the suggested edit. The rule affords the Director discretion to require more than one confining zone, as specif ied at §146.83(a)(2). Where more than one confining zone is required, EPA believes that each confining z one provides a layer of protection for USDWs and should remain intact. See the preamble discussion geologic siting requirements for additional information.

Letter ID: 0122 Comment ID: 24791 Letter Lines: 866 to 879

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: (e) The owner or operator must install a nd use continuous recording devices to monitor: The injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volum e; and must install and use alarms

and automatic down

- hole shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge beyond permitted ranges and/or gradients specified in the permit;

{RRC suggests that the rule not require automatic shutdown. Experience in the

39field has been that ESDs are notorious for high maintenance, and continuous monitoring will sufficiently alert the operator of a need to shut down operations. In addition, such a requirem ent is more stringent than that required for Class I ha zardous waste wells.}

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

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

discretion to mandate automatic down-hole shut -off devices in onshore situations that may warrant their use. The rule requ ires, at §146.88(e)(3) that owners or operators of offshore wells

within State territorial waters instal l automatic down-hole shut-off systems.

EPA recognizes that down-hole shut-off devices may make well maintenance and operation more challenging. However, the bu oyant nature of CO2 and the elevated injection pressures

associated with GS increase the likelihood of an uncontrolled flow of CO2 out of the well, which may endanger USDWs. If CO2 does begin to flow back up an injection well, it will rapidly cool and expand as it moves toward the surface and can result in a stream of solid CO2 which can cause damage to the wellhead and other well instrumentation; such damage has been documented in CO2 ER wells (Skinner, 2003; Du ncan et al., 2008). Additionally, the Agency believes that offshore Class VI wells present unique construction and operational conditions, including isolation from shorelin es and the need to construct we lls through the water column and the subsurface, which may delay response time in the event of well difficu lties. Automatic shutoff devices can help prevent further well compli cations, and EPA believes affording Director's discretion to require down-hole de vices where necessary ensures that proper precautions are taken to prevent subsurface fluid movement and ensure protection of USDWs, human health, and

the environment.

EPA believes that requiring auto matic surface shut-off devices instead of down-hole devices provides more flexibility to owne rs or operators when performi ng required mechanical integrity tests. Additionally, this requireme nt addresses concerns about risk s associated with routine well workovers that may be complicat ed by the presence of down-hole de vices while still maintaining USDW protection.

Letter ID: 0122 Comment ID: 24792 Letter Lines: 881 to 886

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: (f) If a down

- hole automatic shutdow n is triggered or a loss of mechanical integrity is discovered, the owner or oper ator must immediately investigate and identify as expeditiously as po ssible the cause of the shutoff . If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) of this section otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must:

40Individual Response: As described above, after evaluating the risks and benefits of down-hole shut-off systems and considering additional rese arch, EPA will not require automatic down-hole

shut-off devices for onshore Class VI wells sin ce it is not necessary in all cases to ensure protection of USDWs from endangerment. Inst ead, the final rule, at §146.88(e)(2), affords

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

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

offshore wells within State territorial waters install automatic down-hole shut-off systems.

Letter ID: 0122 Comment ID: 24793 Letter Lines: 904 to 910

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: (b) To evaluate the absence of signi ficant leaks under pa ragraph (a)(1) of this section, owners or operators must, following an initia l annulus pressure test, continuously monito r injection pressure, rate, injected volumes, and

pressu re on the annulus between tubing and long stem casing and annulus fluid volume as specified in §146.88(e);

{Redundant language.}

Individual Response: The final rule retains this text to provide clarity about requirements for demonstrating internal mechanical integrity and to specify the n ecessary monitoring. EPA believes that continuous pressure monitoring to demonstrate internal mechanical integrity of Class VI wells (146.89(b)), instead of periodic tes ting (which is required for most other types of deep injection wells) is important given the pot ential corrosive impact of CO2 and impurities on well materials, the potential geomechanical impact s to well integrity due to CO2 phase changes, and the temperature and pressure effects as sociated with injecting supercritical CO2.

For additional information, please see the discus sion of MITs in the final rule preamble.

Letter ID: 0122 Comment ID: 24794 Letter Lines: 975 to 977

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

Comment Code: 4660 2.6.6 Geochemical monitoring

Comment: (d) Periodic monitoring of the ground wate r quality and geochemical changes above the confining zone(s) that may be a result of carbon dioxide movement through the confining zone or additional identif ied zones:

41Individual Response: Regarding monitoring locations, se ction §146.90(d) requ ires periodic monitoring of the ground water qua lity and geochemical changes above the confining zone(s). EPA clarifies that this monitoring requirement does not include the confining layer itself. Monitoring above the confining layer will provide an indication of upward movement of CO2 that might endanger a USDW. The exact number of formations to be tested must, however, be based on site-specific characteri stics and vulnerabilities and desc ribed in the Director-approved testing and monitoring plan.

Letter ID: 0122 Comment ID: 24795 Letter Lines: 986 to 992

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: (e) A demonstration of external mechanic al integrity pursuant to §146.89(c) at least once per year throughout the duration of INJECTION the geologic sequestration project;

{Demonstration of external mechanical in tegrity should not be necessary after cessation of injection and (relatively imme diate) dissipation of pressure near the wellbore resulting from injection.}

Individual Response: In the final rule, EPA has revised th e text at §144.90(e) to specify that owners or operators must demonstrate internal MI at least once per year until the well is plugged.

Letter ID: 0122 Comment ID: 24796 Letter Lines: 997 to 1004

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: (g) Testing and monitoring to track the ex tent of the carbon dioxide plume and the position of the pressure front by e ither monitoring for pressure changes in the first formation overlying the confining zone or using indirect, geophysical techniques (e.g., seismic, el ectrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools);

{If there are changes in the first formation overlying the confining zone, the carbon dioxide stream has not been confined.}

Individual Response: The final rule, at §146.90(g), requires owners or operators to perform monitoring to track the extent of the CO2 plume and pressure fr ont. The owner or operator must use direct methods to monitor for pressure chan ges in the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hol e CO2 detection tools) are required unless the Director de termines, based on site-specific geology that such methods are not appropriate

42EPA 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. When combined with information on temperature, pressure data pr ovide an indication of the phase (e.g., gas, supercritical) and distribution of the injected CO2 (73 FR 43515) . Monitoring can also identify needed remedial actions, provide inputs for AoR reevaluation m odeling, evaluate predictions of plume movement, and target additional ge ochemical and surface monitoring needs.

EPA adds that owners or operators may cons ider (or the Director may require) performing additional pressure monitoring in wells that are above the confining zone (e.g., in the same wells used to perform ground water quality monitoring required at §146.90(d)) to provide additional verification that no pressure cha nges are occurring above the confining zone due to CO2 leakage. The final rule, at §146.90(d), also requires geoc hemical monitoring above the confining zone.

Letter ID: 0122 Comment ID: 24797 Letter Lines: 1006 to 1022

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: (h) At the Director's discretion, su rface air monitoring and/or soil gas monitoring to detect movement of carbon dioxide that could endanger a USDW. (1) The testing and monitoring plan must be based on potential vulnerabilitie s within the area of review; (2) The mon itoring frequency and spatial distribution of surface air monitoring and/or soil ga s monitoring must reflect baseline data and the monitoring plan must include how the proposed monitoring will yield

useful inform ation on the area of review delin eation and/or compliance with standards under 40 CFR 144.12;

{Any requirement for surface air monitoring and/or soil gas monitoring is not warranted. If the purpose is to detect "movement of carbon dioxide that could endanger a USDW, it would be too late if ca rbon dioxide were detected in the air or soil. In addition, levels of ambien t carbon dioxide are too variable for this to be useful. RRC suggests elimin ating any potential requirement for surface air or soil gas monitoring, because formation monitoring should catch whatever condition might reasonably be exp ected to be caught by surface or soil gas monitoring. }

Individual Response: EPA acknowledges that air and soil gas monitoring to ensure USDW protection is not necessary at a ll GS sites and believes that th e decision to use surface monitoring and the selection of monitoring methods for th e purpose of USDW protection will be sitespecific. In the final rule, at §146.90(h), the decisi on to require such monitoring as an additional measure to ensure USDW protection rests with the Director as a means of identifying leaks that may pose a risk to USDWs and informing emer gency notification of a Class VI owner or operator and UIC Director in the event of a US DW endangerment, pursuant to requirements at §146.91(c).

43EPA clarifies that subsurface geochemical and pr essure monitoring in the subsurface formations are the first line of monitoring that would allow detection of potential endangerment to USDWs from GS activities (this is requi red at all GS sites, as descri bed at §146.90(d)). The Agency also

believes that surface air and soil gas monitoring, when coupled with subsurface monitoring, may be appropriate at some GS pr ojects to ensure USDW protection. EPA acknowledges that surface air and soil gas monitoring may not be suitable in all settings as a method to ensure USDW protection. However, EPA does not believe that th is should entirely pr eclude their use. The decision to use surface monitoring and the selecti on of monitoring methods will be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on potential risks to USDWs within the AoR.

Letter ID: 0122 Comment ID: 24798 Letter Lines: 1100 to 1104

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: (1) The owner or operato r must submit the post

- injection site care and site closure plan as a part of the permit applic ation to be approved by the

Director.

{Redundant - See 146.82(w).}

Individual Response: EPA clarifies that the reference to the post-injection site care and site closure plan, in the final rule at §146.82(a)(17), requires that the plan be included in the attachments to the Class VI permit application. Th e details of the plan contents are included in §146.93, along with other requirements related to pos t-injection site care and site closure.

Letter ID: 0122 Comment ID: 24799 Letter Lines: 1109 to 1117

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: (i) The pressure differential between pre- injection and predicted post-injection pressures in the injection zone; (ii) The predicted position of the carbon dioxide plume and associated pressure front at site clos ure as demonstrated in the AOR evaluation required under §146.84(b) ; (iii) A description of postinjection monitoring location, methods, a nd proposed frequenc y; and (iv) A proposed schedule for submitting post-injec tion site care monitoring results to

the Director.

{This should be referenced in 146.82(w).}

Individual Response: EPA clarifies that the reference to the post-injection site care and site closure plan, in the final rule at §146.82(a)(17), is to require that the plan be included in the

44attachments to the Class VI permit application. Th e details of the plan contents are included in§146.93 and are enforceable permit conditions, along with other requirements related to postinjection site care a nd site closure.

Letter ID: 0122 Comment ID: 24800 Letter Lines: 1119 to 1122

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: (3) Upon cessation of injection, THE OWNER OR OPERATOR MUST either

submit an amended post-injection site care and site closure plan or demonstrate to the Director through monitoring da ta and modeling results that no amendment to the plan is needed.

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: 0122 Comment ID: 24801 Letter Lines: 1124 to 1126

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: (4) THE OWNER OR OPERATOR MAY May modify and resubmit the postinjection site care and site closure plan for the Director's approval within 30 days of such change.

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: 0122 Comment ID: 24802 Letter Lines: 1128 to 1137

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: (b) THE OWNER OR OPERATOR MUST Must monitor the site following the

cessation of injection to show the position of the carbon dioxide plume and pressure front

and demonstrate that USDWs are not being endangered.

45(1) THE OWNER OR OPERATOR MUST Must continue to conduct monitoring as specified in the Director-approved post-i njection site care and site closure plan for THE PERIOD OF TIME at least 50 y ears following the cessation of injection . At the Director's discretion, the monitoring will continue until THE DIRECTOR DETERMINES THAT the geologi c sequestration project no longer poses an endangerment to USDWs.

Individual Response: EPA disagrees with the suggested ed its. However, EPA agrees with

commenters that there will be circumstances where it can be demonstrated in less than 50 years that the plume and pressure front no longer pos e a risk of endangerment to USDWs. For this reason, the final GS rule offers owners or operato rs flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretio n to shorten or lengthen the PISC timeframe during the PISC period based on site-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, based on substantial data during the permitting pro cess, 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.

Letter ID: 0122 Comment ID: 24803 Letter Lines: 1153 to 1162

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: (3) Prior to authorization for site clos ure, must submit to the Director a demonstration, based on monitoring and other site-specific data, that the carbon dioxide plume and pressure front have stabilized and that no additional monitoring is needed to assure that the GS project does not pose an endangerment to USDWs.

{The carbon dioxide plume will continue to move with other formation fluids - they are never static. The real test shoul d be whether or not the pressure has dissipated and the pressure front stabili zed to the point that there is no threat of endangering USDWs.}

Individual Response: EPA did not make the suggested cha nge. EPA agrees that a complete

46cessation of plume movement may not occur at so me sites for long time periods due to density differences, natural formation flow gradients and diffusion. EPA clarifies that a complete cessation of plume movement is not required, only a demonstration that the plume and pressure front no longer pose a risk of endangerment to USDWs.

EPA acknowledges that many site-specific factors will influence the determ ination of when the CO2 plume and pressure front no lo nger pose a risk of endangerment to USDWs. It is for this

reason that EPA believes that individual UIC Direct ors, in consultation with operators, will be in the best position to determine whether additional post-injection site care is needed. EPA expects

this decision to be made based on relevant site data and in consultati on with all potentially impacted parties.

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

Letter ID: 0122 Comment ID: 24804 Letter Lines: 1164 to 1167

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: (4) If such a demonstration cannot be made after the 50

- year period, must submit to the Director a plan to continue post

- injection site care.

{See comment above.}

Individual Response: As described above, the post-injec tion site care timeframe may be reduced by the Director if the owner or operato r can demonstrate that the remaining pressure front and plume no longer pose a risk of e ndangerment to USDWs. The non-endangerment finding is left to the discretion of the Director, based on site-sp ecific information such as plume movement, pressure decay, and the location of po tential leakage pathways. As suggested by the commenter, a complete cessation of plume movement is not required, only a demonstration that the plume and pressure front no longer pose a risk of endangerment to USDWs, as specified in §146.93(b)(2-4). EPA retains this provi sion in the final GS regulation GS rule also offers owners or operators flexib ility regarding th e duration of the PISC timeframe by affording the Director discretion to allow a Cl ass VI well owner or oper ator to demonstrate, based on substantial data during the permitting pro cess, 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

47adjust 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: 0122 Comment ID: 24805 Letter Lines: 1169 to 1173

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: (c) Notice of intent for site closure. Must notify the Dire ctor at least 120 days before site closure. At this time, if any changes have been made to the original post-injection site care and site closure pla n, THE OWNER OR OPERATOR must also provide the revised plan. At th e discretion of the Di rector, a shorter notice period may be allowed.

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 discussion of post-injection site care in the preamble to the rule for further discussion on EPA's final approach.

Letter ID: 0122 Comment ID: 24806 Letter Lines: 1175 to 1177

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: (d) After the Director has authorized site closure, THE OWNER OR OPERATOR

must plug all monitoring wells in a manner which will not allow moveme nt of injection or formation fluids that endangers a USDW.

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: 0122 Comment ID: 24807 Letter Lines: 1179 to 1191

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)

48Comment: (e) Once the Director has authorized s ite closure, THE OWNER OR OPERATOR

must submit a site closure report within 90 days that must thereafter be retained at a location designated by the Direct or. The report must include:

(1) Documentation of appropriate inj ection and monitoring well plugging as specified in §146.92 and paragraph (c) of th is section. Must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director, which indicates the locati on of the injection well relative to permanently surveyed benchmarks. Must also submit a copy of the plat to the regional administrator of the appropriate EPA Regional Office ;

{Why is this necessary? The EPA regional o ffice will have access to all records at the State. }

Individual Response: The GS regulation at §146.93(g) requires the owner or ope rator to record a notation on the deed to the facility property or other similar document examined during a title search that the land has been used to seque ster CO2 at the time of site closure.

Letter ID: 0122 Comment ID: 24808 Letter Lines: 1200 to 1210

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: (f) THE OWNER OR OPERATOR MUSTMust record a notation on the deed to the facility property or any other document th at is normally examined during title search that will in perpetuity provide a ny potential purchaser of the property the following information:

(1) The fact that land has been us ed to sequester carbon dioxide; (2) The name of the State agency, local au thority, and/or tribe with which the survey plat was filed, as well as the address of the Regional EPA Office to

which it was submitted ; and (3) The volume of flui d injected, the injection

zone or zones into which it was injected, and the period over which injection occurred.

Individual Response: The GS regulation at §146.93(g) requires the owner or ope rator to record a notation that the land has been used to sequester CO2 on the deed to the facility property at the

time of site closure.

Letter ID: 0122 Comment ID: 24809 Letter Lines: 1212 to 1216

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

49Comment 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: (g) Must retain for three years following site closure, records collected during the post-injection site care period. THE OWNER OR OPERATOR MUST Must

deliver the records to the Director at th e conclusion of the retention period, and the records must thereafter be retained at a location designated by the Director for that purpose.

Individual Response: EPA disagrees that the owner or opera tor should not be responsible for record 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: 0122 Comment ID: 24810 Letter Lines: 1218 to 1226

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

Comment Code: 5000 2.8 Proposed Well Plugging and Post-In jection Site Care Requirements

Comment: §146.94 Emergency and remedial response.

(a) As part of the permit application, TH E OWNER OR OPERATOR must provide the Director with an emergency and remedial re sponse plan that de scribes actions to be taken to address movement of the injection or formation fluids that may cause an endangerment to a USDW during cons truction, operation, cl osure and postclosure periods.

{Redundant - See 146.82(X)}

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: 0122 Comment ID: 24974 Letter Lines: 1139 to 1151

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: (2) If the owner or operator can dem onstrate to the satisfaction of the Director before 50 years, based on monitoring and other site

- specific data, that the GS project no longer poses an enda ngerment to USDWs, the Director may

50approve an a mendment to the post

- injection site care and site closure plan to reduce the frequency of monitoring or may authorize site closure before the end

of the 50

- year period.

{The period of time an owner or operato r is required to conduct post-closure care monitoring should be based on the ab ility of the pressure to cause endangerment of USDWs. A 50-year post- closure care monitoring period is unprecedented and implies that CO2 presen ts a greater risk than it does. RRC suggests that EPA strike the phrase "for at least 50 years" and make the time for continued monitoring be based on site specific data. }

Individual Response: EPA disagrees that a post-injection si te care timeframe of 50 years is excessive for most Class VI wells. EPA proposed a default post-injection s ite care 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 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, which is why EPA is providing the Director discretion to approve an alternat ive post-injection site care time frame as long as the owner or operator can meet the requi rements provided at §146.93(c).

EPA acknowledges there will be circumstances wh ere it can be demonstrated in less than 50 years that the plume and pressure front no longe r pose a risk of endangerment to USDWs. For this reason, the GS rule offers ow ners or operators flexibility re garding the duration of the PISC timeframe by: (1) allowing the Director discretio n to shorten or lengthen the PISC timeframe during the post-injection period based on site-s pecific data, pursuant to requirements at §146.93(b); or (2) affording the Dire ctor discretion to allow a Cla ss 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

5152 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.