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.
October 9, 2009 

Cynthia C. Dougherty 

Director 

Office of Ground Water and Drinking Water 

U. S. Environmental Protection Agency 

1200 Pennsylvania Ave., NW. 

Washington, DC 20460 

Re: Proposed Rule for Geologic Sequestration, Docket No. EPA–HQ–OW–2008–0390

Dear Director Dougherty: 

The organizations identified by the signatures at the end of this letter submit the attached 

proposed provisions to add a new section 146.25 to 40 C.F.R. Part 146 with the recommendation 

that these be adopted as the requirements for wells used for geologic sequestration (GS) in oil 

and gas reservoirs that do not meet the provisions of the (b)(4) language recommended in the 

joint letter submitted by a number of participants in the Multi-Stakeholder Discussion (MSD) 

group on December 23, 2008 (copy attached). The recommendations are conditioned on our 

expectation that the delegation standard for primacy will be based on section 1422 as explained 

in this letter. An earlier version of these recommendations was submitted on March 31, 2009 by 

some of the signatories to this letter. Since that time, we have conducted further discussions 

among many of the participants in the MSD process and have now reached a broader consensus 

on the attached revised recommendations. In addition, these recommendations respond to the 

discussion of geologic sequestration under Class II and EPA’s proposed Class VI regarding 

varying risk profiles and appearing in the Agency’s Notice of Data Availability and Request for 

Comment, 74 Fed. Reg. 44802, 44810 (August 31, 2009). 

Background

As indicated in the joint MSD participants letter submitted on December 23, 2008 and in the 

letters submitted to you on March 17, 2009 by the Clean Air Task Force (CATF), the 

Environmental Defense Fund (EDF) and jointly by the American Petroleum Institute (API), the 

Edison Electric Institute (EEI) and the Carbon Sequestration Council (CSC), the MSD had 

continued efforts toward developing recommendations reflecting common views on a number of 

additional issues in this rulemaking. Some of those discussions also resulted in the additional 

recommendations with respect to EPA’s proposed Class VI requirements submitted to you on 

May 14 and 15, 2009. 

The March 17 letters noted that the MSD group followed a modified—and truncated—approach 

to focus on earlier submission of some recommendations in case the Agency wanted to publish 

those recommendations in conjunction with its planned Notice of Data Availability (NODA). 

The December 23, 2008 letter from MSD participants explained the agreement reached on the 

proposed language describing wells in classification (b)(4) that would establish a “bright line” 
Cynthia C. Dougherty 

October 9, 2009 

Page 2 

definition distinguishing (1) wells that inject CO2 for EOR/EGR and those that inject CO2 for GS 

in conjunction with EOR/EGR from (2) wells that inject CO2 for GS where EOR/EGR activities 

and any hydrocarbon production would be minimal.. The signatories to that letter recommended, 

consistent with EPA’s intent, that wells used for EOR/EGR should remain in Class II and that 

wells used for EOR/EGR with GS – that meet the (b)(4) definition – should also remain in Class 

II and be subject to the current requirements for Class II. Signatories to that letter also agreed 

that the wells used for GS in oil and gas reservoirs that do not meet the criteria of (b)(4) should 

be subject to additional requirements. That letter noted an agreement to define such wells as 

wells used “for geologic sequestration in oil and gas formations and where the criteria of 

paragraph (b)(4) are not met.” This letter and the attached provisions provide specific 

recommended requirements for GS in oil and gas reservoirs when the criteria of paragraph (b)(4) 

are not met. 

In the Multi-Stakeholder Discussions since March 31, 2009, the signatories to this letter have 

agreed that wells used for GS in oil and gas reservoirs that do not meet the criteria of paragraph 

(b)(4) should be subject to a set of additional requirements different from those that would apply 

under the current Class II provisions to wells that inject CO2 for EOR/EGR and GS, due to the 

potential change in the risk profile when EOR/EGR activities cease. This common view is also 

reflected in the four letters you received on March 17, 2009 from MSD participants. Each of 

those March 17 letters asks EPA to include this approach in its final GS rule. 

The March 31, 2009 MSD letter included a smaller number of signatories than this letter because 

consensus on all of the attached requirements to that letter had not been achieved at that time. A 

broader consensus has now been achieved, allowing submission of the attached revised 

recommendations. 

Recommended Provisions for GS in Oil and Gas Reservoirs

Specifically, the undersigned recommend that the attached proposed requirements be added to 

Class II through an amendment to add a new section 146.25, as shown. Although the MSD 

process had also considered that these requirements might be promulgated as a new Class VII in 

a new Part 146, Subpart I, the undersigned MSD participants have now agreed that the addition 

to Class II through a new 146.25 is the better approach provided that EPA adopts the delegation 

standard for primacy explained in this letter. 

The addition of the attached recommended requirements as a new section 146.25 should be 

accompanied by the addition of the word “and” at the end of the new paragraphs 144.5(b)(4), 

144.80(b)(4) and 146.5(b)(4) proposed in the December 23 MSG letter and by the addition of a 

new paragraph (5) in subsections 144.5(b), 144.80(b) and 146.5(b) reading: 

(5) For geologic sequestration in oil and gas formations and where the criteria of 

paragraph (b)(4) are not met. 

And—consistent with the further recommendations presented by MSD participants on May 14, 

2009—subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to read as follows: 
Cynthia C. Dougherty 

October 9, 2009 

Page 3 

“(f) Class VI. Wells used for geologic sequestration but not including those wells 

used for geologic sequestration that are regulated under another Class. Wells used 

for geologic sequestration in basalts, coal seams, salt caverns or shales are 

regulated under Class V as experimental wells until such time as the 

Administrator establishes separate requirements by rule for the specific type of 

formation or determines, following public notice and opportunity for comment, 

that wells used for geologic sequestration of carbon dioxide streams into the 

specific type of formation should be regulated under another class.” 

Under this approach, wells used “[f]or geologic sequestration in oil and gas formations and 

where the criteria of paragraph (b)(4) are not met” would be “wells used for geologic 

sequestration that are regulated under another Class”—namely Class II. In conjunction with 

these revisions and the implementation of these requirements, the undersigned MSD participants 

have agreed that the attached proposed section 146.25 requirements should be subject to state 

primacy approval under the standard of section 1422 of the Safe Drinking Water Act (SDWA) 

rather than the alternative standard of section 1425, especially where it will be clear that injection 

for geologic sequestration in an oil and gas reservoir will be done without recovery of oil or 

natural gas. If the criteria of (b)(4) are not satisfied, any production of oil and gas would be an 

incidental function of the GS injection activities subject to our proposed requirements, and 

accordingly such injection would not relate—within the meaning of section 1425—to: 

(1) the underground injection of brine or other fluids which are brought to the 

surface in connection with oil or natural gas production or natural gas storage 

operations, or 

(2) any underground injection for the secondary or tertiary recovery of oil or 

natural gas. 

It should be noted that – as does EPA’s proposal for Class VI – the attached proposal for section 

146.25 requirements relies on the continued applicability of other provisions of EPA’s existing 

UIC regulations, including in particular the provisions of 144.51, which impose the requirements 

for maintenance of mechanical integrity (MI) and for reporting losses of MI. Requirements for 

responding to a potential lack of mechanical integrity are imposed under 40 C.F.R. §144.51(q). 

Requirements for 24-hour reporting are imposed under 40 C.F.R. §144.51(l)(6). 
Cynthia C. Dougherty 

October 9, 2009 

Page 4 

Conclusion

The undersigned respectfully submit the attached recommendations and request that EPA 

promulgate a new section 146.25 be adopted as the regulatory requirements applicable to wells 

used for geologic sequestration (GS) in oil and gas reservoirs that do not meet the provisions of 

the (b)(4) language recommended in the joint letter submitted by participants in the MultiStakeholder Discussion (MSD) group on December 23, 2008. As previously noted in the 

December 23, 2008 letter, the consensus recommendations presented in this letter are solely for 

the purpose of GS regulation under the Safe Drinking Water Act to protect USDWs and not for 

the purpose of addressing verification requirements for carbon credits. 

Sincerely, 

John McManus 

Vice President, Environmental Services 

American Electric Power 

Kyle Isakower 

Director, of Policy Analysis 

American Petroleum Institute 

D. Brian Williams 

CO2 Storage Manager 

BP Alternative Energy North America Inc. 

Karen St. John 

Director Regulatory Affairs 

BP America Inc. 
Cynthia C. Dougherty 

October 9, 2009 

Page 5 

Robert F. Van Voorhees 

Counsel to the Carbon Sequestration Council (CCS Contact Group) 

Kurt Waltzer 

Carbon Storage Development Coordinator 

Clean Air Task Force 

Sarah A. Edman 

Manager, CCS Policy and Project Development 

ConocoPhillips 

Darlene Radcliffe 

Director, Environmental Technology & Fuel Policy 

Duke Energy 

William L. Fang 

Deputy General Counsel 

Edison Electric Institute 

Scott Anderson 

Senior Policy Advisor, Climate and Air Program 

Environmental Defense Fund 
Cynthia C. Dougherty 

October 9, 2009 

Page 6 

Michael S. Beer 

Vice President, Federal Regulation and Policy 

E.ON U.S. LLC 

 Tiffany Rau 

Manager, Policy & Communications 

Hydrogen Energy International LLC 

Al Collins 

Senior Director, Regulatory Affairs 

Occidental Petroleum Corporation 

Kevin Wanttaja 

Manager, Environmental Services 

Salt River Project 

John A. King 

CO2 Manager - Americas 

Shell Exploration and Production 

Karl R. Moor 

Vice President and Associate General Counsel 

Southern Company 
Cynthia C. Dougherty 

October 9, 2009 

Page 7 

Darrick W. Eugene 

General Counsel 

Texas Carbon Capture & Storage Association 

cc: Stephen Heare 

 Ann Codrington 

 Dina Kruger 

 Anhar Karimjee 

 Bruce Kobelski 

 Suzanne Kelly 

 Lee Whitehurst 
Multi-Stakeholder Discussions

Recommendation on 

Requirements for Geologic Sequestration in Oil and Gas Reservoirs 

where Class II(b)(4) Requirements Are Not Met 

[Revised to incorporate additional MSD recommendations] 

October 9, 2009 

§ 146.25 Geologic sequestration in oil or gas reservoirs for wells classified under 146.6(b)(5). 

Except as otherwise provided in this section, injection wells used for geologic sequestration and 

meeting the classification criteria of 40 CFR §146.5(b)(5) shall be subject to the following 

requirements in lieu of the requirements of 40 CFR §146.22-24: 

(a) Minimum Criteria for Siting - The owner or operator must have demonstrated to the satisfaction 

of the Director that existing wells are, and new 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; 

(2) A confining zone(s) that is laterally continuous and free of known transmissive faults or 

fractures over an area sufficient to prevent the movement of fluids that endangers an 

USDW; 

(b) Area of Review and Corrective Action

(1) The area of review is based on computational modeling, as well as monitoring and other 

operational data, that considers the volumes and the physical and chemical properties of all 

phases of the injected carbon dioxide stream. 

(2) The owner or operator must prepare, maintain, and comply with a plan to delineate the 

area of review for a proposed geologic sequestration project under this section, reevaluate 

the delineation, and perform corrective action that meets the requirements of this section in 

a manner and at a frequency acceptable to the Director. As a part of the permit application 

or revision, the owner or operator must submit an area of review and corrective action plan 

that includes the following information: 

(i) The method for delineating the area of review that meets the requirements of 

§146.25(b)(1) and (3), including the model to be used, assumptions that will be made, 

and the site characterization and other data including any existing monitoring data on 

which the model will be based; 

(ii) A description of: 

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

will be used to inform an area of review reevaluation; and 
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Multi-Stakeholder Discussions 2 

 

(B) How corrective action will be conducted to meet the requirements of 

§146.25(b)(4), 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 site access will be assured for future corrective action. 

(3) The owner or operator must perform the following actions to delineate the area of 

review and identify all wells that require corrective action: 

(i) Project, using computational modeling and available monitoring data, the 

projected lateral and vertical migration of the carbon dioxide plume and formation 

fluids in the subsurface from the commencement of carbon dioxide injection 

activities until the plume movement ceases or pressure differentials sufficient to 

cause the movement of injected fluids or formation fluids into an USDW are no 

longer present. The model must: 

(A) Be based on detailed geologic data collected to characterize the injection 

and confining zones, available monitoring data, and on anticipated operating 

data, including injection pressures, rates and total volumes over the duration 

of injection; 

(B) Take into account relevant geologic heterogeneities, and data quality, and 

their possible impact on model projections; 

(C) Consider potential migration through faults, fractures, and artificial 

penetrations and beyond lateral spill points; and 

(D) Consider the physical and chemical properties of all injected and 

formation fluids in the subsurface. 

(ii) Using methods approved by the Director, identify all known or reasonably 

discoverable artificial penetrations into the confining zone, including active, inactive 

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 or evaluations the Director may require; and 

(iii) Determine which abandoned wells identified in §146.25(b)(3)(ii) have been 

plugged in a manner that prevents the movement of carbon dioxide or displaced 

formation fluids that may endanger USDWs; 

(iv) Determine which active and inactive wells identified in §146.25(b)(3)(ii) have 

been completed in a manner that prevents the movement of carbon dioxide or 

displaced formation fluids that may endanger USDWs. 
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Multi-Stakeholder Discussions 3 

 

(4) The owner or operator must perform corrective action using materials suitable for use 

with the carbon dioxide stream on all wells identified in §146.25(b)(3)(ii) that are determined 

to need corrective action in accordance with 146.25(b)(2)(ii)(B). 

(5) (a) Notwithstanding the requirement in subparagraph (2)(i) of this paragraph to perform 

a reevaluation of the area of review at the frequency set forth in the area of review and 

corrective action plan, the owner or operator must also conduct the following whenever 

warranted by material change in the monitoring and operational data or in the evaluation of 

the monitoring and operational data by the owner or operator: 

“(i) reevaluate the area of review by performing all of the actions specified in 

subparagraphs (3)(i) through (iii) of this subsection to delineate the area of review 

and identify all wells that require corrective action; 

“(ii) perform corrective action on wells requiring corrective action in the reevaluated 

area of review in the same manner specified in paragraph (4) of this subsection; and 

 

“(iii) submit an amended area of review and corrective action plan or demonstrate to 

the Director through monitoring data and modeling results that no change to the 

area of review and corrective action plan is needed. 

“(b) Except as provided in subparagraph (c) of this subsection, the owner or operator shall 

also conduct a reevaluation by performing all of the actions specified in clauses (i)(A) 

through (C) of this subsection: 

“(i) Within the time periods specified in the area of review and corrective action plan 

for conducting such a reevaluation of the area of review; or 

“(ii) If an area of review evaluation or reevaluation has not been performed pursuant 

to §146.84(c) and (d) for the geologic sequestration project during the preceding ten 

(10) years, then within six months after the passage of that 10-year period. 

“(c) The Director shall waive the requirement for a reevaluation pursuant to either 

§146.25(5)(b)(i) or (ii) if the owner or operator demonstrates to the Director through 

monitoring and operational data and modeling results, such as those reviewed annually 

pursuant to section 146.25(m), that such a reevaluation is not warranted by material change.”

(6) The emergency and remedial response plan (as required by §146.25(l)) and a 

demonstration of financial responsibility (as required by §146.25(c)) must account for the 

entire area of review (as modified) regardless of whether or not corrective action in the area 

of review is phased. 

(c) Financial Assurance

(1) The owner or operator must demonstrate the adequacy of existing financial responsibility 

or provide and maintain financial responsibility and resources for: corrective action (that 

meets the requirements of § 146.25 (b)), injection well plugging (that meets the requirements 
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Multi-Stakeholder Discussions 4 

 

of § 146.25(j)), and post-injection site care and site closure (that meets the requirements of 

§ 146.25 (k) and emergency and remedial response (that meets the requirements of 

§ 146.25(l) in a manner prescribed by the Director until: 

(i) The Director receives a well plugging report identified in §146.25(j)(4) or 

completion of the post-injection site care and site closure plan as appropriate; and 

(ii) The Director determines that the site has reached the end of the post-injection 

site care period. 

(2) The owner or operator must provide to the Director, at a frequency determined by the 

Director, but no more frequently than annually, written updates or adjustments up or down 

to the cost estimate to account for any changes to the area of review and corrective action 

plan (§146. 25(b)(2)), the injection well plugging plan (§146. 25(j)(2)), and the post-injection 

site care and site closure plan (§146. 25(k)(1)) and for actions taken or changes in conditions 

that reduce the estimated costs of such plans. 

(3) The owner or operator must notify the Director of adverse financial conditions that may 

affect the ability to carry out injection well plugging and post-injection site care and site 

closure. 

(4) The owner or operator must provide an adjustment of the cost estimate to the Director if 

the Director has reason to believe that the most recent demonstration is no longer adequate 

to cover the cost of injection well plugging (as required by §146. 25(j)) and post-injection site 

care and site closure (as required by §146. 25(k)). 

(5) In conjunction with the submission under (c)(2) and (m), the owner or operator may 

request, and the Director may approve, an adjustment to the financial responsibility required 

by (c)(1) to account for actions or changes in conditions that have reduced the estimated 

costs of the plans referenced in (c)(1). 

(d) Well Construction Requirements 

(1) Applicability 

(i) the requirements of this subsection apply to newly drilled injection wells and any 

existing well except to the extent the well is exempted pursuant to (ii) 

(ii) the Director may exempt an existing well from any of the provisions of (d)(2) if: 

 (A) the well meets the construction requirements of 40 CFR 146.22; and 

 (B) the Director determines, after evaluating the significance of any logs, 

surveys and tests which may be available for the well and the extent to which 

the well does or does not meet the provisions of (d)(2), that requiring the 

well to satisfy a particular provision is not necessary to avoid endangerment 

of an USDW. 
GS in Oil and Gas Reservoirs October 9, 2009 

Multi-Stakeholder Discussions 5 

 

(2) Construction Requirements for newly-drilled injection wells. 

(i) General. The owner or operator must ensure that newly-drilled injection wells are 

constructed and completed to: 

(A) Prevent the movement of fluids into any unauthorized zones or an 

USDW as a result of the planned injection operation; 

(B) Permit the use of appropriate testing devices and workover tools; and 

(C) Permit continuous monitoring of the annulus space between the injection 

tubing and long string casing. 

(ii) Casing and cement or other materials used in the construction of each well to 

which this section is applicable must have sufficient structural strength and be 

designed for the life of the well. All well materials must be compatible with fluids 

with which the materials may be expected to come into contact and meet or exceed 

test standards or practices developed for such materials by the American Petroleum 

Institute, ASTM International, or comparable standards acceptable to the Director. 

The casing and cementing program must be designed to prevent the movement of 

fluids that endangers USDWs. In order to allow the Director to evaluate and 

approve casing and cementing requirements, the owner or operator must provide the 

following information: 

(A) Depth to the injection zone; 

(B) Hole size; 

(C) Size and grade of all casing strings (wall thickness, external diameter, 

nominal weight, length, joint specification and construction material); 

(D) Predicted corrosive characteristics of the combined carbon dioxide 

stream and formation fluids; 

(E) Down-hole temperatures and pressures; 

(F) Lithology of injection and confining zones; 

(G) Type or grade of cement and additives; and 

(H) Quantity, chemical composition, and temperature of the carbon dioxide 

stream. 

(iii) Casing must extend through the base of the lowermost USDW above the 

injection zone and be cemented to the surface. Cement may be staged. Surface casing 

need not extend through the base of the lowermost USDW above the injection zone 
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Multi-Stakeholder Discussions 6 

 

if a combination of cement around the surface casing and intermediate or long-string 

casing achieves continuous cement through the base of the lowermost USDW above 

the injection zone. 

(iv) At least one long string casing, using a sufficient number of centralizers, which at 

a minimum must be sealed from within the injection zone upward through the 

overlying confining zone, and must provide adequate isolation of the injection zone 

and other intervals as necessary for protection of USDWs using cement and/or 

other isolation techniques. The Director may approve the use of packers or 

alternative isolation techniques, provided these are demonstrated to be equivalent to 

cement or more effective to provide adequate isolation and to protect USDWs. 

(v) Cement and cement additives must be suitable for use with the carbon dioxide 

stream and formation fluids and of sufficient quality and quantity to maintain 

integrity over the life the well. The integrity and location of the cement shall be 

verified using technology capable of evaluating cement quality and identifying the 

location of channels to ensure that USDWs are not endangered. 

(vi) Tubing and packer. 

(A) Owners and operators must inject fluids through tubing with a packer set 

at a depth opposite a cemented interval at the location approved by the 

Director. 

(B) In order to allow the Director to evaluate and approve tubing and packer 

requirements, the owner or operator must provide the following 

information:: 

(1) Depth of setting and the depth of the injection zone; 

(2) Composition of the carbon dioxide stream. 

(3) Maximum proposed injection temperature and pressure; 

(4) Maximum proposed annular pressure; 

(5) Maximum proposed injection rate (intermittent or continuous) 

and volume of the carbon dioxide stream; 

(6) Size of casing; and 

(7) Tubing tensile, burst, and collapse strengths. 

(e) Logging, sampling, and testing prior to new well operation – The following requirements apply 

only to newly-drilled wells. 
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Multi-Stakeholder Discussions 7 

 

(1) During the drilling and construction of an 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 evaluate conformance with applicable injection well construction requirements 

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. 

The Director may approve such additional or alternative logs and tests as may be requested 

by the owner or operator after taking into account the availability of similar data in the area 

of the drilling site, the construction plan, and the need for additional information as the 

construction of the well progresses and these may include the following: 

(i) Deviation checks during drilling must be at sufficiently frequent intervals to 

determine the location of the borehole; 

(ii) In conjunction with installation of the surface casing: 

(A) Resistivity, gamma ray, and caliper logs before the casing is installed; and 

(B) Cement evaluation log(s) after the casing is set and cemented and/or 

map(s) to evaluate cement quality with sufficient radial resolution to identify 

channels or missing cement that would prevent compliance with 

§146.25(d)(2). 

(iii) Before and upon installation of the long string casing: 

(A) Resistivity, spontaneous potential, porosity, caliper, gamma ray and any 

other logs the Director requires based on site specific conditions and riskbased factors for the given geology before the casing is installed; and 

(B) Cement evaluation log(s) after the casing is set and cemented and/or 

map(s) to evaluate cement quality with sufficient radial resolution to identify 

channels or missing cement that would prevent compliance with 

§146.25(d)(2). 

(iv) Test(s) designed to demonstrate the internal and external mechanical integrity of 

injection wells, which may include one or more of the following: 

(A) A pressure test with liquid or gas; 

(B) Oxygen-activation logging; 

(C) Tracer surveys; 

(D) A temperature or noise log; or 

(E) A casing inspection log. 
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Multi-Stakeholder Discussions 8 

 

(v)Any alternative methods that provide reliable, equivalent or better information 

and that are required of and/or approved of by the Director. 

(2) The owner or operator must submit to the Director a report describing whole cores or 

sidewall cores representative of the injection zone and confining system and formation fluid 

samples from the injection zone(s). The Director may accept data from cores and fluid 

samples from nearby wells if the owner or operator can demonstrate that such data are 

representative of conditions in the wellbore. 

(3) Prior to injection well operation, the owner or operator must record the formation 

temperature, formation fluid pH and conductivity, and reservoir pressure of the injection 

zone(s). 

(4) At any time prior to injection well operation, the owner or operator must determine 

fracture pressures of the injection and confining zones and conduct tests to verify 

hydrogeologic and geomechanical characteristics of the injection zone as necessary to satisfy 

the requirements of (f)(1). 

(5) The owner or operator must provide the Director with the opportunity to witness all 

logging and testing required by this subpart. The owner or operator must submit a schedule 

of such activities to the Director upon spudding the well and submit any changes to the 

schedule 48 hours prior to the scheduled test. 

(f) Injection well operating requirements

(1) The owner or operator must comply with a maximum injection pressure limit approved 

by the Director and specified in the permit. In approving a maximum injection pressure 

limit, the Director shall consider the results of well tests and, where appropriate, 

geomechanical or other studies that assess the risks of tensile failure and shear failure. The 

Director shall approve limits that, with a reasonable degree of certainty, will avoid initiation 

or propagation of fractures in the confining zone or cause otherwise non-transmissive faults 

transecting the confining zone to become transmissive. In no case may injection pressure 

cause movement of injection or formation fluids in a manner prohibited by 40 CFR 

§144.12(a). 

(2) Injection of the carbon dioxide stream into any annulus or between the outermost casing 

protecting USDWs and the well bore is prohibited. 

(3) The owner or operator must fill the annulus between the tubing and the long string 

casing with a corrosion inhibiting fluid approved by the Director and must maintain a 

positive pressure on the annulus. 

(4) The owner or operator must install and use continuous recording devices to monitor: the 

injection pressure and the rate, volume, and temperature of the carbon dioxide stream. The 

owner or operator must regularly monitor the pressure on the annulus between the tubing 

and the long string casing. The owner or operator must install, test and use alarms and 
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Multi-Stakeholder Discussions 9 

 

automatic shut-off systems, designed to alert the operator and shut-in the well when 

operating parameters such as injection rate, injection pressure, or other parameters approved 

by the Director diverge beyond ranges and/or gradients specified in the permit. 

(5) Mechanical integrity 

(i) A well has mechanical integrity if: 

(A) There is no significant leak in the casing, tubing or packer; and 

(B) There is no significant fluid movement into an USDW through channels 

adjacent to the injection well bore. 

(ii) To evaluate the absence of significant leaks under this subsection, owners or 

operators must, following an initial annulus pressure test, continuously monitor and 

record at least daily injection pressure, rate, injected volumes, and pressure on the 

annulus between tubing and long stem casing and annulus fluid volume as specified 

in §146.25(g)(2)(ii); 

(iii) At least once per year, the owner or operator must confirm the absence of 

significant fluid movement under paragraph (5)(i)(B) of this section using a method 

acceptable to the Director (e.g. including diagnostic surveys such as oxygenactivation logging or temperature or noise logs). 

(iv) The Director may require any other test to evaluate mechanical integrity under 

paragraph (i)(A) or (i)(B) 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. 

(v) 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. 

(vi) 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 
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Multi-Stakeholder Discussions 10 

 

packer or significant movement of fluid into or between USDWs resulting from the 

injection activity as stated in paragraphs (i)(A) and (i)(B) of this section. 

(g) Testing and Monitoring

(1) Based on a site-specific assessment of the potential for fluid movement from the 

injection well or injection zone, and on the potential value of monitoring wells to detect such 

movement, the owner or operator of a 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. 

(2) The testing and monitoring plan must, at a minimum, include: 

(i) analysis of the carbon dioxide stream with sufficient frequency to yield data 

representative of its chemical and physical characteristics; 

(ii) Installation and use, except during well workovers as defined in section 146.88(d), 

of continuous monitoring devices (including digital devices capturing periodic data) 

to monitor injection pressure, rate and volume; and to record at least daily the 

pressure on the annulus between the tubing and the long strong casing; 

(iii) demonstration of external mechanical integrity pursuant to §146.25(f)(5) until the 

well is plugged; 

(iv) monitoring of the pressure buildup in the injection zone annually, including at a 

minimum, a shut down of the well for a time sufficient to conduct a valid 

observation of the pressure fall-off curve at least once every five years; and 

(v) quality assurance provisions. 

(3) Where appropriate, the testing and monitoring plan shall also include: 

(i) Monitoring for pressure changes in an appropriately porous and permeable 

formation overlying the confining zone; 

(ii) The use of indirect, geophysical techniques to determine the position of the 

carbon dioxide stream front, the water quality in a designated formation, or to 

provide other site specific data; 

(iii) Periodic monitoring of water quality for constituents specified in the plan in an 

appropriately porous and permeable formation overlying the injection zone; 

(iv) Periodic monitoring of water quality for constituents specified in the plan in one 

or more USDWs; 
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Multi-Stakeholder Discussions 11 

 

(v) Corrosion monitoring of the well materials that will come into contact with water 

for loss of mass, thickness, cracking, pitting and other signs of corrosion performed 

and recorded at least quarterly which may be modified to be less frequent as 

approved by the Director based on construction materials, operating conditions, and 

monitoring history to ensure that the well components meet minimum standards for 

material strength and performance by: 

(A) Analyzing coupons of the well construction materials placed in contact 

with the carbon dioxide stream; or 

(B) Routing the carbon dioxide stream through a loop constructed with the 

material used in the well and inspecting the materials in the loop; or 

(C) Using an alternative method, materials, or time period approved by the 

Director; 

(vi) Any additional monitoring, as required by the Director, based on site-specific 

conditions and risk-based factors, necessary to support, upgrade, and improve 

computational modeling of the area of review evaluation required under 

§ 146.25(b)(2); and 

(vii) Any additional testing and monitoring necessary to determine whether fluid 

movement is occurring that would endanger an USDW. 

(h) Reporting Requirements

The owner or operator must, at a minimum, provide the following reports to the Director, for each 

permitted well: 

(1) Semi-annual or less frequently as determined by the Director reports containing: 

(i) Any significant changes to the physical, chemical and other relevant characteristics 

of the carbon dioxide stream from the proposed operating data; 

(ii) Monthly average, maximum and minimum values for injection pressure, flow rate 

and volume, and annular pressure; 

(iii) A description of any event that significantly exceeds operating parameters for 

annulus pressure or injection pressure as specified in the permit; 

(iv) A description of any event which triggers a shutdown device required pursuant 

to §146.25(f)(4) and the response taken; 

(v) The monthly volume of the carbon dioxide stream injected over the reporting 

period and project cumulatively; 

(vi) Monthly annulus fluid volume added; and 
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Multi-Stakeholder Discussions 12 

 

(vii) The results of monitoring prescribed under §146.25(g). 

(2) Report, within 30 days the results of: 

(i) Periodic tests of mechanical integrity; 

(ii) Any other test of the injection well conducted by the permittee if required by the 

Director; and 

(iii) Any well workover. 

(3) 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. 

(4) The owner or operator must prepare, maintain, and update required plans in 

accordance with the provisions of this section. 

(i) Owners or operators must submit an annual statement, signed by 

an appropriate company official, confirming that the company has: 

(A) reviewed the monitoring and operational data that are 

relevant to a decision on whether to reevaluate the area of 

review and the monitoring and operational data that are 

relevant to a decision on whether to update a plan identified 

in §146.25(i)(16) or (20) through (23); and 

(B) determined whether any updates were warranted by 

material change in the monitoring and operational data or in 

the evaluation of the monitoring and operational data by the 

owner or operator. 

(ii) Owners or operators must submit either the updated plan or a 

summary of the modifications for each plan for which an update was 

determined to be warranted pursuant to subparagraph (i) of this 

paragraph. The Director may require submission of copies of any 

updated plans and/or additional information regarding whether or 

not updates of any particular plans are warranted. 

(iii) The Director may require the revision of any required plan 

whenever the Director determines that such a revision is necessary to 

comply with the requirements of this subchapter. 
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Multi-Stakeholder Discussions 13 

 

(i) Required permit application information 

This section sets forth the information which the owner or operator must submit to the Director in 

order to be permitted. The application for a permit for construction and operation of an injection 

well or for authorization to operate an existing well must include the following: 

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

(2) A surface map showing the proposed locations for the injection well(s) for which a 

permit is sought and the applicable area of review. Within the area of review, the map must 

show the number, or name and location of all known 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. Only information of public record is required to 

be included on this map; 

(3) A map delineating the area of review based upon modeling, using all available data 

including data available from any logging and testing of wells. 

(4) Information on the geologic structure and reservoir properties of the proposed storage 

site and overlying formations, which may include: 

(i) Isopach maps of the proposed injection and confining zone(s), a structural 

contour map aligned with the top of the proposed injection zone, and at least two 

geologic cross sections of the area of review reasonably perpendicular to each other 

showing the geologic formations from the surface to total depth of the well. 

(ii) Location, orientation, and properties of known or suspected subsurface faults 

that may transect the confining zone(s) in the area of review and a determination that 

they would not interfere with containment; 

(iii) Information on seismic history that have affected the proposed area of review 

including knowledge of previous seismic events and history of these events, 

including the presence and depth of seismic sources and a determination that the 

seismicity would not compromise containment; 

(iv) Data sufficient to demonstrate the effectiveness of the injection and confining 

zone(s), including data on the depth, areal extent, thickness, mineralogy, porosity, 

vertical permeability reservoir pressure and of the injection and confining zone(s) 

within the area of review; including geologic changes based on field data which may 

include geologic cores, outcrop data, seismic surveys, well logs, capillary pressure 

tests and names and lithologic descriptions; 
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Multi-Stakeholder Discussions 14 

 

(v) Geomechanical information representative of the confining zone(s) in the area of 

review, such as information on fractures, stress, ductility, rock strength, and in situ 

fluid pressures; and 

(vi) Geologic and topographic maps and cross sections illustrating geology, 

hydrogeology, and the geologic structure of the area of review. 

(5) A compilation of all artificial penetrations within the area of review which penetrate the 

injection or confining zone(s). Such data should 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; 

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

all USDWs, the location of water wells and perennial springs within the area of review, their 

positions relative to the injection zone(s) and the direction of water movement, where 

known; 

(7) A compilation of available baseline geochemical data on the proposed injection zone and 

nearest adjacent porous and permeable formation to the confining zone, existing utilized 

water supply aquifers and any other USDWs designated by the Director. 

(8) Proposed operating data: 

(i) Average and maximum daily injection rate and volume of the carbon dioxide 

stream; 

(ii) Average and maximum surface injection pressure; 

(iii) The source of the carbon dioxide stream; and 

(iv) An analysis of the chemical and physical characteristics of the carbon dioxide 

stream; 

(9) Proposed formation testing program to obtain an analysis of the chemical and physical 

characteristics of the injection zone and confining zone; 

(10) The compatibility of the carbon dioxide 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 or other data, and with the materials used to construct the well; 

(11) Proposed stimulation program and a determination that stimulation will not 

compromise containment; 

(12) The results of the formation testing program as required in paragraph (j) of this section; 
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Multi-Stakeholder Discussions 15 

 

(13) Proposed procedure to outline steps necessary to conduct injection operation; 

(14) A wellbore schematic of the subsurface construction details and surface wellhead 

construction; 

(15) Injection well construction procedures that meet applicable requirements; 

(16) Proposed area of review and corrective action plan required by §146.25(b)(2); 

(17) All available logging and testing program data on the well required by §146.25(e)(1); 

(18) The proposed demonstration method for mechanical integrity pursuant to §146.25(j)(5); 

(19) A demonstration, satisfactory to the Director, that the applicant has met the financial 

responsibility requirements under §146.25(c); 

(20) Proposed testing and monitoring plan required by §146.25(g); 

(21) Proposed injection and monitor well(s) plugging plan required by §146.25(j)(2); 

(22) Proposed post-injection site care and site closure plan required by §146.25(k); 

(23) Proposed emergency and remedial response plan required by § 146.25(l); and 

(24) Any other information requested by the Director necessary to ensure protection of 

USDWs. 

(j) Injection and monitor well plugging

(1) Prior to the well plugging, the owner or operator must flush each injection well with a 

buffer fluid, determine bottomhole reservoir pressure, and perform a final external 

mechanical integrity test. 

(2) Well Plugging Plan. The owner or operator of a well must prepare, maintain, and comply 

with a well plugging plan for injection and monitor wells 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: 

(i) For injection wells and any monitor wells that penetrate the injection zone: 

(A) Appropriate testing or determination of bottomhole reservoir pressure; 
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Multi-Stakeholder Discussions 16 

 

(B) Appropriate testing or determination of reservoir pressure (including, for 

example, through additional perforations) in other formations only if 

required by the Director; 

(C) Appropriate testing methods to ensure final external mechanical integrity 

as specified in §146.25(f)(5); 

(D) The type and number of plugs to be used; 

(E) The placement of each plug including the elevation of the top and 

bottom of each plug; 

(F) The type and grade and quantity of material to be used in plugging. The 

material must be suitable for use with the carbon dioxide stream, reservoir 

and fluid conditions; and 

(G) The method of placement of the plugs. 

(ii) For monitor wells that do not penetrate the injection zone, information 

to demonstrate that the wells will be plugged in compliance with applicable 

state requirements. 

(3) 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. 

(4) Plugging report. Within 60 days after plugging the owner or operator must submit a 

plugging report to the Director. 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.) 

(k) Post-injection site care and site closure

(1) The owner or operator of a well must prepare, maintain, and comply with a plan for 

post-injection site care and site closure that meets the requirements of paragraph (1)(ii) of 

this section and is acceptable to the Director. 

(i) 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. 

(ii) The post-injection site care and site closure plan must include the following 

information: 

(A) The projected pressure differential between pre-injection and projected 

post-injection pressures in the injection zone; 
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Multi-Stakeholder Discussions 17 

 

(B) The projected position of the carbon dioxide plume and associated 

pressure front at site closure as demonstrated in the area of review evaluation 

required under §146.25(b)(1), (3) and (5); 

(C) A description of post-injection monitoring location, methods, and 

proposed frequency; and 

(D) A proposed schedule for submitting post-injection site care monitoring 

results to the Director. 

(iii) Upon cessation of injection, owners or operators of wells 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. 

(iv) The owner or operator may modify and resubmit the post-injection site care and 

site closure plan for the Director’s approval within 30 days of such change 

(2) The owner or operator shall perform monitoring following the cessation of injection as 

follows: 

(i) The owner or operator shall continue to conduct monitoring as specified in the 

Director-approved post-injection site care and site closure plan, pursuant to the 

performance based criteria described in §146.25(k)(2)(iii). 

(ii) The owner or operator may request and demonstrate to the satisfaction of the 

Director that the post-injection site care and site closure plan should be revised to 

reduce the frequency of monitoring. 

(iii) Prior to authorization for site closure, the owner or operator must demonstrate 

to the Director, based on monitoring, other site-specific data, and modeling that is 

reasonably consistent with site performance that no additional monitoring is needed 

to assure that the geologic sequestration project does not pose an endangerment to 

USDWs. The owner or operator must demonstrate, based on the current 

understanding of the site, including monitoring data and/or modeling, all of the 

following: (A) the estimated magnitude and extent of the project footprint (carbon 

dioxide plume and the area of elevated pressure) ; (B) the estimated location of the 

detectable carbon dioxide plume ; (C) that there is no significant leakage of either 

carbon dioxide or displaced formation fluids that is endangering USDWs; (D) that 

the injected or displaced fluids are not expected to migrate in the future in a manner 

that encounters a potential leakage pathway into an USDW; (E) that the injection 

wells at the site completed into or through the injection zone or confining zone are 

plugged and abandoned in accordance with these requirements; and (F) any 

remaining project monitoring wells at the site are being used and managed pursuant 

to a plan approved by the Director in accordance with §146.25(k)(4). 
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Multi-Stakeholder Discussions 18 

 

(3) Notice of intent for site closure. The owner or operator 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. 

(4) 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 an USDW except that designated wells may remain unplugged pursuant 

to §146.25(k) (2)(iii)(F) with the consent of the owner and operator and pursuant to a postclosure monitoring and plugging plan approved by the Director which shall provide for, and 

designate the person responsible for, operating and plugging all such monitoring wells in a 

manner which will not allow movement of injection or formation fluids that endangers an 

USDW. 

(5) Once the Director has authorized site closure, the owner or operator must submit a site 

closure report within 90 days after completion of all closure operations. The report must 

include: 

(i) Documentation of appropriate injection and monitoring well plugging as specified 

in §146.25(j) and paragraph (4) of this section. The owner or operator must provide a 

copy of a survey plat which has been submitted to the local zoning authority 

designated by the Director. The plat must indicate the location of the injection 

well(s) relative to permanently surveyed benchmarks. The owner or operator must 

also submit a copy of the plat to the Regional Administrator of the appropriate EPA 

Regional Office; 

(ii) 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 

(iii) The volume of fluid injected, the injection zone or zones into which it was 

injected, and the period over which injection occurred. 

(6) Each owner or operator of a injection well must provide notification to the designated 

state authority of the following information: 

(i) The fact that land has been used to sequester carbon dioxide; 

(ii) 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 Environmental Protection 

Agency Office to which it was submitted; and 

(iii) The volume of fluid injected, the injection zone or zones into which it was 

injected, and the period over which injection occurred. 
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Multi-Stakeholder Discussions 19 

 

(7) The owner or operator must retain for three years following site closure, records 

collected during the post-injection site care period. The owner or operator 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. 

(l) Emergency and Remedial Response Plan

(1) As part of a permit application or request for revision to operate under this section, the 

owner or operator must provide the Director with an emergency, risk-based remedial 

response plan that describes actions to be taken to address movement of the injection or 

formation fluids that may cause an endangerment to an USDW during construction, 

operation, closure and post-closure periods. 

(2) If the owner or operator obtains evidence that the injected carbon dioxide stream, 

displaced formation fluids or an associated pressure front endangers an USDW, the owner 

or operator must: 

(i) Cease injection in a prudent manner considering circumstances. 

(ii) Take all steps reasonably necessary to identify and characterize the 

endangerment posed; 

(iii) Notify the Director or the designated representative within 24 hours of 

becoming aware of the endangerment; and 

(iv) Implement the emergency and remedial response plan approved by the 

Director and keep the Director apprized of the implementation. 

(3) 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. 

(4) The owner or operator must notify the Director and obtain his approval prior to 

conducting any well workover or other remediation measures not listed in the emergency 

and remedial response plan. 

(5) If an owner or operator obtains evidence that a pressure front associated with 

one geologic sequestration project intersects or will more likely than not intersect the 

pressure front or area of review associated with another project, the owner or 

operator obtaining such evidence must notify the Director. The Director shall notify 

the owner or operator of the other geologic sequestration project. If the Director 

determines that the pressure front associated with one project interferes or will more 

likely than not interfere with the ability of another project to comply with the terms 

of its permit(s), the Director may require the owners or operators of the interfering 

or potentially interfering projects to modify operations as necessary to mitigate or 

avoid such interference. Such modifications may also include modifications mutually 

agreed upon by the respective owners and operators and approved by the Director.” 
Letter ID: 0353  

Commenter: John McManus  

Organization: American Electric Power (AEP)  

Letter ID: 0353 Comment ID: 28058 Letter Lines: 62 to 168  

Comment Code: 5700 5.14. Comments on Other Aspects of the Proposed Rule  

Comment: MSD participants explained the agreement reached on the proposed language  

describing wells in classification (b)(4) that would establish a "bright line"  

definition distinguishing (1) wells  

that inject CO2 for EOR/EGR and those that inject CO2 for GS in conjunction with  

EOR/EGR from (2) wells that inject CO2 for GS where EOR/EGR activities and any  

hydrocarbon production would be minimal.. The signatories to that letter  

recommended, consistent with EPA’s intent, that wells used for EOR/EGR should  

remain in Class II and that wells used for EOR/EGR with GS ‐ that meet the (b)  

(4) definition ‐ should also remain in Class II and be subject to the current  

requirements for Class II. Signatories to that letter also agreed that the wells  

used for GS in oil and gas reservoirs that do not meet the criteria of (b)(4)  

should be subject to additional requirements. That letter noted an agreement to  

define such wells as wells used "for geologic sequestration in oil and gas  

formations and where the criteria of paragraph (b)(4) are not met." This letter  

and the attached provisions provide specific recommended requirements for GS in  

oil and gas reservoirs when the criteria of paragraph (b)(4) are not met.  

In the Multi‐Stakeholder Discussions since March 31, 2009, the signatories to  

this letter have agreed that wells used for GS in oil and gas reservoirs that do  

not meet the criteria of paragraph (b)(4) should be subject to a set of  

additional requirements different from those that would apply under the current  

Class II provisions to wells that inject CO2 for EOR/EGR and GS, due to the  

potential change in the risk profile when EOR/EGR activities cease. This common  

view is also reflected in the four letters you received on March 17, 2009 from  

MSD participants. Each of those March 17 letters asks EPA to include this  

approach in its final GS rule.  

The March 31, 2009 MSD letter included a smaller number of signatories than this  

letter because consensus on all of the attached requirements to that letter had  

not been achieved at that time. A broader consensus has now been achieved,  

allowing submission of the attached revised recommendations.  
Recommended Provisions for GS in Oil and Gas Reservoirs  

Specifically, the undersigned recommend that the attached proposed requirements  

be added to Class II through an amendment to add a new section 146.25, as shown.  

Although the MSD process had also considered that these requirements might be  

promulgated as a new Class VII in a new Part 146, Subpart I, the undersigned MSD  

participants have now agreed that the addition to Class II through a new 146.25  

is the better approach provided that EPA adopts the delegation standard for  

primacy explained in this letter.  

The addition of the attached recommended requirements as a new section 146.25  

should be accompanied by the addition of the word "and" at the end of the new  

paragraphs 144.5(b)(4), 144.80(b)(4) and 146.5(b)(4) proposed in the December 23  

MSG letter and by the addition of a new paragraph (5) in subsections 144.5(b),  

144.80(b) and 146.5(b) reading:  

(5) For geologic sequestration in oil and gas formations and where the criteria  

of paragraph (b)(4) are not met.  

And‐consistent with the further recommendations presented by MSD participants on  

May 14, 2009‐subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to  

read as follows:  

"(f) Class VI. Wells used for geologic sequestration but not including those  

wells used for geologic sequestration that are regulated under another Class.  

Wells used for geologic sequestration in basalts, coal seams, salt caverns or  

shales are regulated under Class V as experimental wells until such time as the  

Administrator establishes separate requirements by rule for the specific type of  

formation or determines, following public notice and opportunity for comment,  

that wells used for geologic sequestration of carbon dioxide streams into the  

specific type of formation should be regulated under another class."  

Under this approach, wells used "[f]or geologic sequestration in oil and gas  

formations and where the criteria of paragraph (b)(4) are not met" would be  

"wells used for geologic sequestration that are regulated under another  

Class"‐namely Class II. In conjunction with these revisions and the  

implementation of these requirements, the undersigned MSD participants have  

agreed that the attached proposed section 146.25 requirements should be subject  

to state primacy approval under the standard of section 1422 of the Safe  

Drinking Water Act (SDWA) rather than the alternative standard of section 1425,  

especially where it will be clear that injection for geologic sequestration in  
an oil and gas reservoir will be done without recovery of oil or natural gas. If  

the criteria of (b)(4) are not satisfied, any production of oil and gas would be  

an incidental function of the GS injection activities subject to our proposed  

requirements, and accordingly such injection would not relate‐within the meaning  

of section 1425‐to:  

(1) the underground injection of brine or other fluids which are brought to the  

surface in connection with oil or natural gas production or natural gas storage  

operations, or  

(2) any underground injection for the secondary or tertiary recovery of oil or  

natural gas.  

It should be noted that ‐ as does EPA’s proposal for Class VI ‐ the attached  

proposal for section 146.25 requirements relies on the continued applicability  

of other provisions of EPA’s existing UIC regulations, including in particular  

the provisions of 144.51, which impose the requirements for maintenance of  

mechanical integrity (MI) and for reporting losses of MI. Requirements for  

responding to a potential lack of mechanical integrity are imposed under 40  

C.F.R. §144.51(q). Requirements for 24‐hour reporting are imposed under 40  

C.F.R. §144.51(l)(6).  

Conclusion  

The undersigned respectfully submit the attached recommendations and request  

that EPA promulgate a new section 146.25 be adopted as the regulatory  

requirements applicable to wells used for geologic sequestration (GS) in oil and  

gas reservoirs that do not meet the provisions of the (b)(4) language  

recommended in the joint letter submitted by participants in the Multi‐  

Stakeholder Discussion (MSD) group on December 23, 2008. As previously noted in  

the December 23, 2008 letter, the consensus recommendations presented in this  

letter are solely for the purpose of GS regulation under the Safe Drinking Water  

Act to protect USDWs and not for the purpose of addressing verification  

requirements for carbon credits.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28059 Letter Lines: 234 to 245  
Comment Code: 5100 5.2. Comments on the Proposed Siting Requirements (146.83)  

Comment: (a) Minimum Criteria for Siting ‐ The owner or operator must have demonstrated  

to the satisfaction of the Director that existing wells are, and new 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;  

(2) A confining zone(s) that is laterally continuous and free of known  

transmissible faults or fractures over an area sufficient to prevent the movement  

of fluids that endangers an USDW;  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28060 Letter Lines: 249 to 362  

Comment Code: 5150 5.3. Comments on the Proposed AoR and Corrective Action Requirements

(146.84)  

Comment: (1) The area of review is based on computational modeling, as well as monitoring  

and other operational data, that considers the volumes and the physical and  

chemical properties of all phases of the injected carbon dioxide stream.  

(2) The owner or operator must prepare, maintain, and comply with a plan to  

delineate the area of review for a proposed geologic sequestration project under  

this section, reevaluate the delineation, and perform corrective action that  

meets the requirements of this section in a manner and at a frequency acceptable  

to the Director. As a part of the permit application or revision, the owner or  

operator must submit an area of review and corrective action plan that includes  

the following information:  

(i) The method for delineating the area of review that meets the requirements of  

§146.25(b)(1) and (3), including the model to be used, assumptions that will be  

made, and the site characterization and other data including any existing  

monitoring data on which the model will be based;  
(ii) A description of:  

(A) How monitoring and operational data (e.g., injection rate and pressure) will  

be used to inform an area of review reevaluation; and Multi‐Stakeholder  

Discussions (B) How corrective action will be conducted to meet the requirements  

of §146.25(b)(4), 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 site access will be assured for future corrective action.  

(3) The owner or operator must perform the following actions to delineate the  

area of review and identify all wells that require corrective action: (i)  

Project, using computational modeling and available monitoring data, the  

projected lateral and vertical migration of the carbon dioxide plume and  

formation fluids in the subsurface from the commencement of carbon dioxide  

injection activities until the plume movement ceases or pressure differentials  

sufficient to cause the movement of injected fluids or formation fluids into an  

USDW are no longer present. The model must:  

(A) Be based on detailed geologic data collected to characterize the injection  

and confining zones, available monitoring data, and on anticipated operating  

data, including injection pressures, rates and total volumes over the duration  

of injection;  

(B) Take into account relevant geologic heterogeneities, and data quality, and  

their possible impact on model projections;  

(C) Consider potential migration through faults, fractures, and artificial  

penetrations and beyond lateral spill points; and  

(D) Consider the physical and chemical properties of all injected and formation  

fluids in the subsurface.  

(ii) Using methods approved by the Director, identify all known or reasonably  

discoverable artificial penetrations into the confining zone, including active,  

inactive 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 or evaluations the Director may  

require; and  
(iii) Determine which abandoned wells identified in §146.25(b)(3)(ii) have been  

plugged in a manner that prevents the movement of carbon dioxide or displaced  

formation fluids that may endanger USDWs;  

(iv) Determine which active and inactive wells identified in §146.25(b)(3)(ii)  

have been completed in a manner that prevents the movement of carbon dioxide or  

displaced formation fluids that may endanger USDWs.  

(4) The owner or operator must perform corrective action using materials  

suitable for use with the carbon dioxide stream on all wells identified in  

§146.25(b)(3)(ii) that are determined to need corrective action in accordance  

with 146.25(b)(2)(ii)(B).  

(5) (a) Notwithstanding the requirement in subparagraph (2)(i) of this paragraph  

to perform a reevaluation of the area of review at the frequency set forth in  

the area of review and corrective action plan, the owner or operator must also  

conduct the following whenever warranted by material change in the monitoring  

and operational data or in the evaluation of the monitoring and operational data  

by the owner or operator:  

"(i) reevaluate the area of review by performing all of the actions specified in  

subparagraphs (3)(i) through (iii) of this subsection to delineate the area of  

review and identify all wells that require corrective action;  

"(ii) perform corrective action on wells requiring corrective action in the  

reevaluated area of review in the same manner specified in paragraph (4) of this  

subsection; and  

"(iii) submit an amended area of review and corrective action plan or  

demonstrate to the Director through monitoring data and modeling results that no  

change to the area of review and corrective action plan is needed.  

"(b) Except as provided in subparagraph (c) of this subsection, the owner or  

operator shall also conduct a reevaluation by performing all of the actions  

specified in clauses (i)(A) through (C) of this subsection:  

"(i) Within the time periods specified in the area of review and corrective  

action plan for conducting such a reevaluation of the area of review; or  

"(ii) If an area of review evaluation or reevaluation has not been performed  
pursuant to §146.84(c) and (d) for the geologic sequestration project during the  

preceding ten (10) years, then within six months after the passage of that 10‐  

year period.  

"(c) The Director shall waive the requirement for a reevaluation pursuant to  

either §146.25(5)(b)(i) or (ii) if the owner or operator demonstrates to the  

Director through monitoring and operational data and modeling results, such as  

those reviewed annually pursuant to section 146.25(m), that such a reevaluation  

is not warranted by material change."  

(6) The emergency and remedial response plan (as required by §146.25(l)) and a  

demonstration of financial responsibility (as required by §146.25(c)) must  

account for the entire area of review (as modified) regardless of whether or not  

corrective action in the area of review is phased.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28061 Letter Lines: 364 to 403  

Comment Code: 5200 5.4. Comments on the Proposed Financial Responsibility Requirements (146.85)  

Comment: (c) Financial Assurance  

(1) The owner or operator must demonstrate the adequacy of existing financial  

responsibility or provide and maintain financial responsibility and resources  

for: corrective action (that meets the requirements of § 146.25 (b)), injection  

well plugging (that meets the requirements of § 146.25(j)), and post‐injection  

site care and site closure (that meets the requirements of § 146.25 (k) and  

emergency and remedial response (that meets the requirements of § 146.25(l) in a  

manner prescribed by the Director until:  

(i) The Director receives a well plugging report identified in §146.25(j)(4) or  

completion of the post‐injection site care and site closure plan as appropriate;  

and  

(ii) The Director determines that the site has reached the end of the post‐  

injection site care period.  
(2) The owner or operator must provide to the Director, at a frequency  

determined by the Director, but no more frequently than annually, written  

updates or adjustments up or down to the cost estimate to account for any  

changes to the area of review and corrective action plan (§146. 25(b)(2)), the  

injection well plugging plan (§146. 25(j)(2)), and the post‐injection site care  

and site closure plan (§146. 25(k)(1)) and for actions taken or changes in  

conditions that reduce the estimated costs of such plans.  

(3) The owner or operator must notify the Director of adverse financial  

conditions that may affect the ability to carry out injection well plugging and  

post‐injection site care and site closure.  

(4) The owner or operator must provide an adjustment of the cost estimate to the  

Director if the Director has reason to believe that the most recent  

demonstration is no longer adequate to cover the cost of injection well plugging  

(as required by §146. 25(j)) and post‐injection site care and site closure (as  

required by §146. 25(k)).  

(5) In conjunction with the submission under (c)(2) and (m), the owner or  

operator may request, and the Director may approve, an adjustment to the  

financial responsibility required by (c)(1) to account for actions or changes in  

conditions that have reduced the estimated costs of the plans referenced in (c)  

(1).  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28062 Letter Lines: 405 to 509  

Comment Code: 5250 5.5. Comments on the Proposed Construction Requirements (146.86)  

Comment: (d) Well Construction Requirements  

(1) Applicability  

(i) the requirements of this subsection apply to newly drilled injection wells  

and any existing well except to the extent the well is exempted pursuant to (ii)  

(ii) the Director may exempt an existing well from any of the provisions of (d)  
(2) if:  

(A) the well meets the construction requirements of 40 CFR 146.22; and  

(B) the Director determines, after evaluating the significance of any logs,  

surveys and tests which may be available for the well and the extent to which  

the well does or does not meet the provisions of (d)(2), that requiring the well  

to satisfy a particular provision is not necessary to avoid endangerment of an  

USDW.  

(2) Construction Requirements for newly‐drilled injection wells.  

(i) General. The owner or operator must ensure that newly‐drilled injection  

wells are constructed and completed to:  

(A) Prevent the movement of fluids into any unauthorized zones or an USDW as a  

result of the planned injection operation;  

(B) Permit the use of appropriate testing devices and workover tools; and  

(C) Permit continuous monitoring of the annulus space between the injection  

tubing and long string casing.  

(ii) Casing and cement or other materials used in the construction of each well  

to which this section is applicable must have sufficient structural strength and  

be designed for the life of the well. All well materials must be compatible with  

fluids with which the materials may be expected to come into contact and meet or  

exceed test standards or practices developed for such materials by the American  

Petroleum Institute, ASTM International, or comparable standards acceptable to  

the Director. The casing and cementing program must be designed to prevent the  

movement of fluids that endangers USDWs. In order to allow the Director to  

evaluate and approve casing and cementing requirements, the owner or operator  

must provide the following information:  

(A) Depth to the injection zone;  

(B) Hole size;  

(C) Size and grade of all casing strings (wall thickness, external diameter,  

nominal weight, length, joint specification and construction material);  

(D) Predicted corrosive characteristics of the combined carbon dioxide stream  
and formation fluids;  

(E) Down‐hole temperatures and pressures;  

(F) Lithology of injection and confining zones;  

(G) Type or grade of cement and additives; and  

(H) Quantity, chemical composition, and temperature of the carbon dioxide  

stream.  

(iii) Casing must extend through the base of the lowermost USDW above the  

injection zone and be cemented to the surface. Cement may be staged. Surface  

casing need not extend through the base of the lowermost USDW above the  

injection zone if a combination of cement around the surface casing and  

intermediate or long‐string casing achieves continuous cement through the base  

of the lowermost USDW above the injection zone.  

(iv)At least one long string casing, using a sufficient number of centralizers,  

which at a minimum must be sealed from within the injection zone upward through  

the overlying confining zone, and must provide adequate isolation of the  

injection zone and other intervals as necessary for protection of USDWs using  

cement and/or other isolation techniques. The Director may approve the use of  

packers or alternative isolation techniques, provided these are demonstrated to  

be equivalent to cement or more effective to provide adequate isolation and to  

protect USDWs.  

(v) Cement and cement additives must be suitable for use with the carbon dioxide  

stream and formation fluids and of sufficient quality and quantity to maintain  

integrity over the life the well. The integrity and location of the cement shall  

be verified using technology capable of evaluating cement quality and  

identifying the location of channels to ensure that USDWs are not endangered.  

(vi) Tubing and packer.  

(A) Owners and operators must inject fluids through tubing with a packer set at  

a depth opposite a cemented interval at the location approved by the Director.  

(B) In order to allow the Director to evaluate and approve tubing and packer  

requirements, the owner or operator must provide the following information::  

(1) Depth of setting and the depth of the injection zone;  
(2) Composition of the carbon dioxide stream.  

(3) Maximum proposed injection temperature and pressure;  

(4) Maximum proposed annular pressure;  

(5) Maximum proposed injection rate (intermittent or continuous) and volume of  

the carbon dioxide stream;  

(6) Size of casing; and  

(7) Tubing tensile, burst, and collapse strengths.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28063 Letter Lines: 511 to 584  

Comment Code: 5300 5.6. Comments on the Proposed Logging, Sampling, and Testing Requirements

(146.87)  

Comment: (e) Logging, sampling, and testing prior to new well operation – The following  

requirements apply only to newly‐drilled wells.  

(1) During the drilling and construction of an 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 evaluate  

conformance with applicable injection well construction requirements 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. The Director may approve such additional or  

alternative logs and tests as may be requested by the owner or operator after  

taking into account the availability of similar data in the area of the drilling  

site, the construction plan, and the need for additional information as the  

construction of the well progresses and these may include the following:  
(i) Deviation checks during drilling must be at sufficiently frequent intervals  

to determine the location of the borehole;  

(ii) In conjunction with installation of the surface casing:  

(A) Resistivity, gamma ray, and caliper logs before the casing is installed; and  

(B) Cement evaluation log(s) after the casing is set and cemented and/or map(s)  

to evaluate cement quality with sufficient radial resolution to identify  

channels or missing cement that would prevent compliance with §146.25(d)(2).  

(iii) Before and upon installation of the long string casing:  

(A)Resistivity, spontaneous potential, porosity, caliper, gamma ray and any  

other logs the Director requires based on site specific conditions and risk‐  

based factors for the given geology before the casing is installed; and  

(B) Cement evaluation log(s) after the casing is set and cemented and/or map(s)  

to evaluate cement quality with sufficient radial resolution to identify  

channels or missing cement that would prevent compliance with §146.25(d)(2).  

(iv) Test(s) designed to demonstrate the internal and external mechanical  

integrity of injection wells, which may include one or more of the following:  

(A) A pressure test with liquid or gas;  

(B) Oxygen‐activation logging;  

(C) Tracer surveys;  

(D) A temperature or noise log; or  

(E) A casing inspection log.  

(v) Any alternative methods that provide reliable, equivalent or better  

information and that are required of and/or approved of by the Director.  

(2) The owner or operator must submit to the Director a report describing whole  

cores or sidewall cores representative of the injection zone and confining  

system and formation fluid samples from the injection zone(s). The Director may  

accept data from cores and fluid samples from nearby wells if the owner or  

operator can demonstrate that such data are representative of conditions in the  
well bore.  

(3) Prior to injection well operation, the owner or operator must record the  

ormation temperature, formation fluid pH and conductivity, and reservoir  

pressure of the injection zone(s).  

(4) At any time prior to injection well operation, the owner or operator must  

determine fracture pressures of the injection and confining zones and conduct  

tests to verify hydrogeologic and geomechanical characteristics of the injection  

zone as necessary to satisfy the requirements of (f)(1).  

(5) The owner or operator must provide the Director with the opportunity to  

witness all logging and testing required by this subpart. The owner or operator  

must submit a schedule of such activities to the Director upon spudding the well  

and submit any changes to the schedule 48 hours prior to the scheduled test.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28064 Letter Lines: 586 to 613  

Comment Code: 5350 5.7. Comments on the Proposed Operating Requirements (146.88)  

Comment: (f) Injection well operating requirements  

(1) The owner or operator must comply with a maximum injection pressure limit  

approved by the Director and specified in the permit. In approving a maximum  

injection pressure limit, the Director shall consider the results of well tests  

and, where appropriate, geomechanical or other studies that assess the risks of  

tensile failure and shear failure. The Director shall approve limits that, with  

a reasonable degree of certainty, will avoid initiation or propagation of  

fractures in the confining zone or cause otherwise non‐transmissive faults  

transecting the confining zone to become transmissible. In no case may injection  

pressure cause movement of injection or formation fluids in a manner prohibited  

by 40 CFR §144.12(a).  

(2) Injection of the carbon dioxide stream into any annulus or between the  

outermost casing protecting USDWs and the well bore is prohibited.  
(3) The owner or operator must fill the annulus between the tubing and the long  

string casing with a corrosion inhibiting fluid approved by the Director and  

must maintain a positive pressure on the annulus.  

(4) The owner or operator must install and use continuous recording devices to  

monitor: the injection pressure and the rate, volume, and temperature of the  

carbon dioxide stream. The owner or operator must regularly monitor the  

pressure on the annulus between the tubing and the long string casing. The owner  

or operator must install, test and use alarms and automatic shut‐off systems,  

designed to alert the operator and shut‐in the well when operating parameters  

such as injection rate, injection pressure, or other parameters approved by the  

Director diverge beyond ranges and/or gradients specified in the permit.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28065 Letter Lines: 615 to 660  

Comment Code: 5400 5.8. Comments on the Proposed MIT Requirements (146.89)  

Comment: (5) Mechanical integrity  

(i) A well has mechanical integrity if:  

(A) There is no significant leak in the casing, tubing or packer; and  

(B) There is no significant fluid movement into an USDW through channels  

adjacent to the injection well bore.  

(ii) To evaluate the absence of significant leaks under this subsection, owners  

or operators must, following an initial annulus pressure test, continuously  

monitor and record at least daily injection pressure, rate, injected volumes,  

and pressure on the annulus between tubing and long stem casing and annulus  

fluid volume as specified in §146.25(g)(2)(ii);  

(iii) At least once per year, the owner or operator must confirm the absence of  

significant fluid movement under paragraph (5)(i)(B) of this section using a  

method acceptable to the Director (e.g. including diagnostic surveys such as  

oxygen‐activation logging or temperature or noise logs).  
(iv) The Director may require any other test to evaluate mechanical integrity  

under paragraph (i)(A) or (i)(B) 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.  

(v) 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.  

(vi) 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 (i)(A) and  

(i)(B) of this section.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28066 Letter Lines: 662 to 732  

Comment Code: 5450 5.9. Comments on the Proposed Monitoring Requirements (146.90)  

Comment: (g) Testing and Monitoring  

(1) Based on a site‐specific assessment of the potential for fluid movement from  

the injection well or injection zone, and on the potential value of monitoring  
wells to detect such movement, the owner or operator of a 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.  

(2) The testing and monitoring plan must, at a minimum, include:  

(i) analysis of the carbon dioxide stream with sufficient frequency to yield  

data representative of its chemical and physical characteristics;  

(ii)Installation and use, except during well workovers as defined in section  

146.88(d), of continuous monitoring devices (including digital devices capturing  

periodic data) to monitor injection pressure, rate and volume; and to record at  

least daily the pressure on the annulus between the tubing and the long strong  

casing;  

(iii) demonstration of external mechanical integrity pursuant to §146.25(f)(5)  

until the well is plugged;  

(iv) monitoring of the pressure buildup in the injection zone annually,  

including at a minimum, a shut down of the well for a time sufficient to conduct  

a valid observation of the pressure fall‐off curve at least once every five  

years; and  

(v) quality assurance provisions.  

(3) Where appropriate, the testing and monitoring plan shall also include:  

(i) Monitoring for pressure changes in an appropriately porous and permeable  

formation overlying the confining zone;  

(ii) The use of indirect, geophysical techniques to determine the position of  

the carbon dioxide stream front, the water quality in a designated formation, or  

to provide other site specific data;  

(iii) Periodic monitoring of water quality for constituents specified in the  

plan in an appropriately porous and permeable formation overlying the injection  

zone;  

(iv) Periodic monitoring of water quality for constituents specified in the plan  
in one or more USDWs;  

(v) Corrosion monitoring of the well materials that will come into contact with  

water for loss of mass, thickness, cracking, pitting and other signs of  

corrosion performed and recorded at least quarterly which may be modified to be  

less frequent as approved by the Director based on construction materials,  

operating conditions, and monitoring history to ensure that the well components  

meet minimum standards for material strength and performance by:  

(A) Analyzing coupons of the well construction materials placed in contact with  

the carbon dioxide stream; or  

(B) Routing the carbon dioxide stream through a loop constructed with the  

material used in the well and inspecting the materials in the loop; or  

(C) Using an alternative method, materials, or time period approved by the  

Director;  

(vi) Any additional monitoring, as required by the Director, based on site‐  

specific conditions and risk‐based factors, necessary to support, upgrade, and  

improve computational modeling of the area of review evaluation required under §  

146.25(b)(2); and  

(vii) Any additional testing and monitoring necessary to determine whether fluid  

movement is occurring that would endanger an USDW.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28067 Letter Lines: 734 to 924  

Comment Code: 5500 5.10. Comments on the Proposed Reporting Requirements (146.91)  

Comment: (h) Reporting Requirements  

The owner or operator must, at a minimum, provide the following reports to the  

Director, for each permitted well:  

(1) Semi‐annual or less frequently as determined by the Director reports  
containing:  

(i) Any significant changes to the physical, chemical and other relevant  

characteristics of the carbon dioxide stream from the proposed operating data;  

(ii) Monthly average, maximum and minimum values for injection pressure, flow  

rate and volume, and annular pressure;  

(iii) A description of any event that significantly exceeds operating parameters  

for annulus pressure or injection pressure as specified in the permit; (iv) A  

description of any event which triggers a shutdown device required pursuant to  

§146.25(f)(4) and the response taken;  

(v) The monthly volume of the carbon dioxide stream injected over the reporting  

period and project cumulatively;  

(vi) Monthly annulus fluid volume added; and  

(vii) The results of monitoring prescribed under §146.25(g).  

(2)Report, within 30 days the results of:  

(i)Periodic tests of mechanical integrity;  

(ii)Any other test of the injection well conducted by the permittee if required  

by the Director; and  

(iii) Any well workover.  

(3)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.  

(4)The owner or operator must prepare, maintain, and update required plans in  

accordance with the provisions of this section.  

(i)Owners or operators must submit an annual statement, signed by an appropriate  

company official, confirming that the company has:  

(A)reviewed the monitoring and operational data that are relevant to a decision  

on whether to reevaluate the area of review and the monitoring and operational  

data that are relevant to a decision on whether to update a plan identified in  

§146.25(i)(16) or (20) through (23); and  
(B)determined whether any updates were warranted by material change in the  

monitoring and operational data or in the evaluation of the monitoring and  

operational data by the owner or operator.  

(ii)Owners or operators must submit either the updated plan or a summary of the  

modifications for each plan for which an update was determined to be warranted  

pursuant to subparagraph (i) of this paragraph. The Director may require  

submission of copies of any updated plans and/or additional information  

regarding whether or not updates of any particular plans are warranted.  

(iii) The Director may require the revision of any required plan whenever the  

Director determines that such a revision is necessary to comply with the  

requirements of this subchapter.  

(i) Required permit application information This section sets forth the  

information which the owner or operator must submit to the Director in order to  

be permitted. The application for a permit for construction and operation of an  

injection well or for authorization to operate an existing well must include the  

following:  

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

(2)A surface map showing the proposed locations for the injection well(s) for  

which a permit is sought and the applicable area of review. Within the area of  

review, the map must show the number, or name and location of all known  

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. Only information of public record is required to  

be included on this map;  

(3)A map delineating the area of review based upon modeling, using all available  

data including data available from any logging and testing of wells.  

(4)Information on the geologic structure and reservoir properties of the  

proposed storage site and overlying formations, which may include:  

(i)Isopach maps of the proposed injection and confining zone(s), a structural  

contour map aligned with the top of the proposed injection zone, and at least  

two geologic cross sections of the area of review reasonably perpendicular to  
each other showing the geologic formations from the surface to total depth of  

the well.  

(ii)Location, orientation, and properties of known or suspected subsurface  

faults that may transect the confining zone(s) in the area of review and a  

determination that they would not interfere with containment;  

(iii) Information on seismic history that have affected the proposed area of  

review including knowledge of previous seismic events and history of these  

events, including the presence and depth of seismic sources and a determination  

that the seismicity would not compromise containment;  

(iv) Data sufficient to demonstrate the effectiveness of the injection and  

confining zone(s), including data on the depth, areal extent, thickness,  

mineralogy, porosity, vertical permeability reservoir pressure and of the  

injection and confining zone(s) within the area of review; including geologic  

changes based on field data which may include geologic cores, outcrop data,  

seismic surveys, well logs, capillary pressure tests and names and lithologic  

descriptions;  

(v) Geomechanical information representative of the confining zone(s) in the  

area of review, such as information on fractures, stress, ductility, rock  

strength, and in situ fluid pressures; and  

(vi) Geologic and topographic maps and cross sections illustrating geology,  

hydrogeology, and the geologic structure of the area of review.  

(5) A compilation of all artificial penetrations within the area of review which  

penetrate the injection or confining zone(s). Such data should 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;  

(6) Maps and stratigraphic cross sections indicating the general vertical and  

lateral limits of all USDWs, the location of water wells and perennial springs  

within the area of review, their positions relative to the injection zone(s) and  

the direction of water movement, where known;  

(7) A compilation of available baseline geochemical data on the proposed  

injection zone and nearest adjacent porous and permeable formation to the  

confining zone, existing utilized water supply aquifers and any other USDWs  

designated by the Director.  
(8) Proposed operating data:  

(i) Average and maximum daily injection rate and volume of the carbon dioxide  

stream;  

(ii) Average and maximum surface injection pressure;  

(iii) The source of the carbon dioxide stream; and  

(iv) An analysis of the chemical and physical characteristics of the carbon  

dioxide stream;  

(9) Proposed formation testing program to obtain an analysis of the chemical and  

physical characteristics of the injection zone and confining zone;  

(10) The compatibility of the carbon dioxide 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 or other data, and with the materials  

used to construct the well;  

(11) Proposed stimulation program and a determination that stimulation will not  

compromise containment;  

(12) The results of the formation testing program as required in paragraph (j)  

of this section;  

(13) Proposed procedure to outline steps necessary to conduct injection  

operation;  

(14) A well bore schematic of the subsurface construction details and surface  

wellhead construction;  

(15) Injection well construction procedures that meet applicable requirements;  

(16) Proposed area of review and corrective action plan required by §146.25(b)  

(2);  

(17) All available logging and testing program data on the well required by  

§146.25(e)(1);  

(18) The proposed demonstration method for mechanical integrity pursuant to  
§146.25(j)(5);  

(19) A demonstration, satisfactory to the Director, that the applicant has met  

the financial responsibility requirements under §146.25(c);  

(20) Proposed testing and monitoring plan required by §146.25(g);  

(21) Proposed injection and monitor well(s) plugging plan required by §146.25(j)  

(2);  

(22) Proposed post‐injection site care and site closure plan required by  

§146.25(k);  

(23) Proposed emergency and remedial response plan required by § 146.25(l); and  

(24) Any other information requested by the Director necessary to ensure  

protection of USDWs.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0353 Comment ID: 28068 Letter Lines: 926 to 974  

Comment Code: 5550 5.11. Comments on the Proposed Well Plugging Requirements (146.92)  

Comment: (j) Injection and monitor well plugging  

(1) Prior to the well plugging, the owner or operator must flush each injection  

well with a buffer fluid, determine bottomhole reservoir pressure, and perform a  

final external mechanical integrity test.  

(2) Well Plugging Plan. The owner or operator of a well must prepare, maintain,  

and comply with a well plugging plan for injection and monitor wells 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:  

(i) For injection wells and any monitor wells that penetrate the injection zone:  
(A) Appropriate testing or determination of bottomhole reservoir pressure;  

(B) Appropriate testing or determination of reservoir pressure (including, for  

example, through additional perforations) in other formations only if required  

by the Director;  

(C) Appropriate testing methods to ensure final external mechanical integrity as  

specified in §146.25(f)(5);  

(D) The type and number of plugs to be used;  

(E) The placement of each plug including the elevation of the top and bottom of  

each plug;  

(F) The type and grade and quantity of material to be used in plugging. The  

material must be suitable for use with the carbon dioxide stream, reservoir and  

fluid conditions; and  

(G) The method of placement of the plugs.  

(ii) For monitor wells that do not penetrate the injection zone, information to  

demonstrate that the wells will be plugged in compliance with applicable state  

requirements.  

(3) 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.  

(4) Plugging report. Within 60 days after plugging the owner or operator must  

submit a plugging report to the Director. 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.)  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  
Letter ID: 0353 Comment ID: 28069 Letter Lines: 976 to 1091  

Comment Code: 5600 5.12. Comments on the Proposed Post‐Injection Site Care Requirements (146.93)  

Comment: (k) Post‐injection site care and site closure  

(1) The owner or operator of a well must prepare, maintain, and comply with a  

plan for post‐injection site care and site closure that meets the requirements  

of paragraph (1)(ii) of this section and is acceptable to the Director.  

(i) 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.  

(ii) The post‐injection site care and site closure plan must include the  

following information:  

(A) The projected pressure differential between pre‐injection and projected  

post‐injection pressures in the injection zone;  

(B) The projected position of the carbon dioxide plume and associated pressure  

front at site closure as demonstrated in the area of review evaluation required  

under §146.25(b)(1), (3) and (5);  

(C) A description of post‐injection monitoring location, methods, and proposed  

frequency; and  

(D) A proposed schedule for submitting post‐injection site care monitoring  

results to the Director.  

(iii) Upon cessation of injection, owners or operators of wells 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.  

(iv) The owner or operator may modify and resubmit the post‐injection site care  

and site closure plan for the Director’s approval within 30 days of such change  

(2) The owner or operator shall perform monitoring following the cessation of  

injection as follows:  

(i) The owner or operator shall continue to conduct monitoring as specified in  

the Director‐approved post‐injection site care and site closure plan, pursuant  
to the performance based criteria described in §146.25(k)(2)(iii).  

(ii) The owner or operator may request and demonstrate to the satisfaction of  

the Director that the post‐injection site care and site closure plan should be  

revised to reduce the frequency of monitoring.  

(iii) Prior to authorization for site closure, the owner or operator must  

demonstrate to the Director, based on monitoring, other site‐specific data, and  

modeling that is reasonably consistent with site performance that no additional  

monitoring is needed to assure that the geologic sequestration project does not  

pose an endangerment to USDWs. The owner or operator must demonstrate, based on  

the current understanding of the site, including monitoring data and/or  

modeling, all of the following: (A) the estimated magnitude and extent of the  

project footprint (carbon dioxide plume and the area of elevated pressure) ; (B)  

the estimated location of the detectable carbon dioxide plume ; (C) that there  

is no significant leakage of either carbon dioxide or displaced formation fluids  

that is endangering USDWs; (D) that the injected or displaced fluids are not  

expected to migrate in the future in a manner that encounters a potential  

leakage pathway into an USDW; (E) that the injection wells at the site completed  

into or through the injection zone or confining zone are plugged and abandoned  

in accordance with these requirements; and (F) any remaining project monitoring  

wells at the site are being used and managed pursuant to a plan approved by the  

Director in accordance with §146.25(k)(4).  

(3) Notice of intent for site closure. The owner or operator 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.  

(4) 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 an USDW except that designated wells may  

remain unplugged pursuant to §146.25(k) (2)(iii)(F) with the consent of the  

owner and operator and pursuant to a post‐closure monitoring and plugging plan  

approved by the Director which shall provide for, and designate the person  

responsible for, operating and plugging all such monitoring wells in a manner  

which will not allow movement of injection or formation fluids that endangers an  

USDW.  

(5) Once the Director has authorized site closure, the owner or operator must  

submit a site closure report within 90 days after completion of all closure  
operations. The report must include:  

(i) Documentation of appropriate injection and monitoring well plugging as  

specified in §146.25(j) and paragraph (4) of this section. The owner or operator  

must provide a copy of a survey plat which has been submitted to the local  

zoning authority designated by the Director. The plat must indicate the location  

of the injection well(s) relative to permanently surveyed benchmarks. The owner  

or operator must also submit a copy of the plat to the Regional Administrator of  

the appropriate EPA Regional Office;  

(ii) 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  

(iii) The volume of fluid injected, the injection zone or zones into which it  

was injected, and the period over which injection occurred.  

(6) Each owner or operator of a injection well must provide notification to the  

designated state authority of the following information:  

(i) The fact that land has been used to sequester carbon dioxide;  

(ii) 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 Environmental  

Protection Agency Office to which it was submitted; and  

(iii) The volume of fluid injected, the injection zone or zones into which it  

was injected, and the period over which injection occurred.  

(7) The owner or operator must retain for three years following site closure,  

records collected during the post‐injection site care period. The owner or  

operator 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.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  
Letter ID: 0353 Comment ID: 28070 Letter Lines: 1093 to 1135  

Comment Code: 5650 5.13. Comments on the Proposed Emergency and Remedial Response

Requirements (146.94)  

Comment: (l) Emergency and Remedial Response Plan  

(1) As part of a permit application or request for revision to operate under  

this section, the owner or operator must provide the Director with an emergency,  

risk‐based remedial response plan that describes actions to be taken to address  

movement of the injection or formation fluids that may cause an endangerment to  

an USDW during construction, operation, closure and post‐closure periods.  

(2) If the owner or operator obtains evidence that the injected carbon dioxide  

stream, displaced formation fluids or an associated pressure front endangers an  

USDW, the owner or operator must:  

(i) Cease injection in a prudent manner considering circumstances.  

(ii) Take all steps reasonably necessary to identify and characterize the  

endangerment posed;  

(iii) Notify the Director or the designated representative within 24 hours of  

becoming aware of the endangerment; and  

(iv) Implement the emergency and remedial response plan approved by the Director  

and keep the Director apprized of the implementation.  

(3) 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.  

(4) The owner or operator must notify the Director and obtain his approval prior  

to conducting any well workover or other remediation measures not listed in the  

emergency and remedial response plan.  

(5) If an owner or operator obtains evidence that a pressure front associated  

with one geologic sequestration project intersects or will more likely than not  

intersect the pressure front or area of review associated with another project,  

the owner or operator obtaining such evidence must notify the Director. The  

Director shall notify the owner or operator of the other geologic sequestration  

project. If the Director determines that the pressure front associated with one  
project interferes or will more likely than not interfere with the ability of  

another project to comply with the terms of its permit(s), the Director may  

require the owners or operators of the interfering or potentially interfering  

projects to modify operations as necessary to mitigate or avoid such  

interference. Such modifications may also include modifications mutually agreed  

upon by the respective owners and operators and approved by the Director."  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.