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.
March 31, 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 (Attachment A) with the recommendation that these be adopted as the 

requirements for geologic sequestration (GS) in oil and gas reservoirs that does not meet the 

provisions of the (b)(4) language recommended in the joint letter submitted by the MultiStakeholder Group (MSG) on December 23, 2008. We respectfully request that EPA include in 

its Notice of Data Availability (NODA) on this proposed rule a request for public comment on 

these proposed requirements. 

Background

As indicated in the joint MSG letter submitted 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 MSG has continued efforts toward developing 

recommendations reflecting common views on a number of the issues in this rulemaking. 

The March 17 letters noted that the MSG has followed a modified approach to focus in part on 

the potential publication of a NODA. The undersigned organizations are sending this letter at 

this time because we understand that the publication of a NODA is still contemplated. The 

December 23, 2008 joint MSG letter explained the agreement reached on the proposed language 

describing wells in classification (b)(4) that establishes a “bright line” definition for wells that 

inject CO2 for EOR/EGR and GS. The signatories to that letter recommended, consistent with 

EPA’s intent, that these wells should remain in Class II and be subject to the current 

requirements for Class II. We 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. We noted our 

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 specifically address requirements for GS in oil and gas reservoirs when the criteria of 

paragraph (b)(4) are not met. 
Cynthia C. Dougherty 

March 31, 2009 

Page 2 

In our discussions since then, MSG participants have agreed that these wells used for GS in oil 

and gas reservoirs should be subject to a set of 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 

reflected in the four letters you received on March 17 from MSG participants. Each of these 

letters asks EPA to include this approach in its final GS rule. The MSG has also discussed the 

desirability for EPA to take advantage of the opportunity to publish proposed regulations for this 

category of wells for public review and comment in conjunction with a NODA, allowing others 

to address this recommendation in responding to the NODA. That discussion is also reflected in 

several of the March 17 letters. To that end, the signatories to this letter submit the language in 

Attachment A with the request that EPA include in its NODA a request for public comment on 

these proposed requirements. 

The signatories to this letter and Attachment A do not include all of the members of the MSG 

who signed the December 23, 2008 MSG letter because consensus has not been achieved on all 

of the provisions. We will continue the MSG discussion of these provisions to seek consensus, 

as noted in some of the March 17 letters. We hope to achieve consensus on these requirements 

in time to provide comments on the NODA. Rather than press forward with our discussions and 

withhold these recommendations until consensus is achieved, thus possibly missing an 

opportunity for obtaining broader review and comment, it seemed more beneficial at this point to 

provide you a set of provisions that reflect the efforts to date, address the appropriate issues, and 

provide a good basis for seeking comment on this recommended approach. We have discussed 

the potential benefit of submitting the attached recommendations with the MSG and understand 

that you may hear from some of the other participants with respect to this request. 

Recommended Provisions for GS in Oil and Gas Reservoirs

The undersigned recommend that the requirements in Attachment A be added to Class II through 

an amendment to add a new section 146.25, as shown. The MSG discussions, however, have 

also considered that these requirements could be promulgated as a new Class VII in a new Part 

146, Subpart I. To acknowledge those discussions and to provide EPA with a basis for seeking 

comment on that alternative approach, this letter also addresses that alternative. 

The Class II Approach

In conjunction with the requirements proposed in Attachment A, the addition of these 

requirements as section 146.25 should be accompanied by the addition of the word “and” at the 

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

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

March 31, 2009 

Page 3 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration 

except those wells described in paragraphs (b)(4) and (b)(5) of this section or 

otherwise excluded from this Class. 

The Class VII Approach

Alternatively, if a new Class VII were created, a new subsection (g) could be added to sections 

144.5, 144.80 and 146.5 as follows: 

(g) Class VII. Wells injecting a carbon dioxide stream for geologic sequestration 

in oil and gas formations and where the criteria of paragraph (b)(4) are not met. 

And subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to read as follows: 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration 

except those wells described in subsections (b)(4) and (g) of this section or 

otherwise excluded from this Class. 

Conclusion

The undersigned submit these recommendations with the request that the recommendations be 

published as a basis for seeking public comment on this approach and the related issues in 

conjunction with any NODA that is published. In addition, we are committed to continuing the 

MSG discussions with an objective of developing additional specific recommendations for 

improvement of a final rule that could be adopted, consistent with your previously published 

schedule, by late 2010 or early 2011 or sooner. 

As 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. Accordingly, 

we specifically recommend that these requirements be published for comment in conjunction 

with a NODA if one is published. 

Sincerely, 

Kyle Isakower 

Director, of Policy Analysis 

American Petroleum Institute 
Cynthia C. Dougherty 

March 31, 2009 

Page 4 

Craig Walters 

General Manager, Enhanced Oil Recovery 

Anadarko Petroleum Corporation 

Michael E. Moore 

Vice President External Affairs & CCS Business Development 

Blue Source LLC 

Brian Williams 

Global CO2 Storage Manager 

BP Alternative Energy North America Inc. 

Karen St. John 

Director Regulatory Affairs 

BP America Inc. 

Robert F. Van Voorhees 

Counsel to the Carbon Sequestration Council (CCS Contact Group) 

Ronald T. Evans 

Senior Vice President, Reservoir Engineering 

Denbury Resources Inc. 
Cynthia C. Dougherty 

March 31, 2009 

Page 5 

William L. Fang 

Deputy General Counsel 

Edison Electric Institute 

 

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 

Karl R. Moor 

Vice President and Associate General Counsel 

Southern Company 
Cynthia C. Dougherty 

March 31, 2009 

Page 6 

L. Stephen Melzer 

President 

Texas Carbon Capture & Storage Association 

cc: Steve Heare 

 Ann Codrington 

 Bruce Kobelski 

 Suzanne Kelly 

 Lee Whitehurst 
ATTACHMENT A 

Requirements for Geologic Sequestration 

Oil and Gas Reservoirs 

§ 146.25 Geologic sequestration in oil or gas reservoirs for wells under §146.5(b)(5) 

 

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

meeting the classification criteria of 40 C.F.R. §146.5(b)(5) shall be subject to the following 

requirements in lieu of the requirements of 40 C.F.R. §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 a USDW; 

(b) Area of Review and Corrective Action

(1) The area of review is based on computational modeling using all available data including 

monitoring and operational data that account for the physical and chemical properties of all 

phases and volumes 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 

(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 

Multi-Stakeholder Discussions
GS in Oil and Gas Reservoirs March 31, 2008 

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, identify all wells that require corrective action, and perform corrective action on 

those wells: 

(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 a 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; and 

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

penetrations. 

(ii) Using methods approved by the Director, identify all known 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 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 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) When monitoring and operational conditions warrant, including in conjunction with 

reviews conducted pursuant to §146.25(h)(4), the owner or operator must: 

Multi-Stakeholder Discussions 2 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(i) Reevaluate the area of review in the same manner specified in §146.25(b)(3)(i); 

(ii) Identify all wells in the reevaluated area of review that require corrective action in 

the same manner specified in §146.25(b)(3)(ii). 

(iii) Perform corrective action on wells requiring corrective action in the reevaluated 

area of review in the same manner specified in §146.25(b)(2)(ii)(B) and (4); and 

(iv) 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. 

(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 

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 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 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)). 

(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)).

Multi-Stakeholder Discussions 3 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(d) Well Construction Requirements 

(1) Applicability 

(i) Existing wells must meet the construction requirements of 40 C.F.R. §146.22. 

(ii) Newly-drilled wells in existing fields where carbon dioxide injection has occurred 

are subject to the construction requirements of 40 C.F.R. §146.22 if: 

(A) They meet the requirements for casing and cementing applicable to 

permitted Class II injection wells operated in that field in conjunction with 

the extraction of hydrocarbons; and 

(B) Well injection will not result in the movement of fluids into an 

underground source of drinking water so as to create a significant risk to the 

health of persons. 

(iii) Except as provided in paragraph (d)(1)(ii) of this section, newly-drilled wells shall 

be subject to the requirements of subsection (d)(2) of this section. 

(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 that endangers a USDW; 

(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 operating 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 determine and specify casing and cementing requirements, the owner or 

operator must provide the following information: 

(A) Depth to the injection zone; 

(B) Hole size; 

Multi-Stakeholder Discussions 4 

 
GS in Oil and Gas Reservoirs March 31, 2008 

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

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

(D) Predicted corrosive characteristic 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. 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, would create a cement bond through the confining zone, and which 

must extend to the injection zone and must be isolated by placing cement and/or 

other isolation technologies as necessary to provide adequate isolation of the 

injection zone and provide for protection of 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 operating 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 for the Director to determine and specify requirements for 

tubing and packer, the owner or operator must submit the following 

information: 

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

Multi-Stakeholder Discussions 5 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(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; 

(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 require such logs and tests as may be needed after taking into account the 

availability in the area of the drilling site of data having similar quality and reliability as would 

be obtained with new logs and tests, the construction plan, and the need for additional 

information that may arise from time to time as the construction of the well progresses and 

these may include the following: 

(i) Deviation checks during drilling on all holes constructed by drilling a pilot hole 

that is enlarged by reaming or another method. Such checks must be at sufficiently 

frequent intervals to determine the location of the borehole and to assure that 

vertical avenues for fluid movement in the form of diverging holes are not created 

during drilling; 

(ii) Before and upon installation of the surface casing: 

(A) Resistivity, spontaneous potential, and caliper logs before the casing is 

installed; and 

(B) A cement evaluation log or logs after the casing is set and cemented. 

(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) and/or map(s) after the casing is set and 

cemented to evaluate cement quality with sufficient radial resolution to 

Multi-Stakeholder Discussions 6 

 
GS in Oil and Gas Reservoirs March 31, 2008 

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: 

(A) A pressure test with liquid or gas; 

(B) Diagnostic tools such as oxygen-activation logging; 

(C) A temperature or noise log; 

(D) A casing inspection log; and 

(E) Any alternative methods that provide 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. 

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

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

activities to the Director 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 C.F.R. 

§144.12(a). 

Multi-Stakeholder Discussions 7 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(2) Injection of the CO2 stream into any annulus or between the outermost casing 

protecting USDWs and the well bore is prohibited. 

(3) For injection wells constructed with injection tubing and packer, 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. For 

injection wells constructed with injection tubing and packer, 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. 

Notes: 

The duty to establish and maintain mechanical integrity is already imposed under 40 C.F.R. 

§144.51(q)(1). 

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).

(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 a 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 – for wells 

constructed with an injection tube and packer – 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 

Multi-Stakeholder Discussions 8 

 
GS in Oil and Gas Reservoirs March 31, 2008 

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 

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. 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, for wells constructed with 

Multi-Stakeholder Discussions 9 

 
GS in Oil and Gas Reservoirs March 31, 2008 

injection tubing and packer, 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) a quality assurance plan. 

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

(i) Continuous monitoring for pressure changes in an appropriately porous and 

permeable formation overlying the confining zone. When a well is installed to 

enable such monitoring, the owner or operator shall, on a specified frequency or at 

specified times, sample the formation and analyze for constituents specified in the 

plan; 

(ii) The use of indirect, geophysical techniques to determine the position of the CO2 

stream front, the water quality in a designated formation, or to provide other site 

specific data; 

(iii) Periodic monitoring of water quality in an appropriately porous and permeable 

formation overlying the injection zone; 

(iv) Periodic monitoring of water quality in one or more USDWs; 

(v) Corrosion monitoring of the well materials 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 

Multi-Stakeholder Discussions 10 

 
GS in Oil and Gas Reservoirs March 31, 2008 

computational modeling of the area of review evaluation required under § 146.84(b); 

and 

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

movement is occurring that would endanger a USDW. 

(h) Reporting and Certification 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) Owners or operators must submit an annual certification, signed by the appropriate 

company official, that the company has: 

Multi-Stakeholder Discussions 11 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(i) reviewed the area of review and all of the required plans; 

(ii) reviewed all monitoring and operational data since the previous 

certification that are relevant to a decision on whether to update the area of 

review and each plan; 

(iii) determined with regard to the area of review and each plan whether an 

update was warranted; and 

(iv) completed an update pursuant to section 146.84(f) for the area of review 

if warranted by material change, 

(v) completed an update and attached a summary of the modifications for 

each of the plans for which an update was warranted by material change. 

(5) The Director may require submission of copies of any updated plans and/or additional 

information regarding the reasons why updates of particular plans have or have not been 

prepared. 

(6) The Director may require reevaluation of the area of review pursuant to section 

146.84(f) or the revision of any required plan whenever the Director determines on the basis 

of information available to him that an update is necessary to comply with the requirements 

of this Subpart. 

(i) Required permit 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 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 within the area of review. 

(4) Sufficient information on the geologic structure and reservoir properties of the proposed 

storage site and overlying formations, which may include: 

Multi-Stakeholder Discussions 12 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(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 on the confining zone(s) within the area of review; 

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 must include a description of each well’s type, 

construction, date drilled, location, depth, record of plugging and/ or completion, and any 

additional information the Director may require; 

(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: 

Multi-Stakeholder Discussions 13 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(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) 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; 

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

characteristics of the injection zone and confining zone; 

(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 wellbore schematic of the subsurface construction details and surface wellhead 

construction; 

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

(16) Proposed corrective action plan for artificial penetrations within the area of review, if 

necessary; 

(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 monitoring 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); 

Multi-Stakeholder Discussions 14 

 
GS in Oil and Gas Reservoirs March 31, 2008 

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

(24) Any other information requested by the Director. 

(j) Injection 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 plan that is acceptable to the Director. The requirement to maintain and implement 

an approved plan is directly enforceable regardless of whether the requirement is a condition 

of the permit. The well plugging plan must be submitted as part of the permit application 

and must include the following information: 

(i) Appropriate test or measure to determine bottomhole reservoir pressure; 

(ii) Appropriate testing methods to ensure final external mechanical integrity as 

specified in §146.25(f)(5); 

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

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

each plug; 

(v) 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 

(vi) The method of placement of the plugs. 

(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

Multi-Stakeholder Discussions 15 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(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 pressure differential between pre-injection and projected postinjection 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 monitor the site following the cessation of injection. 

(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 can 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 

Multi-Stakeholder Discussions 16 

 
GS in Oil and Gas Reservoirs March 31, 2008 

following: (A) the estimated magnitude and extent of the project footprint (CO2 

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

CO2 plume ; (C) that there is no significant leakage of either CO2 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 a 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 managed by a person and in a manner acceptable to the Director. 

(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 a 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) Records reflecting the nature, composition and volume of the carbon dioxide 

stream. 

(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 

Multi-Stakeholder Discussions 17 

 
GS in Oil and Gas Reservoirs March 31, 2008 

(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. 

(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 a 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 and associated pressure front endangers a 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 intersect the area of review 

associated with another project, the owner or operator obtaining such evidence must 

notify the Director. If the Director determines that the pressure front associated 

with one project will interfere with the ability of another project to comply with the 

terms of its permit(s), the Director may require the owner or operator of the 

potentially interfering project to modify operations as necessary to avoid such 

interference. Such modification may include mutually agreed modifications in 

operations to both projects or other actions if the respective owners and operators 

agree to requirements to implement modifications or other actions approved by the 

Director that will mitigate the interference.” 

Multi-Stakeholder Discussions 18 

 
GS in Oil and Gas Reservoirs March 31, 2008 

Note: 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).

Multi-Stakeholder Discussions 19 

 
Letter ID: 0290 

Commenter: Kyle Isakower 

Organization: American Petroleum Institute 

Letter ID: 0290 Comment ID: 25281 Letter Lines: 64 to 77 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: In our discussions since then, MSG participants have agreed that these wells 

used for GS in oil and gas reservoirs should be subject to a set of 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 reflected in the 

four letters you received on March 17 from MSG participants. Each of these 

letters asks EPA to include this approach in its final GS rule. The MSG has also 

discussed the desirability for EPA to take advantage of the opportunity to 

publish proposed regulations for this category of wells for public review and 

comment in conjunction with a NODA, allowing others to address this 

recommendation in responding to the NODA. That discussion is also reflected in 

several of the March 17 letters. To that end, the signatories to this letter 

submit the language in Attachment A with the request that EPA include in its 

NODA a request for public comment on these proposed requirements. 

Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing 

oil and gas recovery should remain under the Class II Program. EPA also recognizes that the oil 

and gas industry has decades of experience injecting CO2 for the purpose of EOR, and that sites 

used for EOR may be suitable for GS and may be among the first GS sites. However, EPA 

believes that injection for the primary purpose of long term storage is sufficiently different from 

Class II EOR operations and warrants tailored requirements. For example, the volume of CO2 

anticipated to be injected in Class VI wells is significantly greater than for Class II wells. 

Reservoir pressure conditions will also be different, with Class VI injection operations involving 

large volumes of CO2 and likely having higher pressures within their storage formations than 

Class II EOR projects. 

Letter ID: 0290 Comment ID: 25282 Letter Lines: 96 to 139 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: The undersigned recommend that the requirements in Attachment A be added to 

Class II through an amendment to add a new section 146.25, as shown. The MSG 

discussions, however, have also considered that these requirements could be 

promulgated as a new Class VII in a new Part 146, Subpart I. To acknowledge 

1
those discussions and to provide EPA with a basis for seeking comment on that 

alternative approach, this letter also addresses that alternative. 

[In the section below, the text in all CAPS denotes added text. For redline 

strikeout version of this attachment see PDF Docket ID EPA-HQOW-2008-0390-0290.] 

The Class II Approach 

In conjunction with the requirements proposed in Attachment A, the addition of 

these requirements as section 146.25 should be accompanied by the addition of 

the word "and" at the end of paragraphs 144.5(b)(4), 144.80(b)(4) and 146.5(b) 

(4) as proposed in the December 23 MSG letter and 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 subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to read as 

follows: 

(f) Class VI. Wells INJECTING A CARBON DIOXIDE STREAM FOR GEOLOGIC 

SEQUESTRATION EXCEPT THOSE WELLS DESCRIBED IN PARAGRAPHS (B)(4) AND 

(B) 

(5) OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS. 

The Class VII Approach 

Alternatively, if a new Class VII were created, a new subsection (g) could be 

added to sections 144.5, 144.80 and 146.5 as follows: 

(g) Class VII. Wells injecting a carbon dioxide stream for geologic 

sequestration in oil and gas formations and where the criteria of 

paragraph (b)(4) are not met. 

And subsections 144.5(f), 144.80(f) and 146.5(f) should be revised to read as 

follows: 

(f) Class VI. Wells INJECTING A CARBON DIOXIDE STREAM FOR GEOLOGIC 

SEQUESTRATION EXCEPT THOSE WELLS DESCRIBED IN SUBSECTIONS (B)(4) AND 

(G) 

OF THIS SECTION OR OTHERWISE EXCLUDED FROM THIS CLASS. 

Individual Response: As described above, EPA agrees that injection of CO2 for the primary 

purpose of enhancing oil and gas recovery should remain under the Class II Program, but that 

there are significant differences between how ER and GS projects are operated. EPA disagrees 

2
that the creation of a Class VII well category for GS that occurs in oil and gas formations is 

necessary because the Class VI requirements are appropriate for GS in all formations. For more 

information, please see the discussion on transition of Class II wells in the preamble to the final 

GS rule. 

Letter ID: 0290 Comment ID: 25284 Letter Lines: 143 to 156 ; 218 to 1062 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: The undersigned submit these recommendations with the request that the 

recommendations be published as a basis for seeking public comment on this 

approach and the related issues in conjunction with any NODA that is published. 

In addition, we are committed to continuing the MSG discussions with an 

objective of developing additional specific recommendations for improvement of a 

final rule that could be adopted, consistent with your previously published 

schedule, by late 2010 or early 2011 or sooner. 

As 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. Accordingly, we specifically 

recommend that these requirements be published for comment in conjunction with a 

NODA if one is published. 

ATTACHMENT A 

Requirements for Geologic Sequestration 

Oil and Gas Reservoirs 

§ 146.25 Geologic sequestration in oil or gas reservoirs for wells under 

§146.5(b)(5) 

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

sequestration and meeting the classification criteria of 40 C.F.R. §146.5(b)(5) 

shall be subject to the following requirements in lieu of the requirements of 40 

C.F.R. §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; 

3
(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 a USDW; 

(b) Area of Review and Corrective Action 

(1) The area of review is based on computational modeling using all available 

data including monitoring and operational data that account for the physical and 

chemical properties of all phases and volumes 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 

(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, identify all wells that require corrective action, and perform 

corrective action on those wells: 

(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 a 

4
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; and 

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

penetrations. 

(ii) Using methods approved by the Director, identify all known 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 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 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) When monitoring and operational conditions warrant, including in conjunction 

with reviews conducted pursuant to §146.25(h)(4), the owner or operator must: 

(i) Reevaluate the area of review in the same manner specified in §146.25(b)(3) 

(i); 

(ii) Identify all wells in the reevaluated area of review that require 

corrective action in the same manner specified in §146.25(b)(3)(ii). 

(iii) Perform corrective action on wells requiring corrective action in the 

reevaluated area of review in the same manner specified in §146.25(b)(2)(ii)(B) 

and (4); and 

5
(iv) 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. 

(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 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 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 postinjection 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 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)). 

(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)). 

(d) Well Construction Requirements 

(1) Applicability 

6
(i) Existing wells must meet the construction requirements of 40 C.F.R. §146.22. 

(ii) Newly-drilled wells in existing fields where carbon dioxide injection has 

occurred are subject to the construction requirements of 40 C.F.R. §146.22 if: 

(A) They meet the requirements for casing and cementing applicable to permitted 

Class II injection wells operated in that field in conjunction with the 

extraction of hydrocarbons; and 

(B) Well injection will not result in the movement of fluids into an underground 

source of drinking water so as to create a significant risk to the health of 

persons. 

(iii) Except as provided in paragraph (d)(1)(ii) of this section, newly-drilled 

wells shall be subject to the requirements of subsection (d)(2) of this section. 

(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 that endangers a USDW; 

(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 operating 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 determine and specify 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 characteristic of the combined carbon dioxide stream and 

formation fluids; 

(E) Down-hole temperatures and pressures; 

(F) Lithology of injection and confining zones; 

7
(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. 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, would create a cement bond through the confining zone, and 

which must extend to the injection zone and must be isolated by placing cement 

and/or other isolation technologies as necessary to provide adequate isolation 

of the injection zone and provide for protection of 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 operating 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 for the Director to determine and specify requirements for tubing 

and packer, the owner or operator must submit 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; 

(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 

8
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 require such logs and tests as 

may be needed after taking into account the availability in the area of the 

drilling site of data having similar quality and reliability as would be 

obtained with new logs and tests, the construction plan, and the need for 

additional information that may arise from time to time as the construction of 

the well progresses and these may include the following: 

(i) Deviation checks during drilling on all holes constructed by drilling a 

pilot hole that is enlarged by reaming or another method. Such checks must be at 

sufficiently frequent intervals to determine the location of the borehole and to 

assure that vertical avenues for fluid movement in the form of diverging holes 

are not created during drilling; 

(ii) Before and upon installation of the surface casing: 

(A) Resistivity, spontaneous potential, and caliper logs before the casing is 

installed; and 

(B) A cement evaluation log or logs after the casing is set and cemented. 

(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) and/or map(s) after the casing is set and cemented 

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: 

(A) A pressure test with liquid or gas; 

(B) Diagnostic tools such as oxygen-activation logging; 

(C) A temperature or noise log; 

(D) A casing inspection log; and 

(E) Any alternative methods that provide 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 

9
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. 

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

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

submit a schedule of such activities to the Director 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 C.F.R. §144.12(a). 

(2) Injection of the CO2 stream into any annulus or between the outermost casing 

protecting USDWs and the well bore is prohibited. 

(3) For injection wells constructed with injection tubing and packer, 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. For injection wells constructed with injection tubing and 

packer, 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 

10
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. 

Notes: 

The duty to establish and maintain mechanical integrity is already imposed under 

40 C.F.R. §144.51(q)(1). 

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). 

(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 a 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 - for wells constructed with an injection tube and packer - 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. 

11
(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. 

(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. 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, for wells 

constructed with injection tubing and packer, 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) a quality assurance plan. 

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

(i) Continuous monitoring for pressure changes in an appropriately porous and 

permeable formation overlying the confining zone. When a well is installed to 

enable such monitoring, the owner or operator shall, on a specified frequency or 

at specified times, sample the formation and analyze for constituents specified 

in the plan; 

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

the CO2 stream front, the water quality in a designated formation, or to provide 

other site specific data; 

(iii) Periodic monitoring of water quality in an appropriately porous and 

permeable formation overlying the injection zone; 

(iv) Periodic monitoring of water quality in one or more USDWs; 

(v) Corrosion monitoring of the well materials 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 sitespecific conditions and risk-based factors, necessary to support, upgrade, and 

improve computational modeling of the area of review evaluation required under § 

146.84(b); and 

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

movement is occurring that would endanger a USDW. 

(h) Reporting and Certification 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: 

13
(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) Owners or operators must submit an annual certification, signed by the 

appropriate company official, that the company has: 

(i) reviewed the area of review and all of the required plans; 

(ii) reviewed all monitoring and operational data since the previous 

certification that are relevant to a decision on whether to update the area of 

review and each plan; 

(iii) determined with regard to the area of review and each plan whether an 

update was warranted; and 

(iv) completed an update pursuant to section 146.84(f) for the area of review if 

warranted by material change, 

(v) completed an update and attached a summary of the modifications for each of 

the plans for which an update was warranted by material change. 

(5) The Director may require submission of copies of any updated plans and/or 

additional information regarding the reasons why updates of particular plans 

have or have not been prepared. 

(6) The Director may require reevaluation of the area of review pursuant to 

section 146.84(f) or the revision of any required plan whenever the Director 

determines on the basis of information available to him that an update is 

14
necessary to comply with the requirements of this Subpart. 

(i) Required permit 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 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 

within the area of review. 

(4) Sufficient 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 

15
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 on the confining zone(s) within the area of 

review; 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 must include a 

description of each well’s type, construction, date drilled, location, depth, 

record of plugging and/ or completion, and any additional information the 

Director may require; 

(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) 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; 

(10) Proposed formation testing program to obtain an analysis of the chemical 

and physical characteristics of the injection zone and confining zone; 

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

compromise containment; 

16
(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 wellbore schematic of the subsurface construction details and surface 

wellhead construction; 

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

(16) Proposed corrective action plan for artificial penetrations within the area 

of review, if necessary; 

(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 monitoring 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. 

(j) Injection 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 plan that is acceptable to the Director. The requirement to 

maintain and implement an approved plan is directly enforceable regardless of 

whether the requirement is a condition of the permit. The well plugging plan 

must be submitted as part of the permit application and must include the 

17
following information: 

(i) Appropriate test or measure to determine bottomhole reservoir pressure; 

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

as specified in §146.25(f)(5); 

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

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

each plug; 

(v) 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 

(vi) The method of placement of the plugs. 

(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 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 

18
(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 monitor the site following the cessation of 

injection. 

(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 can 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 (CO2 plume and the area of elevated pressure) ; (B) the 

estimated location of the detectable CO2 plume ; (C) that there is no 

significant leakage of either CO2 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 a 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 managed by a person and in a manner acceptable to the Director. 

(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 

19
plug all monitoring wells in a manner which will not allow movement of injection 

or formation fluids that endangers a 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) Records reflecting the nature, composition and volume of the carbon 

dioxide stream. 

(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. 

(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, 

20
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 

a 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 and associated pressure front endangers a 

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 intersect the area of 

review associated with another project, the owner or operator obtaining such 

evidence must notify the Director. If the Director determines that the pressure 

front associated with one project will interfere with the ability of another 

project to comply with the terms of its permit(s), the Director may require the 

owner or operator of the potentially interfering project to modify operations as 

necessary to avoid such interference. Such modification may include mutually 

agreed modifications in operations to both projects or other actions if the 

respective owners and operators agree to requirements to implement modifications 

or other actions approved by the Director that will mitigate the interference." 

Note: 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). 

Individual Response: As described above, EPA agrees that injection of CO2 for the primary 

purpose of enhancing oil and gas recovery should remain under the Class II Program, but that 

there are significant differences between how EOR and GS projects are operated for purposes of 

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protecting USDWs from endangerment. EPA does not believe that GS in oil and gas formations 

should be regulated separately from GS in other geologic formations or that the creation of a 

Class VII well category for GS is necessary. EPA has taken a regulatory approach which 

promotes USDW protection, incorporates flexibility or the discretion of the permitting authority 

when appropriate, seeks to limit burden on owners or operators and permitting agencies, and 

provides a foundation for national consistency in permitting of GS projects. For example, under 

the final rule, many of the permit requirements must be established through site-specific plans 

(e.g., AOR and corrective action plan, testing and monitoring plan, etc.) developed by the owner 

or operator and approved by the Director. Consequently EPA expects that owners or operators 

will consult with the Director as they develop, implement, and update these plans. Additionally, 

the Director has the discretion to approve alternatives to the requirements in some cases. For 

example, the Director may in certain situations modify the length of the post-injection site care 

period under §146.93, allow the use of alternate methods for mechanical integrity testing under 

§146.89, or grant waivers from the requirement to inject below the lowermost USDW under 

§146.95. 

The Agency believes that the nature and risks of CO2 injection for the primary purpose of long 

term storage poses different risks than injection for the primary purpose of EOR, and therefore 

has developed new Class VI regulations to address these unique risks. For example, the volume 

of CO2 anticipated to be injected for long term storage is significantly greater than for EOR 

operations. Reservoir pressure conditions will also be different, with Class VI injection 

operations involving large volumes of CO2 and likely having higher pressures within their 

storage formations than Class II EOR projects, which may lead to fluid movement that endangers 

a USDW. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS Rule. For more information, 

please see the discussion on transition of Class II wells in the preamble to the final GS rule.