### This comment letter response contains two parts:

(1) The original submittal from the commenter.

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

Notes about the response letters:

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

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

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

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

• Each response letter includes: comment text; an EPA

‐ assigned comment code; and an

individual response. These are described and explained below.

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

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

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

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

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

appropriately addressed.

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

Comment ID. Additionally, one or more Comment Codes (i.e., unique topic area ID) was

assigned to each discrete point raised by a commenter. This information was added to

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

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

construction requirements).

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

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

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

commenter was given a unique response.

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

Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter. As a result of this process, there is

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

and attention to each comment letter that was submitted.

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

Responses on each topic area are compiled and are also available in the rulemaking docket.

### October 9, 2009

Cynthia C. Dougherty

Director

Office of Ground Water and Drinking Water

U. S. Environmental Protection Agency

1200 Pennsylvania Ave., NW.

Washington, DC 20460

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

Dear Director Dougherty:

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

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

that these be adopted as the requirements for we lls used for geologic seque stration (GS) in oil

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

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

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

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

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

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

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

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

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

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

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

Background

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

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

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

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

continued efforts toward developing recommenda tions reflecting common views on a number of

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

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

May 14 and 15, 2009.

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

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

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

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

proposed language describing wells in classificati on (b)(4) that would establish a “bright line”

### Cynthia C. Dougherty

October 9, 2009

Page 2

definition distinguishing (1) wells that inject CO 2 

### for EOR/EGR and those that inject CO 2 

### for GS

in conjunction with EOR/EGR from (2) wells that inject CO 2 

### for GS where EOR/EGR activities

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

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

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

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

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

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

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

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

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

are not met.

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

agreed that wells used for GS in oil and gas rese rvoirs that do not meet th e criteria of paragraph

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

under the current Class II provisions to wells that inject CO 2 

### for EOR/EGR and GS, due to the

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

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

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

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

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

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

recommendations.

Recommended Provisions for GS in Oil and Gas Reservoirs

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

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

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

a new Part 146, Subpart I, the undersigned MSD part icipants have now agre ed that the addition

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

standard for primacy explained in this letter.

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

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

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

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

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

paragraph (b)(4) are not met.

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

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

### Cynthia C. Dougherty

October 9, 2009

Page 3

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

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

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

regulated under Class V as experime ntal wells until such time as the

Administrator establishes separate require ments by rule for the specific type of

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

that wells used for geologic sequestra tion of carbon dioxide streams into the

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

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

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

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

these revisions and the implementation of these requirements, the undersi gned MSD participants

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

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

rather than the alternative standard of section 14 25, especially where it will be clear that injection

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

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

incidental function of the GS injection activit ies subject to our prop osed requirements, and

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

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

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

operations, or

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

natural gas.

It should be noted that – as doe s EPA’s proposal for Class VI – th e attached proposal for section

146.25 requirements relies on the continued applicab ility of other provisi ons of EPA’s existing

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

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

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

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

### Cynthia C. Dougherty

October 9, 2009

Page 4

Conclusion

The undersigned respectfully submit the attached recommendations and request that EPA

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

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

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

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

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

the purpose of addressing verificatio n requirements for carbon credits.

Sincerely,

John McManus

Vice President, Environmental Services

American Electric Power

Kyle Isakower

Director, of Policy Analysis

American Petroleum Institute

D. Brian Williams

CO 2 

### Storage Manager

BP Alternative Energy North America Inc.

Karen St. John

Director Regulatory Affairs

BP America Inc.

### Cynthia C. Dougherty

October 9, 2009

Page 5

Robert F. Van Voorhees

Counsel to the Carbon Sequestration Council (CCS Contact Group)

Kurt Waltzer

Carbon Storage Development Coordinator

Clean Air Task Force

Sarah A. Edman

Manager, CCS Policy and Project Development

ConocoPhillips

Darlene Radcliffe

Director, Environmental Technology & Fuel Policy

Duke Energy

William L. Fang

Deputy General Counsel

Edison Electric Institute

Scott Anderson

Senior Policy Advisor, Climate and Air Program

Environmental Defense Fund

### Cynthia C. Dougherty

October 9, 2009

Page 6

Michael S. Beer

Vice President, Federa l Regulation and Policy

E.ON U.S. LLC

Tiffany Rau

Manager, Policy & Communications

Hydrogen Energy International LLC

Al Collins

Senior Director, Regulatory Affairs

Occidental Petroleum Corporation

Kevin Wanttaja

Manager, Environmental Services

Salt River Project

John A. King

CO 2 

### Manager - Americas

Shell Exploration and Production

Karl R. Moor

Vice President and Asso ciate General Counsel

Southern Company

### Cynthia C. Dougherty

October 9, 2009

Page 7

Darrick W. Eugene

General Counsel

Texas Carbon Capture & Storage Association

cc: Stephen Heare

Ann Codrington

Dina Kruger

Anhar Karimjee

Bruce Kobelski

Suzanne Kelly

Lee WhitehurstMulti-Stakeholder Discussions 

### Recommendation on

Requirements for Geologic Sequestrat ion in Oil and Gas Reservoirs

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

[Revised to incorporate additi onal MSD recommendations]

October 9, 2009

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

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

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

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

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

of the Director that existing wells are, and new we lls will be, sited in areas with a suitable geologic

system. The geologic syst em must be comprised of:

(1) An injection zone of sufficient areal exte nt, thickness, porosity, and permeability to

receive the total anticipated volume of the carbon dioxide stream;

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

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

USDW;

(b) Area of Review and Corrective Action

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

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

phases of the injected carbon dioxide stream.

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

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

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

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

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

that includes the following information:

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

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

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

which the model will be based;

(ii) A description of:

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

will be used to inform an area of review reevaluation; andGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

§146.25(b)(4), including what correctiv e action will be performed prior to

injection and what, if any, portions of the area of review will have corrective

action addressed on a phased basis and how the phasing will be determined;

how corrective action will be adjusted if there are changes in the area of

review; and how site access will be assured for future corrective action.

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

review and identify all wells that require corrective action:

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

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

fluids in the subsurface from the comm encement of carbon dioxide injection

activities until the plume movement ceases or pressure differentials sufficient to

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

longer present. The model must:

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

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

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

of injection;

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

their possible impact on model projections;

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

penetrations and beyond lateral spill points; and

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

formation fluids in the subsurface.

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

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

and abandoned wells and underground mine s, in the area of review that may

penetrate the confining zone. Provide a desc ription of each well’s type, construction,

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

additional information or evaluations the Director may require; and

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

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

formation fluids that may endanger USDWs;

(iv) Determine which active and inactive we lls 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.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

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

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

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

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

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

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

the monitoring and operational data by the owner or operator:

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

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

and identify all wells that require corrective action;

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

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

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

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

area of review and corrective action plan is needed.

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

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

through (C) of this subsection:

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

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

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

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

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

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

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

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

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

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

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

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

of review is phased.

(c) Financial Assurance

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

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

meets the requirements of § 146.25 (b)), inject ion well plugging (that meets the requirementsGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

### 4 of § 146.25(j)), and post-injection site care an d site closure (that m eets the requirements of

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

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

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

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

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

site care period.

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

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

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

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

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

that reduce the estimated costs of such plans.

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

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

closure.

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

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

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

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

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

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

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

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

(d) Well Construction Requirements

(1) Applicability

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

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

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

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

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

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

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

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

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

Multi-Stakeholder Discussions 

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

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

constructed and completed to:

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

USDW as a result of the planned injection operation;

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

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

tubing and long string casing.

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

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

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

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

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

Institute, ASTM International, or compar able standards acceptable to the Director.

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

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

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

following information:

(A) Depth to the injection zone;

(B) Hole size;

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

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

(D) Predicted corrosive characteristics of the combined carbon dioxide

stream and formation fluids;

(E) Down-hole temperatures and pressures;

(F) Lithology of injection and confining zones;

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

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

stream.

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

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

need not extend through the base of the lowermost USDW above the injection zoneGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

### 6 if a combination of cement ar ound the surface casing and intermediate or long-string

casing achieves continuous cement throug h the base of the lowermost USDW above

the injection zone.

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

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

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

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

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

alternative isolation techniques, provided th ese are demonstrated to be equivalent to

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

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

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

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

verified using technology capable of eval uating 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 fl uids through tubing with a packer set

at a depth opposite a cemented interva l at the location approved by the

Director.

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

requirements, the owner or operator must provide the following

information::

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

(2) Composition of the carbon dioxide stream.

(3) Maximum proposed injection temperature and pressure;

(4) Maximum proposed annular pressure;

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

and volume of the carbon dioxide stream;

(6) Size of casing; and

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

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

only to newly-drilled wells.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

### 7 (1) During the drilling and construction of an injection well, the owner or operator must run

appropriate logs, surveys and tests to determin e 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 agains t which future measurements may be compared.

The owner or operator must submit to the Director a descriptive report prepared by a

knowledgeable log analyst that includes an interpretation of the results of such logs and tests.

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

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

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

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

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

determine the location of the borehole;

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

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

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

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

channels or missing cement that would prevent compliance with

§146.25(d)(2).

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

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

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

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

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

channels or missing cement that would prevent compliance with

§146.25(d)(2).

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

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

(A) A pressure test with liquid or gas;

(B) Oxygen-activation logging;

(C) Tracer surveys;

(D) A temperature or noise log; or

(E) A casing inspection log.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

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

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

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

samples from the injection zone(s). The Dir ector 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 c onfining zones and conduct tests to verify

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

the requirements of (f)(1).

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

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

of such activities to the Director upon spu dding 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 reas onable 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 tran smissive. In no case may injection pressure

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

§144.12(a).

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

protecting USDWs and the well bore is prohibited.

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

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

positive pressure on the annulus.

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

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

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

and the long string casing. The owner or ope rator must install, test and use alarms andGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

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

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

(5) Mechanical integrity

(i) A well has mechanical integrity if:

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

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

adjacent to the injection well bore.

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

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

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

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

in §146.25(g)(2)(ii);

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

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

acceptable to the Director (e.g. includ ing 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 Administra tor, 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 m echanical 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 rest ricted at the time of approval by the

Administrator.

(v) In conducting and evaluating the tests en umerated 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 othe r 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 orGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

injection activity as stated in paragr aphs (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 poten tial value of monitoring wells to detect such

movement, the owner or operator of a well must prepare, maintain, and comply with a

testing and monitoring plan to verify that th e geologic sequestration project is operating as

permitted and is not endangering USDWs. The testing and monitoring plan must be

submitted with the permit application for Director approval, and must include a description

of how the owner or operator will meet the requirements of this section.

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

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

representative of its chemical and physical characteristics;

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

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

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

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

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

well is plugged;

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

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

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

(v) quality assurance provisions.

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

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

formation overlying the confining zone;

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

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

provide other site specific data;

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

appropriately porous and permeable formation overlying the injection zone;

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

or more USDWs;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

for loss of mass, thickness, cracking, pitti ng 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 construc tion materials, operating conditions, and

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

material strength and performance by:

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

with the carbon dioxide stream; or

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

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

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

Director;

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

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

computational modeling of the area of review evaluation required under

§ 146.25(b)(2); and

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

movement is occurring that would endanger an USDW.

(h) Reporting Requirements

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

permitted well:

(1) Semi-annual or less frequently as determ ined 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 tri ggers a shutdown device required pursuant

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

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

period and project cumulatively;

(vi) Monthly annulus fluid volume added; andGS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

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

(i) Periodic tests of mechanical integrity;

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

Director; and

(iii) Any well workover.

(3) Owners or operators must submit reports in an electronic format acceptable to the

Director. At the discretion of the Di rector, other formats may be accepted.

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

accordance with the provisions of this section.

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

an appropriate company official, c onfirming that the company has:

(A) reviewed the monitoring and operational data that are

relevant to a decision on whether to reevaluate the area of

review and the monitoring and operational data that are

relevant to a decision on whether to update a plan identified

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

(B) determined whether any updates were warranted by

material change in the monitoring and operational data or in

the evaluation of the monitoring and operational data by the

owner or operator.

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

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

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

paragraph. The Director may require submission of copies of any

updated plans and/or additional information regarding whether or

not updates of any particular plans are warranted.

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

whenever the Director determines that such a revision is necessary to

comply with the requirements of this subchapter.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

### 13 (i) Required permit application information

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

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

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

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

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

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

show the number, or name and location of all known injection wells, producing wells,

abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State or EPA

approved subsurface cleanup sites, surface bod ies of water, springs, mines (surface and

subsurface), quarries, water wells and other pert inent 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 ba sed upon modeling, using all available data

including data available from any logging and testing of wells.

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

site and overlying formations, which may include:

(i) Isopach maps of the proposed injecti on 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 re view 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 ha ve affected the proposed area of review

including knowledge of previous seismi c 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 e ffectiveness of the injection and confining

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

vertical permeability reservoir pressure an d 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, seis mic surveys, well logs, capillary pressure

tests and names and lithologic descriptions;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

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

fluid pressures; and

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

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

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

injection or confining zone(s). Such data should include a description of each well’s type,

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

additional information the Director may require;

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

all USDWs, the location of water wells and perenni al 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 geoche mical data on the proposed injection zone and

nearest adjacent porous and permeable formati on 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 phys ical characteristics of the carbon dioxide

stream;

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

characteristics of the injection zone and confining zone;

(10) The compatibility of the carbon dioxide st ream with fluids in the injection zone and

minerals in both the injection and the conf ining zone(s), based on the results of the

formation testing program or other data, and with the materials used to construct the well;

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

compromise containment;

(12) The results of the formation testing program as required in paragraph (j) of this section;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

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

construction;

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

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

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

(18) The proposed demonstration method for mech anical 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 monitori ng plan required by §146.25(g);

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

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

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

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

USDWs.

(j) Injection and monitor well plugging

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

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

mechanical integrity test.

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

with a well plugging plan for injection and monitor wells that is acceptable to the Director.

The requirement to maintain and implement an approved plan is directly enforceable

regardless of whether the requireme nt is a condition of the permit. The well plugging plan

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

information:

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

(A) Appropriate testing or determination of bottomhole reservoir pressure;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

example, through additional perforations) in other formations only if

required by the Director;

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

as specified in §146.25(f)(5);

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

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

bottom of each plug;

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

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

and fluid conditions; and

(G) The method of placement of the plugs.

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

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

state requirements.

(3) Notice of intent to plug. The owner or ope rator must notify the Director at least 60 days

before plugging of a well. At this time, if an y 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 plu gging the owner or operator must submit a

plugging report to the Director. The report must be certified as accurate by the owner or

operator and by the person who performed the plugging operation (if other than the owner

or operator.)

(k) Post-injection site care and site closure

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

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

this section and is acceptable to the Director.

(i) The owner or operator must submit the post-injection site care and site closure

plan as a part of the permit application to be approved by the Director.

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

information:

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

post-injection pressures in the injection zone;GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

pressure front at site closure as demons trated 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 cl osure plan or demonstrate to the Director

through monitoring data and modeling results that no amendment to the plan is

needed.

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

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

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

follows:

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

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

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

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

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

reduce the frequency of monitoring.

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

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

reasonably consistent with site performance that no additional monitoring is needed

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

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

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

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

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

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

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

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

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

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

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

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

to a plan approved by the Director in accordance with §146.25(k)(4).GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

### 18 (3) Notice of intent for site closure. The owne r 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 Direct or, a shorter notice period may be allowed.

(4) After the Director has authorized site cl osure, the owner or operator must plug all

monitoring wells in a manner which will not allow movement of injection or formation

fluids that endangers an USDW except that designated wells may remain unplugged pursuant

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

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

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

USDW.

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

closure report within 90 days after completi on 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 su bmitted 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 Re gional Administrator of the appropriate EPA

Regional Office;

(ii) Documentation of appropriate notificat ion and information to such State, local

and tribal authorities as have authority over drilling activities to enable such State and

local authorities to impose appropriate conditions on subsequent drilling activities

that may penetrate the injection and confining zone(s); and

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

injected, and the period over which injection occurred.

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

state authority of the following information:

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

(ii) The name of the State agency, local authority, and/or tribe with which the survey

plat was filed, as well as the address of the Regional Environmental Protection

Agency Office to which it was submitted; and

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

injected, and the period over which injection occurred.GS in Oil and Gas Reservoirs October 9, 2009

Multi-Stakeholder Discussions 

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

collected during the post-injection site care pe riod. 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 ta ken to address movement of the injection or

formation fluids that may cause an endanger ment to an USDW during construction,

operation, closure and post-closure periods.

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

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

or operator must:

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

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

endangerment posed;

(iii) Notify the Director or the design ated 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 re sume injection prior to remediation if the

owner or operator demonstrates that the in jection operation will not endanger USDWs.

(4) The owner or operator must notify the Di rector 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 eviden ce that a pressure front associated with

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

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

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

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

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

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

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

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

avoid such interference. Such modifications may also include modifications mutually

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

Commenter: John McManus

Organization: American Electric Power (AEP)

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

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

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

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

definition distinguishing (1) wells

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

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

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

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

remain in Class II and that wells used for EOR/EGR with GS

‐ that meet the (b)

(4) definition

‐ should also remain in Class II and be subject to the current

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

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

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

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

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

and the attached provisions provide specific recommended requirements for GS in

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

In the Multi

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

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

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

additional requirements different from those that would apply under the current

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

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

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

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

approach in its final GS rule.

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

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

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

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

Specifically, the undersigned recommend that the attached proposed requirements

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

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

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

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

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

primacy explained in this letter.

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

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

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

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

144.80(b) and 146.5(b) reading:

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

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

And

‐ consistent with the further recommendations presented by MSD participants on

May 14, 2009

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

read as follows:

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

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

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

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

Administrator establishes separate requirements by rule for the specific type of

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

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

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

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

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

"wells used for geologic sequestration that are regulated under another

Class"

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

implementation of these requirements, the undersigned MSD participants have

agreed that the attached proposed section 146.25 requirements should be subject

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

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

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

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

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

requirements, and accordingly such injection would not relate

‐ within the meaning

of section 1425

‐ to:

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

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

operations, or

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

natural gas.

It should be noted that

‐ as does EPA’s proposal for Class VI

‐ the attached

proposal for section 146.25 requirements relies on the continued applicability

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

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

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

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

C.F.R. §144.51(q). Requirements for 24

‐ hour reporting are imposed under 40

C.F.R. §144.51(l)(6).

Conclusion

The undersigned respectfully submit the attached recommendations and request

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

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

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

recommended in the joint letter submitted by participants in the Multi

‐

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

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

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

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

requirements for carbon credits.

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

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

EPA’s response to similar comments.

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

Comment: (a) Minimum Criteria for Siting

‐ The owner or operator must have demonstrated

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

be, sited in areas with a suitable geologic system. The geologic system must be

comprised of:

(1) An injection zone of sufficient areal extent, thickness, porosity, and

permeability to receive the total anticipated volume of the carbon dioxide

stream;

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

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

of fluids that endangers an USDW;

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

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

EPA’s response to similar comments.

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

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

(146.84)

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

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

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

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

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

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

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

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

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

the following information:

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

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

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

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

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

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

‐ Stakeholder

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

of §146.25(b)(4), including what corrective action will be performed prior to

injection and what, if any, portions of the area of review will have corrective

action addressed on a phased basis and how the phasing will be determined; how

corrective action will be adjusted if there are changes in the area of review;

and how site access will be assured for future corrective action.

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

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

Project, using computational modeling and available monitoring data, the

projected lateral and vertical migration of the carbon dioxide plume and

formation fluids in the subsurface from the commencement of carbon dioxide

injection activities until the plume movement ceases or pressure differentials

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

USDW are no longer present. The model must:

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

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

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

of injection;

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

their possible impact on model projections;

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

penetrations and beyond lateral spill points; and

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

fluids in the subsurface.

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

discoverable artificial penetrations into the confining zone, including active,

inactive and abandoned wells and underground mines, in the area of review that

may penetrate the confining zone. Provide a description of each well’s type,

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

completion, and any additional information or evaluations the Director may

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

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

formation fluids that may endanger USDWs;

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

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

displaced formation fluids that may endanger USDWs.

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

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

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

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

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

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

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

conduct the following whenever warranted by material change in the monitoring

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

by the owner or operator:

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

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

review and identify all wells that require corrective action;

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

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

subsection; and

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

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

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

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

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

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

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

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

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

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

‐

year period.

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

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

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

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

is not warranted by material change."

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

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

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

corrective action in the area of review is phased.

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

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

EPA’s response to similar comments.

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

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

Comment: (c) Financial Assurance

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

responsibility or provide and maintain financial responsibility and resources

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

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

‐ injection

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

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

manner prescribed by the Director until:

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

completion of the post

‐ injection site care and site closure plan as appropriate;

and

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

‐

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

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

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

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

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

‐ injection site care

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

conditions that reduce the estimated costs of such plans.

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

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

post

‐ injection site care and site closure.

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

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

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

(as required by §146. 25(j)) and post

‐ injection site care and site closure (as

required by §146. 25(k)).

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

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

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

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

(1).

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

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

EPA’s response to similar comments.

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

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

Comment: (d) Well Construction Requirements

(1) Applicability

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

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

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

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

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

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

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

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

USDW.

(2) Construction Requirements for newly

‐ drilled injection wells.

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

‐ drilled injection

wells are constructed and completed to:

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

result of the planned injection operation;

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

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

tubing and long string casing.

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

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

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

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

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

Petroleum Institute, ASTM International, or comparable standards acceptable to

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

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

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

must provide the following information:

(A) Depth to the injection zone;

(B) Hole size;

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

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

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

(E) Down

‐ hole temperatures and pressures;

(F) Lithology of injection and confining zones;

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

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

stream.

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

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

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

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

intermediate or long

‐ string casing achieves continuous cement through the base

of the lowermost USDW above the injection zone.

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

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

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

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

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

packers or alternative isolation techniques, provided these are demonstrated to

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

protect USDWs.

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

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

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

be verified using technology capable of evaluating cement quality and

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

(vi) Tubing and packer.

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

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

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

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

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

(3) Maximum proposed injection temperature and pressure;

(4) Maximum proposed annular pressure;

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

the carbon dioxide stream;

(6) Size of casing; and

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

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

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

EPA’s response to similar comments.

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

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

(146.87)

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

– The following

requirements apply only to newly

‐ drilled wells.

(1) During the drilling and construction of an injection well, the owner or

operator must run appropriate logs, surveys and tests to determine or verify the

depth, thickness, porosity, permeability, and lithology of, and the salinity of

any formation fluids in, all relevant geologic formations to evaluate

conformance with applicable injection well construction requirements and to

establish accurate baseline data against which future measurements may be

compared. The owner or operator must submit to the Director a descriptive report

prepared by a knowledgeable log analyst that includes an interpretation of the

results of such logs and tests. The Director may approve such additional or

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

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

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

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

to determine the location of the borehole;

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

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

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

to evaluate cement quality with sufficient radial resolution to identify

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

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

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

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

‐

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

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

to evaluate cement quality with sufficient radial resolution to identify

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

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

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

(A) A pressure test with liquid or gas;

(B) Oxygen

‐ activation logging;

(C) Tracer surveys;

(D) A temperature or noise log; or

(E) A casing inspection log.

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

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

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

cores or sidewall cores representative of the injection zone and confining

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

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

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

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

ormation temperature, formation fluid pH and conductivity, and reservoir

pressure of the injection zone(s).

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

determine fracture pressures of the injection and confining zones and conduct

tests to verify hydrogeologic and geomechanical characteristics of the injection

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

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

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

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

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

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

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

EPA’s response to similar comments.

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

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

Comment: (f) Injection well operating requirements

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

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

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

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

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

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

fractures in the confining zone or cause otherwise non

‐ transmissive faults

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

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

by 40 CFR §144.12(a).

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

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

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

must maintain a positive pressure on the annulus.

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

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

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

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

or operator must install, test and use alarms and automatic shut

‐ off systems,

designed to alert the operator and shut

‐ in the well when operating parameters

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

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

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

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

EPA’s response to similar comments.

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

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

Comment: (5) Mechanical integrity

(i) A well has mechanical integrity if:

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

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

adjacent to the injection well bore.

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

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

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

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

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

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

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

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

oxygen

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

under paragraph (i)(A) or (i)(B) of this section. Also, the Director may allow

the use of a test to demonstrate mechanical integrity other than those listed

above with the written approval of the Administrator. To obtain approval, the

Director must submit a written request to the Administrator, which must set

forth the proposed test and all technical data supporting its use. The

Administrator must approve the request if it will reliably demonstrate the

mechanical integrity of wells for which its use is proposed. Any alternate

method approved by the Administrator will be published in the Federal Register

and may be used in all States in accordance with applicable State law unless its

use is restricted at the time of approval by the Administrator.

(v) In conducting and evaluating the tests enumerated in this section or others

to be allowed by the Director, the owner or operator and the Director must apply

methods and standards generally accepted in the industry. When the owner or

operator reports the results of mechanical integrity tests to the Director,

he/she shall include a description of the test(s) and the method(s) used. In

making his/her evaluation, the Director must review monitoring and other test

data submitted since the previous evaluation.

(vi) The Director may require additional or alternative tests if the results

presented by the owner or operator under paragraph (d) of this section are not

satisfactory to the Director to demonstrate that there is no significant leak in

the casing, tubing or packer or significant movement of fluid into or between

USDWs resulting from the injection activity as stated in paragraphs (i)(A) and

(i)(B) of this section.

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

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

EPA’s response to similar comments.

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

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

Comment: (g) Testing and Monitoring

(1) Based on a site

‐ specific assessment of the potential for fluid movement from

the injection well or injection zone, and on the potential value of monitoringwells to detect such movement, the owner or operator of a well must prepare,

maintain, and comply with a testing and monitoring plan to verify that the

geologic sequestration project is operating as permitted and is not endangering

USDWs. The testing and monitoring plan must be submitted with the permit

application for Director approval, and must include a description of how the

owner or operator will meet the requirements of this section.

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

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

data representative of its chemical and physical characteristics;

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

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

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

least daily the pressure on the annulus between the tubing and the long strong

casing;

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

until the well is plugged;

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

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

a valid observation of the pressure fall

‐ off curve at least once every five

years; and

(v) quality assurance provisions.

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

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

formation overlying the confining zone;

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

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

to provide other site specific data;

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

plan in an appropriately porous and permeable formation overlying the injection

zone;

(iv) Periodic monitoring of water quality for constituents specified in the planin one or more USDWs;

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

water for loss of mass, thickness, cracking, pitting and other signs of

corrosion performed and recorded at least quarterly which may be modified to be

less frequent as approved by the Director based on construction materials,

operating conditions, and monitoring history to ensure that the well components

meet minimum standards for material strength and performance by:

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

the carbon dioxide stream; or

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

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

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

Director;

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

‐

specific conditions and risk

‐ based factors, necessary to support, upgrade, and

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

146.25(b)(2); and

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

movement is occurring that would endanger an USDW.

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

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

EPA’s response to similar comments.

Letter ID: 0353 Comment ID: 28067 Letter Lines: 734 to 924

Comment Code: 5500 5.10. Comments on the Proposed Reporting Requirements (146.91)

Comment: (h) Reporting Requirements

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

Director, for each permitted well:

(1) Semi

‐ annual or less frequently as determined by the Director reportscontaining:

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

characteristics of the carbon dioxide stream from the proposed operating data;

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

rate and volume, and annular pressure;

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

for annulus pressure or injection pressure as specified in the permit; (iv) A

description of any event which triggers a shutdown device required pursuant to

§146.25(f)(4) and the response taken;

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

period and project cumulatively;

(vi) Monthly annulus fluid volume added; and

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

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

(i)Periodic tests of mechanical integrity;

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

by the Director; and

(iii) Any well workover.

(3)Owners or operators must submit reports in an electronic format acceptable to

the Director. At the discretion of the Director, other formats may be accepted.

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

accordance with the provisions of this section.

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

company official, confirming that the company has:

(A)reviewed the monitoring and operational data that are relevant to a decision

on whether to reevaluate the area of review and the monitoring and operational

data that are relevant to a decision on whether to update a plan identified in

§146.25(i)(16) or (20) through (23); and(B)determined whether any updates were warranted by material change in the

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

operational data by the owner or operator.

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

modifications for each plan for which an update was determined to be warranted

pursuant to subparagraph (i) of this paragraph. The Director may require

submission of copies of any updated plans and/or additional information

regarding whether or not updates of any particular plans are warranted.

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

Director determines that such a revision is necessary to comply with the

requirements of this subchapter.

(i) Required permit application information This section sets forth the

information which the owner or operator must submit to the Director in order to

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

injection well or for authorization to operate an existing well must include the

following:

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

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

which a permit is sought and the applicable area of review. Within the area of

review, the map must show the number, or name and location of all known

injection wells, producing wells, abandoned wells, plugged wells or dry holes,

deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites,

surface bodies of water, springs, mines (surface and subsurface), quarries,

water wells and other pertinent surface features including structures intended

for human occupancy and roads. Only information of public record is required to

be included on this map;

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

data including data available from any logging and testing of wells.

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

proposed storage site and overlying formations, which may include:

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

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

two geologic cross sections of the area of review reasonably perpendicular toeach other showing the geologic formations from the surface to total depth of

the well.

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

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

determination that they would not interfere with containment;

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

review including knowledge of previous seismic events and history of these

events, including the presence and depth of seismic sources and a determination

that the seismicity would not compromise containment;

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

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

mineralogy, porosity, vertical permeability reservoir pressure and of the

injection and confining zone(s) within the area of review; including geologic

changes based on field data which may include geologic cores, outcrop data,

seismic surveys, well logs, capillary pressure tests and names and lithologic

descriptions;

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

area of review, such as information on fractures, stress, ductility, rock

strength, and in situ fluid pressures; and

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

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

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

penetrate the injection or confining zone(s). Such data should include a

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

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

Director may require;

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

lateral limits of all USDWs, the location of water wells and perennial springs

within the area of review, their positions relative to the injection zone(s) and

the direction of water movement, where known;

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

injection zone and nearest adjacent porous and permeable formation to the

confining zone, existing utilized water supply aquifers and any other USDWs

designated by the Director.(8) Proposed operating data:

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

stream;

(ii) Average and maximum surface injection pressure;

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

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

dioxide stream;

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

physical characteristics of the injection zone and confining zone;

(10) The compatibility of the carbon dioxide stream with fluids in the injection

zone and minerals in both the injection and the confining zone(s), based on the

results of the formation testing program or other data, and with the materials

used to construct the well;

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

compromise containment;

(12) The results of the formation testing program as required in paragraph (j)

of this section;

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

operation;

(14) A well bore schematic of the subsurface construction details and surface

wellhead construction;

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

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

(2);

(17) All available logging and testing program data on the well required by

§146.25(e)(1);

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

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

the financial responsibility requirements under §146.25(c);

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

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

(2);

(22) Proposed post

‐ injection site care and site closure plan required by

§146.25(k);

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

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

protection of USDWs.

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

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

EPA’s response to similar comments.

Letter ID: 0353 Comment ID: 28068 Letter Lines: 926 to 974

Comment Code: 5550 5.11. Comments on the Proposed Well Plugging Requirements (146.92)

Comment: (j) Injection and monitor well plugging

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

well with a buffer fluid, determine bottomhole reservoir pressure, and perform a

final external mechanical integrity test.

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

and comply with a well plugging plan for injection and monitor wells that is

acceptable to the Director. The requirement to maintain and implement an

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

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

the permit application and must include the following information:

(i) For injection wells and any monitor wells that penetrate the injection zone:(A) Appropriate testing or determination of bottomhole reservoir pressure;

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

example, through additional perforations) in other formations only if required

by the Director;

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

specified in §146.25(f)(5);

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

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

each plug;

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

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

fluid conditions; and

(G) The method of placement of the plugs.

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

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

requirements.

(3) Notice of intent to plug. The owner or operator must notify the Director at

least 60 days before plugging of a well. At this time, if any changes have been

made to the original well plugging plan, the owner or operator must also provide

the revised well plugging plan. At the discretion of the Director, a shorter

notice period may be allowed.

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

submit a plugging report to the Director. The report must be certified as

accurate by the owner or operator and by the person who performed the plugging

operation (if other than the owner or operator.)

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

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

EPA’s response to similar comments.Letter ID: 0353 Comment ID: 28069 Letter Lines: 976 to 1091

Comment Code: 5600 5.12. Comments on the Proposed Post

‐ Injection Site Care Requirements (146.93)

Comment: (k) Post

‐ injection site care and site closure

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

plan for post

‐ injection site care and site closure that meets the requirements

of paragraph (1)(ii) of this section and is acceptable to the Director.

(i) The owner or operator must submit the post

‐ injection site care and site

closure plan as a part of the permit application to be approved by the Director.

(ii) The post

‐ injection site care and site closure plan must include the

following information:

(A) The projected pressure differential between pre

‐ injection and projected

post

‐ injection pressures in the injection zone;

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

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

under §146.25(b)(1), (3) and (5);

(C) A description of post

‐ injection monitoring location, methods, and proposed

frequency; and

(D) A proposed schedule for submitting post

‐ injection site care monitoring

results to the Director.

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

submit an amended post

‐ injection site care and site closure plan or demonstrate

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

to the plan is needed.

(iv) The owner or operator may modify and resubmit the post

‐ injection site care

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

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

injection as follows:

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

the Director

‐ approved post

‐ injection site care and site closure plan, pursuantto the performance based criteria described in §146.25(k)(2)(iii).

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

the Director that the post

‐ injection site care and site closure plan should be

revised to reduce the frequency of monitoring.

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

demonstrate to the Director, based on monitoring, other site

‐ specific data, and

modeling that is reasonably consistent with site performance that no additional

monitoring is needed to assure that the geologic sequestration project does not

pose an endangerment to USDWs. The owner or operator must demonstrate, based on

the current understanding of the site, including monitoring data and/or

modeling, all of the following: (A) the estimated magnitude and extent of the

project footprint (carbon dioxide plume and the area of elevated pressure) ; (B)

the estimated location of the detectable carbon dioxide plume ; (C) that there

is no significant leakage of either carbon dioxide or displaced formation fluids

that is endangering USDWs; (D) that the injected or displaced fluids are not

expected to migrate in the future in a manner that encounters a potential

leakage pathway into an USDW; (E) that the injection wells at the site completed

into or through the injection zone or confining zone are plugged and abandoned

in accordance with these requirements; and (F) any remaining project monitoring

wells at the site are being used and managed pursuant to a plan approved by the

Director in accordance with §146.25(k)(4).

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

Director at least 120 days before site closure. At this time, if any changes

have been made to the original post

‐ injection site care and site closure plan,

the owner or operator must also provide the revised plan. At the discretion of

the Director, a shorter notice period may be allowed.

(4) After the Director has authorized site closure, the owner or operator must

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

or formation fluids that endangers an USDW except that designated wells may

remain unplugged pursuant to §146.25(k) (2)(iii)(F) with the consent of the

owner and operator and pursuant to a post

‐ closure monitoring and plugging plan

approved by the Director which shall provide for, and designate the person

responsible for, operating and plugging all such monitoring wells in a manner

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

USDW.

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

submit a site closure report within 90 days after completion of all closureoperations. The report must include:

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

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

must provide a copy of a survey plat which has been submitted to the local

zoning authority designated by the Director. The plat must indicate the location

of the injection well(s) relative to permanently surveyed benchmarks. The owner

or operator must also submit a copy of the plat to the Regional Administrator of

the appropriate EPA Regional Office;

(ii) Documentation of appropriate notification and information to such State,

local and tribal authorities as have authority over drilling activities to

enable such State and local authorities to impose appropriate conditions on

subsequent drilling activities that may penetrate the injection and confining

zone(s); and

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

was injected, and the period over which injection occurred.

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

designated state authority of the following information:

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

(ii) The name of the State agency, local authority, and/or tribe with which the

survey plat was filed, as well as the address of the Regional Environmental

Protection Agency Office to which it was submitted; and

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

was injected, and the period over which injection occurred.

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

records collected during the post

‐ injection site care period. The owner or

operator must deliver the records to the Director at the conclusion of the

retention period, and the records must thereafter be retained at a location

designated by the Director for that purpose.

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

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

EPA’s response to similar comments.Letter ID: 0353 Comment ID: 28070 Letter Lines: 1093 to 1135

Comment Code: 5650 5.13. Comments on the Proposed Emergency and Remedial Response

Requirements (146.94)

Comment: (l) Emergency and Remedial Response Plan

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

this section, the owner or operator must provide the Director with an emergency,

risk

‐ based remedial response plan that describes actions to be taken to address

movement of the injection or formation fluids that may cause an endangerment to

an USDW during construction, operation, closure and post

‐ closure periods.

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

stream, displaced formation fluids or an associated pressure front endangers an

USDW, the owner or operator must:

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

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

endangerment posed;

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

becoming aware of the endangerment; and

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

and keep the Director apprized of the implementation.

(3) The Director may allow the operator to resume injection prior to remediation

if the owner or operator demonstrates that the injection operation will not

endanger USDWs.

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

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

emergency and remedial response plan.

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

with one geologic sequestration project intersects or will more likely than not

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

the owner or operator obtaining such evidence must notify the Director. The

Director shall notify the owner or operator of the other geologic sequestration

project. If the Director determines that the pressure front associated with oneproject interferes or will more likely than not interfere with the ability of

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

require the owners or operators of the interfering or potentially interfering

projects to modify operations as necessary to mitigate or avoid such

interference. Such modifications may also include modifications mutually agreed

upon by the respective owners and operators and approved by the Director."

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

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

EPA’s response to similar comments.