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.
BP Alternative Energy International Limited, a company registered in England and Wales with the company number 1553681, VAT number GB 243 5105 93 and whose registered office is 

Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP. 

BP Alternative Energy Holdings Limited, a company registered in England and Wales with the company number 2515099, VAT number GB 243 5105 93 and whose registered office is 

Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP 

December 23, 2008 

Via Electronic Mail and Overnight Mail 

 

Docket ID No.: EPA-HQ-OW-2998-0390 

 

Cynthia C. Dougherty 

Director 

Office of Ground Water and Drinking Water 

Environmental Protection Agency, Mailcode: 2822T

1200 Pennsylvania Ave., NW. 

Washington, DC 20460 

Re: BP Alternative Energy North America Inc.’s Comments on United States 

Environmental Protection Agency’s Proposed Rule: Federal Requirements 

under the Underground Injection Control (UIC) Program for Carbon Dioxide 

(CO2) Geologic Sequestration (GS) Wells 

Dear Director Dougherty: 

 BP Alternative Energy North America Inc. (“BP”) is pleased to submit its 

comments on the United States Environmental Protection Agency’s (“EPA”) Proposed 

Rule: Federal Requirements Under the Underground Injection Control (UIC) Program 

for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells (“Proposed Rule”),

published on July 25, 2008 for review and comment by the public (73 Fed. Reg. 

43492-541). BP appreciates the opportunity to participate in this rulemaking process 

and has been actively engaged in the process to date. 

 

As an initial matter, we applaud EPA’s significant efforts to include and 

encourage broad stakeholder participation both before and after publication of the 

Proposed Rule. Furthermore, it is evident from the Proposed Rule that EPA 

considered and incorporated many of the stakeholders’ comments from the public 

workshops. Accordingly, EPA adopted a framework that is intended to encourage the 

CO2 Storage Manager, CCS Technology 

BP Alternative Energy North America Inc. 

D. Brian Williams 

BP Alternative Energy North America, Inc. 

501 Westlake Park Blvd. 

MC – 9.188A 

P O Box 3092 

Houston, Texas 77253-3092 

Direct: (281) 366-4833 

Main: (281) 366-2000 

Mobile: (713) 471-6474 

Fax: (281) 366-7416 

williadb@bp.com 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 2 of 20 

deployment of carbon capture and sequestration or storage (“CCS”) in a manner that 

is protective of underground sources of drinking water (“USDWs”). There is growing 

consensus among scientists, environmental groups and members of government that 

CCS will play a critical role in addressing greenhouse gas emissions. 

The comments herein are founded on knowledge and experience gained 

through decades of industry operations, and are intended to provide constructive input 

on the Proposed Rule. BP’s comments are based upon two important and mutuallyachievable goals: (1) protecting USDWs; and (2) adopting regulations that are 

reasonable, cost-effective and facilitate geologic sequestration of CO2. BP concurs 

with EPA’s conclusion that CCS presents a “key climate change mitigation 

technology.” (73 Fed. Reg. at 43495.) 

In the context of geologic sequestration of CO2, it is imperative to maintain 

flexibility in the regulatory requirements due to the site-specific nature of this activity 

and because the technology is continually advancing. For geologic sequestration of 

CO2, “one-size-fits-all” is not an approach that is necessarily or reasonably protective 

of USDWs. Rather, each site has site-specific characteristics that merit differing 

requirements. Indeed, what may appear to be a standard protective measure in the 

context of a particular site could actually have the opposite effect and increase 

potential risks at another site. (See A Technical Basis for Carbon Dioxide Storage, CO2

Capture Project, December 2008.) 

Consequently, BP strongly encourages EPA to provide performance standards 

for the various phases of a geologic sequestration project (i.e., site characterization, 

operation and site closure), while providing the Director flexibility to add requirements 

as necessary to address site-specific characteristics. This type of approach, 

consistent with Regulatory Alternative 2, offers the degree of flexibility that the 

permitting authority will require to tailor fit-for-purpose requirements that address site 

specific characteristics. Furthermore, it ensures that project costs will be 

commensurate with the geologic risk, and will further the continued evolution of the 

best technologies. 

 Our comments address the following important topics: (A) Enhanced Oil 

Recovery or Enhanced Gas Recovery (“EOR/EGR”) and CO2 Storage; (B) Wells, 

Monitoring & Operations; (C) Site Closure Period; (D) Financial Assurance; and (E) 

Issues Related To Oil & Gas Production. BP further joins in the comments submitted 

by the American Petroleum Institute. 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 3 of 20 

(A) Importance of EPA’s Recognition That EOR/EGR and Storage of CO2 

Occur At the Same Time 

BP commends EPA for its recognition, as stated in the Preamble of the 

Proposed Rule, that oil and gas reservoirs will play a valuable role in the geologic 

storage of CO2. Two of the reasons cited by EPA are: (1) oil and gas reservoirs are 

natural storage containers that have trapped fluid (both liquid and gaseous) 

hydrocarbons for millions of years; and (2) oil and gas exploration and production 

activities have created a wealth of knowledge and geologic data that can support the 

site characterization process for geologic sequestration. (73 Fed. Reg. at 43502-03.) 

Indeed, oil and gas reservoirs have proven capable of containing water-buoyant fluids 

for millions of years. These reservoirs are well studied and they offer the best 

opportunity to kick-start large-scale geologic sequestration of CO2, building on 100 

years of oil and gas field operating experience. Consequently, many oil and gas 

reservoirs are available now to serve CCS projects at a commercial scale, and will add 

insights for subsequent application to other formations. 

EPA should provide further discussion and acknowledgement in its Proposed 

Rule that, when CO2 is injected for use in EOR/EGR projects, geologic sequestration 

(or long term storage) of CO2 occurs during EOR/EGR operations and continues after 

EOR/EGR operations cease (“EOR and Storage”). Furthermore, it is critical that EPA 

support and encourage geologic sequestration of CO2 in these well-studied and 

proven oil and gas reservoirs by amending certain elements of the Proposed Rule to 

clarify and streamline requirements. EPA’s recognition of EOR and Storage will 

provide a much-needed near-term, economic incentive to CCS projects. Incentivizing 

the use of anthropogenic CO2 for EOR/EGR will provide many lasting benefits to the 

United States, by significantly reducing current CO2 emissions and increasing energy 

security. 

It has become increasingly clear that early EOR and Storage projects will 

significantly advance the deployment of CCS technology and geologic sequestration of 

CO2 for many reasons: 

• Oil and gas formations offer the best characterized sites among potential 

sinks for anthropogenic CO2; 

• Much of the required infrastructure and operational experience is already in 

place; 

• Class II requirements have proven to be an effective regulatory framework 

in protecting USDWs in the context of CO2 EOR operations, evidenced by 

more than 30 years of experience in the Permian Basin and more than 25 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 4 of 20 

years of miscible gas injection projects on the North Slope of Alaska (where 

CO2 comprises 25% of the miscible gas injected); 

• Demand for large volumes of CO2 for EOR is increasing1; and 

• EOR can provide a revenue stream to supplement the economics of earlymover CCS projects. 

EOR and Storage have the added benefit of increasing domestic energy 

supplies in the face of increasing demand. Carbon dioxide injection has proven 

capable of increasing oil or gas recovery in mature fields from 5% to more than 20%. 

The Department of Energy estimates that EOR has the potential to add 40-80 billion 

barrels of oil reserves in the United States, which is 2 to 4 times the current United 

States’s total proven reserve. The Intergovernmental Panel on Climate Change 

(“IPCC”) has agreed that EOR technology can provide a significant kick-start on 

proving geologic sequestration of CO2 on a commercial scale. Indeed, the early 

commercial scale CCS projects will probably employ EOR and Storage as their basis of 

design, which will extensively inform the technical development and safe deployment 

of CCS projects in other types of geologic formations.2

 

(1) Brief Explanation of EOR/EGR Operations Utilizing CO2

Currently, EOR/EGR operators purchase CO2 for injection. This can represent a 

significant portion of the cost of an EOR/EGR project. Consequently, CO2 is a valuable 

commodity to EOR/EGR operators and is treated accordingly. Because it is a valuable 

commodity in EOR/EGR operations, CO2 is not emitted or vented to the atmosphere 

during operations or after operations cease. Any injected CO2 that returns to the 

surface during production operations is separated from the hydrocarbons and reinjected for additional enhanced recovery use. 

Approximately 30% to 50% of the injected CO2 volume typically remains 

permanently stored in the oil or gas reservoir after production operations cease. The 

injected CO2 is monitored in the formation and injection operations are designed to 

minimize CO2 procurement and maximize oil (and recycled CO2) production. Despite 

best efforts to re-use all the CO2, additional trapping of CO2 occurs with each 

subsequent injection cycle, necessitating further purchases of CO2. When the EOR 

 1

 Currently, over 2 billion cubic feet of naturally-occurring CO2 is used daily for EOR operations and the 

volume is growing. 

2 Notably, it is estimated that site characterization of saline reservoirs will likely cost tens of millions of 

dollars and take years of study to permit one commercial scale saline storage reservoir. 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 5 of 20 

operations cease (and the field is blown down to recover any CO2 available for use in 

another operation), wells are closed and the remainder of the injected CO2 remains 

permanently stored underground. However, an EOR operator could quite easily, at its 

option, manage operations to store the injected CO2 for the long term (rather than 

recover it). 

The foregoing demonstrates that, based on decades of experience gained in 

existing EOR/EGR operations utilizing CO2, EPA should acknowledge in the Final Rule 

preamble that injected CO2 can be trapped and stored for long term during EOR 

operations and continues afterwards. Furthermore, existing Class II regulations and 

industry practice employ proven methodologies to conduct these operations in a safe 

manner that is protective of USDWs. 

 

(2) Requested Amendments to Proposed Rule

For the reasons stated above, EPA should expand its discussion and 

acknowledge in the Final Rule text and preamble that, when CO2 is injected for use in 

EOR/EGR projects, geologic sequestration (or long term storage) of CO2 occurs during 

EOR/EGR operations and continues after operations cease – thus EOR and Storage. 

BP supports EPA’s statement that EOR/EGR, as long as any production is occurring, 

will continue to be permitted under the Class II program. 

We also understand that it is EPA’s intent, which we strongly support, that the 

proven Class II program applies to storage of CO2 that is occurring during and in 

connection with EOR/EGR operations. Such an approach is logical, technically sound, 

and protective of USDWs as demonstrated by decades of safe operations. 

Accordingly, EPA should amend the Proposed Rule language and expand its 

discussion in the Final Rule preamble to clarify that (a) when CO2 is injected for EOR 

and Storage, the applicable requirements are under Class II; and (b) when CO2 is 

exclusively injected for storage, the applicable requirements are under Class VI. 

(i) Clear Well Classification With Respect to EOR and Storage

BP requests that EPA amend sections 144.3, 144.6, 144.80, 146.5 and 146.81 

of the Proposed Rule to clarify that (a) Class II applies to EOR/EGR operations where 

geologic sequestration of CO2 is occurring during or in connection with EOR/EGR 

operations or activities (i.e. EOR and Storage); and (b) Class VI applies when the 

exclusive purpose is geologic sequestration of CO2. In addition to the reasons stated 

above, this clarity is needed because some amount of CO2 is sequestered or stored 

during EOR/EGR operations regardless of the intent of the operator. As currently 

drafted, the Proposed Rule may be interpreted – contrary to EPA’s intent – to require 

EOR/EGR operations to proceed under Class VI. API has submitted specific language 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 6 of 20 

to clarify that the applicable well class is Class II. We support API’s proposed 

language modifications to sections 144.3, 144.6, 144.80, 146.5 and 146.81 of the 

Proposed Rule. 

In addition, we have participated in discussions among multi-stakeholders 

including environmental groups, various associations and different industries (the 

“Multi-Stakeholder Discussions Group”); we also support the language recommended 

in the correspondence from the MSDG dated December 23, 2008 (the “MSDG 

Proposal”) to sections 144.6, 144.80 and 146.5(f) establishing a “bright line” for wells 

injecting CO2 for EOR and Storage. The MSDG Proposal defines a “bright line” for 

wells that inject CO2 for EOR and Storage, and consistent with EPA’s intent, remain in 

Class II and are subject to the existing Class II regulations – which have adequately 

safeguarded USDWs in the context of EOR/EGR operations for decades. 

The MSDG has also agreed to continue discussions regarding specific rules that 

would be applicable to geologic sequestration of CO2 in oil and gas formations 

following the completion of EOR/EGR production. We intend to participate in these 

negotiations. The development of a subclass under Class II or Class II-B regulations 

would result in a regulatory framework that would effectively protect USDWs and also 

promote the geologic sequestration of CO2 in oil and gas formations, especially 

following the cessation of EOR/EGR production activities. 

The advantages of a subclass dedicated to geologic sequestration in oil and gas 

formations are that a Class II-B will address risks associated specifically with oil and 

gas formations, rely upon information and data gathered during the terminated 

EOR/EGR production activities and maintain permitting authority under a single agency 

with historical knowledge and expertise about the former operations and the receiving 

oil and gas formation. This would maximize the efficient use of administrative 

resources and allow for seamless transitioning of operations from EOR and geologic 

sequestration of CO2 to injection of CO2 only for geologic sequestration. 

BP requests that EPA consider the foregoing discussion of a subclass or Class 

II-B wells for oil and gas formations for future rulemaking. However, in the context of 

the current Proposed Rule, we submit the following recommendations on the 

question of grandfathering. 

(ii) Grandfathering – Transitioning from EOR and Storage to 

Exclusively CO2 Storage

After the EOR and Storage projects conclude production of oil or gas, injection 

of CO2 may continue at the option of the operator to utilize fully all available pore 

space. EPA regulations should facilitate this transition from EOR and Storage to 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 7 of 20 

exclusively storage operations when EOR/EGR operations are completed. EPA’s 

decision to allow grandfathering of construction requirements in sections 146.81 and 

146.86 of the Proposed Rule is an excellent example of both protective and 

reasonable regulation. BP supports EPA’s proposal and recommends that EPA 

expand the grandfathering provisions to encourage and facilitate continued injection of 

CO2 exclusively for storage when EOR/EGR operations cease. 

Specifically, the Proposed Rule should be modified also to allow grandfathering 

of sections 146.88(e) and (f) (continuous recording devices and down-hole automatic 

shut-off devices, respectively) regarding Operations; and Section 146.89(b) and (c) 

(continuous monitoring and specific yearly tests, respectively) regarding Mechanical 

Integrity. Existing, operationally-compliant, Class II EOR-wells will continue to protect 

USDWs, as established by their operational histories, even when injection is for the 

exclusive purpose of CO2 sequestration without the foregoing additional Operation or 

Mechanical Integrity requirements. In addition, the following sections of the Proposed 

Rule simply will not be applicable or pertinent at the time of transition because these 

provisions presume that no injection has commenced. These sections are as follows: 

• Permit Application § 146.82(g) and (j); 

• Area of Review § 146.84 (b)(2)(iv), (c)(1) and (d); 

• Logging Sampling and Testing § 146.87(a), (b) and (f); and 

• Testing and Monitoring § 146.90 (b), (d), (g) and (h). 

These provisions should not and cannot apply when a Class II EOR and Storage 

project transitions to an exclusively storage project because, as a practical matter, 

performance of certain “baseline measurements,” “model predictions,” “witnessing 

of logging and testing,” and “corrective actions” will not be possible prior to injection 

of CO2. 

 

In sum, EPA should expand the grandfathering provisions to encourage 

continued storage of CO2 after EOR/EGR operations have ceased. Most of the 

existing Class II requirements that were appropriate for regulation of EOR and Storage 

will continue to operate effectively and to safeguard USDWs during exclusively 

storage operations. Finally, appropriately expanded grandfathering will facilitate 

optimal utilization of these proven oil and gas reservoirs for geologic sequestration of 

CO2. 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 8 of 20 

CCS in connection with EOR provides a forward-looking energy policy for the 

United States, as it will significantly reduce CO2 emissions with the added benefit of 

increasing energy security through increased domestic oil production. 

(B) WELLS, MONITORING & OPERATIONS 

In general, regulations for geologic sequestration should provide for effective 

storage management by requiring the following activities: 

 

• Site characterization that validates the geological model of the storage site 

and confirms potential leakage pathways have been identified and 

evaluated; 

• Risk assessment that builds upon the predicted behavior and movement of 

the CO2 in the reservoir over time and confirms that the potential for 

leakage has been evaluated through site characterization; and 

• A monitoring plan that measures the performance of the highest leakage 

risk parameters and validates or updates predictive performance models. 

The appropriate implementation of these key areas will ensure the safe and secure 

operation of a geologic sequestration project. 

(1) Importance of Well Integrity 

EPA has appropriately recognized that wells are a fundamental component of a 

secure system for the long-term geologic sequestration of CO2. As such, applying 

appropriate well design, construction & operating requirements is critical to the 

delivery of secure storage. As previously discussed, oil and gas operators have nearly 

four decades of experience, via past and existing production operations, in 

constructing and operating CO2 EOR/EGR wells in a safe and secure manner. 

Notably, Class II requirements have proven to be effective in ensuring the nonendangerment of USDWs. Therefore, BP believes it would be prudent to rely upon 

this extensive existing regulatory and industry experience and knowledge in setting 

Class VI requirements for wells that inject CO2 for long term sequestration. 

(2) Flexibility in Design of Monitoring Programs and Selection of 

Technologies

BP agrees with EPA that monitoring is important. For example, once a site has 

been selected, appropriate baseline surveys should be conducted and analyzed prior 

to commencing operations. During operations and at site closure, appropriate 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 9 of 20 

monitoring technologies should be applied to confirm the integrity and effectiveness 

of the storage site. However, there is a common misperception that, in order to 

achieve secure storage, a large amount of monitoring is required. The United Nations 

states that “the proportion of CO2 retained by appropriately selected and managed 

sites is likely to exceed 99% over 1,000 years.” Thus, the key to secure storage is 

the appropriate selection and management of the site and these activities should be 

the focus of any regulatory framework for CO2 geo-sequestration. If done properly, a 

selected site will be secure with a monitoring program that is designed and focused 

on the particular storage site. 

BP has significant and highly relevant experience around monitoring of the 

subsurface and the surface. For many decades, BP has been effectively employing a 

number of monitoring technologies to ensure the safety and integrity of its customary 

oil and gas operations, including CO2 EOR-related operations since the 1970’s in West 

Texas and Alaska. Notably, since 2004 BP has been operating the In Salah, Algeria, 

CO2 storage project where BP (and partners) has been storing around 1 million tones 

CO2 per year in a deep saline formation close to a producing gas field. The In Salah 

CO2 Storage project also incorporates a research project to test CO2 storage 

monitoring technologies with a program that is much more extensive than would be 

appropriate for a commercial project. At In Salah, BP is testing new technologies 

(such as satellite imagery and micro-seismic) and conventional oilfield technologies 

(such as tracers and conventional 3D seismic) to compare and contrast results as the 

partnership endeavors to design and develop monitoring technologies and 

methodologies that are reliable and cost-effective, given the expectation of future 

commercial application. 

Before initiating injection at In Salah, BP conducted a thorough assessment of 

potential leakage paths at the site; BP then tailored the monitoring program to address 

those site-specific risks. There are two other monitored, industrial-scale CO2 injection 

projects in the world (at Sleipner and Weyburn) and the site-specific nature of 

monitoring requirements is demonstrated by comparing these three CO2 storage 

projects – monitoring that works well at one location may not work at all in another 

location. 

With respect to monitoring requirements in general, EPA should adopt 

regulations that are performance and risk-based and will result in a site-specific 

monitoring program that is designed to understand the location, movement and 

stabilization of the CO2 plume in the subsurface as well as the early identification of 

any leakage for appropriate corrective action. BP commends EPA for its efforts in this 

regard, but believes that further modification is necessary. BP agrees with the 

proposal to allow a phased approach to conduct corrective action in an Area of Review 

that has pre-existing well penetrations. Existing wells within the AoR may be ideal 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 10 of 20 

candidates for conversion to monitoring or injection wells during the life of the project 

and, therefore, should not be plugged and abandoned prior to injection. Existing wells 

within the likely plume area that are not plugged and abandoned should have 

diagnostic testing to ensure there is minimal risk of vertical leakage prior to conversion 

to monitoring or injection status. 

Furthermore, in various parts of the Proposed Rule, EPA has prescribed 

particular monitoring technologies. Mandating any specific technology(ies) would 

have the adverse effect of (1) promoting particular technologies to the exclusion of 

other developed – and to be developed – technology(ies), and (2) substantially 

increasing costs without necessarily contributing to the protection of USDWs. This 

would hinder the development and deployment of CCS at commercial scale. 

Moreover, it would discourage the development of other technologies. BP therefore 

strongly discourages EPA from promulgating regulations that mandate the use of any 

specific monitoring technology. 

(3) Specific Comments

In addition to the foregoing, BP respectfully submits the following areas of 

specific comment: 

(i) Well Design and Construction To Avoid Corrosion

One area of comment requested by EPA relates to requirements for 

“degradation-resistant well construction materials, such as acid-resistant cements and 

corrosion resistant casing.” (73 Fed. Reg. at 43510) Based upon historical industry 

experience and field studies, this would be an excessive requirement and not 

reasonably necessary to protect USDWs. Risk Profile of a CO2 Geological Storage 

Project: Wells, by Christopher, Crow, Dodds, Wright, Williams, March 2008. 

BP strongly discourages EPA from setting a requirement to use degradationresistant materials & cement. Actual field observations based upon sampling of in 

situ casing and annular cements do not support this general requirement. The studies 

referenced by EPA in its Preamble exposed cement in a laboratory setting to a 

continuously-refreshed supply of CO2-saturated brine, which then reportedly caused 

the cement to degrade. (Duguid et al., 2004 and Kutchko et al., 2007.) These studies 

represent variations in cement alteration rates due to curing and exposure conditions, 

but neither supports the requirement for the use of degradation-resistant materials 

and cement because the laboratory procedures that were used do not necessarily 

represent the actual barrier exposure conditions in an appropriately cemented 

operating well. Indeed, the findings of Kutchko’s laboratory study suggested there 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 11 of 20 

would be limited degradation even after decades, which is consistent with the field 

study results of Carey et al., 2007. 

EPA’s rulemaking should give considerable weight to documented field surveys 

which provide more relevant well information, such as those conducted at the 

SACROC development in the Permian Basin (ref. Carey et al., 2007) and in Colorado 

(ref. Crow et al, and CO2 Capture Project, 2008). Both of these field studies identified 

that hydraulic isolation was maintained across the caprock, and the majority of cement 

reaction was localized to the area near the CO2 interval. Field results indicate it is the 

appropriate placement of cement, and not the type of cement, that is key to delivery 

of effective isolation and hence prevention of casing corrosion. Furthermore, cement 

placement to completely fill the annular space between borehole and casing is the 

primary means of achieving this objective. 

Based on the foregoing, degradation-resistant materials should not be 

mandated for all projects, without regard to site-specific characteristics. Rather, the 

application of degradation-resistant materials & cement, if any, should be defined on 

site-specific characteristics. 

BP strongly supports, with one modification discussed below, EPA’s actual 

language of the Proposed Rule in section 146.86(b)(5), which establishes a reliable 

performance standard that will achieve protection of USDWs. Section 146.86(b)(5) 

states, “Cement and cement additives must be compatible with the carbon dioxide 

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

over the design life the geologic sequestration project.“ BP recommends that EPA’s 

discussion in the Preamble should be consistent with the actual language of the 

Proposed Rule to ensure clarity and remove any ambiguity regarding the performancebased approach set forth in the Proposed Rule. 

Furthermore, section 146.86(b)(5) should be amended to base the choice of 

casing and cement materials on the planned operating life of the well as opposed to 

the ultimate duration of the geologic sequestration project. EPA may have set the 

duration as the life of the project in an effort to prevent corrosion of the casing over 

the long term after injection has ceased. However, this legitimate concern is 

mitigated by appropriate plugging of the static well at the end of its life. This plugging 

could employ corrosion-resistant material, if an extra level of mitigation were deemed 

necessary at that time based upon site characteristics. API has submitted specific 

language to address the foregoing. We support API’s proposed language modification 

to section 144.86 (b)(5). 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 12 of 20 

(ii) Horizontal Wells Should Be Approved for Geologic Sequestration

BP agrees with EPA’s discussion regarding the usefulness and benefits of 

constructing horizontal wells in geologic sequestration projects. It is evident that EPA 

has done a good amount of research in this area and is well informed on this topic. 

BP has direct experience with horizontal wells used in connection with geologic 

sequestration. At In Salah, 1mmtpa CO2 is being sequestered in a formation that is 

6,000ft deep, 60ft thick and has permeability of only 10mD. These characteristics are 

very similar to many deep saline formations in the United States. To do this, requires 

only three wells, but the wells have very long horizontal sections in the storage 

formation. In fact, each well is about as long as it is deep. Horizontal wells provide a 

means of achieving high performance completions that optimize/improve injectivity. 

Additionally, horizontal wells can reduce the risk of leakage because their use limits 

the number of penetrations through the caprock. There are other options to optimize 

injectivity as well that include, but should not be limited to, hydraulic fracture 

treatments, multiple injection points along the wellbore and open hole completions. 

(iii) Long String Casing Is Not Needed

Section 146.86(b)(3) states that “at least one long string casing . . . must 

extend [from the surface] to the injection zone and must be cemented . . . .” (73 Fed. 

Reg. at 43538; § 146.86(b)(3).) This requirement is excessive and its implementation 

would unnecessarily constrain the ability to undertake future potential well 

interventions that support downhole monitoring and well remediation, if such become 

necessary. 

To avoid such an unintended result, BP recommends that EPA not mandate the 

placement of an isolation casing string from the surface, but rather allow the casing 

string to extend from beneath the surface or otherwise based upon site 

characteristics. Cement should cover the uppermost caprock (within the Area of 

Review) by approximately 500 feet; cement coverage should not be required all the 

way to surface. The ultimate decision for each project should rest with the Director 

since each storage site is unique in the geological intervals of the caprock(s), injection 

zone(s) and position relative to USDW(s). Moreover, any expectation to cement in the 

injection interval should permit the use of external casing packers or other isolation 

methods in conjunction with cementing requirements across the caprock, as 

discussed above. 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 13 of 20 

(iv) Definition of Carbon Dioxide Stream

Section 146.81 of the Proposed Rule defines “carbon dioxide stream” as 

follows: 

Carbon dioxide stream means carbon dioxide that has been captured from an 

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

derived from the source materials and the capture process, and any substances 

added to the stream to enable or improve the injection process. This subpart 

does not apply to any carbon dioxide stream that meets the definition of a 

hazardous waste under 40 CFR part 261. 

By limiting the definition to “emission sources,” the Class VI regulations may have the 

unintended effect of narrowing the types of sources that might inject CO2 for geologic 

sequestration. The particular source of the CO2 is not material in terms of protecting 

USDWs. Furthermore, the Final Rule should not address the source because it is 

beyond the scope of this regulation. We recommend deleting the phrase “has been 

captured from an emission source (e.g., a power plant)” from the definition contained 

in section 146.81 of the Proposed Rule so that the Final Rule does not inadvertently 

preclude other non-emission sources of CO2. 

(v) EPA Should Not Restrict Injection To Below Lower-Most USDW

The Proposed Rule restricts injection of CO2 to below the lower-most USDW. 

(See §§ 144.6(f), 146.5(f) and 146.81.) EPA acknowledges that such a restriction 

would preclude the consideration and use of various potential storage sites, and has 

requested comment on this approach. 

BP disagrees with such a blanket restriction, one that would pose a barrier to 

many, viable storage sites. The imposition of an artificial constraint limiting injection 

only to reservoirs below the USDW is not justified by technical knowledge or historical 

industry experience. For example, Class II requirements have proven successful in 

protecting USDWs even though injection into certain reservoirs has occurred above

the lower-most USDW. Given the EPA’s effort in adopting a general performancebased approach, injection should be allowed to proceed into acceptable reservoirs 

provided the reservoir is demonstrated to provide secure CO2 storage above and 

below the injection formation. 

A containment system with appropriate site characterization, risk assessment 

and monitoring is the key to secure storage and protection of USDWs. Proximity of 

the injection zone to USDWs (i.e. whether shallower or deeper) is not the appropriate 

criteria for protection of USDWs because proximity alone does not materially impact 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 14 of 20 

risk of leakage. Similarly, EPA should not establish minimum depths for CO2 injection. 

Instead, any constraints placed on injection should be site-specific, consistent with the 

containment and capacity parameters of the storage site in question. 

Related to the depth of injection, BP also disagrees with the requirement in 

section 146.86(b)(2) that “(s)urface casing must extend through the base of the 

lowermost USDW and be cemented to the surface.” One reason is that at certain 

potential storage sites USDWs may be located at depth; consequently, it would be 

technologically infeasible to construct surface casing to the requisite depth prescribed 

by the Proposed Rule. 

In summary, EPA should not mandate a requirement of injection only below the 

lower-most USDW nor a minimum depth for injection of CO2. Such a comprehensive 

prohibition would unjustifiably exclude potential storage sites that do not pose an 

endangerment to USDWs. 

(vi) Injection Well Operation & Mechanical Integrity Requirements

Consistent with the earlier discussion about blanket construction limitations, BP 

also disagrees with universal mandates regarding certain CO2 injection operations. 

EPA should not include automatic downhole shut-in devices as a standard requirement 

for CO2 injection wells (section 146.88(e)). An across-the-board requirement for 

installation of downhole devices is excessive – unsupported by technical knowledge 

and industry experience – and would impose unnecessary costs. Overpressure 

protection is best achieved by ensuring compatibility of the casing/tubing material 

design strength with the surface injection (compression) system. Downhole shut-in 

devices may be appropriate, however, for site-specific situations (such as offshore), 

but they should not be mandated for all storage sites. Rather, the requirement of 

downhole shut-in devices should be left to the discretion of the Director. 

With regard to validating mechanical integrity of CO2 injection wells, BP 

generally agrees with EPA’s suggestion to evaluate the “absence of significant leaks” 

by monitoring at some regular frequency the injection pressure, flow rate, injected 

volumes and the annular pressure. (See § 146.89 (b).) An alternative method for 

determining mechanical integrity, as noted by EPA, is periodic pressure testing; this 

should remain an option for site-specific cases. Where periodic pressure testing is 

implemented, the pressure should be considered by evaluation of the formation 

potential instead of casing burst or tubing collapse limit. 

The frequency of the monitoring should be defined not as “continuous” but as 

“regular” or “periodic” based upon site characteristics because regular monitoring 

(e.g., every minute or hour) will often be adequate. For example, fluid volume in the 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 15 of 20 

annulus is static and requires evaluation of a pressure pulse to determine the depth of 

top of fluid. Therefore, this should be monitored on a monthly or quarterly basis to 

support the pressure data. 

Section 146.89(c) lists specific methodologies to monitor fluid movement. BP 

strongly disagrees with the requirement of any particular methodology because this 

would limit technology development and favor certain technologies to the exclusion of 

others without any rationale basis. 

(C) SITE CLOSURE PERIOD 

EPA correctly states in its Preamble that defining the post-injection site care 

period is “difficult to define because it is based on site-specific considerations.” (73 

Fed. Reg. at 43519.) The three studies cited by EPA also concluded that “the actual 

time for CO2 plume stabiliziation . . . will be very site-specific, being influenced by 

geologic factors such as formation permeability, geochemistry, and the degree of 

capillary trapping.” (Id.) However, the Proposed Rule establishes a default 50-year 

period (following the cessation of injection) during which the operator must conduct 

monitoring to demonstrate that “the carbon dioxide plume and pressure front have 

stabilized and the geologic sequestration project does not pose an endangerment to 

USDWs.” (See § 146.93(b).) The designation of a 50-year time-period without regard 

to particular site characteristics is arbitrary and not supported by existing scientific 

studies or industry experience. Moreover, the 50-year timeframe does not provide 

any incremental benefit as compared with a performance standard to protecting 

USDWs; rather, it will be a significant deterrent to commercial investment in geologic 

sequestration projects. 

BP urges EPA to adopt the performance standard that EPA considered in its 

review. EPA considered three options: (1) fixed period; (2) performance standard; and 

(3) combination of fixed period and performance standard; EPA states it adopted the 

latter approach. (73 Fed. Reg. at 43519.) While the Proposed Rule allows a Director 

to reduce the 50-year minimum (§146.93(b)(2)), the practical effect will be the 50-year 

timeframe applies unless an operator is able to overcome the presumption built into 

the Proposed Rule that 50 years is adequate. Indeed, this is more prescriptive than 

the requirement for Class I hazardous wells, which provides that the timeframe for 

post-injection site care ends when the plume has stabilized and cannot endanger 

USDWs. (Id.; 40 CFR §146.71.) 

EPA should adopt the performance-based standard that it considered 

previously. Accordingly, the post-injection site care period ends when monitoring and 

other site-specific data demonstrate that the geologic sequestration project does not 

pose an endangerment to USDWs. (See e.g., 73 Fed. Reg. 43520.) A performance-
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 16 of 20 

based approach is consistent with technical knowledge and historic industry 

experience. The site closure period would be appropriately based on particular site 

characteristics and historic site performance. For example, a well-selected and -

managed sequestration site (such as an existing oil or gas field) that has met its 

performance objectives (including plume stabilization) will be much more secure and 

could be closed reasonably quickly (potentially, in as few as 2-3 years). At other sites 

that are less well confined (e.g., deep saline formation without a conventional 4-way 

closure), the CO2 could move around for some time even after injection ceases before 

stabilizing, and might therefore require a longer period to allow for additional residual 

and solubility trapping. 

In summary, BP recommends that EPA adopt a performance-based approach to 

determine the timeframe for site closure. We also support the site closure standard 

offered in the MSDG Proposal for section 146.93(b), which sets forth detailed criteria 

that must be satisfied to demonstrate that the site does not pose an endangerment to 

USDWs. The advantage of the MSDG Proposal as opposed to a fixed period is it 

establishes clear criteria that an operator must demonstrate before obtaining site 

closure based upon particular site characteristics and is, therefore, reasonable 

applicable to any storage site as opposed to a standard based upon a fixed-duration. 

The current proposal of 50-years minimum, even subject to potential reduction, would 

result in significantly discouraging the deployment of this technology at commercial 

scale without providing measurable additional protection of USDWs. 

(D) EPA’s Proposed Financial Responsibility Demonstration 

Requirements 

The proposed financial assurance requirements for Class VI UIC wells require 

the owner or operator to establish financial responsibility (or “financial assurance”) to 

cover the costs of plugging and abandoning injection wells, as well as the costs of 

corrective action, post-injection site care, site closure and emergency and remedial 

responses. (73 Fed. Reg. at 43537; §146.85.) The financial responsibility 

requirements should be consistent with the need to protect USDWs, while being 

reasonable and cost-effective, yet facilitating geologic sequestration of CO2. We 

support EPA’s proposed approach that allows for a wide range of financial assurance 

mechanisms to be utilized to demonstrate financial responsibility. We also suggest 

that EPA adopt a flexible, iterative approach to financial assurance in keeping with the 

phased, adaptive management philosophy of other aspects of the Proposed Rule. 

(1) Allow for a Broad Range of Financial Assurance Mechanisms

We support an approach that takes into account changing market conditions 

and other factors and allows an operator to utilize a wide range and variety of financial 

assurance mechanisms to demonstrate financial responsibility. This should be coupled 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 17 of 20 

with the flexibility to combine multiple types of financial assurance mechanisms to 

demonstrate compliance. The regulations or guidance should be flexible and authorize 

EPA to accept and recognize other types of instruments, programs or conditions that 

provide similar reliable assurance. 

While the Proposed Rule does not limit the range of financial assurance 

mechanisms, EPA indicates that the Agency is considering revising various guidance 

documents related to financial assurance. (73 Fed. Reg. at 43520-21.) EPA refers to 

several reports issued by the United States General Accountability Office (“GAO”), 

Office of Inspector General (“OIG”), and the Environmental Financial Advisory Board 

(“EFAB”). Id. In 2003, the GAO issued a report reviewing, in part, the financial 

assurance requirements for Class I injection wells. See GAO Report to the Honorable 

Lynn C. Woolsey, House of Representatives, Deep Injection Wells: EPA Needs to 

Involve Communities Earlier and Ensure that Financial Assurance Requirements are 

Adequate, GAO-03-761, 17-22 (June 2003). GAO noted that there is uncertainty about 

the adequacy of financial assurance requirements, but did not make any conclusions 

about specific mechanisms. Similarly, in 2005, OIG issued a report reviewing the 

financial assurance mechanisms under the RCRA program. OIG Evaluation Report, 

Continued EPA Leadership Will Support State Needs for Information and Guidance on 

RCRA Financial Assurance, Report No. 2005-P-00026 (Sept. 26, 2005). OIG concluded 

that despite ongoing concerns, the lack of uniform national data prohibited ready 

identification of the problems. Id. at 8. 

As EPA develops revisions or potential modifications to financial assurance 

guidance that would be applied to UIC permits, it should provide further public notice, 

review and engagement opportunities that allow for feedback to EPA on specific 

proposals. 

(2) EPA’s Suggestion for a Phased Approach to Financial Assurance for PostInjection Site Care Should be Adopted

EPA is relying on an adaptive management approach for regulation of CO2

injection. (73 Fed. Reg. at 43522.) EPA specifically requested comment on allowing 

separate financial demonstration to be submitted for well-plugging and for postinjection site care. In the Preamble, EPA states that: 

Since post-injection site care has the potential to extend many years into the 

future, subsequent to the time a permit is issued, the Agency believes that it 

may be advantageous to require the approval of the well plugging financial 

demonstration at permit issuance and the post-injection site care financial 

demonstration at a later time (e.g., within 180 days of notifying the Director that 

the well will be plugged and abandoned). Trying to determine the cost for post-
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 18 of 20 

injection site care, possibly 30 to 50 years in the future, could be difficult, as 

could the approval of a financial demonstration. 

(73 Fed. Reg. at 43522.) We agree with EPA’s stated rationale and recommend that 

EPA specifically incorporate language in the Final Rule that describes the manner in 

which determinations and demonstrations of financial assurance for post-injection site 

care will be postponed until a later time as discussed by EPA. 

(3) Clarifying that adaptive management approach allows for phased financial 

assurance release

In accordance with the adaptive management approach for CCS, the 

rulemaking should clarify that the financial assurance can be released (or amounts 

reduced) as particular activities are completed and regulatory criteria are met (e.g., 

well plugging for corrective action). Also, the owner or operator should be able to use 

site-specific data gathered from such activities to support revisions to site-specific 

financial assurance requirements. 

(E) ISSUES SPECIFICALLY RELATED TO OIL & GAS PRODUCTION 

EPA has appropriately restricted the applicability of Class VI regulations to 

projects that are exclusively geologic sequestration projects. Furthermore, BP 

appreciates EPA’s efforts to limit this rulemaking to the authority vested in EPA by 

Congress pursuant to the Safe Drinking Water Act (“SDWA”). BP requests that EPA 

include some of the discussion in the Preamble to the Final Rule to ensure that 

unrelated activities in the Oil & Gas industry are not impacted by unintended 

inferences or interpretations of the Proposed Rule. 

(1) Property Rights Issues Are Matter of State Law

EPA accurately states that the SDWA does not afford EPA the authority to 

regulate many issues involved in CO2 sequestration, including property rights which 

are regulated under state law. (73 Fed. Reg. at 43495.) In many instances, the owner 

of the surface property rights may be different than the owner of the subsurface 

mineral rights. There may be a legal question as to who owns the subsurface storage 

rights as between, for example, the surface property rights owner and the mineral 

rights owner. This is a matter of state law as correctly discussed by EPA. BP 

requests that EPA expand on its assertion in the Preamble that it does not have 

authority to regulate in this area and that nothing in the Proposed Rule should be 

interpreted or inferred as a grant of subsurface storage rights. 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 19 of 20 

(2) Organic-Rich Shales Are Primary Remaining Supply of Natural Gas

EPA also states in the Preamble that organic-rich shales are potential reservoirs 

for geologic sequestration of CO2. However, these shales are also the single largest 

source of natural gas remaining in the United States, and will likewise help to ensure 

that low-carbon energy supplies are available to fuel the United States’s economy. 

EPA should include in its Preamble a clear statement that nothing in the Preamble 

and/or the Proposed Rule should be interpreted or inferred as a preference for the use 

of these organic-rich shales for geologic sequestration as opposed to natural gas 

production. Whether organic-rich shales are used for natural gas production or 

geologic sequestration should be a matter left to negotiations between private parties. 

 (3) Proposed Rule Should Not Affect Injection of Oil & Gas Waste

Oil and gas waste (such as produced water and amine waste gases [CO2 and 

H2S]) are often injected back into the reservoir after separation during oil and gas 

production activities. This type of injection is and has been historically permissible 

under Class II regulations. (See 40 CFR § 144.6(b)(1).) EPA was silent on whether 

the Proposed Rule would in any manner affect the applicability of the Class II well 

regulations for injection of oil and gas waste. EPA should indicate in its Preamble to 

the Final Rule that the Final Rule does not alter in any manner the applicability of Class 

II regulations to injection of oil and gas waste. 

CONCLUSION

BP commends EPA for the tremendous amount of work that EPA has done in 

preparing the Preamble and Proposed Rule in an expedited timeframe. After due 

consideration of studies and analyses performed by international research 

organizations, non-governmental organizations, sister-agencies, and scientists 

worldwide, EPA’s research has determined that CCS could be “a key mitigation 

technology for achieving domestic emissions reductions,” and CCS has the “potential 

to play a significant role in climate change mitigation scenarios.” (73 Fed. Reg. at 

45496.) BP applauds EPA’s willingness to play a significant role in this Nation’s 

strategy to address climate change. We are very supportive of EPA’s effort to 

implement a regulatory scheme that will both protect one of our vital resources, 

USDWs, and facilitate the implementation of CCS technology and geologic 

sequestration of CO2. 

Significantly, this technology does not start on a blank slate. The Oil & Gas 

industry has extensive, relevant experience with injection into the subsurface that can 

inform this rulemaking. Moreover, BP is a leader in studies and demonstration 

projects conducted around the world regarding geologic sequestration of CO2. The 
BP’s Comments To EPA’s Proposed Rule 

Docket ID No.: EPA-HQ-OW-2998-0390 

Page 20 of 20 

comments submitted here are in large measure based upon BP’s significant 

experience and technical knowledge. We would be pleased to review our comments 

and/or any questions that EPA may have regarding our comments at EPA’s 

convenience. BP also welcomes the opportunity to provide additional information or 

input to EPA as EPA continues its evaluation and study of comments, scientific 

papers/studies or other information submitted or considered in this rulemaking 

process. 

Please contact the undersigned with any questions or comments. 

 BP Alternative Energy North America Inc. 

 Brian Williams by Asteghik Khajetoorians

 ____________________________________ 

 Brian Williams 

 CO2 Storage Manager 

 

 
Letter ID: 0225 

Commenter: Brian Williams 

Organization: BP Alternative Energy North America, Inc. (BP) 

Letter ID: 0225 Comment ID: 21711 Letter Lines: 57 to 61 

Comment Code: 1910 1.4.4 Stakeholder outreach 

Comment: As an initial matter, we applaud EPA’s significant efforts to include and 

encourage broad stakeholder participation both before and after publication of 

the Proposed Rule. Furthermore, it is evident from the Proposed Rule that EPA 

considered and incorporated many of the stakeholders’ comments from the public 

workshops. Accordingly, EPA adopted a framework that is intended to encourage 

Individual Response: EPA acknowledges the comment and agrees that input of and 

participation by a wide spectrum of stakeholders is a vital component of successful rulemaking. 

The Agency appreciates the degree of cooperation, participation, and active dialogue between the 

EPA and stakeholders and will continue to work with stakeholders and experts as it implements 

the GS rule. 

Letter ID: 0225 Comment ID: 21712 Letter Lines: 61 to 74 

Comment Code: 1330 1.1.3.1 Support use of GS in general 

Comment: workshops. Accordingly, EPA adopted a framework that is intended to encourage 

the deployment of carbon capture and sequestration or storage ("CCS") in a 

manner that is protective of underground sources of drinking water ("USDWs"). 

There is growing consensus among scientists, environmental groups and members of 

government that CCS will play a critical role in addressing greenhouse gas 

emissions. 

The comments herein are founded on knowledge and experience gained through 

decades of industry operations, and are intended to provide constructive input 

on the Proposed Rule. BP’s comments are based upon two important and mutuallyachievable goals: (1) protecting USDWs; and (2) adopting regulations that are 

reasonable, cost-effective and facilitate geologic sequestration of CO2. BP 

concurs with EPA’s conclusion that CCS presents a "key climate change mitigation 

technology." (73 Fed. Reg. at 43495.) 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA’s 

responses to this comment for further details. For additional information on EPA’s final 

regulatory approach, please see the final rule and preamble as well as the rulemaking docket. 

1
Letter ID: 0225 Comment ID: 21713 Letter Lines: 76 to 95 

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

Comment: In the context of geologic sequestration of CO2, it is imperative to maintain 

flexibility in the regulatory requirements due to the site-specific nature of 

this activity and because the technology is continually advancing. For geologic 

sequestration of CO2, "one-size-fits-all" is not an approach that is necessarily 

or reasonably protective of USDWs. Rather, each site has site-specific 

characteristics that merit differing requirements. Indeed, what may appear to be 

a standard protective measure in the context of a particular site could actually 

have the opposite effect and increase potential risks at another site. (See A 

Technical Basis for Carbon Dioxide Storage, CO2 Capture Project, December 2008.) 

Consequently, BP strongly encourages EPA to provide performance standards for 

the various phases of a geologic sequestration project (i.e., site 

characterization, operation and site closure), while providing the Director 

flexibility to add requirements as necessary to address site-specific 

characteristics. This type of approach, consistent with Regulatory Alternative 

2, offers the degree of flexibility that the permitting authority will require 

to tailor fit-for-purpose requirements that address site specific 

characteristics. Furthermore, it ensures that project costs will be 

commensurate with the geologic risk, and will further the continued evolution of 

the best technologies. 

Individual Response: The Agency believes that the Class VI requirements balance site-specific 

flexibility with USDW protection. Rather than setting performance or technology-based 

standards for GS projects, EPA is adopting a flexible approach, where operators of GS projects 

would develop and implement site-specific plans for delineating the AoR, testing and monitoring 

the site, performing corrective action, and post-injection site care. EPA believes that the plans—

which would be reviewed and approved by the Director and periodically updated throughout the 

life of the project—promote an ongoing dialogue between the operator and the Director that will 

encourage use of the most appropriate technologies for a particular project. 

To address the comment that the rule should accommodate future technological developments 

related to GS, EPA adds that it is using an adaptive approach to regulating GS under the UIC 

Program. Even after finalization of the GS regulation, EPA plans, every six years, to collect and 

review project data on GS research projects to determine whether the appropriate amount and 

types of information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0225 Comment ID: 21714 Letter Lines: 103 to 257 ; 847 to 852 

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

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

2
Comment: (A) Importance of EPA’s Recognition That EOR/EGR and Storage of CO2 Occur At 

the 

Same Time 

BP commends EPA for its recognition, as stated in the Preamble of the Proposed 

Rule, that oil and gas reservoirs will play a valuable role in the geologic 

storage of CO2. Two of the reasons cited by EPA are: (1) oil and gas reservoirs 

are natural storage containers that have trapped fluid (both liquid and gaseous) 

hydrocarbons for millions of years; and (2) oil and gas exploration and 

production activities have created a wealth of knowledge and geologic data that 

can support the site characterization process for geologic sequestration. (73 

Fed. Reg. at 43502-03.) Indeed, oil and gas reservoirs have proven capable of 

containing water-buoyant fluids for millions of years. These reservoirs are 

well studied and they offer the best opportunity to kick-start large-scale 

geologic sequestration of CO2, building on 100 years of oil and gas field 

operating experience. Consequently, many oil and gas reservoirs are available 

now to serve CCS projects at a commercial scale, and will add insights for 

subsequent application to other formations. 

EPA should provide further discussion and acknowledgement in its Proposed Rule 

that, when CO2 is injected for use in EOR/EGR projects, geologic sequestration 

(or long term storage) of CO2 occurs during EOR/EGR operations and continues 

after EOR/EGR operations cease ("EOR and Storage"). Furthermore, it is critical 

that EPA support and encourage geologic sequestration of CO2 in these wellstudied and proven oil and gas reservoirs by amending certain elements of the 

Proposed Rule to clarify and streamline requirements. EPA’s recognition of EOR 

and Storage will provide a much-needed near-term, economic incentive to CCS 

projects. Incentivizing the use of anthropogenic CO2 for EOR/EGR will provide 

many lasting benefits to the United States, by significantly reducing current 

CO2 emissions and increasing energy security. 

It has become increasingly clear that early EOR and Storage projects will 

significantly advance the deployment of CCS technology and geologic 

sequestration of CO2 for many reasons: 

- Oil and gas formations offer the best characterized sites among potential 

sinks for anthropogenic CO2; 

- Much of the required infrastructure and operational experience is already in 

place; 

- Class II requirements have proven to be an effective regulatory framework in 

protecting USDWs in the context of CO2 EOR operations, evidenced by more than 30 

years of experience in the Permian Basin and more than 25 years of miscible gas 

injection projects on the North Slope of Alaska (where CO2 comprises 25% of the 

miscible gas injected); 

3
- Demand for large volumes of CO2 for EOR is increasing [FN1]; and 

- EOR can provide a revenue stream to supplement the economics of early-mover 

CCS projects. 

EOR and Storage have the added benefit of increasing domestic energy supplies in 

the face of increasing demand. Carbon dioxide injection has proven capable of 

increasing oil or gas recovery in mature fields from 5% to more than 20%. The 

Department of Energy estimates that EOR has the potential to add 40-80 billion 

barrels of oil reserves in the United States, which is 2 to 4 times the current 

United States’s total proven reserve. The Intergovernmental Panel on Climate 

Change ("IPCC") has agreed that EOR technology can provide a significant kickstart on proving geologic sequestration of CO2 on a commercial scale. Indeed, 

the early commercial scale CCS projects will probably employ EOR and Storage as 

their basis of design, which will extensively inform the technical development 

and safe deployment of CCS projects in other types of geologic formations.[FN2] 

(1) Brief Explanation of EOR/EGR Operations Utilizing CO2 

Currently, EOR/EGR operators purchase CO2 for injection. This can represent a 

significant portion of the cost of an EOR/EGR project. Consequently, CO2 is a 

valuable commodity to EOR/EGR operators and is treated accordingly. Because it 

is a valuable commodity in EOR/EGR operations, CO2 is not emitted or vented to 

the atmosphere during operations or after operations cease. Any injected CO2 

that returns to the surface during production operations is separated from the 

hydrocarbons and reinjected for additional enhanced recovery use. 

Approximately 30% to 50% of the injected CO2 volume typically remains 

permanently stored in the oil or gas reservoir after production operations 

cease. The injected CO2 is monitored in the formation and injection operations 

are designed to minimize CO2 procurement and maximize oil (and recycled CO2) 

production. Despite best efforts to re-use all the CO2, additional trapping of 

CO2 occurs with each subsequent injection cycle, necessitating further purchases 

of CO2. When the EOR operations cease (and the field is blown down to recover 

any CO2 available for use in another operation), wells are closed and the 

remainder of the injected CO2 remains permanently stored underground. However, 

an EOR operator could quite easily, at its option, manage operations to store 

the injected CO2 for the long term (rather than recover it). 

The foregoing demonstrates that, based on decades of experience gained in 

existing EOR/EGR operations utilizing CO2, EPA should acknowledge in the Final 

Rule preamble that injected CO2 can be trapped and stored for long term during 

EOR operations and continues afterwards. Furthermore, existing Class II 

regulations and industry practice employ proven methodologies to conduct these 

operations in a safe manner that is protective of USDWs. 

4
(2) Requested Amendments to Proposed Rule 

For the reasons stated above, EPA should expand its discussion and acknowledge 

in the Final Rule text and preamble that, when CO2 is injected for use in 

EOR/EGR projects, geologic sequestration (or long term storage) of CO2 occurs 

during EOR/EGR operations and continues after operations cease - thus EOR and 

Storage. BP supports EPA’s statement that EOR/EGR, as long as any production is 

occurring, will continue to be permitted under the Class II program. 

We also understand that it is EPA’s intent, which we strongly support, that the 

proven Class II program applies to storage of CO2 that is occurring during and 

in connection with EOR/EGR operations. Such an approach is logical, technically 

sound, and protective of USDWs as demonstrated by decades of safe operations. 

Accordingly, EPA should amend the Proposed Rule language and expand its 

discussion in the Final Rule preamble to clarify that (a) when CO2 is injected 

for EOR and Storage, the applicable requirements are under Class II; and (b) 

when CO2 is exclusively injected for storage, the applicable requirements are 

under Class VI. 

(i) Clear Well Classification With Respect to EOR and Storage 

BP requests that EPA amend sections 144.3, 144.6, 144.80, 146.5 and 146.81 of 

the Proposed Rule to clarify that (a) Class II applies to EOR/EGR operations 

where geologic sequestration of CO2 is occurring during or in connection with 

EOR/EGR operations or activities (i.e. EOR and Storage); and (b) Class VI 

applies when the exclusive purpose is geologic sequestration of CO2. In 

addition to the reasons stated above, this clarity is needed because some 

amount of CO2 is sequestered or stored during EOR/EGR operations regardless 

of the intent of the operator. As currently drafted, the Proposed Rule may 

be interpreted - contrary to EPA’s intent - to require EOR/EGR operations to 

proceed under Class VI. API has submitted specific language BP’s Comments To 

EPA’s Proposed Rule to clarify that the applicable well class is Class II. We 

support API’s proposed language modifications to sections 144.3, 144.6, 

144.80, 146.5 and 146.81 of the Proposed Rule. 

In addition, we have participated in discussions among multi-stakeholders 

including environmental groups, various associations and different industries 

(the "Multi-Stakeholder Discussions Group"); we also support the language 

recommended in the correspondence from the MSDG dated December 23, 2008 (the 

"MSDG Proposal") to sections 144.6, 144.80 and 146.5(f) establishing a "bright 

line" for wells injecting CO2 for EOR and Storage. The MSDG Proposal defines a 

"bright line" for wells that inject CO2 for EOR and Storage, and consistent with 

EPA’s intent, remain in Class II and are subject to the existing Class II 

regulations - which have adequately safeguarded USDWs in the context of EOR/EGR 

operations for decades. 

5
The MSDG has also agreed to continue discussions regarding specific rules that 

would be applicable to geologic sequestration of CO2 in oil and gas formations 

following the completion of EOR/EGR production. We intend to participate in 

these negotiations. The development of a subclass under Class II or Class II-B 

regulations would result in a regulatory framework that would effectively 

protect USDWs and also promote the geologic sequestration of CO2 in oil and gas 

formations, especially following the cessation of EOR/EGR production activities. 

The advantages of a subclass dedicated to geologic sequestration in oil and gas 

formations are that a Class II-B will address risks associated specifically with 

oil and gas formations, rely upon information and data gathered during the 

terminated EOR/EGR production activities and maintain permitting authority under 

a single agency with historical knowledge and expertise about the former 

operations and the receiving oil and gas formation. This would maximize the 

efficient use of administrative resources and allow for seamless transitioning 

of operations from EOR and geologic sequestration of CO2 to injection of CO2 

only for geologic sequestration. 

[FN1] Currently, over 2 billion cubic feet of naturally-occurring CO2 is used 

daily for EOR operations and the volume is growing. 

[FN2] Notably, it is estimated that site characterization of saline reservoirs 

will likely cost tens of millions of dollars and take years of study to permit 

one commercial scale saline storage reservoir. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for GS and may 

be among the first GS sites. However, the Agency believes that the nature and risks of CO2 

injection for the primary purpose of long term storage poses different risks than injection for the 

primary purpose of EOR, and therefore has developed new Class VI regulations to address these 

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is 

significantly greater than for EOR operations. Reservoir pressure conditions will also be 

different, with Class VI injection operations involving large volumes of CO2 and likely having 

higher pressures within their storage formations than Class II EOR projects, which may lead to 

fluid movement that endangers a USDW. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

6
EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in determining whether an injection project should be transitioned from 

Class II where the primary purpose is oil and gas production to Class VI where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

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

EPA clarifies that the GS rule does not require any facilities to sequester CO2; nor does it create 

an economic incentive to do so. The purpose of the GS regulation is to ensure that, where 

deployed, GS is conducted in a manner that does not endanger USDWs. 

Letter ID: 0225 Comment ID: 21715 Letter Lines: 259 to 316 

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

Comment: BP requests that EPA consider the foregoing discussion of a subclass or Class 

II-B wells for oil and gas formations for future rulemaking. However, in the 

context of the current Proposed Rule, we submit the following recommendations on 

the question of grandfathering. 

(ii) Grandfathering - Transitioning from EOR and Storage to Exclusively CO2 

Storage 

After the EOR and Storage projects conclude production of oil or gas, 

injection of CO2 may continue at the option of the operator to utilize 

fully all available pore space. EPA regulations should facilitate this 

transition from EOR and Storage to BP’s Comments To EPA’s Proposed Rule 

exclusively storage operations when EOR/EGR operations are completed. EPA’s 

decision to allow grandfathering of construction requirements in sections 

146.81 and 146.86 of the Proposed Rule is an excellent example of both 

protective and reasonable regulation. BP supports EPA’s proposal and 

recommends that EPA expand the grandfathering provisions to encourage and 

facilitate continued injection of CO2 exclusively for storage when EOR/EGR 

operations cease. 

Specifically, the Proposed Rule should be modified also to allow grandfathering 

of sections 146.88(e) and (f) (continuous recording devices and down-hole 

automatic shut-off devices, respectively) regarding Operations; and Section 

146.89(b) and (c) (continuous monitoring and specific yearly tests, 

respectively) regarding Mechanical Integrity. Existing, operationally-compliant, 

Class II EOR-wells will continue to protect USDWs, as established by their 

7
operational histories, even when injection is for the exclusive purpose of CO2 

sequestration without the foregoing additional Operation or Mechanical Integrity 

requirements. In addition, the following sections of the Proposed Rule simply 

will not be applicable or pertinent at the time of transition because these 

provisions presume that no injection has commenced. These sections are as 

follows: 

- Permit Application § 146.82(g) and (j); 

- Area of Review § 146.84 (b)(2)(iv), (c)(1) and (d); 

- Logging Sampling and Testing § 146.87(a), (b) and (f); and 

- Testing and Monitoring § 146.90 (b), (d), (g) and (h). 

These provisions should not and cannot apply when a Class II EOR and Storage 

project transitions to an exclusively storage project because, as a practical 

matter, performance of certain "baseline measurements," "model predictions," 

"witnessing of logging and testing," and "corrective actions" will not be 

possible prior to injection of CO2. 

In sum, EPA should expand the grandfathering provisions to encourage continued 

storage of CO2 after EOR/EGR operations have ceased. Most of the existing Class 

II requirements that were appropriate for regulation of EOR and Storage will 

continue to operate effectively and to safeguard USDWs during exclusively 

storage operations. Finally, appropriately expanded grandfathering will 

facilitate optimal utilization of these proven oil and gas reservoirs for 

geologic sequestration of CO2. 

CCS in connection with EOR provides a forward-looking energy policy for the 

United States, as it will significantly reduce CO2 emissions with the added 

benefit of increasing energy security through increased domestic oil production. 

Individual Response: EPA agrees that many Class II wells are designed and constructed to 

withstand exposure to CO2. The final GS rule provides for the construction of these wells to be 

grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director 

that the wells were engineered and constructed to meet the requirements at §146.86(a) and 

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). 

EPA disagrees that other requirements (e.g., monitoring, operational, and AoR requirements) 

should also be grandfathered. Following re-permitting of the well as Class VI, many of the 

unique factors of GS sites (e.g., increased reservoir pressures associated with large volumes of 

stored CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk 

profile, warranting the specific requirements in the final GS rule. Following re-permitting as 

Class VI wells, these projects must be subject to the operational, MIT, monitoring, reporting, 

plugging, and post-injection site care and site closure requirements in the final GS rule. See the 

8
discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail 

on these requirements. 

EPA adds that promotion of energy security and a broader energy policy are not within the scope 

of the GS rulemaking. This rule focuses on ensuring that, where GS is deployed, it is conducted 

in a manner that protects USDWs from endangerment. 

Letter ID: 0225 Comment ID: 21716 Letter Lines: 318 to 324 ; 326 to 328 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: (B) WELLS, MONITORING & OPERATIONS 

In general, regulations for geologic sequestration should provide for effective 

storage management by requiring the following activities: 

- Site characterization that validates the geological model of the storage site 

and confirms potential leakage pathways have been identified and evaluated; 

- Risk assessment that builds upon the predicted behavior and movement of the 

CO2 in the reservoir over time and confirms that the potential for leakage has 

been evaluated through site characterization; and 

Individual Response: EPA agrees with the commenter. The requirements for geologic site 

characterization are based on a long standing UIC regulatory framework tailored to address 

specific risks to USDWs posed by injection. These requirements promote a flexible, risk-based, 

site-specific approach to characterizing and permitting a site for GS projects, and are intended to 

improve understanding of the project as a whole and promote better modeling of the site. 

Letter ID: 0225 Comment ID: 21717 Letter Lines: 330 to 334 

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

Comment: - A monitoring plan that measures the performance of the highest leakage risk 

parameters and validates or updates predictive performance models. 

The appropriate implementation of these key areas will ensure the safe and 

secure operation of a geologic sequestration project. 

Individual Response: EPA agrees with commenters that developing and following testing and 

monitoring plans is an important part of assuring that a GS project is operating properly and is 

crucial for the early detection of potential endangerment to USDWs. The final rule retains this 

requirement. 

9
Letter ID: 0225 Comment ID: 21718 Letter Lines: 336 to 348 

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

146.86) 

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

Comment: (1) Importance of Well Integrity 

EPA has appropriately recognized that wells are a fundamental component of a 

secure system for the long-term geologic sequestration of CO2. As such, applying 

appropriate well design, construction & operating requirements is critical to 

the delivery of secure storage. As previously discussed, oil and gas operators 

have nearly four decades of experience, via past and existing production 

operations, in constructing and operating CO2 EOR/EGR wells in a safe and secure 

manner. Notably, Class II requirements have proven to be effective in ensuring 

the non-endangerment of USDWs. Therefore, BP believes it would be prudent to 

rely upon this extensive existing regulatory and industry experience and 

knowledge in setting Class VI requirements for wells that inject CO2 for long 

term sequestration. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of enhanced recovery and that many of the wells used for ER may 

be suitable for GS. EPA believes that GS is sufficiently different from Class II ER operations to 

warrant the tailored construction requirements for Class VI wells at §146.86. For example, the 

volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class 

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

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

formations than Class II ER projects. Therefore, Class VI GS reservoir pressures will increase 

more in comparison to Class II ER during the injection phase of the GS project. 

The final GS rule, at §146.81(c), allows the construction of these wells to be grandfathered, 

provided the owner or operator can demonstrate to the Director that the wells were engineered 

and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu 

of requirements at §146.86(b) and §146.87(a). Only the cemented-in-place construction 

requirements would be grandfathered under the final GS rule; following conversion, these wells 

must be permitted as Class VI wells and be subject to the operational, MIT, monitoring, 

reporting, plugging, and post-injection site care and site closure requirements in the final GS 

rule. 

EPA is developing guidance on transitioning from Class II to Class VI. The guidance will assist 

Directors and owner/operators in evaluating where a project may fit within a Class II to Class VI 

transition. The guidance describes the methods available for the Director to determine the risk 

posed to USDWs from a GS/ER project, and how the Director may determine if a project should 

be regulated by a Class II or Class VI UIC program. The guidance will be available on EPA's 

web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

10
Regarding operational requirements, EPA believes such requirements for Class VI wells are 

necessary to protect USDWs from endangerment by providing multiple safeguards to ensure that 

well integrity, containment of fluids within the injection zone, and that the integrity of the 

confining zone is not compromised. Some of the operating requirements in the GS regulation 

(e.g., pressure limitations or annulus pressure requirements) are consistent with those for other 

injection well types, while other requirements (e.g., use of automatic shut-off systems or tracers 

at the Director's discretion) are tailored to directly address the potential for large volumes of CO2 

to be injected, among other factors. 

Letter ID: 0225 Comment ID: 21719 Letter Lines: 350 to 364 

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

Comment: (2) Flexibility in Design of Monitoring Programs and Selection of Technologies 

BP agrees with EPA that monitoring is important. For example, once a site has 

been selected, appropriate baseline surveys should be conducted and analyzed 

prior to commencing operations. During operations and at site closure, 

appropriate monitoring technologies should be applied to confirm the integrity 

and effectiveness of the storage site. However, there is a common misperception 

that, in order to achieve secure storage, a large amount of monitoring is 

required. The United Nations states that "the proportion of CO2 retained by 

appropriately selected and managed sites is likely to exceed 99% over 1,000 

years." Thus, the key to secure storage is the appropriate selection and 

management of the site and these activities should be the focus of any 

regulatory framework for CO2 geo-sequestration. If done properly, a selected 

site will be secure with a monitoring program that is designed and focused on 

the particular storage site. 

Individual Response: EPA agrees that good site selection, modeling, and management are 

crucial elements of a successful GS project, but disagrees that this is an effective substitute for 

rigorous site monitoring. EPA also agrees with commenters and believes that flexibility is 

important in developing and implementing a monitoring plan that is appropriately tailored for a 

specific GS site. The purpose of the requirement at §146.90 to develop site-specific testing and 

monitoring plans is to ensure that the monitoring performed at a site is appropriate for site 

operational conditions and the geologic setting. EPA believes that this is the best approach for 

addressing potential risks at GS sites. These flexible provisions in the monitoring requirements 

for Class VI wells enable the owner or operator to tailor monitoring programs to the specific 

needs of each project in consultation with the Director. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

11
be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0225 Comment ID: 21720 Letter Lines: 366 to 389 

Comment Code: 1840 1.4.1.3 Other research 

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

comment) 

Comment: BP has significant and highly relevant experience around monitoring of the 

subsurface and the surface. For many decades, BP has been effectively employing 

a number of monitoring technologies to ensure the safety and integrity of its 

customary oil and gas operations, including CO2 EOR-related operations since the 

1970’s in West Texas and Alaska. Notably, since 2004 BP has been operating the 

In Salah, Algeria, CO2 storage project where BP (and partners) has been storing 

around 1 million tones CO2 per year in a deep saline formation close to a 

producing gas field. The In Salah CO2 Storage project also incorporates a 

research project to test CO2 storage monitoring technologies with a program that 

is much more extensive than would be appropriate for a commercial project. At In 

Salah, BP is testing new technologies (such as satellite imagery and microseismic) and conventional oilfield technologies (such as tracers and 

conventional 3D seismic) to compare and contrast results as the partnership 

endeavors to design and develop monitoring technologies and methodologies that 

are reliable and cost-effective, given the expectation of future commercial 

application. 

Before initiating injection at In Salah, BP conducted a thorough assessment of 

potential leakage paths at the site; BP then tailored the monitoring program to 

address those site-specific risks. There are two other monitored, industrialscale CO2 injection projects in the world (at Sleipner and Weyburn) and the 

site-specific nature of monitoring requirements is demonstrated by comparing 

these three CO2 storage projects - monitoring that works well at one location 

may not work at all in another location. 

Individual Response: EPA continues to track ongoing field and laboratory research into all 

aspects of GS, including subsurface CO2 monitoring. The Agency is tracking the operations and 

technical developments of more than three dozen small- and large-scale GS injection projects in 

the US and abroad. Also, since field experience and well construction, injection, and monitoring 

information relevant to GS comes from operations that inject acid gas or inject CO2 for ER, the 

Agency has conducted evaluations regarding these commercial field operations and continues to 

track GS-relevant developments in these commercial operations. 

Additionally, EPA ORD's National Center for Environmental Research (NCER) awarded six 

Science To Achieve Results (STAR) grants in the Fall of 2009 to recipients from major 

universities and institutions within the scope of "Integrated Design, Modeling and Monitoring of 

Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking 

12
Water." In one project, the University of Texas at Austin will assess appropriate monitoring 

approaches at geologic sequestration sites. 

Regarding the development of monitoring and testing plans, EPA believes that testing and 

monitoring plans should be based on site-specific information, and believes that flexibility is 

important in developing and implementing a monitoring plan that is appropriately tailored for a 

specific GS site. The purpose of the requirement at §146.90 to develop site-specific testing and 

monitoring plans is to ensure that the monitoring performed at a site is appropriate for site 

operational conditions and the geologic setting. EPA believes that this is the best approach for 

addressing potential risks at GS sites. These flexible provisions in the monitoring requirements 

for Class VI wells enable the owner or operator to tailor monitoring programs to the specific 

needs of each project in consultation with the Director. 

The final regulation provides for flexibility in: 1) methodologies used to collect these data, 2) the 

spatial resolution at which the data should be collected, and 3) how often the data should be 

collected. The number and placement of monitoring wells will be based on site-specific 

information such as the calculated AoR, injection rate and volume, site geology, baseline data, 

and the presence of artificial penetrations within the AoR. In some instances, there may be a 

limited number of options for complying with EPA's minimum requirements. For example, 

monitoring for geochemical changes will require use of monitoring wells and collection of 

groundwater samples for chemical analysis. Many options currently exist for complying with 

other requirements, such as tracking the position of the plume and pressure front within the 

injection zone. 

Flexibility is also provided regarding how to monitor for the specific data required by the final 

rule. The testing and monitoring plan is developed by the owner or operator in consultation with 

the Director and is designed to ensure that a detailed, Director-approved document describing 

how monitoring will be conducted during the lifetime of the project exists. EPA is developing 

guidance on testing and monitoring to assist owners or operators and Directors in evaluating 

requirements under §146.90, including proposed monitoring plans. The guidance describes 

available technologies and recommended approaches for implementing a testing and monitoring 

plan, including pre-operational geophysical logging and testing of injection wells, MITs, 

injection well testing during operation, groundwater quality monitoring, tracking the CO2 plume 

and pressure front, and soil gas and surface air monitoring which may be required by the UIC 

Director for specific GS projects. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0225 Comment ID: 21721 Letter Lines: 391 to 397 

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

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

CFR 146.90) 

Comment: With respect to monitoring requirements in general, EPA should adopt regulations 

that are performance and risk-based and will result in a site-specific 

monitoring program that is designed to understand the location, movement and 

13
stabilization of the CO2 plume in the subsurface as well as the early 

identification of any leakage for appropriate corrective action. BP commends 

EPA for its efforts in this regard, but believes that further modification is 

necessary. BP agrees with the proposal to allow a phased approach to conduct 

Individual Response: EPA agrees with commenters and believes that flexibility is important in 

developing and implementing a monitoring plan that is appropriately tailored for a specific GS 

site. The purpose of the requirement at §146.90 to develop site-specific testing and monitoring 

plans is to ensure that the monitoring performed at a site is appropriate for site operational 

conditions and the geologic setting. EPA believes that this is the best approach for addressing 

potential risks at GS sites. These flexible provisions in the monitoring requirements for Class VI 

wells enable the owner or operator to tailor monitoring programs to the specific needs of each 

project in consultation with the Director. 

The final regulation provides for flexibility in: 1) methodologies used to collect these data, 2) the 

spatial resolution at which the data should be collected, and 3) how often the data should be 

collected. The number and placement of monitoring wells will be based on site-specific 

information such as the calculated AoR, injection rate and volume, site geology, baseline data, 

and the presence of artificial penetrations within the AoR. In some instances, there may be a 

limited number of options for complying with EPA's minimum requirements. For example, 

monitoring for geochemical changes will require use of monitoring wells and collection of 

groundwater samples for chemical analysis. Many options currently exist for complying with 

other requirements, such as tracking the position of the plume and pressure front within the 

injection zone. 

Flexibility is also provided regarding how to monitor for the specific data required by the final 

rule. The testing and monitoring plan is developed by the owner or operator in consultation with 

the Director and is designed to ensure that a detailed, Director-approved document describing 

how monitoring will be conducted during the lifetime of the project exists. EPA is developing 

guidance on testing and monitoring to assist owners or operators and Directors in evaluating 

requirements under §146.90, including proposed monitoring plans. The guidance describes 

available technologies and recommended approaches for implementing a testing and monitoring 

plan, including pre-operational geophysical logging and testing of injection wells, MITs, 

injection well testing during operation, groundwater quality monitoring, tracking the CO2 plume 

and pressure front, and soil gas and surface air monitoring which may be required by the UIC 

Director for specific GS projects. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0225 Comment ID: 21722 Letter Lines: 397 to 398 

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

Comment: necessary. BP agrees with the proposal to allow a phased approach to conduct 

corrective action in an Area of Review that has pre-existing well penetrations. 

Individual Response: EPA acknowledges the commenter’s support of phased corrective action 

14
and agrees that phased corrective action may provide many benefits to a project including, but 

not limited to, spreading the burden of cost, avoiding delays in project start-up, allowing for use 

of future, improved corrective action techniques and addressing unanticipated changes in the 

movement of the CO2 plume or pressure front. EPA believes that the phased corrective action 

approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS 

regulation. 

Letter ID: 0225 Comment ID: 21728 Letter Lines: 399 to 404 

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

CFR 146.84) 

Comment: Existing wells within the AoR may be ideal candidates for conversion to 

monitoring or injection wells during the life of the project and, therefore, 

should not be plugged and abandoned prior to injection. Existing wells within 

the likely plume area that are not plugged and abandoned should have diagnostic 

testing to ensure there is minimal risk of vertical leakage prior to conversion 

to monitoring or injection status. 

Individual Response: EPA recognizes that operators may choose to convert existing wells in the 

AoR for use as monitoring wells or injection wells. An operator seeking to use an existing well 

as a monitoring well would need to describe that well in the proposed testing and monitoring 

plan to demonstrate that is appropriately constructed for use as a monitoring well and compatible 

with the GS injection operation and injectate. The Director would take the condition of the well 

into consideration in approving the proposed testing and monitoring plan. 

Letter ID: 0225 Comment ID: 21729 Letter Lines: 406 to 414 

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

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

Comment: Furthermore, in various parts of the Proposed Rule, EPA has prescribed 

particular monitoring technologies. Mandating any specific technology(ies) would 

have the adverse effect of (1) promoting particular technologies to the 

exclusion of other developed - and to be developed - technology(ies), and (2) 

substantially increasing costs without necessarily contributing to the 

protection of USDWs. This would hinder the development and deployment of CCS at 

commercial scale. Moreover, it would discourage the development of other 

technologies. BP therefore strongly discourages EPA from promulgating 

regulations that mandate the use of any specific monitoring technology. 

Individual Response: EPA agrees that prescribing specific technologies to be used in all cases 

for GS would not be appropriate given the variability in sites, and believes that the rule provides 

flexibility to owners or operators to develop site-specific testing and monitoring plans that 

employ appropriate technologies provided they meet the requirements at §146.90. EPA is 

15
developing guidance on testing and monitoring to assist owners or operators and Directors in 

evaluating requirements under §146.90, including proposed monitoring plans. The guidance 

describes available technologies and recommended approaches for implementing a testing and 

monitoring plan, including pre-operational geophysical logging and testing of injection wells, 

MITs, injection well testing during operation, groundwater quality monitoring, tracking the CO2 

plume and pressure front, and soil gas and surface air monitoring which may be required by the 

UIC Director for specific GS projects. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. In addition, in January 2009, 

DOE published a best practices manual entitled "Monitoring, Verification, and Accounting of 

CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this manual is included in 

the docket for the for the final GS rule. 

Letter ID: 0225 Comment ID: 21730 Letter Lines: 416 to 461 

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

Comment: (3) Specific Comments 

In addition to the foregoing, BP respectfully submits the following areas of 

specific comment: 

(i) Well Design and Construction To Avoid Corrosion 

One area of comment requested by EPA relates to requirements for 

"degradation-resistant well construction materials, such as acid- resistant 

cements and corrosion resistant casing." (73 Fed. Reg. at 43510) Based upon 

historical industry experience and field studies, this would be an 

excessive requirement and not reasonably necessary to protect USDWs. Risk 

Profile of a CO2 Geological Storage Project: Wells, by Christopher, Crow, 

Dodds, Wright, Williams, March 2008. 

BP strongly discourages EPA from setting a requirement to use degradationresistant materials & cement. Actual field observations based upon sampling of 

in situ casing and annular cements do not support this general requirement. The 

studies referenced by EPA in its Preamble exposed cement in a laboratory setting 

to a continuously-refreshed supply of CO2-saturated brine, which then reportedly 

caused the cement to degrade. (Duguid et al., 2004 and Kutchko et al., 2007.) 

These studies represent variations in cement alteration rates due to curing and 

exposure conditions, but neither supports the requirement for the use of 

degradation-resistant materials and cement because the laboratory procedures 

that were used do not necessarily represent the actual barrier exposure 

conditions in an appropriately cemented operating well. Indeed, the findings of 

Kutchko’s laboratory study suggested there would be limited degradation even 

after decades, which is consistent with the field study results of Carey et al., 

2007. 

16
EPA’s rulemaking should give considerable weight to documented field surveys 

which provide more relevant well information, such as those conducted at the 

SACROC development in the Permian Basin (ref. Carey et al., 2007) and in 

Colorado (ref. Crow et al, and CO2 Capture Project, 2008). Both of these field 

studies identified that hydraulic isolation was maintained across the caprock, 

and the majority of cement reaction was localized to the area near the CO2 

interval. Field results indicate it is the appropriate placement of cement, and 

not the type of cement, that is key to delivery of effective isolation and hence 

prevention of casing corrosion. Furthermore, cement placement to completely fill 

the annular space between borehole and casing is the primary means of achieving 

this objective. 

Based on the foregoing, degradation-resistant materials should not be mandated 

for all projects, without regard to site-specific characteristics. Rather, the 

application of degradation-resistant materials & cement, if any, should be 

defined on site-specific characteristics. 

Individual Response: The rule does not specify the materials and cements to be used; rather, it 

provides owners or operators with the flexibility to choose, as long as the cements are compatible 

with the CO2 stream and formation fluids and of sufficient quality and quantity to maintain 

integrity over the design life of the GS project, as specified at §146.86(b)(5). 

EPA recognizes that each GS project will be unique and, for this reason, the rule provides 

flexibility regarding the selection and use of cements for Class VI wells that are appropriate to 

the site-specific conditions of the project. With the permit application, the owner or operator 

must submit well construction procedures, as specified at §146.82 (a)(12), that demonstrate that 

the well as constructed will prevent unacceptable fluid movement; allow the use of appropriate 

testing devices and workover tools; and allow continuous monitoring of the annulus space 

between the injection tubing and long-string casing, as specified at §146.86(a). The Director will 

evaluate the procedures in the context of geological and proposed operating data about the site. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0225 Comment ID: 21731 Letter Lines: 463 to 472 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

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

Comment: BP strongly supports, with one modification discussed below, EPA’s actual 

language of the Proposed Rule in section 146.86(b)(5), which establishes a 

reliable performance standard that will achieve protection of USDWs. Section 

146.86(b)(5) states, "Cement and cement additives must be compatible with the 

carbon dioxide stream and formation fluids and of sufficient quality and 

17
quantity to maintain integrity over the design life the geologic sequestration 

project." BP recommends that EPA’s discussion in the Preamble should be 

consistent with the actual language of the Proposed Rule to ensure clarity and 

remove any ambiguity regarding the performance-based approach set forth in the 

Proposed Rule. 

Individual Response: The final rule does not specifically require the use of acid-resistant 

cements, but it requires at §146.86(b)(5) that cement and cement additives be compatible with 

the CO2 stream and formation fluids and of sufficient quality and quantity to maintain integrity 

over the design life the GS project. Both field and laboratory studies have found acid alteration 

where traditional well cements have been used for CO2 injection. Although the laboratory and 

field studies suggest that corrosion problems may not be severe, such problems cannot be 

conclusively ruled out, and the amount of available data on this problem is still relatively small. 

Laboratory investigation of cement degradation is an ongoing research area, and field-based 

studies are very few. There also does not appear to be a clear consensus at this time on the 

corrosion risks for the steel components of injection wells. Given the anticipated long lifespan of 

a Class VI well and the difficulties that would be associated with a corrosion-related well failure, 

EPA believes that the construction requirements at §146.86 are justified. 

EPA clarifies that the requirement at §146.86(b)(5) is that cement and cement additives must be 

compatible with the CO2 stream and formation fluids and of sufficient quality and quantity to 

maintain integrity over the design life of the GS project. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0225 Comment ID: 21732 Letter Lines: 474 to 483 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: Furthermore, section 146.86(b)(5) should be amended to base the choice of casing 

and cement materials on the planned operating life of the well as opposed to the 

ultimate duration of the geologic sequestration project. EPA may have set the 

duration as the life of the project in an effort to prevent corrosion of the 

casing over the long term after injection has ceased. However, this legitimate 

concern is mitigated by appropriate plugging of the static well at the end of 

its life. This plugging could employ corrosion-resistant material, if an extra 

level of mitigation were deemed necessary at that time based upon site 

characteristics. API has submitted specific language to address the foregoing. 

We support API’s proposed language modification to section 144.86 (b)(5). 

Individual Response: EPA disagrees that the casing, cement or other materials should only be 

designed for the period of the injection process, rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

18
wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDW from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Letter ID: 0225 Comment ID: 21733 Letter Lines: 485 to 499 

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

Comment: (ii) Horizontal Wells Should Be Approved for Geologic Sequestration 

BP agrees with EPA’s discussion regarding the usefulness and benefits of 

constructing horizontal wells in geologic sequestration projects. It is 

evident that EPA has done a good amount of research in this area and is well 

informed on this topic. BP has direct experience with horizontal wells used in 

connection with geologic sequestration. At In Salah, 1mmtpa CO2 is being 

sequestered in a formation that is 6,000ft deep, 60ft thick and has permeability 

of only 10mD. These characteristics are very similar to many deep saline 

formations in the United States. To do this, requires only three wells, but the 

wells have very long horizontal sections in the storage formation. In fact, each 

well is about as long as it is deep. Horizontal wells provide a means of 

achieving high performance completions that optimize/improve injectivity. 

Additionally, horizontal wells can reduce the risk of leakage because their use 

limits the number of penetrations through the caprock. There are other options 

Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In 

the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques 

for Class VI wells, and commenters representing energy companies, electric utilities, the oil and 

gas industry, CCS associations, states, and the public, unanimously supported the concept and 

provided many reasons why horizontal wells could be beneficial at GS sites. Based on an 

evaluation of these comments and additional research by EPA, the Agency has concluded that 

horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to 

meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment. 

Letter ID: 0225 Comment ID: 21735 Letter Lines: 499 to 502 

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

Comment Code: 4130 2.4.1.3 Appropriateness of using fracturing for well stimulation (seeking 

comment) 

19
Comment: limits the number of penetrations through the caprock. There are other options 

to optimize injectivity as well that include, but should not be limited to, 

hydraulic fracture treatments, multiple injection points along the wellbore and 

open hole completions. 

Individual Response: EPA agrees that hydraulic fracturing is one of several stimulation 

technologies available to improve wellbore and formation injectivity. The final rule allows the 

use of hydraulic fracturing at GS sites, if approved by the Director. 

EPA clarifies that all stimulation of Class VI wells, including hydraulic fracturing, must be 

approved by the Director. Owners or operators must submit a proposed stimulation program as 

part of the permit application under §146.82(a)(9); the plan must demonstrate that any 

stimulation activities will not compromise the integrity of the confining zone. The Director will 

evaluate the owner or operator's proposed stimulation plan in the context of all information about 

the site, and the owner or operator must perform stimulation only as approved. 

The final rule also requires that the owner or operator notify the Director 30 days before 

performing stimulation during injection operations (§146.91(d)(2)); this will provide an 

additional opportunity for the Director to review the owner or operator's plans for stimulation 

and add other requirements as needed. EPA clarifies that UIC regulations prohibit fracturing of 

the confining zone at any time during injection or stimulation. 

EPA also agrees that multiple and open hole completions are also acceptable manners to improve 

injectivity. Class VI wells with these types of completions are acceptable, provided all other 

construction requirements at §146.86 are met. 

Letter ID: 0225 Comment ID: 21736 Letter Lines: 504 to 523 

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

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

Comment: (iii) Long String Casing Is Not Needed 

Section 146.86(b)(3) states that "at least one long string casing . . . must 

extend [from the surface] to the injection zone and must be cemented . . . ." 

(73 Fed. Reg. at 43538; § 146.86(b)(3).) This requirement is excessive and its 

implementation would unnecessarily constrain the ability to undertake future 

potential well interventions that support downhole monitoring and well 

remediation, if such become necessary. 

To avoid such an unintended result, BP recommends that EPA not mandate the 

placement of an isolation casing string from the surface, but rather allow the 

casing string to extend from beneath the surface or otherwise based upon site 

characteristics. Cement should cover the uppermost caprock (within the Area of 

Review) by approximately 500 feet; cement coverage should not be required all 

the way to surface. The ultimate decision for each project should rest with the 

20
Director since each storage site is unique in the geological intervals of the 

caprock(s), injection zone(s) and position relative to USDW(s). Moreover, any 

expectation to cement in the injection interval should permit the use of 

external casing packers or other isolation methods in conjunction with cementing 

requirements across the caprock, as discussed above. 

Individual Response: EPA does not believe that the cementing requirements at §146.86 would 

prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has 

been performed successfully in the past by owners or operators of Class I hazardous and Class I 

municipal waste disposal wells. Some of these wells, which must meet the same cementing and 

casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully 

cemented in a manner that maintains integrity and allows for all required well testing, operation, 

and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in 

the preamble to the final GS rule for additional information. Additionally, EPA is developing 

guidance on the construction of Class VI wells. This guidance will be available on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0225 Comment ID: 21737 Letter Lines: 525 to 543 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: (iv) Definition of Carbon Dioxide Stream 

Section 146.81 of the Proposed Rule defines "carbon dioxide stream" as follows: 

Carbon dioxide stream means carbon dioxide that has been captured from an 

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

derived from the source materials and the capture process, and any substances 

added to the stream to enable or improve the injection process. This subpart 

does not apply to any carbon dioxide stream that meets the definition of a 

hazardous waste under 40 CFR part 261. 

By limiting the definition to "emission sources," the Class VI regulations may 

have the unintended effect of narrowing the types of sources that might inject 

CO2 for geologic sequestration. The particular source of the CO2 is not material 

in terms of protecting USDWs. Furthermore, the Final Rule should not address the 

source because it is beyond the scope of this regulation. We recommend deleting 

the phrase "has been captured from an emission source (e.g., a power plant)" 

from the definition contained in section 146.81 of the Proposed Rule so that the 

Final Rule does not inadvertently preclude other non-emission sources of CO2. 

Individual Response: EPA disagrees with the suggested edit. The final definition of carbon 

dioxide stream at §146.81(d) remains unchanged and reads as: “[C]arbon dioxide that has been 

captured from an emission source (e.g., a power plant), plus incidental associated substances 

derived from the source materials and the capture process, and any substances added to the 

stream to enable or improve the injection process. This subpart does not apply to any carbon 

21
dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261.” 

EPA clarifies that the Class VI GS requirements apply to owners or operators of injection wells 

that will be used to inject CO2 into the subsurface for the purposes of GS. The capture of CO2 is 

outside the scope of the final rule. 

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

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0225 Comment ID: 21738 Letter Lines: 545 to 560 

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

USDW 

Comment: (v) EPA Should Not Restrict Injection To Below Lower-Most USDW 

The Proposed Rule restricts injection of CO2 to below the lower-most USDW. (See 

§§ 144.6(f), 146.5(f) and 146.81.) EPA acknowledges that such a restriction 

would preclude the consideration and use of various potential storage sites, and 

has requested comment on this approach. 

BP disagrees with such a blanket restriction, one that would pose a barrier to 

many, viable storage sites. The imposition of an artificial constraint limiting 

injection only to reservoirs below the USDW is not justified by technical 

knowledge or historical industry experience. For example, Class II requirements 

have proven successful in protecting USDWs even though injection into certain 

reservoirs has occurred above the lower-most USDW. Given the EPA’s effort in 

adopting a general performance-based approach, injection should be allowed to 

proceed into acceptable reservoirs provided the reservoir is demonstrated to 

provide secure CO2 storage above and below the injection formation. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. 

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type 

of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or 

22
between USDWs when appropriate and where it can be demonstrated that USDWs will be 

protected; and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, 

EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. For 

additional information on the waiver approach, please see the final rule and preamble, as well as 

EPA's responses to comments on the Notice of Data Availability and Request for Comment. 

Letter ID: 0225 Comment ID: 21739 Letter Lines: 562 to 569 

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

Comment: A containment system with appropriate site characterization, risk assessment and 

monitoring is the key to secure storage and protection of USDWs. Proximity of 

the injection zone to USDWs (i.e. whether shallower or deeper) is not the 

appropriate criteria for protection of USDWs because proximity alone does not 

materially impact risk of leakage. Similarly, EPA should not establish minimum 

depths for CO2 injection. Instead, any constraints placed on injection should 

be site-specific, consistent with the containment and capacity parameters of the 

storage site in question. 

Individual Response: EPA agrees that it is not appropriate to set a minimum injection depth for 

GS projects and the Agency believes that a determination of site-suitability for GS (i.e., that 

subsurface formations will receive and confine injected CO2) should be made on a site-specific 

basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and 

project-specific information to the Director to demonstrate that the site meets the minimum site 

criteria at §146.83, that the CO2 will be contained within the injection formation, and that 

USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs, as long as appropriate protections 

are in place. The final GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements for injection into non-USDW 

formations above and/or between USDWs. The waiver approach requires the submission of 

extensive, site-specific information (in conjunction with the permit application submission) to 

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be 

done in a manner that is protective of USDWs. The requirements are designed to ensure that the 

owner or operator, the Director, and the Regional Administrator consider, on a site specific basis, 

the implications, benefits, and challenges associated with GS and ensuring water availability and 

USDW protection. For additional information on the waiver approach, please see the final rule 

and preamble, as well as EPA's responses to comments on the Notice of Data Availability and 

Request for Comment. 

Letter ID: 0225 Comment ID: 21740 Letter Lines: 571 to 576 

23
Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

Comment: Related to the depth of injection, BP also disagrees with the requirement in 

section 146.86(b)(2) that "(s)urface casing must extend through the base of the 

lowermost USDW and be cemented to the surface." One reason is that at certain 

potential storage sites USDWs may be located at depth; consequently, it would be 

technologically infeasible to construct surface casing to the requisite depth 

prescribed by the Proposed Rule. 

Individual Response: The final GS rule at §146.86(b)(2) requires that surface casing extend 

through the base of the lowermost USDW and be cemented to the surface through the use of a 

single string or multiple strings of casing and cement. It does not, however, specify how 

cementing must be accomplished, and allows the owner or operator to propose alternate methods 

that provide a sufficient amount of cement to meet the standard that USDWs are protected from 

endangerment. EPA notes that there are many potential ways to meet the requirement, such as 

the use of staged cementing. 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW 

is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 

includes requirements for owners or operators that seek a waiver of the injection depth 

requirements. Owners or operators of wells operating under injection depth waivers must comply 

with additional construction requirements to ensure that wells used to inject above or between 

USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS 

rule for additional information. 

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the 

number of USDWs in an area, is the primary mission and mandate of the UIC program and the 

purpose of all requirements for injection wells. Any injection activity must be demonstrated to 

not endanger USDWs, regardless of their depth, and if such non-endangerment cannot be shown, 

the activity will not be allowed under UIC requirements or the SDWA. 

Letter ID: 0225 Comment ID: 21741 Letter Lines: 578 to 581 

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

USDW 

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

Comment: In summary, EPA should not mandate a requirement of injection only below the 

lower-most USDW nor a minimum depth for injection of CO2. Such a comprehensive 

prohibition would unjustifiably exclude potential storage sites that do not pose 

an endangerment to USDWs. 

Individual Response: As described above, EPA agrees that it is not appropriate to set a 

minimum injection depth for GS projects and the Agency believes that a determination of sitesuitability for GS (i.e., that subsurface formations will receive and confine injected CO2) should 

be made on a site-specific basis. EPA also acknowledges that there are limited circumstances 

24
where injection above the lowermost USDW can be performed in a manner that protects 

USDWs, as long as appropriate protections are in place. The final GS rule at §146.95 establishes 

a process by which owners or operators can seek a waiver of the Class VI injection depth 

requirements for injection into non-USDW formations above and/or between USDWs. 

Letter ID: 0225 Comment ID: 21742 Letter Lines: 583 to 596 

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

Comment: (vi) Injection Well Operation & Mechanical Integrity Requirements 

Consistent with the earlier discussion about blanket construction limitations, 

BP also disagrees with universal mandates regarding certain CO2 injection 

operations. EPA should not include automatic downhole shut-in devices as a 

standard requirement for CO2 injection wells (section 146.88(e)). An across-theboard requirement for installation of downhole devices is excessive - 

unsupported by technical knowledge and industry experience - and would impose 

unnecessary costs. Overpressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength with the surface 

injection (compression) system. Downhole shut-in devices may be appropriate, 

however, for site-specific situations (such as offshore), but they should not be 

mandated for all storage sites. Rather, the requirement of downhole shut-in 

devices should be left to the discretion of the Director. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

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

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. EPA believes that requiring the installation of automatic surface shut-off 

devices for onshore wells (and affording Director's discretion to require down-hole devices 

where necessary) ensures that proper precautions are taken to prevent subsurface fluid movement 

and ensure protection of USDWs. 

The GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off devices for Class 

VI wells located in the offshore submerged lands within the jurisdiction of a State UIC program. 

The Agency believes that the unique construction and operational conditions for offshore Class 

VI wells, including isolation from shorelines and the need to construct wells through the water 

column and the subsurface, may delay response time in the event of well difficulties. These 

conditions merit requiring automatic down-hole shut-off devices for offshore wells in the 

submerged lands of a State. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that 

for off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities 

such as acid gas injection wells and high pressure, high-temperature wells. While valve failure is 

25
a concern, EPA believes that technology has advanced sufficiently to make valve failure a rare 

occurrence and to appropriately handle such failure if it occurs. For example, wireline retrievable 

devices can allow repair or replacement of damaged devices without necessitating pulling the 

tubing. 

EPA believes that requiring the installation of automatic surface shut-off devices for onshore 

wells (and affording Director's discretion to require down-hole devices where necessary) and 

automatic down-hole shut-off devices for offshore wells in submerged lands within the 

jurisdiction of a State ensures that proper precautions are taken to prevent subsurface fluid 

movement and ensure protection of USDWs. 

Letter ID: 0225 Comment ID: 21743 Letter Lines: 598 to 606 

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 

146.89) 

Comment: With regard to validating mechanical integrity of CO2 injection wells, BP 

generally agrees with EPA’s suggestion to evaluate the "absence of significant 

leaks" by monitoring at some regular frequency the injection pressure, flow 

rate, injected volumes and the annular pressure. (See § 146.89 (b).) An 

alternative method for determining mechanical integrity, as noted by EPA, is 

periodic pressure testing; this should remain an option for site-specific cases. 

Where periodic pressure testing is implemented, the pressure should be 

considered by evaluation of the formation potential instead of casing burst or 

tubing collapse limit. 

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal 

mechanical integrity as required under §146.89(b) is preferable to periodic pressure testing as a 

means of demonstrating internal MI. The combination of computer-driven continuous pressure 

monitoring linked to an automatic injection shut-off system provides maximum protection to 

USDWs from endangerment and is the earliest warning to owners or operators that well repairs 

need to be performed. EPA believes that the technology for continuous monitoring is available, 

is currently in fairly wide use. The Texas Class I well regulations for industrial wells currently 

require continuous monitoring of annulus pressure and volume and the majority of injection 

wells in Ohio conduct continuous monitoring (GWPC, 2006). At least one commenter indicated 

that the technology required for continuous monitoring is currently available and should not 

present an undue cost burden. Continuous annulus monitoring is also conducted at the 

commercial-scaled carbon capture and geologic sequestration operation at the In Salah, Algeria 

natural gas plant where more than 3 million tons of CO2 have been sequestered since 2004. 

EPA is using an adaptive approach to regulating GS. The Agency plans to collect and review 

data every six years on early GS projects, including MIT data, to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. 

26
Letter ID: 0225 Comment ID: 21744 Letter Lines: 608 to 613 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: The frequency of the monitoring should be defined not as "continuous" but as 

"regular" or "periodic" based upon site characteristics because regular 

monitoring (e.g., every minute or hour) will often be adequate. For example, 

fluid volume in the annulus is static and requires evaluation of a pressure 

pulse to determine the depth of top of fluid. Therefore, this should be 

monitored on a monthly or quarterly basis to support the pressure data. 

Individual Response: EPA believes that continuous pressure monitoring of GS wells, instead of 

periodic testing, which is required for most other types of deep injection wells is appropriate 

because the potentially corrosive nature of CO2 injectate streams in the presence of water 

enables the immediate identification of corrosion-related internal mechanical integrity problems 

that could lead to significant well problems and failure. Continuous monitoring was found to be 

very important in an EPA study of UIC Class I internal MIT failure rates and causes (USEPA 

1993). The study reviewed MIT results over a 5 year period and found 135 MIT failures in 428 

wells (a single well can have more than one MIT failure). In all cases, the MIT failures were 

found through continuous annulus monitoring which served the important role of an early 

warning to prevent any well failure. Class VI injection wells must be equipped with dedicated 

computer-based continuous pressure monitoring devices in concert with the shut-off systems 

required for GS wells, which typically take readings several times per second and record them 

electronically in a computer system. 40 CFR §146.91(a)(2) requires that monthly averages of the 

continuous annulus monitoring be reported on a semi-annual basis. 

EPA believes that monitoring of annulus fluid volume is an important method for verifying that 

the well system is intact, and knowing the annulus fluid volume is necessary for monitoring 

annulus pressure. While this requirement has until now been limited to Class I hazardous waste 

injection wells, the high volumes and supercritical nature of the injectate, the potential 

geomechanical stresses in the wellbore, and the potential for movement of the buoyant CO2 in 

the event of a MI loss make it an important safety consideration for GS projects. Continuous 

pressure monitoring allows immediate identification of corrosion-related well integrity loss. EPA 

agrees with the commenter that recording annulus fluid volume may not be appropriate. 

However, EPA believes that knowing annulus fluid volume as specified at §146.88(e) is a 

necessary component of monitoring well mechanical integrity, but believes that knowing the 

annulus fluid volume added is sufficient to meet the intent of the requirement. The final GS rule 

requires that owners or operators use continuous recording devices to monitor injection pressure, 

rate and volume; as well as the pressure on the annulus between the tubing and the long string 

casing. It also modifies the requirement in the proposed rule to continuously monitor annulus 

fluid volume; it now requires recording of annulus fluid volume added. See §§146.88(e); 

146.89(b); and 146.90(b). 

Fluid level can be detected using acoustic techniques (Schubert, 1998). The Texas Class I well 

27
regulations for industrial wells currently require continuous monitoring of annulus pressure and 

volume, and the majority of injection wells in Ohio conduct continuous monitoring (GWPC, 

2006). At least one commenter indicated that the technology required for continuous monitoring 

is currently available and should not present an undue cost burden. Continuous annulus 

monitoring is also conducted at the commercial-scaled carbon capture and geologic sequestration 

operation at the In Salah, Algeria natural gas plant where more than 3 million tons of CO2 have 

been sequestered since 2004. The technology for continuous monitoring is available, is currently 

in fairly wide use, and the costs are not burdensome, especially given the operational and safety 

considerations addressed. 

Letter ID: 0225 Comment ID: 21745 Letter Lines: 615 to 618 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Section 146.89(c) lists specific methodologies to monitor fluid movement. BP 

strongly disagrees with the requirement of any particular methodology because 

this would limit technology development and favor certain technologies to the 

exclusion of others without any rationale basis. 

Individual Response: EPA believes that the MITs described in the rule at §146.89 are effective 

methods and have been used successfully by injection well operators for decades and provide an 

important early warning of potential problems in the injection well system. 

EPA clarifies that the regulations provides the Director discretion to require additional methods 

or, with the Administrator's approval, to approve the use of alternative MIT methods based on 

specific information about the site or the well. See §146.89(e). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect 

and review data every six years on GS projects to determine whether the appropriate amount and 

types of information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. EPA believes this flexibility and 

the adaptive approach will allow the incorporation of future technologies. 

Letter ID: 0225 Comment ID: 21746 Letter Lines: 620 to 637 

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

Comment: (C) SITE CLOSURE PERIOD 

EPA correctly states in its Preamble that defining the post-injection site care 

period is "difficult to define because it is based on site-specific 

considerations." (73 Fed. Reg. at 43519.) The three studies cited by EPA also 

concluded that "the actual time for CO2 plume stabiliziation . . . will be very 

28
site-specific, being influenced by geologic factors such as formation 

permeability, geochemistry, and the degree of capillary trapping." (Id.) 

However, the Proposed Rule establishes a default 50-year period (following the 

cessation of injection) during which the operator must conduct monitoring to 

demonstrate that "the carbon dioxide plume and pressure front have stabilized 

and the geologic sequestration project does not pose an endangerment to USDWs." 

(See § 146.93(b).) The designation of a 50-year time-period without regard to 

particular site characteristics is arbitrary and not supported by existing 

scientific studies or industry experience. Moreover, the 50-year timeframe does 

not provide any incremental benefit as compared with a performance standard to 

protecting USDWs; rather, it will be a significant deterrent to commercial 

investment in geologic sequestration projects. 

Individual Response: EPA disagrees that the 50 year time frame is unsupported. In determining 

the post-injection site care-timeframe for the proposed regulation, EPA reviewed industry 

reports, existing environmental programs, and initial GS research studies. EPA provided a 

synthesis of pertinent results from GS modeling studies in the preamble to the proposed 

regulation. Further explanation of this analysis was included in an EPA-prepared background 

document that is available in the federal docket, titled "Computational Modeling of Underground 

Injection of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to 

Underground Sources of Drinking Water." Based on review of these studies, modeling results 

indicate that the CO2 plume stabilization may occur on the timeframe of 10-100 years after the 

cessation of injection. EPA believes that a 50-year default post-injection site care timeframe is a 

reasonable midpoint for most GS projects and available data, including data submitted by 

commenters, do not support a different default timeframe, and has retained this in the final 

regulation. 

However, EPA recognizes that there may be sites where the 50 year post injection site care 

timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. For this reason, the GS rule offers owners or operators flexibility regarding 

the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or 

lengthen the PISC timeframe during the post-injection period based on site-specific data, 

pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class 

VI well owner or operator to demonstrate, during the permitting process based on substantial 

data, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of 

USDWs pursuant to requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in most cases. The default 50 year post-injection site 

care timeframe represents a reasonable and protective monitoring period based on a review of 

research studies, industry reports, and existing environmental programs, and evaluation of public 

comments. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

29
substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

Letter ID: 0225 Comment ID: 21753 Letter Lines: 639 to 649 

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

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

Comment: BP urges EPA to adopt the performance standard that EPA considered in its 

review. EPA considered three options: (1) fixed period; (2) performance 

standard; and (3) combination of fixed period and performance standard; EPA 

states it adopted the latter approach. (73 Fed. Reg. at 43519.) While the 

Proposed Rule allows a Director to reduce the 50-year minimum (§146.93(b)(2)), 

the practical effect will be the 50-year timeframe applies unless an operator is 

able to overcome the presumption built into the Proposed Rule that 50 years is 

adequate. Indeed, this is more prescriptive than the requirement for Class I 

hazardous wells, which provides that the timeframe for post-injection site care 

ends when the plume has stabilized and cannot endanger USDWs. (Id.; 40 CFR 

§146.71.) 

Individual Response: EPA agrees that some owners or operators will be able to demonstrate, in 

less than 50 years, that the pressure front and plume no longer pose a risk of endangerment to 

USDWs. However, based on studies, EPA believes that the 50 year default time frame is 

warranted based on additional review of research studies and reports and evaluation of public 

comments. 

EPA believes that the best way to address all possibilities, while ensuring USDW protection 

from endangerment, is to set a 50 year default post-injection site care timeframe, with flexibility 

to: (1) allow the Director discretion to shorten or lengthen the PISC timeframe during the PISC 

period based on site-specific data, pursuant to requirements at §146.93(b); or (2) afford the 

Director discretion to allow a Class VI well owner or operator to demonstrate, based on 

substantial data during the permitting process, that an alternative PISC timeframe may be 

appropriate if it ensures non-endangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

30
Letter ID: 0225 Comment ID: 21754 Letter Lines: 651 to 678 

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

Comment: EPA should adopt the performance-based standard that it considered previously. 

Accordingly, the post-injection site care period ends when monitoring and other 

site-specific data demonstrate that the geologic sequestration project does not 

pose an endangerment to USDWs. (See e.g., 73 Fed. Reg. 43520.) A 

performancebased approach is consistent with technical knowledge and historic 

industry experience. The site closure period would be appropriately based on 

particular site characteristics and historic site performance. For example, a 

well-selected and managed sequestration site (such as an existing oil or gas 

field) that has met its performance objectives (including plume stabilization) 

will be much more secure and could be closed reasonably quickly (potentially, in 

as few as 2-3 years). At other sites that are less well confined (e.g., deep 

saline formation without a conventional 4-way closure), the CO2 could move 

around for some time even after injection ceases before stabilizing, and might 

therefore require a longer period to allow for additional residual and 

solubility trapping. 

In summary, BP recommends that EPA adopt a performance-based approach to 

determine the timeframe for site closure. We also support the site closure 

standard offered in the MSDG Proposal for section 146.93(b), which sets forth 

detailed criteria that must be satisfied to demonstrate that the site does not 

pose an endangerment to USDWs. The advantage of the MSDG Proposal as opposed to 

a fixed period is it establishes clear criteria that an operator must 

demonstrate before obtaining site closure based upon particular site 

characteristics and is, therefore, reasonable applicable to any storage site as 

opposed to a standard based upon a fixed-duration. The current proposal of 50- 

years minimum, even subject to potential reduction, would result in 

significantly discouraging the deployment of this technology at commercial scale 

without providing measurable additional protection of USDWs. 

Individual Response: EPA agrees that there will be circumstances where it can be demonstrated 

in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to 

USDWs. For this reason, the GS rule offers owners or operators flexibility regarding the duration 

of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the post-injection period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in most cases. The default 50 year post-injection site 

31
care timeframe represents a reasonable and protective monitoring period based on a review of 

research studies, industry reports, and existing environmental programs, and evaluation of public 

comments. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA adds that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose 

of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects 

USDWs from endangerment. 

Letter ID: 0225 Comment ID: 21755 Letter Lines: 680 to 693 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: (D) EPA’s Proposed Financial Responsibility Demonstration Requirements 

The proposed financial assurance requirements for Class VI UIC wells require the 

owner or operator to establish financial responsibility (or "financial 

assurance") to cover the costs of plugging and abandoning injection wells, as 

well as the costs of corrective action, post-injection site care, site closure 

and emergency and remedial responses. (73 Fed. Reg. at 43537; §146.85.) The 

financial responsibility requirements should be consistent with the need to 

protect USDWs, while being reasonable and cost-effective, yet facilitating 

geologic sequestration of CO2. We support EPA’s proposed approach that allows 

for a wide range of financial assurance mechanisms to be utilized to demonstrate 

financial responsibility. We also suggest that EPA adopt a flexible, iterative 

approach to financial assurance in keeping with the phased, adaptive management 

philosophy of other aspects of the Proposed Rule. 

Individual Response: Owners or operators may choose from a variety of financial instruments 

to meet their financial responsibility obligations, provided the Director determines that the 

operator's proposed financial responsibility demonstration is adequate to protect USDWs from 

endangerment, which includes the ability to pay for each activity for which financial 

responsibility must be demonstrated, including corrective action on wells in the AoR, injection 

well plugging, PISC and site closure, and emergency and remedial response. The allowable 

instruments are identified at §146.85(a). EPA clarifies that it will allow owners or operators to 

use separate and multiple financial responsibility instruments for different GS activities, and that 

owners or operators can be released from an instrument when the phase of the project for which 

32
the instrument was required is complete, as specified in §146.85(b)(1). However, owners or 

operators must demonstrate adequate financial responsibility for all activities for which financial 

responsibility is required with their permit applications, per §146.85(a). See the final rule and 

preamble for further discussion of EPA's final approach to financial responsibility. 

Given that the practice of GS is fairly new and EPA does not have enough information in 

supporting future prediction, EPA plans, every six years, to collect and review data on GS 

projects to determine whether the appropriate amount and types of information and appropriate 

documentation are being collected, and to determine if modifications to the requirements are 

appropriate or necessary. 

Letter ID: 0225 Comment ID: 21756 Letter Lines: 695 to 722 

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

comment) 

Comment Code: 5434 2.9.1.2 Need for additional instruments (seeking comment) 

Comment: (1) Allow for a Broad Range of Financial Assurance Mechanisms 

We support an approach that takes into account changing market conditions and 

other factors and allows an operator to utilize a wide range and variety of 

financial assurance mechanisms to demonstrate financial responsibility. This 

should be coupled with the flexibility to combine multiple types of financial 

assurance mechanisms to demonstrate compliance. The regulations or guidance 

should be flexible and authorize EPA to accept and recognize other types of 

instruments, programs or conditions that provide similar reliable assurance. 

While the Proposed Rule does not limit the range of financial assurance 

mechanisms, EPA indicates that the Agency is considering revising various 

guidance documents related to financial assurance. (73 Fed. Reg. at 43520-21.) 

EPA refers to several reports issued by the United States General Accountability 

Office ("GAO"), Office of Inspector General ("OIG"), and the Environmental 

Financial Advisory Board ("EFAB"). Id. In 2003, the GAO issued a report 

reviewing, in part, the financial assurance requirements for Class I injection 

wells. See GAO Report to the Honorable Lynn C. Woolsey, House of 

Representatives, Deep Injection Wells: EPA Needs to Involve Communities Earlier 

and Ensure that Financial Assurance Requirements are Adequate, GAO-03-761, 17-22 

(June 2003). GAO noted that there is uncertainty about the adequacy of financial 

assurance requirements, but did not make any conclusions about specific 

mechanisms. Similarly, in 2005, OIG issued a report reviewing the financial 

assurance mechanisms under the RCRA program. OIG Evaluation Report, Continued 

EPA Leadership Will Support State Needs for Information and Guidance on RCRA 

Financial Assurance, Report No. 2005-P-00026 (Sept. 26, 2005). OIG concluded 

that despite ongoing concerns, the lack of uniform national data prohibited 

ready identification of the problems. Id. at 8. 

33
Individual Response: EPA agrees that it is appropriate to allow a flexible approach for financial 

responsibility. Under the final GS rule owners or operators have the flexibility to choose from a 

variety of financial instruments to meet their financial responsibility obligations. Owners or 

operators may use one or multiple financial responsibility instruments for well plugging and 

PISC (§146.85(a)(6)). However EPA will not allow for a separate financial responsibility 

demonstration for well plugging and PISC (i.e., a demonstration submitted prior to well plugging 

and the beginning of the post-injection site care period rather than with the permit application). A 

demonstration of financial responsibility for all phases of the GS project will be required prior to 

the issuance of a Class VI permit (§146.85(a)(5)(i)). 

EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) to help owners or operators, 

permitting authorities, and third parties choose and evaluate appropriate financial methods, and 

states may set more specific financial responsibility requirements if they so choose. 

Letter ID: 0225 Comment ID: 21757 Letter Lines: 724 to 727 

Comment Code: 1910 1.4.4 Stakeholder outreach 

Comment: As EPA develops revisions or potential modifications to financial assurance 

guidance that would be applied to UIC permits, it should provide further public 

notice, review and engagement opportunities that allow for feedback to EPA on 

specific proposals. 

Individual Response: EPA subjected the financial responsibility guidance to expert review; the 

final guidance reflects this input. In addition, EPA is using an adaptive approach to regulating 

GS under the UIC Program. Even after finalization of the GS regulation, the Agency plans to 

collect and review data every six years on GS projects to determine whether the appropriate 

amount and types of information and appropriate documentation are being collected, and to 

determine if modifications to the requirements are appropriate or necessary. EPA will also 

evaluate whether any changes to the GS rule necessitate revisions to the guidance. 

Letter ID: 0225 Comment ID: 21758 Letter Lines: 729 to 760 

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and 

abandonment and post-injection site care (seeking comment) 

Comment: (2) EPA’s Suggestion for a Phased Approach to Financial Assurance for PostInjection Site Care Should be Adopted 

EPA is relying on an adaptive management approach for regulation of CO2 

injection. (73 Fed. Reg. at 43522.) EPA specifically requested comment on 

allowing separate financial demonstration to be submitted for well-plugging and 

for post-injection site care. In the Preamble, EPA states that: 

34
Since post-injection site care has the potential to extend many years into the 

future, subsequent to the time a permit is issued, the Agency believes that it 

may be advantageous to require the approval of the well plugging financial 

demonstration at permit issuance and the post-injection site care financial 

demonstration at a later time (e.g., within 180 days of notifying the Director 

that the well will be plugged and abandoned). Trying to determine the cost for 

postinjection site care, possibly 30 to 50 years in the future, could be 

difficult, as could the approval of a financial demonstration. 

(73 Fed. Reg. at 43522.) We agree with EPA’s stated rationale and recommend that 

EPA specifically incorporate language in the Final Rule that describes the 

manner in which determinations and demonstrations of financial assurance for 

post-injection site care will be postponed until a later time as discussed by 

EPA. 

(3) Clarifying that adaptive management approach allows for phased financial 

assurance release 

In accordance with the adaptive management approach for CCS, the rulemaking 

should clarify that the financial assurance can be released (or amounts reduced) 

as particular activities are completed and regulatory criteria are met (e.g., 

well plugging for corrective action). Also, the owner or operator should be able 

to use site-specific data gathered from such activities to support revisions to 

site-specific financial assurance requirements. 

Individual Response: EPA will allow owners or operators to use separate financial 

responsibility instruments for well plugging and site closure. However, owners or operators must 

demonstrate adequate financial responsibility for all required activities with their permit 

applications, per §146.82(a)(14), and financial responsibility will need to be reevaluated prior to 

well plugging or site closure, or at any other time deemed appropriate by the Director. EPA 

believes this is necessary to ensure that resources are available to prevent the endangerment of 

USDWs in the event that the owner or operator experiences financial difficulties at any time 

during the life of the GS project. 

EPA recognizes that there are challenges associated with estimating costs for activities that will 

occur far in the future. However, the Agency believes that owners or operators must demonstrate 

that financial resources are available to plug the injection well and provide post-injection care at 

the time the Class VI well is permitted. 

EPA agrees that GS technologies and cost estimating methods are likely to change and improve 

as GS is deployed nationwide. However, EPA believes that past injection practices provide a 

good foundation for estimating the necessary costs and demonstrating financial responsibility. 

EPA envisions that financial responsibility updates required at the time of AoR reevaluation or at 

other frequencies specified by the Director, will provide opportunities to refine the cost estimates 

and adjust the financial responsibility instruments as appropriate. 

35
In order to assist owners or operators and financial institutions in achieving accurate cost 

estimates for all GS activities, EPA plans to issue financial responsibility guidance that will 

include a discussion of how to estimate costs, including how to adjust cost estimates for inflation 

to account for the long-term nature of GS projects, in its guidance on meeting financial 

responsibility requirements for GS wells. 

EPA clarifies that the final rule, at §146.85(b)(2), allows release from a financial instrument 

when the phase of the project for which the instrument was obtained is complete, assuming that 

all other financial obligations have been met. 

Letter ID: 0225 Comment ID: 21759 Letter Lines: 762 to 770 

Comment Code: 1230 1.1.1.2 General comments on the regulatory text 

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

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

Comment: (E) ISSUES SPECIFICALLY RELATED TO OIL & GAS PRODUCTION 

EPA has appropriately restricted the applicability of Class VI regulations to 

projects that are exclusively geologic sequestration projects. Furthermore, BP 

appreciates EPA’s efforts to limit this rulemaking to the authority vested in 

EPA by Congress pursuant to the Safe Drinking Water Act ("SDWA"). BP requests 

that EPA include some of the discussion in the Preamble to the Final Rule to 

ensure that unrelated activities in the Oil & Gas industry are not impacted by 

unintended inferences or interpretations of the Proposed Rule. 

Individual Response: EPA clarifies that the final Class VI regulations require that any owner or 

operator injecting CO2 for the primary purpose of long term storage obtain a Class VI permit 

with some special consideration for the fact that they are transitioning from a well not originally 

designed to meet Class VI requirements. The Director has the authority to determine at what 

point a Class VI permit is required for those projects that are transitioning from the primary 

purpose of EOR to long term storage of CO2. The final regulation provides a set of technical 

factors for the Director to evaluate in making this determination, at §144.19. EPA believes that 

this approach provides sufficient protection of USDWs when there is an increased risk to 

USDWs as compared to traditional Class II operations while allowing for site-specific flexibility. 

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

the final GS rule. 

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the 

purpose of ER, and that sites used for ER may be suitable for GS and may be among the first GS 

sites. EPA also believes that the nature and risks of CO2 injection for the primary purpose of 

long term storage poses different risks than injection for the primary purpose of ER, and 

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

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

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

36
operations involving large volumes of CO2 and likely having higher pressures within their 

storage formations than Class II ER projects. 

Letter ID: 0225 Comment ID: 21760 Letter Lines: 772 to 784 

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space 

ownership 

Comment: (1) Property Rights Issues Are Matter of State Law 

EPA accurately states that the SDWA does not afford EPA the authority to 

regulate many issues involved in CO2 sequestration, including property rights 

which are regulated under state law. (73 Fed. Reg. at 43495.) In many instances, 

the owner of the surface property rights may be different than the owner of the 

subsurface mineral rights. There may be a legal question as to who owns the 

subsurface storage rights as between, for example, the surface property rights 

owner and the mineral rights owner. This is a matter of state law as correctly 

discussed by EPA. BP requests that EPA expand on its assertion in the Preamble 

that it does not have authority to regulate in this area and that nothing in the 

Proposed Rule should be interpreted or inferred as a grant of subsurface storage 

rights. 

Individual Response: EPA clarifies that pore space ownership and surface and subsurface 

property and mineral rights are outside of the scope of the Class VI GS rulemaking. These issues 

are under the purview of states and any of these issues, as they relate to GS, will need to be 

addressed though state regulations. 

The UIC program’s authority under SDWA is focused on ensuring that where GS technologies 

are deployed, GS is performed in a manner that protects USDWs from endangerment. 

Letter ID: 0225 Comment ID: 21761 Letter Lines: 786 to 797 

Comment Code: 4440 2.4.4.3.4 Injection into organic-rich shales above USDWs (seeking 

comment) 

Comment: (2) Organic-Rich Shales Are Primary Remaining Supply of Natural Gas 

EPA also states in the Preamble that organic-rich shales are potential 

reservoirs for geologic sequestration of CO2. However, these shales are also the 

single largest source of natural gas remaining in the United States, and will 

likewise help to ensure that low-carbon energy supplies are available to fuel 

the United States’s economy. EPA should include in its Preamble a clear 

statement that nothing in the Preamble and/or the Proposed Rule should be 

interpreted or inferred as a preference for the use of these organic-rich shales 

for geologic sequestration as opposed to natural gas production. Whether 

37
organic-rich shales are used for natural gas production or geologic 

sequestration should be a matter left to negotiations between private parties. 

Individual Response: EPA clarifies that the GS rule does not address the use of any formation 

types or specific formations for a particular activity (e.g., GS or natural gas production). Rather, 

the intent of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that 

protects USDWs from endangerment. 

Letter ID: 0225 Comment ID: 21762 Letter Lines: 799 to 809 

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space 

ownership 

Comment: (3) Proposed Rule Should Not Affect Injection of Oil & Gas Waste 

Oil and gas waste (such as produced water and amine waste gases [CO2 and H2S]) 

are often injected back into the reservoir after separation during oil and gas 

production activities. This type of injection is and has been historically 

permissible under Class II regulations. (See 40 CFR § 144.6(b)(1).) EPA was 

silent on whether the Proposed Rule would in any manner affect the applicability 

of the Class II well regulations for injection of oil and gas waste. EPA should 

indicate in its Preamble to the Final Rule that the Final Rule does not alter in 

any manner the applicability of Class II regulations to injection of oil and gas 

waste. 

Individual Response: The Agency clarifies that the final Class VI GS rule does not require 

owners or operators to use GS technologies, nor does it impact business as usual for Class II 

owners or operators that are injecting CO2 to enhance production of oil or gas. Those owners or 

operators that choose to transition from enhanced recovery to GS may do so, provided they meet 

the requirements for Class VI wells. 

Letter ID: 0225 Comment ID: 21763 Letter Lines: 811 to 824 

Comment Code: 1420 1.2.1.1 Support the GS rulemaking 

Comment: CONCLUSION 

BP commends EPA for the tremendous amount of work that EPA has done in preparing 

the Preamble and Proposed Rule in an expedited timeframe. After due 

consideration of studies and analyses performed by international research 

organizations, non-governmental organizations, sister-agencies, and scientists 

worldwide, EPA’s research has determined that CCS could be "a key mitigation 

technology for achieving domestic emissions reductions," and CCS has the 

"potential to play a significant role in climate change mitigation scenarios." 

(73 Fed. Reg. at 45496.) BP applauds EPA’s willingness to play a significant 

38
role in this Nation’s strategy to address climate change. We are very supportive 

of EPA’s effort to implement a regulatory scheme that will both protect one of 

our vital resources, USDWs, and facilitate the implementation of CCS technology 

and geologic sequestration of CO2. 

Individual Response: EPA believes that the creation of a new injection well class (VI) under the 

existing UIC Program is necessary to enable the use of GS as a climate change mitigation 

technology in a manner that protects USDWs from endangerment. EPA agrees that the UIC 

Program, under the authority of the SDWA, provides a strong framework for regulating injection 

of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the 

unique issues associated with large-scale GS including large injection volumes, the relative 

buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in 

captured CO2, and its mobility within subsurface geologic formations. 

Letter ID: 0225 Comment ID: 21764 Letter Lines: 826 to 836 

Comment Code: 1000 1. General and Administrative Comments 

Comment: Significantly, this technology does not start on a blank slate. The Oil & Gas 

industry has extensive, relevant experience with injection into the subsurface 

that can inform this rulemaking. Moreover, BP is a leader in studies and 

demonstration projects conducted around the world regarding geologic 

sequestration of CO2. The comments submitted here are in large measure based 

upon BP’s significant experience and technical knowledge. We would be pleased to 

review our comments and/or any questions that EPA may have regarding our 

comments at EPA’s convenience. BP also welcomes the opportunity to provide 

additional information or input to EPA as EPA continues its evaluation and study 

of comments, scientific papers/studies or other information submitted or 

considered in this rulemaking process. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of EOR. The GS rulemaking builds upon existing experience and 

knowledge about safe injection practices in EOR and other injection industries, with tailored 

requirements that address the unique nature of CO2 injection for GS. 

EPA acknowledges the comment. Please see the remainder of EPA's responses to this comment 

for further details. For additional information on EPA's final regulatory approach, please see the 

final rule and preamble, including the discussion of the repermitting of Class II EOR wells for 

GS, as well as the rulemaking docket. 

39