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 
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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-
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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 
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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-
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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. 
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(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 
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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