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Proposed Rule

Enhanced Oil and Natural Gas Production Through Carbon Dioxide Injection

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Information about this document as published in the Federal Register.

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AGENCY:

Bureau of Land Management, Minerals Management Service, Interior.

ACTION:

Advance notice of proposed rulemaking.

SUMMARY:

The Bureau of Land Management (BLM) and the Minerals Management Service (MMS) request comments and suggestions to assist in preparing a proposed rule governing carbon dioxide injection for increased production and recovery of oil and natural gas. The rule would provide for royalty relief incentives to promote the capture, transportation, and injection of produced carbon dioxide (CO2), natural CO2, and other appropriate gases or other matter for injection/sequestration into oil and gas fields, to promote oil and natural gas production from the Outer Continental Shelf (OCS) and onshore Federal leases. We encourage members of the public to provide comments and suggestions to help clarify and define the requirements for enhanced oil and natural gas recovery production incentives as described in the Energy Policy Act of 2005.

DATES:

We will accept comments and suggestions on the advance notice of proposed rulemaking until April 7, 2006.

ADDRESSES:

You may submit comments by any of the following methods listed below. Federal rulemaking portal: http://www.regulations.gov (Follow the instructions for submitting comments.) Internet e-mail: comments_washington@blm.gov. (Include “Attn: AD82”) Mail: Director (630), Bureau of Land Management, Administrative Record, Room 401-LS, Eastern States Office, 7450 Boston Boulevard, Springfield, Virginia 22153. Personal or messenger delivery: Room 401, 1620 L Street, NW., Washington, DC 20036.

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FOR FURTHER INFORMATION CONTACT:

For onshore, Thomas J. Zelenka at (202) 452-0334 and for offshore, Marshall Rose at (703) 787-1536, as to the substance of the advance notice, or Ted Hudson at (202) 452-5042, as to procedural matters. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8330, 24 hours a day, seven days a week, to contact the above individuals.

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SUPPLEMENTARY INFORMATION:

I. Public Comment Procedures

II. Background

III. Description of Information Requested

I. Public Comment Procedures

A. How Do I Comment on the Advance Notice of Proposed Rulemaking?

Your written comments should:

  • Be specific;
  • Explain the reason for your comments and suggestions; and
  • Be about the issues outlined in the notice.

Comments and recommendations that will be most useful and likely to influence decisions on the content of the proposed rule are:

  • Those supported by quantitative information or studies, and
  • Those that include citations to and analyses of any applicable laws and regulations.

We are particularly interested in receiving comments and suggestions about the topics listed under Section III. Description of Information Requested.

If you wish to comment, you may submit your comments by any one of several methods, in each case referring to “1004-AD82”.

  • You may mail comments to Director (630), Bureau of Land Management, Administrative Record, Room 401 LS, Start Printed Page 11558Eastern States Office, 7450 Boston Boulevard, Springfield, Virginia 22153.
  • You may deliver comments to Room 401, 1620 L Street, NW., Washington, DC 20036.
  • You may comment on the rule at the Federal eRulemaking Portal: http://www.regulations.gov following the instructions at that link.
  • You may also comment via e-mail to: comments_washington@blm.gov.

BLM and MMS may not necessarily consider or include in the Administrative Record for the final rule comments that BLM receives after the close of the comment period (see DATES) or comments delivered to an address other than those listed above (see ADDRESSES).

B. May I Review Comments Submitted by Others?

Comments, including names and street addresses of respondents, will be available for public review at the address listed under “ADDRESSES: Personal or messenger delivery” during regular business hours (7:45 a.m. to 4:15 a.m.), Monday through Friday, except holidays.

Individual respondents may request confidentiality, which we will honor to the extent allowable by law. If you wish to withhold your name or address, except for the city or town, you must state this prominently at the beginning of your comment. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, available for public inspection in their entirety.

II. Background

A. Statutory: The Energy Policy Act of 2005 (EPAct), at Section 354, Enhanced Oil and Natural Gas Production through Carbon Dioxide Injection, is intended: (1) To promote the capture, transportation, and injection of produced CO2, natural CO2, and other appropriate gases or other substances for sequestration into oil and gas fields; and (2) to promote oil and natural gas production from the OCS and onshore Federal leases by providing royalty incentives to use enhanced recovery techniques using injection of substances referred to above. The statute directs the Secretary to undertake a rulemaking to grant royalty relief “if the Secretary determines that reduction of the royalty under a Federal oil and gas lease * * * is in the public interest and promotes the purposes of this section * * *”. The EPAct, at Section 354(b)(2), also directs the Secretary to issue an Advance Notice of Proposed Rulemaking within 180 days after the August 8, 2005, date of its enactment.

B. Technical Review: Traditional primary and secondary oil production methods typically recover one third of the oil in place in a field. This leaves behind two thirds of the oil as a target for enhanced oil recovery (EOR) techniques. Thermal, chemical, and gas flooding are three major EOR methods which have been developed and utilized for maximizing oil reserves recovery from onshore fields.

EOR is fairly advanced in some regions of the United States. Steam flooding is used to enhance production from many California fields because the oil can be very viscous. CO2 flooding is common in the fields in New Mexico, West Texas, western Oklahoma, and Wyoming because commercial pipelines deliver the CO2 gas to these regions from natural CO2 sources or from natural gas processing plants. CO2 is also available for some fields in Mississippi and Louisiana. EOR operations are not common in most of the rest of the nation because steam is not needed or CO2 is not available. Where CO2 from natural sources is not available nearby, the use of CO2 sequestration from gas processing or other industrial plants may be an alternative source.

Studies conducted by DOE and industry estimate that 55 percent of oil and 33 percent of gas remain stranded offshore Louisiana using traditional primary and secondary recovery practices. Preliminary research suggests that one-tenth to one-third of that stranded resource could be recovered using CO2 EOR technology. In Norway, the target for original oil left behind in place is about 45% and other new offshore projects are attempting further increases in the rate of recovery. Domestically, incentives to spur new technology may encourage additional technologies and recovery efficiencies.

C. Ongoing Research and Development Activities: The potential for enhanced oil recovery through CO2 injection has been demonstrated to be a viable technology for mature onshore oil fields. Until recently, most of the CO2 used for EOR projects has come from naturally-occurring reservoirs. New technologies are being developed to produce CO2 from industrial applications such as natural gas processing, fertilizer, ethanol, and hydrogen plants in locations where naturally-occurring CO2 reservoirs are not available.

Large scale field expansion potential for enhanced coal bed methane (ECBM) gas recovery through CO2 and nitrogen gas (N2) injection into coal bed natural gas reservoirs has not yet been demonstrated to be technically and economically feasible. Until more pilot performance testing can be successfully performed and evaluated for large project expansion, enhanced natural gas production potential remains to be realized.

III. Description of Information Requested

We are committed to carrying out the provisions of the EPAct. The diverse enhanced recovery (ER) techniques available for increasing oil and gas recovery from the OCS and onshore Federal lands suggest that a rule providing for a flexible, case-by-case assessment of each ER application for royalty relief would be the most logical approach to take.

The CO2 and other gases or matter injection production incentive aims to promote additional oil and natural gas recovery from mature oil and natural gas fields by providing a royalty suspension volume of up to 5 million barrels of oil equivalent for each eligible lease, the maximum amount authorized under the EPAct. A lease may be eligible if:

  • It is a lease for the production of oil and gas from the OCS or Federal onshore lands;
  • The injection of produced CO2, natural CO2, and other appropriate gases or matter will be used as an enhanced recovery technique on such lease; and
  • The Secretary determines the lease contains oil or gas that would likely not be produced without the royalty reduction provided in the EPAct.

The royalty relief, if authorized under a final rule and approved for an eligible lease, would apply only to production occurring on or after the date of publication of this advance notice of proposed rulemaking. Under Section 354(b)(4) of the EPAct, while relief is retroactive to the date of the advance notice of proposed rulemaking, lessees must pay royalty on production that occurs before publication of a final rule. However, lessees may request a refund of the royalties paid after publication of a final rule. In addition, pursuant to Section 354(b)(5) of the EPAct, royalty relief may be subject to oil and natural gas price threshold provisions or other limitations based on market price.

We are interested in receiving comments regarding incentive provisions that would encourage enhanced recovery techniques to increase oil and gas production from existing fields.

Topics we are considering for the proposed regulations include, but are not limited to, the following:

1. Is there an appropriate Federal role in providing production incentives for Start Printed Page 11559enhanced oil and gas recovery projects or should such decisions be left to market forces?

2. If the Secretary determines that incentives are warranted, does the case-by-case assessment approach for enhanced recovery project evaluation provide the appropriate framework for the intended production incentives?

3. Should existing enhanced oil recovery (EOR) projects be considered to qualify for production royalty relief to promote additional oil recovery as the project nears the end of its economic life? If yes, how?

4. How should the assessment be structured with regard to determining whether royalty relief is needed? Is it reasonable to expect that such assessments can be consistently and reliably completed for a wide variety of projects? If the Secretary determines that relief is warranted, how should the amount of relief be calculated?

5. Should the relief awarded be conditioned on market price? If yes, how?

6. How should the production incentive be applied to the enhanced recovery projects to promote project expansions and maximum oil and gas recoveries?

7. Should this incentive be limited to new technology? Should other gases and matter be considered for EOR royalty relief?

8. How should royalty relief be structured for the additional production resulting from enhanced recovery methods?

9. How should production currently using CO2 for recovery be differentiated from new production which results from an incentive?

10. How could we encourage the capture, transportation, and sequestration of CO2 and promote other public interests in addition to enhanced oil recovery?

11. In making the determination of whether the royalty relief described in Section 354 would be in the public interest, how should the Secretary value the benefit associated with the sequestration of CO2 or other appropriate gases used to increase oil and gas production?

12. How, where, and when in the process should the value of the CO2 (or other gas) or the benefit of its sequestration be measured: at its source or upon its capture, transportation, or sequestration on the lease?

13. Are there recommended methodologies, economic models, or other precedents that the Secretary could consider in assessing the value of sequestration?

14. Can relief be structured to focus on sequestering CO2 that would otherwise be released into the atmosphere or not used for productive purposes?

15. Should this royalty relief take into consideration any existing incentives available for energy production?

16. Are there other issues that should be considered?

Section 354(b)(1) of the EPAct requires that the Secretary determine that royalty reduction is in the public interest and promotes the purposes of the Act. Thus, the Secretary must determine whether the anticipated amount of additional production justifies the level of Federal subsidies that would be provided through such royalty reduction. As a result of comments received in response to this Advance Notice of Proposed Rulemaking, the Secretary may determine that the production royalty incentive provided for by Section 354 of the EPAct is either unnecessary to promote enhanced oil and gas recovery or is insufficient to increase oil and gas production through enhanced recovery. Therefore, the Secretary is not yet prepared to make the determination under Section 354(b)(1) of the EPAct that royalty relief for CO2 injection is in the public interest and promotes the purpose of that section of the Act. However, if BLM and/or MMS adopt a royalty relief rule it would be applicable to any eligible production occurring on or after the publication date of this Advance Notice of Proposed Rulemaking in the Federal Register.

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Dated: February 1, 2006.

Johnnie Burton,

Acting Assistant Secretary of the Interior.

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[FR Doc. 06-2170 Filed 3-7-06; 8:45 am]

BILLING CODE 4310-84-P; 4310-MR-P