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Rule

Oil and Gas and Sulphur Operations in the Outer Continental Shelf-Decommissioning Activities

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Information about this document as published in the Federal Register.

Published Document

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Start Preamble Start Printed Page 35398

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Final rule.

SUMMARY:

This final rule amends MMS regulations governing oil and gas operations in the Outer Continental Shelf (OCS) to update decommissioning requirements. The rule includes requirements for plugging a well, decommissioning a platform and pipeline, and clearing a lease site. We restructured the requirements to make the regulations easier to read and understand. The final rule also updates requirements to reflect changes in technology. The final technical changes will help ensure that lessees and pipeline right-of-way holders conduct decommissioning operations safely and effectively.

EFFECTIVE DATE:

July 16, 2002.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Sharon Buffington, Engineering and Research Branch, at (703) 787-1147.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

On July 7, 2000, we published the proposed rule in the Federal Register (65 FR 41892). During the 90-day comment period, which ended on October 5, 2000, MMS received eight letters of comment from the oil and gas industry, the environmental community, and other government agencies.

Background

In 1996, at the request of MMS, the Marine Board of the National Research Council (NRC) published a report titled “An Assessment of Techniques for Removing Offshore Structures.” On April 15-17, 1996, MMS convened an International Decommissioning Workshop in New Orleans, Louisiana, to discuss the recommendations in the NRC report and current industry decommissioning practices. The workshop drew over 475 attendees to discuss and make recommendations on OCS decommissioning operations. On August 8, 1996, MMS published a notice in the Federal Register (61 FR 41422) that requested comments on its plans to follow up on recommendations received at the workshop.

We also sponsored several other public workshops, including one in Ventura, California, on September 23-25, 1997. The purpose of the workshops was to continue the process of discussing decommissioning activities and to receive recommendations.

Differences Between Proposed and Final Rules

In addition to the changes we made to the final rule in response to comments, MMS reworded certain phrases for further clarity. In many instances, the changes improve MMS's internal work processes. MMS has also added more specific guidance in this final rule concerning items that should be included in decommissioning applications.

Response to Comments

We reviewed all of the comments, and in some instances, we revised the final language based on these comments. MMS grouped the comments by major issues and regulatory sections.

Organization of the Regulation

We received comments from various non-government agencies supporting the new organizational structure of the regulation which locates all of the decommissioning requirements into one subpart. We received no negative comments; therefore, we have kept that structure.

Abandoning Platforms in Place (30 CFR 250.1728)

Comment: MMS received comments from non-profit public interest groups, private citizens and government agencies stating that MMS should not permit oil companies to abandon platforms in place in the Pacific and Alaska OCS Regions.

Response: MMS requires that lessees remove all platforms to at least 15 feet below the mud line. Depending on the situation, MMS may allow an alternate removal depth if the remaining structure would not become a hazard to other users of the seafloor and in other very specific situations as listed in § 250.1728. However, this is not meant to allow large portions of platforms to be abandoned in place. As one commenter suggested, MMS is closely following the research and legislation on artificial reefs. As provided in § 250.1730, MMS may grant a departure from the removal requirements if the structure becomes part of an artificial reef program.

Power Cable Guidance

Comment: A lessee requested that MMS provide guidance on power cables.

Response: Under 30 CFR 250.1700, power cables associated with OCS oil, gas, or sulphur operations may be considered to be obstructions. If they are, the lessee must remove them under §§ 250.1740 through 250.1743.

Site Clearance

Comment: A lessee asked if NTL 98-26 concerning site clearance will be rescinded or revised because the new regulations would discuss site clearance.

Response: We may revise the NTL, as authorized under § 250.103, to provide more detail on trawling consistent with this final rule.

Comment: A government agency recommended that the regulation should specify that the operator must remove drilling piles or shell mounds from the base of the platform if required by the Department of the Interior (DOI).

Response: MMS has defined these items as obstructions in § 250.1700. Sections 250.1740 through 250.1743 require that obstructions be removed.

Comment: An oil industry group asked what the trawling requirements are for unburied pipelines.

Response: We address the relationship of the trawling requirements to unburied pipelines in the regulation at § 250.1741(g). That section prescribes that trawling must be parallel to an unburied pipeline and may not cross the pipeline unless the pipeline is smaller than 8 inches in diameter and has no obstructions present.

Comment: An oil industry representative asked if the Regional Supervisor would be authorized to prescribe variances for site clearance.

Response: Section 1740(c) authorizes variance.

Regulatory Flexibility (RF) Act

Comment: Lessees commented that the costs for trawling operations for temporarily abandoned wells were underestimated for § 250.1722.

Response: We received estimates from trawling organizations that the trawling operation would cost about $2,500 per day, and it may take 1 to 3 days to trawl the site of a temporarily abandoned (TA) well. However, we did not include an estimate for equipment that may be lost or damaged during the operation. Therefore, we may have unintentionally underestimated the cost by using an average cost of $3,000. We have re-verified the costs with trawling organizations and have adjusted the costs upward to an average cost of $9,000 per operation. The trawling organizations noted that the costs for temporary abandonment would be less than the costs of trawling for site clearance because the amount of debris Start Printed Page 35399should be substantially less for a TA well site.

Section 250.1006

Comment: Pipeline companies commented that it is not clear whether § 250.1006 applies to both lease term and right-of-way pipelines.

Response: The requirements apply to both lease term and right-of-way pipelines because DOI has regulatory authority for both. We have added the term “DOI” to the heading to make it clear that we are not referring to pipelines regulated by the Department of Transportation.

Comment: A pipeline company commented that MMS should clarify the requirements for out-of-service pipelines at each timeframe.

Response: We have created a table to clarify the requirements for out-of-service pipelines for 0 to 1 year, more than 1 year, and 5 or more years.

Comment: A pipeline company suggested adding a definition for out-of-service pipelines.

Response: We have added a definition for out-of-service pipelines in § 250.1001.

Comment: A pipeline company commented that 1 year is not enough time to allow before MMS requires a lessee to flush and fill a line with seawater when the line is out of service. Also, 5 years is too much time before requiring total decommissioning.

Response: We have retained the 1-year and 5-year requirements. MMS is doing research on flushing out-of-service pipelines and may address this in the future.

Section 250.1700

Comment: A government agency commented that MMS should expand the definition of obstacles to include marine growth such as shell mounds, and debris from oil, gas, or sulphur operations left in vessel traffic lanes.

Response: We have added marine growth to the definition of obstructions. Obstructions already include all debris from oil, gas, or sulphur operations, which is practical to remove from the area to be trawled.

Comment: A lessee commented that MMS should remove “(in the Pacific OCS Region)” from the definition because the Gulf OCS Region has power cables.

Response: We agree. MMS may require power cables to be removed if they are part of OCS oil, gas, or sulphur operations.

Section 250.1702

Comment: A lessee commented that MMS should add a qualifier that the sales contracts between operating partners may excuse the new lessee from accruing decommissioning obligations.

Response: All transferees of title or operating rights will continue to accrue the decommissioning obligations. Assignors and assignees may provide in their contract for allocation of responsibilities, but the Government should not be restricted from seeking performance by any of the parties by terms of a private agreement. This position has not changed.

Section 250.1703

Comment: A government agency commented that MMS should include a diligence requirement to prevent operators from indefinitely delaying proper decommissioning. As a mechanism, the commenter suggested that MMS review production to determine if the operator is entitled to continue operations based on economics.

Response: MMS does require lessees to prove that leases are still capable of production in paying quantities under 30 CFR 250.180 and that wells and other facilities are still needed for lease operations. Also see §§ 250.1710 and 250.1711 for timely well plugging requirements.

Section 250.1704

Comment: A lessee questioned how the MMS could expect to receive a platform removal application for the Pacific OCS Region and Alaska OCS Region at least 2 years before production ceases.

Response: Planning ahead is the key to a successful decommissioning operation, particularly given the size of the facilities to be removed in the Pacific OCS Region. Removal events are planned and contracted for several years in advance. The platforms that will be removed in the Pacific OCS Region will be the largest platforms located in the deepest water to date. According to a research project that MMS contracted for the Pacific OCS Region titled the “State of the Art of Removing Large Platforms Located in Deep Water,” some of the removal equipment will be brought in from the North Sea at great expense, and it will take a considerable amount of planning and time.

Comment: A lessee commented that MMS should include a requirement to make the final platform removal application due 2 years after the deadline for the initial platform removal application (in the Pacific OCS Region and Alaska OCS Region).

Response: We have included this recommendation in § 250.1704(b).

Comment: A lessee commented that MMS should replace the provision for submitting decommissioning applications in (a) “at least 2 years before production is projected to cease” with “at least 1 year before production is projected to cease.”

Response: We have maintained the requirement for submitting the application 2 years in advance because of the complexity of the platform removals. If we find that we no longer need 2 years notice, we will revisit this regulation. However, we have adopted the recommendation to add the language “before production is projected to cease” to the requirement.

Section 250.1711 (Proposed section 250.1707)

Comment: An oil industry organization recommended that MMS change (b) to “If the well is the last producing well on a lease, and not useful for further operations and is not capable of profitable oil, gas, or sulphur production.” This would eliminate abandonment of wells for a producing lease, field, or platform.

Response: We disagree. It is MMS's responsibility to ensure that wells are properly plugged as soon as it is determined that they are no longer needed for operations. We do not see any benefit to keeping an unnecessary well unplugged.

Comment: We received a comment from a government agency asking how we know when a well is not capable of producing in paying quantities.

Response: Some of the information that we may request with form MMS-124 includes recent well tests, remaining recoverable reserves, production data, pressure data, and economic analysis. This information would help us determine if a well is capable of producing in paying quantities.

Section 250.1712 (Proposed section 250.1709)

Comment: An oil industry organization recommended that in proposed § 250.1709(a)(2), MMS should only require submission of “available” recent well test data and pressure data because the data may not be available at the time of the submittal of form MMS-124.

Response: We agree, and we have revised the final rule at § 250.1712(b).

Comment: An oil industry organization recommended that MMS change proposed § 250.1709(a)(6)(ii) from “All perforated intervals” to “All perforated intervals that have not been plugged.” This eliminates the need to re-submit any details regarding other Start Printed Page 35400intervals in the well that were previously abandoned with the appropriate approvals.

Response: We agree, and we have made the change at § 250.1712(f)(2).

Section 250.1715 (Proposed section 250.1710)

Comment: An oil industry organization recommended that MMS delete proposed paragraph § 250.1710(h) concerning cement displacement plugs because it is addressed in paragraph (k) for testing of plugs placed by displacement, it is not common practice and is expensive ($20,000).

Response: We agree, and we have made the change and renumbered the paragraphs. See § 250.1715(b) in this final rule.

Comment: An oil industry organization recommended that MMS change “plugs” to “plug(s)” as applicable to cover both where it would be one plug and where there may be more than one anticipated.

Response: We agree, and we have done so in appropriate places in the rule.

Comment: An oil industry organization recommended that MMS remove the word “permanent” before bridge plugs in proposed § 250.1710(d)(2), because other references to bridge plugs do not specify the type of bridge plug.

Response: We agree, and we have deleted this limitation to a specific type of bridge plug.

Comment: An oil industry organization recommended that MMS change proposed § 250.1710(i) to “Cement plugs designed to set before freezing and have a low heat of hydration” for clarity.

Response: We agree, and we have made the change.

Section 250.1716 (Proposed section 250.1712 and section 250.1713)

Comments: A county government organization recommended that this section should specify that the operators should not leave the wellheads and casing above the mud line.

Response: MMS will only allow a lessee an alternate removal depth when the object would not become a hazard, the water depth is greater than 800 meters, or other very specific situations. We believe that this is a reasonable requirement. A 1996 report from the NRC titled, “An Assessment of Techniques for Removing Structures,” recommends that regulations governing removals need to be sufficiently flexible to accommodate the complex requirements of a wide variety of structures, a spectrum of marine life, and various users. MMS will analyze the requests for alternate removal depth carefully and case-by-case.

Comment: A lessee noted that it is not clear how to determine and/or prove that a particular obstruction constitutes a hazard.

Response: In determining whether an obstruction constitutes a hazard, consider whether the area would not be used by others (fishing community, military, etc.) and whether geotechnical information demonstrates that erosional processes will not expose the object to create obstructions.

Comment: A lessee recommended that MMS use 1,000 feet or more instead of 800 meters (2,624 feet) as the depth for departure from the requirement to remove all wellheads and casings to at least 15 feet below the mud line, in paragraph (a).

Response: Allowing an alternate removal requirement for all wellheads and casings in water depths 1,000 feet or more may not provide adequate protection against the wellhead becoming an obstruction. However, applications for removal in water depths less than 800 meters (2,624 feet) will be evaluated case-by-case. We also request concurrence from the Department of the Navy on these types of proposals.

Comment: An oil industry organization recommended that MMS add language to allow an alternative removal depth if “seafloor sediment stability poses safety concerns,” because when using divers, mudline requirements can be difficult to meet in areas with soft sediments, and cave-ins have led to diver injuries.

Response: We agree that there may be cases when seafloor sediment stability poses safety concerns if divers are used; however, we would only approve an alternative removal depth if you determine, and MMS concurs, that you must use divers, and seafloor sediment stability poses safety concerns. You must have determined that no other removal method is possible. We have made this change in the regulations.

Section 250.1721 (Proposed section 250.1711)

Comment: An oil industry organization recommended that MMS change the wording in proposed § 250.1711(c) to “Set a retrievable or permanent-type bridge plug or a cement plug at least 100-feet long in the inner-most casing. The top of the bridge plug or cement plug must be no greater than 1,000 feet below the mud line. MMS may consider approving alternate requirements for sub-sea wells case-by-case.” Shallow plugs on wells intended for re-entry can be dangerous.

Response: We agree and have added § 250.1721(d).

Comment: A lessee commented that MMS should require a subsea dome cover only when the water is less than 200 feet.

Response: We disagree because damage can occur to fishing nets in depths between 200 and 300 feet. Therefore, we have specified in § 250.1721(f) that subsea domes are not required in water depths greater than 300 feet.

Comment: An oil industry organization recommended that MMS should allow subsea domes in proposed § 250.1711(g)(3) that extend more than 10 feet above the seafloor case-by-case due to different well conditions that may exist. The 10-foot requirement seems an arbitrary figure, with no engineering or maritime justification. In fact, the current installations are greater than 10 feet above the seafloor.

Response: We have added flexibility in § 250.1722(b) for allowing subsea domes that extend beyond 10 feet when approved. However, the higher the dome, the more difficult it will be for lessees to add a net guard and to have the trawling completed. We have also clarified that corrective action must be taken if the dome is not effective.

Comment: A lessee commented that MMS should rescind NTL 98-19 and use § 250.1720.

Response: The NTL is designed to give more specific guidance on satisfying the performance-based requirement. We plan to revise it to compliment the new regulation.

Comment: A lessee commented that MMS should add more flexibility to the new requirement for trawling over temporarily abandoned well domes.

Response: We agree. In § 250.1722(h), MMS has added that we may issue a departure for the trawling test if the lessee marks the subsea protective covering with an automatic daily tracking buoy or uses a design and installation method that has been proven with similar bottom conditions.

Section 250.1725 (Proposed section 250.1718)

Comment: A lessee commented that in proposed § 250.1718(a) MMS should include a requirement for considering whether removal and placement in a previously designated artificial reef site is more appropriate, and to allow time to make this determination.

Response: MMS is not the agency to determine if placement in an artificial reef site is more appropriate. However, if time is needed to make this determination, it may be obtained under § 250.1725(a). Start Printed Page 35401

Comment: An oil industry organization recommended that MMS add language to allow abandonment in place of subsea equipment in greater than 1,000 feet of water because they pose no hazard or obstruction. This has also been approved in DWOP submittals by MMS.

Response: MMS may approve such a request on a case-by-case basis only. However, blanket approval will not be given.

Comment: An oil industry organization recommended that MMS amend the rule to provide a waiver to defer platform removal as part of a joint industry program to remove multiple platforms or facilities. A joint industry program to remove multiple platforms (e.g. SWARS program in the Pacific OCS Region) may require that platforms remain for longer than 1 year after lease termination. This may also be the preferred alternative due to lower environmental impacts.

Response: Under 30 CFR 250.141, MMS can grant departures from regulations or lease stipulations or approve alternative compliance measures for sufficient cause.

Section 250.1727 (Proposed section 250.1719)

Comment: A commenter recommended that MMS require that unburied pipelines that may become an obstruction be removed.

Response: Removal is required under § 250.1754 because lessees and pipeline right-of-way holders may only decommission pipelines in place if they will not become a hazard.

Comment: A lessee asked what constitutes an active pipeline. Also NTL 98-26 lists requirements for unburied lines. The lessee recommended that we put these requirements in this rule.

Response: Active pipelines are those not out of service or decommissioned. We have put a definition for pipelines taken out of service at § 250.1001 and included the requirements for unburied pipelines in § 250.1741(g).

Comment: An oil industry organization recommended that MMS add “if applicable” before the list of information to include in the platform removal application.

Response: We agree, and we have made the change.

Comment: A commenter recommended that MMS include the requirements of the removal for subsea equipment.

Response: Subsea equipment removals are handled case-by-case by the MMS District offices. Too many variables exist to specify the requirements in the regulations. However, lessees can assume that equipment must be removed unless the requirements of §§ 250.1725 through 250.1728 are met.

Section 250.1728 (Proposed section 250.1720 and section 250.1721)

Comment: A commenter argued that subsea equipment in water depths greater than 1,000 feet should be allowed to remain on the seafloor as long as it is cleaned and flushed of all hydrocarbons.

Response: MMS believes that § 250.1728 is flexible enough to accommodate this request if the equipment is not an obstruction. However, lessees must still seek approval from the Regional Supervisor. MMS coordinates with the Department of the Navy on these requests, and we keep a list of all objects remaining above the mud line. Also, MMS does not have the authority to allow leaving a partial platform in place. If the platform is not officially converted into an artificial reef, it requires an ocean dumping permit from the Environmental Protection Agency (EPA). MMS believes that wellheads and casing are not part of the platform, and the decision to leave these types of structures in place is similar to abandoning pipelines in place, and does not require an EPA permit.

Comment: Specify the 800-meter water depth in feet also.

Response: MMS will state the water depth both as 800 meters and 2,624 feet throughout the regulation.

Section 250.1730 (Proposed section 250.1723)

Comment: A commenter suggested that a minimum unobstructed water column depth of 300 feet be given as acceptable for marine navigation regarding partial structure removals.

Response: MMS does not have the authority to set specific limitations on partial structure removals because the limitations will be determined by other agencies.

Comment: A commenter suggested that instead of requiring that an unobstructed water column be above the structure, MMS should require that lessees satisfy U.S. Coast Guard (USCG) navigational requirements for the remaining structure.

Response: We agree, and we have changed (b) accordingly. We have also made a change in (a) from the National Artificial Reef Program to the State's artificial reef plan for accuracy.

Section 250.1740 (Proposed section 250.1714)

Comment: An oil industry organization recommended that MMS reduce the required water depth for trawling to 200 feet.

Response: We did not make this change in the final rule because we are also anticipating future fishing and military uses with our requirements because the obstructions would be there for a very long time. We also have determined this criteria in consultation with a representative group of interested parties; therefore, we have not made this change.

Section 250.1741 (Proposed section 250.1714 and section 250.1717)

In § 250.1741, we have clarified that sensitive biological features must be protected by not trawling closer than 500 feet. This is a current requirement.

Comment: An oil industry organization recommended that MMS limit the requirement for trawling around wells to less than a 200-foot water depth and use a 200-foot radius centered on an exploration or delineation well.

Response: We are maintaining the requirement for 300 feet for both water depth and radius because 200 feet would not protect other users of the OCS. We have determined these requirements in consultation with a representative group of interested parties who are anticipating future needs.

Section 250.1742 (Proposed section 250.1715)

Comment: An oil industry organization recommended that MMS add the flexibility to use diver or remotely operated vehicle (ROV) inspections and video documentation. Many drilling rigs are now equipped with an ROV, which provides for an efficient, reliable inspection of the well site before rig departure.

Response: We agree, and we have made the change.

Section 250.1741 (Proposed section 250.1717)

Comment: A commenter recommended that the lessee should send the clearance report that is required in proposed § 250.1717(g) to MMS, along with the completion report to ensure that all the right paperwork is submitted to MMS on time. Paragraph (g)(6) should be combined with (g).

Response: We agree and have changed the final rule accordingly. Start Printed Page 35402

Proposed Section 250.1722

Comments: A private citizen, a non-profit public interest group, and a government agency suggested that MMS should not state its policy on artificial reefs, since it does not manage the program, and it is controversial in California. Also, paragraph (c) needs to allow for the operator, not the State, to retain liability for the structure if left as an artificial reef. Another commenter said that paragraph (c) unilaterally requires the State agency to take responsibility for the platforms, in perpetuity. Also, another commenter mentioned that an area previously designated as an artificial reef should be considered the number one option for a reef proposal.

Response: MMS deleted proposed § 250.1722 because it is unnecessary to the regulation.

Comment: A commenter said that the rule should address other uses, such as mariculture and research for decommissioned platforms.

Response: Having agreed to delete proposed § 250.1722, there is no need for the suggested change.

Section 250.1750 (Proposed section 250.1724)

Comment: A commenter argued that this paragraph needs to specify that pipelines may be left in place only when they are buried.

Response: If the unburied pipeline is an obstruction, it may not be left in place. This is now covered in § 250.1754.

Section 250.1754 (Proposed section 250.1725)

Comment: A commenter suggested that the rule define the term “hazard.”

Response: We have changed the term “hazard” to “obstruction” because “obstruction” is defined in the regulation. We have also moved the requirement to remove a pipeline that subsequently becomes a hazard (proposed § 250.1725(i)) to § 250.1754 for emphasis and clarity.

Procedural Matters

Regulatory Planning and Review (Executive Order 12866)

This document is not a significant rule and is not subject to review by the Office of Management and Budget (OMB) under Executive Order 12866.

(1) This rule will not have an effect of $100 million or more on the economy. It will not adversely affect in a material way the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities. The new or expanded requirements are written in plain language and designed to ensure that lessees decommission facilities to protect the environment and minimize obstructions to other uses of the OCS. The economic effects of this rule will be minimal. Lessees planning decommissioning activities in the Pacific OCS Region and Alaska OCS Region would be required to plan these activities at least 2 years before production ceases and submit an initial decommissioning application. This will impact an estimated two lessees a year, as shown in Table 1. The cost to develop an initial decommissioning application is estimated at $1,000 per application.

Table 1.—New Reporting Cost for the Initial Decommissioning Application Submitted in the Pacific and Alaska OCS Regions

Yearly
Cost @ $1,000 per applicationLessees affectedApplications submitted
Small Businesses$1,00011
Other Lessees1,00011
Totals2,00022

Table 2.—New Requirement Cost for Trawling

First yearSubsequent years
Total cost @ $9000 per trawlLessees affectedDomes trawledTotal cost @ $9000 per TrawlLessees affectedDomes trawled
Small Businesses$180,0002020$27,00033
Other Lessees225,000102518,00022
Totals405,000304545,00055

Table 3.—Total Costs for Both the New Plan and New Trawling Requirement

First yearSubsequent years
Total costLessees affectedDomes trawled + plans submittedTotal costLessees affectedDomes trawled + plans submitted
Small Businesses$181,0002121$28,00044
Other Lessees226,000112619,00033
Totals407,000324747,00077
Start Printed Page 35403

Also, lessees who use domes to protect temporarily abandoned wells would be required to trawl over those domes after they install them. We estimate the cost for trawling would be $9,000 for each of the 45 existing domes and $9,000 to trawl each of the 10 additional domes installed each year. We estimate that 30 lessees will be required to trawl the 45 existing domes, and 5 lessees will trawl the additional 10 domes each subsequent year as shown in Table 2. The total costs are shown in Table 3.

(2) This rule will not create a serious inconsistency or otherwise interfere with an action taken or planned by another agency. The new or expanded requirements are minimal and apply only to the OCS decommissioning activities.

(3) This rule does not significantly alter the budgetary effects or entitlements, grants, user fees, or loan programs or the rights or obligations of their recipients. The new requirements and costs are minimal, and the main purpose of the rule is to write it in plain language.

(4) This rule does not raise novel legal or policy issues. The new requirements are based on the legal authority of the OCS Lands Act and other laws.

Regulatory Flexibility (RF) Act

The Department certifies that this proposed rule will not have a significant economic effect on a substantial number of small entities under the RF Act (5 U.S.C. 601 et seq.). The changes proposed in 30 CFR 250, subpart Q, will not have a significant economic effect on offshore lessees and operators, including those that are classified as small businesses. The Small Business Administration (SBA) defines a small business as having:

  • Annual revenues of $5 million or less for exploration service and field service companies.
  • Fewer than 500 employees for drilling companies and for companies that extract oil, gas, or natural gas liquids.

Under the SBA's North American Industry Classification System code 211111, Crude Petroleum and Natural Gas Extraction, MMS estimates that there is a total of 1,380 firms that drill oil and gas wells onshore and offshore. Of these, approximately 130 companies are offshore lessees/operators, based on current estimates. According to SBA estimates, 39 companies qualify as large firms, leaving 91 companies qualified as small firms with fewer than 500 employees.

Where there are some additional new or expanded reporting requirements in this rule, they do not impose extensive burdens. The cost to comply with the new requirements is a one-time cost of approximately $9,000 paid to a trawling organization to trawl over domes of temporarily abandoned wells in shallow water. The OCS has approximately 45 of these domes. In subsequent years, we predict that 10 new domes will be trawled over. We estimate that 20 of the 30 lessees that will trawl over the 45 existing domes are small businesses and 3 out of the 5 lessees that will trawl over domes in subsequent years will be small businesses. The cost to the small businesses will be $180,000 the first year and $27,000 each subsequent year, as shown in Table 2 (in the Regulatory Planning and Review section). However, the trawling industry, another small business, will benefit by having less loss to their equipment.

Also, about two lessees per year in the Pacific OCS Region or Alaska OCS Region will need to submit an initial decommissioning plan for a cost of approximately $1,000 to develop each application as shown in Table 1 (in the Regulatory Planning and Review section).

We estimate that one of these lessees will be a small business. These plans are necessary to ensure that early planning is occurring for these upcoming decommissioning activities.

Based on these calculations, this rule has no significant economic impact on small entities.

Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small businesses. If you wish to comment on the enforcement actions of MMS, call toll-free (888) 734-3247.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

This rule is not a major rule under the SBREFA (5 U.S.C. 804(2)). This rule:

(a) Does not have an annual effect on the economy of $100 million or more. The main purpose of this rule is to reorganize the requirements and write them in plain language. The new requirements will cost lessees $407,000 for the first year and $47,000 in subsequent years and only a few lessees will be affected.

(b) Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. The cost to comply with the new requirements is minor and will minimize conflicts with other uses of the OCS.

(c) Does not have a significant adverse effect on competition, employment, investment, productivity, innovation, or ability of U.S.-based enterprises to compete with foreign-based enterprises. The regulation contains a few new requirements that are not burdensome and ensure that decommissioning operations in the OCS are conducted properly.

Paperwork Reduction Act (PRA) of 1995

We examined the proposed rule and these final regulations under section 3507(d) of the PRA. As part of the proposed rulemaking process, we submitted the information collection requirements in the entire proposed subpart Q to OMB for approval. The final regulations do contain minor changes in the collection of information from what was proposed. Therefore, before publication, we again submitted the subpart Q information collection to OMB, and OMB approved them under OMB control number 1010-0142, with a current expiration date of July 31, 2004. An agency may not collect or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.

The title of the collection of information for this final rule is “30 CFR 250, Subpart Q—Decommissioning Activities.” Respondents include approximately 130 Federal OCS oil and gas or sulphur lessees and 106 holders of pipeline rights-of-way. The frequency of response is on occasion or annually, depending upon the requirement. Responses to this collection of information are mandatory. MMS will protect proprietary information according to the Freedom of Information Act and 30 CFR 250.196, “Data and information to be made available to the public.”

This rulemaking primarily consolidates information collection requirements on decommissioning from our current regulations in 30 CFR 250, subparts G, I, and J (approved under OMB control numbers 1010-0079, 1010-0058, and 1010-0050, respectively). The approved burdens for those subparts will be correspondingly reduced when the new subpart Q regulations take effect. The proposed rulemaking imposed only one new information collection burden. Section 250.1726 (proposed § 250.1705) requires submission of an initial decommissioning application in the Pacific OCS Region and Alaska OCS Start Printed Page 35404Region, which we estimate will require 20 burden hours per application.

Most of the section numbers in the final regulations have changed from the proposed rule, and information collection requirements are now in different sections. The final regulations also are more specific with respect to several reporting requirements. These new burdens were included in the subsequent information collection submission that OMB approved.

We estimate the total annual reporting “hour” burden for the final rule to be 6,071 hours. There are no recordkeeping requirements. There are no paperwork “non-hour cost” burdens associated with these regulations. Following is a breakdown of the hour burden estimate.

Burden Breakdown

Citation 30 CFR 250 subpart QReporting requirementBurdenAverage number per yearAnnual burden hours
1703; 1704Request approval for decommissioningBurden included below0
1704(f); 1712; 1716; 1717; 1721(a), (f), (g); 1722(a),(b), (d); 1723(b); 1743(a)Submit form MMS-124 to plug wells; provide subsequent report; request alternate depth departure; request procedure to protect obstructions above seafloor; report results of trawling; certify area cleared of obstructions; remove casing stub or mud line suspension equipment and subsea protective covering; or other departures.Burden included under 1010-0045.0
1713 (Final New)Notify MMS 48 hours before beginning operations to permanently plug a well15 minutes100 notices25
1721(e); 1722(e), (h)(1); 1741(c)Identify and report subsea wellheads, casing stubs, or other obstructions; mark wells protected by a dome; mark location to be cleared as navigation hazardU.S. Coast Guard requirement.0
1722(c), (g)(2) (Final New)Notify MMS within 5 days if trawl does not pass over protective device or causes damages to it; or if inspection reveals casing stub or mud line suspension is no longer protected15 minutes10 notices3
1722(f), (g)(3)Submit annual report on plans for re-entry to complete or permanently abandon the well and inspection report.2 hours75 reports150
1722(h) (Final New)Request waiver of trawling test2 hours2 requests4
1704(a); 1726 (Proposed New)Submit initial decommissioning application in Pacific OCS and Alaska OCS Regions20 hours2 applications40
1704(b); 1725; 1727; 1728; 1730Submit final application to remove platform or other subsea facility structures (including alternate depth departure) or approval to maintain, to conduct other operations, or to convert to artificial reef8 hours124 applications992
1725(e) (Final New)Notify MMS 48 hours before beginning removal of platform and other facilities15 minutes124 notices31
1704(c); 1729 (Final New)Submit post platform or other facility removal report2 hours124 reports248
1740(b)(5), (c)(3); 1740(g)(1); 1743(b)Request approval of well site, platform, or other facility clearance method; including contacting pipeline owner or operator4 hours125 requests500
1743(b)Verify permanently plugged well, platform, or other facility removal site cleared of obstructions and submit certification letter12 hours124 verifications1,488
1704(d); 1751; 1752Submit application to decommission pipeline in place or remove pipeline8 hours257 applications2,056
1753 (Final New)Submit post pipeline decommissioning report2 hours257 reports514
1700 through 1754General departure and alternative compliance requests not specifically covered elsewhere in subpart Q regulations2 hours10 requests20
Total Reporting1,3346,071

Federalism (Executive Order 13132)

According to Executive Order 13132, this rule does not have Federalism implications. This rule does not substantially and directly affect the relationship between the Federal and State governments. The final rule revises existing operation regulations. It does not prevent any lessee, operator, or drilling contractor from performing operations on the OCS, provided they follow the regulations. This rule is updating decommissioning requirements and will not impose costs on States or localities.

Takings Implication Assessment (Executive Order 12630)

According to Executive Order 12630, the final rule does not represent a governmental action capable of interference with constitutionally protected property rights. The new requirements are minor and deal with minimizing obstructions to other uses of the OCS. Thus, a Takings Implication Assessment need not be prepared according to Executive Order 12630, Government Action and Interference with Constitutionally Protected Property Rights.

Energy Supply, Distribution, or Use (Executive Order 13211)

This rule is not a significant rule and is not subject to review by OMB under Executive Order 13211. The rule does not have a significant effect on energy supply, distribution, or use because it will not reduce crude oil supply or production. It also will not increase energy prices or increase dependence on foreign supplies. The new or expanded requirements are written in plain language and designed to ensure that lessees decommission facilities to protect the environment and minimize Start Printed Page 35405obstructions to other uses of the OCS. The economic effects of this rule will be minimal.

Civil Justice Reform (Executive Order 12988)

According to Executive Order 12988, the Office of the Solicitor has determined that this rule does not unduly burden the judicial system and meets the requirements of §§ 3(a) and 3(b)(2) of the Order.

Unfunded Mandate Reform Act (UMRA) of 1995 (Executive Order 12866)

This rule does not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. This rule was mainly updated to include plain language and to give additional guidance. It contains very few new requirements, and it will not have a significant or unique effect on State, local, or tribal governments or the private sector. Therefore, a statement containing the information required by the UMRA (2 U.S.C. 1531 et seq.) is not required.

National Environmental Policy Act (NEPA) of 1969

This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the NEPA is not required.

Start List of Subjects

List of Subjects

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Dated: April 23, 2002.

Rebecca W. Watson,

Assistant Secretary, Land and Minerals Management.

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For the reasons stated in the preamble, the Minerals Management Service (MMS) amends

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PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF

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1. The authority citation for part 250 continues to read as follows:

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Authority: 43 U.S.C. 1331, et seq.

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What does this part do?
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2. In § 250.102, the following changes are made:

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a. In § 250.102, in the table in paragraph (b), line (1) is removed.

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b. Lines 2 through 13 are redesignated lines 1 through 12 respectively.

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c. A new line 13 is added to read as follows:

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Table.—Where To Find Information for Conducting Operations

For information about—Refer to—
*    *    *    *    *
(13) Permanently plugging wells§ 250.1710
*    *    *    *    *
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3. In § 250.199, the following changes are made:

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a. In the table in paragraph (e), entry (7) is removed.

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b. Entries (8) through (16) are renumbered (7) through (15).

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c. A new entry (16) is added to read as follows:

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30 CFR 250 subpart/title (OMB control No.)Reasons for collecting information and how used
*         *         *         *         *         *         *
(16) Subpart Q, Decommissioning Activities (1010-0142)To determine that decommissioning activities comply with regulatory requirements and approvals. To ensure that site clearance and platform or pipeline removal are properly performed to protect marine life and the environment and do not conflict with other users of the OCS.
*         *         *         *         *         *         *

Subpart G—[Removed and Reserved]

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4. Subpart G ( §§ 250.700-250.704) is removed and reserved.

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Subpart I—Platforms and Structures

[Removed]
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5. Section 250.913 is removed.

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Subpart J—Pipelines and Pipeline Rights-of-Way

6. In § 250.1001, the following definition is added in alphabetical order:

Definitions.
* * * * *

Out-of-service pipelines are those pipelines that have not been used to transport oil, natural gas, sulfur, or produced water for more than 30 consecutive days.

* * * * *
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7. Section 250.1006 is revised to read as follows:

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How must I decommission and take out of service a DOI pipeline?

(a) The requirements for decommissioning pipelines are listed in § 250.1750 through § 250.1754.

(b) The table in this section lists the requirements if you take a DOI pipeline out of service:

If you have the pipeline out of service for:Then you must:
(1) 1 year or lessIsolate the pipeline with a blind flange or a closed block valve at each end of the pipeline.
(2) More than 1 year but less than 5 yearsFlush and fill the pipeline with inhibited seawater.
(3) 5 or more yearsDecommission the pipeline according to §§ 250.1750-250.1754.
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[Amended]
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8. In § 250.1007 paragraph (c) is removed.

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9. In § 250.1014, the second sentence is revised to read as follows:

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Relinquishment of a right-of-way grant.

* * * It must contain those items addressed in §§ 250.1751 and 250.1752 of this part. * * *

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10. Subpart Q is added to read as follows:

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Subpart Q—Decommissioning Activities

General

250.1700 250.1701 250.1702 250.1703 250.1704

Permanently Plugging Wells

250.1710 250.1711 250.1712 250.1713 250.1714 250.1715 250.1716 250.1717

Temporarily Plugging Wells

250.1721 250.1722 250.1723

Removing Platforms and Other Facilities

250.1725 250.1726 250.1727 250.1728 250.1729 250.1730

Site Clearance for Wells, Platforms, and Other Facilities

250.1740 250.1741 250.1742 250.1743

Pipeline Decommissioning

250.1750 250.1751 250.1752 250.1753 250.1754 Start Authority

Authority: 43 U.S.C. 1331 et seq.

End Authority

Subpart Q—Decommissioning Activities

General

What do the terms “decommissioning”, “obstructions”, and “facility” mean?

(a) Decommissioning means:

(1) Ending oil, gas, or sulphur operations; and

(2) Returning the lease or pipeline right-of-way to a condition that meets the requirements of regulations of MMS and other agencies that have jurisdiction over decommissioning activities.

(b) Obstructions means structures, equipment, or objects that were used in oil, gas, or sulphur operations or marine growth that, if left in place, would hinder other users of the OCS. Obstructions may include, but are not limited to, shell mounds, wellheads, casing stubs, mud line suspensions, well protection devices, subsea trees, jumper assemblies, umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline valves, and power cables.

(c) Facility means any installation other than a pipeline used for oil, gas, or sulphur activities that is permanently or temporarily attached to the seabed on the OCS. Facilities include production and pipeline risers, templates and pilings, and any other facility or equipment that constitutes an obstruction such as jumper assemblies, termination skids, umbilicals, anchors, and mooring lines.

Who must meet the decommissioning obligations in this subpart?

(a) Lessees and owners of operating rights are jointly and severally responsible for meeting decommissioning obligations for facilities on leases, including the obligations related to lease-term pipelines, as the obligations accrue and until each obligation is met.

(b) All holders of a right-of-way are jointly and severally liable for meeting decommissioning obligations for facilities on their right-of-way, including right-of-way pipelines, as the obligations accrue and until each obligation is met.

(c) In this subpart, the terms “you” or “I” refer to lessees and owners of operating rights, as to facilities installed under the authority of a lease, and to right-of-way holders as to facilities installed under the authority of a right-of-way.Start Printed Page 35407

When do I accrue decommissioning obligations?

You accrue decommissioning obligations when you do any of the following:

(a) Drill a well;

(b) Install a platform, pipeline, or other facility;

(c) Create an obstruction to other users of the OCS;

(d) Are or become a lessee or the owner of operating rights of a lease on which there is a well that has not been permanently plugged according to this subpart, a platform, a lease term pipeline, or other facility, or an obstruction;

(e) Are or become the holder of a pipeline right-of-way on which there is a pipeline, platform, or other facility, or an obstruction; or

(f) Re-enter a well that was previously plugged according to this subpart.

What are the general requirements for decommissioning?

When your facilities are no longer useful for operations, you must:

(a) Get approval from the appropriate District Supervisor before decommissioning wells and from the Regional Supervisor before decommissioning platforms and pipelines or other facilities;

(b) Permanently plug all wells;

(c) Remove all platforms and other facilities;

(d) Decommission all pipelines;

(e) Clear the seafloor of all obstructions created by your lease and pipeline right-of-way operations; and

(f) Conduct all decommissioning activities in a manner that is safe, does not unreasonably interfere with other uses of the OCS, and does not cause undue or serious harm or damage to the human, marine, or coastal environment.

When must I submit decommissioning applications and reports?

You must submit decommissioning applications and receive approval and submit subsequent reports according to the table in this section.

Decommissioning Applications and Reports Table

Decommissioning applicationsWhen to submitInstructions
(a) Initial platform removal application [not required in the Gulf of Mexico OCS Region]In the Pacific OCS Region or Alaska OCS Region, submit the application to the Regional Supervisor at least 2 years before production is projected to ceaseInclude information required under § 250.1726.
(b) Final removal application for a platform or other facilityBefore removing a platform or other facility in the Gulf of Mexico OCS Region, or not more than 2 years after facility the submittal of an initial platform removal application to the Pacific OCS Region and the Alaska OCS RegionInclude information required under § 250.1727.
(c) Post-removal report for a platform or other facilityWithin 30 days after you remove a platform or other facilityInclude information required under § 250.1729.
(d) Pipeline decommissioning applicationBefore you decommission a pipelineInclude information required under § 250.1751(a) or § 250.1752(a), as applicable.
(e) Post-pipeline decommissioning reportWithin 30 days after you decommission a pipelineInclude information required under § 250.1753.
(f) Form MMS-124, Sundry Notices and Reports on Wells(1) Before you plug a wellInclude information required under § 250.1712.
(2) Within 30 days after you plug a wellInclude information required under § 250.1717.
(3) Within 30 days after you complete siteclearance activitiesInclude information required under § 250.1743(b).

Permanently Plugging Wells

When must I permanently plug all wells on a lease?

You must permanently plug all wells on a lease within 1 year after the lease terminates.

When will MMS order me to permanently plug a well?

MMS will order you to permanently plug a well if that well:

(a) Poses a hazard to safety or the environment; or

(b) Is not useful for lease operations and is not capable of oil, gas, or sulphur production in paying quantities.

What information must I submit before I permanently plug a well or zone?

Before you permanently plug a well or zone, you must submit form MMS-124, Sundry Notices and Reports on Wells, and receive approval. A request for approval must contain the following information:

(a) The reason you are plugging the well (or zone), for completions with production amounts specified by the Regional Supervisor, along with substantiating information demonstrating its lack of capacity for further profitable production of oil, gas, or sulfur;

(b) Recent well test data and pressure data, if available;

(c) Maximum possible surface pressure, and how it was determined;

(d) Type and weight of well-control fluid you will use;

(e) A description of the work (including any measures proposed to protect archaeological or biological bottom features from anchor damage); and

(f) A current and proposed well schematic and description that includes:

(1) Well depth;

(2) All perforated intervals that have not been plugged;

(3) Casing and tubing depths and details;

(4) Subsurface equipment;

(5) Estimated tops of cement (and the basis of the estimate) in each casing annulus;

(6) Plug locations;

(7) Plug types;

(8) Plug lengths;

(9) Properties of mud and cement to be used;

(10) Perforating and casing cutting plans;

(11) Plug testing plans;

(12) Casing removal (including information on explosives, if used);

(13) Proposed casing removal depth; and

(14) Your plans to protect archaeological and sensitive biological features during plugging operations, including a brief assessment of the environmental impacts of the plugging operations and the procedures and Start Printed Page 35408mitigation measures you will take to minimize such impacts.

Must I notify MMS before I begin well plugging operations?

You must notify the appropriate District Supervisor at least 48 hours before beginning operations to permanently plug a well.

What must I accomplish with well plugs?

You must ensure that all well plugs:

(a) Provide downhole isolation of hydrocarbon and sulphur zones;

(b) Protect freshwater aquifers; and

(c) Prevent migration of formation fluids within the wellbore or to the seafloor.

How must I permanently plug a well?

(a) You must permanently plug wells according to the table in this section. The District Supervisor may require additional well plugs as necessary.

Permanent Well Plugging Requirements

If you have—Then you must use—
(1) Zones in open holeCement plug(s) from at least 100 feet below the bottom to 100 feet above the top of oil, gas, and fresh-water zones to isolate fluids in the strata.
(2) Open hole below casing(i) A cement plug set by the displacement method, at least 100 feet above and below deepest casing shoe; (ii) A cement retainer with effective back-pressure control set 50 to 100 feet above the casing shoe, and a cement plug that extends at least 100 feet below the casing shoe and at least 50 feet above the retainer; or (iii) A bridge plug 50 feet to 100 feet above the shoe with 50 feet of cement on top of the bridge plug, for expected or known lost circulation conditions.
(3) perforated zone that is currently open and not previously squeezed or isolatedA (i) A method to squeeze cement to all perforations; (ii) A cement plug set by the displacement method, at least 100 feet above to 100 feet below the perforated interval, or down to a casing plug, whichever is less; or (iii) If the perforated zones are isolated from the hole below, you may use any of the plugs specified in paragraphs (A) through (E) of this paragraph instead of those specified in paragraphs (3)(i) and (3)(ii) of this section:
(A) A cement retainer with effective back-pressure control 50 to 100 feet above the top of the perforated interval, and a cement plug that extends at least 100 feet below the bottom of the perforated interval with at least 50 feet of cement above the retainer;
(B) A bridge plug set 50 to 100 feet above the top of the perforated interval and at least 50 feet of cement on top of the bridge plug;
(C) A cement plug at least 200 feet in length, set by the displacement method, with the bottom of the plug no more than 100 feet above the perforated interval;
(D) A through-tubing basket plug set no more than 100 feet above the perforated interval with at least 50 feet of cement on top of the basket plug; or
(E) A tubing plug set no more than 100 feet above the perforated interval topped with a sufficient volume of cement so as to extend at least 100 feet above the uppermost packer in the wellbore and at least 300 feet of cement in the casing annulus immediately above the packer.
(4) A casing stub where the stub end is within the casing(i) A cement plug at least 100 feet above and below the stub end; (ii) A cement retainer or bridge plug set at least 50 to 100 feet above the stub end with at least 50 feet of cement on top of the retainer or bridge plug; or (iii) A cement plug at least 200 feet long with the bottom of the plug set no more than 100 feet above the stub end.
(5) A casing stub where the stub end is below the casingA plug as specified in paragraph (a)(1) or (a)(2) of this section, as applicable.
(6) An annular space that communicates with open hole and extends to the mud lineA cement plug at least 200 feet long set in the annular space. For a well completed above the ocean surface, you must pressure test each casing annulus to verify isolation.
(7) A subsea well with unsealed annulusA cutter to sever the casing, and you must set a stub plug as specified in paragraphs (a)(4) and (a)(5) of this section.
(8) A well with casingA cement surface plug at least 150 feet long set in the smallest casing that extends to the mud line with the top of the plug no more than 150 feet below the mud line.
(9) Fluid left in the holeA fluid in the intervals between the plugs that is dense enough to exert a hydrostatic pressure that is greater than the formation pressures in the intervals.

(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The plug must pass one of the following tests to verify plug integrity:

(1) A pipe weight of at least 15,000 pounds on the plug; or

(2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes. The District Supervisor may require you to tests other plug(s).

To what depth must I remove wellheads and casings?

(a) Unless the District Supervisor approves an alternate depth under paragraph (b) of this section, you must remove all wellheads and casings to at least 15 feet below the mud line.

(b) The District Supervisor may approve an alternate removal depth if:

(1) The wellhead or casing would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or

(2) You determine, and MMS concurs, that you must use divers, and the seafloor sediment stability poses safety concerns; or

(3) The water depth is greater than 800 meters (2,624 feet).

After I permanently plug a well, what information must I submit?

Within 30 days after you permanently plug a well, you must submit form MMS-124, Sundry Notices and Reports Start Printed Page 35409on Wells (subsequent report), and include the following information:

(a) Information included in § 250.1712 with a final well schematic;

(b) Description of the plugging work;

(c) Nature and quantities of material used in the plugs; and

(d) If you cut and pulled any casing string, the following information:

(1) A description of the methods used (including information on explosives, if used);

(2) Size and amount of casing removed; and

(3) Casing removal depth.

Temporary Plugging of Wells

If I temporarily plug a well that I plan to re-enter, what must I do?

You may temporarily plug a well when it is necessary for proper development and production of a lease. To temporarily plug a well, you must do all of the following:

(a) Submit form MMS-124, Sundry Notices and Reports on Wells, and the applicable information required by § 250.1712 to the appropriate District Supervisor and receive approval;

(b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in § 250.1715, except for § 250.1715 (a)(8). You do not need to sever the casings, remove the wellhead, or clear the site;

(c) Set a bridge plug or a cement plug at least 100-feet long at the base of the deepest casing string, unless the casing string has been cemented and has not been drilled out. If a cement plug is set, it is not necessary for the cement plug to extend below the casing shoe into the open hole;

(d) Set a retrievable or a permanent-type bridge plug or a cement plug at least 100 feet long in the inner-most casing. The top of the bridge plug or cement plug must be no more than 1,000 feet below the mud line. MMS may consider approving alternate requirements for subsea wells case-by-case;

(e) Identify and report subsea wellheads, casing stubs, or other obstructions that extend above the mud line according to U.S. Coast Guard (USCG) requirements; and

(f) Except in water depths greater than 300 feet, protect subsea wellheads, casing stubs, mud line suspensions, or other obstructions remaining above the seafloor by using one of the following methods, as approved by the Regional or District Supervisor:

(1) A caisson designed according to 30 CFR 250, subpart I, and equipped with aids to navigation;

(2) A jacket designed according to 30 CFR 250, subpart I, and equipped with aids to navigation; or

(3) A subsea protective device that meets the requirements in § 250.1722.

(g) Within 30 days after you temporarily plug a well, you must submit form MMS-124, Sundry Notices and Reports on Wells (subsequent report), and include the following information:

(1) Information included in § 250.1712 with a well schematic;

(2) Information required by § 250.1717(b), (c), and (d); and

(3) A description of any remaining subsea wellheads, casing stubs, mudline suspension equipment, or other obstructions that extend above the seafloor.

If I install a subsea protective device, what requirements must I meet?

If you install a subsea protective device under § 250.1721(f), you must install it in a manner that allows fishing gear to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear.

(a) Use form MMS-124, Sundry Notices and Reports on Wells to request approval from the appropriate District Supervisor to install a subsea protective device.

(b) The protective device may not extend more than 10 feet above the seafloor (unless MMS approves otherwise).

(c) You must trawl over the protective device when you install it (adhere to the requirements at § 250.1740(a)). If the trawl does not pass over the protective device or causes damage to it, you must notify the appropriate District Supervisor within 5 days and perform remedial action within 30 days of the trawl;

(d) Within 30 days after you complete the trawling test described in paragraph (c) of this section, submit a report to the appropriate District Supervisor using form MMS-124, Sundry Notices and Reports on Wells, that includes the following:

(1) The date(s) the trawling test was performed and the vessel that was used;

(2) A plat at an appropriate scale showing the trawl lines;

(3) A description of the trawling operation and the net(s) that were used;

(4) An estimate by the trawling contractor of the seafloor penetration depth achieved by the trawl;

(5) A summary of the results of the trawling test including a discussion of any snags and interruptions, a description of any damage to the protective covering, the casing stub or mud line suspension equipment, or the trawl, and a discussion of any snag removals requiring diver assistance; and

(6) A letter signed by your authorized representative stating that he/she witnessed the trawling test.

(e) If a temporarily abandoned well is protected by a subsea device installed in a water depth less than 100 feet, mark the site with a buoy installed according to the USCG requirements.

(f) Provide annual reports to the Regional Supervisor describing your plans to either re-enter and complete the well or to permanently plug the well.

(g) Ensure that all subsea wellheads, casing stubs, mud line suspensions, or other obstructions in water depths greater than 300 feet remain protected.

(1) To confirm that the subsea protective covering remains properly installed, either conduct a visual inspection or perform a trawl test at least annually.

(2) If the inspection reveals that a casing stub or mud line suspension is no longer properly protected, or if the trawl does not pass over the subsea protective covering without causing damage to the covering, the casing stub or mud line suspension equipment, or the trawl, notify the appropriate District Supervisor within 5 days, and perform the necessary remedial work within 30 days of discovery of the problem.

(3) In your annual report required by paragraph (f) of this section, include the inspection date, results, and method used and a description of any remedial work you will perform or have performed.

(h) You may request approval to waive the trawling test required by paragraph (c) of this section if you plan to use either:

(1) A buoy with automatic tracking capabilities installed and maintained according to USCG requirements at 33 CFR part 67 (or its successor); or

(2) A design and installation method that has been proven successful by trawl testing of previous protective devices of the same design and installed in areas with similar bottom conditions.

What must I do when it is no longer necessary to maintain a well in temporary abandoned status?

If you or MMS determines that continued maintenance of a well in a temporarily plugged status is not necessary for the proper development or production of a lease, you must:

(a) Promptly and permanently plug the well according to § 250.1715;

(b) Remove any casing stub or mud line suspension equipment and any subsea protective covering. You must submit a request for approval to perform such work to the appropriate District Start Printed Page 35410Supervisor using form MMS-124, Sundry Notices and Reports on Wells; and

(c) Clear the well site according to § 250.1740 through § 250.1742.

Removing Platforms and Other Facilities

When do I have to remove platforms and other facilities?

(a) You must remove all platforms and other facilities within 1 year after the lease or pipeline right-of-way terminates, unless you receive approval to maintain the structure to conduct other activities. Platforms include production platforms, well jackets, single-well caissons, and pipeline accessory platforms.

(b) Before you may remove a platform or other facility, you must submit a final removal application to the Regional Supervisor for approval and include the information listed in § 250.1727.

(c) You must remove a platform or other facility according to the approved application.

(d) You must flush all production risers with seawater before you remove them.

(e) You must notify the Regional Supervisor at least 48 hours before you begin the removal operations.

When must I submit an initial platform removal application and what must it include?

An initial platform removal application is required only for leases in the Pacific OCS Region or the Alaska OCS Region. It must include the following information:

(a) Platform or other facility removal procedures, including the types of vessels and equipment you will use;

(b) Facilities (including pipelines) you plan to remove or leave in place;

(c) Platform or other facility transportation and disposal plans;

(d) Plans to protect marine life and the environment during decommissioning operations, including a brief assessment of the environmental impacts of the operations, and procedures and mitigation measures that you will take to minimize the impacts; and

(e) A projected decommissioning schedule.

What information must I include in my final application to remove a platform or other facility?

You must submit a final application to remove a platform or other facility to the Regional Supervisor for approval. This requirement applies to leases in all MMS Regions. If you are proposing to use explosives, provide three copies of the application. If you are not proposing to use explosives, provide two copies of the application. Include the following information in the final removal application, as applicable:

(a) Identification of the applicant including:

(1) Lease operator/pipeline right-of-way holder;

(2) Address;

(3) Contact person and telephone number; and

(4) Shore base.

(b) Identification of the structure you are removing including:

(1) Platform Name/MMS Complex ID Number;

(2) Location (lease/right-of-way, area, block, and block coordinates);

(3) Date installed (year);

(4) Proposed date of removal (Month/Year); and

(5) Water depth.

(c) Description of the structure you are removing including:

(1) Configuration (attach a photograph or a diagram);

(2) Size;

(3) Number of legs/casings/pilings;

(4) Diameter and wall thickness of legs/casings/pilings;

(5) Whether piles are grouted inside or outside;

(6) Brief description of soil composition and condition;

(7) The sizes and weights of the jacket, topsides (by module), conductors, and pilings; and

(8) The maximum removal lift weight and estimated number of main lifts to remove the structure.

(d) A description, including anchor pattern, of the vessel(s) you will use to remove the structure.

(e) Identification of the purpose, including:

(1) Lease expiration/right-of-way relinquishment date; and

(2) Reason for removing the structure.

(f) A description of the removal method, including:

(1) A brief description of the method you will use;

(2) If you are using explosives, the following:

(i) Type of explosives;

(ii) Number and sizes of charges;

(iii) Whether you are using single shot or multiple shots;

(iv) If multiple shots, the sequence and timing of detonations;

(v) Whether you are using a bulk or shaped charge;

(vi) Depth of detonation below the mud line; and

(vii) Whether you are placing the explosives inside or outside of the pilings;

(3) If you will use divers or acoustic devices to conduct a pre-removal survey to detect the presence of turtles and marine mammals, a description of the proposed detection method; and

(4) A statement whether or not you will use transducers to measure the pressure and impulse of the detonations.

(g) Your plans for transportation and disposal (including as an artificial reef) or salvage of the removed platform.

(h) If available, the results of any recent biological surveys conducted in the vicinity of the structure and recent observations of turtles or marine mammals at the structure site.

(i) Your plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures you will take to minimize such impacts.

(j) A statement whether or not you will use divers to survey the area after removal to determine any effects on marine life.

To what depth must I remove a platform or other facility?

(a) Unless the Regional Supervisor approves an alternate depth under paragraph (b) of this section, you must remove all platforms and other facilities (including templates and pilings) to at least 15 feet below the mud line.

(b) The Regional Supervisor may approve an alternate removal depth if:

(1) The remaining structure would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or

(2) You determine, and MMS concurs, that you must use divers and the seafloor sediment stability poses safety concerns; or

(3) The water depth is greater than 800 meters (2,624 feet).

After I remove a platform or other facility, what information must I submit?

Within 30 days after you remove a platform or other facility, you must submit a written report to the Regional Supervisor that includes the following:

(a) A summary of the removal operation including the date it was completed;

(b) A description of any mitigation measures you took; and

(c) A statement signed by your authorized representative that certifies that the types and amount of explosives you used in removing the platform or other facility were consistent with those Start Printed Page 35411set forth in the approved removal application.

When might MMS approve partial structure removal or toppling in place?

The Regional Supervisor may grant a departure from the requirement to remove a platform or other facility by approving partial structure removal or toppling in place for conversion to an artificial reef or other use if you meet the following conditions:

(a) The structure becomes part of a State artificial reef program, and the responsible State agency acquires a permit from the U.S. Army Corps of Engineers and accepts title and liability for the structure; and

(b) You satisfy any U.S. Coast Guard (USCG) navigational requirements for the structure.

Site Clearance for Wells, Platforms, and Other Facilities

How must I verify that the site of a permanently plugged well, removed platform, or other removed facility is clear of obstructions?

Within 60 days after you permanently plug a well or remove a platform or other facility, you must verify that the site is clear of obstructions by using one of the following methods:

(a) For a site in water depths less than 300 feet, you must drag a trawl over the site.

(b) For a well site in water depths 300 feet or more, you may:

(1) Drag a trawl over the site;

(2) Scan across the location using sonar equipment;

(3) Inspect the site using a diver;

(4) Videotape the site using a camera on a remotely operated vehicle (ROV); or

(5) Use another method approved by the District Supervisor if the particular site conditions warrant.

(c) For a platform or other facility site in water depths 300 feet or more, you may:

(1) Drag a trawl over the site;

(2) Scan across the site using sonar equipment; or

(3) Use another method approved by the District Supervisor if the particular site conditions warrant.

If I drag a trawl across a site, what requirements must I meet?

If you drag a trawl across the site in accordance with § 250.1740, you must meet all of the requirements of this section.

(a) You must drag the trawl in a grid-like pattern as shown in the following table:

For a—You must drag the trawl across a—
(1) Well site300-foot-radius circle centered on the well location.
(2) Subsea well site600-foot-radius circle centered on the well location.
(3) Platform site1,320-foot-radius circle centered on the location of the platform.
(4) Single-well caisson, well protector jacket, template, or manifold600-foot-radius circle centered on the structure location.

(b) You must trawl 100 percent of the limits described in § 250.1741 in two directions.

(c) You must mark the area to be cleared as a hazard to navigation according to USCG requirements until you complete the site clearance procedures.

(d) You must use a trawling vessel equipped with a calibrated navigational positioning system capable of providing position accuracy of ±30 feet.

(e) You must use a trawling net that is representative of those used in the commercial fishing industry (one that has a net strength equal or greater than that provided by No. 18 twine).

(f) You must ensure that you trawl no closer than 300 feet from a shipwreck, and 500 feet from a sensitive biological feature.

(g) If you trawl near an active pipeline, you must meet the requirements in the following table:

For—You must trawl—And you must—
(1) Buried active pipelinesFirst contact the pipeline owner or operator to determine the condition of the pipeline before trawling over the buried pipeline.
(2) Unburied active pipelines that are 8 inches in diameter or largerno closer than 100 feet to the either side of the pipelineTrawl parallel to the pipeline Do not trawl across the pipeline.
(3) Unburied smaller diameter pipelines in the trawl area that have obstructions (e.g., pipeline valves) presentno closer than 100 feet to either side of the pipeline.Trawl parallel to the pipeline. Do not trawl across the pipeline.
(4) Unburied active pipelines in the trawl area that are smaller than 8 inches in diameter and have no obstructions presentparallel to the pipeline

(h) You must ensure that any trawling contractor you may use:

(1) Has no corporate or other financial ties to you; and

(2) Has a valid commercial trawling license for both the vessel and its captain.

What other methods can I use to verify that a site is clear?

If you do not trawl a site, you can verify that the site is clear of obstructions by using any of the methods shown in the following table:

If you use—You must—And you must—
(a) Sonarcover 100 percent of the appropriate grid area listed in § 250.1741(a)Use a sonar signal with a frequency of at least 500 kHz.
Start Printed Page 35412
(b) A diverensure that the diver visually inspects 100 percent of the appropriate grid area listed in § 250.1741(a)Ensure that the diver uses a search pattern of concentric circles or parallel lines spaced no more than 10 feet apart.
(c) An ROV ensure (remotely operated vehicle)ensure that the ROV camera records videotape over 100 percent of the appropriate grid area listed in § 250.1741(a)Ensure that the ROV uses a pattern of concentic circles or parallel lines spaced no more than 10 feet apart.
How do I certify that a site is clear of obstructions?

(a) For a well site, you must submit to the appropriate District Supervisor within 30 days after you complete the verification activities a form MMS-124, Sundry Notices and Reports on Wells, to include the following information:

(1) A signed certification that the well site area is cleared of all obstructions;

(2) The date the verification work was performed and the vessel used;

(3) The extent of the area surveyed;

(4) The survey method used;

(5) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and

(6) A post-trawling job plot or map showing the trawled area.

(b) For a platform or other facility site, you must submit the following information to the appropriate District Supervisor within 30 days after you complete the verification activities:

(1) A letter signed by an authorized company official certifying that the platform or other facility site area is cleared of all obstructions and that a company representative witnessed the verification activities;

(2) A letter signed by an authorized official of the company that performed the verification work for you certifying that they cleared the platform or other facility site area of all obstructions;

(3) The date the verification work was performed and the vessel used;

(4) The extent of the area surveyed;

(5) The survey method used;

(6) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and

(7) A post-trawling job plot or map showing the trawled area.

Pipeline Decommissioning

When may I decommission a pipeline in place?

You may decommission a pipeline in place when the Regional Supervisor determines that the pipeline does not constitute a hazard (obstruction) to navigation and commercial fishing operations, unduly interfere with other uses of the OCS, or have adverse environmental effects.

How do I decommission a pipeline in place?

You must do the following to decommission a pipeline in place:

(a) Submit a pipeline decommissioning application in triplicate to the Regional Supervisor for approval that includes the following information:

(1) Reason for the operation;

(2) Proposed decommissioning procedures;

(3) Length (feet) of segment to be decommissioned; and

(4) Length (feet) of segment remaining.

(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical;

(c) Flush the pipeline;

(d) Fill the pipeline with seawater;

(e) Cut and plug each end of the pipeline;

(f) Bury each end of the pipeline at least 3 feet below the seafloor or cover each end with protective concrete mats, if required by the Regional Supervisor; and

(g) Remove all pipeline valves and other fittings that could unduly interfere with other uses of the OCS.

How do I remove a pipeline?

Before removing a pipeline, you must:

(a) Submit a pipeline removal application in triplicate to the Regional Supervisor for approval that includes the following information:

(1) Proposed removal procedures;

(2) If the Regional Supervisor requires it, a description, including anchor pattern(s), of the vessel(s) you will use to remove the pipeline;

(3) Length (feet) to be removed;

(4) Length (feet) of the segment that will remain in place;

(5) Plans for transportation of the removed pipe for disposal or salvage;

(6) Plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures that you will take to minimize such impacts; and

(7) Projected removal schedule and duration.

(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; and

(c) Flush the pipeline.

After I decommission a pipeline, what information must I submit?

Within 30 days after you decommission a pipeline, you must submit a written report to the Regional Supervisor that includes the following:

(a) A summary of the decommissioning operation including the date it was completed;

(b) A description of any mitigation measures you took; and

(c) A statement signed by your authorized representative that certifies that the pipeline was decommissioned according to the approved application.

When must I remove a pipeline decommissioned in place?

You must remove a pipeline decommissioned in place if the Regional Supervisor determines that the pipeline is an obstruction.

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PART 256—LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL SHELF

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11. The authority citation for part 256 continues to read as follows:

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Authority: 42 U.S.C. 6213, 43 U.S.C. 1331 et seq.

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[Amended]
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12. In § 256.56(a)(1), the citation “250.700” is revised to read “250.1703”.

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[Amended]
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13. In § 256.62(e)(2), the citation “part 250”, subpart G” is revised to read “part 250, subpart Q”.

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[FR Doc. 02-11640 Filed 5-16-02; 8:45 am]

BILLING CODE 4310-MR-P