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Proposed Rule

Oil and Gas and Sulphur Operations in the Outer Continental Shelf-Pipelines and Pipeline Rights-of-Way

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Information about this document as published in the Federal Register.

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Start Preamble Start Printed Page 56442

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Proposed rule.

SUMMARY:

This proposed rulemaking completely revises the MMS Outer Continental Shelf pipeline and pipeline Rights-of-Way (ROW) regulations, and brings them up to date with current industry practices and technology. The proposed rule incorporates parts of several new and revised industry standards into the regulations. It also incorporates several conditions of approval for pipelines, plus guidance from various Notices to Lessees and Operators (NTLs) and one Letter to Lessees and Operators (LTL) into one set of comprehensive pipeline regulations. The proposed regulations would eliminate several NTLs and the LTL, and have been rewritten in plain language.

DATES:

Submit comments by January 31, 2008. The MMS may not fully consider comments received after this date. Submit comments to the Office of Management and Budget on the information collection burden in this proposed rule by November 2, 2007.

ADDRESSES:

You may submit comments on the proposed rulemaking by any of the following methods. Please use the Regulation Identifier Number (RIN) 1010-AD11 as an identifier in your message. See also Public Availability of Comments under Procedural Matters.

  • Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions on the Web site for submitting comments.
  • E-mail MMS at rules.comments@mms.gov. Use RIN 1010-AD11 in the subject line.
  • Fax: 703-787-1546. Identify with the RIN, 1010-AD11.
  • Mail or hand-carry comments to the Department of the Interior; Minerals Management Service; Attention: Regulations and Standards Branch (RSB); 381 Elden Street, MS-4024; Herndon, Virginia 20170-4817. Please reference “Pipelines and Pipeline Rights-of-way, 1010-AD11” in your comments and include your name and return address.
  • Send comments on the information collection in this rule to: Interior Desk Officer 1010-0050, Office of Management and Budget, 202-395-6566 (fax); e-mail: oira_docket@omb.eop.gov. Please also send a copy to MMS.
Start Further Info

FOR FURTHER INFORMATION CONTACT:

For comments or questions on procedural issues, contact Richard Ensele, Regulations and Standards Branch, 703-787-1583. For questions on technical issues, contact Alex Alvarado, Pipeline Section, Gulf of Mexico Outer Continental Shelf Region, 504-736-2547.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

The proposed rule is a complete revision of the regulations regarding pipelines and pipeline ROWs on the Outer Continental Shelf (OCS). The current regulations were originally published on April 1, 1988; various sections have been updated, and MMS has issued several NTLs and one LTL to clarify the regulations and to provide guidance. In addition, MMS often uses “conditions of approval” when approving pipeline applications to ensure that pipelines are installed, operated, maintained, and repaired in a safe and environmentally sound manner. The proposed rule incorporates some of those conditions of approval, and the guidance from the following NTLs and LTL (these documents are available on the MMS Web site at http://www.mms.gov/​ntls/​):

  • NTL No. 2007-G09, Air Emissions Information for Applications for Accessory Platforms to Pipeline Rights-of-way (would be eliminated by the proposed rule);
  • NTL No. 98-09, Proposed and As-Built Pipeline Location Data (would be eliminated by the proposed rule);
  • NTL No. 2007-G01, Shallow Hazards Requirements;
  • NTL No. 2000-G20, Deepwater Chemosynthetic Communities;
  • NTL No. 2002-G03, Supervisory Control and Data Acquisition (SCADA) Systems;
  • NTL No. 2007-G20, Coastal Zone Management Program Requirements for OCS ROW Pipeline Applications (would be eliminated by the proposed rule);
  • NTL No. 2004-G05, Biologically Sensitive Areas of the Gulf of Mexico;
  • NTL No. 2005-G07, Archaeological Resource Surveys and Reports;
  • NTL No. 2007-G14, Pipeline Risers Subject to the Platform Verification Program (would be eliminated by the proposed rule); and
  • LTL dated April 18, 1991, Provide Clarification, Description, and Interpretation with Regard to Pipeline Requirements (would be eliminated by the proposed rule).

One of the goals in the proposed rule is to minimize the use of conditions of approval and NTLs. By incorporating this information, we hope to eliminate most of the conditions of approval, the four NTLs as noted above, and the LTL listed above. The remaining five NTLs would remain in effect, since they apply to other operations in addition to pipelines. In most cases, the industry has complied with these conditions and followed the guidance in the NTLs for several years. Even though these requirements are new to the regulations, they are generally not new to the industry.

Another goal of the proposed rule is to update several industry standards already incorporated by reference into the regulations, and to incorporate new standards which would give the industry more options in designing new pipelines.

Review of Proposed Rule

The proposed revision of subpart J is much longer than the current regulations in subpart J. It is more comprehensive, clear, and detailed. Most of the changes are designed to enhance safety and protect the environment. Many of the changes are based on American Petroleum Institute (API), American National Standards Institute (ANSI), and American Society of Mechanical Engineers (ASME) recommended practices, as well as standard MMS and industry practices. MMS will discuss the more significant changes here.

The proposed rule revises several of the definitions in § 250.105. The definitions in § 250.105 that MMS proposes to revise appear in other subparts as well as subpart J. Terms used only in subpart J are defined in proposed § 250.1000 if the term is used in more than one place in subpart J. If a term is used in only one place in subpart J, it is defined in place.

The proposed rule uses standards incorporated by reference applicable to pipelines. In some cases, MMS decided to include only the applicable language from a standard in the rule, rather than incorporate the entire standard. In other instances, MMS incorporated the standard or updated the currently incorporated standard. MMS will address the specific standards as they appear in the proposed rule. Since all documents incorporated by reference are covered under 30 CFR 250 subpart A at § 250.198, MMS proposes to update this section to include any new or changed documents. This includes revising the citations listed for several currently incorporated documents to correspond to the proposed subpart J rulemaking. MMS also added and changed requirements that relate to OCS Start Printed Page 56443pipelines contained in 30 CFR parts 253, Oil Spill Financial Responsibility; 254, Oil Spill Response Requirements for Facilities Located Seaward of the Coastline; and 256, Leasing of Sulphur or Oil or Gas in the Outer Continental Shelf.

MMS has divided the proposed rule into several broad subject categories as follows:

  • General
  • Applications for New Pipelines
  • Pipeline Application Contents
  • Pipeline Design
  • Pipeline Fabrication
  • Pipeline Construction
  • Pipeline Risers Connected to Floating Platforms
  • Pipeline Pressure Testing
  • Pipeline Safety Equipment
  • Pipeline Leak Detection
  • Pipeline Internal Corrosion Control and Flow Assurance
  • Pipeline Operations and Maintenance
  • Pipeline Modifications and Repairs
  • Pipeline Surveying, Monitoring, and Inspection
  • Pipeline Decommissioning
  • Pipeline Right-of-way (ROW) Grants
  • Accessories to Right-of-way (ROW) Pipelines

The following is an overview of each category, and a discussion of the significant changes and requirements.

General

The General category covers definitions, general requirements, types of pipelines, jurisdiction, and a table that summarizes required applications, notifications, plans, and reports. The definitions used in this rulemaking have been discussed above. MMS considered adding a listing or table of acronyms after the definitions section, but decided against that due to the length of this proposed subpart. Would it be helpful to include such a listing or table?

The proposed rule provides the basic regulations for OCS pipelines. There are other laws, conditions, and stipulations that apply to pipelines on the OCS which are not mentioned in the current regulations, but are addressed in this proposed rule. They include:

  • OCS Lands Act (OCSLA), as amended
  • National Environmental Policy Act (NEPA)
  • Coastal Zone Management Act (CZMA)
  • Oil Pollution Act of 1990 (OPA 90)
  • Federal Water Pollution Control Act (FWPCA)
  • Applicable implementing regulations
  • Approved applications
  • Development Operations Coordination Documents (DOCD)
  • Development and Production Plans (DPP)
  • Lease provisions and stipulations

The Department of the Interior (DOI), through MMS, is one of two Federal agencies with jurisdiction over OCS oil and gas pipelines. The other is the U.S. Department of Transportation (DOT). Jurisdictional issues between the two agencies are addressed in this category. The jurisdictional criteria are based on the December 1996 Memorandum of Understanding (MOU) between DOI and DOT. According to the MOU, producer-operated pipelines are generally under DOI jurisdiction, and transporter-operated pipelines are generally under DOT jurisdiction. The MOU includes the flexibility to cover situations that do not correspond to its general definition of the jurisdictional boundary as “the point at which operating responsibility transfers from a producing operator to a transporting operator.” The MOU also provides that DOI and DOT may, through their enforcement agencies and in consultation with the affected parties, agree to exceptions to the MOU on a facility-by-facility or area-by-area basis. Operators may also petition DOI and DOT for exceptions to the MOU.

This category includes a table that summarizes the various applications, notifications, plans, and reports that a company must submit to MMS, including the timing of the submittal or notification and the number of copies required.

Applications for New Pipelines

MMS approval is required to install, maintain, and operate all new pipelines on the OCS. This category covers the responsibilities of the applicant and MMS in the pipeline application process. The conditions under which the Secretary of the Interior may cancel approval of a pipeline application are also addressed.

The proposed rule covers:

  • When the Regional Supervisor (RS) may require additional information;
  • When the RS may limit the information needed;
  • When an application may be withdrawn;
  • Requirements for informing impacted lessees, lease operators, and pipeline ROW holders; and
  • Information submitted to affected States.

MMS added a section to allow the RS to require additional information for those situations where conditions or features may warrant further scrutiny. Additionally, MMS added a section to allow the RS to limit the information to be submitted, if that information was submitted previously or is otherwise available. MMS is also codifying the Coastal Zone Management information requirements for affected States for the first time in the pipeline regulations. Guidance on this subject is currently contained in an NTL which would be eliminated by this proposed rule.

The proposed rule documents the current process that MMS follows in its standard review of applications. That process is not addressed in the current regulations. Steps in the process include:

  • Initial review
  • Compliance review
  • Environmental impact evaluation
  • Amendments
  • Approval restrictions
  • Objections to coastal zone consistency certifications

Pipeline Application Contents

The information that the applicant must supply to MMS in a pipeline application is spelled out, in detail, in this category. The proposed rule consolidates current MMS application content and application process requirements, with related guidance from several NTLs and one LTL.

Activities for lease term pipelines must be covered in DOCDs in the western Gulf of Mexico (GOM), and in DPPs in the eastern GOM and in the Pacific and Alaska OCS Regions. The requirements for these OCS plans are covered in 30 CFR 250, subpart B, Plans and Information. The proposed rule imposes similar requirements for information on ROW pipeline applications that must be addressed in the DOCD and DPP required by subpart B for lease term pipelines. Current pipeline ROW regulations do not impose these requirements. They are contained as guidance in an NTL. As stated earlier, this proposed rulemaking would eliminate four NTLs and one LTL.

Proposed § 250.1016 lists other agencies and entities with which an applicant must coordinate, and the information required by MMS documenting that the coordination has taken place. Proposed §§ 250.1017 and 1018 provide a detailed description of the information required regarding the location of the proposed pipeline. In addition, proposed §§ 250.1019 and 1020 provide a detailed description of the information required in the application regarding horizontal components, risers, appurtenances, and schematic flow diagrams.

Applicants currently provide much of the information required in proposed §§ 250.1022, 1023, and 1025 regarding construction, support, and products under the guidance of the NTLs listed earlier. The information requirements in proposed § 250.1026 regarding Start Printed Page 56444biological and archaeological resources are also currently submitted under the guidance of the NTLs. The proposed rule codifies current procedures.

The requirements in proposed § 250.1028 regarding oil spill response plans, and those in proposed § 250.1029 regarding oil spill financial responsibility for ROW pipelines, are both new to subpart J. However, the proposed regulations simply reference current requirements in 30 CFR parts 254 and 253, respectively.

The information requirements in proposed § 250.1030 regarding environmental impact analyses for ROW pipelines are new to the pipeline regulations, but are necessary for MMS to comply with NEPA.

Pipeline Design

Section 250.1002 of the current regulations contains pipeline design requirements. The proposed rule expands the design requirements into §§ 250.1031 through 250.1036. The proposed rule includes performance requirements for designing a pipeline to mitigate and withstand the detrimental effects of environmental factors such as currents, storm and ice scouring, mud slides, earthquakes, hurricanes, and load factors such as differential pressures, dynamic loads, expansion and contraction, corrosion, and hydrogen sulfide gas.

The proposed rule includes the formula for internal design pressure for steel horizontal components and risers that is in the current regulations. However, the proposed rule allows the use of equations from sections 4.3.1, 4.3.1.1, or 4.3.1.2 of API Recommended Practice 1111, Design, Construction, Operation, and Maintenance of Offshore Hydrocarbon Pipelines (Limit State Design) (API RP 1111), in lieu of the current formula. This may result in a cost savings to the pipeline company depending on the type of pipe required by the different equations. It gives the pipeline company a choice in designing the pipeline. In addition, the proposed rule incorporates the formulas in sections 4.3.2.1 and 4.3.2.2 of API RP 1111 for predicting the external design (collapse) pressure for steel pipe, and the formulas in sections 4.5.4 and 4.1.6.2 of API RP 1111 for designing a catenary riser for a fixed structure. The proposed rule would incorporate these seven sections of API RP 1111 into the regulations.

Pipeline Fabrication

MMS included new performance requirements for pipeline fabrication in the proposed rule. The requirements are general in nature, and cover quality control, design tolerances, recognized engineering practices, and compliance.

Pipeline Construction

Many of the proposed requirements in this category are new to the regulations. These include the performance requirements in the proposed § 250.1040, and the requirements for constructing a pipeline in or near a designated use area, and in or near a sensitive biological feature or archaeological resource. Also new in the proposed regulations are requirements for hazard mitigation and installing hot taps.

MMS included in this proposed rule a requirement to notify the military when crossing established military warning and water test areas, and a recommendation to notify the U.S. Coast Guard (USCG) for the preparation of a Notice to Mariners.

The proposed rule would require pipeline companies in the Alaska OCS Region (AKOCSR) and Pacific OCS Region (POCSR) to take cathodic protection readings on all pipelines during repairs and hot tap installations, not just on those pipelines that are over 20 years old. MMS added this requirement to ensure that the entire length of the pipeline remains protected from external corrosion. MMS also proposes requirements for protecting the coating on the horizontal component of the pipeline and the riser during construction, and we changed the requirements for protecting appurtenances and crossings so that all equipment must have protection or cover in water depths less than 500 feet. The separation for pipeline crossings is changed from 18 inches to 12 inches. The reduction still provides adequate protection, and is compatible with industry standards and DOT requirements. However, MMS invites your specific comments on this proposed change.

The U.S. Department of Defense (DOD) provided the requirements in proposed § 250.1047(a) regarding military test and water test areas. They are currently part of the lease agreement and stipulations. The requirements in proposed § 250.1048 regarding sensitive biological features and archaeological resources are taken from guidance contained in several of the previously listed NTLs. Pipeline companies have followed the guidance in these NTLs and their predecessors for several years.

The proposed rule would require companies to submit construction reports within 45 days after completion of pipeline construction, instead of the current 90 days. This is a reasonable requirement with today's technology, and will allow for faster updating of maps.

Pipeline Risers Connected to Floating Platforms

The proposed rule establishes a Pipeline Riser Verification Program for risers connected to floating platforms. The proposed rule at § 250.1052 requires that all such pipeline risers be subject to separate verification that necessitates the use of a Certified Verification Agent (CVA) specifically for the pipeline riser. This requirement would be in addition to the platform verification requirements in subpart I. MMS is proposing this requirement because pipeline risers from floating platforms are highly sophisticated and complicated components that require extensive specialized technical analysis and oversight. Also, riser failures could have high failure consequences, such as spills, explosions, fires and other major incidents. The proposed rulemaking would eliminate one NTL on this subject.

Pipeline Pressure Testing

This category covers hydrostatic pressure testing and leak testing. The proposed rule provides a definition of a successful hydrostatic pressure test, including when to conduct these tests and how to report the results. Most of the proposed requirements are the same as the current regulations. However, there are some new requirements for pressure testing after a repair using a spool piece.

The requirements for submitting test results are revised to include specific information in the report. The proposed rule lists the instances when a hydrostatic pressure test is required, and the pressure requirements for the test. MMS is also proposing specific requirements for leak tests. In addition, the proposed rule allows pretesting of a spool piece for a repair to conform to DOT regulations.

Pipeline Safety Equipment

This category covers the required safety equipment for pipelines. This includes departing, incoming, crossing, and bi-directional pipelines and pipeline pumps. The proposed rule describes the types, location, and operation of the required equipment. It also addresses requirements for providing redundant safety devices and for dealing with safety equipment failure.

This category begins with a general performance requirement. MMS proposes to expand the regulatory requirements for departing pipelines to include certain requirements currently Start Printed Page 56445imposed as conditions of approval for various permits. These requirements include the settings of high/low pressure sensors (PSHLs), and methods to determine the settings. In addition, the RS may require the installation of a flow safety valve (FSV) or a shutdown valve (SDV) on departing pipelines. These requirements are currently common industry safety practices.

On new incoming, crossing, and bidirectional pipelines, the proposed rule requires that companies install SDVs no more than 10 feet from the boarding pipeline riser and in an unclassified area. On new crossing pipelines, the proposed rule requires installation of an FSV on unmanned and non-production platforms to prevent backflow. MMS currently imposes these requirements as conditions of approval to prevent spills and decrease the likelihood of explosions and fires.

If the safety equipment fails, the proposed rule requires that the company shut in all pipelines immediately to ensure safety and protect the environment. Pipeline companies may not resume operations until the equipment is repaired or replaced, unless an equivalent degree of protection is provided.

Pipeline Leak Detection

The proposed rule allows the RS to require leak detection systems if MMS determines that they are necessary. The proposed rule recommends the use of current technology. This includes, but is not limited to, computational pipeline monitoring (CPM), including supervisory control and data acquisition (SCADA) systems.

Pipeline Internal Corrosion Control and Flow Assurance

This category includes new requirements to prevent internal pipeline corrosion and to maintain adequate flow over the life of a pipeline. These proposed changes are based on current industry practices included in API RP 1111.

Pipeline Operations and Maintenance

Proposed § 250.1079 would require the preparation of an operations and maintenance manual, an integrity management program, an emergency plan, and a personnel qualification program. MMS is proposing these requirements to ensure that lessees, designated lease operators, and pipeline ROW holders maintain OCS pipelines in accordance with current industry practices, and that the personnel performing the maintenance are capable of that task. Recent pipeline leaks in onshore pipelines in the United States, and other integrity issues associated with those pipelines, have prompted MMS to address offshore pipeline integrity in this proposed rule. The new requirements in § 250.1079 are performance based. At a later time, MMS may propose more prescriptive regulations if research indicates the need for them.

Proposed § 250.1080 would require marking pipeline segment numbers on the pipeline at each platform. The proposed rule would require marking immediately for new pipelines, but allows 6 months to mark existing pipelines. The proposed rule allows for the use of the component identifier from API RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms (incorporated by reference into the regulations at § 250.198) using the MMS-assigned pipeline segment number as the unique identifier. In API RP 14C, pipelines are identified by the codes KAA (bi-directional), KAH (departing), and KAQ (incoming). Under the proposed rule, the MMS-assigned pipeline segment number could be added to the API code (e.g., KAH-1425, where 1425 is the MMS-assigned pipeline segment number).

MMS included new requirements for the preparation of an H2 S Contingency Plan for pipelines that transport products containing H2 S in certain concentrations. Since such plans are required for all other OCS operations where H2 S is present, this proposed requirement makes the pipeline regulations consistent with the rest of our regulations.

Although the requirements in proposed § 250.1083 regarding remote operations are also new to the regulations, they are based on guidance from a current NTL covering operations during storms or other emergencies requiring evacuation.

The specific requirements in proposed § 250.1084 covering testing of safety equipment are new to the pipeline regulations. The current regulation at § 250.1004(a) is a performance based requirement for testing safety equipment. The proposed rule would require testing as outlined in API RP 14C. Pipeline safety equipment is currently tested in accordance with the requirements in subpart H, Oil and Gas Production Safety Systems. This revision places the requirements in subpart J. Prudent companies already follow these procedures in testing pipeline safety equipment.

The proposed rule includes notification and reporting requirements for safety equipment and pipelines removed from service. In addition, MMS proposes testing requirements for resuming operations on pipelines that have been shut in. Proposed § 250.1088 would require suspension of pipeline operations and notification to MMS if a pipeline leaks. The notification requirement is based on guidance in a current LTL (which would be eliminated by this proposed rule), and is also normally a condition of approval to reactivate a pipeline. We included the requirements in proposed § 250.1089, covering flaring gas from a pipeline, to be consistent with the regulations in subpart K, Oil and Gas Production Rates.

Pipeline Modifications and Repairs

MMS has completely revised the regulations covering pipeline modifications and pipeline repairs to more closely resemble the requirements covering new pipelines. The information required in a modification application is expanded to satisfy safety and environmental protection requirements. MMS incorporated guidance currently addressed in an NTL to satisfy Coastal Zone Management Act (CZMA) requirements if the modification affects any States. For those modifications that involve the installation of a hot tap, we proposed requirements covering the design, location, and description of the hot tap. In addition, the proposed rule would require the submission of a modification report within 30 days of completion.

The new information proposed for a repair application is necessary for safety and the protection of the environment. The proposed rule would require that the company submit a repair report within 30 days of the completion of the repair. The report must include location information, confirmation of the damage, confirmation that the repair was completed as approved, the results of pressure tests, and the cathodic protection measurements.

MMS revised the requirements (proposed § 250.1096) for repairing a pipeline with a clamp to differentiate those repairs below the splash zone from those in or above the splash zone. If you use a clamp to repair the pipeline on the horizontal component or on the pipeline riser below the splash zone, the proposed rule allows for the use of a welded clamp or a mechanical clamp. The proposed rule would require an application for a permanent repair in or above the splash zone, if you temporarily repaired the pipeline with a mechanical clamp. The permanent repair would require the use of a welded clamp, a spool piece, or other method approved by the RS.Start Printed Page 56446

Pipeline Surveying, Monitoring, and Inspection

The proposed rule would require visual surveys of all pipeline routes at least monthly, and gives several methods for conducting the surveys. In addition, the proposed rule would require annual inspections of each pipeline riser in and above the splash zone, and inspection of the underwater portions of the riser in conjunction with the platform inspection requirements in 30 CFR 250, subpart I, Platforms and Structures. MMS included proposed requirements, currently in effect as guidance in an NTL, for inspecting the pipeline after a storm or earthquake. These proposed requirements are considered critical to the safe operation of pipelines.

MMS proposes to change the deadline for reporting anode system inspections from March 1 to October 31 of each year, with the inspections to be conducted no later than September 30 of each year. This synchronizes MMS requirements for these reports with the timing of industry, since the inspections are normally conducted during the summer months. Pipeline companies currently either submit reports for inspections that they performed the previous summer, which are almost a year old, or they conduct the inspections when the weather is not ideal. By changing the reporting deadline to October 31 of each year, MMS ensures that the companies submit current information. The proposed regulation also allows the company to conduct tests at anytime and submit the reports within 60 days of the test, but no later than October 31 of each year. This provides more flexibility to the company in the timing of the tests.

The ultrasonic test inspections, in-line inspections, and trawling tests in proposed § 250.1103(d), (e), and (f) are new to the regulations. The RS may require these inspections and tests if specific conditions indicate the need for them.

Pipeline Decommissioning

The regulations for decommissioning a pipeline are mostly unchanged. MMS is proposing to relocate the pipeline decommissioning regulations from 30 CFR 250, subpart Q, Decommissioning Activities, to subpart J since these regulations are unique to pipeline operations. This would consolidate almost all pipeline specific regulations in one subpart. MMS requests your specific comments on this proposal, and comments on whether we should adopt this approach with other subparts within 30 CFR 250.

MMS added one section (proposed § 250.1113) covering the requirements for re-commissioning a decommissioned pipeline. This section refers the applicant to the pipeline application process in proposed § 250.1007.

Pipeline Right-of-Way (ROW) Grants

This category covers the terms and conditions for holding a pipeline ROW grant, including when a grant is needed, who may hold a grant, and how to apply for a grant. It also covers:

  • Bonding
  • Application submittal
  • MMS review
  • Compliance
  • Environmental review
  • State consistency review
  • Modification
  • Cessation of operations
  • Assigning a grant
  • Suspensions
  • Relinquishing a grant
  • Terminating a grant

Because of certain administrative similarities between pipeline ROW grants and OCS leases, many of the proposed changes are based on or derived from the regulations in 30 CFR 256, which address OCS leasing. Each separate ROW pipeline requires a separate ROW grant. The proposed financial security requirements are more detailed than in the current regulations. Currently, pipeline companies must furnish an area bond in the amount of $300,000 to hold pipeline ROW grants in an MMS OCS Region. The proposed rule would allow a pipeline ROW holder the option of choosing to cover the pipeline ROW with either a $300,000 pipeline ROW grant individual bond or a $1,000,000 pipeline ROW grant area bond. The $1,000,000 area bond will cover all pipeline ROW grants held by a company in one MMS OCS Region. These requirements represent an increase from the current bonding amount, and will more accurately reflect the actual liabilities in decommissioning pipelines. The new proposed amounts would apply to all existing and future grants. Companies would be required to cover existing pipeline ROW grants by these increased amounts within 6 months after the rule becomes effective. The Regional Director may also require additional security based on an evaluation of a company's ability to carry out present and future financial obligations under the pipeline ROW grant. Companies have the opportunity to provide MMS with written or oral arguments during the evaluation. These securities are required primarily to ensure that the U.S. Government has sufficient funds available to properly decommission a pipeline in the event that the pipeline company is unable or unwilling to do so. The proposed rule includes language giving MMS the ability to reduce the amount required by a bond, to deal with lapses in bonds, and to determine bond forfeiture.

The service fee for a pipeline ROW grant would remain unchanged. The proposed rule addresses pipeline ROW grant assignments. The conditions for when MMS will suspend a ROW grant are spelled out more clearly.

The MMS is proposing to increase the annual rental fees for pipeline ROW grants to reflect the current rates established for new rights-of-use and easement (see 30 CFR 250.160(f) and (g)) and pipeline accessory structures (see 30 CFR 250.1012(b)). The amount established by these regulations are $5.00 per acre per year for sites in water depths less than 200 meters and $7.50 per acre per year for sites in water depths 200 meters or greater. The current rental rate for pipeline ROW grants is $15 per mile. A pipeline ROW grant is 200 feet wide. Therefore, the area of a pipeline ROW grant is 24.24 acres per mile. At $5.00 per acre, the rental rate would be approximately $125 per mile (actually $121.20). Since raising the rental for pipeline ROW grants to $125 per mile from $15 per mile is a major increase, MMS is proposing to raise the rental in two steps. This proposed rule would increase the annual rental for pipeline ROW grants to $70 per mile. MMS will propose the second increase to $125 per mile in a future rulemaking. Although this is a large increase, MMS believes the higher fee is a fair and reasonable amount to pay for access to Federal lands.

The terms and conditions for holding a pipeline ROW grant remain unchanged with respect to the OCS Lands Act provisions requiring ROW pipelines to transport oil and natural gas produced in the vicinity of the pipeline without discrimination, and to provide open access.

The proposed rule (§ 250.1131(j)) would make compliance with Executive Order 11246, regarding non-discrimination in employment, a condition for holding a pipeline ROW grant. Therefore, the requirement (currently § 250.1015(d)) for pipeline ROW grant applicants to include the “Non-discrimination in Employment” form (YN 3341-1) with their applications is eliminated.

This category also covers relinquishing a pipeline ROW grant. It Start Printed Page 56447addresses the application requirements, rental payments, delinquent payments, the effective date of relinquishment, and financial securities. Proposed § 250.1137 covers cancellation, forfeiture, and expiration of pipeline ROW grants. One of the grounds for forfeiture in this proposed rule (§ 250.1137(b)(2)) concerns open and nondiscriminatory access to shippers. The MMS recently published in the Federal Register a proposed rule (72 FR 17047, April 6, 2007) which would establish 30 CFR part 291, Open and Nondiscriminatory Movement of Oil and Gas as Required by the Outer Continental Shelf Lands Act. Part 291 will be referenced in this regulation when it (part 291) becomes final.

The proposed rule covers the obligations of the pipeline ROW holder after a pipeline ROW grant is terminated for any reason. The pipeline ROW holder has 1 year after the grant terminates to decommission the associated ROW pipeline. Current regulations require that the company remove the pipeline. However, the proposed rule allows for ROW pipelines to be decommissioned in place if the RS approves. The proposed rule also provides requirements for re-commissioning of decommissioned pipelines.

Accessories to Right-of-Way (ROW) Pipelines

The proposed rule expands the current subpart J regulations for accessories to ROW pipelines. However, there are very few new requirements. The proposed rule clarifies that accessories to ROW pipelines are subject to the requirements currently contained in 30 CFR 250, subpart H, Oil and Gas Production Safety Systems, and 30 CFR 250, subpart I, Platforms and Structures, just like all other OCS structures. It also clarifies that applications for new accessories are subject to Coastal Zone Management Act consistency requirements. The proposed rule documents the internal MMS process for approving an accessory application.

Appendix

The following appendix will not appear in the Code of Federal Regulations. Appendix A is included in this proposed rule so we may solicit your comments on a proposed new form for use in reporting some of the information required in subpart J.

Appendix A—Department of the Interior—Form MMS 153, “Notification of Pipeline Installation/Relocation/Hydrotest”

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Procedural Matters

Public Availability of Comments

Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.

Regulatory Planning and Review (Executive Order (E.O.) 12866)

This proposed rule is not a significant rule as determined by the Office of Management and Budget (OMB), and is not subject to review under E.O. 12866.

(1) The proposed rule would not have an annual effect of $100 million or more on the economy. It would 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. There will be an increase in administrative costs, mainly information submitted to MMS in applications, plans, requests, and reports. MMS estimates that this proposed rule would cost the industry approximately $11.8 million in administrative costs each year. For more detail about these costs, please see the Paperwork Reduction Act section in this preamble. We estimate that the current pipeline regulations cost the industry approximately $7 million in administrative costs each year. Therefore, this proposed rule increases the annual administrative cost to industry by $4.8 million. However, the industry is currently submitting most of the information which would be required by this proposed rule as a condition of approval for a pipeline or pipeline right-of-way, or as requested in the NTLs mentioned earlier in this preamble. In addition, we estimate that this proposed rule will add $10.2 million in one-time costs to industry to comply with the new requirements for pipeline integrity management plans and associated manuals. The increased rental rate for pipeline ROW grants would result in an additional annual cost of $1.2 million to the industry. See the Regulatory Flexibility Act section of this preamble for more information. The MMS estimates that increasing the area-wide pipeline ROW bond from $300,000 to $1,000,000 would result in an additional annual cost of $3.7 million to the industry. This estimate is based on 300 area-wide pipeline ROW bonds in the GOM. The increased amount per bond would be $700,000. The average annual cost per bond in the GOM is 1.75 percent of the bond amount. The average annual increase in pipeline ROW bonding costs would be: 300 × $700,000 × 1.75% = $3,675,000. In summary, there would be an annual increase in costs to the industry of approximately $9.7 million plus a one time cost of $10.2 million. The overall impact would be less than $100 million. Most of the changes in the proposed rule clarify existing requirements or incorporate standard practices. Most operations would continue without many changes. This proposed rule is designed to codify existing practices that MMS and industry have generally followed for many years.

(2) The proposed rule would not create a serious inconsistency or otherwise interfere with an action taken or planned by another agency.

Both DOI and DOT have jurisdiction over OCS oil and natural gas pipelines. These jurisdictional boundaries are defined in the proposed rule.

The DOI and DOT have a MOU dated December 10, 1996. According to the MOU, producer-operated pipelines are generally under DOI jurisdiction and transporter-operated pipelines are generally under DOT jurisdiction. The MOU includes the flexibility to cover situations that do not correspond to the general definition of the jurisdictional boundary as “the point at which operating responsibility transfers from a producing operator to a transporting operator.” The DOI and DOT may, through their enforcement agencies and in consultation with the affected parties, agree to exceptions to this MOU on a facility-by-facility or area-by-area basis. Companies may also petition DOI and DOT for exceptions to this MOU.

(3) The proposed rule would not alter the budgetary effects of entitlements, grants, user fees, or loan programs, or the rights or obligations of their recipients. The proposed rule does not address entitlements, grants, user fees, or loan programs; and therefore, can have no effects on such programs. The proposed rule does increase the rental fees paid for pipeline ROW grants by the pipeline companies.

(4) The proposed rule would not raise novel legal or policy issues. Most of the requirements in the proposed rule represent established MMS and industry practices, and are in accordance with the provisions of the DOT/DOI MOU dated December 10, 1996.

Regulatory Flexibility Act (RFA)

The Department certifies that this proposed rule would not have a significant economic effect on a substantial number of small entities under the RFA (5 U.S.C. 601 et seq.). A regulatory flexibility analysis is not required.

This proposed rule applies to all lessees, designated lease operators, and pipeline ROW holders operating on the OCS. Lessees/operators are classified under the Small Business Administration's North American Industry Classification System (NAICS) code 211111, Crude Petroleum and Natural Gas Extraction. Under this NAICS code, companies with fewer than 500 employees are considered small businesses. MMS estimates that 130 lessees/operators explore for and produce oil and gas on the OCS. Approximately 70 percent of them (91 companies) fall into the small business category.

A pipeline ROW holder (non-producer) is a small entity if it is a liquid pipeline company with fewer than 1,500 employees, or a natural gas pipeline company with gross annual receipts of $25 million or less. MMS's database indicates that there are 88 pipeline ROW holders who do not own an interest in any oil and gas leases on the OCS. Fifty-seven of these companies are either major energy companies (large oil and gas or pipeline transmission companies), or wholly owned subsidiaries of such companies. Another 13 entities were either formed by partnerships among major producers and transporters, or have “arms-length” contractual relationships with several major producers on the OCS for which they provide transportation services. It is our understanding that in such relationships, one of the major partners usually serves as the “managing partner” of the entity so that the entity (whether a partnership or a corporation) is not actually independent in the usual sense. The remaining 18 entities could be categorized as small independent pipeline companies in the sense that they provide transportation services for several non-major oil or gas producers. These companies are classified by NAICS code 213112, Support Activities for Oil and Gas Operations. Thus, there are 218 companies affected by this proposed rule, of which 109 would be considered small businesses.

The costs of installing, operating, and maintaining pipelines on the OCS are high due to the operating environment, i.e., marine environment, water depth, distance from shore. The costs imposed by this proposed rule are mainly due to recordkeeping and reporting, and are therefore minor in comparison to the overall operation.Start Printed Page 56450

The increase in annual rental fees for pipeline ROW grants appears to be substantial, going from $15 per mile to $70 per mile. The MMS initially intended on raising the rental to the same rate as paid by holders of rights-of-use and easement and operators of accessory structures on the OCS ($5.00 per acre per year). Increasing the rental to $5.00 per acre would result in an annual rental rate of approximately $125 per mile. This proposed rule would increase the annual rental for pipeline ROW grants to $70 per mile (1/2 of the increase). MMS will propose the second increase in a future rulemaking. This acreage is computed based on a pipeline ROW being 200 feet wide. Therefore, the area of a pipeline ROW grant is 24.24 acres per mile. At $5.00 per acre, the rental rate would be approximately $125 per mile (actually $121.20). The MMS estimates that there are currently 20,114 miles of active ROW pipelines in the Gulf of Mexico comprised of 2,512 pipeline segments. Since MMS collects rentals on fractions of a mile for each segment, we added a correction factor to more accurately represent the mileage for which pipeline ROW holders are charged for annual rentals. Assuming the average fraction is 0.5 mile, the additional mileage will be the number of segments times 0.5. Therefore, the total mileage for which MMS collects rental is 20,114 + 1,256 = 21,370. At $15 per mile, the total annual rental comes to $320,550. At $70 per mile, the total annual rental amounts to $1,495,900. However, this approximately $1.2 million annual increase is spread over the total number of pipeline ROW holders, and it is a minor cost when compared to the costs of installing, operating, and maintaining ROW pipelines.

Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small business about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the actions of MMS, call 1-888-734-3247. You may comment to the Small Business Administration without fear of retaliation. Disciplinary action for retaliation by an MMS employee may include suspension or termination from employment with the DOI.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

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

a. Would not have an annual effect on the economy of $100 million or more. The proposed rule deals with OCS pipeline operations. It would ensure that safe and environmentally sound pipeline operations continue. The impacts of this proposed rule would not be economic. This proposed rule would not have a large impact on the costs of OCS pipeline operations, and would not have an impact on oil or natural gas prices. Oil and natural gas prices are driven more by market factors than by the cost of production.

b. Would not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. This proposed rule would not significantly increase the cost of pipeline operations on the OCS since most of the requirements are established practices that industry has followed for years. In general, doing business on the OCS (of any kind) is expensive. Any new costs imposed by this proposed rule would be minor.

The proposed rule would not have a large impact on the costs of OCS pipeline operations, and will not have an impact on oil or natural gas prices. Oil and natural gas prices are driven more by market factors than by the cost of production.

c. Would not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. Leasing on the OCS is limited to residents of the U.S. or companies incorporated in the U.S. This proposed rule would not change that requirement. The proposed rule would not interfere with competition and would not impact employment, investment, or productivity. The proposed rule encourages innovation since it allows for alternative methods of conducting pipeline operations.

Unfunded Mandate Reform Act (UMRA)

This proposed rule would not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The proposed rule would not have a significant or unique effect on State, local or tribal governments, or the private sector. A statement containing the information required by the UMRA (2 U.S.C. 1531 et seq.) is not required. There are no mandates for State, local, or tribal governments. This proposed rule only impacts pipeline companies on the OCS; it does not affect State or local governments or tribal lands.

Takings Implication Assessment (Executive Order 12630)

The proposed rule is not a governmental action capable of interference with constitutionally protected property rights. Thus, MMS did not need to prepare a Takings Implication Assessment according to E.O. 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights. The proposed rule revises existing pipeline regulations. It would not prevent any lessee, designated lease operator, or pipeline ROW holder from performing operations on the OCS, as long as they complied with the regulations.

Federalism (Executive Order 13132)

With respect to E.O. 13132, this proposed rule would not have federalism implications. This proposed rule would not substantially and directly affect the relationship between the Federal and State governments. To the extent that State and local governments have a role in OCS activities, this proposed rule would not affect that role.

The OCS is under Federal jurisdiction seaward from the State's jurisdiction. There is no overlap between State and Federal jurisdiction. This proposed rule applies only to areas under Federal jurisdiction. None of the changes in this proposed rule would affect areas that are controlled by the States. It would not change the way that the States and the Federal government interact, or the way that States interact with private companies.

Civil Justice Reform (Executive Order 12988)

With respect to E.O. 12988, the Office of the Solicitor has determined that the proposed rule does not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order.

Paperwork Reduction Act (PRA)

This proposed rule contains a collection of information that will be submitted to the Office of Management and Budget (OMB) for review and approval under § 3507(d) of the PRA. The title of the collection of information for this rule is 30 CFR 250, Subpart J Pipelines and Pipeline Rights-of-Way (Proposed Rulemaking) (OMB Control Number 1010-0050, expiration 3/31/09). Respondents primarily are an estimated 130 Federal OCS lessees and Start Printed Page 56451designated lease operators and 88 pipeline ROW holders. Other potential respondents are companies that submit letters of no objection to, or comments on, pipeline applications; certified verification agents (CVAs), independent certification agents (IVAs), or other third-party reviewers; and surety or other third-party guarantors. The frequency of response varies depending upon the requirement. Responses to this collection of information are mandatory or required to obtain or retain a benefit. MMS will protect proprietary information according to the Freedom of Information Act and 30 CFR 250.197, “Data and information to be made available to the public or for limited inspection.”

As discussed earlier in the preamble, the proposed rule is a complete revision of the current pipelines and pipeline rights-of-way regulations at 30 CFR 250, subpart J. It incorporates guidance from several NTLs and one LTL that respondents currently follow, and would codify various conditions that MMS imposes when approving pipeline applications to ensure that pipelines are installed and operated in a safe and environmentally sound manner. The OMB approved the information collection burden of the current 30 CFR 250, subpart J regulations under control number 1010-0050 (107,874 burden hours; and $2,369,400 non-hour burden cost service fees). When the final revised subpart J regulations take effect, the information collection burden approved for this rulemaking will replace the collection under 1010-0050 in its entirety.

A table at § 250.198 lists all of the 30 CFR 250 incorporated documents. That table would be revised to include the new 30 CFR 250, subpart J, incorporated documents added or updated under this proposed regulation. There are also several proposed changes to 30 CFR parts 253 and 254. However, these proposed changes do not affect the currently approved information collection burden of 30 CFR 250, subpart A (OMB Control Number 1010-0114) or 30 CFR parts 253 and 254 (OMB Control Numbers 1010-0106 and 1010-0091, respectively).

The current regulations on pipeline decommissioning and associated information collection are located in 30 CFR 250, subpart Q. The rule proposes to relocate the pipeline decommissioning requirements into the revised 30 CFR 250, subpart J regulations. The OMB approved the information collection burden of the current subpart Q regulations under control number 1010-0142. When the new 30 CFR 250, subpart J final regulations take effect, the pertinent 30 CFR 250, subpart Q pipeline decommissioning paperwork burden (3,000 burden hours) and their associated non-hour cost fees ($417,000) will be removed from the 1010-0142 collection of information.

There is a new paragraph (g) proposed for 30 CFR 256.62 which does impose a new information collection requirement. The paperwork burden for this proposed regulation is included in the submission to OMB for approval of the proposed 30 CFR 250 subpart J information collection. When this regulation becomes final, the 30 CFR 256 paperwork burden would be removed from this collection of information and consolidated with the information collection burden for 30 CFR 256 under OMB Control Number 1010-0006.

The following table provides a breakdown of the paperwork burden and fee estimates for this proposed rulemaking. For the current requirements retained in the proposed rule, we used the approved estimated hour burdens and the average number of annual responses where discernable. However, due to the vastly different structure of the proposed rule from current regulations, some adjustments (−4,874 hours) occurred. The proposed rule eliminates four currently approved information collection requirements in current regulations at §§ 250.1000(c)(2), (4), (8); and 250.1016 for a minimal burden reduction (−9 hours). However, there are several new requirements in the proposed rule as follows:

  • Most are procedures and practices that are currently being followed by respondents. However, their hour burdens are not identifiable in the OMB approval of current information collection estimates, and are therefore considered “new” information collection burdens (+67,293 hours).
  • Although a new Form MMS-153 is proposed for notifying MMS of pipeline installations or relocations and hydrostatic pressure tests, it should be noted that the information reported on the form is not a new burden (0 hours).
  • A proposed new section, Pipeline Risers Connected to Floating Platforms (§§ 250.1053-1056) would add new burden requirements (+8,100 hours).
  • When the rule takes effect, proposed § 250.1079 will require an initial one-time burden (+141,700 hours) on current respondents to develop the operating procedures. In future years, this burden will be drastically reduced as only new respondents will have to develop their initial operating procedures. There will be a substantially lower ongoing burden to maintain and update the procedures annually (+15,260 hours).
  • Current subpart J regulations have 107,874 hours approved by OMB. This revision to the collection requests a total of 337,884 hours which is a burden hour net increase of 230,010 hours. The fee is unchanged.
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As part of our continuing effort to reduce paperwork and respondent burdens, MMS invites the public and other Federal agencies to comment on any aspect of the reporting and recordkeeping burden. You may submit Start Printed Page 56461your comments directly to the Office of Information and Regulatory Affairs, OMB. You should provide MMS with a copy of your comments so that we can summarize all written comments and address them in the final rule preamble. Refer to the ADDRESSEES section for instructions on submitting comments. You may obtain a copy of our submission to OMB to revise and extend the OMB approval for 1010-0050 by contacting the Bureau's Information Collection Clearance Officer at (202) 208-7744.

The PRA provides that an agency may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. Until OMB approves this collection of information and assigns an OMB control number and the regulations become final, you are not required to respond. OMB is required to make a decision concerning the collection of information of this proposed regulation between 30 to 60 days after publication of this document in the Federal Register. Therefore, a comment to OMB is best assured of having its full effect if OMB receives it by November 2, 2007. This does not affect the deadline for the public to comment to MMS on the proposed regulations.

MMS specifically solicits comments on the following questions:

(a) Is the collection of information necessary for MMS to properly perform its functions, and will it be useful?

(b) Are the estimates of the burden hours of the collection reasonable?

(c) Do you have any suggestions that would enhance the quality, clarity, or usefulness of the information to be collected?

(d) Is there a way to minimize the information collection burden on those who are to respond, including the use of appropriate automated electronic, mechanical, or other forms of information technology?

In addition, the PRA requires agencies to estimate the total annual reporting and recordkeeping “non-hour cost” burden resulting from the collection of information. Other than the cost recovery fees listed in the table above, we have not identified any other costs, and we solicit your comments on this item. For reporting and recordkeeping only, your response should split the cost estimate into two components: (a) Total capital and start-up cost component, and (b) annual operation, maintenance, and purchase of services component. Your estimates should consider the costs to generate, maintain, and disclose or provide the information. You should describe the methods you use to estimate major cost factors, including system and technology acquisition, expected useful life of capital equipment, discount rate(s), and the period over which you incur costs. Generally, your estimates should not include equipment or services purchased:

(1) Before October 1, 1995;

(2) To comply with requirements not associated with the information collection;

(3) For reasons other than to provide information or keep records for the Government; or

(4) As part of customary and usual business or private practices.

National Environmental Policy Act (NEPA) of 1969

The MMS has determined that this proposed rule is categorically excluded under 516 Department Manual Chapter 2, Appendix 1, 1.10, which covers “Policies, directives, regulations, and guidelines that are of an administrative, financial, legal, technical, or procedural nature and whose environmental effects are too broad, speculative, or conjectural to lend themselves to meaningful analysis and will later be subject to the NEPA process, either collectively or case-by-case.

This proposed rule would revise MMS's regulations at 30 CFR parts 250, 253, 254, and 256 and brings them up-to-date with current industry practices and technology. It also incorporates several conditions of approval for pipelines, plus guidance from various Notices to Lessees and Operators and one Letter to Lessees and Operators into one set of comprehensive pipeline regulations. The proposed regulations also have been written in plain language.

The changes to be implemented by this proposed rule are administrative, technical, and procedural in nature. The environmental effects of the proposed changes are either indirect (e.g., revised monitoring and reporting requirements), or too broad and speculative to lend themselves to a meaningful NEPA analysis. Individual pipelines and pipeline rights-of-way approved and regulated under this proposed rule will be subjected to the NEPA process. In addition, this proposed rule does not involve extraordinary circumstances as outlined in 516 DM 2, Appendix 2 that would trigger further NEPA analysis.

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

Executive Order 13211 requires the agency to prepare a Statement of Energy Effects when it takes a regulatory action that is identified as a significant energy action. This proposed rule is not a significant energy action, and therefore would not require a Statement of Energy Effects, because it:

a. Is not a significant regulatory action under E.O. 12866,

b. Is not likely to have a significant adverse effect on the supply, distribution, or use of energy, and

c. Has not been designated by the Administrator of the Office of Information and Regulatory Affairs, Office of Management and Budget, as a significant energy action.

Consultation With Indian Tribes (Executive Order 13175)

Under the criteria in E.O. 13175, we have evaluated this proposed rule and determined that it has no potential effects on federally recognized Indian tribes. There are no Indian or tribal lands on the OCS.

Clarity of This Regulation

Executive Order 12866 requires each agency to write regulations that are easy to understand. MMS invites your comments on how to make this proposed rule easier to understand, including answers to questions such as the following:

(1) Are the requirements in the proposed rule clearly stated?

(2) Does the proposed rule contain technical language or jargon that interferes with its clarity?

(3) Does the format of the proposed rule (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce its clarity?

(4) Would the proposed rule be easier to understand if it were divided into more (but shorter) sections?

(5) Is the description of the proposed rule in the SUPPLEMENTARY INFORMATION section of this preamble helpful in understanding the rule? What else can we do to make the rule easier to understand?

Send a copy of any comments that concern how we could make this rule easier to understand to: Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street, NW., Washington, DC 20240. You may also e-mail the comments to this address: Exsec@ios.doi.gov.

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List of Subjects

End List of Subjects Start Signature

Dated: August 3, 2007.

C. Stephen Allred,

Assistant Secretary—Land and Minerals Management.

End Signature

For the reasons stated in the preamble, Minerals Management Service (MMS) proposes to amend 30 CFR parts 250, 253, 254, and 256 as follows:

Start Part

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

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

Start Authority

Authority: 43 U.S.C. 1331 et seq., 31 U.S.C. 9701.

End Authority

2. Amend § 250.105 as follows:

A. Remove the definitions of “Lease term pipelines,” “Pipelines,” and “Right-of-way pipelines.”

B. Amend the definition of the term “Affected State” by removing the word “or” at the end of paragraph (4), removing the period at the end of paragraph (5) and adding a semicolon in its place, and adding new paragraphs (6) and (7).

C. Add the definitions of “Chemosynthetic communities,” “Lease term pipeline,” “Pipeline,” “Pipeline right-of-way (ROW),” “Pipeline ROW holder,” and “ROW pipeline” in alphabetical order.

The additions read as follows:

Definitions.
* * * * *

Affected State * * *

(6) Which is directly adjacent to the proposed route of a ROW pipeline; or

(7) Which contains the onshore base you will use to provide supply and service support for ROW pipeline operations.

* * * * *

Chemosynthetic communities means assemblages of tubeworms, clams, mussels, bacterial mats, and a variety of associated organisms that obtain their energy from the oxidation of various organic compounds rather than from light (photosynthesis) and the sun-dependent photosynthetic food chain that supports all other life on earth.

* * * * *

Lease term pipeline means a pipeline that is applied for by a lessee or designated lease operator, and that is completely contained within the boundaries of a single lease, unitized leases, or contiguous (not cornering) leases held by that lessee or operated by that designated lease operator.

* * * * *

Pipeline means the horizontal components, risers, and appurtenances installed for transporting oil, gas, sulphur, and produced water. Piping confined to a production platform or structure, commonly referred to as a flowline, is regulated under subpart H of this part, Oil and Gas Production Safety Systems, and is excluded from this subpart.

Pipeline right-of-way (ROW) means an authorization issued by MMS under the authority of section 5(e) of the OCSLA (43 U.S.C. 1334(e)) and section 8 of the OCSLA (43 U.S.C. 1337(p)(1)(B)) that allows for the construction and use of an associated ROW pipeline for the purpose of transporting oil, natural gas, or sulphur. The term also means the area covered by that authorization.

Pipeline ROW holder means a person, association, or corporation that has been granted a pipeline ROW on the OCS by MMS under the authority of section 5(e) of the OCSLA (43 U.S.C 1334(e)) and section 8 of the OCSLA (43 U.S.C. 1337(p)(1)(b)).

* * * * *

ROW pipeline means a pipeline that is within:

(1) An unleased OCS block(s), or which crosses any portion of an unleased OCS block;

(2) An OCS lease or unit, or which crosses any portion of an OCS lease or unit, and the applicant is not a lessee or the designated lease operator of that lease, or the unit operator of that unit.

* * * * *

3. Amend § 250.125(a) as follows:

A. Remove the paragraphs (a)(20) through (a)(26);

B. Remove paragraphs (a)(35) and (a)(36);

C. Redesignate paragraphs (a)(27) through (a)(34) as paragraphs (a)(29) through (a)(36), respectively; and

D. Add paragraphs (a)(20) through (a)(28) as set forth below.

Service fees.

(a) * * *

Service—processing of the following:Fee amount30 CFR citation
*         *         *         *         *         *         *
(20) New Pipeline Application (Lease Term Pipeline)$3,100§ 250.1014(g).
(21) Pipeline Application-Modification (Lease Term Pipeline)$1,800§ 250.1093(b)(7).
(22) Pipeline Application-Modification (ROW Pipeline) (includes the application to modify the associated Pipeline ROW Grant, if applicable)$3,650§ 250.1093(b)(7); § 250.1132(a).
(23) Pipeline Repair Application$340§ 250.1095(a)(9).
(24) Application to Decommission a Pipeline (Lease Term Pipeline)$1,000§ 250.1109(a)(1)(vii); § 250.1109(a)(2)(xii).
(25) Application for a New Pipeline ROW Grant (includes the application for the associated ROW pipeline and any application to install or establish an associated accessory)$2,350§ 250.1125(b); § 250.1126(h).
(26) Application for a Pipeline ROW Grant (to convert a Lease Term Pipeline to an ROW Pipeline)$200§ 250.1125(b); § 250.1126(h).
(27) Request to Assign a Pipeline ROW Grant$170§ 250.1134(a)(5).
(28) Application to Relinquish a Pipeline ROW Grant (includes the decommissioning application for the associated ROW pipeline and any application to decommission an associated accessory)$1,900§ 250.1136(a)(6).
*         *         *         *         *         *         *
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* * * * *

4. Amend § 250.198 as follows:

A. Redesignate paragraph (d)(7) as paragraph (a)(8) and add new paragraph (d)(7);

B. In the table in paragraph (e), add entries in alphanumerical order for the following new documents incorporated by reference: API RP 1111 and DNV RP B401; and

C. In the table in paragraph (e), revise the entries for the following documents incorporated by reference: ANSI/ASME B16.5, ANSI/ASME B31.8, API RP 2A-WSD, API RP 2RD, API RP 14C, API RP 500, API RP 505, API Spec 6A, API Spec 6D/ISO 14313, API Spec 17J, and NACE MR0175.

The additions and revisions read as follows:

Documents incorporated by reference.
* * * * *

(d) * * *

ForWrite to
*    *    *    *    *
(7) DNV Recommended PracticeDet Norske Veritas, 16340 Park Ten Place, Houston, TX 77084.
*    *    *    *    *

(e) * * *

Title of documentsIncorporated by reference at
*         *         *         *         *         *         *
ANSI/ASME B16.5-2003 (including Errata) and B16.5a-2003 Addenda, Pipe Flanges and Flanged Fittings§ 250.1034(b)(1).
ANSI/ASME B31.8-2003, Gas Transmission and Distribution Piping Systems§ 250.1033(a).
*         *         *         *         *         *         *
API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms-Working Stress Design; Twenty-first Edition, December 2002; Errata and Supplement 1, December 2002; Errata and Supplement 2, October 2005; API Stock No. G2AWSD§ 250.901(a)(4); § 250.908(a); § 250.920(a), (b), (c), (e); § 250.1033(k); § 250.1141(a)(1)(ii), (iii); § 250.1146(d).
*         *         *         *         *         *         *
API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998, API Stock No. G02RD1§ 250.800(b); § 250.901(a)(6); § 250.1033(d).
*         *         *         *         *         *         *
API RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Seventh Edition, March 2001, API Stock No. G14C07§ 250.802(b), (e)(2); § 250.803(a), (b)(2)(i), (b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); § 250.804(a), (a)(6); § 250.1068(a)(1); § 250.1080(c); § 250.1084(a)(1), (b)(1), (c)(1), (d)(1), (d)(2), (e)(1); § 250.1628(c), (d)(2); § 250.1629(b)(2), (b)(4)(v); § 250.1630(a).
*         *         *         *         *         *         *
API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as Class I, Division 1 and Division 2, Second Edition, November 1997, reaffirmed November 2002, API Stock No. C50002§ 250.114(a); § 250.459; § 250.802(e)(4)(i); § 250.803(b)(9)(i); § 250.1064(b)(2); § 250.1065(b)(2); § 250.1066(b)(2); § 250.1628(b)(3), (d)(4)(i); § 250.1629(b)(4)(i).
API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition, November 1997, reaffirmed November 2002, API Stock No. C50501§ 250.114(a); § 250.459; § 250.802(e)(4)(i); § 250.803(b)(9)(i); § 250.1064(b)(2); § 250.1065(b)(2); § 250.1066(b)(2); § 250.1628(b)(3), (d)(4)(i); § 250.1629(b)(4)(i).
API RP 1111, Design, Construction, Operation, and Maintenance of Offshore Hydrocarbon Pipelines (Limit State Design), Third Edition, July 1999, Sections 4.1.6.2, 4.3.1, 4.3.1.1, 4.3.1.2, 4.3.2.1, 4.3.2.2, and 4.5.4 only, API Stock No. D11113§ 250.1033(a), (b), (c).
*         *         *         *         *         *         *
API Spec 6A, Specification for Wellhead and Christmas Tree Equipment, Nineteenth Edition, July 2004, API Stock No. GX06A19§ 250.806(a)(3); § 250.1034(a), (b)(1).
Start Printed Page 56464
*         *         *         *         *         *         *
API Spec 6D/ISO 14313, Specification for Pipeline Valves, Twenty-second Edition, January 2002, effective date July 1, 2002, API Stock No. G0X6D22§ 250.1034(a).
*         *         *         *         *         *         *
API Spec 17J, Specification for Unbonded Flexible Pipe, Second Edition, November 1999, effective date July 1, 2000, API Stock No. G17J02§ 250.803(b)(2)(iii); § 250.1015(c)(5); § 250.1016(b)(5); § 250.1033(e).
*         *         *         *         *         *         *
DNV RP B401, Recommended Practice for Cathodic Protection Design, 1993, Table 6.9.1 only§ 250.1034(d)(2).
*         *         *         *         *         *         *
NACE Standard MR0175, Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments, January 17, 2003, NACE Item No. 21302§ 250.490(p)(2); § 250.901(a)(19); § 250.1035.
*         *         *         *         *         *         *

5. In § 250.199, revise paragraph (e)(9) to read as follows:

Paperwork Reduction Act statements—information collection.
* * * * *

(e) * * *

*         *         *         *         *         *         *
(9) Subpart J, Pipelines and Pipeline Rights-of-Way (1010-0050), including Forms MMS-153, Notification of Pipeline Installation/Relocation/Hydrotest; MMS-2030, OCS Pipeline Right-of-Way Grant Bond; MMS-149, Assignment of Federal OCS Pipeline Right-of-Way GrantTo provide MMS with information regarding the design, installation, and operation of pipelines on the OCS. To ensure that pipeline operations are safe and protect the human, marine, and coastal environment.
*         *         *         *         *         *         *
[REDESIGNATED]

6. Redesignate §§ 250.1100-1107 as §§ 250.1150-1157.

7. Revise subpart J to read as follows.

Subpart J—Pipelines and Pipeline Rights-of-Way General
Definitions.
What general performance and recordkeeping requirements apply to OCS pipelines?
What are the types of OCS pipelines?
Which departments have jurisdiction over OCS pipelines?
What are the criteria for determining jurisdiction?
What are the requirements regarding jurisdiction transfer points?
When must I submit the applications, requests, plans and reports, and make the notifications required by this subpart?
Applications for New Pipelines
How do I apply for approval of a new pipeline?
Where must I send copies of my pipeline application?
How does MMS process a pipeline application?
What conditions must my pipeline application meet?
What can I do if an affected State objects to my pipeline ROW application?
How will the Regional Supervisor notify me of the decision on my pipeline application?
When may the Secretary cancel approval of a pipeline application?
Pipeline Application Contents
General information.
Other general information.
Information regarding other agencies and entities.
Location information.
Origination and termination information.
Horizontal component and appurtenances information.
Schematic flow diagram.
Shallow hazards information.
Construction information.
Onshore support base, terminal, support vessels, and aircraft information.
Operation information.
Service and products information.
Biological and archaeological information.
Requests for alternative compliance or departure.
Oil and hazardous substance spill response information.
Oil Spill Financial Responsibility (OSFR) demonstration information.
Environmental Impact Analysis (EIA) information.
Pipeline Design
What are the general requirements for designing a pipeline?
What must I do to avoid or mitigate hazards?
What are the design requirements for horizontal components and risers?
What are the design requirements for appurtenances?
What are the design requirements for sewer service?
When must I sectionalize a pipeline?
Pipeline Fabrication
What are the general requirements for fabricating a pipeline?
Pipeline Construction
What are the general requirements for constructing a pipeline?
Who must I notify before I begin construction?
What must I do to avoid or mitigate hazards during construction?
What must I do to install a hot tap?
What must I do to protect a horizontal component?
What must I do to protect a riser?
What must I do to protect an appurtenance and crossing?
What must I do to construct a pipeline in or near a designated use area?Start Printed Page 56465
What must I do to construct a pipeline in or near a sensitive biological feature or area?
What must I do to construct a pipeline in or near an archaeological resource?
When must I prepare and implement an H2S contingency plan for construction?
What information must I submit after construction is completed?
Pipeline Risers Connected to Floating Platforms
What are the requirements for pipeline risers connected to floating platforms?
What are the requirements for pipeline riser verification plans?
What must the CVA do to verify pipeline riser design?
What must the CVA do to verify pipeline riser fabrication?
What must the CVA do to verify pipeline riser installation?
Pipeline Pressure Testing
What are the general requirements for pressure testing a pipeline?
What are the requirements for conducting a hydrostatic pressure test for a pipeline?
What are the requirements for leak testing a pipeline?
When must I perform a pressure test on a pipeline?
What information must I include in a pressure test report?
Pipeline Safety Equipment
What are the general requirements for pipeline safety equipment?
What are the safety equipment requirements for a departing pipeline?
What are the safety equipment requirements for an incoming pipeline?
What are the safety equipment requirements for a crossing pipeline?
What are the safety equipment requirements for a bi-directional pipeline?
When must I provide redundant safety equipment?
What are the safety equipment requirements for a pipeline pump?
What must I do if safety equipment fails to operate as intended?
Pipeline Leak Detection
When do I need to use a leak detection system?
Pipeline Internal Corrosion Control and Flow Assurance
What are the general requirements for internal corrosion control?
What are the general requirements for flow assurance?
Pipeline Operations and Maintenance
What are the general requirements for operating and maintaining a pipeline?
What written procedures must I establish before I operate an OCS pipeline?
When must I mark the MMS-assigned pipeline segment number on a pipeline?
How do I determine the MAOP of a pipeline?
What must I do if the pipeline transports H2S?
What are the requirements for conducting remote operations during a platform evacuation?
What are the requirements for testing pipeline safety equipment?
What must I do when safety equipment is removed from service?
What must I do when a pipeline is taken out of service?
What must I do if a pipeline is shut in?
What must I do if a pipeline leaks?
What must I do if I need to flare or vent gas from a pipeline?
When must I provide impact protection for existing risers?
When will MMS suspend or temporarily prohibit pipeline operations?
Pipeline Modifications and Repairs
What must I do to modify an approved pipeline?
What are the general requirements for repairing a pipeline?
What must I do to commence and complete a repair?
What must I do to repair a pipeline using a clamp?
When do I need to submit a corrective action plan and report?
Pipeline Surveying, Monitoring, and Inspection
What are the general requirements for surveying, monitoring, and inspecting a pipeline?
What must I do to survey and monitor a pipeline or route?
What inspections are required for my pipeline or route?
What additional inspections or surveys may the Regional Supervisor require?
Pipeline Decommissioning
When do I accrue pipeline decommissioning obligations?
When must I decommission a pipeline?
What must I do to decommission a pipeline in place?
What must I do to decommission a pipeline by removal?
How do I obtain approval to decommission a pipeline?
How does MMS process a decommissioning application?
After I decommission a pipeline, what information must I submit?
When must I remove a pipeline decommissioned in place?
What are the requirements for re-commissioning a decommissioned pipeline?
Pipeline Right-of-Way (ROW) Grants
What is a pipeline ROW grant?
When must I obtain a pipeline ROW grant?
Who can be a pipeline ROW grant holder?
What are the financial security requirements for holding a pipeline ROW grant?
When will MMS terminate the period of liability of my financial security?
When will MMS cancel my financial security?
What happens if my financial security is reduced or lapses?
How will MMS determine that my financial security is forfeited?
What penalties can MMS assess if my financial security is not sufficient, is reduced or lapses, or is forfeited?
What happens to my financial security after a pipeline ROW grant terminates?
How do I submit an application for a pipeline ROW grant?
What information must I include in an application for a pipeline ROW grant?
How does MMS process an application for a pipeline ROW grant?
When will MMS temporarily suspend or prohibit construction of an ROW pipeline?
What must I do if the as-built location of the associated ROW pipeline deviates from the approved pipeline ROW grant?
What rental fees and payment schedules apply to a pipeline ROW grant?
What are the terms and conditions for holding a pipeline ROW grant?
How do I modify a pipeline ROW grant?
How does temporary cessation and cessation of pipeline operations affect a pipeline ROW grant?
How do I assign a pipeline ROW grant?
When may MMS suspend a pipeline ROW grant?
How do I relinquish a pipeline ROW grant?
When will a pipeline ROW grant be cancelled, be forfeited, or expire?
What must I do after a pipeline ROW grant terminates?
Accessories to Right-of-Way (ROW) Pipelines
What are the requirements for an accessory to an ROW pipeline?
How do I obtain approval to install, operate, and maintain an accessory?
How does MMS process an accessory application?
Who do I need to notify before I install an accessory?
What information must I submit after an accessory is installed?
What accessory inspections must I conduct?
What must I do to modify an accessory?
When must I decommission an accessory?
Start Printed Page 56466 Subpart J—Pipelines and Pipeline Rights-of-Way General
Definitions

Terms used in this subpart have the following meanings:

Accessory means a platform, a major subsea manifold, or similar subsea structures attached to a ROW pipeline to support pump stations, compressors, manifolds, etc. The site used for an accessory is part of the pipeline ROW grant.

Appurtenance means equipment, device, apparatus, or other object attached to or associated with a horizontal component or riser. Examples include anodes, valves, flanges, fittings, umbilicals, vortex-induced vibration (VIV) devices, subsea manifolds, templates, pipeline end modules (PLEM's), pipeline end terminals (PLET's), anode sleds, other sleds, and jumpers (other than jumpers connecting subsea wells to manifolds).

Failure, when applied to a pipeline or safety system, means any condition of the pipeline or a safety system component that prevents the complete performance of its design and function.

Horizontal component means a horizontal pipe that connects a pipeline riser, subsea wellhead or template, or pipeline to a pipeline riser, subsea wellhead or template, or pipeline (synonymous with the term “linepipe”).

Leak means the release of product from a pipeline.

Live bottoms (low relief features) means sea grass communities; areas that contain biological assemblages consisting of sessile invertebrates and/or algae living upon and attached to naturally occurring hard or rocky formations with rough, broken, or smooth topography; and areas where a hard substrate and vertical relief may favor the accumulation of turtles, fishes, or other fauna. These features occur throughout the POCSR, in the Eastern Planning Area of the Gulf of Mexico, and in the Beaufort Sea in Alaska.

Live bottoms (pinnacle trend features or seamounts) means small, isolated, low to moderate relief carbonate reef features; outcrops of unknown origin; or hard substrates exposed by erosion that provide surface area for the growth of sessile invertebrates and/or algae, and attract large numbers of fish. These features occur in an area of topographic relief throughout the POCSR and AKOCSR, and in the northeastern portion of the western GOMR. In the POCSR and AKOCSR, these features include rocky reefs, rock outcrops, pinnacles or seamounts. In the GOMR, these features include pinnacle trend features.

Maximum allowable operating pressure (MAOP) means the highest operating pressure allowable at any point in a pipeline.

Military warning or water test area means an area on the OCS that is used by the U.S. Department of Defense for conducting various mission operations, including air-to-air gunnery, rocket and missile research and testing, sonar buoy operations, pilot training, and aircraft carrier operations.

New or unusual technology means equipment or procedures that have:

(1) Not been used previously or extensively in an MMS OCS Region;

(2) Not been used previously under the anticipated operating conditions; or

(3) Operating characteristics that are outside the performance parameters established by this subpart.

Potentially sensitive biological features means those features not protected by an MMS biological lease stipulation that are of moderate to high relief (about 8 feet or higher), provide surface area for the growth of sessile invertebrates, and attract large numbers of fish. These features would be located outside any “No Activity Zone” of any of the named topographic features and would not be located on any live-bottom (pinnacle trend) stipulated blocks.

Production platform means a platform on the OCS that receives hydrocarbon or sulphur production either directly from wells or from other platforms that produce hydrocarbons or sulphur from wells. It may include processing equipment for treating the production or separating it into its various liquid and gaseous components.

Riser means a vertical conducting pipe that connects a horizontal component of a pipeline to equipment on a platform.

Splash zone means that portion of a pipeline riser that is located between 20 feet above the maximum tide and 20 feet below the minimum tide.

Topographic features means identified isolated areas of moderate to high relief that provide habitat for hard-bottom communities and numerous plant and animal species, and support, either as shelter or food, large numbers of commercially and recreationally important fishes.

What general performance and recordkeeping requirements apply to OCS pipelines?

(a) Performance. You must design, construct, operate, maintain, inspect, and decommission all OCS pipelines, appurtenances, accessories, and safety system components in a manner that:

(1) Conforms to the OCSLA (43 U.S.C. 1331, et seq.), as amended, applicable implementing regulations, other applicable laws, approved applications, approved Development Operations Coordination Documents (DOCD) and Development and Production Plans (DPP), and lease provisions and stipulations;

(2) Is safe;

(3) Prevents unauthorized discharges;

(4) Does not unreasonably interfere with other uses of the OCS, including those involved with national security or defense; and

(5) Does not cause undue or serious harm or damage to the human, marine, or coastal environment.

(b) Records. You must retain all records related to the design, construction, operation, maintenance, testing, inspections, repairs, failures, and decommissioning of an OCS pipeline for as long as the pipeline remains in place, unless otherwise specified by the Regional Supervisor or in these regulations, and make them available to MMS upon request.

What are the types of OCS pipelines?

An OCS pipeline is either a lease term pipeline or an ROW pipeline.

Which departments have jurisdiction over OCS pipelines?

An OCS pipeline is under the jurisdiction of either the Department of the Interior (DOI) or the Department of Transportation (DOT).

What are the criteria for determining jurisdiction?

(a) DOI jurisdiction criteria. An OCS pipeline is under DOI jurisdiction if it is:

(1) A lease term pipeline that is not subject to regulation under 49 CFR, parts 192 and 195, and does not cross into State waters; or

(2) An ROW pipeline that is operated by an identified pipeline operator (the person or entity identified by the pipeline ROW holder as authorized to control or manage the pipeline's operations), and that is either:

(i) A producing pipeline operator (the identified pipeline operator of an ROW pipeline that is a lessee or designated lease operator of one or more OCS leases), unless it is subject to regulation under 49 CFR, parts 192 and 195, and crosses into State waters; or

(ii) A transporting pipeline operator (the identified pipeline operator of an ROW pipeline that is not a lessee or a designated lease operator of an OCS lease), and the pipeline is not subject to regulation under 49 CFR, parts 192 and 195.Start Printed Page 56467

(b) DOT jurisdiction criteria. An OCS pipeline that is not under DOI jurisdiction (see paragraph (a) of this section) is under DOT jurisdiction.

(c) Jurisdiction transfer. You may request that a pipeline under DOI jurisdiction be transferred to DOT jurisdiction, or that a pipeline under DOT jurisdiction be transferred to DOI jurisdiction, by submitting a written petition for approval to the Regional Supervisor and the DOT Office of Pipeline Safety (OPS) Regional Director. In the petition, you must provide sufficient justification for the transfer. The Regional Supervisor and the DOT OPS Regional Director will decide jointly whether to approve the petition.

What are the requirements regarding jurisdiction transfer points?

(a) Jurisdiction transfer point. For each applicable pipeline, you must meet the requirements of this paragraph (a).

(1) You must identify the specific point at which regulatory jurisdiction transfers from DOI to DOT, or from DOT to DOI, by:

(i) Durably marking an above-water jurisdiction transfer point or, if that is not practical, identifying the transfer point on a schematic; or

(ii) Identifying an underwater jurisdiction transfer point on a schematic.

(2) You must keep the schematics referenced in paragraph (a)(1) of this section at the nearest OCS facility and make them available to MMS upon request.

(b) Jurisdiction transfer point disagreement. If the lessee(s), designated lease operator(s), or pipeline ROW holder(s) of connecting pipelines cannot agree upon a transfer point, the Regional Supervisor and the DOT OPS Regional Director will jointly determine the jurisdiction transfer point.

When must I submit the applications, requests, plans and reports, and make the notifications required by this subpart?

(a) Applications and requests. For all OCS pipelines you must submit applications to MMS, and receive approvals, according to the following table:

Application or requestRequired byWhen to submitTotal number of copies
(1) Transfer jurisdiction§ 250.1004(c)Before jurisdiction can be transferred from DOI to DOT, or from DOT to DOI1 to MMS. 1 to OPS.
(2) New pipeline§ 250.1007(a)Before you install, maintain, or operate a new pipeline3
(3) Modify a pipeline§ 250.1093(a), (b)Before you conduct operations to modify a pipeline3
(4) Repair a pipeline§ 250.1095(a)Before you conduct any repair work on a pipeline1
(5) Decommission a pipeline in place§ 250.1109(a)(1)Before you conduct operations to decommission a pipeline in place3
(6) Decommission a pipeline by removal§ 250.1109(a)(2)Before you conduct operations to decommission a pipeline by removal3
(7) Re-commission a decommissioned pipeline§ 250.1113(a)(1)Before you re-commission a decommissioned pipeline1
(8) Accessory§ 250.1141(a)Before you install, operate, and maintain an accessory to an ROW pipeline3
(9) Modify an accessory§ 250.1146Before you conduct operations to modify an accessory3
(10) Decommission an accessory—Initial§ 250.1147 (see § 250.1726)In the POCSR and AKOCSR, at least 2 years before you decommission an accessory1
(11) Decommission an accessory—Final§ 250.1147 (see § 250.1727)Before you decommission an accessory2

(b) Pipeline ROW grant applications and requests. For ROW pipelines, you must submit the following applications and requests to MMS, and receive approvals, in addition to those listed in paragraph (a) of this section:

Application or requestRequired byWhen to submitTotal number of copies
(1) Obtain a pipeline ROW grant§ 250.1125(a)Before you install, maintain, or operate an ROW pipeline1 original and 2 copies.
(2) Modify a pipeline ROW grant§ 250.1132(a)Before you can modify a pipeline ROW grant1 original and 2 copies.
(3) Assign a pipeline ROW grant§ 250.1134(a)Before you can assign a pipeline ROW grant2 executed originals.
(4) Relinquish a pipeline ROW grant§ 250.1136(a)Before you can relinquish a pipeline ROW grant1 original and 2 copies.

(c) Notifications. You must make notifications to MMS according to the following table:

NotificationUnder sectionWhen to notify
(1) Pipeline construction§ 250.1041(a), using Form MMS-153At least 48 hours before you commence pipeline construction.
(2) Discovery of archaeological resource§ 250.1049(d)Immediately.
(3) Hydrostatic pressure test§ 250.1058(b), using Form MMS-153At least 48 hours before you conduct a hydrostatic pressure test on a pipeline.
Start Printed Page 56468
(4) Safety equipment failure or removal§§ 250.1069(b) and 250.1085(a)In the GOMR, when the safety equipment remains out of service for 12 hours. Immediately in the POCSR and AKOCSR.
(5) Corrective action§ 250.1069(d)Immediately when you repair or replace safety equipment and resume operating the pipeline, or when you have provided an equivalent degree of protection and resume operating the pipeline.
(6) Return safety equipment to service§ 250.1085(c)Immediately when you return out-of-service safety equipment to service or when you provide an equivalent degree of protection.
(7) Pipeline leak§ 250.1088(b)Immediately or as soon as practicable after you discover that a pipeline has leaked.
(8) Pipeline relocation§ 250.1093(e), using Form MMS-153At least 48 hours before you begin the work to relocate a pipeline.
(9) Lapse of financial security for a pipeline ROW grant§ 250.1121(b)Within 72 hours after the security lapses.
(10) Sabotage or subversive activity§ 250.1131(k)Immediately upon discovery.

(d) Plans and Reports. You or the Certified Verification Agent (CVA), as appropriate, must submit plans and reports to MMS according to the following table:

Plan/ReportUnder sectionWhen to submitTotal number of copies
(1) Pipeline construction, including pressure test results§ 250.1051(a)Within 45 calendar days after you complete pipeline construction3
(2) Design verification plans for pipeline risers connected to floating platforms§ 250.1053(a)At least 30 calendar days before you submit the associated pipeline application1
(3) Fabrication verification plans for pipeline risers connected to floating platforms§ 250.1053(b)At least 30 calendar days before you submit the associated pipeline application1
(4) Installation verification plans for pipeline risers connected to floating platforms§ 250.1053(c)At least 30 calendar days before you submit the associated pipeline application1
(5) Interim CVA reports for pipeline risers connected to floating platforms§ 250.1054(c); § 250.1055(d); § 250.1056(d)CVA submits during each verification phase1
(6) Final CVA design reports for pipeline risers connected to floating platforms§ 250.1054(d)CVA submits within 90 calendar days of receipt of the design data, or within 90 calendar days after MMS approval to act as a CVA, whichever is latest, and before fabrication begins1
(7) Final CVA fabrication reports for pipeline risers connected to floating platforms§ 250.1055(e)CVA submits within 90 calendar days after completion of fabrication, and before installation1
(8) Final CVA installation reports for pipeline risers connected to floating platforms§ 250.1056(e)CVA submits within 45 calendar days after pipeline installation1
(9) Directed pressure test§ 250.1060(d)As directed by the Regional SupervisorAs directed by the Regional Supervisor.
(10) Out-of-service pipeline§ 250.1086(d)Within 48 hours after a pipeline is deemed to be out of service1
(11) Out-of-service pipeline reactivation, including pressure test results§ 250.1086(g)Within 30 calendar days after you reactivate a pipeline that has been out of service1
(12) Flaring/venting operations§ 250.1089(b)Within 72 hours after completing flaring or venting operations1
(13) Pipeline modification, including pressure test results§ 250.1093(f)Within 30 calendar days after you complete the pipeline modification1
(14) Pipeline repair, including pressure test results§ 250.1095(e)Within 30 calendar days after you complete a repair1
(15) Flexible joint inspections§ 250.1102(b)Within 30 calendar days after you complete the inspection1
(16) Pipe-to-electrolyte potential measurements§ 250.1102(d)No later than October 31 of the same year, or within 60 calendar days of the measurements, whichever is earlier1
(17) Additional inspections and surveys§ 250.1103(a) through (f)As directed by the Regional Supervisor1
(18) Pipeline decommissioning§ 250.1111Within 30 calendar days after you complete the decommissioning1
(19) Decommissioned pipeline re-commissioning, including pressure test results§ 250.1113(b)Within 30 calendar days after you complete the re-commissioning1
(20) Accessory installation§ 250.1144Within 45 calendar days after you complete accessory installation3
(21) Accessory inspections§ 250.1145(a)(2)By November 1 of each year1
(22) Accessory decommissioning§ 250.1147 (see § 250.1729)Within 30 calendar days after you decommission an accessory2
Start Printed Page 56469
(23) Accessory site clearance§ 250.1147 (see § 250.1743(b))Within 30 calendar days after you conduct site clearance verification operations2
Applications for New Pipelines
How do I apply for approval for a new pipeline?

Before you install, maintain, or operate a new pipeline (including a jumper), or a pipeline you create with a combination of new pipe and existing pipe, you must submit three copies of a pipeline application to the Regional Supervisor for approval. If you prefer to submit all or part of your pipeline application electronically (see § 250.186(a)(3)), you should consult with the Regional Supervisor for further guidance.

(a) Application contents. (1) Your application must include the information described in §§ 250.1014 through 250.1030.

(2) The Regional Supervisor may require you to include additional information, if necessary, to assist in evaluating your pipeline application.

(3) The Regional Director may require less information or analysis than you otherwise must provide in your pipeline application when:

(i) Sufficient information or analysis is readily available to MMS;

(ii) Other coastal or marine resources are not present or affected; or

(iii) Other factors, such as technological advances, affect information needs.

(b) Where to submit the application. You must submit a pipeline application to one of the MMS Regional offices shown in the following table.

For OCS areas adjacent to the . . .Submit your application to . . .
(1) State of AlaskaMinerals Management Service, Alaska OCS Region (AKOCSR), Regional Supervisor, Field Operations.
(2) Atlantic Coast States and in the Gulf of MexicoMinerals Management Service, Gulf of Mexico OCS Region (GOMR), Regional Supervisor, Field Operations.
(3) States of California, Oregon, Washington, or HawaiiMinerals Management Service, Pacific OCS Region (POCSR), Chief, Office of Facilities, Safety & Enforcement.

(c) Withdrawal after submission. You may withdraw your pipeline application at any time, and for any reason, by notifying the Regional Supervisor in writing.

Where must I send copies of my pipeline application?

(a) Impacted leases and pipeline ROW grants. When you submit a pipeline application to MMS, you must provide a copy of the pipeline application to each lessee or designated lease operator of an existing lease, and to each holder of a pipeline ROW grant (active or terminated) that could be impacted by your proposed pipeline construction or towing operations.

(b) Affected States. Unless the proposed operations described in your pipeline application are under a general concurrence from the affected State, when you submit a new ROW pipeline application to MMS you must provide each affected State with all of the following:

(1) A copy of the pipeline application. Pursuant to 43 CFR part 2, Appendix E, MMS has determined that none of the information included in an ROW pipeline application is proprietary. Therefore, you must not exclude any information from the copies of the application you submit to affected States.

(2) A consistency certification (see 15 CFR 930.57).

(3) All necessary data and information (see 15 CFR 930.58).

How does MMS process a pipeline application?

The Regional Supervisor determines whether the application is complete, accurate, and fulfills the requirements of this subpart. If the Regional Supervisor determines that your application does not meet these conditions, the Regional Supervisor will notify you of the problem or deficiency. The Regional Supervisor will not begin final review of your application until it is complete.

(a) Compliance review. The Regional Supervisor will ensure that your proposed operations conform to the OCSLA (43 U.S.C.1331, et seq.), as amended; other applicable laws; and applicable MMS regulations.

(b) Environmental impact evaluation. The Regional Supervisor will evaluate the environmental impacts of your proposed operations, and prepare environmental documentation under NEPA (42 U.S.C. 4321, et seq.) and its implementing regulations (40 CFR parts 1500 through 1508).

(c) Amendments. During the review of your pipeline application, the Regional Supervisor may require you, or you may elect, to change your pipeline application.

What conditions must my pipeline application meet?

The Regional Supervisor will approve your pipeline application only if you satisfy all of the criteria in this section.

(a) You must obtain the Regional Supervisor's approval of either a DOCD or DPP that covers the structure at the originating end of the pipeline (e.g., platform, well, subsea skid), if the proposed pipeline is a lease term pipeline (see § 250.1015(b)).

(b) You must provide the Regional Supervisor with a copy of your approved State permit (see § 250.1016(c)), if the proposed pipeline will enter or cross any State submerged lands.

(c) If the proposed pipeline will enter or cross any safety fairway or anchorage area, you must provide the Regional Supervisor with a copy of your approved U.S. Army Corps of Engineers permit (see § 250.1016(d)).

(d) If an OCS lease or pipeline ROW grant could be impacted by your proposed pipeline construction or towing operations (see § 250.1016(e) and (f)), you must:

(1) Provide the Regional Supervisor with a return receipt or letter of no objection from the lessee or designated lease operator of each impacted lease, or the holder of each impacted pipeline ROW grant (active or terminated); and

(2) Ensure that each entity you notified under paragraph (d)(1) of this section had at least 30 days from the Start Printed Page 56470date they received the pipeline application from you to submit comments to the Regional Supervisor.

(e) If the proposed pipeline will terminate or originate at a new hot tap or other connection on the OCS, the lessee, designated lease operator, or pipeline ROW holder of the receiving or delivering pipeline must first obtain approval from the Regional Supervisor to modify their pipeline.

(f) For ROW pipeline and new accessory installation applications, either:

(1) All affected States with approved CZMA programs have concurred, or have been conclusively presumed to concur, with your coastal zone consistency certification in your pipeline application under section 307(c)(3)(A) of the Coastal Zone Management Act (CZMA) (16 U.S.C. 1456(c)(3)(A)); or

(2) The Secretary of Commerce finds, under section 307(c)(3)(A) of the CZMA (16 U.S.C.1456(c)(3)(A)), that the proposed ROW pipeline operations or new accessory installation are consistent with the objectives of CZMA, or are otherwise necessary in the interest of national security.

(g) For ROW pipeline applications, you must demonstrate oil spill financial responsibility (OSFR) as required by 30 CFR 253.13, if applicable (see § 250.1029).

What can I do if an affected State objects to my ROW pipeline application?

For ROW pipeline and new accessory installation applications, if an affected State objects to the coastal zone consistency certification in your application, you may follow the procedures in either paragraph (a) or (b) of this section.

(a) You may amend your application to accommodate the State's objection, and submit the amendment to the Regional Supervisor for approval and to the affected State for its consistency determination. The amendment need only address information related to the State's objection.

(b) You may appeal the State's objection to the Secretary of Commerce using the procedures in 15 CFR part 930, subpart H. The Secretary of Commerce will either:

(1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) of CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that the proposed operations are consistent with the objectives of CZMA, or are otherwise necessary in the interest of national security; or

(2) Deny your appeal, in which case you may either amend your application under paragraph (a) of this section or withdraw your application and not conduct the proposed operations.

How will the Regional Supervisor notify me of the decision on my pipeline application?

After review and evaluation, the Regional Supervisor will notify you in writing whether your pipeline application is approved or disapproved.

(a) The Regional Supervisor will approve your pipeline application if it complies with all applicable requirements; and will inform you of any conditions that you may be required to meet. In the approval letter, the Regional Supervisor will assign a unique MMS pipeline segment number that you must use in all subsequent correspondence regarding the pipeline.

(b) The Regional Supervisor will disapprove your pipeline application if the proposed operations would probably cause serious harm or damage (and you cannot amend the proposed pipeline operations to avoid such conditions) to life (including fish or other aquatic life), property, any mineral (in areas leased or not leased), the national security or defense, or the marine, coastal, or human environment. The Regional Supervisor will provide the reason(s) for disapproving your pipeline application in writing.

When may the Secretary cancel approval of a pipeline application?

The Secretary may cancel approval of your pipeline application upon your request, or if pipeline operations under the application are in suspension or temporary prohibition (see § 250.1091) for at least 5 years (see section 5(a)(2) of the OCSLA (43 U.S.C. 1334(a)(2)). To cancel approval under this section, the Secretary must determine after a hearing that all of the following conditions are met:

(a) Continued operation under the approved pipeline application would probably cause serious harm or damage to life (including fish and other aquatic life), property, mineral resources (in areas leased or not leased); the national security or defense, or the marine, coastal, or human environment;

(b) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and

(c) The advantages of cancellation outweigh the advantages of continuing the pipeline application in force.

Pipeline Application Contents
General information.

You must provide the following general information:

You must provide a(n). . .That includes. . .and. . .
(a) Cover letter(1) The name of the company and the name, title, and signature of the company representative filing the application; and (2) A statement that you are applying for approval of the pipeline in accordance with § 250.1007
(b) List of contactsThe name and MMS operator number of the company filing the application, and the company's managerial, regulatory, and technical representatives who the Regional Supervisor can contact while processing the applicationFor each contact, you must include the: (1) Company name; (2) Business and postal address; (3) Telephone number; (4) Telefax number; and (5) E-mail address.
(c) Indication of the pipeline typeAn indication whether the proposed pipeline will be a lease term pipeline type or an ROW pipeline
(d) Indication of the pipeline jurisdictionAn indication whether the proposed pipeline will be under the jurisdiction of DOI or DOTIf you wish petition to transfer jurisdiction from DOI to DOT or to transfer jurisdiction from DOT to DOI (see § 250.1004(b)), you may include the request in your pipeline application.
(e) Tentative schedule for conducting pipeline operationsThe date your installation operations will begin and endThe date you will place the pipeline into service.
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(f) New or unusual technology statementA statement whether you will or will not use a new or unusual technology to carry out your proposed pipeline operationsIf you will use new or unusual technology, provide a narrative description of the technology and the rationale for its selection.
(g) PaymentPayment of a nonrefundable service fee (see § 250.125 for amount)If the application is for a lease term pipeline.
Other general information.

If your proposed pipeline operations meet any of the criteria in the following table, you must provide the indicated information:

If. . .You must provide. . .
(a) You are applying for an ROW pipelineA statement that certifies that you have an approved National Pollutant Discharge Elimination System (NPDES) permit, or that you have applied for an NPDES permit that covers your proposed pipeline operations.
(b) You are applying for lease term pipeline in the GOMRThe MMS assigned control number for the DOCD or DPP that a covers or will cover your proposed pipeline operations. If you have not submitted the DOCD or DPP, you must provide the date you intend to submit the document or plan to the GOMR.
(c) You are applying for an ROW pipeline and you propose to use measures beyond those required by this part to minimize or mitigate environmental impactsA description of the additional measures you will use.
(d) Your pipeline will operate in a sour environmentA certification that the pipeline is designed in accordance with the requirements in § 250.1035.
(e) You will install a supervisory control and data acquisition(SCADA) systemA brief description of the system.
Information regarding other agencies and entities.

If your proposed pipeline operations meet any of the criteria in the following table, you must provide the indicated information:

For each . . .You must provide . . .
(a) ROW pipeline and new accessory installation(1) Coastal zone consistency certification according to 15 CFR 930.57 for each affected State; and (2) Evidence that you sent your pipeline or accessory application, consistency certification (see 15 CFR 930.57), and all necessary data and information (see 15 CFR 930.58) to each affected State for their CZMA consistency determination.
(b) ROW pipeline, if the routes of the vessels and aircraft you will use to support your proposed pipeline operations are located in or could traverse established military warning or water test areas(1) An identification of the warning and water test area(s); and (2) A certification that, before you begin pipeline construction operations, you will contact the military installation with jurisdiction over the area concerning the control of electromagnetic emissions and the use of vessels and aircraft in the area.
(c) Proposed pipeline that will enter into or cross State offshore watersA copy of the approved permit from that State.1
(d) Proposed pipeline that will enter into or cross any safety fairway or anchorage areaA copy of the approved U.S. Army Corps of Engineers permit.1
(e) Proposed pipeline that will enter into an existing OCS lease, or whose construction operations could impact lease operations (e.g., placing anchors on the lease)OCS area and block designations, OCS lease number, and name of the lessee or designated lease operator for each impacted lease.
(f) Proposed pipeline that will cross, or whose construction operations could impact an existing ROW pipeline or a decommissioned pipeline (i.e., placing anchors or routing the pipeline across or within 500 feet of an existing ROW pipeline)OCS area and block designations of the crossing or impact point, and name of the pipeline ROW holder.
(g) Proposed pipeline that will originate or terminate at an existing valve or hot tap assembly(1) OCS area and block designations of the tie-in point(s); and (2) Name of the lessee or designated lease operator if a connecting pipeline is a lease term pipeline; or the name of the pipeline ROW holder if a connecting pipeline is an ROW pipeline.
(h) Proposed pipeline you identified pursuant to paragraphs (e), (f), and (g) of this sectionA photocopy of a return receipt or a letter of no objection that indicates the date that the lessee, designated lease operator, or pipeline ROW holder received a copy of your pipeline application by registered or certified mail (or equivalent).1
1 If this document is not available when you submit your application, you may submit the document later.
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Location information.

(a) You must provide the following location information:

You must provide . . .That must . . .
(1) A location plat based on the North American Datum of 1927 (NAD 27) for the GOMR (Gulf) and POCSR, and the North American Datum of 1983 (NAD 83) for the AKOCSR and GOMR (Atlantic), with a minimum scale of 1 inch = 2,000 feetInclude the information listed in paragraph (b) of this section.
(2) An Electronic file of the digital coordinates of a sufficient number of points to provide an accurate representation of the entire route of the proposed pipeline, including turns and umbilicalsBe in decimal degree latitude and longitude and based on NAD 27 for the GOMR (Gulf) and POCSR, and NAD 83 for the AKOCSR and GOMR (Atlantic). The Regional Supervisor will specify the file format for providing this information.
(3) Information on the proposed locations of the origin, termination, and inclusive OCS blocks traversed by the pipeline routeInclude, if applicable, the OCS area, block number, and lease number.
(4) The total length (feet) of the proposed pipeline excluding risers, the length in Federal waters (feet), and the length in State waters (feet), if applicable

(b) The location plat required by paragraph (a)(1) of this section must do all of the following:

(1) Identify the lessee, designated lease operator, or pipeline ROW holder.

(2) Show OCS area, block, and lease designations.

(3) Show the pipeline route from origination to termination, including the plant or refinery, if applicable. It must also show flow direction and, if an ROW pipeline, the 200-foot pipeline ROW and any site for an accessory.

(4) Show the routes and flow directions of all umbilicals.

(5) Identify all platforms (including accessories) and pipelines (MMS-assigned segment numbers) that your proposed pipeline will connect to, cross, or otherwise impact.

(6) Identify all safety fairways, anchorage areas, and military warning or water test areas that are within 500 feet of the center line of the proposed pipeline.

(7) Show the burial depth (feet) of the pipeline along its entire length.

(8) Show the water depth (feet) along the entire length of the pipeline.

(9) Depict the water depth (feet), X-Y coordinates, and decimal degree latitude and longitude of each of the following key points:

(i) Locations of the originating and terminating structures;

(ii) Points where the proposed pipeline crosses a fairway, an anchorage area, or a lease or block boundary;

(iii) Locations of subsea valves, flanges, hot taps, tie-ins, anode sleds, connecting sleds (including PLEM's and PLET's), manifolds (including those that are accessories), and other appurtenances;

(iv) Locations of pipeline crossings;

(v) Points throughout the curvature of a turn; and

(vi) Point where the pipeline enters into State jurisdiction, if applicable.

(10) Include a certification by a registered engineer or land surveyor that the information on the plat is accurately represented.

(c) For each ROW pipeline, you must provide a map at an appropriate scale that shows the:

(1) Proposed pipeline route relative to the shoreline, the onshore support base you will use, and the proposed primary transportation routes for your support vessels and aircraft; and

(2) Distance to shore (miles) of the pipeline route origination and termination points.

Origination and termination information.

You must provide origination and termination information as indicated in the following table:

Type of informationWhen requiredContents
(a) General information on the facilities where the proposed pipeline will originate and terminateIn all cases(1) The type of structure (i.e., platform, well jacket or caisson, subsea well, manifold, tie-in, or blind flange); (2) MMS-assigned name of the structure (if applicable); (3) OCS area and block designations; (4) OCS lease number (if applicable); (5) Distance to shore (miles); (6) Water depth (feet); (7) Whether the structure is manned or unmanned; and (8) If the facility is equipped with a pig launcher/receiver, a description of its major features and rating.
(b) Riser design information for each pipe diameterIf the pipeline will connect at a platform, well jacket, or caisson(1) Design life (years); (2) Outside diameter (inches); (3) Wall thickness (inches); (4) Pipe grade; (5) Hydrostatic test pressure (psi) and duration (hours); (6) Type and thickness (mils) of the external corrosion coating; (7) Type and thickness (mils) of the external corrosion coating in the splash zone; (8) Type and thickness (mils) of the internal corrosion coating; (9) Type of riser, e.g., fixed, catenary, top tension, flexible; (10) Type, pressure rating (psi), and, if applicable, the de-rated pressure rating (psi) of the insulating flange; and (11) Whether the riser can be inspected using in-line inspection tools (e.g., smart pigs).
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(c) Non-traditional pipeIf you plan to use any non-traditional pipe (e.g., flexible pipe) to construct the riser(1) The name and a description of the non-traditional pipe; (2) The manufacturer's design specification sheet; (3) The design pressure (psi); (4) An identification of the design standards you used; and (5) A review by a third-party verification agent (specified in API Spec 17J (incorporated by reference as specified in § 250.198), where applicable) if you intend to use any unbonded flexible pipe.
(d) Riser guard designIn all casesA drawing that shows how you will protect the riser(s) from physical damage that could result from contact with floating vessels.
(e) Catenary and other non-traditional riserIf the riser will be a catenary or other non-traditional design(1) Design fatigue life (years) of the riser and the fatigue point at which you would replace the riser; (2) Identification of the design standards you used; and (3) Type and rating of the connecting device you will use;
(f) Subsea manifoldIf the proposed pipeline will originate or terminate at a subsea manifoldA diagram of the facility showing its major features including: (1) Pressure rating (psi) of the pressure limiting component; (2) Type of exterior protective coating; and (3) Description of the cathodic protection system.
(g) Subsea tie-inIf the proposed pipeline will originate or terminate at a subsea tie-inInformation about the tie-in that includes: (1) Type of tie-in assembly (existing valve or new hot tap); (2) MMS-assigned pipeline segment number of the delivering or receiving pipeline; (3) MAOP (psi) of the delivering or receiving pipeline; and (4) Schematic drawing of the tie- in assembly.
(h) Subsea blind flangeIf the pipeline will originate or terminate at a subsea blind flangeInformation about the blind flange that includes the: (1) Type; (2) Pressure rating (psi); and (3) If applicable, the de-rated pressure rating (psi).
(i) Other appurtenances and other accessoriesIf the pipeline will include any equipment, device, apparatus, or other object not described in paragraphs (e) through (h) of this sectionInformation about the appurtenance that includes: (1) Description of the appurtenance; (2) Schematic drawings showing the arrangement and orientation of the appurtenances; and (3) For subsea manifolds, pipeline end modules (PLEM's), and pipeline end terminals (PLET's), a diagram of the appurtenance showing its major features and dimensions, pressure rating (psi), and type of exterior protective coating, and a description of the cathodic protection system.
Horizontal component and appurtenances information.

You must provide horizontal component and appurtenances information as indicated in the following table:

Type of informationWhen requiredRequired data elements
(a) Pipeline internal design pressureFor all pipelines(1) Internal design pressure (psi) you calculated; (2) Formula you used to calculate the internal design pressure; (3) Design factors you used in calculating the internal design pressure; and (4) Calculations you performed to derive the internal design pressure for each pipe diameter and wall thickness.
(b) Pipeline collapse design pressureFor all pipelines to be installed in water depths greater than 1000 feet(1) External pressure on the pipe in (psi); (2) Collapse design pressure (psi) you calculated; (3) Formula you used to calculate the external design pressure; (4) Collapse factor you used in calculating the external design pressure; (5) Calculations you performed to derive the external design pressure for each pipe diameter and wall thickness; and (6) Description of any collapse arrestors you intend to install or other mitigation you intend to use.
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(c) Horizontal component designFor all pipelines, for each pipe diameter incorporated in the horizontal component of the pipeline(1) Design life (years); (2) Pipe outside diameter (inches); (3) Pipe wall thickness (inches); (4) Pipe grade; (5) Bare pipe and weighted pipe specific gravities, and a statement (based on stability analysis) that the pipeline will remain stable following installation; (6) Type of welds (e.g., longitudinal, electrical resistance welded (ERW), submerged arc welded (SAW), seamless); (7) Hydrostatic test pressure (psi) and test duration (hours); (8) Type and thickness (mils) of the external corrosion coating; (9) Type and thickness (mils) of the internal corrosion coating; (10) Density (pounds/cubic foot) and thickness (inches) of the concrete weight coating; and (11) Statement indicating whether or not the pipe can be inspected using in-line inspection tools (e.g., smart pigs).
(d) Non-traditional pipeIf you plan to use any non-traditional pipe (e.g., coiled tubing, flexible pipe, unbonded flexible pipe) to construct the horizontal component(1) Name and a description of the non-traditional pipe; (2) Manufacturer's design specification sheet; (3) Design pressure (psi); (4) Identification of the design standards you used; and (5) Review by a third-party independent verification agent (specified in API Spec 17J (incorporated by reference as specified in § 250.198), where applicable) if you intend to use any unbonded flexible pipe.
(e) Pipeline cathodic protection systemIf you plan to install a cathodic protection system that uses bracelet anodes(1) Anode composition; (2) Design anode life expectancy (years); (3) Formula and calculations you used to determine the design life of your anodes; (4) Anode consumption rate (pounds/amp/year); (5) Net weight per anode (pounds); (6) Anode interval (feet); and (7) Number of anodes.
(f) Non-traditional cathodic protection systemIf you plan to install a cathodic protection system that does not use bracelet anodes(1) Specify and describe the system; and (2) Provide the applicable information from paragraph (e) of this section, and the information and calculations you used to show that your pipeline is cathodically protected.
(g) Pipeline valves and flangesIf you plan to install a valve or flange on the horizontal component (not at the originating or terminating points) as an appurtenance to the pipelineInformation about each valve or flange that includes the: (1) Type; (2) Pressure rating (psi); and (3) If applicable, the de-rated pressure rating (psi).
(h) UmbilicalsIf you plan to install umbilicals as appurtenances to the pipelineA drawing that shows: (1) Types of umbilicals (e.g., electrical, hydraulic, chemical) you plan to install; (2) Configuration of the umbilicals in the bundle; (3) Length (feet) and outside diameter (inches) of the bundle; and (4) Any associated umbilical termination assemblies.
(i) Other appurtenancesIf you plan to install any equipment, device, apparatus, or other object not described in paragraphs (e) through (h) of sectionInformation about each appurtenance that includes: (1) Description of the appurtenance; (2) Schematic drawings showing the arrangement and orientation of the appurtenances; and (3) For subsea manifolds, pipeline end modules (PLEM's), and pipeline end terminals (PLET's), a diagram of the appurtenance showing its major features and dimensions, pressure rating (psi), type of exterior protective coating, and a description of the cathodic protection system.
(j) Pipeline crossingsIf the pipeline will cross any existing pipeline, umbilical, power or communication cable, or other structure or object(1) MMS-assigned segment number of the pipeline or umbilical (if applicable) to be crossed; (2) OCS area and block designations of the crossing location; (3) Description of the method you will use to separate the pipeline from the existing structure or object and the separation distance (inches); (4) Water depth (feet) at the pipeline crossing; (5) Indication of the presence or absence of H2S in the crossed pipeline; and (6) Diagram that shows a profile of the crossing that includes the depth of cover (feet).
Schematic flow diagram.

You must provide a schematic flow diagram of the proposed pipeline that is consistent with the diagram(s) required by § 250.802(e)(1) through (3), as appropriate, and that shows:

(a) All pressure sensing devices and associated control lines;Start Printed Page 56475

(b) All pressure safety valves (PSVs) and settings;

(c) All shutdown valves (SDVs), flow safety valves (FSVs), and block valves;

(d) All pressure-regulating devices (including back-pressure regulators);

(e) Any subsea manifolds, PLEMs and PLETs, and other appurtenances;

(f) Input source(s) (e.g., wells, pumps, compressors, and vessels) and the maximum source pressure (MSP) (psi) of each;

(g) Flow direction (or predominate direction for bi-directional flow);

(h) Safety equipment for the input source;

(i) Rated working pressure (psi) of all valves and flanges;

(j) Any specification (spec) breaks;

(k) Initial receiving equipment, vessel, or pipeline, and its rated working pressure (psi) or MAOP (psi);

(l) Pig launchers and receivers;

(m) Calculated MAOP (psi) of the proposed pipeline;

(n) MMS-assigned segment number and approved MAOP (psi) of any connecting pipeline; and

(o) The transfer point where jurisdiction changes between DOI and DOT, if applicable.

Shallow hazards information.

You must provide information on shallow hazards as indicated in the following table:

Type of informationWhen requiredContents
(a) Shallow hazards survey reportFor ROW pipelines in the GOMR, and for all pipelines in the POCSR and AKOCSRShallow hazards survey report of the proposed pipeline route based on information obtained from the shallow hazards survey (see § 250.1032(a)). The Regional Supervisor will specify requirements for preparing the report.
(b) Shallow hazards analysis of any seafloor and subsurface geologic features, and any manmade features or conditions, which may have an adverse effect on the proposed pipelineIn all cases(1) Description of the hazards along the pipeline route; (2) Discussion of any special safety measures you will take to minimize the adverse effects of shallow hazards on the proposed pipeline; and (3) Discussion of how you will comply with the hazard mitigation requirements specified in § 250.1042.
Construction information.

You must provide pipeline construction information as indicated in the following table:

Type of informationWhen requiredContents
(a) Installation methodIn all casesA brief description of the method you will use to install the proposed pipeline (e.g., S-lay, J-lay, reeled lay, towed lay).
(b) General information on the vessel/equipment you will use to construct the proposed pipelineIn all cases(1) Type of vessel (e.g., anchor supported, dynamic positioning) or equipment (e.g., trucks, bulldozers); (2) Name of the vessel (if known); (3) Maximum anchor radius (feet); (4) Capacity of fuel tanks (barrels); and (5) Proposed anchor location for operations in the POCSR.
(c) Tow routeIf you plan to install the pipeline by towing or dragging it to the installation site(1) Plat that depicts the entire tow route and indicates where the pipeline will be dragged on the seafloor, if applicable. (2) Electronic file containing the the digital coordinates of sufficient points to provide an accurate representation of the proposed tow route. In preparing this file, you must: (i) Use the file format specified by the Regional Supervisor; (ii) Include the data for the entire tow route; and (iii) Present the data in decimal degree latitude and longitude, based on NAD 27 for the GOMR (Gulf) and the POCSR, and NAD 83 for AKOCSR and GOMR (Atlantic). (3) Shallow hazards survey report for the tow route (see § 250.1032(a)). (4) Analysis of any seafloor and subsurface geologic features, and any manmade features or conditions, which may have an adverse effect on the pipeline if towed or dragged. The analysis must include a: (i) Discussion of the hazards along the pipeline tow route; (ii) Description of any special safety measures you will take to minimize the adverse effects of shallow hazards on the towing operations; and (iii) Discussion of how you will comply with the hazard mitigation requirements specified in § 250.1042.
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(d) Air emissionsFor ROW pipelines in the GOMR, and for all pipelines in the POCSR and AKOCSR, you must provide air emissions information for all combustion sources used in pipeline construction operations(1) Total rated output (horsepower) of each vessel/equipment; (2) Rated output (horsepower) of each combustion emission source on the vessel(s) and a description of its use (e.g., crane, compressor, generator, dehydrator); (3) Run time (hours/day and days/year) for each emission source; (4) Documentation of any emission control technologies you will employ; and (5) Maximum hourly, daily, and total projected emissions for all pipeline installation-related emission sources.
(e) Vessel dischargesFor ROW pipelines in the GOMR, and for all pipelines in the POCSR and AKOCSR, you must provide information on discharges for all vessels associated with your pipeline installation(1) Types and general characteristics of the wastes that will be generated and discharged into the ocean during construction operations; (2) Volume (gallons) of waste that will be discharged; (3) Average and maximum discharge rates (gallons/hour); (4) Description of any treatment or storage; and (5) Discharge location and method for each type of discharge.
(f) Pipeline burialIf you plan to bury the pipeline (see § 250.1044(c))(1) Method you will use to bury the pipeline (e.g., jet, plow); and (2) Depth of burial (feet), including the depths in safety fairways and anchorage areas.
(g) Pipeline self burialIf you expect that the pipeline will bury itself naturally in the sediment, you must provide a request to use an alternative procedure under § 250.141(1) Appropriate site-specific geotechnical data (e.g., sediment compaction, shear strength) and other information to verify sediment conditions; and (2) Information specified in § 250.1027(a).
(h) Obstruction protectionIn all casesInformation concerning any covering (e.g., dome, cage, sandbags, concrete mats) you will use to protect a manifold, tie-in, or blind flange at the pipeline origination and termination points, and all valves, flanges, other appurtenances, and pipeline crossings along the horizontal component of the pipeline (see § 250.1046(a)). The information you provide must include: (1) A drawing that shows the specifications of the protective covering and the equipment it will protect; (2) A drawing and a description of the relationship of the protective covering to the seafloor (e.g., mat edges buried); (3) A discussion of any anchor pins or sandbags you will use to hold the protective covering in place, if applicable; (4) A description of the cathodic protection system for the protective covering, if appropriate; and (5) A discussion of your plans for maintaining the protective covering.
(i) Underwater vent pipelinesIf you plan to install an underwater vent pipelineA description of the provisions you will make for anchoring the end of the underwater vent pipeline.
Onshore support base, terminal, support vessels, and aircraft information.

You must provide information on each onshore base you will use to provide supply and service support for your proposed pipeline operations as indicated in the following table:

Type of informationWhen requiredContents
(a) Onshore support baseIn all cases(1) Name and location of the onshore support base, and whether it will be a new or existing facility; (2) Description of the necessary work, if you plan to construct a new onshore support base or make major additions to an existing one; and (3) Timetable for land acquisition (including rights-of-way and easements) and construction or expansion if you plan to acquire land to construct a new facility or expand an existing one.
(b) Onshore terminalFor pipelines that will transport product to shoreThe name, description, and location of the primary onshore terminal (including any refinery, gas plant, or compressor station) that will be built or undergo expansion or major modification as the result of your proposed pipeline operations.
(c) Support vessels and aircraft (general)For ROW pipelines in the GOMR, and all pipelines in the POCSR and AKOCSRInformation for each type of vessel/equipment (e.g., anchor-handling boats, tug boats, supply boats, service boats, crew boats) and aircraft you will use to support your proposed pipeline operations that includes: (1) Fuel tank storage capacity (barrels); (2) Maximum number of vessels/equipment that will be in the area of operations at any one time; and (3) Trip frequency or duration.
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(d) Diesel oil supply vessel/equipmentFor ROW pipelines in the GOMR, and all pipelines in the POCSR and AKOCSRInformation on the vessels you will use to supply diesel oil to your pipeline installation vessels/equipment that includes: (1) Vessel length (feet); (2) Diesel oil storage capacity (barrels); and (3) Frequency of fuel transfers.
Operation information.

You must provide the following pipeline operation information:

(a) Pipeline operating temperature. The anticipated maximum and minimum operating temperatures (°F) of the proposed pipeline.

(b) Proposed MAOP. Your proposed MAOP (psi) for the pipeline, and the method you used to determine the MAOP (see § 250.1081).

Service and products information.

You must indicate the primary service and, if applicable, the secondary service of the proposed pipeline (e.g., oil, bulk oil, natural gas, bulk gas, condensate, gas and condensate, gas lift, instrument, flare/vent, water, methanol, glycol, sulphur, or other chemicals). If the pipeline will be bidirectional, you must provide the service for each direction and indicate which one will predominate.

If you will be primarily transporting . . .Then you must provide . . .The Regional Supervisor may also require . . .
(a) Natural gas(1) The anticipated maximum flow rate (MMCFD); (2) The maximum design flow rate (MMCFD); (3) The specific gravity of the gas; (4) The carbon dioxide (CO2) and hydrogen sulfide (H2 S) concentrations (ppm); (5) Your provisions for controlling internal corrosion; and (6) Your provisions for flow assuranceThe chemical and physical characteristics of the gas.
(b) Liquid hydrocarbons(1) The anticipated maximum flow rate (BPD); and (2) The maximum design flow rate (BPD); (3) The API° gravity of the liquid; (4) The anticipated CO2 and H2 S concentrations (ppm); (5) Your provisions for controlling internal corrosion; and (6) Your provisions for flow assuranceThe chemical and physical characteristics of the oils (see definition under 30 CFR 254.6).
(c) Chemicals(1) The anticipated maximum flow rate (BPD); (2) The maximum design flow rate (BPD); (3) Your provisions for controlling internal corrosionThe chemical and physical characteristics of each chemical.
(d) A product with an H2 S concentration greater than 20 ppm, or will cross a pipeline that transports a product with an H2 S concentration greater than 20 ppm(1) An H2 S Contingency Plan prepared according to § 250.490(f); (2) A reference to an approved or submitted H2 S Contingency Plan that covers the operation of the proposed pipeline and/or the construction operations at the pipeline crossing; or (3) A statement that you will submit for approval to the appropriate District Manager either an H2 S Contingency Plan(s) or an amendment to an approved H2 S Contingency Plan(s) before you install the proposed pipeline.
(e) A product with an H2 S concentration greater than 500 ppmTwo (2) copies of an H2 S dispersion modeling report or the modeling results (see § 250.1082(b)), or a reference to such report or results if already submitted to the Regional Supervisor.
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Biological and archaeological information.

You must provide the biological and archaeological information indicated in the following table:

Type of informationWhen requiredContents
(a) Chemosynthetic communities reportIf the proposed pipeline, or the associated anchors or chains of the pipeline construction vessel (or a proposed accessory, or the associated anchors or chains of the construction barge) will be placed in water depths 1,312 feet or greaterThree copies of a high-density chemosynthetic communities report. The Regional Supervisor will specify the contents of this report.
(b) Sensitive biological features reports or documentationIf the proposed pipeline, or the associated anchors or chains of the pipeline construction vessel (or a proposed accessory platform, or the associated anchors or chains of the construction barge) will be placed in the vicinity of any biologically-sensitive features, including but not limited to topographic features, live bottoms (low-relief features), live bottoms (pinnacle trend features or seamounts), and potentially sensitive biological featuresPlats, a photo documentation survey report, and/or a high-resolution geophysical data survey report to identify and locate the features. The Regional Supervisor will specify when you must provide these plats and reports, and their contents.
(c) Archaeological reportIf you propose bottom-disturbing operations in areas that are identified as high probability shipwreck blocks or prehistoric areasThree copies of an archaeological report, or a reference to such a report if it was already provided to the Regional Supervisor. The Regional Supervisor will specify the contents of the archaeological report.
Requests for alternative compliance or departure.

You must provide any request for alternative compliance or departure as indicated in the following table:

Type of requestWhen requiredWhat your request must do
(a) Alternative complianceYou must request approval from the Regional Supervisor if you plan to use any alternate procedures or equipment (see § 250.141)(1) Identify the MMS regulation for which you are seeking alternative compliance; (2) Describe the procedure, method, or equipment you plan to use; (3) Explain the reason you want to use the procedure, method, or equipment; and (4) Explain how you will achieve a level of safety and environmental protection that is equal to or greater than that prescribed by the MMS regulation.
(b) DepartureYou must request approval from the Regional Supervisor if you plan to depart from any current MMS regulatory requirements (see § 250.142) concerning the proposed pipeline(1) Identify the MMS regulation for which you are seeking to forego or delay compliance; (2) Describe the procedure, method, or equipment you plan to use, if applicable; and (3) Explain the reason you wish to forego or delay compliance with the identified MMS regulation.
Oil and hazardous substance spill response information.

You must provide the following oil and hazardous substance spill response information:

(a) Oil spill response planning. For ROW pipelines, you must provide either:

(1) An Oil Spill Response Plan (OSRP) for the pipeline prepared according to the requirements of 30 CFR part 254; or

(2) A reference to your approved regional or subregional OSRP (see 30 CFR 254.3) that includes:

(i) A discussion of your regional or subregional OSRP, and a statement that your proposed ROW pipeline operations will be covered by that OSRP;

(ii) The locations of your primary oil spill equipment base and any preplanned equipment staging areas;

(iii) The names of your oil spill removal organizations for both spill response equipment and personnel;Start Printed Page 56479

(iv) The calculated volume (barrels) of your worst case discharge scenario (see 30 CFR 254.26(a)) for your proposed ROW pipeline;

(v) A comparison of the above worst case discharge scenario with the applicable worst case discharge scenario in your approved regional or subregional OSRP; and

(vi) A discussion of your worst case discharge scenario and your response in adverse weather conditions for your proposed operations (see 30 CFR 254.26(b), (c), (d) and (e)).

(b) Modeling report. If you model a potential oil or hazardous substance spill, a modeling report, the modeling results, or a reference to such report or results if you already submitted it to the Regional Supervisor.

(c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you propose to conduct operations within the protective zones of the FGBNMS, a description of your provisions for monitoring the impacts of an oil spill on the environmentally sensitive resources at the FGBNMS.

Oil Spill Financial Responsibility (OSFR) demonstration information.

For ROW pipelines that will transport oil (see definition at 30 CFR 253.3), you must provide a statement that you have demonstrated or will demonstrate OSFR coverage in the amount specified in 30 CFR 253.13(b) unless the static volume of the pipeline is 1,000 barrels, or less, or the calculated volume of your worst case discharge scenario is 1,000 barrels or less.

Environmental Impact Analysis (EIA) information.

For ROW pipelines, you must provide a project-specific EIA that identifies and analyzes the potential direct and indirect environmental impacts of your proposed ROW pipeline operations (including the installation and operation of any accessory) to assist the Regional Supervisor in complying with NEPA (42 U.S.C. 4321, et seq.) and other relevant Federal laws. Your EIA must include:

Type of informationWhat must be included
(a) Resources, conditions, and activities that could affect or be affected by your proposed ROW pipeline operations(1) Meteorology, oceanography, geology, and geological and/or manmade hazards; (2) Air and water quality; (3) Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, and algal or plant life;
(4) Threatened or endangered species, and their critical habitat, as defined by the Endangered Species Act (ESA) of 1973 (16 U.S.C. 1531, et seq.);
(5) Sensitive biological resources or habitats such as essential fish habitat, refuges, preserves, special management areas identified in coastal management programs, sanctuaries, coastal monuments, national natural landmarks, rookeries, and calving grounds;
(6) Archaeological resources;
(7) Socio-economic resources, as specified in paragraph (b) of this section;
(8) Coastal and marine uses, such as military or commercial operations, shipping, and mineral exploration or development; and
(9) Other resources, conditions, and operations identified by the Regional Supervisor.
(b) Socio-economic resources(1) The approximate number, timing, and duration of employment of persons engaged in onshore support and construction operations; (2) Population (including the approximate number of people and families added to local onshore areas);
(3) Existing offshore and onshore infrastructure (including major sources of supplies, services, energy, and water);
(4) Types of contractors or vendors that may place a demand on local goods and services;
(5) Land use;
(6) Subsistence resources and harvest practices;
(7) Recreation and recreational and commercial fishing (including seasons, location, and type);
(8) Minority and lower income groups;
(9) Federally-recognized tribes in the AKOCSR; and
(10) Coastal zone management programs.
(c) Impact producing factors (IPF) that can cause impacts to the environmental resources you identified in paragraph (a) of this section(1) Air emissions; (2) Seafloor disturbance from anchoring and structure emplacement; (3) Discharges; (4) Emissions of light and noise; (5) Water intakes and discharges; (6) Use of service vessels and helicopters;
(7) Construction or expansion of onshore support facilities;
(8) Onshore waste disposal; and
(9) Accidental events, including oil or chemical spills and hydrogen sulfide (H2S) releases.
(d) Environmental impact analysis (EIA)(1) Analysis of the direct and indirect impacts (including those from accidents) of the IPFs you identified in paragraph (c) of this section on the environmental resources, conditions, and activities you identified in paragraph (a) of this section;
(2) Analysis of the potential cumulative impacts from other activities to those environmental resources, conditions, and activities you identified in paragraph (a) of this section;
(3) Description of the type, severity, and duration of the potential impacts, and their biological, physical, and other consequences and implications;
(4) Description of the potential measures to minimize or mitigate the potential impacts; and
(5) Description of the alternatives to your proposed ROW pipeline operations that you considered while developing your pipeline application, and a comparison of the potential environmental impacts.
(e) ConsultationA list of agencies and persons that you consulted or you will consult, regarding potential impacts associated with your proposed pipeline operations.
(f) References citedA list of the references that you cite in the EIA.
Start Printed Page 56480 Pipeline Design
What are the general requirements for designing a pipeline?

You must design a pipeline, including the horizontal component, risers, valves, flanges, fittings, umbilicals, and all other appurtenances to do all of the following:

(a) Mitigate any reasonably anticipated detrimental effects of water currents, storm or ice scouring, soft or hard bottoms, mud slides, earthquakes, hurricanes, subfreezing temperatures, and other environmental factors;

(b) Withstand the anticipated maximum differential pressure to prevent both burst and collapse;

(c) Withstand the static and dynamic loads that will be imposed on the pipe during construction and under operating conditions;

(d) Mitigate the effects of thermal expansion and contraction; and

(e) Mitigate the effects of internal and external corrosion.

What must I do to avoid or mitigate hazards?

(a) Shallow hazards survey. You must conduct a shallow hazards survey using appropriate high-resolution geophysical survey techniques and other tools to locate potential hazards. The Regional Supervisor will specify the survey area, instrumentation, and methodology.

(b) Route selection. You must use the results of the shallow hazards survey required by paragraph (a) of this section, charts, maps, and other sources of relevant information to:

(1) Select a route that avoids surface and subsurface hazards as much as possible (e.g., in anchorage areas, existing pipelines, other manmade objects, active faults, rock outcrops, mudslide areas); and

(2) Identify hazards that you cannot avoid, and design the pipeline to mitigate the effects of these hazards.

What are the design requirements for horizontal components and risers?

(a) Internal design pressure. (1) You must determine the internal design pressure for steel horizontal components and risers using the following formula or the equations in section 4.3.1 of API RP 1111 and, if applicable, sections 4.3.1.1 and 4.3.1.2 of API RP 1111 (incorporated by reference as specified in § 250.198):

VariableDescription
PInternal design pressure (psi).
SSpecified minimum yield strength (psi), stipulated in the specification under which the pipe was purchased from the manufacturer or determined in accordance with section 811.253(h) of ANSI/ASME B31.8 (incorporated by reference as specified in § 250.198).
TNominal wall thickness (inches).
DNominal outside diameter of pipe (inches).
FConstruction design factor (0.72 for the horizontal component and 0.60 for risers).
ELongitudinal joint factor from Table 841.1B of ANSI/ASME B31.8 (incorporated by reference as specified in § 250.198) (See also section 811.253(d) of this standard).
TTemperature derating factor obtained from Table 841.1C of ANSI/ASME B31.8 (incorporated by reference as specified in § 250.198).

(2) For limitations, see section 841.121 of ANSI/ASME B.31.8 (incorporated by reference as specified in § 250.198). When calculating the internal design pressure for steel pipe, you may account for the effects of external hydrostatic pressure as shown in ANSI/ASME B.31.8, Chapter 8 (incorporated by reference as specified in § 250.198).

(b) External design pressure. You must predict the external (collapse) design pressure for steel pipe for pipelines to be installed in water depths greater than 1000 feet using the equations in sections 4.3.2.1 and 4.3.2.2 of API RP 1111 (incorporated by reference as specified in § 250.198).

(c) Catenary riser for a fixed structure. You must design a catenary riser for a fixed structure according to sections 4.5.4 and 4.1.6.2 of API RP 1111 (incorporated by reference as specified in § 250.198).

(d) Riser for tension leg platform or a floating system. You must design a pipeline riser for a tension leg platform or a floating system according to API RP 2RD (incorporated by reference as specified in § 250.198).

(e) Unbonded flexible pipe. If you plan to install a pipeline using unbonded flexible pipe, you must design the pipeline according to the specifications and the review standards for a third-party independent verification agent specified in API Spec 17J (incorporated by reference as specified in § 250.198).

(f) External protective coating. You must design a pipeline to provide the:

(1) Horizontal component and appurtenances with an external protective coating to minimize external corrosion;

(2) Risers with an additional external coating to resist the detrimental effects of corrosion, sunlight, and wave action in the splash zone; and

(3) Pipe and appurtenances exposed to the atmosphere with a suitable coating.

(g) Internal corrosion control. You must design a pipeline to mitigate internal corrosion (e.g., the use of internal coatings, corrosion-resistant alloys) over its design life.

(h) Flow assurance. You must design a pipeline to ensure that adequate flow can be sustained throughout its design life (e.g., using pipe-in-pipe, insulated pipe, electrically heated pipe, piggable pipe).

(i) Pipeline on-bottom stability. You must design a pipeline so that it will be stable in the geologic and weather conditions for the area.

(1) Your pipeline must remain stable during a storm. The stability must be determined using appropriate backfill rates and storm data for the area. If the pipeline is in a water depth less than 200 feet and is jetted at least 3 feet below the natural seabed, it must be stable during a 2-year storm (minimum). If you expect that the pipeline will bury itself naturally in the sediment in a water depth less than 200 feet, it must remain stable during a 100-year storm (minimum). If the pipeline is in a water depth 200 feet or greater and is not buried, it must be stable during a 100-year storm (minimum).

(2) The Regional Supervisor may require additional stability design measures based on the geologic or weather conditions for the area.

(j) Underwater vent pipeline. You must design an underwater vent pipeline (any pipeline that transports natural gas that has been vented during upset or abnormal conditions or bleed Start Printed Page 56481down operations to a location where the gas is discharged underwater or flared at a flare pile) to ensure that the discharge point is:

(1) A minimum of 250 feet from the delivering structure; and

(2) Anchored to the sea floor, unless the gas is flared at a flare pile.

(k) Riser supports. When designing riser supports, you must consider the:

(1) Loads induced by riser operations;

(2) Environmental loads, taking into account 100-year return period storm criteria as set out in API RP 2A-WSD (incorporated by reference as specified in § 250.198); and

(3) Installation loads on risers that are pre-installed.

What are the design requirements for appurtenances?

You must design pipeline appurtenances as set forth below:

(a) Pipeline valve. You must design a pipeline valve to meet the minimum design requirements of API Spec 6A (incorporated by reference as specified in § 250.198), API Spec 6D/ISO 14313 (incorporated by reference as specified in § 250.198), or the equivalent. You may not use a valve under any operating conditions that exceed the applicable pressure or temperature ratings in those standards. The material of the valve must be compatible with the product being transported.

(b) Pipeline flange. You must design a pipeline flange:

(1) To meet the minimum design requirements of ANSI B16.5 (incorporated by reference as specified in § 250.198), API Spec 6A (incorporated by reference as specified in § 250.198), or the equivalent;

(2) To withstand the MAOP of the pipeline;

(3) To maintain its physical and chemical properties at the maximum and minimum anticipated operating temperatures; and

(4) Using material that is compatible with the product being transported.

(c) Pipeline fittings. You must use pipeline fittings (couplings, elbows, unions, tees, swage nipples, buckle arrestors, gaskets, etc.) that:

(1) Have pressure-temperature ratings based on stresses for pipe of the same or equivalent material;

(2) Have a bursting strength greater than the computed bursting strength of the pipe; and

(3) Use material that is compatible with the product being transported.

(d) Anode cathodic protection system. You must:

(1) Design your anode cathodic protection system to have a life expectancy of 30 years or for the design life of the pipeline, whichever is longer; and

(2) Use the following equation, or another equation and/or method acceptable to the Regional Supervisor in accordance with the provisions of § 250.141, to calculate anode design life:

VariableDescription
TTime (years).
MTotal net anode mass (pounds).
UUtilization factor.
vElectrochemical efficiency (amp × hour/pound).
ICurrent demand (amp).

(3) You can obtain values for the utilization factor (U) from DNV RP B401, Table 6.9.1 (incorporated by reference as specified in § 250.198). You can obtain values for electrochemical efficiency (v) from the anode manufacturer.

What are the design requirements for sour service?

If your pipeline will operate in a sour environment (fluids containing water as liquid and H2 S exceeding the limits defined in paragraphs 1.3.1.1 and 1.3.1.2 of NACE Standard MR0175 (incorporated by reference as specified in § 250.198)), you must design your pipeline in accordance with section 10.5 of NACE Standard MR0175.

When must I sectionalize a pipeline?

The Regional Supervisor may require you to design your pipeline in sections to reduce the volume of your worst case discharge (see 30 CFR 254.47).

Pipeline Fabrication
What are the general requirements for fabricating a pipeline?

You must fabricate each pipeline in a manner that:

(a) Adheres to a suitable quality control program that includes inspection, testing, spot checks, and evaluation by qualified personnel;

(b) Adheres to the specified design tolerances;

(c) Conforms to recognized engineering practices; and

(d) Complies with applicable regulations, codes, guides, standards, and recommended practices.

Pipeline Construction
What are the general requirements for constructing a pipeline?

You must construct each pipeline in accordance with your approved application, and in a manner that:

(a) Minimizes construction stresses and strains;

(b) Ensures that the pipeline is constructed on the approved route;

(c) Avoids or mitigates geologic and manmade hazards, artificial reefs, archaeological resources, and biologically sensitive features;

(d) Minimizes the length of unsupported spans; and

(e) Protects the pipeline from damage.

Who must I notify before I begin construction?

Before you begin pipeline construction, you must make the notifications in the following table:

Who you must notifyWhen you must make notificationOther requirements
(a) U.S. Coast Guard (USCG)At least 30 calendar days before you conduct pipeline construction operationsYou are encouraged to notify the applicable USCG Marine Safety Office so that a Notice to Mariners can be prepared.
(b) Military installationsBefore you conduct pipeline construction operations in an established military warning or water test areaYou must notify the commander of the military installation that exercises jurisdiction of the area concerning the control of electromagnetic emissions and the use of vessels, equipment, and aircraft in the area.
(c) MMS, Regional SupervisorAt least 48 hours before you commence construction operationsYou must make this notification by telefax or email, using Form MMS-153 (Notification of Pipeline Installation/Relocation/Hydrotest).
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What must I do to avoid or mitigate hazards during construction?

To avoid or mitigate hazards during pipeline construction, you must comply with the requirements in the following table:

RequirementWhat you must doDetails
(a) Buoying hazardsBefore you perform pipeline construction operations or other bottom-disturbing activitiesYou must: (1) Buoy all existing pipelines and other potential hazards located within 500 feet of the operation (including anchor patterns); or
(2) In areas congested with pipelines or debris, use buoys to outline a safe working area large enough to accommodate your proposed pipeline construction operations.
(b) Navigation systemIn lieu of complying with paragraph (a) of this sectionYou may use a state-of-the-art, real-time primary navigational positioning equipment (e.g., DGPS) on all vessels (e.g., pipeline construction vessels, derrick barges, anchor-handling vessels) associated with your pipeline construction operations to depict existing pipelines and other potential hazards.
(c) Location platBefore you perform pipeline construction operationsYou must: (1) Prepare a plat with a minimum scale of 1:12,000 oriented to true north depicting the location of proposed pipeline construction operations, all associated anchor patterns, existing pipelines (both active and inactive), debris fields, or other potential hazards in the area. The plat must be dated, accurate, and indicative of current conditions (including post-hurricane conditions and recent construction or modification activities0; and
(2) Provide copies of the plat to key personnel on all vessels (e.g., pipeline construction vessels, derrick barges, and anchor-handling vessels) associated with your pipeline construction operations.
What must I do to install a hot tap?

To install a hot tap, you must comply with the requirements in the following table:

RequirementWhat you must doDetails
(a) Area inspectionIf you plan to install a hot tap on an existing pipeline located in a water depth less than 200 feet, you must first determine whether proper cover is being maintained on the portion of the pipeline in the vicinity of the proposed work. If you determine that environmental or other factors have detrimentally affected the burial depth of the pipeline(1) Notify the Regional Supervisor within 48 hours after you first observe the problem; and (2) Submit a plan of corrective action under § 250.1097 to the Regional Supervisor within 30 calendar days after you first observe the problem.
(b) Cathodic protection system measurementsIf your pipeline is located in: (1) The AKOCSR; or (2) The GOMR or POCSR, and (i) The pipeline is composed of any pipe that is more than 20 years old; or (ii) The life expectancy of the cathodic protection system cannot be calculatedTake measurements of the pipe-to-electrolyte potential at locations along submerged sections of a pipeline when you conduct hot tap operations on a pipeline.
What must I do to protect a horizontal component?

To protect the horizontal component during construction, you must comply with the requirements in the following table:

Component or activityRequirement
(a) External coatingYou must protect the external coating of the horizontal component during construction.
(b) Cathodic protection systemYou must locate and install the components of the cathodic protection system in a manner that will minimize the possibility of damage.
(c) BurialYou must bury each pipeline you install in water depths less than 200 feet to a depth of at least three feet below the mud line. On a case-by-case basis, the Regional Supervisor may:
(1) Grant you approval to allow a pipeline to self bury, or allow you to use an alternative method of compliance in accordance with the provisions of § 250.141; or
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(2) Require you to increase the burial depth of a pipeline that will transport a product containing H2 S in highly congested or active areas.
(d) Other protective measuresThe Regional Supervisor may require burial or other protection of the pipeline in any water depth if the Regional Supervisor determines that such measures will reduce the likelihood of environmental degradation, or mitigate a potential hazard to trawling operations or other uses of the OCS.
(e) Burial in fairways and anchorage areasYou must consult with the U.S. Army Corps of Engineers as they may have more stringent burial requirements for pipelines that enter or cross safety fairways or anchorage areas.
(f) SpanningYou must provide sufficient supports, or use other mitigation measures (e.g., installing strakes), to avoid excessive loads or deformations and fatigue damage that could result from spanning.
What must I do to protect a riser?

To protect a riser during construction, you must comply with the requirements in the following table:

You must have . . .and you must . . .
(a) External coatingProtect the external coating of the riser during construction.
(b) Cathodic protection systemLocate and install the components of the cathodic protection system in a manner that will minimize the possibility of damage.
(c) Vortex induced vibration (VIV) suppression devicesProtect any preinstalled VIV suppression devices during construction.
(d) Impact protection(1) Protect a pipeline riser from physical damage that could result from contact with floating vessels by using riser guards or other protection measures that are capable of transferring impact loads to the platform structure; and
(2) Not use pipe-in-pipe configurations as riser impact protection.
What must I do to protect an appurtenance and crossing?

(a) Protection methods. You must protect all pipeline valves, taps, tie-in assemblies, capped pipelines, flanges, crossings, and repaired sections installed in water depths less than 500 feet with at least 3 feet of cover or with a protective device (e.g., cement mats, cages) unless an alternate procedure is otherwise approved by the Regional Supervisor in accordance with the provisions of § 250.141.

If you . . .You must . . .
(1) Bury the appurtenance or crossingMaintain the three-foot burial depth throughout the life of the pipeline, including after the pipeline has been decommissioned in place.
(2) Use a protective deviceDesign it to be compatible with other uses of the OCS. The height and the slope of the device must allow for a smooth transition over the appurtenance or crossing.

(b) Separation. You must install the pipeline in a manner that:

(1) Provides for a separation of at least 12 inches for the life of the pipeline at pipeline crossings, power cable crossings, etc.; and

(2) Prevents physical contact with existing umbilicals and communication cables.

(c) Existing pipelines. If you plan to install a pipeline that will tie into or cross an existing pipeline, you must examine the portion of the existing pipeline in the vicinity of the proposed tie-in or crossing. If you determine that environmental or other factors have detrimentally affected the burial depth of the pipe or any appurtenance, any protective cover of the pipe (in water depths less than 200 feet), or any protective cover for any appurtenance (in water depths less than 500 feet), you must notify the Regional Supervisor. The Regional Supervisor may require the responsible party to submit a plan of corrective action (under § 250.1097) to remedy the problem.

(d) Atmospheric zone. You must protect valves and fittings exposed to the atmosphere with a suitable coating.

What must I do to construct a pipeline in or near a designated use area?

If you construct a pipeline in or near a designated use area, you must follow the requirements in the following table. Pipeline construction operations include the use of anchors, chains, and wire ropes.

If your pipeline construction operations . . .Then . . .
(a) Are conducted in or near a designated military warning or water test areaYou must: (1) Assume all risks of damage to property, or injury to persons you employ or who are otherwise connected with your pipeline construction operations, that is caused by any act or omission, regardless of negligence or fault, resulting from the programs or activities of the military installation exercising jurisdiction over the military warning or water test area;
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(2) Indemnify and hold harmless the United States against all claims for loss, damage, or injury sustained by persons you employ, or who are otherwise connected with your pipeline construction operations, that are caused by any act or omission, regardless of negligence or fault, resulting from the programs or activities of the military installation exercising jurisdiction over the military warning or water test area;
(3) Control your electromagnetic emissions in accordance with the requirements specified by the commander of the military installation that has jurisdiction over the military warning or water test area to the degree necessary to prevent damage to, or interference with, Department of Defense flight, testing, or operations; and
(4) Enter into an agreement with the commander of the individual command headquarters when you operate, or cause to be operated on your behalf, a boat, ship, or aircraft in a military warning or water test area. Such an agreement must provide for the positive control of boats, ships, and aircraft operating in the military warning or water test area at all times.
(b) Will be in a designated lightering zone (see 33 CFR 156.300) or traditional lightering area in the Gulf of MexicoYou must contact representatives of the Industry Taskforce on Offshore Lightering to discuss potential conflicts between your pipeline construction operations and the lightering activities in these zones and areas.
(c) Could be in a designated safety fairway or anchorage area, in a safety or security zone, or near a deepwater portThe operations are subject to the prohibitions, restrictions, procedures, and other requirements contained in applicable U.S. Coast Guard regulations (see 33 CFR part 166 for fairways and anchorage areas, 33 CFR part 165 for safety and security zones, and 33 CFR part 150 for deepwater ports).
(d) Are in the vicinity of a State-established artificial reefYou must: (1) Contact the appropriate State natural resource agency or artificial reef coordinator; and
(2) Ensure that the pipeline route is not within 1000 feet, or other distance specified by the Regional Supervisor, from the perimeter of the artificial reef area.
(e) Could disturb the sea floor in or near an area that was used until 1970 by the Department of Defense as an ordnance dumping areaYou must consider the area as potentially hazardous and take appropriate and necessary precautions.
(f) Are in the vicinity of any U.S. Air Force communication towers in the Gulf of MexicoYou must ensure that: (1) The construction vessel and any support vessels do not move within: (i) A 500-foot radius of the center of a tower site; and (ii) 100 feet of the centerline of a line of sight between a master tower and a remote tower; and (2) Your electromagnetic transmissions do not interfere with the operation of the towers.
What must I do to construct a pipeline in or near a sensitive biological feature or area?

If you construct a pipeline in or near a biological feature or area, you must follow the requirements in the following table. Pipeline construction operations include the use of anchors, chains, and wire ropes.

If your pipeline construction operations could . . .Then . . .
(a) Disturb seafloor areas in water depths greater than 1,312 feetYou must: (1) If required by the Regional Supervisor, obtain appropriate high-resolution geophysical data of chemosynthetic communities in the area of pipeline construction operations to accurately identify and locate the features to prepare the required submittals (e.g., bathymetry map, survey report);
(2) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire ropes, appurtenance installation, and the pipeline) at least 250 feet from any identified features or areas that could support high-density chemosynthetic communities; and
(3) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that any seafloor disturbances do not occur within 250 feet of such features of areas.
(b) Disturb the sensitive biological habitats (e.g., coral reefs) associated with an identified topographic featureYou must: (1) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire ropes, appurtenance installation, and the pipeline) at least 500 feet outside the boundary of the designated “No Activity Zone” of such a feature; and (2) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that any seafloor disturbances do not occur within 500 feet of the boundary of the designated “No Activity Zone” of such a feature.
(c) Disturb live bottoms (pinnacle trend features or seamounts) that likely provide habitat for high-density biological assemblagesYou must: (1) If required by the Regional Supervisor, obtain appropriate high-resolution geophysical data or photo-documentation of live bottoms (pinnacle trend features or seamounts) in the area of pipeline construction operations to accurately identify and locate the features and to prepare the required submittals (e.g., bathymetry map, survey report);
(2) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire ropes, appurtenance installation, and the pipeline) at least 100 feet from the identified live bottoms; and
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(3) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that any seafloor disturbances do not occur within 100 feet of the live bottoms.
(d) Disturb live bottoms (low relief features) that likely provides habitat for sea grasses; aggregated fishes, turtles, or other fauna; or coral community organismsYou must: (1) If required by the Regional Supervisor, obtain appropriate high-resolution geophysical data or photo documentation of live bottoms (low relief features) in the area of operations to accurately identify and locate the features to prepare the required submittals (e.g., bathymetry map, survey report);
(2) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire ropes, appurtenance installation, and the pipeline) to avoid impacting the identified live bottoms; and
(3) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that you do not adversely impact the live bottoms.
(e) Disturb potentially sensitive biological features, as determined from your analysis or review of survey informationYou must: (1) Locate all seafloor disturbances (including those caused by anchors, anchor chains, wire ropes, appurtenance installation, and the pipeline) to avoid impacting the potentially biological sensitive features; and
(2) Use a state-of-the-art primary navigation system (e.g., DGPS) on your pipeline construction vessel and anchor-handling vessels to ensure that you do not adversely impact the potentially sensitive biological features.
(f) Adversely affect a marine sanctuary established by the Secretary of Commerce under the authority of section 302 of the Marine Protection, Research and Sanctuaries Act of 1972, as amended (16 U.S.C. 1432)Marine sanctuaries are subject to the prohibitions, restrictions, procedures, and other requirements contained in 15 CFR part 922.
What must I do to construct a pipeline in or near an archaeological resource?

If you construct a pipeline in or near an archaeological resource, you must follow the requirements in the following table. Pipeline construction operations include the use of anchors, chains, and wire ropes.

If . . .You must . . .
(a) An archaeological resource is known to exist, or the Regional Director has reason to believe that an archaeological resource may exist, in the area of the proposed pipeline construction operationsObtain appropriate high-resolution geophysical data in the area of operations to accurately identity and locate the existing or potential archaeological resources to prepare a survey report. The Regional Supervisor will specify the survey area, instrumentation, and methodology.
(b) The review by the Regional Supervisor of the archaeological report included with your pipeline application (see § 250.1026(c)) concludes that an archaeological resource may be presentEither: (1) Locate the site of your pipeline construction operations to avoid the potential archaeological resource by at least the distance specified by the Regional Supervisor; or (2) Establish to the satisfaction of the Regional Director that an archaeological resource either does not exist or will not be adversely affected by your pipeline construction operations. In making this determination, the Regional Director may require you to conduct further archaeological investigations, using personnel, equipment, and techniques the Regional Director considers appropriate. You must submit the investigation report to the Regional Director for review.
(c) Based on further archaeological investigations, the Regional Director will notify you immediately if it's determined that the archaeological resource exists and may be adversely affected by your pipeline construction operationsNot take any action that may adversely affect the archaeological resource until the Regional Director has told you how to protect it.
(d) You discover a potential archaeological resource while conducting your pipeline surveys, pipeline construction operations, or any other activity related to the pipelineImmediately halt all seafloor disturbing operations within the area of the discovery and notify the Regional Director of the discovery within 72 hours. If the site was impacted by your operations, or if impacts to the site or to the area cannot be avoided, the Regional Director will specify the additional investigations you must conduct to determine if the resource is potentially eligible for listing to the National Register of Historic Places under criteria established by 36 CFR 60.4. If these investigations determine that the resource is potentially eligible for listing in the National Register of Historic Places, the Regional Director will tell you how to protect the resource, or how to mitigate adverse impacts to the site.
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When must I prepare and implement an H2 S contingency plan for construction?

You must prepare an H2 S Contingency Plan before you construct a pipeline (using an anchor-supported construction vessel) that crosses a pipeline which transports a product with an H2 S concentration that, if released, could result in atmospheric concentrations of 20 ppm or more. The H2 S Contingency Plan must be in accordance with § 250.490(f) and cover your pipeline construction operations. You must:

(a) Implement this H2 S Contingency Plan before the leading construction vessel anchors are placed within 3,000 feet of the crossed pipeline, and maintain it in effect until no trailing construction vessel anchors are within 3,000 feet of the crossed pipeline; and

(b) Keep a copy of the H2 S Contingency Plan on the pipeline construction vessel.

What information must I submit after construction is completed?

(a) Construction report. You must submit three copies of a pipeline construction report to the Regional Supervisor within 45 calendar days after you complete pipeline construction. The construction report must include:

(1) The MMS-assigned pipeline segment number.

(2) The dates you started and concluded pipeline construction operations.

(3) An “as built” location plat, based on NAD 27 for the GOMR (Gulf) and POCSR, or NAD 83 for the AKOCSR and GOMR (Atlantic), drawn at a minimum scale of 1 inch = 2,000 feet that:

(i) Depicts the same information you included with your pipeline application (see § 250.1017(a) and (b));

(ii) Includes a list of the latitude and longitude coordinates in both NAD 27 and NAD 83, and the X-Y coordinates in NAD 27 for the GOMR (Gulf) and POCSR, or NAD 83 for AKOCSR and GOMR (Atlantic), of all key points;

(iii) Depicts the boundaries of the pipeline ROW, as granted, if applicable; and

(iv) Includes a certification by a registered engineer or land surveyor that attests to the accuracy of the “as-built” locations of the pipeline and appurtenances.

(4) An electronic file containing the digital coordinates of the key points of the “as-built” pipeline and umbilical routes, including turns, and, if required by the Regional Supervisor, the position of lay barge anchors, chains, and cables. The digital data must be in decimal degrees latitude and longitude and based on NAD 83.

(5) Discussion of the reasons for deviation if the pipeline route deviates from the route in your approved application by more than 200 feet.

(6) The type, size, weight, number, and spacing of any anodes that were installed on the pipeline, if the information differs substantially from the information you provided in your approved pipeline application.

(7) A description of the protective covering, anchor pins, or sand bags you used to install or protect a valve, tap, subsea tie-in, capped line, or other appurtenance, if the installation differs substantially from the design you provided in your approved pipeline application.

(8) The pipe-to-electrolyte potential readings for hot taps required by § 250.1043(b).

(9) A report of the hydrostatic pressure test (see § 250.1061) required by § 250.1060(a)(1).

(10) A plat at a scale of 1 inch = 1,000 feet (or other scale required by the Regional Supervisor) that depicts bathymetry, any biologically-sensitive or archaeological feature (if applicable), and the position of all anchors, chains, and cables, if the pipeline or the associated anchors, chains, or cables are:

(i) Located in the POCSR or AKOCSR; or

(ii) Located in the GOMR, and if they are within:

(A) 500 feet of the “No Activity Zone” of an identified topographic feature or other biologically-sensitive feature;

(B) 100 feet of any live bottom (pinnacle trend feature or seamount) with a vertical relief of eight feet or more;

(C) 100 feet of any live bottom (low relief feature); or

(D) A distance specified by the Regional Supervisor of any potential archaeological resource.

(b) MMS actions. The Regional Supervisor will review your pipeline construction report and inform you in writing of any deficiencies if the report is unacceptable.

(c) National Ocean Service (NOS). You must submit a copy of the “as-built” location plat required by paragraph (a)(3) of this section to the NOS within 45 calendar days after you complete pipeline construction.

Pipeline Risers Connected To Floating Platforms
What are the requirements for pipeline risers connected to floating platforms?

(a) General. New pipeline risers and major modifications of, or repairs to, existing risers connected to floating platforms are subject to the Pipeline Riser Verification Program. A major modification or major repair to a pipeline riser means:

(1) The replacement, removal, or repair of any material, component, or appurtenance;

(2) Any reconfiguration or external event that could affect the design life of the riser; or

(3) Any operation on the riser that involves welding.

(b) Verification requirements. All pipeline risers subject to the Pipeline Riser Verification Program must undergo design verification, fabrication verification, and installation verification.

(c) Certified Verification Agent (CVA). All pipeline risers subject to the Pipeline Riser Verification Program require separate verification that necessitates the use of a CVA specifically for the pipeline riser.

(d) CVA qualifications. (1) Your design verification must be conducted by, or be under the direct supervision of, a registered professional civil or structural engineer or equivalent with previous experience in directing the design of similar risers.

(2) Your fabrication verification must be conducted by qualified personnel with previous experience in third-party fabrication verification or experience in the fabrication of similar risers.

(3) Your installation verification must be conducted by qualified personnel with previous experience in third-party installation verification or experience in the installation of similar risers.

(e) CVA responsibilities. (1) The CVA must conduct the activities specified in §§ 250.1054, 250.1055, and 250.1056.

(2) The CVA must consider the provisions of applicable regulations, codes, guides, standards, recommended practices, approved plans, and the requirements of this subpart when performing riser verification.

(3) Individuals or organizations acting as CVA's must not function in any capacity that would create a conflict of interest, or the appearance of a conflict of interest.

(4) The CVA is the contact with the Regional Supervisor regarding all riser verification and reporting. The CVA is directly responsible for providing immediate reports to the Regional Supervisor of all incidents that affect the design, fabrication, and installation of pipeline risers.

What are the requirements for pipeline riser verification plans?

(a) Design verification plan. You must submit a design verification plan to the Regional Supervisor for approval before Start Printed Page 56487the design work is completed, before you start fabrication and installation, and at least 30 calendar days before you submit the associated pipeline application. You must submit a separate design verification plan for each pipeline riser. Your design verification plan must include:

(1) Riser diameter, service, type, and designer(s);

(2) A project management timeline (Gantt Chart) that depicts key design activities and when the CVA will submit the interim and final reports required by § 250.1054(c) and (d);

(3) Abstracts of the computer programs that will be used in design verification;

(4) A summary of major design considerations and the approach that will be used to verify the validity of these design considerations; and

(5) The CVA nomination information specified in paragraph (d) of this section.

(b) Fabrication verification plan. You must submit a fabrication verification plan to the Regional Supervisor for approval before you start fabrication and at least 30 days before you submit the associated pipeline application. You must submit a separate fabrication verification plan for each pipeline riser. Your fabrication verification plan must include the following:

(1) Riser diameter, service, and type;

(2) A project management timeline (Gantt Chart) that depicts key fabrication activities and when the CVA will submit the interim and final reports required by § 250.1055(d) and (e);

(3) A summary of major fabrication considerations and the approach that will be used to verify the validity of these fabrication considerations; and

(4) The CVA nomination information specified in paragraph (d) of this section.

(c) Installation verification plan. You must submit an installation verification plan to the Regional Supervisor at least 30 days before you submit the associated pipeline application. You must submit a separate installation verification plan for each pipeline riser. Your installation verification plan must include the following:

(1) Riser diameter, service, and type;

(2) A project management timeline (Gantt Chart) that depicts key installation activities and when the CVA will submit the interim and final reports required by § 250.1056(d) and (e);

(3) Abstracts of the computer programs that will be used in installation verification;

(4) A summary of major installation considerations and the approach to be used to verify the validity of these installation considerations; and

(5) The CVA nomination information specified in paragraph (d) of this section.

(d) CVA nomination information. (1) As part of your design verification, fabrication verification, and installation verification plans, you must include nominations for your proposed CVA's for the Regional Supervisor's approval.

(2) For each nomination, you must provide a qualifications statement that includes the following information:

(i) Whether the nomination is for the design, fabrication, or installation phase of verification, or for any combination of these phases;

(ii) Experience in the design, fabrication, or installation of similar risers;

(iii) Experience in third-party verification, inspection, or auditing of similar risers;

(iv) Resumes of key personnel and their responsibilities;

(v) Size and type of organization or corporation;

(vi) In-house availability of, or access to, appropriate technology, including computer programs, hardware, and testing materials and equipment;

(vii) Ability to perform the CVA functions for the specific project considering current commitments; and

(viii) Previous experience with MMS requirements and procedures.

(e) Modifications. Submit modifications to your verification plans, including changes in the CVA and key personnel, to the Regional Supervisor for approval.

What must the CVA do to verify pipeline riser design?

The riser design CVA must use good engineering judgment and practices while conducting an independent verification of the design of the riser. The CVA must ensure that the riser is designed to withstand the environmental and functional load conditions appropriate for the intended design life of the riser at the proposed location. The pipeline riser design CVA must verify information, conduct analyses, and submit design reports as required by paragraphs (a) through (d) of this section.

(a) The CVA must verify the following:

(1) Planning criteria, including the design basis;

(2) Operational requirements;

(3) Environmental loading data;

(4) Soil conditions;

(5) Safety factors;

(6) Material and component specifications;

(7) Cathodic protection design and riser coating;

(8) Interference analysis;

(9) Input for the design of vendor components, such as specialty joints and connectors;

(10) Vortex-induced vibration (VIV) suppression system to ensure that specifications for installation and design meet required suppression efficiency;

(11) Welding specifications to ensure that they are appropriate and adequate for the design and inspection of the riser;

(12) Preliminary installation analysis;

(13) Provisions to account for marine growth and associated cleaning recommendations;

(14) Recommendations on in-service inspection frequency; and

(15) Other pertinent parameters of the proposed design.

(b) The CVA must perform independent analyses of the following:

(1) Riser design cases with appropriate load conditions, as specified in API RP 2RD (incorporated by reference as specified in § 250.198), including, but not limited to, operation, shut-in, and extreme;

(2) Riser stresses, including extreme storm response for critical design conditions; and

(3) Riser fatigue of selected cases that consider VIV, wave frequency fatigue analysis, vortex-induced motion (VIM), thermal and pressure cycles, riser interaction with seabed (touchdown zone), fatigue due to internal corrosion (if sour service), and other applicable concerns and issues.

(c) The CVA must submit interim design reports to the Regional Supervisor at intervals approved in your design verification plan. The CVA must include the following in each interim design report:

(1) Details of how, by whom, and when the design verification activities were conducted to date;

(2) Description of the CVA's activities during design verification to date;

(3) Summary of the CVA's findings to date;

(4) Description of any outstanding or notable issues found on the riser design to date; and

(5) A Gantt chart showing project progress.

(d) The CVA must submit a final design report to the Regional Supervisor before fabrication begins and either within 90 calendar days after receipt of the design data, or within 90 calendar days after MMS approves the design verification plan, whichever is later. The CVA must submit a separate final design report for each pipeline riser. The CVA must include the following in the final design report:Start Printed Page 56488

(1) Riser diameter, service, type, and designer(s);

(2) Details of how, by whom, and when the design verification activities;

(3) Description of the CVA's activities during design verification;

(4) Summary of the CVA's findings;

(5) Confirmation of compliance with the design specifications;

(6) Recommendation to accept or reject the riser design; and

(7) Any additional information and comments that the CVA deems necessary including, but not limited to:

(i) Design basis;

(ii) Summary of design CVA scope;

(iii) Key drawings;

(iv) Summary of input and output from the independent analyses performed;

(v) Comparison between results of the original design analyses and the CVA design analyses;

(vi) In-service inspection frequency and inspection method recommendations; and

(vii) Cleaning recommendations.

What must the CVA do to verify pipeline riser fabrication?

The riser fabrication CVA must use good engineering judgment and practices while conducting an independent verification of the fabrication activities. The CVA must monitor the fabrication of the riser to ensure that it has been built according to the approved design and fabrication plans. If the CVA finds that fabrication procedures are changed or design specifications are modified, the CVA must inform you. If you accept the modifications, then the CVA must notify the Regional Supervisor. The pipeline riser fabrication CVA must make inspections, witness activities, perform spot checks and submit fabrication reports as required by paragraphs (a) through (e) of this section.

(a) The CVA must make periodic onsite inspections while fabrication is in progress and verify the following fabrication items, as appropriate:

(1) Quality assurance and quality control programs;

(2) Adequacy of fabrication site facilities;

(3) Material quality and identification methods;

(4) Fabrication procedures specified in the approved plan, and adherence to such procedures;

(5) Welder and welding procedures qualification and identification;

(6) Dimensional tolerances specified, and adherence to those tolerances;

(7) Nondestructive examination (NDE) requirements, and evaluation results of the specific examinations;

(8) Destructive testing requirements and results;

(9) Repair procedures;

(10) Installation of corrosion protection systems and splash-zone protection; and

(11) Status of quality assurance and quality control records at various stages of fabrication.

(b) The CVA must witness:

(1) Factory Acceptance Testing (FAT) of vendor components; and

(2) Welding of specialty joint to riser material.

(c) The CVA must perform spot checks as necessary to determine compliance with applicable regulations, codes, guides, standards, recommended practices, and approved plans.

(d) The CVA must submit interim fabrication reports to the Regional Supervisor at intervals approved in your verification plan. The CVA must include the following in each interim fabrication report:

(1) Details of how, by whom, when, and where the fabrication verification activities were conducted to date;

(2) Description of the CVA's activities during fabrication verification to date;

(3) Summary of the CVA's findings to date;

(4) Description of any outstanding or notable riser design issues found to date; and

(5) A Gantt chart showing project progress.

(e) The CVA must submit a final fabrication report to the Regional Supervisor within 90 calendar days after completion fabrication, but before the beginning of pipeline installation. The CVA must submit a separate final fabrication report for each pipeline riser. The CVA must include the following in the final fabrication report;

(1) Riser diameter, service, and type;

(2) Details of how, by whom, when, and where the fabrication verification activities were conducted;

(3) A description of the CVA's activities during fabrication verification;

(4) A summary of the CVA's findings;

(5) Confirmation of compliance with the design specifications and the approved fabrication plan;

(6) Recommendations to accept or reject the fabrication; and

(7) Any additional information and comments that the CVA deems necessary, including:

(i) Summary of fabrication scope;

(ii) Welding program details;

(iii) NDE program details, including acceptance criteria and evaluation results;

(i) Dimensional control adherence;

(v) The inspection report of the FAT of vendor components; and

(vi) Quality assurance and quality control program details.

What must the CVA do to verify pipeline riser installation?

The pipeline riser CVA must use good engineering judgment and practice in conducting an independent verification of the installation activities. The CVA must monitor the installation of the riser to ensure that it has been built according to the approved design and installation plans. If the CVA finds that installation procedures are changed or design specifications are modified, the CVA must inform you. If you accept the modifications, the CVA must notify the Regional Supervisor. The pipeline riser installation CVA must verify compliance, perform spot checks, and submit fabrication reports as required by paragraphs (a) through (e) of this section.

(a) The CVA must verify the:

(1) Quality assurance and quality control program;

(2) Adequacy of installation vessel(s) and equipment;

(3) Material quality and identification methods;

(4) Installation procedures specified in the approved installation plan, and adherence to such procedures;

(5) Welder and welding procedures qualification and identification;

(6) Dimensional tolerances specified, and adherence to those tolerances;

(7) NDE requirements, and evaluation results of the specified examinations;

(8) Repair procedures;

(9) Installation test data;

(10) Installation of corrosion protection systems and splash-zone protection;

(11) Installation of VIV suppression devices as specified in the approved design, and adherence to such design; and

(12) Status of quality assurance and quality control records at various stages of installation.

(b) The CVA must perform spot checks as necessary to determine compliance with applicable regulations, codes, guides, standards, recommended practices, and approved plans.

(c) The CVA must witness the:

(1) Pipe load-out at the shore base; and

(2) Riser installation operations.

(d) The CVA must submit interim installation reports to the Regional Supervisor at intervals approved in your verification plan. The CVA must include the following in each interim installation report:

(1) Details of how, by whom, when, and where the installation verification activities were conducted to date;Start Printed Page 56489

(2) Description of the CVA's activities during installation verification to date;

(3) Summary of the CVA's findings to date;

(4) Description of any outstanding or notable riser design issues found to date; and

(5) A Gantt chart showing project progress.

(e) The CVA must submit a final installation report to the Regional Supervisor within 45 calendar days after installation of the pipeline. The CVA must submit a separate installation report for each pipeline riser. The CVA must include the following in the final installation report:

(1) Riser diameter, service, and type;

(2) Details of how, by whom, when, and where the installation verification activities were conducted;

(3) A description of the CVA's activities during installation verification;

(4) Summary of the CVA's findings;

(5) Confirmation of compliance with the design specifications and the approved installation plan;

(6) A recommendation to accept or reject the installation; and

(7) Any additional information and comments that the CVA deems necessary, including:

(i) Summary of installation scope;

(ii) Welding program details, including weld maps;

(iii) NDE program details, including acceptance criteria and evaluation results;

(iv) Dimensional control adherence;

(v) Quality assurance and quality control program details;

(vi) Incidents that occurred during installation; and

(vii) As-built drawings.

Pipeline Pressure Testing
What are the general requirements for pressure testing a pipeline?

You must pressure test a pipeline in a manner that:

(a) Verifies that the pipeline has the requisite structural integrity to withstand normal and maximum operating pressures, and is capable of product containment;

(b) Ensures that the test equipment is properly selected and in good working order; and

(c) Uses work practices and procedures that reduce hazards to personnel and equipment, and protect the environment.

What are the requirements for conducting a hydrostatic pressure test for a pipeline?

(a) Purpose. A hydrostatic pressure test must test the tensile strength of a pipeline by pressuring up the pipeline with water.

(b) Notification. You must notify the Regional Supervisor, using Form MMS-153 (Notification of Pipeline Installation/Relocation/Hydrotest), at least 48 hours before you conduct a hydrostatic pressure test on a pipeline.

(c) Equipment. During a hydrostatic pressure test, you must:

(1) Measure the test fluid temperature and the test fluid pressure using synchronized temperature and pressure recorders; and

(2) Use pressure gauges and recorders that are sufficiently accurate to determine whether the pipeline is leaking during the test.

(d) Procedures. When you conduct a hydrostatic pressure test, you must:

(1) Test the pipeline (including the riser(s)) at a minimum stabilized pressure of at least 125 percent of the MAOP for the length of time specified in § 250.1060(a), (b), or (c);

(2) Take deadweight test readings and record the reading, time, and reason for any pressure fluctuations at intervals no greater than 30 minutes; and

(3) Use a test pressure that will not produce a stress in the pipeline in excess of 95 percent of the specified minimum-yield strength of the pipe.

(e) Successful test. A successful hydrostatic pressure test means that there was no observable leakage, and a stabilized pressure was maintained for the last 2 hours of the test.

(f) Discharging test medium. You must dispose of the test medium in accordance with applicable laws and regulations.

What are the requirements for leak testing a pipeline?

(a) Conducting a leak test. When you conduct a leak test, you must:

(1) Use a stabilized pressure that is capable of detecting all leaks;

(2) Use pressure gauges and recorders that are sufficiently accurate to determine whether the pipeline is leaking during the test; and

(3) Conduct the test for at least two hours during daylight.

(b) Successful leak test. A leak test must successfully test the integrity of a pipeline. A successful leak test means no observable leakage during the test period.

When must I perform a pressure test on a pipeline?

(a) Hydrostatic pressure test. After you install the pipeline, you must successfully perform an 8-hour hydrostatic pressure test of a pipeline (including the riser(s)) before you:

(1) Put a new pipeline into service;

(2) Put a relocated pipeline into service;

(3) Put a pipeline with an increased MAOP into service;

(4) Reactivate a pipeline that was out of service for more than one year;

(5) Re-commission a pipeline that was decommissioned; or

(6) Re-activate a pipeline that was modified by adding new pipe (except in the case of a pipeline repair using a spool piece that complies with paragraph (c) of this section).

(b) Pressure test after repair using a clamp. Before you return a pipeline to service following a repair using a clamp:

If you completed the repair using a . . .You must successfully perform . . .
(1) Mechanical clampA leak-test of the pipeline (including riser(s)) or, if required by the Regional Supervisor, an 8-hour hydrostatic pressure test of the pipeline (including riser(s)).
(2) Welded clampAn 8-hour hydrostatic pressure test of the pipeline (including riser(s)).

(c) Pressure test after repair using a spool piece. Before you return a pipeline to service following a repair using a spool piece you must meet the requirements in the following table:

After you install the spool piece, if . . .You must successfully perform . . .
(1) You connected the spool piece using flangesA 4-hour hydrostatic pressure bench test of the spool piece, and a leak test of the pipeline (including riser(s)).
Start Printed Page 56490
(2) The spool piece is visible during the test and is not connected using flangesA 4-hour hydrostatic pressure test of the pipeline (including riser(s)), and a non-destructive test (i.e., x-rays) of the connections.
(3) The spool piece is not visible during the testAn 8-hour hydrostatic pressure test of the pipeline (including riser(s)).

(d) Directed pressure test. The Regional Supervisor may require you to pressure test a pipeline to verify its integrity whenever the Regional Supervisor determines that there is a reasonable likelihood that the pipeline was damaged or weakened by external or internal conditions. When so directed, you must submit the results of these tests to the Regional Supervisor (see § 250.1061).

What information must I include in a pressure test report?

(a) Hydrostatic pressure test. You must submit the results of the hydrostatic pressure test in conjunction with the reports required by §§ 250.1051(a)(9), 250.1060(d), 250.1086(g)(5), 250.1093(g)(5), 250.1095(e)(6), and 250.1113(b)(5). The pressure test report must include:

(1) Test description;

(2) Pressure and temperature charts;

(3) Instrument calibration data;

(4) Minimum and maximum pressure calculations;

(5) Deadweight pressure test readings and temperature log;

(6) Record of problems encountered during the test including their causes and corrective actions taken; and

(7) Documentation of any factors that affected pressures or temperatures.

(b) Leak test. You must submit the pressure and temperature charts of any required leak test in conjunction with the report required by § 250.1095(e)(7).

Pipeline Safety Equipment
What are the general requirements for pipeline safety equipment?

You must provide each pipeline with safety equipment that:

(a) Prevents or minimizes the consequences of overpressure, leaks, and failures;

(b) Protects personnel and the environment;

(c) Considers the need to limit surge pressures and other deviations from normal operations; and

(d) Is properly installed, operated, and maintained.

What are the safety equipment requirements for a departing pipeline?

(a) Departing pipeline means a pipeline that receives:

(1) Production from a production, boosting, compressor, or manifold platform; a subsea well, manifold, or other facility; or an incoming pipeline;

(2) Gas-lift gas;

(3) Supply gas; or

(4) Water, fuel, or chemicals.

(b) You must comply with the safety requirements for a departing pipeline in the following table:

Safety equipmentRequirements
(1) Pressure safety high and low (PSHL) sensorsYou must protect a departing pipeline with PSHL sensors that directly or indirectly shut in all delivering sources.
(2) PSHL sensor settings(i) You must set the PSHL sensors required by paragraph (a) of this section to activate at pressures that are no more than 15 percent above and below the limits of the normal operating pressure range of the pipeline. (ii) For pipelines that transport a product containing H2 S, you must set the pressure safety low (PSL) sensor to activate at a pressure that is no more than 10 percent below the lower limit of the normal operating pressure range of the pipeline. (iii) For a departing pipeline that receives production from a subsea well, you may set the pressure safety high (PSH) sensor to activate at a pressure that is up to 5 percent above the latest recorded wellhead shut-in tubing pressure. (iv) You must not set the PSH sensor to activate at a pressure greater than the MAOP of the pipeline. (v) You must not set the PSH sensor to activate at a pressure within 5 percent of the pressure safety valve (PSV) set point.
(3) PSHL sensor settings determination(i) You must determine the sensor settings required by paragraph (b) of this section by using a pressure recorder to establish the current normal operating pressure range. You must keep the most current pressure recorder charts at the nearest OCS facility, and make them available for inspection by MMS upon request. (ii) For a departing pipeline that receives production from a subsea well, you must use well test records to determine the sensor settings. You must keep the most recent well test records at the nearest OCS facility, and make them available for inspection by MMS upon request.
(4) Flow safety valve (FSV) and shutdown valve (SDV)The Regional Supervisor may require you to equip or otherwise protect a departing pipeline with an FSV and/or an automatic SDV.
(5) Subsea tie-inYou must equip the originating end of all departing pipelines that receive production from a connecting pipeline at a subsea tie-in with a block valve and an FSV.
What are the safety equipment requirements for an incoming pipeline?

(a) Incoming pipeline means a pipeline that delivers:

(1) Production to a production, booster, or compressor platform;

(2) Gas-lift gas to a well, manifold platform, or to another pipeline at a subsea tie-in;

(3) Supply gas; or

(4) Water, fuel, or chemicals.

(b) You must comply with the safety equipment requirements for an incoming pipeline in the following table:

Safety equipmentRequirements
(1) FSVYou must protect an incoming pipeline with an FSV to prevent backflow.
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(2) SDVYou must equip an incoming pipeline, except a water pipeline, that boards a production platform or manned platform (a platform that has personnel on board 24 hours per day, or on which personnel are quartered overnight) with an automatic SDV that: (i) Is actuated by the platform's automatic- and remote-emergency shut-in systems; (ii) Is located immediately upon boarding the platform. If the SDV is on a horizontal section, you must locate it in an unclassified area (classified area is defined in API RP 500 and API RP 505; both documents are incorporated by reference in § 250.198) and no more than 10 feet from the boarding pipeline riser. This requirement applies only to pipelines installed or modified after [INSERT THE EFFECTIVE DATE OF THE RULE]; and (iii) Closes within 45 seconds after it is actuated.
(3) Gas-lift pipelineThis paragraph applies to an existing incoming gas-lift pipeline installed before [INSERT THE DATE SIX MONTHS AFTER THE EFFECTIVE DATE OF THE RULE] to an unmanned minor platform. (A minor platform is one that contains fewer than six well completions or fewer than two pieces of production equipment). In lieu of complying with paragraphs (b)(1) and (b)(2) of this section, you may protect the pipeline with an FSV located either: (i) Immediately upstream of each casing annulus; or (ii) Immediately upstream of the first inlet valve on the wellhead.
(4) Subsea tie-inYou must equip the terminating end of an incoming pipeline that delivers production to a connecting pipeline at a subsea tie-in with a block valve and an FSV.
What are the safety equipment requirements for a crossing pipeline?

(a) A crossing pipeline means a pipeline that crosses a platform but does not receive or deliver production to that platform. A crossing pipeline includes both the incoming and departing pipeline segments.

(b) You must comply with the safety requirements for a crossing pipeline in the following table:

Safety equipmentRequirements
(1) FSVYou must protect a crossing pipeline installed after [INSERT THE EFFECTIVE DATE OF THE RULE] that crosses an unmanned or non-production platform with an FSV to prevent backflow.
(2) SDVYou must equip the terminating end of the incoming segment(s) of a crossing pipeline (except a water pipeline) that crosses a production platform or manned platform (a platform that has personnel on board 24 hours per day, or on which personnel are quartered overnight) with an automatic SDV that: (i) Is operated by a PSHL sensor to protect the departing segment(s) of the crossing pipeline; (ii) Is actuated by the platform's automatic- and remote-emergency shut-in systems; (iii) Is located immediately upon boarding the platform. If the SDV is on a horizontal section, you must locate it in an unclassified area (a classified area is defined in API RP 500 and API RP 505; both documents are incorporated by reference in § 250.198) and no more than 10 feet from the boarding pipeline riser. This requirement applies only to pipelines installed or modified after [INSERT THE EFFECTIVE DATE OF THE RULE]; and (iv) Closes within 45 seconds after it is actuated.
What are the safety equipment requirements for a bi-directional pipeline?

(a) Bidirectional pipeline means a pipeline designed and configured to transport fluids in either direction.

(b) You must comply with the safety equipment requirements for a bi-directional pipeline in the following table:

Safety equipmentRequirements
(1) PSHL sensorsYou must protect both ends of a bi-directional pipeline with PSHL sensors that directly or indirectly shut in all delivering sources. Requirements for the setting levels of the PSHL sensors are specified at §§ 250.1063(b)(2) and (3).
(2) Automatic SDVYou must equip both ends of a bi-directional pipeline with an automatic SDV that: (i) Is actuated by the platform's automatic- and remote-emergency shut-in systems; (ii) Is located immediately upon boarding the platform. If the SDV is on a horizontal section, you must locate it in an unclassified area (a classified area is defined in API RP 500 and API RP 505, both documents incorporated by reference as specified in § 250.198) and no more than 10 feet from the boarding pipeline riser. This requirement applies only to pipelines installed or modified after [INSERT THE EFFECTIVE DATE OF THE RULE]; and (iii) Closes within 45 seconds after it is actuated.
(3) Block valveYou must equip a bi-directional pipeline that connects to a pipeline at a subsea tie-in with a block valve at the tie-in assembly.
When must I provide redundant safety equipment?

(a) If the maximum source pressure (MSP) is from a well, and it exceeds the MAOP of the pipeline, you must protect the pipeline by using either:

(1) One surface safety valve (SSV) controlled by a PSH sensor, and a PSV that relieves in a safe and pollution-free manner; or

(2) Two SSV's controlled by independent PSH sensors connected to separate relays and sensing points.

(b) For pipelines installed after [INSERT THE EFFECTIVE DATE OF THE RULE], if the MSP is from a well, and it is more than 11/2 times the MAOP of the pipeline, you must protect the pipeline by using two SSV's controlled by independent PSH sensors connected Start Printed Page 56492to separate relays and sensing points, and one PSV that relieves in a safe and pollution-free manner.

(c) If the maximum source pressure (MSP) is not from a well, and it exceeds the MAOP of the pipeline, you must protect the pipeline by using either:

(1) One shutdown valve (SDV) controlled by a PSH sensor, and a PSV that relieves in a safe and pollution-free manner; or

(2) Two SDV's controlled by independent PSH sensors connected to separate relays and sensing points.

(d) If you use the configuration specified in paragraph (c)(1) above, you must set the PSV to activate at a pressure between 5 and 10 percent above the MAOP.

What are the safety equipment requirements for a pipeline pump?

(a) General. You must do both of the following:

(1) Protect a pipeline pump according to section A7 of API RP 14C (incorporated by reference as specified in § 250.198). Requirements for setting the levels of the PSHL sensors are specified at § 250.1063(b)(2) and (3).

(2) Set any PSV you installed on the pipeline to protect the pump to activate at a pressure less than the MAOP of the pipeline.

(b) Time delays for pumps. During startup and idle operations, you may apply industry standard Class B, Class C, and Class B/C logic to all PSL sensors installed on pipeline pumps. You do not need a departure approval to use these types of time delay circuitry if the time delay does not exceed 45 seconds. You must obtain a departure approval under the provisions of § 250.142 from the appropriate District Manager before you use a time delay greater than 45 seconds.

(1) Class B logic allows for a PSL sensor on pipeline pumps to be bypassed for a fixed time period (typically less than 15 seconds, but not more than 45 seconds).

(2) Class C logic allows for a PSL sensor to be bypassed until the component comes into full service.

(3) Class B/C logic allows for a PSL sensor to incorporate a combination of Class B and Class C circuitry. This device is used to ensure that a PSL sensor is not unnecessarily bypassed during start-up and idle operations (e.g., Class B/C bypass circuitry activates when a pump is shut down during normal operations). The PSL sensor remains bypassed until the pump start circuitry is activated and either:

(i) The Class B timer expires after 45 seconds from start activation; or

(ii) The Class C bypass is initiated until the pump builds up pressure above the PSL set point and the PSL comes into full service.

(c) PSL Sensors and bypass circuits. When the PSL sensor comes into full service, the PSL sensor is fully active. If the PSL sensor should trip while the pump is running, the pump will shut down and the Class B/C bypass circuit will remain inactive until the safety system devices are cleared and reset.

What must I do if safety equipment fails to operate as intended?

If any safety equipment required by this subpart experiences a failure you must follow the requirements of paragraphs (a) through (e) of this section.

(a) Suspending operations. You must shut in the pipeline immediately.

(b) Out-of-service notification. You must notify the Regional Supervisor:

(1) If the safety equipment remains out of service for more than 12 hours in the GOMR; and

(2) Immediately after the safety equipment is out of service in the POCSR and AKOCSR.

(c) Resuming operations. You may resume operation of the pipeline after you:

(1) Repair the failed safety equipment (see §§ 250.1094 through 1096);

(2) Replace the failed safety equipment (see § 250.1093); or

(3) Provide an equivalent degree of protection and place an appropriate warning sign on the failed safety equipment.

(d) Corrective action notification. If you shut in your pipeline because of a safety equipment failure and were required by paragraph (b) of this section to notify the Regional Supervisor, you must also notify the Regional Supervisor immediately when you repair the safety equipment and resume operating the pipeline, or when you have provided an equivalent degree of protection and resume operating the pipeline.

(e) Repair application. If the corrective action you take to address a safety equipment failure necessitates a repair (see § 250.1094), you must submit a repair application in accordance with § 250.1095(a) and receive approval from the Regional Supervisor before you perform the work.

Pipeline Leak Detection
When do I need to use a leak detection system?

If your pipeline transports liquid hydrocarbons to shore, or if the Regional Supervisor otherwise requires it, you must use a computational pipeline monitoring (CPM) system or equivalent methodology to detect leaks by continuously determining or calculating the imbalance between the incoming (receipt) and outgoing (delivery) volumes of a pipeline. A CPM system means an algorithmic monitoring tool that allows you to respond to a pipeline operating anomaly that may indicate a release of liquid hydrocarbons. You must:

(a) Equip your CPM system with an alarm that signals when the imbalance exceeds a predetermined threshold for a selected time interval; and

(b) Use SCADA technology to gather, process, and display the data you use in your CPM system. SCADA is an acronym for supervisory control and data acquisition, the technology that makes it possible to monitor and control pipelines remotely.

Pipeline Internal Corrosion Control and Flow Assurance
What are the general requirements for internal corrosion control?

You must establish and implement internal corrosion control measures (e.g., running pipeline scrapers; dehydrating; using corrosion inhibitors, bactericides, or oxygen scavengers) to protect the pipeline over its service life.

What are the general requirements for flow assurance?

You must establish and implement measures (e.g., chemical additives, routine pigging) to ensure that adequate flow can be sustained throughout the service life of a pipeline under all expected flow conditions for the range of pressures, temperatures, fluid properties, and phase conditions expected during start up, normal, shut down, and emergency operations.

Pipeline Operations and Maintenance
What are the general requirements for operating and maintaining a pipeline?

You must operate and maintain a pipeline in a manner that:

(a) Protects life, property, and the environment for the service life of the pipeline;

(b) Ensures that all pipelines, appurtenances, and safety equipment are not subjected to operating conditions that exceed applicable design parameters and the MAOP;

(c) Anticipates the detrimental effects of corrosion; product composition; thermal cycling; pressure fluctuations; hydrate, asphaltene, or paraffin formation; sediment transfer or scour (due to wave action and currents); storm or ice scouring; gross seafloor movement (such as mudslides, faults, and subsidence); hurricanes; earthquakes; subfreezing temperatures; and other natural or manmade phenomena;Start Printed Page 56493

(d) Maintains the approved burial depth throughout the life of the pipeline including after the pipeline is decommissioned in place; and

(e) Does not interfere with other uses of the OCS.

What written procedures must I establish before I operate an OCS pipeline?

(a) Operations and maintenance manual. You must prepare a written operations and maintenance manual for your OCS pipelines that complies with the regulations in this subpart and includes provisions for all of the following:

(1) Conducting normal operations;

(2) Conducting periodic surveillance and inspections;

(3) Performing systematic and routine preventive maintenance;

(4) Ensuring that safety system components are functioning properly;

(5) Resuming operations after a storm;

(6) Monitoring and mitigating the effects of internal and external corrosion and erosion;

(7) Monitoring and mitigating the effects of paraffin, wax, and hydrate formation;

(8) Responding to foreseeable abnormal operating conditions, malfunctions, failures, or personnel error; and

(9) Identifying and responding to conditions that could affect safe operations.

(b) Integrity management program. You must have a written pipeline integrity management program for your OCS pipelines that includes the seven elements listed in this paragraph.

(1) Baseline integrity assessment. A plan and a risk-based schedule for obtaining baseline information on the integrity of each pipeline by either:

(i) Using an in-line inspection tool (e.g., smart pig) to detect corrosion or deformation anomalies;

(ii) Performing hydrostatic pressure tests (see § 250.1058) to test tensile strength; or

(iii) Using other technology that can provide an equivalent understanding of the condition of your pipelines.

(2) Information analysis. An analysis that integrates all other available information (e.g., inspections, tests, surveys, and monitoring results) about pipeline integrity.

(3) Review. Provisions to review the integrity assessment results and information analysis by a qualified person.

(4) Remedial actions. Criteria for performing prompt remedial actions to address anomalous conditions you discover through integrity assessment or information analysis.

(5) Periodic assessment and evaluation. Provisions for periodically reassessing and re-evaluating the integrity of the pipeline at a frequency based on specific risk factors such as proximity to environmentally sensitive areas, product being transported, previous failure history, and water depth.

(6) Preventive and mitigation measures. Provisions for identifying and taking preventive and mitigation measures to enhance safety and environmental protection such as SCADA systems, cathodic protection monitoring, and shorter inspection intervals.

(7) Program effectiveness. Provisions for measuring the effectiveness of your integrity management program.

(c) Emergency plan. You must prepare a written emergency plan that you will immediately implement in the event of a pipeline failure, accident, or other emergency that includes provisions for:

(1) Training personnel responsible for executing emergency actions;

(2) Establishing an effective communication system;

(3) Conducting periodic drills;

(4) Ensuring personnel safety;

(5) Evacuating platforms;

(6) Limiting property damage;

(7) Minimizing pollution and protecting the environment;

(8) Conducting remote operations, if applicable;

(9) Making construction information and operating history available to appropriate personnel;

(10) Notifying appropriate government agencies;

(11) Investigating failures; and

(12) Reviewing performance during drills and actual emergencies.

(d) Personnel qualification program. You must have a written qualification program for individuals who perform pipeline operation, maintenance, and repair duties for you that may affect the safe operation or integrity of a pipeline. This program must include provisions for:

(1) Identifying covered tasks;

(2) Ensuring through periodic evaluation that the individuals who perform covered tasks are qualified;

(3) Evaluating an individual if you have reason to believe that the individual's performance of a covered task contributed to an incident;

(4) Evaluating an individual if you have reason to believe that the individual is no longer qualified to perform a covered task;

(5) Communicating changes that affect covered tasks to individuals performing those tasks; and

(6) Complying with 30 CFR 250, Subpart O—Well Control and Production Safety Training, as applicable.

(e) Implementation procedures. You must establish procedures to make sure that your personnel implement and follow the provisions of your operations and maintenance manual, integrity management program, emergency plan, and personnel qualification program.

(f) Annual review. You must review your operations and maintenance manual, integrity management program, emergency plan, and personnel qualification program at least annually and make any necessary changes to ensure that they remain effective.

(g) Inspection. You must make copies of your operations and maintenance manual, integrity management program, emergency plan, and personnel qualification program available to MMS personnel at the nearest OCS facility upon request.

When must I mark the MMS-assigned pipeline segment number on a pipeline?

You must comply with the marking requirements indicated in the following table:

Type of pipelineWhen you must mark the pipeline segment number
(a) New pipelineBefore you operate a pipeline you construct after [INSERT THE EFFECTIVE DATE OF THE REGULATION], you must durably mark the MMS-assigned pipeline segment number on the pipeline at each platform.
(b) Existing pipelineIf you constructed a pipeline before [INSERT THE EFFECTIVE DATE OF THE REGULATION], you must durably mark the MMS-assigned pipeline segment number on the pipeline at each platform no later than [INSERT THE DATE 6 MONTHS AFTER THE EFFECTIVE DATE OF THE REGULATION].
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(c) ExceptionYou are not required to separately mark the MMS-assigned pipeline segment number on a pipeline to comply with paragraphs (a) or (b) of this section if you durably mark the component identification (see API RP14C, section 2.4 (incorporated by reference as specified in § 250.198)) on the pipeline using the MMS-assigned pipeline segment number as the unique identifier (e.g., KAH-1425, where 1425 is the MMS-assigned pipeline segment number).
How do I determine the MAOP of a pipeline?

The MAOP of a pipeline must not exceed the lowest of the following:

(a) The internal design pressure of the horizontal component and risers;

(b) The pressure ratings of appurtenances;

(c) Eighty percent of the hydrostatic test pressure of the pipeline; or

(d) If applicable, the MAOP of a connecting pipeline.

What must I do if the pipeline transports H2 S?

(a) H2S Contingency Plan for operations. Before you operate a pipeline which transports a product with an H2S concentration that, if released, could result in atmospheric concentrations of 20 ppm or more, you must prepare an H2S Contingency Plan in accordance with § 250.490(f) that covers your pipeline operations. You do not need to prepare an H2S Contingency Plan if the pipeline is covered under an appropriate facility plan.

(b) H2S dispersion modeling report. Before you operate a pipeline which transports a product with an H2S concentration greater than 500 ppm, you must model a potential worst-case accidental H2S release from the pipeline and prepare a report. The modeling report must include:

(1) The data you used in the model (e.g., meteorological data) in an electronic format acceptable to the Regional Supervisor;

(2) A site-specific analysis of your pipeline operation that considers any nearby human-occupied OCS platforms, shipping lanes, fishery areas, and other points where humans may be subject to potential exposure from an accidental H2S release; and

(3) If the accidental release could result in an H2S concentration of 10 ppm or greater at an onshore area, an analysis consistent with the risk management plan (RMP) methodologies of the EPA as outlined in 40 CFR part 68.

(c) Batch treatment. The Regional Supervisor may require that you batch treat your pipeline if there are indications that H2S could be detrimentally affecting the pipeline.

What are the requirements for conducting remote operations during a platform evacuation?

(a) Pipeline shut-in. When you evacuate your personnel from an OCS platform due to an impending storm or other emergency, you must shut in any connecting pipeline unless you have remote operations capability.

(b) Remote operations. You may conduct remote operations on the pipeline during an evacuation only if:

(1) The Regional Supervisor grants you prior approval;

(2) Your pipeline has remote monitoring and remote shut-in capabilities;

(3) You immediately shut in any pipeline that transports liquid hydrocarbons or H2S, or any pipeline that transports natural gas (if the pipeline experiences an upset condition) when the sustained wind speeds of any storm reach 74 mph over any part of the pipeline; and

(4) You design time-delay circuitry (local storm timers) to shut in a pipeline no more than 4 hours after the capability to monitor and control a process is lost, and include this circuitry in the SCADA logic.

(c) Resuming operations. You may not remotely resume operation of a shut-in pipeline if any part of the pipeline was within 25 miles (or other distance specified by the Regional Supervisor) of the eye center path of a major storm (74 mph or greater).

What are the requirements for testing pipeline safety equipment?

(a) You must periodically test your pipeline safety equipment to ensure that it is in good mechanical condition, properly installed, and able to perform safety functions in accordance with the requirements in the following table. You must conduct all tests using the test procedure specified in the appropriate subsection of API RP 14C, appendix D, section D4, table D2 (incorporated by reference as specified in § 250.198).

Safety equipmentFrequencySubsectionIfThen you must
(1) FSV. You must test each required FSV, except those installed underwater, for leakageAt least annually, with no more than 13 months between testsdThe FSV does not operate properly, or if the flow rate exceeds 200 cubic centimeters/minute for liquid flow or 5 cubic feet/minute for natural gas flowRepair or replae the FSV.
(2) PSHL sensors. You must conduct an external pressure test of each required PSHL sensorAt least monthly, with no more than 6 weeks between testsg(i) The PSHL sensor does not operate properly (ii) The PSHL sensor set pressure tolerance is plus or minus 5 percent or five psi, whichever is greaterRepair or reglace the PSHL sensor. Adjust the set point(s) of the PSHL sensor.
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(3) PSV. You must conduct an external pressure test of each required PSVAt least annually, with no more than 13 months between testsi(i) The PSV does not operate properly (ii) The PSV set pressure tolerance is plus or minus two psi for pressures up to and including 70 psi, or plus or minus 3 percent for pressures above 70 psiRepair or replace the PSV. Adjust the set point of the PSV.
(4) SDV. For each required SDV, you must conduct a(an):
(i) Operations testAt least monthly, with no more than 6 weeks between testsk (option 1)The SDV does not operate properlyRepair or replace the SDV.
(ii) Full valve closure testAt least annually, with no more than 13 months between testsk (option 2)The SDV does not operate properly, or if the flow rate exceeds 200 cubic centimeters/minute for liquid flow or 5 cubic feet/minute for natural gas flowRepair or replace the SDV.
(iii) Pressure holding testIf required by the Regional SupervisorNot addressedTo be determined by the Regional SupervisorTo be determined by the Regional Supervisor.
(5) SSV. You must conduct a pressure holding test of each required SSVAt least monthly, with no more than 6 weeks between testsmThe SSV does not operate properly, or if any fluid flow is observed during the testRepair or replace the SSV.

(b) Recordkeeping. You must retain the records of the results of the tests required by paragraph (a) of this section at the nearest OCS facility for at least 2 years, and make them available to MMS upon request.

What must I do when safety equipment is removed from service?

(a) Removal from service notification. You must notify the Regional Supervisor:

(1) If the safety equipment remains removed from service for more than 12 hours in the GOMR; or

(2) Immediately after the safety equipment is removed from service in the POCSR and AKOCSR.

(b) Equivalent degree of protection. You may continue to operate the pipeline only if you:

(1) Provide an equivalent degree of protection; and

(2) Place an appropriate warning sign on the equipment removed from service.

(c) Follow-up notification. If you are required by paragraph (a) of this section to notify the Regional Supervisor immediately that safety equipment is out of service, you must also notify the Regional Supervisor immediately in the POCSR and AKOCSR, and within 12 hours in the GOMR, when you return the safety equipment to service, or when you provide an equivalent degree of protection.

What must I do when a pipeline is taken out of service?

(a) Definition. Out-of-service pipeline means a pipeline that has not been used to transport oil, natural gas, sulphur, or produced water for more than 30 consecutive days. The out-of-service period begins on the 31st day of inactivity.

(b) Isolation. You must immediately equip an out-of-service pipeline with either a blind flange or a block valve locked in the closed position at each end.

(c) Safety equipment. During the 30-day period of inactivity preceding the date that a pipeline attains out-of-service status, you must maintain and test all required pipeline safety equipment.

(d) Out-of-service report. You must submit a written report to the Regional Supervisor within 48 hours after a pipeline attains out-of-service status. In the out-of-service report, you must include:

(1) The name of the company submitting the report;

(2) The name and telephone number of your contact;

(3) The MMS-assigned pipeline segment number;

(4) The reason you took the pipeline out of service;

(5) An estimate of the time that the pipeline will remain out of service; and

(6) Confirmation that you have isolated the pipeline as required by paragraph (a) of this section.

(e) Flush and fill. When a pipeline is out of service for one year, you must:

(1) Immediately flush the pipeline with seawater until the returns comply with appropriate EPA NPDES standards;

(2) Fill the pipeline with inhibited seawater;

(3) Retain the records of your flush and fill activities at your nearest OCS facility until the pipeline is reactivated;

(4) Make the records available to MMS upon request; and

(5) If you discharge any returns into the water column, dispose of them in accordance with applicable laws and regulations.

(f) Reactivation. Before you reactivate an out-of-service pipeline, you must test all required safety equipment in accordance with the procedures in § 250.1084.

(g) Reactivation report. Within 30 calendar days after you reactivate an out-of-service pipeline, you must submit a written report to the Regional Supervisor. In the reactivation report, you must include the:

(1) Name of the company preparing the report;

(2) Name and telephone number of your contact;

(3) MMS-assigned pipeline segment number;

(4) Date you returned the pipeline to service; and

(5) Report of the hydrostatic pressure test (see § 250.1061(a)), if required by § 250.1060(a)(4).Start Printed Page 56496

(h) Decommissioning an out-of-service pipeline. You must decommission (see §§ 250.1105 through 250.1113) a pipeline within 1 year after:

(1) It has been out of service for 5 years; or

(2) You determine that it will be out of service for 5 years or more.

What must I do if a pipeline is shut in?

Before you resume operations after your pipeline was shut in, you must determine that the pipeline does not leak by conducting a visual survey of the pipeline route (see § 250.1103(a)) and a leak test (see § 250.1059). These requirements are applicable if your pipeline was shut in because:

(a) The eye center path of a major storm (winds 74 mph or greater) passed within 25 miles (or other distance specified by the Regional Supervisor) of any part of the pipeline;

(b) You had indications that pipeline integrity may have been compromised; or

(c) Your pipeline had an unexplained automatic shut-in (e.g., a PSL shut-in).

What must I do if a pipeline leaks?

If your pipeline experiences an accidental leak, you must:

(a) Immediately suspend operations and not resume operations until the pipeline is repaired in accordance with §§ 250.1094 through 250.1096; and

(b) Notify the Regional Supervisor immediately, or as soon as practicable, after you discover that a pipeline is leaking.

What must I do if I need to flare or vent gas from a pipeline?

(a) Approval. You must receive approval from the Regional Supervisor to flare or vent natural gas from your pipeline during blowdown, unless the blowdown discharge point is downstream of the royalty meter (see subpart K, redesignated § 250.1155).

(b) Report. You must submit a written report to the Regional Supervisor that includes the location, time, flare or vent volume, and the reason for flaring or venting, within 72 hours after you complete the flaring or venting operations (see subpart K, redesignated § 250.1155).

(c) Extended flaring or venting. If you need to flare or vent natural gas from a pipeline for 48 continuous hours or more, you must adhere to the requirements in subpart K, redesignated § 250.1155.

When must I provide impact protection for existing risers?

You must provide impact protection to all pipeline risers installed prior to April 1, 1988, and that are outside of the platform structure, whenever:

(a) The Regional Supervisor determines that significant damage potential exists;

(b) You perform maintenance or repair operations on any existing pipeline riser that is protected by a pipe-in-pipe configuration; or

(c) You perform major repairs or modifications on any pipeline riser that is not protected.

When will MMS suspend or temporarily prohibit pipeline operations?

The Regional Supervisor may suspend or temporarily prohibit any pipeline operation if:

(a) The Regional Supervisor determines that continued activity would threaten or result in serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life); property; mineral resources; or the marine, coastal, or human environment;

(b) The Regional Supervisor determines that you have failed to comply with a provision of the OCSLA or any other applicable law, a provision of this part or other applicable regulations, or a condition of a pipeline application approval or a pipeline ROW grant; or

(c) Prohibiting the pipeline operation is in the interest of national security or defense.

Pipeline Modifications and Repairs
What must I do to modify an approved pipeline?

(a) Definition. Modifying a pipeline means significantly changing an approved pipeline. Modifications include changing a pipeline route; installing, modifying, or replacing a subsea tie-in valve assembly; adding, modifying, or replacing safety equipment; changing service; changing flow direction; installing or replacing a pig receiving/launching assembly; changing a pipeline riser configuration; changing the MAOP; replacing or adding anodes; and adding a hot-tap. Modifications do not include routine operations such as performing a hydrostatic pressure test; pigging; injecting chemicals; flushing and filling a pipeline; installing a blind flange on an out-of-service pipeline; installing a clamp, sleeve, or wrap to mitigate pipe wall loss; and performing other routine operations or preventive maintenance.

(b) Modification application. Before you conduct any operations to modify a pipeline, you must submit three copies of a modification application to the Regional Supervisor for approval. In the modification application, you must include each of the elements required by the following paragraphs (b)(1) through (b)(7) of this section.

(1) The MMS-assigned pipeline segment number.

(2) Those items in your approved pipeline application (see §§ 250.1014 through 250.1030) affected by the proposed modification.

(3) The step-by-step procedures you will follow in making the modification, including the measures you will take to:

(i) Ensure safety;

(ii) Minimize pollution;

(iii) Comply with burial and covering requirements; and

(iv) Perform any required hydrostatic pressure or leak test.

(4) If required by the Regional Supervisor, a work plan that describes the specific measures you intend to take, and the specific procedures you intend to follow, to ensure the safety of offshore workers and to prevent pollution. The work plan must include or consider:

(i) The operating history of the pipeline you plan to modify, including past modifications or repairs, and the operating conditions peculiar to the pipeline;

(ii) Reasonable measures to ensure that pressure in the pipeline is equal to the external pressure;

(iii) Reasonable measures to ensure that you purge combustibles and H2 S from the pipeline immediately before you conduct the modification;

(iv) Advance notification to facility workers (both company and contract) concerning significant aspects of the upcoming modification;

(v) Re-notification of all facility workers immediately before you attempt to de-pressurize, cut into, or open the pipeline to perform the modification;

(vi) Onsite supervision during the entire modification operation; and

(vii) Safeguards to ensure that the pipeline remains isolated during the entire modification operation so that facility workers are not endangered by pressure, H2 S, or explosive or combustible products.

(5) Requests for alternative compliance (see § 250.141) necessitated by the modification.

(6) If applicable, an electronic file containing the digital coordinates of sufficient points to provide an accurate representation of the proposed modified route, including turns, for both the pipeline and umbilicals.

(7) Payment of a nonrefundable service fee (see § 250.125 for amount).

(c) Hot tap modification application. If you plan to modify a pipeline by installing a hot tap, your modification application must include, in addition to Start Printed Page 56497the requirements in paragraph (b) of this section:

(1) The design specifications for the hot tap;

(2) A drawing of the proposed hot tap assembly;

(3) A plat that shows the location of the hot tap, specifies its location in both X-Y coordinates and latitude and longitude in NAD 27 for the GOMR (Gulf) and POCSR, or NAD 83 for AKOCSR and GOMR (Atlantic), and shows the water depth (feet); and

(4) A description of the hot tapping operations.

(d) Affected States. Unless each affected State has given general concurrence, or the Regional Director determines that a State is not an affected State, you must provide the information required by § 250.1016(a) if your planned modification of an approved ROW pipeline involves:

(1) Installation of additional pipe (except those modifications that involve only minor reconfiguration of existing pipelines);

(2) Installation of a new accessory platform; or

(3) Changing the product from natural gas to oil.

(e) MMS review. A pipeline modification application is subject to the same review requirements as those for a new pipeline application (see § 250.1009).

(f) Relocation notification. If the approved pipeline modification involves the relocation of a pipeline, you must notify the Regional Supervisor at least 48 hours before you begin the work, using Form MMS-153 (Notification of Pipeline Installation/Relocation/Hydrotest).

(g) Modification report. Within 30 calendar days after you complete any pipeline modification that changed the location plat, or that required a hydrostatic pressure test, you must submit a written modification report to the Regional Supervisor. In the modification report you must include all of the following:

(1) The MMS-assigned pipeline segment number.

(2) If applicable, a location plat based on the NAD 27 for the GOMR (Gulf) and POCSR, or NAD 83 for AKOCSR and GOMR (Atlantic), at a minimum scale of 1 inch = 2,000 feet that:

(i) Depicts the actual location of the modification;

(ii) Includes the latitude and longitude coordinates in both NAD 27 and NAD 83, and the X-Y coordinates in NAD 27 for the GOMR (Gulf) and POCSR, or NAD 83 for the AKOCSR and GOMR (Atlantic), of the key points of the modification; and

(iii) Includes a certification by a registered engineer or land surveyor that attests to the accuracy of the “as-built” locations of the pipeline as modified.

(3) If applicable, an electronic file containing the digital coordinates of the key points of the “as-built” pipeline and umbilical routes, including turns, as modified. You must report the digital data in decimal degrees latitude and longitude, based on NAD 83.

(4) Confirmation that the modification was accomplished as approved by the Regional Supervisor.

(5) If applicable, a report of the hydrostatic pressure test (see § 250.1061) required by § 250.1060(a)(2), (3), or (6).

(6) If applicable, the pipe-to-electrolyte potential measurements required by § 250.1043(b).

What are the general requirements for repairing a pipeline?

Repairing a pipeline means performing remedial work as a result of a failure and/or the leaking of a pipeline or associated equipment, or a reduction in wall thickness that would have required a reduction in the MAOP. You must repair a pipeline in a manner that:

(a) Meets or exceeds the original design specifications of the pipeline, appurtenances, and safety system components;

(b) Prevents unauthorized discharges;

(c) Does not unreasonably interfere with other uses of the OCS; and

(d) Does not cause undue or serious harm or damage to the human, marine, or coastal environment.

What must I do to commence and complete a repair?

(a) Repair application. Before you conduct any repair work on a pipeline, you must submit one copy of an application to the Regional Supervisor for approval. You may submit this repair application at the same time as, or after, you make the notification required by § 250.1088(b). The repair application must include all of the elements required by the following paragraphs (a)(1) through (a)(9) of this section.

(1) The MMS-assigned pipeline segment number.

(2) The location (latitude and longitude in NAD 27 for the GOMR (Gulf) and POCSR, and in NAD 83 for AKOCSR and GOMR (Atlantic)) and water depth (feet) of the repair.

(3) A description of the damaged component, and the reason for the repair.

(4) For pipelines that transport liquids, an estimate of the volume spilled (barrels), including slick size and appearance, if applicable.

(5) For pipelines that transport natural gas, an estimate of the volume of gas leaked (MMCF), including sheen/boil size and appearance, if applicable.

(6) Specifications of any new pipe, spool piece, clamps, or other materials you will use in making the repair.

(7) The step-by-step procedures you will follow to make the repair, including the measures you will take to:

(i) Ensure safety;

(ii) Minimize pollution;

(iii) Comply with burial and covering requirements; and

(iv) Conduct any required hydrostatic pressure or leak test.

(8) If required by the Regional Supervisor, a work plan that describes the specific measures you intend to take, and the specific procedures you intend to follow, to ensure the safety of offshore workers and to prevent pollution. The work plan must include or consider:

(i) The operating history of the pipeline you plan to repair, including past modifications or repairs, and the operating conditions peculiar to the pipeline;

(ii) Reasonable measures to ensure that pressure in the pipeline is equal to the external pressure;

(iii) Reasonable measures to ensure that you purge combustibles and H2 S from the pipeline immediately before you commence the repair work;

(iv) Advance notification to all facility workers concerning significant aspects of the upcoming repair work;

(v) Re-notification of all facility workers immediately before you attempt to de-pressurize, cut into, or open the pipeline to perform the repair work;

(vi) Onsite supervision during the entire repair operation; and

(vii) Safeguards to ensure that the pipeline remains isolated during the entire repair operation so that facility workers are not endangered by the release of pressure, H2 S, or explosive or combustible products.

(9) Payment of a nonrefundable service fee (see § 250.125 for amount).

(b) MMS review. The Regional Supervisor will review the pipeline repair application to ensure that the proposed operations conform to the regulations in this subpart.

(c) Pressure testing. You must comply with the pressure testing requirements in § 250.1060(b) and (c).

(d) Cathodic protection system measurements. When you conduct underwater repairs, you must measure the pipe-to-electrolyte potential at the location of the repair site if your pipeline:

(1) Is located in the AKOCSR; or

(2) Is located in either the GOMR or POCSR and either:Start Printed Page 56498

(i) The pipeline is composed of any pipe that is more than 20 years old; or

(ii) The life expectancy of the cathodic protection system cannot be calculated.

(e) Repair report. You must submit a written repair report to the Regional Supervisor within 30 calendar days after you complete a repair. In the repair report, you must include:

(1) The MMS-assigned pipeline segment number;

(2) The actual location of the repair (latitude and longitude in NAD 27 for the GOMR (Gulf) and POCSR, and in NAD 83 for the AKOCSR and GOMR (Atlantic)) and water depth (feet);

(3) Confirmation of the failure or damage to the pipeline as originally reported to the Regional Supervisor;

(4) Confirmation that the repair was accomplished as approved by the Regional Supervisor;

(5) For pipelines that transport liquids, an estimate of the volume that spilled (barrels), if any, while you performed the repair work;

(6) A report of any hydrostatic pressure test (see § 250.1061(a)) required by § 250.1060(b) and (c);

(7) The results of any leak test (see § 250.1061(b)) required by § 250.1060(b)(1) or (c)(1); and

(8) The pipe-to-electrolyte potential measurements required by paragraph (d) of this section.

(f) Failure analysis and examination. The Regional Supervisor may require you to analyze a pipeline failure, and examine samples of a failed pipe or associated equipment in a laboratory to determine the cause of failure. When so directed, you must submit a comprehensive written report of your findings to the Regional Supervisor.

What must I do to repair a pipeline using a clamp?

When repairing a pipeline using a clamp, you must comply with the requirements in the following table:

If you use . . .Then . . .
(a) A clamp to make a repair on a pipelineYou must use a full encirclement clamp with a rated working pressure equal to or greater than the MAOP of the pipeline.
(b) A clamp on the horizontal component or on the riser below the splash zoneYou may use a welded clamp or a mechanical clamp.
(c) A mechanical clamp to temporarily repair a riser in or above the splash zoneYou must: (1) Submit a repair application (see § 250.1095(a)) to the Regional Supervisor for approval to make a permanent repair. (2) Within 30 calendar days after you install the mechanical clamp, complete the permanent repair using a welded clamp, spool piece, or other method approved by the Regional Supervisor.
When do I need to submit a corrective action plan and report?

(a) Plan. The Regional Supervisor may require you to submit a corrective action plan for approval if there are internal or external conditions that could detrimentally affect a pipeline including, but not limited to:

(1) Conditions that might affect the performance or integrity of pipeline valves and fittings at a subsea tie-in;

(2) Conditions that could cause interference with navigation or other uses of the OCS;

(3) Riser or riser clamp damage;

(4) Pipeline exposure or displacement; or

(5) Anomalies and metal loss.

(b) Submittal. You must submit the corrective action plan required by paragraph (a) of this section to the Regional Supervisor. If the remedial work under the corrective action plan requires MMS approval of a modification application (see § 250.1093(a)) or a repair application (see § 250.1095(a)), you may include the appropriate application in your corrective action plan.

(c) Report. The Regional Supervisor may require you to submit a written report, within 30 calendar days after you complete the corrective action, confirming that you carried out your corrective action plan as approved.

Pipeline Surveying, Monitoring and Inspection
What are the general requirements for surveying, monitoring, and inspecting a pipeline?

You must survey, monitor, and inspect all pipelines, including shut in pipelines, in a manner that:

(a) Periodically verifies the integrity of the pipeline and risers;

(b) Prevents unauthorized discharges;

(c) Does not unreasonably interfere with other uses of the OCS; and

(d) Does not cause undue or serious harm or damage to the human, marine, or coastal environment.

What must I do to survey and monitor a pipeline or route?

(a) Surveying. You must conduct a visual survey of each of your pipeline routes at least monthly (or at a frequency specified by the Regional Supervisor) for indication of pipeline leaks. You may conduct this visual survey from a helicopter, marine vessel, or vehicle; by walking on ice; or by other means approved by the Regional Supervisor. The survey must be conducted during daylight hours (except in the AKOCSR). You must retain the results of the visual survey for at least 2 years, and make them available to MMS upon request.

(b) Product monitoring. You must monitor the products transported in the pipeline to ensure that your internal corrosion and flow assurance measures remain effective.

What inspections are required for my pipeline or route?

You must conduct the inspections in the following table:Start Printed Page 56499

Component and conditions for inspectionInspection requirementsReporting and recordkeeping requirements
(a) All risersYou must: (1) Conduct a visual inspection of each pipeline riser in and above the splash zone at least annually for indications of damage or corrosion (2) In conjunction with the platform inspections required by § 250.919, inspect the underwater portions of each pipeline riser for indications of corrosion, soil erosion, or damageYou must retain the records of the riser inspections for at least 2 years on the nearest OCS facility, and make them available to MMS upon request.
(b) All flexible joints on risersYou must: (1) Conduct a visual inspection of the flexible joints on each riser at least annually (2) If the results of an inspection required by item (1) of this paragraph indicate that a flexible joint shows signs of deterioration, conduct the required inspections at least every 6 monthsYou must submit the results of each flexible joint inspection to the Regional Supervisor within 30 calendar days after you complete the inspection.
(c) Impressed current sources if your pipeline is protected by rectifiers or other impressed current sourcesYou must inspect the impressed current sources at least six times each year (with no more than 10 weeks between inspections) to determine if the pipeline is adequately protectedYou must retain the records of the impressed current source inspections for at least 2 years on the nearest OCS facility, and make them available to MMS upon request.
(d) Anode systems if your pipeline is cathodically protected by anodes and if your pipeline is:You must measure the pipe-to-electrolyte potential annually by September 30 of each yearYou must submit the pipe-to-electrolyte potential measurements to the Regional Supervisor no later than October 31 of the same year, or within 60 calendar days of the measurements, whichever is earlier.
(1) Located in the POCSR or AKOCSR; or
(2) Located in the GOMR and either:
(i) The pipeline is composed of any pipe that is more than 20 years old; or
(ii) The life expectancy of the cathodic protection system cannot be calculated.
What additional inspections or surveys may the Regional Supervisor require?

The Regional Supervisor may require you to conduct the inspections or surveys in the following table:

Type of inspection the regional supervisor may requireInspection requirementsReporting and record keeping requirements
(a) Horizontal components inspectionConduct a visual or remote inspection of the horizontal component of your pipelineSubmit a report on the results of the horizontal component inspection to the Regional Supervisor. The Regional Supervisor will specify the contents and submittal deadline of the report.
(b) Pipeline inspection after a storm. If any portion of your pipeline within 25 miles (or other distance specified by Regional Supervisor) of the eye (central path) of a major storm (74 mph or greater)(1) Survey the pipeline route (2) Conduct a visual inspection of the above-water portion of the pipeline riser for damage to the riser and clamps (3) Inspect the underwater portion of the pipeline riser (including clamps, VIV suppression, and connection devices) for evidence of displacement or exposureSubmit a report of the results of the post-storm inspection(s) listed in this paragraph to the Regional Supervisor. The Regional Supervisor will specify the contents and submittal deadline of the report.
(4) Inspect the horizontal component from the base of the riser to a point at least 200 feet away from the base of the riser for evidence of displacement or exposure
(5) Conduct an underwater visual inspection by divers or ROV of each of your pipeline valves, crossings, and tie-ins to determine:
(i) Whether or not any valves or fittings became exposed; and
Start Printed Page 56500
(ii) The extent of any damage, including damage to protective devices, mats, and sandbags
(c) Pipeline Inspection after an earthquake. If any portion of your pipeline may have been affected by an earthquakeConduct surveillance, inspection, and monitoring of the pipelineSubmit a report on the results of the post-earthquake surveillance, inspections, or monitoring to the Regional Supervisor. The Regional Supervisor will specify the contents and submittal deadline of the report.
(d) Ultrasonic test (UT) inspectionConduct a UT inspection of your pipelineSubmit a report on the UT inspection results to the Regional Supervisor. The Regional Supervisor will specify the contents and submittal deadline of the report.
(e) In-line inspectionConduct an in-line inspection of your pipeline using smart pigsSubmit a report on results of the in-line inspection to the Regional Supervisor. The Regional Supervisor will specify the contents and submittal deadline of the report.
(f) Trawl test or other surveyConduct a trawl test, diver survey, or ROV survey, or use another method approved by the Regional Supervisor, to determine whether the pipeline interferes with other uses of the OCSSubmit a report on the results of the trawl test, diver survey, or ROV survey to the Regional Supervisor. The Regional Supervisor will specify the contents and submittal deadline of the report.
Pipeline Decommissioning
When do I accrue pipeline decommissioning obligations?

You accrue pipeline decommissioning obligations when you are, or become:

(a) A lessee, or the owner of operating rights, of a lease on which there is a lease term pipeline; or

(b) The holder of a pipeline ROW on which there is a pipeline, accessory, or appurtenance (including umbilicals).

When must I decommission a pipeline?

You must decommission your pipeline within 1 year after:

(a) The pipeline has been out of service for 5 years (see § 250.1086(h)(1));

(b) You determine that a pipeline will be out of service for 5 years or more (see § 250.1086(h)(2));

(c) For ROW pipelines, your pipeline ROW grant terminates (see § 250.1138(b)); or

(d) For lease term pipelines, your OCS lease terminates.

What must I do to 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 or obstruction to navigation and commercial fishing operations, unduly interfere with other uses of the OCS, or have adverse environmental effects. To decommission a pipeline in place you must meet the requirements in the following table.

RequirementWhat you must do to meet the requirement
(a) ApplicationSubmit a pipeline decommissioning application to the Regional Supervisor in accordance with § 250.1109(a)(1), and receive approval from the Regional Supervisor before you begin the work.
(b) Purging and flushing(1) You must either: (i) Pig the pipeline, including risers, using a pig that will displace the entire contents of the pipeline; or (ii) Flush the pipeline, including risers, with seawater until the returns comply with appropriate EPA NPDES standards. (2) If you discharge any flushed returns into the water column, you must dispose of them in accordance with applicable laws and regulations.
(c) FillingFill the pipeline, including risers, with seawater.
(d) RecordsFor each pipeline decommissioned in place after (INSERT THE EFFECTIVE DATE OF THE REGULATION), retain the records of your flushing and filling activities and make them available to MMS upon request for the life of the pipeline.
(e) DisconnectingDisconnect the pipeline from connecting platforms, pipelines, and subsea manifolds.
(f) Cutting and pluggingCut and plug each end of the pipeline.
(g) Protecting endsProtect the ends of the pipeline as follows: (1) If the pipeline end is in a water depth less than 200 feet, bury the end to a depth at least 3 feet below the seafloor, and cover it with either sand bags or a concrete mat. If you use sand bags, they must have a slope above the seafloor of 1:3 (rise:run). If you use a concrete mat, the edges of the mat must be below the seafloor. (2) If the pipeline end is in a water depth 200 feet or greater but less than 500 feet, you may either bury the end to a depth at least 3 feet below the seafloor, or cover the end with a concrete mat. If you use a concrete mat, the edges of the mat must be below the seafloor. (3) If the pipeline end is in a water depth 500 feet or greater, you may forego burial and covering if the Regional Supervisor determines that the pipeline end is not an obstruction to other uses of the seafloor or area.
(h) Removing appurtenancesRemove all pipeline appurtenances unless: (1) The Regional Supervisor determines that the appurtenance would not unduly interfere with other uses of the seafloor or area; or (2) The water depth is greater than 2,624 feet.
(i) Decommission umbilicals in placeDecommissioning all umbilicals in place in accordance with the requirements of paragraphs (a) through (g) of this section.
Start Printed Page 56501
What must I do to decommission a pipeline by removal?

To decommission a pipeline by removal, you must:

RequirementWhat you must do to meet the requirement
(a) ApplicationSubmit a pipeline decommissioning application to the Regional Supervisor in accordance with § 250.1109(a)(2), and receive approval from the Regional Supervisor before you begin the work.
(b) Purging and flushing(1) You must either: (i) Pig the pipeline, including risers, using a pig that will displace the entire contents of the pipeline; or (ii) Flush the pipeline, including risers, with seawater until the returns comply with appropriate EPA NPDES standards. (2) If you discharge any flushed returns into the water column, you must dispose of them in accordance with applicable laws and regulations.
(c) Removing umbilicalsRemove all umbilicals in accordance with the requirements of paragraphs (a) and (b) of this section.
(d) Removing the pipelinePhysically remove the pipeline.
How do I obtain approval to decommission a pipeline?

(a) To obtain approval to decommission a pipeline, you must:

What to submitApplication contents
(1) Submit three copies of a pipeline decommissioning application to the Regional Supervisor for approval(i)The MMS-assigned pipeline segment number; (ii) Reason for the decommissioning; (iii) Proposed decommissioning procedures, including those to comply with the requirements of § 250.1107; (iv) Length (feet) of pipe to be decommissioned; (v) Length (feet) of pipe that will remain in place; (vi) Requests for alternative compliance or a departure under §§ 250.141 or 250.142; and (vii) If the application is to decommission a lease term pipeline, payment of a nonrefundable service fee (see § 250.125 for amount).
(2) Submit three copies of a pipeline decommissioning application to the Regional Supervisor for approval(i) The MMS-assigned pipeline segment number; (ii) The reason for the decommissioning; (iii) Your proposed removal procedures, including decommissioning those to comply with the requirements of § 250.1108; (iv) A description of the vessel(s) you will use to remove the pipeline, including anchor pattern(s), if required by the Regional Supervisor. (v) The length (feet) of pipe to be removed; (vi) The length (feet) of pipe that will remain in place; (vii) Plans for transportation of removed pipe for disposal or salvage; (viii) Plans to protect archaeological and sensitive biological features during removal operations; (ix) An assessment of the environmental impacts of the removal operations, and the procedures and mitigation measures that you will take to minimize such impacts; (x) A projected pipeline removal schedule; (xi) If the application is to decommission an ROW pipeline by removal: (A) A coastal zone consistency certification according to 15 CFR 930.57, for each affected State; and (B) Evidence that you have sent your decommissioning application, consistency certification (see 15 CFR 930.57), and all necessary data and information (see 15 CFR 930.58) to each affected State for their consistency determination under the CZMA; and (xii) If the application is to decommission a lease term pipeline, payment of a nonrefundable service fee (see § 250.125 for amount).

(b) Electronic submission. You may submit part or all of your decommissioning application electronically (see § 250.186(a)(3)). If you prefer to submit your application electronically, you should consult with the Regional Supervisor for further guidance.

(c) Withdrawal of application. You may withdraw your decommissioning application at any time, for any reason, by notifying the Regional Supervisor in writing.

How does MMS process a decommissioning application?

After you submit a decommissioning application, the Regional Supervisor will process it as shown in the following table.

Processing stepWhat the Regional Supervisor will do
(a) Completeness review.Determine whether your decommissioning application (either in place or by removal) is complete, and will notify you in writing of any problem or deficiency. The Regional Supervisor will not begin processing your application until it is complete.
(b) Compliance reviewReview the proposed operations described in your decommissioning application to ensure that they conform to the OCSLA (43 U.S.C.1331, et seq.), other applicable laws, and MMS regulations.
Start Printed Page 56502
(c) Environmental impact evaluationEvaluate the environmental impacts of the operations described in your decommissioning application, and prepare environmental documentation under NEPA (42 U.S.C. 4321, et seq.) and the implementing regulations (40 CFR parts 1500 through 1508).
(d) AmendmentsDuring the review of your decommissioning application, the Regional Supervisor may require you, or you may elect, to change the application.
(e) MMS decisionReview your decommissioning application, notify you in writing of the decision, and either: (1) Approve the application, if it complies with all applicable requirements, and inform you of any conditions of approval; or (2) Require you to amend the application, and inform you of the reasons for requiring the amendment, if the proposed decommissioning operations would probably cause serious harm or damage to life (including fish or other aquatic life); property; mineral resources (in areas leased or not leased); the national security or defense; or the marine, coastal, or human environment.
After I decommission a pipeline, what information must I submit?

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

(a) The MMS-assigned pipeline segment number;

(b) A summary of the decommissioning operation, including the date the work was completed;

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

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

When must I remove a pipeline decommissioned in place?

If the Regional Supervisor subsequently determines that the pipeline decommissioned in place is an obstruction to other uses of the OCS, you must remove the pipeline in accordance with the requirements in §§ 250.1108, 1109(a)(2), and 1111.

What are the requirements for re-commissioning a decommissioned pipeline?

(a) Re-commissioning. Before re-commissioning a decommissioned pipeline, the current lessee, current designated lease operator, or former pipeline ROW holder, as applicable, must:

(1) Submit an application under § 250.1007(a), including the MMS-assigned pipeline segment number, and receive approval from the Regional Supervisor.

(2) If the application is to re-commission a pipeline as an ROW pipeline, include:

(i) An application for a pipeline ROW grant, if applicable (see § 250.1125(a)), and receive approval from the Regional Supervisor; and

(3) Hydrostatically pressure test the pipeline in accordance with § 250.1060(a)(5).

(4) Conduct all inspections required by the Regional Supervisor, including those in § 250.1102(b), (c), and (d) and § 250.1103(a), (d), and (e).

(b) Re-commissioning report. Within 30 calendar days after you re-commission a decommissioned pipeline, you must submit a written re-commissioning report to the Regional Supervisor that includes all of the following:

(1) The MMS-assigned pipeline segment number.

(2) A location plat based on the NAD 27 for the GOMR (Gulf) and POCSR, or NAD 83 for AKOCSR and GOMR (Atlantic), at a minimum scale of 1 inch = 2,000 feet. The location plat must depict the actual location of the re-commissioned pipeline.

(3) An electronic file of the digital coordinates of the key points of your “as-built” pipeline route, as re-commissioned. You must report the digital data in decimal degrees latitude and longitude, based on NAD 83.

(4) Confirmation that the re-commissioning was accomplished as approved by the Regional Supervisor.

(5) A report of the hydrostatic pressure test (see § 250.1061) required by § 250.1060(a)(5).

Pipeline Right-of-Way (ROW) Grants
What is a pipeline ROW grant?

A pipeline ROW grant is an authorization issued by MMS for the use of submerged lands for the construction and operation of an associated ROW pipeline to transport oil, natural gas, sulphur, or other associated products.

(a) Authority. MMS grants a pipeline ROW pursuant to section 5(e) of the OCSLA (43 U.S.C. 1334(e)).

(b) Term. A pipeline ROW granted by MMS under the provisions of this subpart remains in effect until it is relinquished, cancelled, or forfeited, or until it expires.

(c) Dimensions. A pipeline ROW includes the site on which the pipeline, and any associated appurtenances and accessories, are or will be situated.

(1) The width of the pipeline ROW is 200 feet centered on the pipeline.

(2) The site of an accessory includes the areal extent of anchor chains, pipeline risers, and other facilities and devices associated with the accessory.

(d) Conveyed rights. If the Regional Supervisor approves a pipeline ROW grant, you have the:

(1) Exclusive right and privilege to construct, maintain, and operate the associated pipeline for the purpose of transporting oil, natural gas, sulphur, or other associated products; and

(2) Right to be notified and consulted if any proposed OCS operations will cross or otherwise impact your pipeline ROW.

When must I obtain a pipeline ROW grant?

Before you may construct an ROW pipeline, or use an existing pipeline that qualifies as a ROW pipeline, the Regional Supervisor must grant you a pipeline ROW in accordance with the provisions of this subpart. You must receive a separate pipeline ROW grant for each ROW pipeline, even if the new pipeline ROW grant would overlap another pipeline ROW grant.

Who can be a pipeline ROW grant holder?

(a) Entities. A pipeline ROW holder must be one of the following:

(1) A citizen or national of the United States;

(2) An alien lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20);

(3) A private, public, or municipal corporation recognized by the United States and organized under the laws of the United States or a territory thereof, the District of Columbia, or any State; or

(4) An association (including a partnership) of such citizens, nationals, resident aliens, or private, public, or municipal corporations.

(b) Qualification file. In the pipeline ROW grant application required by § 250.1125(a), you may reference statements and records you previously Start Printed Page 56503submitted to an MMS OCS Region regarding incorporation, and the person(s) authorized to act on behalf of your corporation or association (see § 250.1126(b) and (c)) and to receive process and notifications. The Regional Supervisor will maintain this information in a qualification file. If you choose to establish a qualification file, you must ensure that it contains accurate and up-to-date information to avoid delays in reviewing your pipeline ROW grant application.

(c) Disqualification. The Director may disqualify you from acquiring any new pipeline ROW grants, or from holding any existing pipeline ROW grants, if your operating performance is unacceptable. The Director will give you notice and an opportunity for a review by MMS before disqualifying you.

What are the financial security requirements for holding a pipeline ROW grant?

(a) ROW grant financial security. You (the applicant) must furnish the Regional Director with a bond or other security in the sum of $300,000 for each pipeline ROW grant you hold. This security is in addition to any security required of a lessee by 30 CFR 256, subpart I, Bonding.

(b) ROW grant area financial security. In lieu of providing the security required by paragraph (a) of this section, you may maintain with the Regional Director, or furnish to the Regional Director, a bond or other security in the sum of $1 million that covers all of the pipeline ROW grants you hold in an MMS OCS Region. The following table shows MMS regions and the areas they encompass.

MMS OCS regions are . . .For OCS areas adjacent to the . . .
(1) Alaska OCS Region (AKOCSR).State of Alaska.
(2) Gulf of Mexico OCS Region (GOMR).Atlantic Coast States or in the Gulf of Mexico.
(3) Pacific OCS Region (POCSR).States of California, Oregon, Washington, or Hawaii.

(c) Additional financial security. The Regional Director may require you to provide additional security (i.e., security above the sum of $300,000 specified in paragraph (a) of this section, or the sum of $1 million specified in paragraph (b) of this section).

(1) The Regional Director will base the determination and the amount of additional security on an evaluation of your ability to carry out present and future financial obligations under the pipeline ROW grant, including your obligation to maintain and remove an accessory to the ROW pipeline.

(2) During the evaluation, the Regional Director will give you an opportunity to submit written or oral statements.

(3) If the Regional Director requires additional security, you may either increase the amount of your existing bond or other security, or provide a supplemental bond(s) or other security.

(d) General requirements. Any bond or other security you provide under this section must:

(1) Be submitted on Form MMS-2030 (Outer Continental Shelf (OCS) Pipeline Right-of-Way Grant Bond);

(2) Be payable upon demand to the Regional Director;

(3) Guarantee your compliance with the terms and conditions of the pipeline ROW grant, your obligations under the grant, the OCSLA (43 U.S.C.1331, et seq.), other laws, and applicable MMS regulations;

(4) If the security is a bond, be issued by a surety that the U.S. Department of the Treasury certifies as an approved surety on Federal bonds and that is listed in the current Treasury Circular No. 570;

(5) If the security is a bond, be executed by authorized officials representing you and the surety;

(6) If the surety is a corporation, be signed by an authorized corporate officer and attested to with its embossed corporate seal; and

(7) Be non-cancelable, except as provided in §§ 250.1120 and 250.1124.

(e) State law. If the security is a bond, the bond must continue in full force and effect even if the surety's obligation has been diminished, terminated, or canceled under State law.

When will MMS terminate the period of liability of my financial security?

The Regional Director will not terminate the period of liability of your bond or other security for a pipeline ROW grant except under the conditions in this section.

(a) If your surety requests termination of liability from the Regional Director, the Regional Director will approve the request and terminate that period of liability within 90 calendar days after receipt of the request.

(b) If you intend to maintain the pipeline ROW grant, or have not fulfilled all decommissioning or other obligations, you must provide the Regional Director with a replacement bond or other security of equivalent value.

(c) When the Regional Director terminates the period of liability of a bond or other security, the period during which obligations continue to accrue ends. This termination does not relieve the surety of the responsibility for obligations and responsibilities that accrued during the period of liability and before the date of termination. The obligations and responsibilities that accrue during a period of liability also include those that began accruing before the beginning of the period of liability and have not been fulfilled.

(d) If the Regional Director terminates the period of liability, but the bond or other security is not cancelled, the surety that provided the bond will continue to be liable for accrued obligations until they have been fulfilled.

When will MMS cancel my financial security?

The Regional Director will cancel your bond or other security, and thus relieve the surety of accrued obligations, only if you request cancellation from the Regional Director and either:

(a) The Regional Director determines that there are no outstanding obligations; or

(b) You provide the Regional Director with a replacement bond or other security of equivalent value in which:

(1) The new surety agrees to assume all outstanding liabilities under the bond or other security to be cancelled; and

(2) The new bond or other security is in an amount equal to or greater than the bond or other security to be cancelled.

What happens if my financial security is reduced or lapses?

(a) Reduced financial security value. If the value of a required pipeline ROW grant bond or other security is reduced because of a default, or for any other reason, you must provide the Regional Director with additional coverage sufficient to meet the security required by § 250.1118(a) or (b) and, if applicable, § 250.1118(c). You must provide this additional coverage within 30 calendar days, or within a shorter period if required by the Regional Start Printed Page 56504Director, after the value of your security coverage is reduced.

(b) Lapse of financial security. If your surety is decertified by the Department of the Treasury, becomes bankrupt or insolvent, or has its charter or license suspended or revoked, your security coverage terminates immediately. In that event, you must:

(1) Notify the Regional Director within 72 hours; and

(2) Provide the Regional Director with a new bond or other security sufficient to meet the security required by § 250.1118(a) or (b) and, if applicable, § 250.1118(c) You must do this within 15 calendar days after your security coverage terminates, or within a shorter period if required by the Regional Director.

How will MMS determine that my financial security is forfeited?

(a) The Regional Director will pursue forfeiture of all or part of your bond(s) or other security if the Regional Director finds that either:

(1) You refuse, or are unable, to comply with the terms and conditions of the pipeline ROW grant, your obligations under the grant, the OCSLA (43 U.S.C. 1331, et seq.), other laws, or applicable MMS regulations; or

(2) You have otherwise defaulted under any condition imposed when the Regional Director accepted the bond or other security.

(b) The Regional Director may pursue forfeiture of your bond(s) or other security without first making demands for performance against you.

(c) In pursuing forfeiture of your bond(s) or other security, the Regional Director will:

(1) Notify you and your surety in writing that the forfeiture process has begun, and include the reasons for the forfeiture and the amount to be forfeited;

(2) Base the amount to be forfeited on an estimate of the total cost to bring your pipeline ROW grant into compliance, or to correct any default; and

(3) Advise you and your surety in writing that you may avoid forfeiture if, within 5 working days either:

(i) You agree to, and demonstrate that you will, bring your pipeline ROW grant into compliance or correct any default within a timeframe prescribed by the Regional Director; or

(ii) Your surety agrees to, and demonstrates that it will, bring your pipeline ROW grant into compliance or correct any default within a timeframe prescribed by the Regional Director, even if the cost of compliance or correcting the default exceeds the amount of your bond or other security.

(d) If you or your surety refuse, or are unable, to comply with the conditions in paragraph (c)(3) of this section, the Regional Director will determine that your bond or other security is forfeited, and will:

(1) Collect the forfeited amount;

(2) Use the collected funds to bring your pipeline ROW grant into compliance, or to correct any default;

(3) Initiate proceedings to recover from you all costs in excess of the amount the Regional Director collected from your forfeited bond or other security, if the collected funds are insufficient to bring your pipeline ROW grant into compliance or to correct any default; and

(4) Return any funds collected from the forfeited bond or other security that were not used to bring your pipeline ROW grant into compliance or to correct any default.

(e) If your bond or other security is forfeited, you must furnish the Regional Director with a new bond or other security sufficient to meet the security required by § 250.1118(a) or (b) and, if applicable, § 250.1118(c). You must do this within 15 calendar days after your bond or other security was forfeited, or within a shorter period if required by the Regional Director.

What penalties can MMS assess if my financial security is not sufficient, is reduced or lapses, or is forfeited?

If you fail to provide any additional security required by the Regional Director (under § 250.1118(c)), replace or provide additional coverage for a devalued bond or other security (under § 250.1121(a)), or replace a lapsed or forfeited bond or other security (under § 250.1121(b) or § 250.1122), then:

(a) The Regional Director may assess penalties under 30 CFR 250, subpart N, Outer Continental Shelf (OCS) Civil Penalties;

(b) The Regional Supervisor may suspend the pipeline ROW grant in accordance with § 250.1135(b); and

(c) The Secretary may cancel the pipeline ROW grant in accordance with § 250.1137(a)(4).

What happens to my financial security after a pipeline ROW grant terminates?

When your pipeline ROW grant terminates (either by relinquishment, cancellation, forfeiture, or expiration), your surety(s) remains responsible, and the Regional Director will retain your bond or other financial security as shown in the following table:

For . . .the period of liability ends . . .and . . .
(a) Securities provided under § 250.1118(a) or (b)When the Regional Director determines that you have fulfilled all of your obligations under the pipeline ROW grant(1) The Regional Director will cancel your financial security 7 years after the pipeline ROW grant terminates; 6 years after you complete all secured obligations; or at the conclusion of any appeals or litigation related to your secured obligation, whichever is the latest. (2) The Regional Director will reduce the amount or return a portion of your bond or other security if the Regional Director determines that a lesser amount is required to cover any unforeseen events under your accrued obligations.
(b) Additional securities provided under § 250.1118(c)When the Regional Director determines that you have fulfilled all of your obligations covered by the additional securityThe Regional Director will cancel your financial security either: (1) When you meet your secured obligations; or (2) Seven years after the pipeline ROW grant terminates; if the Regional Director determines that the amount required to cover unforeseen events under your accrued obligations is greater than the amount of the security you provided under § 250.1118(a) or (b); or (3) At the conclusion of any appeals or litigation related to your secured obligation; whichever is the latest.
Start Printed Page 56505
How do I submit an application for a pipeline ROW grant?

(a) Application. You must submit one original and two copies of an application for a pipeline ROW grant to the Regional Supervisor. You must attach the ROW grant application to the application for the associated ROW pipeline (see § 250.1007(a)), and include the information required by § 250.1126 in your ROW grant application.

(b) Service fee. With each pipeline ROW grant application you submit, including an application for a pipeline ROW grant to convert an existing lease term pipeline to an ROW pipeline or an application to for an ROW grant for an existing pipeline, you must include payment of the applicable nonrefundable service fee (see § 250.125 for the amount).

(c) Submitting additional information. The Regional Supervisor may require your ROW grant application to include information in addition to that required by § 250.1126, if the Regional Supervisor determines that it is necessary to evaluate the application.

(d) Electronic submission. You may submit part or all of your pipeline ROW grant application electronically (see § 250.186(a)(3)). If you prefer to submit your pipeline ROW grant application electronically, you should consult with the Regional Supervisor for further guidance.

(e) Withdrawal of application. You may withdraw your pipeline ROW grant application at any time, and for any reason, by notifying the Regional Supervisor in writing.

What information must I include in an application for a pipeline ROW grant?

(a) Cover letter. You must provide a cover letter that states:

(1) You are submitting the pipeline ROW grant application pursuant to section 5 of the OCSLA (43 U.S.C. 1334(e)) or section 8 of the OCSLA (43 U.S.C. 1337(p)(1)(B)) and the regulations contained in 30 CFR 250, subpart J;

(2) You consent to be bound by the provisions of the OCSLA (43 U.S.C. 1331, et seq.) and other applicable laws, MMS regulations, and the terms and conditions of the pipeline ROW grant;

(3) The purpose(s) for which you will use the pipeline ROW grant; and

(4) The name, title, and signature of your authorizing official. This information must be the same as the information you provide or reference in your MMS qualification records (see § 250.1117(b)).

(b) Qualification. You must provide information regarding your qualification to be a pipeline ROW holder as follows:

If you are . . .You must provide . . .
(1) An individualA statement of citizenship or nationality.
(2) An alien lawfully admitted for permanent residence in the United StatesEvidence of such status.
(3) A corporation(i) A statement certified by the Secretary or Assistant Secretary of the corporation with the corporate seal showing the State where it is incorporated; and (ii) The name(s), title(s), and signature(s) of the person(s) authorized to act on behalf of the corporation.
(4) An association (including a partnership)(i) A certified copy of the articles of association; and (ii) The name(s), title(s), and signature(s) of the person(s) authorized to act on behalf of the association.

(c) Reference to qualification records. In lieu of providing the information required by paragraphs (b)(3) and (4) of this section, you may reference statements and records you previously submitted to MMS regarding the corporation or association, and the persons authorized to act on behalf of the corporation or association (see § 250.1117(b)). If you choose this alternative, you must state that the company official who signed the cover letter has the authority to:

(1) Submit the pipeline ROW grant application;

(2) Bind the corporation or association to compliance with the terms and conditions of the pipeline ROW grant; and

(3) Bind the corporation or association to compliance with the various statements and certifications made in your pipeline ROW grant application.

(d) Identified ROW pipeline operator. If the pipeline ROW grant holder will not be the operator of the associated pipeline, you must identify the operator and provide its MMS company number, if any.

(e) Bond or other financial security. You must describe your bond or other security coverage for the proposed pipeline ROW (see § 250.1118(a) or (b)).

(f) Additional financial security. If the Regional Director determines that you must provide additional security, you must describe such security (see § 250.1118(c)).

(g) Accessory footprint. If your pipeline ROW will include a site for an accessory, you must provide the size of the affected area (acres), and information that shows how you determined the size (see § 250.1130(a)(2)) and the maximum water depth.

(h) Payments. You must include your service fee and rental payments, made payable to the Minerals Management Service. If you pay by credit card, follow the instructions in § 250.125(b)(1). If you pay by check, your check must identify the check number, date, and name of the financial institution upon which the check is written. You must provide additional information that includes:

(1) Total amount of the service fee (see § 250.125(b));

(2) Total amount of the pipeline rental, and the time period it covers (see § 250.1130(a)(1));

(3) Total amount of rental for an accessory site (if applicable), and the time period it covers (see § 250.1130(a)(2)); and

(4) Total payment amount.

How does MMS process an application for a pipeline ROW grant?

(a) Compliance review. The Regional Supervisor will review your pipeline ROW grant application to ensure that it complies with the OCSLA (43 U.S.C.1331, et seq.), other applicable laws, and MMS regulations.

(b) Amendments. During the review of your pipeline ROW grant application, the Regional Supervisor may require you, or you may elect, to change the application.

(c) Decision. The Regional Supervisor will review your pipeline ROW grant application, and take one of the following actions:Start Printed Page 56506

The Regional Supervisor will . . .If . . .And the Regional Supervisor also . . .
(1) Approve your application for a pipeline ROW grant in writingIt complies with all applicable requirements(i) Will simultaneously approve the associated pipeline (see § 250.1012(a)) and, if applicable, any associated accessory (see § 250.1142(e)(1)); and (ii) May require you to meet certain conditions.
(2) Require you amend your application for a pipeline ROW grantThe Regional Supervisor determines that it is inconsistent with the OCSLA (43 U.S.C. 1331, et seq.), applicable MMS regulations, or other Federal lawsWill notify you in writing of the decision, and describe the changes you must make to your pipeline ROW grant application to ensure it complies with all applicable requirements.
(3) Deny your application(i) The application for the associated pipeline is disapproved under § 250.1012(b); (ii) You do not qualify to hold a pipeline ROW grant, or are unable to post the required bonds or other security; (iii) You do not comply with applicable requirements, and are unable to amend the application to achieve compliance; or (iv) The proposed pipeline ROW will cross any OCS lands (e.g., fairways or anchorage areas) that are under the jurisdiction of another Federal agency and that agency does not consent to the pipeline ROW grantWill issue the decision to you in writing, and state the reasons for the denial.
When will MMS temporarily suspend or prohibit construction of an ROW pipeline?

The Regional Supervisor may suspend or temporarily prohibit construction operations if the Regional Supervisor determines that a significant change in conditions occurred after the Regional Supervisor granted a pipeline ROW, but before you complete construction of the associated ROW pipeline.

What must I do if the as-built location of the associated ROW pipeline deviates from the approved pipeline ROW grant?

The Regional Supervisor will notify you in writing if the Regional Supervisor determines that the as-built location of the associated ROW pipeline deviates from the approved pipeline ROW grant. Within 60 calendar days after the date you submitted the pipeline construction report to the Regional Supervisor (see § 250.1050(a)), you must:

(a) Notify the lessee or designated lease operator of each lease, and the pipeline ROW holder of each pipeline ROW, that is crossed or could be affected by the associated pipeline as constructed;

(b) Provide the Regional Supervisor with evidence of such notification; and

(c) Submit an application under § 250.1132(a)(3) to the Regional Supervisor for approval to modify the pipeline ROW grant.

What rental fees and payment schedules apply to a pipeline ROW grant?

(a) Rental fees. For the first calendar year, or fraction thereof, that you hold a pipeline ROW grant, and for each calendar year thereafter that the grant remains in effect, you must pay MMS an annual rental as follows:

(1) You must pay $70.00 for each statute mile, or part of a statute mile, of the OCS that your pipeline ROW crosses; and

(2) If you hold a pipeline ROW grant that includes a site for an accessory to your pipeline, you must pay MMS an additional annual rental according to the following table:

If your accessory site is or will be located in water depths . . .You must pay MMS an additional annual rental of . . .
(i) Less than 656 feet$5.00 per acre, with a minimum of $450 for use of the affected area.
(ii) 656 feet or greater$7.50 per acre, with a minimum of $675 for use of the affected area.

(b) Affected area. For purposes of this section, the affected area includes the areal extent of anchor chains, risers, appurtenances, and other devices associated with the accessory.

(c) Payment schedule and deadline. You may make the rental payments required by paragraph (a) of this section to MMS on an annual basis, for a 5-year period, or for multiples of 5 years. All payment periods begin on January 1. You must pay all rental fees in advance and before the beginning of the payment period.

(d) Late rental payments. You will be subject to an interest charge if you do not make a rental payment by the deadline specified in paragraph (c) of this section.

(1) MMS will assess interest on a late payment on unpaid and underpaid amounts from the date the amounts are due.

(2) MMS will assess interest only on the amount not received.

(3) MMS will assess interest only for the number of days the payment is late.

(4) The interest charge on a late rental payment will be at the underpayment rate established by the Internal Revenue Service Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).

(5) MMS may offset an overpayment you made on the rental for a pipeline ROW grant that you hold against an underpayment you made on a different pipeline ROW grant that you hold to determine the net underpayment for which interest is due.

What are the terms and conditions for holding a pipeline ROW grant?

(a) Compliance. You must comply with the OCSLA (43 U.S.C. 1331, et seq.), as amended, other applicable laws, and MMS regulations.

(b) Address changes. You must update your qualification file (see § 250.1117(b)) within 30 calendar days after a change of address as follows:Start Printed Page 56507

If you are . . .You must provide . . .
(1) An individualYour change of address.
(2) A corporation or associationAddress of your principal place of business, or name and address of the officer or agent authorized to act on your behalf and to be served with process.

(c) Non-interference. Your pipeline ROW grant does not allow you to prevent or interfere in any way with the management, administration, or the granting of other rights by the United States, either before or after the pipeline ROW is granted by MMS.

(d) Occupancy and use. You must allow the occupancy and use by the United States, its lessees or designated lease operators, or other pipeline ROW holders of any part of the pipeline ROW grant not actually occupied, or necessarily incident to its use, for any necessary operations involved in the management, administration, or the enjoyment of other granted rights.

(e) Compensation and indemnification. You must:

(1) Compensate the United States, its lessees, or other pipeline ROW holders, as the case may be, for the full value of all damages to the property of the United States or of its lessees or pipeline ROW holders; and

(2) Indemnify the United States against any and all liability for damages to life, person, or property arising from the occupation and use of the area covered by the pipeline ROW grant.

(f) Federal Energy Regulatory Commission (FERC) determination. The pipeline associated with the pipeline ROW grant must transport, or you must purchase, oil or natural gas produced from submerged lands of the OCS in the vicinity of the pipeline in such proportionate amounts as FERC may determine to be reasonable. The FERC will make this determination only after a full hearing with due notice thereof to the interested parties, taking into account, among other things, conservation and the prevention of waste.

(g) Open and nondiscriminatory access. (1) Unless otherwise exempted by FERC under section 5(f)(2) of the OCSLA (43 U.S.C. 1334(f)(2)), you must provide open and nondiscriminatory access to the associated ROW pipeline to both owner and non-owner shippers.

(2) The express condition that ROW oil and natural gas pipelines must transport or purchase without discrimination is within MMS's delegated authority to enforce, even when those pipelines are also under FERC jurisdiction by separate authority. To the extent that the oil or natural gas pipelines are subject to FERC's jurisdiction, MMS intends to defer to FERC its authority to decide whether those pipelines have complied with the open and nondiscriminatory access requirements. For pipelines not under FERC jurisdiction, MMS will decide whether those pipelines have complied with the open and nondiscriminatory access requirements of the OCSLA. All complaints by shippers alleging that pipelines have not complied with the open and nondiscriminatory access requirements are subject to the regulations in 30 CFR part 291.

(h) Expansion of throughput capacity. You must comply with the provisions of section 5(f)(1)(B) of the OCSLA (43 U.S.C. 1334(f)(1)(B)), under which FERC may order expansion of the throughput capacity of an associated ROW pipeline that was approved after September 18, 1978, and that is not located in the Gulf of Mexico or the Santa Barbara Channel.

(i) Open for inspection. You must keep the area covered by the pipeline ROW grant, and all improvements thereon, open for inspection by MMS.

(j) Nondiscrimination in employment. You must comply fully with Executive Order 11246, section 202, paragraphs (1) through (7), as amended (reprinted in 41 CFR 60-1.4(a)), and must not discriminate against any employee or applicant for employment on the basis of race, color, religion, sex, or national origin.

(k) Sabotage or subversive activity. You must immediately notify the Regional Supervisor, by the fastest possible means of communication, if you discover any evidence of sabotage or subversive activity involving or endangering any pipeline, accessory, vessel, aircraft, or any operation conducted under the pipeline ROW grant.

How do I modify a pipeline ROW grant?

(a) Application. You must submit one executed original and two copies of an application to modify a pipeline ROW grant to the Regional Supervisor for approval if you plan to:

(1) Cease pipeline operations, and need to maintain the pipeline ROW grant in effect;

(2) Change the purpose(s) for which the grant was made;

(3) Change the route of the associated ROW pipeline; or

(4) Establish a site for an accessory, or change the footprint of an accessory.

(b) Associated pipeline application. For those applications specified in paragraphs (a)(2), (a)(3), and (a)(4) of this section, you must attach the application to modify the pipeline ROW grant to the application to modify the associated ROW pipeline (see § 250.1093(a)).

(c) Application contents. Your application to modify a pipeline ROW grant must include:

(1) Company name;

(2) Contact name, telephone number, telefax number, and e-mail address;

(3) Reason for the modification, and a description of the proposed modification to the pipeline ROW grant;

(4) MMS-assigned pipeline ROW number, the segment number of the associated pipeline, and, if applicable, the name of any accessory;

(5) Name, title, and signature of your authorizing official. This information must be the same as the information you provided or referenced in the MMS qualification records;

(6) If you propose to cease pipeline operations:

(i) Date that you stopped using the pipeline;

(ii) Steps you will take to resume operations under the pipeline ROW grant;

(iii) The approximate date you intend to resume operations; and

(iv) Plans for maintaining the associated ROW pipeline in the interim;

(7) If the modification results in additional rental (see § 250.1130), payment for the increase in the manner prescribed in § 250.1126(h); and

(d) MMS actions. The Regional Supervisor will review your application to modify a pipeline ROW grant, along with your application to modify the associated ROW pipeline (see § 250.1093(a)), to ensure that it complies with the OCSLA (43 U.S.C. 1331, et seq.), other applicable laws, and applicable MMS regulations, and will take one of the actions prescribed in § 250.1127(c).

How does temporary cessation and cessation of pipeline operations affect a pipeline ROW grant?

(a) Definitions—(1) Temporary cessation of pipeline operations means the use of a pipeline associated with a pipeline ROW grant for a purpose other than that for which the grant was made for a period of 180 consecutive calendar days or less.Start Printed Page 56508

(2) Cessation of pipeline operations means the use of a pipeline associated with a pipeline ROW grant for a purpose other than that for which the grant was made for a period of more than 180 consecutive calendar days. Simply maintaining pressure on the pipeline is not using the pipeline for the purpose for which the grant was made.

(b) Temporary cessation of pipeline operations. Temporary cessation of pipeline operations will not cause the associated pipeline ROW grant to expire.

(c) Cessation of pipeline operations. Cessation of pipeline operations, whether voluntary or resulting from a suspension or temporary prohibition of operations directed by MMS, will cause the associated pipeline ROW grant to expire unless the Regional Supervisor approves an application to modify the pipeline ROW grant (see § 250.1132(a)(1)) to allow for a cessation of operations for a specified time period.

(d) Obligations. If MMS approves your application to modify the pipeline ROW grant to cease operations, you must:

(1) Continue to pay the annual rentals required by § 250.1130(a);

(2) Adhere to the requirements for out-of-service pipelines in § 250.1086; and

(3) If, at any time, you determine that cessation of pipeline operations will continue for 5 years or more, or for a shorter period as specified by the Regional Supervisor, you must submit to the Regional Supervisor, within 60 days:

(i) A request to relinquish the pipeline ROW grant (see § 250.1136(a)); and

(ii) An application to decommission the associated pipeline (see §§ 250.1107 or 1108).

How do I assign a pipeline ROW grant?

(a) Assignment request. You may assign a pipeline ROW grant by submitting two originals of Form MMS-149 (Assignment of Federal OCS Pipeline Right-of-Way Grant) to the Regional Supervisor for approval. The assignment must transfer the pipeline ROW grant in its entirety and to only one assignee. Your assignment request must include:

(1) The MMS-assigned pipeline ROW number, the segment number of the associated pipeline, and, if applicable, the name of any accessory;

(2) The names and MMS company numbers for both the assignor and the assignee;

(3) The names and telephone numbers of the contacts for both the assignor and the assignee;

(4) The names, titles, and signatures of the authorizing officials for both the assignor and the assignee;

(5) Payment of a nonrefundable service fee (see § 250.125 for the amount);

(6) A statement from the assignee that the assignee agrees to comply with, and to be bound by, the terms and conditions of the pipeline ROW grant;

(7) The same showing of qualifications of the assignee as is required of an applicant for a pipeline ROW grant in § 250.1117;

(8) A statement describing how the assignee will comply with the financial security requirements of § 250.1118;

(9) The name of the identified operator, if the company that will operate the associated pipeline will not be the assignee;

(10) A revised safety flow schematic that shows the new transfer point, if the assignment will result in a change of the jurisdictional transfer point of the associated pipeline; and

(11) The information required by §§ 250.1028 and 250.1029.

(b) Rental payments for a pipeline ROW grant pending assignment. If you have submitted a request to assign a pipeline ROW grant, you (the assignor) will be billed for the annual pipeline ROW rental payment if the payment is due (see § 250.1130(c)) and the Regional Supervisor has not yet approved the assignment. MMS will not mediate any financial disputes between an assignor and an assignee.

(c) Effective date. The assignment takes effect on the date the Regional Supervisor approves it.

(d) Assignor obligations. The assignor is liable for all obligations that accrue under a pipeline ROW grant before the date the Regional Supervisor approves the assignment. An assignment approval by MMS does not relieve the assignor of liability for accrued obligations that the assignee, or a subsequent assignee, fails to fulfill.

(e) Assignee obligations. The assignee and each subsequent assignee:

(1) Agrees to be bound by the terms and conditions of the pipeline ROW grant; and

(2) Is liable for all obligations that accrue under a pipeline ROW grant after the date the Regional Supervisor approves the assignment.

(f) Disqualification. The Director may disqualify you from acquiring any pipeline ROW grants by assignment if your operating performance is unacceptable. The Director will give you adequate notice, and an opportunity to have your case reviewed, before disqualification.

(g) Financial securities. After the Regional Supervisor approves an assignment of a pipeline ROW grant, you may request that the Regional Director approve a “Termination of the Period of Liability” for your pipeline ROW area bond or other security and any additional securities (see § 250.1119) if you:

(1) No longer hold any pipeline ROW grants in an MMS OCS Region; and

(2) Do not plan to become a pipeline ROW grant holder in the near future in that MMS OCS Region.

When may MMS suspend a pipeline ROW grant?

The Regional Supervisor may suspend a pipeline ROW grant if:

(a) The Regional Supervisor suspends or temporarily prohibits operation of the associated ROW pipeline under § 250.1091;

(b) You fail to provide any additional security required by the Regional Director (see § 250.1118(c)), replace or provide additional coverage for a de-valued bond or other security (see § 250.1121(a)), or replace a lapsed or forfeited bond or other security (see §§ 250.1121(b) and 1122) within the prescribed time period; or

(c) The Regional Supervisor determines that you have failed to comply with a provision of the OCSLA (43 U.S.C.1331, et seq.) or any other applicable law, a provision of applicable regulations, or a stipulation, term, or condition of the pipeline ROW grant.

How do I relinquish a pipeline ROW grant?

(a) Relinquishment request. You may voluntarily surrender a pipeline ROW grant, or a portion of a pipeline ROW grant, by filing one original and two copies of a relinquishment request with the Regional Supervisor for approval. You must attach the relinquishment request to the application required by §§ 250.1107 or 250.1108 to decommission the associated ROW pipeline and, if applicable, the application required by § 250.1727 to decommission an associated accessory. Your relinquishment request must include:

(1) Company name;

(2) Contact name, telephone number, telefax number, and e-mail address;

(3) Reason you are requesting relinquishment of the pipeline ROW grant;

(4) MMS-assigned pipeline ROW number, the segment number of the associated pipeline, and, if applicable, the name of any accessory;

(5) Name, title, and signature of your authorizing official which must be the Start Printed Page 56509same as the information you provide or reference in your MMS qualification records;

(6) Payment of a nonrefundable service fee (see § 250.125 for the amount); and

(7) A statement that you will adhere to the requirements of § 250.1138(a) and (b).

(b) Rental payment for a pipeline ROW grant pending relinquishment. If you have submitted a request to relinquish a pipeline ROW grant, you will be billed for the annual pipeline ROW rental payment if the payment is due (see § 250.1130(c)) and the Regional Supervisor has not yet approved the relinquishment.

(c) Delinquent payments. The Regional Supervisor will not approve your relinquishment request until you have paid all outstanding rentals and fines.

(d) Effective date. The relinquishment takes effect on the date the Regional Supervisor approves it.

(e) Financial securities. After the Regional Supervisor approves the relinquishment of a pipeline ROW grant you may request that the Regional Director approve a “Termination of the Period of Liability” for your pipeline ROW area bond or other security and any additional securities (see § 250.1119) if you:

(1) No longer hold any pipeline ROW grants in an MMS OCS Region; and

(2) Do not plan to become a pipeline ROW grant holder in the near future in that MMS OCS Region.

When will a pipeline ROW grant be cancelled, be forfeited, or expire?

Your ROW grant will be cancelled, be forfeited, or expire as shown in the following table.

Termination typeWhen termination will occur
(a) CancellationThe Secretary may cancel a pipeline ROW grant if:
(1) The Secretary cancels MMS approval of the application for the associated ROW pipeline pursuant to § 250.1013;
(2) You no longer qualify to hold a pipeline ROW grant;
(3) You are disqualified from holding pipeline ROW grants according to § 250.1117(c); or
(4) You fail to provide any additional security required by the Regional Director (see § 250.1118(c)), replace or provide additional coverage for a de-valued bond or other security (see § 250.1121(a)), or replace a lapsed or forfeited bond or other security (see §§ 250.1121(b) and 1122) within the prescribed time period.
(b) ForfeitureYou may forfeit a pipeline ROW grant, in an appropriate judicial proceeding instituted by the United States, in accordance with the provisions of § 23 of the OCSLA (43 U.S.C. 1349) if:
(1) You fail to comply with the provisions of § 5(e) of the OCSLA (43 U.S.C. 1334(e)), or the regulations prescribed in this subpart;
(2) The Director determines that you have not provided open access or nondiscriminatory access to a shipper; or
(3) There is substantial deviation of an associated ROW pipeline (as constructed) from the pipeline ROW grant, and the Regional Supervisor has not approved a modification to the pipeline ROW grant.
(c) ExpirationA pipeline ROW grant expires if:
(1) You do not construct the associated pipeline within 5 years after the grant was approved by the Regional Supervisor;
(2) You ceased pipeline operations and did not obtain approval from the Regional Supervisor pursuant to § 250.1132(a)(1);
(3) You permanently discontinue using the associated ROW pipeline for any reason; or
(4) You cease operations for 5 years.
What must I do after a pipeline ROW grant terminates?

(a) Pipeline operation. After a pipeline ROW grant terminates, for any reason (relinquishment, cancellation, forfeiture, or expiration), you must no longer use the associated pipeline.

(b) Decommissioning. Within 1 year after a pipeline ROW grant terminates, you must decommission:

(1) The associated ROW pipeline in accordance with the requirements of §§ 250.1106 through 1109 and § 250.1111; and

(2) Any associated accessory in accordance with the requirements of §§ 250.1725 through 1730 and §§ 250.1741 through 1743.

(c) Failure to comply. If you fail to decommission the associated pipeline and any accessory within the prescribed time period:

(1) You remain liable for decommissioning costs, and responsible for accidents or damages that might result from such failure; and

(2) The violation may be subject to a civil penalty under 30 CFR 250, subpart N, Outer Continental Shelf (OCS) Civil Penalties.

(d) Obligations. You remain liable for all obligations that accrued under a pipeline ROW grant before the date the pipeline ROW grant terminated.

Accessories to Right-of-Way (ROW) Pipelines
What are the requirements for an accessory to an ROW pipeline?

(a) General. You must design, fabricate, install, and maintain an accessory to an ROW pipeline in accordance with the requirements of 30 CFR 250, subpart I, Platforms and Structures.

(b) Surface safety system. You must protect personnel, the environment, and the accessory with a basic and ancillary surface safety system. You must design, analyze, install, test, operate, and maintain the surface safety system in accordance with the applicable requirements of subpart H of this part, Oil and Gas Production Safety Systems.

(c) Existing OCS platforms. If you plan to convert an existing OCS platform to an accessory, you must decommission all wells on the platform in accordance with the requirements of §§ 250.1715 and 250.1716 before the Regional Supervisor will approve the accessory application (see § 250.1141(a)).

How do I obtain approval to install, operate, and maintain an accessory?

(a) Accessory application. Before you install, operate, and maintain an accessory to a ROW pipeline, you must submit three copies of an application to the Regional Supervisor for approval. You must attach the accessory application to the application for the associated ROW pipeline. Your accessory application must include all of the following:

(1) The following information, based on the type of platform:Start Printed Page 56510

For . . .Your application must include . . .and . . .
(i) New platformsthe information required by §§ 250.905 and 912, if applicable
(ii) Existing platforms that are being converted for a different usethe information required by § 250.905the results of your platform assessment in accordance with API RP 2A-WSD, section 15, Reuse (incorporated by reference as specified in § 250.198).
(iii) Existing platforms that are completing ongoing activitythe information required by § 250.905the results of your platform assessment in accordance with API RP 2A-WSD, section 17, Assessment of Existing Platforms (incorporated by reference as specified in § 250.198.

(2) The MMS-assigned pipeline ROW number and the segment number of the associated pipeline, if the accessory will be under an existing pipeline ROW grant.

(3) The maximum anchor radius (feet) of the construction vessel you will use to install the accessory.

(4) Information on air emission sources that includes:

(i) The rated output (horsepower) of each tug, construction vessel, and service vessel or equipment;

(ii) An estimate of the number of vessel or equipment trips per year;

(iii) An estimate of the time (days) that each vessel/equipment will be within 25 miles of the accessory;

(iv) An estimate of the number of component connections (e.g., valves, flanges) on the accessory;

(v) The contents and capacity (gallons) of hydrocarbon storage tanks, and their average daily and annual throughput (gallons/day and gallons/year); and

(vi) Documentation of any emission control technologies you will employ.

(5) Information on combustion emission sources that includes:

(i) The rated output (horsepower) of each emission source (e.g., crane, compressor, generator, dehydrator);

(ii) The run time (hours/day and days/year) for each emission source; and

(iii) The average hourly and annual throughput of gas through glycol dehydrators.

(6) Information on wastes generated at the accessory that includes, as appropriate:

(i) The type and general characteristic of the wastes that will be generated by operations at the accessory and released (locally) into the ocean;

(ii) The amount of waste to be discharged (gallons);

(iii) The average maximum discharge rates (gallons/day);

(iv) A description of any waste treatment or storage; and

(v) The discharge location and method for each type of discharge.

(7) The safety system design and installation information required by § 250.802(e).

(b) Electronic submission. You may submit part or all of your accessory application electronically (see § 250.186(a)(3)). If you prefer to submit your application electronically, you should consult with the Regional Supervisor for further guidance.

(c) Withdrawal of application. You may withdraw your accessory application, at any time, and for any reason, by notifying the Regional Supervisor in writing.

How does MMS process an accessory application?

(a) Completeness review. The Regional Supervisor will determine whether your accessory application is complete, and will notify you in writing of any problem or deficiency. The Regional Supervisor will not begin processing your application until it is complete.

(b) Compliance review. The Regional Supervisor will review the proposed operations described in your accessory application to ensure that they conform to the OCSLA (43 U.S.C. 1331, et seq.), other applicable laws, and MMS regulations.

(c) Environmental impact evaluation. The Regional Supervisor will evaluate the environmental impacts of the operations described in your accessory application, and prepare environmental documentation under NEPA (42 U.S.C. 4321, et seq.) and the implementing regulations (40 CFR parts 1500 through 1508).

(d) Amendments. During the review of your accessory application, the Regional Supervisor may require you, or you may elect, to change the application.

(e) MMS decision. The Regional Supervisor will review your accessory application and will notify you in writing of the decision. The Regional Supervisor will either:

(1) Approve the application if it complies with all applicable requirements, and inform you of any conditions you may be required to meet; or

(2) Disapprove the application, and inform you of the reasons for disapproval if the:

(i) Proposed accessory operations would probably cause serious harm or damage to life (including fish or other aquatic life); property; mineral resources (in areas leased or not leased); the national security or defense; or the marine, coastal, or human environment; and you cannot amend the proposed accessory operations to avoid such condition(s); or

(ii) Regional Supervisor has disapproved your application for a connecting ROW pipeline (see § 250.1012(b)) or denied your application for the associated pipeline ROW grant (see § 250.1127(c)(3)).

Who do I need to notify before I install an accessory?

(a) Military installations. Before you install an accessory in an established military warning area or water test area, you must notify the commander of the military installation that exercises jurisdiction of the area concerning the control of electromagnetic emissions and the use of vessels, equipment, and aircraft in the area.

(b) U.S. Coast Guard (USCG). You are encouraged to notify the applicable USCG Marine Safety Office at least 30 calendar days before you conduct accessory installation operations so that a Notice to Mariners can be prepared.

(c) National Geospatial-Intelligence Agency (NGA). You must notify the NGA in Bethesda, Maryland before you begin accessory installation operations.

What information must I submit after an accessory is installed?

You must submit three copies of an accessory installation report to the Regional Supervisor within 45 calendar days after you complete accessory installation. The installation report must include:

(a) The MMS-assigned pipeline ROW number and the segment number of the associated pipeline;

(b) The dates you started and concluded accessory installation operations; and

(c) An “as built” location plat that depicts the accessory, based on the NAD 27 for the GOMR (Gulf) and POCSR, or on the NAD 83 for the AKOCSR and Start Printed Page 56511GOMR (Atlantic), drawn at a minimum scale of 1 inch = 2,000 feet.

What accessory inspections must I conduct?

You must conduct structural and pollution inspections on your accessory as required by this section.

(a) Structural inspections. If the accessory is a platform, you must do all of the following:

(1) Periodically inspect the platform in accordance with a comprehensive in-service inspection plan as required by § 250.919(a).

(2) As required by § 250.919(b), submit a written report, by November 1 of each year, of the inspections that you conducted during the preceding 12 months. The report must include:

(i) The MMS-assigned pipeline ROW number and the segment number of the associated pipeline, and the MMS complex identification number for the platform;

(ii) The extent and area of each inspection;

(iii) The type of inspection conducted (i.e., visual, magnetic particle, ultrasonic);

(iv) The results of the inspection;

(v) A discussion of the overall condition of the platform; and

(vi) A description of any necessary repairs.

(b) Pollution inspections. If the accessory is a compressor or booster platform, you must inspect the accessory daily in accordance with § 250.301 for evidence of pollution. You must retain the inspection records for at least two years, and make them available to MMS upon request.

What must I do to modify an accessory?

Before you conduct any operations to modify an approved accessory, you must submit three copies of a modification application to the Regional Supervisor for approval. In the accessory modification application, you must include:

(a) The MMS-assigned pipeline ROW number and the segment number of the associated pipeline;

(b) Those items in your approved application affected by the proposed modification;

(c) If required by the Regional Supervisor, the step-by-step procedures you will follow to modify the accessory; and

(d) If the accessory is a platform, the results of your platform assessment, based on platform assessment initiators listed in sections 17.2.1 through 17.2.5 of API RP 2A-WSD (incorporated by reference as specified in § 250.198).

When must I decommission an accessory?

Within 1 year after an accessory has not been used for 5 years, or within 1 year after you determine that an accessory will not be used for 5 years or more, you must decommission the accessory (see §§ 250.1725 through 1730 and §§ 250.1740 through 1743).

[AMENDED]

8. In § 250.1700(a)(2), remove the phrase “or pipeline right-of-way.”

[AMENDED]

9. Amend § 250.1701 as follows:

A. Remove paragraph (b);

B. Redesignate paragraph (c) as paragraph (b);

C. Remove the phrase “and to right-of-way holders as to facilities installed under the authority of a right-of-way” in newly redesignated paragraph (b); and

D. Remove the comma after the word “lease” and add in its place a period.

10. In § 250.1702, revise paragraphs (b) and (d), remove paragraph (e), and redesignate paragraph (f) as paragraph (e). The revisions read as follows:

When do I accrue decommissioning obligations?
* * * * *

(b) Install a platform or other facility;

* * * * *

(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, or other facility, or an obstruction; or

* * * * *
[Amended]

11. In § 250.1703, remove paragraph (d) and redesignate paragraphs (e) and (f) as paragraphs (d) and (e).

[Amended]

12. In § 250.1704, remove paragraphs (d) and (e) and redesignate paragraphs (f) and (g) as paragraphs (d) and (e).

[Removed]

13. Remove §§ 250.1750 through 250.1754 and the undesignated center heading “Pipeline Decommissioning” before § 250.1750.

End Part Start Part

PART 253—OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE FACILITIES

14. The authority citation for part 253 continues to read as follows:

Start Authority

Authority: 33 U.S.C. 2701 et seq.

End Authority

15. In § 253.3, revise the definitions of the terms “Designated applicant,” “Pipeline,” “Responsible party,” and “Right of use and easement (RUE)” to read as follows:

How are the terms used in this regulation defined?
* * * * *

Designated applicant means the responsible party or, if there is more than one responsible party, a person that the responsible parties designate to demonstrate OSFR for a COF on a lease, permit, pipeline right-of-way (ROW), or right-of-use and easement (RUE).

* * * * *

Pipeline means the horizontal component, risers, and appurtenances installed for the purpose of transporting oil, gas, sulphur, and produced water.

Responsible Party has the following meanings:

(1) For a COF that is an ROW pipeline, responsible party means the pipeline ROW holder.

(2) For a COF that is not an ROW pipeline, responsible party means either a lessee or permittee of the area on which the COF is located; or the holder of an RUE granted under applicable State law, or under the OCSLA (43 U.S.C. 1331 et seq.) for the area in which the COF is located (if the holder is a different person than the lessee or permittee). A Federal agency, State, municipality, commission, or political subdivision of a State, or any interstate body that as owner transfers possession and right to use the property to another person by lease, assignment, or permit is not a responsible party.

(3) For a decommissioned COF, responsible party means any person who would have been a responsible party for the COF immediately before decommissioning.

Right-of-use and easement (RUE) means an authorization granted by MMS to use the OCS to construct and maintain platforms, artificial islands, and installations and other devices at an OCS site other than an OCS lease you own. This does not include pipeline ROWs.

* * * * *

16. Revise § 253.10 to read as follows:

What facilities does this part cover?

(a) This part applies to any COF that is on any lease or permit issued, any ROW pipeline (see definition at § 250.105 of this chapter), or on any RUE granted under the OCSLA (43 U.S.C. 1331, et seq.) or applicable State law.

(b) For a COF that is an ROW pipeline which extends onto land, this part applies to the portion of the pipeline lying seaward of the first accessible flow shut-off device on land.Start Printed Page 56512

17. Amend § 253.11 as follows:

A. Redesignate paragraphs (d), (e), and (f) as paragraphs (e), (f), and (g), respectively.

B. Add new paragraph (d), and revise newly redesignated paragraphs (e) and (f) as follows:

Who must demonstrate OSFR?
* * * * *

(d) The designated applicant for a ROW pipeline must be the pipeline ROW holder.

(e) The designated applicant for a COF on a RUE must be the holder of the RUE.

(f) MMS may require the designated applicant for a lease, permit, pipeline ROW, or RUE to be a person other than the person identified in paragraphs (b) through (e) of this section if MMS determines that the person identified in paragraphs (b) through (e) of this section cannot adequately demonstrate OSFR.

* * * * *

18. Revise § 253.15(a) as follows:

What are my general OSFR compliance responsibilities?

(a) You must maintain continuous coverage for all your leases, permits, pipeline ROWs, and RUEs with COFs for which you are the designated applicant.

* * * * *
End Part Start Part

PART 254—OIL SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED SEAWARD OF THE COASTLINE

19. The authority citation for part 254 continues to read as follows:

Start Authority

Authority: 33 U.S.C. 1321

End Authority
[Amended]

20. In § 254.6, revise the definition of “Owner or operator” to read as follows:

* * * * *

Owner or operator means, in the case of an offshore facility, any person owning or operating such a facility. If the facility is a right-of-way (ROW) pipeline (see definition at § 250.105), the owner or operator is the pipeline ROW holder. In the case of a decommissioned offshore facility, it means the person who owned such facility immediately prior to such decommissioning.

* * * * *
End Part Start Part

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

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

Start Authority

Authority: 43 U.S.C. 1331, et seq., 42 U.S.C. 6213, 31 U.S.C. 9701.

End Authority

22. In § 256.62, add a new paragraph (g) to read as follows:

Assignment of lease or interest in lease.
* * * * *

(g) Within 30 calendar days after MMS approves an assignment of a lease, or approves a new designation of operator for a lease under § 250.143 or § 250.144, you (the new lessee or designated lease operator) must submit a report to the Regional Supervisor that:

(1) Lists every lease term pipeline (see definition at § 250.105), including decommissioned pipelines on the lease; and

(2) Indicates which pipelines remained as lease term pipelines after the lease assignment was approved by MMS.

End Part End Supplemental Information

BILLING CODE 4310-MR-P

[FR Doc. 07-4831 Filed 10-2-07; 8:45 am]

BILLING CODE 4310-MR-C