Acronyms and terms used in this subpart have the following meanings:

(a) Acronyms used frequently in this subpart are listed alphabetically below:

(1) BOEM means Bureau of Ocean Energy Management of the U.S. Department of the Interior.

(2) BSEE means Bureau of Safety and Environmental Enforcement of the U.S. Department of the Interior.

(3) CID means Conservation Information Document.

(4) CZMA means Coastal Zone Management Act.

(5) DOCD means Development Operations Coordination Document.

(6) DPP means Development and Production Plan.

(7) DWOP means Deepwater Operations Plan.

(8) EIA means Environmental Impact Analysis.

(9) EP means Exploration Plan.

(10) ESA means Endangered Species Act.

(11) HPHT means High Pressure High Temperature

(12) I3P means Independent Third Party

(13) MMPA means Marine Mammal Protection Act.

(14) NPDES means National Pollutant Discharge Elimination System.

(15) NTL means Notice to Lessees and Operators.

(16) OCS means Outer Continental Shelf.

(b) Terms used in this subpart are listed alphabetically below:

Amendment means a change you make to an EP, DPP, or DOCD that is pending before BOEM for a decision (see 30 CFR 550.232(d) and 30 CFR 550.267(d)).

Barrier categorization includes identifying barriers as one of the following two types of categories:

Category 1 Barrier means any equipment, component, or assembly that functions as part of a primary barrier during any operational phase of its life cycle. The operational phases of the barrier equipment, component, or assembly are drilling, completion, workover, intervention, injection, production, or abandonment.

Category 2 Barrier means any equipment, component, or assembly that normally functions as part of a secondary barrier during any operational phase of its life cycle, except when a primary barrier fails. The operational phases of the barrier equipment, component, or assembly are drilling, completion, workover, intervention, injection, production, or abandonment. BSEE may consider non-barrier structural components of a barrier system as a Category 2 Barrier if failure of this structural component could reasonably result in a Primary Barrier failure.

Fit for Purpose means a determination made by an I3P at the conclusion of I3P review that the barrier equipment design has been verified and validated in conformance with recognized engineering standards and any additional project specification requirements; that the material selection, design verification analysis, design validation testing, and quality control are appropriate to justify the technical specifications; and that the technical specifications meet or exceed a project's site specific functional requirements.

Fit for Service means a determination made by the operator that the material selection, design verification analysis, design validation testing, and quality control of the barrier equipment is appropriate to justify the technical specifications and that the technical specifications meet or exceed a project's site-specific functional requirements.

New or unusual technology means equipment or procedures used for any drilling, completion, workover, intervention, injection, production, pipeline, platform, decommissioning, or abandonment operations that meet any of the following criteria:

(1) Has not been approved for use or used extensively in a BSEE OCS Region;

(2) Has not been approved for use or used extensively under the anticipated operating conditions;

(3) Has operating characteristics that are outside the performance parameters established in this part;

(4) Will operate in an HPHT environment as defined in § 250.105; or

(5) Is part of a primary or secondary barrier system that uses materials, design analysis techniques, validation testing methods, or manufacturing processes not addressed in existing industry standards.

Primary Barrier means the equipment, material, component, or assembly that is designated as the principal means of isolating the hydrocarbon pressure source from people and the environment.

Secondary Barrier means the equipment, material, component, or assembly that is designated as the secondary means of isolating the hydrocarbon pressure source from people and the environment.

Subsea tieback development technology means, but is not limited to, floating production systems, tension leg platforms, spars, Floating Production Storage and Offloading (FPSO) systems, guyed towers, compliant towers, subsea manifolds, subsea wells, hybrid wells, production risers, export risers, and other subsea completion or production components that rely on a remote site or host facility for utility and well control services.

(a) Plans and permits. Before you conduct the activities on your lease or unit listed in the following table, you must submit, and BSEE must approve, the listed plans (or relevant portions thereof), and any applicable permits. Your plans and applicable permits may cover one or more leases or units.

(b) Submitting additional information. On a case-by-case basis, the Regional Supervisor may require you to submit additional information if the Regional Supervisor determines that it is necessary to evaluate your proposed plan or permit.

(c) Referencing. In preparing your proposed plan or permit, you may reference information and data discussed in other plans or permits you previously submitted or that are otherwise readily available to BSEE.

(d) All plans listed under paragraph (a) of this section that are initially submitted after October 29, 2024 must comply with the requirements of this subpart.

(a) To protect the rights of the Federal government, you must either:

(1) Drill and produce the wells that the Regional Supervisor determines are necessary to protect the Federal government from loss due to production on other leases or units or from adjacent lands under the jurisdiction of other entities (e.g., State and foreign governments); or

(2) Pay a sum that the Regional Supervisor determines as adequate to compensate the Federal government for your failure to drill and produce any well.

(b) Payment under paragraph (a)(2) of this section may constitute production in paying quantities for the purpose of extending the lease term.

(c) You must complete and produce any penetrated hydrocarbon-bearing zone that the Regional Supervisor determines is necessary to conform to sound conservation practices.

For wells that could intersect or drain an adjacent property, the Regional Supervisor may require special measures to protect the rights of the Federal government and objecting lessees or operators of adjacent leases or units.

If you plan to install HPHT barrier equipment, you must submit information with your applicable Project Conceptual Plan, New or Unusual Technology Barrier Equipment Conceptual Plan, DWOP, and applicable permit(s) that demonstrates the equipment is fit for service in the applicable HPHT environment. You must follow the applicable DWOP Process requirements (e.g., §§ 250.229 and 250.242).

A barrier or barrier system is any engineered equipment, material, component, or assembly that is installed to contain a hydrocarbon pressure source(s) to prevent harm to people or the environment. BSEE only recognizes barriers that are either permanently or temporarily installed, pressure controlling, and/or pressure containing. You must be able to activate pressure controlling barriers on demand (i.e., closed by an operator or automated safety system). You must function test and pressure test any pressure controlling barriers or barrier systems to defined acceptance criteria that can be repeated. You must pressure test any pressure containing barrier or barrier system to defined acceptance criteria that can be repeated.

You must install and maintain a primary and a secondary barrier system (redundant barriers) to prevent a loss of containment during any operational phase of a well, flowline, pipeline, production, or riser system.

(a) Compliance. You must conduct all of your lease and unit activities according to your approved EP, DPP, or DOCD and any approval conditions. If you fail to comply with your approved EP, DPP, or DOCD:

(1) You may be subject to BSEE enforcement action, including civil penalties; and

(2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you may not be entitled to compensation under 30 CFR 550.185(b) and 30 CFR 556.1102.

(b) Emergencies. Nothing in this subpart or in your approved EP, DPP, or DOCD relieves you of or limits your responsibility to take appropriate measures to meet emergency situations. In an emergency situation, the Regional Environmental Officer may approve or require departures from your approved EP, DPP, or DOCD.

(a) Approvals and permits. Before you conduct activities under your approved EP, DPP, or DOCD you must obtain the following approvals and or permits, as applicable, from the District Manager or BSEE Regional Supervisor:

(1) Approval of Applications for Permits to Drill (APDs) (see § 250.410);

(2) Approval of production safety systems (see § 250.800);

(3) Approval of new platforms and other structures (or major modifications to platforms and other structures) (see § 250.905);

(4) Approval of applications to install lease term pipelines (see § 250.1007); and

(5) Other permits, as required by applicable law.

(b) Conformance. The activities proposed in these applications and permits must conform to the activities described in detail in your approved EP, DPP, or DOCD.

The Regional Supervisor may direct you to conduct monitoring programs, including monitoring in accordance with the ESA and the MMPA, in association with your approved EP, DPP, DWOP, or DOCD. You must retain copies of all monitoring data obtained or derived from your monitoring programs and make them available to BSEE upon request. The Regional Supervisor may require you to:

(a) Submit monitoring plans for approval before you begin work; and

(b) Prepare and submit reports that summarize and analyze data and information obtained or derived from your monitoring programs. The Regional Supervisor will specify requirements for preparing and submitting these reports.

If you have an approved new or unusual technology and it experiences a failure (i.e., any condition that prevents the equipment from meeting its functional specification) during or post-installation, you must notify the applicable Regional Supervisor within 30 days of the failure. You must also provide a failure analysis report as soon as it is available following notification. The failure analysis report must include any results of and potential root cause(s) of the failure. You must also follow all applicable failure or incident reporting requirements associated with the failure (e.g., §§ 250.188, 250.730, and 250.803).

(a) The DWOP process consists of providing sufficient information from a total system approach for BSEE to review:

(1) A deepwater development project,

(2) A subsea tieback development technology, or

(3) Any other project or system that uses new or unusual technology during any phase of the following operations: drilling, completion, workover, intervention, injection, production, pipeline, platform, decommissioning, or abandonment.

(b) The DWOP process does not replace but complements other submittals required by the regulations, such as BOEM EPs, DPPs, and DOCDs, or BSEE applications and/or permits (e.g., APD, Application for Permit to Modify (APM), pipeline application, and platform application). BSEE will use the information in your DWOP process to determine whether the project will be developed in an acceptable manner, particularly with respect to operational safety and environmental protection involved with a deepwater development project, subsea tieback development technology, or new or unusual technology.

(c) The DWOP process consists of two phases:

(1) The Conceptual Plans. The Conceptual Plans outline certain equipment and process specifications, operational concepts, and basis of design that you plan to use for project development, and for applicable equipment design, installation, and operation. Sections 250.227 through 250.229 prescribe what each of the Conceptual Plans must contain. Each Conceptual Plan may be submitted separately or combined as applicable; and

(2) The DWOP. The DWOP identifies specific design, fabrication, installation and operational requirements for equipment, systems, and activities as applicable in §§ 250.236 through 250.242.

(d) You must submit to BSEE the applicable plan(s) covered under the DWOP process as appropriate (see § 250.225 for Conceptual Plan requirements and § 250.235 for DWOP requirements). Certain projects requiring New or Unusual Technology Conceptual Plans or New or Unusual Technology Barrier Equipment Conceptual Plans may not be required to have an associated Project Conceptual Plan or DWOP.

(a) You must use the DWOP process for any project that meets any of the following criteria:

(1) Is planned in water depths greater than 1000 ft;

(2) Will use subsea tieback development technology, regardless of water depth; or

(3) Will use any new or unusual technology for any drilling, completion, workover, intervention, injection, production, pipeline, platform, decommissioning, or abandonment project.

(b) If you are unsure if your project will use subsea tieback development technology or new or unusual technology, contact the Regional Supervisor for guidance.

There are three types of Conceptual Plans:

(a) A Project Conceptual Plan is required for any project that is planned in water depths greater than 1000 feet, will use subsea tieback development technology, or will use new or unusual technology for completion, injection, production, pipeline, or platform operations;

(b) A New or Unusual Technology Conceptual Plan is required for any project or system that involves equipment or procedures that are considered new or unusual technology (see § 250.200 for the definition of new or unusual technology) for drilling, completion, workover, intervention, injection, production, pipeline, platform, decommissioning, or abandonment operations; and

(c) A New or Unusual Technology Barrier Equipment Conceptual Plan is required for any project or system involving new or unusual technology that is also identified as a primary or secondary barrier (see § 250.200 for the definition of primary and secondary barriers) for drilling, completion, workover, intervention, injection, production, pipeline, platform, decommissioning, or abandonment operations.

You must submit each applicable Conceptual Plan to the Regional Supervisor after you have decided on the general concept(s) for a project or system, and before you finalize engineering design of the equipment, well, well safety control system, or subsea production systems. You must submit, for BSEE approval, each Conceptual Plan according to the following table:

In the Project Conceptual Plan, you must explain the basis of design that you will use to develop the field. You must include the following information:

(a) An overview of the development concept(s);

(b) The system control type (i.e., direct hydraulic or electro-hydraulic);

(c) The estimated distance from each of the wells to the host platform, and umbilical length(s);

(d) A statement that the subsea production safety system will be designed to comply with Subpart H of this part;

(e) For a new facility, a description of the type of facility you plan to install (e.g. spar, tension leg platform (TLP), FPSO, etc.);

(f) For a subsea tie back to an existing facility:

(1) A description of known structural modifications that you will need to make to accommodate the tieback, including a statement about whether these accommodations constitute minor or major modifications,

(2) The BSEE-approved service life of the existing facility, and

(3) A description of how you will evaluate whether the modifications may affect the BSEE-approved service life.

(g) A statement regarding whether the host facility will be manned or unmanned;

(h) A schedule of development activities, including well completion, facility installation, and date of first oil;

(i) Schematics, including:

(1) A proposed well location plat,

(2) A conceptual subsea field schematic depicting the planned development infrastructure that contains (as applicable) the wells, pipelines, manifolds, subsea booster pumps, high integrity pressure protection system, riser systems, umbilical(s), and facility footprint,

(3) The surface or subsea tree, and

(4) A proposed wellbore and completion schematic for a typical well (including Surface Controlled Subsurface Safety Valve (SCSSV) location and chemical injection points; and depiction or description of gas zones, if any, behind the production casing or production liner and how those gas zones will be isolated).

(j) A description of the drilling and completion systems;

(k) The estimated shut-in tubing pressure for the proposed well(s), including the calculation used to arrive at the estimate, specifying true vertical depth (TVD), reservoir pressure, and the fluid gradient used, or a brief discussion of the pressure volume temperature (PVT) data used for estimation;

(l) The wellbore static bottomhole temperature and the estimated flowing temperature at the tree;

(m) The pressure and temperature rating of the tree and wellhead;

(n) Whether there will be corrosive production (e.g., hydrogen sulfide (H2S), Carbon dioxide (CO2), Mercury (Hg) or injection fluids (e.g., acid)), including concentrations;

(o) Whether any of the proposed equipment will be re-furbished and re-certified;

(p) Whether enhanced recovery is planned for the early life of the project;

(q) Whether any new or unusual technology will be used to develop your project involving the following: drilling, completion, injection, production, risers, pipelines, or platforms;

(r) Whether the well(s) will include smart completion technology;

(s) A list of requests for any alternate procedures or equipment in accordance with § 250.141 and request for departures in accordance with § 250.142 associated with your applicable Conceptual Plans; and

(t) Documentation demonstrating payment of the service fee listed in § 250.125.

(a) You must include the following information, as applicable, in your New or Unusual Technology Conceptual Plan:

(1) How the New or Unusual Technology Conceptual Plan fits within your overall site specific project, if applicable, including an overview of the project development concepts.

(2) A description of the technology and specific conditions under which it will be used;

(3) A description of shut-in capabilities and procedures;

(4) A description of redundancies of critical components or systems that will be used;

(5) A discussion of how the new or unusual technology could impact the barrier or safety system, if any, including:

(i) The detection method for new or unusual technology failure;

(ii) A description of how barriers or safety systems function to a fail-safe state when impacted by tew or unusual technology failure;

(6) Information on inspection and testing capabilities;

(7) A risk assessment and failure mode analysis;

(8) Operating procedures;

(9) A history of development and application of the technology;

(10) The basis of design, including design verification and validation testing;

(11) Detailed schematics identifying all components;

(12) A justification for new or unusual technology use, and any additional information required for a complete review;

(13) A list of requests for alternate procedures or equipment in accordance with § 250.141 and request for departures in accordance with § 250.142 needed for the new or unusual technology proposed in your New or Unusual Technology Conceptual Plan;

(14) A statement that the technology is fit for service in the applicable environment (for the specific project at location); and

(15) Documentation demonstrating payment of the service fee listed in § 250.125.

(b) The Regional Supervisor may require the use of an I3P according to § 250.231 if the system or equipment you propose to use requires a high degree of specialized or technically complex engineering knowledge, expertise, and experience to evaluate, or if existing industry standards do not address the system or equipment you propose to use.

(1) The Regional Supervisor may also require you to follow the I3P requirements according to § 250.232, as applicable, on a case-by-case basis.

(2) If you have any questions about I3P requirements for the New or Unusual Technology Conceptual Plan, contact the applicable Regional Supervisor.

Your New or Unusual Technology Barrier Equipment Conceptual Plan must include the following information:

(a) A description how the New or Unusual Technology Barrier Equipment Conceptual Plan fits within your overall site-specific project, if applicable. You must include an overview of the project development concepts and a proposed schedule for submittal of associated Conceptual Plans;

(b) Detailed schematics depicting the primary and secondary barriers that include all components, assemblies, or sub-assemblies, each labeled and categorized as a Category 1 barrier or Category 2 barrier;

(c) A list of the primary and secondary barriers that includes all components, assemblies, or sub-assemblies specifying each assigned barrier as either a Category 1 barrier or Category 2 barrier;

(d) A list of the engineering standards that will be used in the equipment's material selection and qualification, design verification analysis, and design validation testing;

(e) A list of requested alternate procedures or equipment in accordance with § 250.141 and requested departures in accordance with § 250.142 needed for the new or unusual technology barrier equipment proposed in your New or Unusual Technology Barrier Equipment Conceptual Plan;

(f) A list of the functional requirements (e.g., environmental and physical loads (magnitude and frequency)) for which the barrier equipment is being designed;

(g) A description of the equipment's safety critical functions, (e.g., function(s) performed by or inherent to the equipment enabling it to achieve or maintain a safe state);

(h) An I3P nomination, in accordance with § 250.231(a);

(i) An I3P verification plan that includes the following:

(1) A discussion of the equipment's material selection and qualification;

(2) A discussion of the equipment's design verification analyses;

(3) A discussion of the equipment's design validation testing;

(4) An explanation of why the analyses, processes, and procedures ensure that the equipment is fit for service in the applicable environment; and

(5) Details regarding how the I3P will address the additional items listed in § 250.232.

(j) Documentation demonstrating payment of the service fee listed in § 250.125.

You must submit to BSEE any I3P reports required in § 250.232 for any equipment identified in your New or Unusual Technology Barrier Equipment Conceptual Plan and when required by the Regional Supervisor. BSEE will not approve your associated Conceptual Plan until BSEE reviews the required I3P Reports.

In accordance with each applicable Conceptual Plan, you must:

(a) Nominate I3P(s) to review the design verification and design validation documentation of the Original Equipment Manufacturer (OEM). Your I3P must be a technical classification society, a licensed professional engineering firm, or a registered professional engineer capable of providing the required verifications and validations. You must submit your I3P nomination(s) within the applicable Conceptual Plan for separate BSEE acceptance before BSEE will approve the applicable Conceptual Plan. Your I3P nomination must include the following descriptions:

(1) Previous experience in third-party verification and validation or experience in the design, fabrication, and installation of applicable offshore oil and gas equipment;

(2) Technical capabilities of the individual or the primary staff for the specific project;

(3) Size and type of organization or corporation;

(4) In-house availability of, or access to, appropriate technology to review the specific project. This should include, but not limited to, computer programs, hardware, and equipment as applicable;

(5) Ability to perform the I3P functions for the specific project considering current commitments (e.g., project timelines, schedules, and personnel availability); and

(6) Previous experience with BSEE requirements and procedures.

(b) You must ensure that the I3P has access to all associated documentation and equipment related to items listed on the I3P verification plan defined at § 250.229(i) and necessary for performance of complete reviews in accordance with § 250.232, including relevant OEM documentation (including documentation and data labeled as confidential and proprietary) and access to the OEM fabrication and manufacturing locations if such access is necessary to review the data.

(c) If your project involves submittal of multiple Conceptual Plans, you may propose to use the services of an I3P previously accepted by BSEE for the same project, and not submit the items required under paragraph (a), if the BSEE-accepted I3P's qualifications are still valid and applicable to provide the required verifications and validations. You must submit documentation regarding the previous I3P nomination acceptance.

In accordance with each applicable Conceptual Plan, the I3P must:

(a) Review the following information regarding the applicable equipment and/or system:

(1) Basis of Design, technical specification of the equipment (if known at this point in the design process) and functional requirements of the specific project (e.g., environmental and physical loads (magnitude and frequency));

(2) Risk assessment and failure mode analysis;

(3) Material specification, selection, qualification, and testing;

(4) Design verification analysis, including:

(i) Structural/strength analysis, and

(ii) Fatigue assessment and/or analysis.

(5) If fatigue is identified as a potential failure mode, as identified in the fatigue assessment and/or analysis in paragraph (a)(4) of this section, the plan to record and gather data (load monitoring) in order to conduct a future fatigue analysis;

(6) Design validation testing; and

(7) A fabrication, quality management system, and inspection and test plan that identifies the quality control/quality assurance process, and inspection of the final products.

(b) Submit a report to BSEE documenting the review of each item covered under paragraph (a) of this section. Each report must clearly identify all OEM and operator documents used during the I3P review. The report must also include:

(1) The equipment and/or system's technical specifications, including a statement that the equipment and/or system is fit for purpose for the technical specification by the I3P; and

(2) Verification that the equipment's technical specifications meet or exceed the project's functional requirements, including a statement that the equipment and/or system is fit for purpose for the proposed project by the I3P.

(c) For any new project, you may use previous I3P reviews of equipment and/or systems technical specification that was approved in a previous Conceptual Plan. The Regional Supervisor may accept a final report in accordance with paragraph (c) of this section that includes the following:

(1) A statement that the previous report submitted pursuant to of paragraph (b) of this section remains valid;

(2) Verification that the equipment's technical specifications meet or exceed the proposed project's functional requirements; and

(3) A statement by the I3P that the equipment and/or system is fit for purpose for the proposed project.

An I3P Report as required in § 250.232 must be a standalone document that clearly summarizes the required verification and validation work performed and must contain a sufficient level of detail (e.g., quantitative information) and clarity to establish the basis of the I3P's findings. Each report must identify the OEM or operator documents reviewed, describe the detailed I3P review, and convey the results of the I3P's review without requiring BSEE to review of any other referenced documents.

(a) You must submit the DWOP to the Regional Supervisor after BSEE has approved your Project Conceptual Plan and you have substantially completed system design, and before you conduct installation activities post-well completion for:

(1) A deepwater development project;

(2) A project that will use subsea tieback development technology in any water depth; or

(3) An HPHT development project, any project that uses Category 1 or 2 new or unusual technology barrier equipment, or any project that uses new or unusual technology that may impact the safety critical function of Category 1 or 2 barrier equipment regardless of the water depth.

(b) You may install subsea systems and associated pipelines after you have received applicable BSEE permit(s) and Conceptual Plan approvals. However, you may not begin production from the well until BSEE approves your DWOP.

Your DWOP must contain the following information, as applicable:

You must include the following general information in your DWOP, as applicable:

(a) A list of requests for any alternate procedures or equipment in accordance with § 250.141 and requests for departures in accordance with § 250.142 applicable to the DWOP, and a list of any identified alternate procedures or equipment or departures for which you may request approval in any future applicable permit or application. You do not need to list alternative procedures or equipment or departure requests that were previously submitted and approved for the same project's Conceptual Plans unless the same alternate procedures or equipment or departure requests are needed for a different piece of equipment for post-completion activities.

(b) Documentation demonstrating payment of the service fee listed in § 250.125; and

(c) A list of any associated industry standards not incorporated in the regulations that you are using for your project design or operation.

You must include the following information in your DWOP, as applicable, to be consistent with the activities to be addressed in the associated well permit(s):

(a) A description and schematic of the typical wellbore, casing, and completion;

(b) Information concerning the drilling and completion systems; and

(c) Design and fabrication information for each wellbore riser system (e.g., drilling, completion, workover, intervention, injection, or production) deployed from a floating production facility or TLP.

You must include the following information in your DWOP, as applicable, to align with the activities to be addressed in the associated platform application, including any major modifications:

(a) Structural design, fabrication, and installation information;

(b) Design, fabrication, installation, and monitoring information on the tendon, or mooring systems, including the turret or buoy system, if applicable; and

(c) Information on any active station keeping system(s) involving thrusters or other means of propulsion.

You must include the following information in your DWOP, as applicable, to be consistent with the activities you plan to address in the associated production safety system application:

(a) A general description of the operating procedures;

(b) Information about the design, fabrication, and operation of an offtake system for transferring produced hydrocarbons to a transport vessel, including a table summarizing the curtailment of production and offloading based on operational considerations;

(c) A description of the process facility installation and commissioning procedure;

(d) A safety analysis flow diagram of the production system from the SCSSV downstream to the first item of separation equipment;

(e) A statement that the surface and/or subsea safety system and emergency support systems will comply with Subpart H of this part. This statement must include:

(1) The methods, frequency, and acceptance criteria for testing the underwater safety valves (USVs), SCSSVs, and boarding shutdown valves;

(2) A description of the function and testing of the host facility Emergency Shutdown Device (ESD) system and its interface to the subsea system; and

(3) If applicable, a description of the surface and/or subsea safety system and emergency support systems not covered in Subpart H of this part. If you propose to use systems not covered in Subpart H of this part, you must request an approval of alternate procedures or equipment according to § 250.141, and you must also include a table that depicts what valves will close, at what times, and for what events or reasons; and

(f) Information regarding the design, operation, maintenance, personnel competency, and testing of your subsea leak detection system to protect your subsea field/infrastructure (e.g., trees, manifolds, jumpers). You must include a description of the procedures regarding how you will operate the system, ensure system functionality, identify a leak, and the actions you will take if a leak is identified.

(a) You must include the following information common to the subsea system and the associated pipeline systems, which constitute all or part of a single project development covered by the DWOP and/or is consistent with activities addressed in your associated pipeline application, as applicable:

(1) The subsea field schematic depicting the planned subsea development equipment and infrastructure, including wells/trees, non-pipe subsea equipment, pipeline route(s), pipeline riser systems, umbilical(s), and platform footprint;

(2) A description of the subsea development project detailing the subsea and pipeline equipment design criteria and analysis procedures (including industry standards, pressure and temperature ratings, materials selection), testing methods, and general operational procedures;

(3) A description of the fabrication and assembly/testing location of subsea trees, pipelines, and non-pipe subsea equipment (manifold, Pipeline End Manifold (PLEM), Pipeline End Termination (PLET), Subsea Umbilical Termination Assembly (SUTA), subsea pumps, suction piles, etc.);

(4) A summary of the Integrity Management Program for subsea tieback development technologies, including a plan for inspection and monitoring to support assessment of the condition of the systems a minimum of once every 10 years. This should include, but is not limited to, the in-service inspections or surveys of hull and topsides structures, tendons, mooring, and pipeline and/or wellbore riser systems to assess component condition by inspection and analysis after each significant environmental event (e.g., hurricane, earthquake, loop and eddy currents, or mudslide) impacting the system, or once every 10 years, whichever occurs first. You must also include in your Integrity Management Plan a description of how you will determine significant environmental events; and

(5) A summary of safety and environmental controls.

(b) You must include the following information about subsea systems that constitute all or part of a single project development covered by the DWOP:

(1) The system control type (e.g., direct hydraulic or electro-hydraulic);

(2) Well tree(s), wellhead, and non-pipe equipment general arrangement drawings and schematics, with size and valve type annotations to illustrate the tree and other equipment in operation;

(3) The estimated shut-in tubing pressure for the proposed well(s), including the calculation used to arrive at the estimate, specifying TVD, reservoir pressure, and the fluid gradient used, or a brief discussion of the PVT data used for estimation;

(4) The wellbore static bottomhole temperature and the estimated flowing temperature at the tree, including a description of the method used to calculate this estimate;

(5) A description of the umbilical(s) and umbilical connection(s), including an umbilical cross-section schematic;

(6) A description of the chemical or other injection systems and/or enhanced recovery systems you plan to use;

(7) A description of the corrosion monitoring and prevention/inhibition processes;

(8) Details of any re-furbished and/or re-certified equipment you plan to use; and

(9) A schedule of development activities, including well completion, facility installation, and anticipated date of first oil.

(c) You must include the following pipeline information in your DWOP, as applicable, to be consistent with your associated pipeline application(s):

(1) General design and fabrication information for each pipeline riser system;

(2) If you propose to use a pipeline free standing hybrid riser (FSHR) on a permanent installation that uses a buoyancy air can suspended from the top of the riser, you must provide the following information in your DWOP as part of the discussions required by paragraphs (b)(1) and (2) of this section:

(i) A detailed description and drawings of the FSHR, buoy, and the associated connection system;

(ii) Detailed information regarding the system used to connect the FSHR to the buoyancy air can, and associated redundancies; and

(iii) Descriptions of your monitoring system and monitoring plan for the pipeline FSHR and the associated connection system for fatigue, stress, and any other abnormal condition (e.g., corrosion), that may negatively impact the riser system's integrity.

(3) Pipeline and pipeline riser installation methods.

You must include the following new or unusual technology information in your DWOP, as applicable:

(a) A description of any new or unusual technology being used in your development project, including a reference to previously approved New or Unusual Technology Conceptual Plans or New or Unusual Technology Barrier Equipment Conceptual Plans.

(b) A description of any new or unusual technology not covered under the New or Unusual Technology Conceptual Plan or New or Unusual Technology Barrier Equipment Conceptual Plan. You must include the same applicable information as required in §§ 250.228 or 250.229.

If your development project meets the following criteria, you may submit a combined Project Conceptual Plan/DWOP that complies with all applicable requirements for both, on or before the deadline for submitting the Project Conceptual Plan, as described in § 250.226:

(a) The project is similar to projects involving subsea tieback development technology for which you have obtained approval previously, and

(b) The project does not involve either new or unusual technology or a new platform.

You must revise your approved DWOP to reflect any material change to the plan that does not involve a physical alteration of the equipment on the platform or the seabed.

You must supplement your DWOP to reflect additions or changes in your development project that:

(a) Physically alter the equipment or systems upstream of your boarding shut down valve, approved in your DWOP. If a Supplemental DWOP includes the addition of a well or wells (e.g., a new subsea field) not approved in your original DWOP, you may not complete or produce from the new well(s) until BSEE approves the Supplemental DWOP; or

(b) Involves the addition of any new or unusual technology to your project that was not previously covered under the New or Unusual Technology Conceptual Plan, New or Unusual Technology Barrier Equipment Conceptual Plan, or DWOP. You may not install any new or unusual technology until BSEE approves the applicable Conceptual Plan and Supplemental DWOP.

You must include the following information, as applicable, in your Supplemental DWOP:

(a) The same information for your wells or equipment as required in the applicable Conceptual Plan and DWOP requirements in this subpart;

(b) A description of each applicable Conceptual Plan or DWOP section that is being impacted by the addition or change; and

(c) Documentation demonstrating payment of the service fee listed in § 250.125.