30 C.F.R. §§ 250.236–250.242

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

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

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

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;

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;

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.);

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

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

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;

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;

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

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

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

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

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

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

General design and fabrication information for each pipeline riser system;

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: