30 C.F.R. Part 250 — OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF

§ 250.101 Authority and applicability. The Secretary of the Interior (Secretary) authorized the Bureau of Safety and Environmental Enforcement (BSEE) to regulate oil, gas, and sulphur exploration, development, and production operations on the Outer Continental Shelf (OCS). Under the Secretary's authority, the Director requires that all operations: (a) Be conducted according to the OCS Lands Act (OCSLA), the regulations in this part, BSEE orders, the lease or right-of-way, and other applicable laws, regulations, and amendments; and (b) Conform to sound conservation practice to preserve, protect, and develop mineral resources of the OCS to: (1) Make resources available to meet the Nation's energy needs; (2) Balance orderly energy resource development with protection of the human, marine, and coastal environments; (3) Ensure the public receives a fair and equitable return on the resources of the OCS; (4) Preserve and maintain free enterprise competition; and (5) Minimize or eliminate conflicts between the exploration, development, and production of oil and natural gas and the recovery of other resources.

§ 250.102 What does this part do? (a) This part 250 contains the regulations of the BSEE Offshore program that govern oil, gas, and sulphur exploration, development, and production operations on the OCS. When you conduct operations on the OCS, you must submit requests, applications, and notices, or provide supplemental information for BSEE approval. (b) The following table of general references shows where to look for information about these processes.

§ 250.103 Where can I find more information about the requirements in this part? BSEE may issue Notices to Lessees and Operators (NTLs) that clarify, supplement, or provide more detail about certain requirements. NTLs may also outline what you must provide as required information in your various submissions to BSEE.

§ 250.104 How may I appeal a decision made under BSEE regulations? To appeal orders or decisions issued under BSEE regulations in 30 CFR parts 250 to 282, follow the procedures in 30 CFR part 290.

§ 250.105 Definitions. Terms used in this part will have the meanings given in the Act and as defined in this section: Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.). Affected State means with respect to any program, plan, lease sale, or other activity proposed, conducted, or approved under the provisions of the Act, any State: (1) The laws of which are declared, under section 4(a)(2) of the Act, to be the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted; (2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or installation or other device permanently or temporarily attached to the seabed; (3) Which is receiving, or according to the proposed activity, will receive oil for processing, refining, or transshipment that was extracted from the OCS and transported directly to such State by means of vessels or by a combination of means including vessels; (4) Which is designated by the Secretary as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the OCS; or (5) In which the Secretary finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents to the marine or coastal environment in the event of any oil spill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities. Air pollutant means any airborne agent or combination of agents for which the Environmental Protection Agency (EPA) has established, under section 109 of the Clean Air Act, national primary or secondary ambient air quality standards. Analyzed geological information means data collected under a permit or a lease that have been analyzed. Analysis may include, but is not limited to, identification of lithologic and fossil content, core analysis, laboratory analyses of physical and chemical properties, well logs or charts, results from formation fluid tests, and descriptions of hydrocarbon occurrences or hazardous conditions. Ancillary activities mean those activities on your lease or unit that you: (1) Conduct to obtain data and information to ensure proper exploration or development of your lease or unit; and (2) Can conduct without Bureau of Ocean Energy Management (BOEM) approval of an application or permit. Archaeological interest means capable of providing scientific or humanistic understanding of past human behavior, cultural adaptation, and related topics through the application of scientific or scholarly techniques, such as controlled observation, contextual measurement, controlled collection, analysis, interpretation, and explanation. Archaeological resource means any material remains of human life or activities that are at least 50 years of age and that are of archaeological interest. Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas (for more information on these areas, see the Proposed Final OCS Oil and Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/Oil-and-Gas-Energy-Program/Leasing/Five-Year-Program/2012-2017/Program-Area-Maps/index.aspx). Arctic OCS conditions means, for the purposes of this part, the conditions operators can reasonably expect during operations on the Arctic OCS. Such conditions, depending on the time of year, include, but are not limited to: Extreme cold, freezing spray, snow, extended periods of low light, strong winds, dense fog, sea ice, strong currents, and dangerous sea states. Remote location, relative lack of infrastructure, and the existence of subsistence hunting and fishing areas are also characteristic of the Arctic region. Attainment area means, for any air pollutant, an area that is shown by monitored data or that is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) not to exceed any primary or secondary ambient air quality standards established by EPA. Best available and safest technology (BAST) means the best available and safest technologies that the BSEE Director determines to be economically feasible wherever failure of equipment would have a significant effect on safety, health, or the environment. Best available control technology (BACT) means an emission limitation based on the maximum degree of reduction for each air pollutant subject to regulation, taking into account energy, environmental and economic impacts, and other costs. The Regional Supervisor will verify the BACT on a case-by-case basis, and it may include reductions achieved through the application of processes, systems, and techniques for the control of each air pollutant. BOP systems and related equipment includes all pressure controlling and pressure containing well control equipment that may or will be exposed to the well's MASP during drilling, completion, workover, intervention, or abandonment. Well control equipment includes equipment that is installed for the purpose of pressure control and pressure containment when it becomes necessary to physically enter a well bore during drilling, completion, workover, intervention, or abandonment modes of operation. Cap and flow system means an integrated suite of equipment and vessels, including a capping stack and associated flow lines, that, when installed or positioned, is used to control the flow of fluids escaping from the well by conveying the fluids to the surface to a vessel or facility equipped to process the flow of oil, gas, and water. A cap and flow system is a high pressure system that includes the capping stack and piping necessary to convey the flowing fluids through the choke manifold to the surface equipment. Capping stack means a mechanical device, including one that is pre-positioned, that can be installed on top of a subsea or surface wellhead or blowout preventer to stop the uncontrolled flow of fluids into the environment. Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the terrestrial ecosystem from the shoreline inward to the boundaries of the coastal zone. Coastal zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder) strongly influenced by each other and in proximity to the shorelands of the several coastal States. The coastal zone includes islands, transition and intertidal areas, salt marshes, wetlands, and beaches. The coastal zone extends seaward to the outer limit of the U.S. territorial sea and extends inland from the shorelines to the extent necessary to control shorelands, the uses of which have a direct and significant impact on the coastal waters, and the inward boundaries of which may be identified by the several coastal States, under the authority in section 305(b)(1) of the Coastal Zone Management Act (CZMA) of 1972. Competitive reservoir means a reservoir in which there are one or more producible or producing well completions on each of two or more leases or portions of leases, with different lease operating interests, from which the lessees plan future production. Containment dome means a non-pressurized container that can be used to collect fluids escaping from the well or equipment below the sea surface or from seeps by suspending the device over the discharge or seep location. The containment dome includes all of the equipment necessary to capture and convey fluids to the surface. Correlative rights when used with respect to lessees of adjacent leases, means the right of each lessee to be afforded an equal opportunity to explore for, develop, and produce, without waste, minerals from a common source. Data means facts and statistics, measurements, or samples that have not been analyzed, processed, or interpreted. Departures mean approvals granted by the appropriate BSEE or BOEM representative for operating requirements/procedures other than those specified in the regulations found in this part. These requirements/procedures may be necessary to control a well; properly develop a lease; conserve natural resources, or protect life, property, or the marine, coastal, or human environment. Development means those activities that take place following discovery of minerals in paying quantities, including but not limited to geophysical activity, drilling, platform construction, and operation of all directly related onshore support facilities, and which are for the purpose of producing the minerals discovered. Development geological and geophysical (G&G) activities mean those G&G and related data-gathering activities on your lease or unit that you conduct following discovery of oil, gas, or sulphur in paying quantities to detect or imply the presence of oil, gas, or sulphur in commercial quantities. Director means the Director of BSEE of the U.S. Department of the Interior, or an official authorized to act on the Director's behalf. District Manager means the BSEE officer with authority and responsibility for operations or other designated program functions for a district within a BSEE Region. For activities on the Alaska OCS, any reference in this part to District Manager means the BSEE Regional Supervisor. Eastern Gulf of America means all OCS areas of the Gulf of America the BOEM Director decides are adjacent to the State of Florida. The Eastern Gulf of America-is not the same as the Eastern Planning Area, an area established for OCS lease sales. Emission offsets mean emission reductions obtained from facilities, either onshore or offshore, other than the facility or facilities covered by the proposed Exploration Plan (EP) or Development and Production Plan (DPP). Enhanced recovery operations mean pressure maintenance operations, secondary and tertiary recovery, cycling, and similar recovery operations that alter the natural forces in a reservoir to increase the ultimate recovery of oil or gas. Existing facility, as used in 30 CFR 550.303, means an OCS facility described in an Exploration Plan or a Development and Production Plan approved before June 2, 1980. Exploration means the commercial search for oil, gas, or sulphur. Activities classified as exploration include but are not limited to: (1) Geophysical and geological (G&G) surveys using magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, coring, or other systems to detect or imply the presence of oil, gas, or sulphur; and (2) Any drilling conducted for the purpose of searching for commercial quantities of oil, gas, and sulphur, including the drilling of any additional well needed to delineate any reservoir to enable the lessee to decide whether to proceed with development and production. Facility means: (1) As used in § 250.130, all installations permanently or temporarily attached to the seabed on the OCS (including manmade islands and bottom-sitting structures). They include mobile offshore drilling units (MODUs) or other vessels engaged in drilling or downhole operations, used for oil, gas or sulphur drilling, production, or related activities. They include all floating production systems (FPSs), variously described as column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. They also include facilities for product measurement and royalty determination (e.g., lease Automatic Custody Transfer Units, gas meters) of OCS production on installations not on the OCS. Any group of OCS installations interconnected with walkways, or any group of installations that includes a central or primary installation with processing equipment and one or more satellite or secondary installations is a single facility. The Regional Supervisor may decide that the complexity of the individual installations justifies their classification as separate facilities. (2) As used in 30 CFR 550.303, means all installations or devices permanently or temporarily attached to the seabed. They include mobile offshore drilling units (MODUs), even while operating in the “tender assist” mode (i.e., with skid-off drilling units) or other vessels engaged in drilling or downhole operations. They are used for exploration, development, and production activities for oil, gas, or sulphur and emit or have the potential to emit any air pollutant from one or more sources. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. During production, multiple installations or devices are a single facility if the installations or devices are at a single site. Any vessel used to transfer production from an offshore facility is part of the facility while it is physically attached to the facility. (3) As used in § 250.490(b), means a vessel, a structure, or an artificial island used for drilling, well completion, well-workover, or production operations. (4) As used in §§ 250.900 through 250.921, means all installations or devices permanently or temporarily attached to the seabed. They are used for exploration, development, and production activities for oil, gas, or sulphur and emit or have the potential to emit any air pollutant from one or more sources. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. During production, multiple installations or devices are a single facility if the installations or devices are at a single site. Any vessel used to transfer production from an offshore facility is part of the facility while it is physically attached to the facility. (5) As used in subpart S of this part, all types of structures permanently or temporarily attached to the seabed (e.g., mobile offshore drilling units (MODUs); floating production systems; floating production, storage and offloading facilities; tension-leg platforms; and spars) that are used for exploration, development, and production activities for oil, gas, or sulphur in the OCS. Facilities also include DOI-regulated pipelines. Flaring means the burning of natural gas as it is released into the atmosphere. Gas reservoir means a reservoir that contains hydrocarbons predominantly in a gaseous (single-phase) state. Gas-well completion means a well completed in a gas reservoir or in the associated gas-cap of an oil reservoir. Geological and geophysical (G&G) explorations mean those G&G surveys on your lease or unit that use seismic reflection, seismic refraction, magnetic, gravity, gas sniffers, coring, or other systems to detect or imply the presence of oil, gas, or sulphur in commercial quantities. Governor means the Governor of a State, or the person or entity designated by, or under, State law to exercise the powers granted to such Governor under the Act. H2S absent means: (1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H2S in concentrations that could potentially result in atmospheric concentrations of 20 ppm or more of H2S; or (2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an absence of H2S throughout the area to be drilled. H2S present means drilling, logging, coring, testing, or producing operations have confirmed the presence of H2S in concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of H2S. H2S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2S has been confirmed. HPHT environment means when one or more of the following well conditions exist: (1) The drilling, completion, workover, intervention, injection, production, or abandonment of the well requires pressure controlling or pressure containing equipment, including well control equipment, assigned a pressure rating greater than 15,000 psia or a temperature rating greater than 350 degrees Fahrenheit; (2) The MASP or SITP is greater than 15,000 psia at the seafloor for a well with a subsea wellhead or at the surface for a well with a surface wellhead; or (3) The flowing temperature is greater than 350 degrees Fahrenheit at the seafloor for a well with a subsea wellhead or at the surface for a well with a surface wellhead. Human environment means the physical, social, and economic components, conditions, and factors that interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the OCS. Interpreted geological information means geological knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of data and analyzed geological information. Interpreted geophysical information means geophysical knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geophysical data and analyzed geophysical information. Lease means an agreement that is issued under section 8 or maintained under section 6 of the Act and that authorizes exploration for, and development and production of, minerals. The term also means the area covered by that authorization, whichever the context requires. Lease term pipelines mean those pipelines owned and operated by a lessee or operator that are completely contained within the boundaries of a single lease, unit, or contiguous (not cornering) leases of that lessee or operator. Lessee means a person who has entered into a lease with the United States to explore for, develop, and produce the leased minerals. The term lessee also includes the BOEM-approved assignee of the lease, and the owner or the BOEM-approved assignee of operating rights for the lease. Major Federal action means any action or proposal by the Secretary that is subject to the provisions of section 102(2)(C) of the National Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that will have a significant impact on the quality of the human environment requiring preparation of an environmental impact statement under section 102(2)(C) of the National Environmental Policy Act). Marine environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the marine ecosystem. These include the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and wetlands within the coastal zone and on the OCS. Material remains mean physical evidence of human habitation, occupation, use, or activity, including the site, location, or context in which such evidence is situated. Maximum efficient rate (MER) means the maximum sustainable daily oil or gas withdrawal rate from a reservoir that will permit economic development and depletion of that reservoir without detriment to ultimate recovery. Maximum production rate (MPR) means the approved maximum daily rate at which oil or gas may be produced from a specified oil-well or gas-well completion. Minerals include oil, gas, sulphur, geopressured-geothermal and associated resources, and all other minerals that are authorized by an Act of Congress to be produced. Natural resources include, without limiting the generality thereof, oil, gas, and all other minerals, and fish, shrimp, oysters, clams, crabs, lobsters, sponges, kelp, and other marine animal and plant life but does not include water power or the use of water for the production of power. Nonattainment area means, for any air pollutant, an area that is shown by monitored data or that is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) to exceed any primary or secondary ambient air quality standard established by EPA. Nonsensitive reservoir means a reservoir in which ultimate recovery is not decreased by high reservoir production rates. Oil reservoir means a reservoir that contains hydrocarbons predominantly in a liquid (single-phase) state. Oil reservoir with an associated gas cap means a reservoir that contains hydrocarbons in both a liquid and gaseous (two-phase) state. Oil-well completion means a well completed in an oil reservoir or in the oil accumulation of an oil reservoir with an associated gas cap. Operating rights mean any interest held in a lease with the right to explore for, develop, and produce leased substances. Operator means the person the lessee(s) designates as having control or management of operations on the leased area or a portion thereof. An operator may be a lessee, the BSEE-approved or BOEM-approved designated agent of the lessee(s), or the holder of operating rights under a BOEM-approved operating rights assignment. Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Person includes a natural person, an association (including partnerships, joint ventures, and trusts), a State, a political subdivision of a State, or a private, public, or municipal corporation. Pipelines are the piping, risers, and appurtenances installed for transporting oil, gas, sulphur, and produced waters. Processed geological or geophysical information means data collected under a permit or a lease that have been processed or reprocessed. Processing involves changing the form of data to facilitate interpretation. Processing operations may include, but are not limited to, applying corrections for known perturbing causes, rearranging or filtering data, and combining or transforming data elements. Reprocessing is the additional processing other than ordinary processing used in the general course of evaluation. Reprocessing operations may include varying identified parameters for the detailed study of a specific problem area. Production means those activities that take place after the successful completion of any means for the removal of minerals, including such removal, field operations, transfer of minerals to shore, operation monitoring, maintenance, and workover operations. Production areas are those areas where flammable petroleum gas, volatile liquids or sulphur are produced, processed (e.g., compressed), stored, transferred (e.g., pumped), or otherwise handled before entering the transportation process. Projected emissions mean emissions, either controlled or uncontrolled, from a source or sources. Prospect means a geologic feature having the potential for mineral deposits. Regional Director means the BSEE officer with responsibility and authority for a Region within BSEE. Regional Supervisor means the BSEE officer with responsibility and authority for operations or other designated program functions within a BSEE Region. Right-of-Use and Easement (RUE) means a right to use a portion of the seabed at an OCS site, other than on a lease you own, to construct, secure to the seafloor, use, modify, or maintain platforms, sea floor production equipment, artificial islands, facilities, installations, and other devices, established to support the exploration, development, or production of oil and gas, mineral, or energy resources from an OCS or State submerged lands lease. Right-of-way pipelines are those pipelines that are contained within: (1) The boundaries of a single lease or unit, but are not owned and operated by a lessee or operator of that lease or unit; (2) The boundaries of contiguous (not cornering) leases that do not have a common lessee or operator; (3) The boundaries of contiguous (not cornering) leases that have a common lessee or operator but are not owned and operated by that common lessee or operator; or (4) An unleased block(s). Routine operations, for the purposes of subpart F, mean any of the following operations conducted on a well with the tree installed: (1) Cutting paraffin; (2) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves that can be removed by wireline operations; (3) Bailing sand; (4) Pressure surveys; (5) Swabbing; (6) Scale or corrosion treatment; (7) Caliper and gauge surveys; (8) Corrosion inhibitor treatment; (9) Removing or replacing subsurface pumps; (10) Through-tubing logging (diagnostics); (11) Wireline fishing; (12) Setting and retrieving other subsurface flow-control devices; and (13) Acid treatments. Sensitive reservoir means a reservoir in which the production rate will affect ultimate recovery. Significant archaeological resource means those archaeological resources that meet the criteria of significance for eligibility to the National Register of Historic Places as defined in 36 CFR 60.4, or its successor. Source control and containment equipment (SCCE) means the capping stack, cap and flow system, containment dome, and/or other subsea and surface devices, equipment, and vessels the collective purpose of which is to control a spill source and stop the flow of fluids into the environment or to contain fluids escaping into the environment. “Surface devices” refers to equipment mounted or staged on a barge, vessel, or facility to separate, treat, store and/or dispose of fluids conveyed to the surface by the cap and flow system or the containment dome. “Subsea devices” includes, but is not limited to, remotely operated vehicles, anchors, buoyancy equipment, connectors, cameras, controls and other subsea equipment necessary to facilitate the deployment, operation, and retrieval of the SCCE. The SCCE does not include a blowout preventer. Suspension means a granted or directed deferral of the requirement to produce (Suspension of Production (SOP)) or to conduct leaseholding operations (Suspension of Operations (SOO)). Venting means the release of gas into the atmosphere without igniting it. This includes gas that is released underwater and bubbles to the atmosphere. Waste of oil, gas, or sulphur means: (1) The physical waste of oil, gas, or sulphur; (2) The inefficient, excessive, or improper use, or the unnecessary dissipation of reservoir energy; (3) The locating, spacing, drilling, equipping, operating, or producing of any oil, gas, or sulphur well(s) in a manner that causes or tends to cause a reduction in the quantity of oil, gas, or sulphur ultimately recoverable under prudent and proper operations or that causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas; or (4) The inefficient storage of oil. Welding means all activities connected with welding, including hot tapping and burning. Wellbay is the area on a facility within the perimeter of the outermost wellheads. Well-completion operations mean the work conducted to establish production from a well after the production-casing string has been set, cemented, and pressure-tested. Well-control fluid means drilling mud, completion fluid, or workover fluid as appropriate to the particular operation being conducted. Western Gulf of America means all OCS areas of the Gulf of America except those the BOEM Director decides are adjacent to the State of Florida. The Western Gulf of America is not the same as the Western Planning Area, an area established for OCS lease sales. Workover operations mean the work conducted on wells after the initial well-completion operation for the purpose of maintaining or restoring the productivity of a well. You means a lessee, the owner or holder of operating rights, a designated operator or agent of the lessee(s), a pipeline right-of-way holder, or a State lessee granted a right-of-use and easement.

§ 250.106 What standards will the Director use to regulate lease operations? The Director will regulate all operations under a lease, right-of-use and easement, or right-of-way to: (a) Promote orderly exploration, development, and production of mineral resources; (b) Prevent injury or loss of life; (c) Prevent damage to or waste of any natural resource, property, or the environment; and (d) Cooperate and consult with affected States, local governments, other interested parties, and relevant Federal agencies.

§ 250.107 What must I do to protect health, safety, property, and the environment? (a) You must protect health, safety, property, and the environment by: (1) Performing all operations in a safe and workmanlike manner; (2) Maintaining all equipment and work areas in a safe condition; (3) Utilizing recognized engineering practices that reduce risks to the lowest level practicable when conducting design, fabrication, installation, operation, inspection, repair, and maintenance activities; and (4) Complying with all lease, plan, and permit terms and conditions. (b) You must immediately control, remove, or otherwise correct any hazardous oil and gas accumulation or other health, safety, or fire hazard. (c) Best available and safest technology. (1) On all new drilling and production operations and, except as provided in paragraph (c)(3) of this section, on existing operations, you must use the best available and safest technologies (BAST) which the Director determines to be economically feasible whenever the Director determines that failure of equipment would have a significant effect on safety, health, or the environment, except where the Director determines that the incremental benefits are clearly insufficient to justify the incremental costs of utilizing such technologies. (2) Conformance with BSEE regulations will be presumed to constitute the use of BAST unless and until the Director determines that other technologies are required pursuant to paragraph (c)(1) of this section. (3) The Director may waive the requirement to use BAST on a category of existing operations if the Director determines that use of BAST by that category of existing operations would not be practicable. The Director may waive the requirement to use BAST on an existing operation at a specific facility if you submit a waiver request demonstrating that the use of BAST would not be practicable. (d) BSEE may issue orders to ensure compliance with this part, including, but not limited to, orders to produce and submit records and to inspect, repair, and/or replace equipment. BSEE may also issue orders to shut-in operations of a component or facility because of a threat of serious, irreparable, or immediate harm to health, safety, property, or the environment posed by those operations or because the operations violate law, including a regulation, order, or provision of a lease, plan, or permit.

§ 250.108 What requirements must I follow for cranes and other material-handling equipment? (a) All cranes installed on fixed platforms must be operated in accordance with American Petroleum Institute's Recommended Practice for Operation and Maintenance of Offshore Cranes, API Recommended Practice 2D (incorporated by reference, see § 250.198). (b) All cranes installed on fixed platforms must be equipped with a functional anti-two block device. (c) If a fixed platform is installed after March 17, 2003, all cranes on the platform must meet the requirements of American Petroleum Institute Specification for Offshore Pedestal Mounted Cranes, API Specification 2C (incorporated by reference, see § 250.198). (d) All cranes manufactured after March 17, 2003, and installed on a fixed platform, must meet the requirements of API Spec 2C. (e) You must maintain records specific to a crane or the operation of a crane installed on an OCS fixed platform, as follows: (1) Retain all design and construction records, including installation records for any anti-two block safety devices, for the life of the crane. The records must be kept at the OCS fixed platform. (2) Retain all inspection, testing, and maintenance records of cranes for at least 4 years. The records must be kept at the OCS fixed platform. (3) Retain the qualification records of the crane operator and all rigger personnel for at least 4 years. The records must be kept at the OCS fixed platform. (f) You must operate and maintain all other material-handling equipment in a manner that ensures safe operations and prevents pollution. Editorial Note:At 91 FR 35346, June 10, 2026, § 250.108(d) was amended; however, the amendment could not be incorporated due to inaccurate instructions.

§ 250.109 What documents must I prepare and maintain related to welding? (a) You must submit a Welding Plan to the District Manager before you begin drilling or production activities on a lease. You may not begin welding until the District Manager has approved your plan. (b) You must keep the following at the site where welding occurs: (1) A copy of the plan and its approval letter; and (2) Drawings showing the designated safe-welding areas.

§ 250.110 What must I include in my welding plan? You must include all of the following in the welding plan that you prepare under § 250.109: (a) Standards or requirements for welders; (b) How you will ensure that only qualified personnel weld; (c) Practices and procedures for safe welding that address: (1) Welding in designated safe areas; (2) Welding in undesignated areas, including wellbay; (3) Fire watches; (4) Maintenance of welding equipment; and (5) Plans showing all designated safe-welding areas. (d) How you will prevent spark-producing activities (i.e., grinding, abrasive blasting/cutting and arc-welding) in hazardous locations.

§ 250.111 Who oversees operations under my welding plan? A welding supervisor or a designated person in charge must be thoroughly familiar with your welding plan. This person must ensure that each welder is properly qualified according to the welding plan. This person also must inspect all welding equipment before welding.

§ 250.112 What standards must my welding equipment meet? Your welding equipment must meet the following requirements: (a) All engine-driven welding equipment must be equipped with spark arrestors and drip pans; (b) Welding leads must be completely insulated and in good condition; (c) Hoses must be leak-free and equipped with proper fittings, gauges, and regulators; and (d) Oxygen and fuel gas bottles must be secured in a safe place.

§ 250.113 What procedures must I follow when welding? (a) Before you weld, you must move any equipment containing hydrocarbons or other flammable substances at least 35 feet horizontally from the welding area. You must move similar equipment on lower decks at least 35 feet from the point of impact where slag, sparks, or other burning materials could fall. If moving this equipment is impractical, you must protect that equipment with flame-proofed covers, shield it with metal or fire-resistant guards or curtains, or render the flammable substances inert. (b) While you weld, you must monitor all water-discharge-point sources from hydrocarbon-handling vessels. If a discharge of flammable fluids occurs, you must stop welding. (c) If you cannot weld in one of the designated safe-welding areas that you listed in your safe welding plan, you must meet the following requirements: (1) You may not begin welding until: (i) The welding supervisor or designated person in charge advises in writing that it is safe to weld. (ii) You and the designated person in charge inspect the work area and areas below it for potential fire and explosion hazards. (2) During welding, the person in charge must designate one or more persons as a fire watch. The fire watch must: (i) Have no other duties while actual welding is in progress; (ii) Have usable firefighting equipment; (iii) Remain on duty for 30 minutes after welding activities end; and (iv) Maintain a continuous surveillance with a portable gas detector during the welding and burning operation if welding occurs in an area not equipped with a gas detector. (3) You may not weld piping, containers, tanks, or other vessels that have contained a flammable substance unless you have rendered the contents inert and the designated person in charge has determined it is safe to weld. This does not apply to approved hot taps. (4) You may not weld within 10 feet of a wellbay unless you have shut in all producing wells in that wellbay. (5) You may not weld within 10 feet of a production area, unless you have shut in that production area. (6) You may not weld while you drill, complete, workover, or conduct wireline operations unless: (i) The fluids in the well (being drilled, completed, worked over, or having wireline operations conducted) are noncombustible; and (ii) You have precluded the entry of formation hydrocarbons into the wellbore by either mechanical means or a positive overbalance toward the formation.

§ 250.114 How must I install, maintain, and operate electrical equipment? The requirements in this section apply to all electrical equipment on all platforms, artificial islands, fixed structures, and their facilities. (a) You must classify all areas according to API Recommended Practice 500 (incorporated by reference, see § 250.198), or API Recommended Practice 505 (incorporated by reference, see § 250.198). (b) Employees who maintain your electrical systems must have expertise in area classification and the performance, operation and hazards of electrical equipment. (c) You must install all electrical systems according to API Recommended Practice 14F (incorporated by reference, see § 250.198), or API Recommended Practice 14FZ (incorporated by reference, see § 250.198). (d) On each engine that has an electric ignition system, you must use an ignition system designed and maintained to reduce the release of electrical energy.

§ 250.115 What are the procedures for, and effects of, incorporation of documents by reference in this part? For the documents incorporated by reference in this part: (a) Incorporation by reference of a document is limited to the edition of the document, or the specific edition and supplement or addendum, that is cited in § 250.198. Future amendments or revisions of the incorporated document are not included. BSEE will publish any changes to the incorporation of the document in the Federal Register and amend § 250.198 as appropriate. (b) BSEE may make a rule amending the incorporation of a document effective without prior opportunity for public comment when BSEE determines: (1) That the revisions to the document result in safety improvements or represent new industry standard technology and do not impose undue costs on the affected parties; and (2) BSEE meets the requirements for making a rule immediately effective under 5 U.S.C. 553. (c) The effect of incorporation by reference of a document into the regulations in this part is that the incorporated document is a requirement. When a section in this part refers to an incorporated document, you are responsible for complying with the provisions of that entire document, except to the extent that the section that refers to the document provides otherwise. When a section in this part refers to a part of an incorporated document, you are responsible for complying with that part of the document as provided in that section. (d) Under §§ 250.141 and 250.142, you may comply with a later edition of a specific document incorporated by reference, provided: (1) You show that complying with the later edition provides a degree of protection, safety, or performance equal to or better than would be achieved by compliance with the listed edition; and (2) You obtain prior written approval for alternative compliance from the authorized BSEE official.

§§ 250.116-250.117 [Reserved]

§ 250.118 Will BSEE approve gas injection? The Regional Supervisor may authorize you to inject gas on the OCS, on and off-lease, to promote conservation of natural resources and to prevent waste. (a) To receive BSEE approval for injection, you must: (1) Show that the injection will not result in undue interference with operations under existing leases; and (2) Submit a written application to the Regional Supervisor for injection of gas. (b) The Regional Supervisor will approve gas injection applications that: (1) Enhance recovery; (2) Prevent flaring of casinghead gas; or (3) Implement other conservation measures approved by the Regional Supervisor.

§ 250.119 [Reserved]

§ 250.120 How does injecting, storing, or treating gas affect my royalty payments? (a) If you produce gas from an OCS lease and inject it into a reservoir on the lease or unit for the purposes cited in § 250.118(b), you are not required to pay royalties until you remove or sell the gas from the reservoir. (b) If you produce gas from an OCS lease and store it according to 30 CFR 550.119, you must pay royalty before injecting it into the storage reservoir. (c) If you produce gas from an OCS lease and treat it at an off-lease or off-unit location, you must pay royalties when the gas is first produced.

§ 250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in place and injected gas, when you produce gas from the reservoir you must use a BSEE-approved formula to determine the amounts of injected or stored gas and gas original to the reservoir.

§ 250.122 What effect does subsurface storage have on the lease term? If you use a lease area for subsurface storage of gas, it does not affect the continuance or expiration of the lease.

§ 250.123 [Reserved]

§ 250.124 Will BSEE approve gas injection into the cap rock containing a sulphur deposit? To receive the Regional Supervisor's approval to inject gas into the cap rock of a salt dome containing a sulphur deposit, you must show that the injection: (a) Is necessary to recover oil and gas contained in the cap rock; and (b) Will not significantly increase potential hazards to present or future sulphur mining operations.

§ 250.125 Service fees. (a) The table in this paragraph (a) shows the fees that you must pay to BSEE for the services listed. The fees will be adjusted periodically according to the Implicit Price Deflator for Gross Domestic Product by publication of a document in the Federal Register. If a significant adjustment is needed to arrive at the new actual cost for any reason other than inflation, then a proposed rule containing the new fees will be published in the Federal Register for comment. (b) Payment of the fees listed in paragraph (a) of this section must accompany the submission of the document for approval or be sent to an office identified by the Regional Director. Once a fee is paid, it is nonrefundable, even if an application or other request is withdrawn. If your application is returned to you as incomplete, you are not required to submit a new fee when you submit the amended application. (c) Verbal approvals are occasionally given in special circumstances. Any action that will be considered a verbal permit approval requires either a paper permit application to follow the verbal approval or an electronic application submittal within 72 hours. Payment must be made with the completed paper or electronic application.

§ 250.126 Electronic payment instructions. (a) You must file all payments electronically through the Fees for Services Page on the BSEE website at https://www.bsee.gov/who-we-are/working-with-us/Fees-for-Services. This includes, but is not limited to, all OCS applications, permits, or any filing fees. You must include a copy of the Pay.gov confirmation receipt page with your application, permit, or filing fee. (b) If you submitted an application or permit through eWell, you must use the interactive payment feature in that system, which directs you through Pay.gov to make a payment. It is recommended that you keep a copy of your payment confirmation receipt in the event that any questions arise regarding your transaction.

§ 250.130 Why does BSEE conduct inspections? BSEE will inspect OCS facilities and any vessels engaged in drilling or other downhole operations. These include facilities under jurisdiction of other Federal agencies that we inspect by agreement. We conduct these inspections: (a) To verify that you are conducting operations according to the Act, the regulations, the lease, right-of-way, the BOEM-approved Exploration Plan or Development and Production Plans; or right-of-use and easement, and other applicable laws and regulations; and (b) To determine whether equipment designed to prevent or ameliorate blowouts, fires, spillages, or other major accidents has been installed and is operating properly according to the requirements of this part.

§ 250.131 Will BSEE notify me before conducting an inspection? BSEE conducts both scheduled and unscheduled inspections.

§ 250.132 What must I do when BSEE conducts an inspection? (a) When BSEE conducts an inspection, you must provide: (1) Access to all platforms, artificial islands, and other installations on your leases or associated with your lease, right-of-use and easement, or right-of-way; and (2) Helicopter landing sites and refueling facilities for any helicopters we use to regulate offshore operations. (b) You must make the following available for us to inspect: (1) The area covered under a lease, right-of-use and easement, right-of-way, or permit; (2) All improvements, structures, and fixtures on these areas; and (3) All records of design, construction, operation, maintenance, repairs, or investigations on or related to the area.

§ 250.133 Will BSEE reimburse me for my expenses related to inspections? Upon request, BSEE will reimburse you for food, quarters, and transportation that you provide for BSEE representatives while they inspect lease facilities and operations. You must send us your reimbursement request within 90 days of the inspection.

§ 250.135 What will BSEE do if my operating performance is unacceptable? BSEE will determine if your operating performance is unacceptable. BSEE will refer a determination of unacceptable performance to BOEM, who may disapprove or revoke your designation as operator on a single facility or multiple facilities. We will give you adequate notice and opportunity for a review by BSEE officials before making a determination that your operating performance is unacceptable.

§ 250.136 How will BSEE determine if my operating performance is unacceptable? In determining if your operating performance is unacceptable, BSEE will consider, individually or collectively: (a) Accidents and their nature; (b) Pollution events, environmental damages and their nature; (c) Incidents of noncompliance; (d) Civil penalties; (e) Failure to adhere to OCS lease obligations; or (f) Any other relevant factors.

§ 250.140 When will I receive an oral approval? When you apply for BSEE approval of any activity, we normally give you a written decision. The following table shows circumstances under which we may give an oral approval.

§ 250.141 May I ever use alternate procedures or equipment? You may use alternate procedures or equipment after receiving approval as described in this section. (a) Any alternate procedures or equipment that you propose to use must provide a level of safety and environmental protection that equals or surpasses current BSEE requirements. (b) You must receive the District Manager's or Regional Supervisor's written approval before you can use alternate procedures or equipment. (c) To receive approval, you must either submit information or give an oral presentation to the appropriate Regional Supervisor. Your presentation must describe the site-specific application(s), performance characteristics, and safety features of the proposed procedure or equipment.

§ 250.142 How do I receive approval for departures? We may approve departures to the operating requirements. You may apply for a departure by writing to the District Manager or Regional Supervisor.

§§ 250.143-250.144 [Reserved]

§ 250.145 How do I designate an agent or a local agent? (a) You or your designated operator may designate for the Regional Supervisor's approval, or the Regional Director may require you to designate an agent empowered to fulfill your obligations under the Act, the lease, or the regulations in this part. (b) You or your designated operator may designate for the Regional Supervisor's approval a local agent empowered to receive notices and submit requests, applications, notices, or supplemental information.

§ 250.146 Who is responsible for fulfilling leasehold obligations? (a) When you are not the sole lessee, you and your co-lessee(s) are jointly and severally responsible for fulfilling your obligations under the provisions of 30 CFR parts 250 through 282 and 30 CFR parts 550 through 582 unless otherwise provided in these regulations. (b) If your designated operator fails to fulfill any of your obligations under 30 CFR parts 250 through 282 and 30 CFR parts 550 through 582, the Regional Supervisor may require you or any or all of your co-lessees to fulfill those obligations or other operational obligations under the Act, the lease, or the regulations. (c) Whenever the regulations in 30 CFR parts 250 through 282 and 30 CFR parts 550 through 582 require the lessee to meet a requirement or perform an action, the lessee, operator (if one has been designated), and the person actually performing the activity to which the requirement applies are jointly and severally responsible for complying with the regulation.

§ 250.150 How do I name facilities and wells in the Gulf of America Region? (a) Assign each facility a letter designation except for those types of facilities identified in paragraph (c)(1) of this section. For example, A, B, CA, or CB. (1) After a facility is installed, rename each predrilled well that was assigned only a number and was suspended temporarily at the mudline or at the surface. Use a letter and number designation. The letter used must be the same as that of the production facility, and the number used must correspond to the order in which the well was completed, not necessarily the number assigned when it was drilled. For example, the first well completed for production on Facility A would be renamed Well A-1, the second would be Well A-2, and so on; and (2) When you have more than one facility on a block, each facility installed, and not bridge-connected to another facility, must be named using a different letter in sequential order. For example, EC 222A, EC 222B, EC 222C. (3) When you have more than one facility on multiple blocks in a local area being co-developed, each facility installed and not connected with a walkway to another facility should be named using a different letter in sequential order with the block number corresponding to the block on which the platform is located. For example, EC 221A, EC 222B, and EC 223C. (b) In naming multiple well caissons, you must assign a letter designation. (c) In naming single well caissons, you must use certain criteria as follows: (1) For single well caissons not attached to a facility with a walkway, use the well designation. For example, Well No. 1; (2) For single well caissons attached to a facility with a walkway, use the same designation as the facility. For example, rename Well No.10 as A-10; and (3) For single well caissons with production equipment, use a letter designation for the facility name and a letter plus number designation for the well. For example, the Well No. 1 caisson would be designated as Facility A, and the well would be Well A-1.

§ 250.151 How do I name facilities in the Pacific Region? The operator assigns a name to the facility.

§ 250.152 How do I name facilities in the Alaska Region? Facilities will be named and identified according to the Regional Director's directions.

§ 250.153 Do I have to rename an existing facility or well? You do not have to rename facilities installed and wells drilled before January 27, 2000, unless the Regional Director requires it.

§ 250.154 What identification signs must I display? (a) You must identify all facilities, artificial islands, and mobile offshore drilling units with a sign maintained in a legible condition. (1) You must display an identification sign that can be viewed from the waterline on at least one side of the platform. The sign must use at least 3-inch letters and figures. (2) When helicopter landing facilities are present, you must display an additional identification sign that is visible from the air. The sign must use at least 12-inch letters and figures and must also display the weight capacity of the helipad unless noted on the top of the helipad. If this sign is visible to both helicopter and boat traffic, then the sign in paragraph (a)(1) of this section is not required. (3) Your identification sign must: (i) List the name of the lessee or designated operator; (ii) In the GOA-OCS Region, list the area designation or abbreviation and the block number of the facility location as depicted on OCS Official Protraction Diagrams or leasing maps; (iii) In the Pacific OCS Region, list the lease number on which the facility is located; and (iv) List the name of the platform, structure, artificial island, or mobile offshore drilling unit. (b) You must identify singly completed wells and multiple completions as follows: (1) For each singly completed well, list the lease number and well number on the wellhead or on a sign affixed to the wellhead; (2) For wells with multiple completions, downhole splitter wells, and multilateral wells, identify each completion in addition to the well name and lease number individually on the well flowline at the wellhead; and (3) For subsea wells that flow individually into separate pipelines, affix the required sign on the pipeline or surface flowline dedicated to that subsea well at a convenient location on the receiving platform. For multiple subsea wells that flow into a common pipeline or pipelines, no sign is required.

§§ 250.160-250.167 [Reserved]

§ 250.168 May operations or production be suspended? (a) You may request approval of a suspension, or the Regional Supervisor may direct a suspension (Directed Suspension), for all or any part of a lease or unit area. (b) Depending on the nature of the suspended activity, suspensions are labeled either Suspensions of Operations (SOO) or Suspensions of Production (SOP).

§ 250.169 What effect does suspension have on my lease? (a) A suspension may extend the term of a lease (see § 250.180(b), (d), and (e)). The extension is equal to the length of time the suspension is in effect, except as provided in paragraph (b) of this section. (b) A Directed Suspension does not extend the term of a lease when the Regional Supervisor directs a suspension because of: (1) Gross negligence; or (2) A willful violation of a provision of the lease or governing statutes and regulations.

§ 250.170 How long does a suspension last? (a) BSEE may issue suspensions for up to 5 years per suspension. The Regional Supervisor will set the length of the suspension based on the conditions of the individual case involved. BSEE may grant consecutive suspension periods. (b) An SOO ends automatically when the suspended operation commences. (c) An SOP ends automatically when production begins. (d) A Directed Suspension normally ends as specified in the letter directing the suspension. (e) BSEE may terminate any suspension when the Regional Supervisor determines the circumstances that justified the suspension no longer exist or that other lease conditions warrant termination. The Regional Supervisor will notify you of the reasons for termination and the effective date.

§ 250.171 How do I request a suspension? You must submit your request for a suspension to the Regional Supervisor, and BSEE must receive the request before the end of the lease term (i.e., end of primary term, end of the 1-year period following the last leaseholding operation, and end of a current suspension). Your request must include: (a) The justification for the suspension including the length of suspension requested; (b) A reasonable schedule of work leading to the commencement or restoration of the suspended activity; (c) A statement that a well has been drilled on the lease and determined to be producible according to 30 CFR 550.115 or 30 CFR 550.116; (d) A commitment to production (SOP only); and (e) The service fee listed in § 250.125 of this subpart.

§ 250.172 When may the Regional Supervisor grant or direct an SOO or SOP? The Regional Supervisor may grant or direct an SOO or SOP under any of the following circumstances: (a) When necessary to comply with judicial decrees prohibiting any activities or the permitting of those activities. The effective date of the suspension will be the effective date required by the action of the court; (b) When activities pose a threat of serious, irreparable, or immediate harm or damage. This would include a threat to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment. BSEE may require you to do a site-specific study (see § 250.177(a)). (c) When necessary for the installation of safety or environmental protection equipment; (d) When necessary to carry out the requirements of NEPA or to conduct an environmental analysis; or (e) When necessary to allow for inordinate delays encountered in obtaining required permits or consents, including administrative or judicial challenges or appeals.

§ 250.173 When may the Regional Supervisor direct an SOO or SOP? The Regional Supervisor may direct a suspension when: (a) You failed to comply with an applicable law, regulation, order, or provision of a lease or permit; or (b) The suspension is in the interest of National security or defense.

§ 250.174 When may the Regional Supervisor grant or direct an SOP? The Regional Supervisor may grant or direct an SOP when the suspension is in the National interest, and it is necessary because the suspension will meet one of the following criteria: (a) It will allow you to properly develop a lease, including time to construct and install production facilities; (b) It will allow you time to obtain adequate transportation facilities; (c) It will allow you time to enter a sales contract for oil, gas, or sulphur. You must show that you are making an effort to enter into the contract(s); or (d) It will avoid continued operations that would result in premature abandonment of a producing well(s).

§ 250.175 When may the Regional Supervisor grant an SOO? (a) The Regional Supervisor may grant an SOO when necessary to allow you time to begin drilling or other operations when you are prevented by reasons beyond your control, such as unexpected weather, unavoidable accidents, or drilling rig delays. (b) The Regional Supervisor may grant an SOO when all of the following conditions are met: (1) The lease was issued with a primary lease term of 5 years, or with a primary term of 8 years with a requirement to drill within 5 years; (2) Before the end of the third year of the primary term, you or your predecessor in interest must have acquired and interpreted geophysical information that indicates: (i) The presence of a salt sheet; (ii) That all or a portion of a potential hydrocarbon-bearing formation may lie beneath or adjacent to the salt sheet; and (iii) The salt sheet interferes with identification of the potential hydrocarbon-bearing formation. (3) The interpreted geophysical information required under paragraph (b)(2) of this section must include full 3-D depth migration beneath the salt sheet and over the entire lease area. (4) Before requesting the suspension, you have conducted or are conducting additional data processing or interpretation of the geophysical information with the objective of identifying a potential hydrocarbon-bearing formation. (5) You demonstrate that additional time is necessary to: (i) Complete current processing or interpretation of existing geophysical data or information; (ii) Acquire, process, or interpret new geophysical data or information; or (iii) Drill into the potential hydrocarbon-bearing formation identified as a result of the activities conducted in paragraphs (b)(2), (b)(4), and (b)(5) of this section. (c) The Regional Supervisor may grant an SOO to conduct additional geological and geophysical data analysis that may lead to the drilling of a well below 25,000 feet true vertical depth below the datum at mean sea level (TVD SS) when all of the following conditions are met: (1) The lease was issued with a primary lease term of: (i) Five years; or (ii) Eight years with a requirement to drill within 5 years. (2) Before the end of the fifth year of the primary term, you or your predecessor in interest must have acquired and interpreted geophysical information that: (i) Indicates that all or a portion of a potential hydrocarbon-bearing formation lies below 25,000 feet TVD SS; and (ii) Includes full 3-D depth migration over the entire lease area. (3) Before requesting the suspension, you have conducted or are conducting additional data processing or interpretation of the geophysical information with the objective of identifying a potential hydrocarbon-bearing geologic structure or stratigraphic trap lying below 25,000 feet TVD SS. (4) You demonstrate that additional time is necessary to: (i) Complete current processing or interpretation of existing geophysical data or information; (ii) Acquire, process, or interpret new geophysical or geological data or information that would affect the decision to drill the same geologic structure or stratigraphic trap, as determined by the Regional Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; or (iii) Drill a well below 25,000 feet TVD SS into the geologic structure or stratigraphic trap identified as a result of the activities conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and (ii) of this section.

§ 250.176 Does a suspension affect my royalty payment? A directed suspension may affect the payment of rental or royalties for the lease as provided in 30 CFR 1218.154.

§ 250.177 What additional requirements may the Regional Supervisor order for a suspension? If BSEE grants or directs a suspension under paragraph § 250.172(b), the Regional Supervisor may require you to: (a) Conduct a site-specific study. (1) The Regional Supervisor must approve or prescribe the scope for any site-specific study that you perform. (2) The study must evaluate the cause of the hazard, the potential damage, and the available mitigation measures. (3) You must pay for the study unless you request, and the Regional Supervisor agrees to arrange, payment by another party. (4) You must furnish copies and results of the study to the Regional Supervisor. (5) BSEE will make the results available to other interested parties and to the public. (6) The Regional Supervisor will use the results of the study and any other information that becomes available: (i) To decide if the suspension can be lifted; and (ii) To determine any actions that you must take to mitigate or avoid any damage to the environment, life, or property. (b) Submit a revised Exploration Plan (including any required mitigating measures); (c) Submit a revised Development and Production Plan (including any required mitigating measures); or (d) Submit a revised Development Operations Coordination Document according to 30 CFR part 550, subpart B.

§ 250.180 What am I required to do to keep my lease term in effect? (a) If your lease is in its primary term: (1) You must submit a report to the District Manager according to paragraphs (h) and (i) of this section whenever production begins initially, whenever production ceases during the last year of the primary term, and whenever production resumes during the last year of the primary term. (2) Your lease expires at the end of its primary term unless you are conducting operations on your lease (see 30 CFR part 556). For purposes of this section, the term operations means, drilling, well-reworking, or production in paying quantities. The objective of the drilling or well-reworking must be to establish production in paying quantities on the lease. (b) If you stop conducting operations during the last year of your primary lease term, your lease will expire unless you either resume operations or receive an SOO or an SOP from the Regional Supervisor under § 250.172, § 250.173, § 250.174, or § 250.175 before the end of the year after you stop operations. (c) If you extend your lease term under paragraph (b) of this section, you must pay rental or minimum royalty, as appropriate, for each year or part of the year during which your lease continues in force beyond the end of the primary lease term. (d) If you stop conducting operations on a lease that has continued beyond its primary term, your lease will expire unless you resume operations or receive an SOO or an SOP from the Regional Supervisor under § 250.172, § 250.173, § 250.174, or § 250.175 before the end of the year after you stop operations. (e) You may ask the Regional Supervisor to allow you more than a year to resume operations on a lease continued beyond its primary term when operating conditions warrant. The request must be in writing and explain the operating conditions that warrant a longer period. In allowing additional time, the Regional Supervisor must determine that the longer period is in the National interest, and it conserves resources, prevents waste, or protects correlative rights. (f) When you begin conducting operations on a lease that has continued beyond its primary term, you must immediately notify the District Manager either orally or by fax or e-mail and follow up with a written report according to paragraph (g) of this section. (g) If your lease is continued beyond its primary term, you must submit a report to the District Manager under paragraphs (h) and (i) of this section whenever production begins initially, whenever production ceases, whenever production resumes before the end of the 1-year period after having ceased, or whenever drilling or well-reworking operations begin before the end of the 1-year period. (h) The reports required by paragraphs (a) and (g) of this section must contain: (1) Name of lessee or operator; (2) The well number, lease number, area, and block; (3) As appropriate, the unit agreement name and number; and (4) A description of the operation and pertinent dates. (i) You must submit the reports required by paragraphs (a) and (g) of this section within the following timeframes: (1) Initialization of production—within 5 days of initial production. (2) Cessation of production—within 15 days after the first full month of zero production. (3) Resumption of production—within 5 days of resuming production after ceasing production under paragraph (i)(2) of this section. (4) Drilling or well reworking operations—within 5 days of beginning and completing the leaseholding operations. (j) For leases continued beyond the primary term, you must immediately report to the District Manager if operations do not begin before the end of the 1-year period.

§§ 250.181-250.185 [Reserved]

§ 250.186 What reporting information and report forms must I submit? (a) You must submit information and reports as BSEE requires. (1) You may obtain copies of forms from, and submit completed forms to, the District Manager or Regional Supervisor. (2) Instead of paper copies of forms available from the District Manager or Regional Supervisor, you may use your own computer-generated forms that are equal in size to BSEE's forms. You must arrange the data on your form identical to the BSEE form. If you generate your own form and it omits terms and conditions contained on the official BSEE form, we will consider it to contain the omitted terms and conditions. (3) You may submit digital data when the Region/District is equipped to accept it. (b) When BSEE specifies, you must include, for public information, an additional copy of such reports. (1) You must mark it Public Information (2) You must include all required information, except information exempt from public disclosure under § 250.197 or otherwise exempt from public disclosure under law or regulation.

§ 250.187 What are BSEE's incident reporting requirements? (a) You must report all incidents listed in § 250.188(a) and (b) to the District Manager. The specific reporting requirements for these incidents are contained in §§ 250.189 and 250.190. (b) These reporting requirements apply to incidents that occur on the area covered by your lease, right-of-use and easement, pipeline right-of-way, or other permit issued by BOEM or BSEE, and that are related to operations resulting from the exercise of your rights under your lease, right-of-use and easement, pipeline right-of-way, or permit. (c) Nothing in this subpart relieves you from making notifications and reports of incidents that may be required by other regulatory agencies. (d) You must report all spills of oil or other liquid pollutants in accordance with 30 CFR 254.46.

§ 250.188 What incidents must I report to BSEE and when must I report them? (a) You must report the following incidents to the District Manager immediately via oral communication, and provide a written follow-up report (hard copy or electronically transmitted) within 15 calendar days after the incident: (1) All fatalities. (2) All injuries that require the evacuation of the injured person(s) from the facility to shore or to another offshore facility. (3) All losses of well control. “Loss of well control” means: (i) Uncontrolled flow of formation or other fluids. The flow may be to an exposed formation (an underground blowout) or at the surface (a surface blowout); (ii) Flow through a diverter; or (iii) Uncontrolled flow resulting from a failure of surface equipment or procedures. (4) All fires and explosions. (5) All reportable releases of hydrogen sulfide (H2S) gas, as defined in § 250.490(l). (6) All collisions that result in property or equipment damage greater than $25,000. “Collision” means the act of a moving vessel (including an aircraft) striking another vessel, or striking a stationary vessel or object (e.g., a boat striking a drilling rig or platform). “Property or equipment damage” means the cost of labor and material to restore all affected items to their condition before the damage, including, but not limited to, the OCS facility, a vessel, helicopter, or equipment. It does not include the cost of salvage, cleaning, gas-freeing, dry docking, or demurrage. (7) All incidents involving structural damage to an OCS facility. “Structural damage” means damage severe enough so that operations on the facility cannot continue until repairs are made. (8) All incidents involving crane or personnel/material handling operations. (9) All incidents that damage or disable safety systems or equipment (including firefighting systems). (b) You must provide a written report of the following incidents to the District Manager within 15 calendar days after the incident: (1) Any injuries that result in one or more days away from work or one or more days on restricted work or job transfer. One or more days means the injured person was not able to return to work or to all of their normal duties the day after the injury occurred; (2) All gas releases that initiate equipment or process shutdown; (3) All incidents that require operations personnel on the facility to muster for evacuation for reasons not related to weather or drills; (4) All other incidents, not listed in paragraph (a) of this section, resulting in property or equipment damage greater than $25,000. (c) On the Arctic OCS, in addition to the requirements of paragraphs (a) and (b) of this section, you must provide to the BSEE inspector on location, if one is present, or to the Regional Supervisor, both of the following: (1) An immediate oral report if any of the following occur: (i) Any sea ice movement or condition that has the potential to affect your operation or trigger ice management activities; (ii) The start and termination of ice management activities; or (iii) Any “kicks” or operational issues that are unexpected and could result in the loss of well control. (2) Within 24 hours after completing ice management activities, a written report of such activities that conforms to the content requirements in § 250.190.

§ 250.189 Reporting requirements for incidents requiring immediate notification. For an incident requiring immediate notification under § 250.188(a), you must notify the District Manager via oral communication immediately after aiding the injured and stabilizing the situation. Your oral communication must provide the following information: (a) Date and time of occurrence; (b) Operator, and operator representative's, name and telephone number; (c) Contractor, and contractor representative's name and telephone number (if a contractor is involved in the incident or injury/fatality); (d) Lease number, OCS area, and block; (e) Platform/facility name and number, or pipeline segment number; (f) Type of incident or injury/fatality; (g) Operation or activity at time of incident (i.e., drilling, production, workover, completion, pipeline, crane, etc.); and (h) Description of the incident, damage, or injury/fatality.

§ 250.190 Reporting requirements for incidents requiring written notification. (a) For any incident covered under § 250.188, you must submit a written report within 15 calendar days after the incident to the District Manager. The report must contain the following information: (1) Date and time of occurrence; (2) Operator, and operator representative's name and telephone number; (3) Contractor, and contractor representative's name and telephone number (if a contractor is involved in the incident or injury); (4) Lease number, OCS area, and block; (5) Platform/facility name and number, or pipeline segment number; (6) Type of incident or injury; (7) Operation or activity at time of incident (i.e., drilling, production, workover, completion, pipeline, crane etc.); (8) Description of incident, damage, or injury (including days away from work, restricted work or job transfer), and any corrective action taken; and (9) Property or equipment damage estimate (in U.S. dollars). (b) You may submit a report or form prepared for another agency in lieu of the written report required by paragraph (a) of this section, provided the report or form contains all required information. (c) The District Manager may require you to submit additional information about an incident on a case-by-case basis.

§ 250.191 How does BSEE conduct incident investigations? Any investigation that BSEE conducts under the authority of sections 22(d)(1) and (2) of the Act (43 U.S.C. 1348(d)(1) and (2)) is a fact-finding proceeding with no adverse parties. The purpose of the investigation is to prepare a public report that determines the cause or causes of the incident. The investigation may involve panel meetings conducted by a chairperson appointed by BSEE. The following requirements apply to any panel meetings involving persons giving testimony: (a) A person giving testimony may have legal or other representative(s) present to provide advice or counsel while the person is giving testimony. The chairperson may require a verbatim transcript to be made of all oral testimony. The chairperson also may accept a sworn written statement in lieu of oral testimony. (b) Only panel members, and any experts the panel deems necessary, may address questions to any person giving testimony. (c) The chairperson may issue subpoenas to persons to appear and provide testimony or documents at a panel meeting. A subpoena may not require a person to attend a panel meeting held at a location more than 100 miles from where a subpoena is served. (d) Any person giving testimony may request compensation for mileage, and fees for services, within 90 days after the panel meeting. The compensated expenses must be similar to mileage and fees the U.S. District Courts allow.

§ 250.192 What reports and statistics must I submit relating to a hurricane, earthquake, or other natural occurrence? (a) You must submit evacuation statistics to the Regional Supervisor for a natural occurrence, such as a hurricane, a tropical storm, or an earthquake. Statistics include facilities and rigs evacuated and the amount of production shut-in for gas and oil. You must: (1) Submit the statistics by fax or email (for activities in the BSEE GOA-OCS Region, use Form BSEE-0132) as soon as possible when evacuation occurs. In lieu of submitting your statistics by fax or email, you may submit them electronically in accordance with 30 CFR 250.186(a)(3); (2) Submit the statistics on a daily basis by 11 a.m., as conditions allow, during the period of shut-in and evacuation; (3) Inform BSEE when you resume production; and (4) Submit the statistics either by BSEE district, or the total figures for your operations in a BSEE region. (b) If your facility, production equipment, or pipeline is damaged by a natural occurrence, you must: (1) Submit an initial damage report to the Regional Supervisor within 48 hours after you complete your initial evaluation of the damage. You must use Form BSEE-0143, Facility/Equipment Damage Report, to make this and all subsequent reports. In lieu of submitting Form BSEE-0143 by fax or e-mail, you may submit the damage report electronically in accordance with 30 CFR 250.186(a)(3). In the report, you must: (i) Name the items damaged (e.g., platform or other structure, production equipment, pipeline); (ii) Describe the damage and assess the extent of the damage (major, medium, minor); and (iii) Estimate the time it will take to replace or repair each damaged structure and piece of equipment and return it to service. The initial estimate need not be provided on the form until availability of hardware and repair capability has been established (not to exceed 30 days from your initial report). (2) Submit subsequent reports monthly and immediately whenever information submitted in previous reports changes until the damaged structure or equipment is returned to service. In the final report, you must provide the date the item was returned to service.

§ 250.193 Reports and investigations of possible violations. (a) Any person may report to BSEE any hazardous or unsafe working condition on any facility engaged in OCS activities, and any possible violation or failure to comply with: (1) Any provision of the Act, (2) Any provision of a lease, approved plan, or permit issued under the Act, (3) Any provision of any regulation or order issued under the Act, or (4) Any other Federal law relating to safety of offshore oil and gas operations. (b) To make a report under this section, a person is not required to know whether any legal requirement listed in paragraph (a) of this section has been violated. (c) When BSEE receives a report of a possible violation, or when a BSEE employee detects a possible violation, BSEE will investigate according to BSEE procedures and notify any other Federal agency(ies) for further investigation, as appropriate. (d) BSEE investigations of possible violations may include: (1) Conducting interviews of personnel; (2) Requiring the prompt production of documents, data, and other evidence; (3) Requiring the preservation of all relevant evidence and access for BSEE investigators to such evidence; and (4) Taking other actions and imposing other requirements as necessary to investigate possible violations and assure an orderly investigation. (e)(1) Reports should contain sufficient credible information to establish a reasonable basis for BSEE to investigate whether a violation or other hazardous or unsafe working condition exists. (2) To report hazardous or unsafe working conditions or a possible violation: (i) Contact BSEE by: (A) Phone at 1-877-440-0173 (BSEE Toll-free Safety Hotline), (B) Internet at www.bsee.gov, or (C) Mail to: U.S. DOI/BSEE, 1849 C Street NW., Mail Stop 5438, Washington, DC 20240 Attention: IRU Hotline Operations. (ii) Include the following items in the report: (A) Name, address, and telephone number should be provided if you do not want to remain anonymous; (B) The specific concern, provision or Federal law, if known, referenced in (a) that a person violated or with which a person failed to comply; and (C) Any other facts, data, and applicable information. (f) When a possible violation is reported, BSEE will protect a person's identity to the extent authorized by law.

§ 250.194 How must I protect archaeological resources? (a)-(b) [Reserved] (c) If you discover any archaeological resource while conducting operations in the lease or right-of-way area, you must immediately halt operations within the area of the discovery and report the discovery to the BSEE Regional Director. If investigations determine that the resource is significant, the Regional Director will tell you how to protect it.

§ 250.195 What notification does BSEE require on the production status of wells? You must notify the appropriate BSEE District Manager when you successfully complete or recomplete a well for production. You must: (a) Notify the District Manager within 5 working days of placing the well in a production status. You must confirm oral notification by telefax or e-mail within those 5 working days. (b) Provide the following information in your notification: (1) Lessee or operator name; (2) Well number, lease number, and OCS area and block designations; (3) Date you placed the well on production (indicate whether or not this is first production on the lease); (4) Type of production; and (5) Measured depth of the production interval.

§ 250.196 Reimbursements for reproduction and processing costs. (a) BSEE will reimburse you for costs of reproducing data and information that the Regional Director requests if: (1) You deliver geophysical and geological (G&G) data and information to BSEE for the Regional Director to inspect or select and retain; (2) BSEE receives your request for reimbursement and the Regional Director determines that the requested reimbursement is proper; and (3) The cost is at your lowest rate or at the lowest commercial rate established in the area, whichever is less. (b) BSEE will reimburse you for the costs of processing geophysical information (that does not include cost of data acquisition): (1) If, at the request of the Regional Director, you processed the geophysical data or information in a form or manner other than that used in the normal conduct of business; or (2) If you collected the information under a permit that BSEE issued to you before October 1, 1985, and the Regional Director requests and retains the information. (c) When you request reimbursement, you must identify reproduction and processing costs separately from acquisition costs. (d) BSEE will not reimburse you for data acquisition costs or for the costs of analyzing or processing geological information or interpreting geological or geophysical information.

§ 250.197 Data and information to be made available to the public or for limited inspection. BSEE will protect data and information that you submit under this part, and 30 CFR part 203, as described in this section. Paragraphs (a) and (b) of this section describe what data and information will be made available to the public without the consent of the lessee, under what circumstances, and in what time period. Paragraph (c) of this section describes what data and information will be made available for limited inspection without the consent of the lessee, and under what circumstances. (a) All data and information you submit on BSEE forms will be made available to the public upon submission, except as specified in the following table: (b) BSEE will release lease and permit data and information that you submit and BSEE retains, but that are not normally submitted on BSEE forms, according to the following table: (c) BSEE may allow limited inspection, but only by persons with a direct interest in related BSEE decisions and issues in specific geographic areas, and who agree in writing to its confidentiality, of G&G data and information submitted under this part or 30 CFR part 203 that BSEE uses to: (1) Make unitization determinations on two or more leases; (2) Make competitive reservoir determinations; (3) Ensure proper plans of development for competitive reservoirs; (4) Promote operational safety; (5) Protect the environment; (6) [Reserved]; or (7) Determine eligibility for royalty relief.

§ 250.198 Documents incorporated by reference. Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. All approved incorporation by reference (IBR) material is available for inspection at BSEE and at the National Archives and Records Administration (NARA). Contact BSEE at: the Houston BSEE office at 1919 Smith Street Suite 14042, Houston, Texas 77002; 1-844-259-4779; or at regs@bsee.gov. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email: fr.inspection@nara.gov. The material may be obtained from the following sources: (a) American Concrete Institute (ACI), ACI Standards, 38800 Country Club Drive, Farmington Hills, MI 48331-3439: phone: 248-848-3700; website: www.concrete.org: (1) ACI Standard 318-95, Building Code Requirements for Reinforced Concrete, 1995; into § 250.901. (2) ACI 318R-95, Commentary on Building Code Requirements for Reinforced Concrete, 1995; into § 250.901. (3) ACI 357R-84, Guide for the Design and Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997, into § 250.901. (b) American Gas Association (AGA Reports), 400 North Capitol Street NW, Suite 450, Washington, DC 20001; phone: 202-824-7000; website: www.aga.org. (1) AGA Report No. 7, Measurement of Natural Gas by Turbine Meters, Revised February 2006; into § 250.1203(b). (2) AGA Report No. 8, Part 1, Thermodynamic Properties of Natural Gas and Related Gases Detail and Gross Equations of State, Third Edition, April 2017; into § 250.1203(b). (3) AGA Report No. 8, Part 2, Thermodynamic Properties of Natural Gas and Related Gases, GERG-2008 Equation of State, First Edition, April 2017; into § 250.1203(b). (4) AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters; Fourth Edition, 2022; into § 250.1203(b). (5) AGA Report No. 10, Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases, Copyright 2003; into § 250.1203(b). (6) AGA Report No. 11, Measurement of Natural Gas by Coriolis Meter, Second Edition, February 2013; into § 250.1203(b). (c) American Institute of Steel Construction, Inc. (AISC), AISC Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802; phone: 312-670-2400; website: www.aisc.org. (1) ANSI/AISC 360-05, Specification for Structural Steel Buildings; into § 250.901. (2) [Reserved] (d) American National Standards Institute (ANSI), 25 West 43rd Street, Fourth Floor, New York, NY 10036-7417; phone: 212-642-4980; email: info@ansi.org; website: www./webstore.ansi.org/: (1) ANSI/ASME B16.5-2003, Pipe Flanges and Flanged Fittings; into § 250.1002. (2) ANSI/ASME B31.8-2003, Gas Transmission and Distribution Piping Systems; into § 250.1002. (3) ANSI Z88.2-1992, American National Standard for Respiratory Protection; into § 250.490. (e) American Petroleum Institute (API), 200 Massachusetts Avenue NW, Suite 1100, Washington, DC 20001-5571; phone: 202-682-8000; website: www.api.org. (1) Manual of Petroleum Measurement Standards (MPMS)—(i) Chapter 1. (A) API MPMS Chapter 1, Vocabulary, Second Edition, July 1994; into § 250.1201. (B) [Reserved] (ii) Chapter 2. (A) API MPMS Chapter 2—Tank Calibration, Section 2A—Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method, First Edition February 1995, reaffirmed August 2017; into § 250.1202(a) and (l). (B) API MPMS Chapter 2—Tank Calibration, Section 2B—Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method, First Edition, March 1989, reaffirmed April 2019 (including Addendum 1, October 2019); into § 250.1202(a) and (l). (iii) Chapter 3. (A) API MPMS Chapter 3.1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Third Edition, August 2013, Errata 1, January 2021; into § 250.1202(a) and (l). (B) API MPMS Chapter 3—Tank Gauging, Section 1B—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition, June 2001, reaffirmed February 2016; into § 250.1202(a) and (l). (iv) Chapter 4. (A) API MPMS Chapter 4—Proving Systems, Section 1—Introduction, Third Edition, February 2005, reaffirmed June 2014; into § 250.1202(a). (B) API MPMS Chapter 4—Proving Systems, Section 2—Displacement Provers, Third Edition, September 2003; Addendum February 2015, Reaffirmed December 2022; into § 250.1202(a). (C) API MPMS Chapter 4—Proving Systems, Section 4—Tank Provers, Second Edition May 1998, reaffirmed May 2015; into § 250.1202(a) and (f). (D) API MPMS Chapter 4.5, Master Meter Provers, Fourth Edition, June 2016; into § 250.1202(a). (E) API MPMS Chapter 4—Proving Systems, Section 6—Pulse Interpolation, Second Edition, May 1999; Errata April 2007; reaffirmed October 2013; into § 250.1202(a) and (h). (F) API MPMS Chapter 4—Proving Systems, Section 7—Field Standard Test Measures, Third Edition, April 2009, reaffirmed June 2014; into § 250.1202(a). (G) API MPMS Chapter 4.8, Operation of Proving Systems, Third Edition, July 2021; into § 250.1202(a), (f), and (g). (H) API MPMS Chapter 4—Proving Systems, Section 9—Methods of Calibration for Displacement and Volumetric Tank Provers, Part 2—Determination of the Volume of Displacement and Tank Provers by the Water-draw Method of Calibration, First Edition, December 2005, reaffirmed July 2015; into § 250.1202(a). (v) Chapter 5. (A) API MPMS Chapter 5—Metering, Section 1—General Considerations for Measurement by Meters, Fourth Edition, September 2005, Errata 1 June 2008, Errata 2 June 2011, reaffirmed December 2022; into § 250.1202(a). (B) API MPMS Chapter 5—Metering, Section 2—Measurement of Liquid Hydrocarbons by Displacement Meters, Third Edition, September 2005, reaffirmed July 2015; into § 250.1202(a). (C) API MPMS Chapter 5—Metering, Section 3—Measurement of Liquid Hydrocarbons by Turbine Meters, Fifth Edition, September 2005, reaffirmed August 2014; into § 250.1202(a). (D) API MPMS Chapter 5—Metering, Section 4—Accessory Equipment for Liquid Meters, Fourth Edition, September 2005, Errata May 2015, reaffirmed August 2015; into § 250.1202(a). (E) API MPMS Chapter 5—Metering, Section 5—Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, August 2005, reaffirmed August 2015; into § 250.1202(a). (F) API MPMS Chapter 5—Metering, Section 6—Measurement of Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002, reaffirmed November 2013; into § 250.1202(a). (G) API MPMS Chapter 5.8, Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters, Second Edition, November 2011, Errata February 2014, reaffirmed May 2017; into § 250.1202(a). (vi) Chapter 6. (A) API MPMS Chapter 6.1, Lease Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; Addendum 1 August 2020; into § 250.1202(a). (B) API MPMS Chapter 6—Metering Assemblies, Section 6—Pipeline Metering Systems, Second Edition, May 1991, reaffirmed December 2017; into § 250.1202(a). (C) API MPMS Chapter 6—Metering Assemblies, Section 7—Metering Viscous Hydrocarbons, Second Edition, May 1991, reaffirmed March 2018; into § 250.1202(a). (vii) Chapter 7. (A) API MPMS Chapter 7.1, Temperature Determination-Liquid-in-Glass Thermometers, Second Edition, August 2017; into § 250.1202(a). (B) API MPMS Chapter 7.3, Temperature Determination—Temperature Determination—Fixed Automatic Tank Temperature Systems, Second Edition, October 2011; reaffirmed September 2021 into § 250.1202(a). (viii) Chapter 8. (A) API MPMS Chapter 8.1, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, Sixth Edition, September 2022; into § 250.1202(a) and (k). (B) API MPMS Chapter 8.2, Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products, Sixth Edition, September 2022; into § 250.1202(a), (b), and (k). (C) API MPMS Chapter 8.3, Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products, Second Edition, September 2019; into § 250.1202(a). (ix) Chapter 9. (A) API MPMS Chapter 9.1, Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, Third Edition, December 2012, reaffirmed May 2017; into § 250.1202(a). (B) API MPMS Chapter 9.2, Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer, Fourth Edition, November 2022; into § 250.1202(a). (C) API MPMS Chapter 9.4, Continuous Density Measurement Under Dynamic (Flowing) Conditions, First Edition, January 2018; into § 250.1202(a). (x) Chapter 10. (A) API MPMS Chapter 10—Sediment and Water, Section 1—Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method, Third Edition, November 2007; reaffirmed October 2012; into § 250.1202(a); (B) API MPMS Chapter 10.2, Standard Test Method for Water in Crude Oil by Distillation, Fifth Edition, December 2022; into § 250.1202(a). (C) API MPMS Chapter 10.3, Standard Test Method for Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure), Fifth Edition, December 2022; into § 250.1202(a). (D) API MPMS Chapter 10.4, Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure), Fifth Edition, August 2020; into § 250.1202(a). (E) API MPMS Chapter 10.9, Standard Test Method for Water in Crude Oils by Coulometric Karl Fisher Titration, Third Edition, May 2013, reaffirmed June 2018; into § 250.1202(a). (xi) Chapter 11. (A) API MPMS Chapter 11.1—Volume Correction Factors, Volume 1, Table 5A—Generalized Crude Oils and JP-4 Correction of Observed API Gravity to API Gravity at 60 °F, and Table 6A—Generalized Crude Oils and JP-4 Correction of Volume to 60 °F Against API Gravity at 60 °F, API Standard 2540, First Edition, August 1980; reaffirmed March 1997; into § 250.1202(a). (B) API MPMS Chapter 11—Physical Properties Data, Section 1—Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products, and Lubricating Oils, May 2004, Addendum 1 September 2007, Addendum 2 May 2019; into § 250.1202(a), (g), and (l). (C) API MPMS Chapter 11.2.2—Compressibility Factors for Hydrocarbons: 0.350-0.637 Relative Density (60 °F/60 °F) and −50 °F to 140 °F Metering Temperature, Second Edition, October 1986; reaffirmed: December 2007; into § 250.1202(a). (D) API MPMS Chapter 11—Physical Properties Data, Addendum to Section 2, Part 2—Compressibility Factors for Hydrocarbons, Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First Edition, December 1994; reaffirmed December 2002; into § 250.1202(a). (xii) Chapter 12. (A) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1—Introduction, Second Edition, May 1995; reaffirmed March 2014; into § 250.1202(a). (B) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2—Measurement Tickets, Third Edition, June 2003; reaffirmed February 2016; into § 250.1202(a). (C) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3—Proving Report; First Edition, October 1998, reaffirmed March 2014; into § 250.1202(a) and (g). (D) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4—Calculation of Base Prover Volumes by the Waterdraw Method, First Edition, December 1997; reaffirmed September 2014; into § 250.1202(a), (f), and (g). (E) API MPMS Chapter 12.2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Second Edition, July 2021; into § 250.1202(a). (xiii) Chapter 14. (A) API MPMS Chapter 14.1, Collecting and Handling of Natural Gas Samples for Analysis by Gas Chromatography, Eighth Edition, September 2022; into § 250.1203(b). (B) API MPMS Chapter 14.3.1—Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1: General Equations and Uncertainty Guidelines, Fourth Edition September 2012, Errata July 2013, Reaffirmed September 2017; into § 250.1203(b). (C) API MPMS Chapter 14.3.2, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 2: Specification and Installation Requirements, Fifth Edition, March 2016, Errata 1 March 2017, Errata 2 January 2019; into § 250.1203(b). (D) API MPMS 14.3.3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 3: Natural Gas Applications, Fourth Edition November 2013, Reaffirmed June 2021; into § 250.1203(b). (E) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer; Third Edition, January 2009; reaffirmed February 2014; into § 250.1203(b). (F) API MPMS Chapter 14—Natural Gas Fluids Measurement, Section 8—Liquefied Petroleum Gas Measurement, Second Edition, July 1997; reaffirmed, March 2006; into § 250.1203(b). (xiv) Chapter 20. (A) API MPMS Chapter 20—Allocation Measurement, Section 1—Allocation Measurement, First Edition, September 1993, Addendum 1 January 2013, Addendum 2 November 2016, Addendum 3 December 2017, Reaffirmed June 2024; into §§ 250.1202(a); 250.1203(b). (B) API MPMS Chapter 20.3, Measurement of Multiphase Flow, First Edition, January 2013; reaffirmed, October 2018; into § 250.1203(b). (C) API MPMS Chapter 20.5, Recommended Practice for Application of Production Well Testing in Measurement and Allocation, First Edition, December 2017; Errata 1, August 2023; into § 250.1204(b). (xv) Chapter 21. (A) API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 1—Electronic Gas Measurement, First Edition, August 1993; reaffirmed, July 2005; into § 250.1203(b). (B) API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 2—Electronic Liquid Volume Measurement Using Positive Displacement and Turbine Meters; First Edition, June 1998; reaffirmed October 2016; into § 250.1202(a). (C) API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Addendum to Section 2—Flow Measurement Using Electronic Metering Systems, Inferred Mass; First Edition, reaffirmed February 2006; into § 250.1202(a). (2) Recommended Practices, Specifications, and Standards—(i) 1-99. (A) API Recommended Practice 2A-WSD, Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design, Twenty-second Edition, November 2014, reaffirmed September 2020; into §§ 250.901(a) and (d); 250.908(a); 250.920(f). (B) API Specification 2C, Specification for Offshore Pedestal Mounted Cranes, Sixth Edition, March 2004; into § 250.108. (C) API Recommended Practice 2D, Operation and Maintenance of Offshore Cranes, Sixth Edition, May 2007; into § 250.108. (D) API Recommended Practice 2FPS, Planning, Designing, and Constructing Floating Production Systems, Second Edition, October 2011, Reaffirmed September 2020; into § 250.901(a) and (d). (E) API Recommended Practice 2FSIM, Floating Systems Integrity Management, First Edition, September 2019; into § 250.901(a) and (d). (F) ANSI/API Recommended Practice 2GEO, Geotechnical and Foundation Design Considerations, First Edition April 2011, Addendum 1 October 2014, Reaffirmed January 2021; into § 250.901(a) and (d). (G) API Recommended Practice 2I, In-Service Inspection of Mooring Hardware for Floating Structures; Third Edition, April 2008; into § 250.901(a) and (d). (H) ANSI/API Recommended Practice 2MET, Derivation of Metocean Design and Operating Conditions; Second Edition, January 2021; into § 250.901(a) and (d). (I) API Recommended Practice 2MIM, Mooring Integrity Management; First Edition, September 2019; into § 250.901(a) and (d). (J) ANSI/API Recommended Practice 2N, Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions, Third Edition, April 2015; into § 250.470(g). (K) API Recommended Practice 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998; reaffirmed, May 2006; Errata, June 2009; into §§ 250.733; 250.800(c); 250.901(a) and (d); 250.1002(b). (L) API Recommended Practice 2RIM, Integrity Management of Risers from Floating Production Systems; First Edition, September 2019; into § 250.901(a) and (d). (M) API Recommended Practice 2SIM, Structural Integrity Management of Fixed Offshore Structures, First Edition November 2014; reaffirmed September 2020; into §§ 250.901(a) and (d); 250.919(b) and (d); 250.920. (N) API Recommended Practice 2SK, Design and Analysis of Stationkeeping Systems for Floating Structures, Third Edition October 2005, Addendum May 2008, reaffirmed June 2015; into §§ 250.800(c); 250.901(a) and (d). (O) API Recommended Practice 2SM, Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, Second Edition, July 2014; Reaffirmation, September 2020; into §§ 250.800(c); 250.901(a) and (d). (P) API Recommended Practice 2T, Planning, Designing, and Constructing Tension Leg Platforms, Third Edition, July 2010, reaffirmed June 2015; into § 250.901(a) and (d). (Q) API Specification 6A, Specification for Wellhead and Christmas Tree Equipment, Twenty-First Edition November 2018, Errata 1 April 2019, Errata 2 June 2020, Errata 3 September 2020, Errata 4 September 2021, Addendum 1, July 2020, Addendum 2, June 2021, Addendum 3, August 2022; into §§ 250.518(c); 250.619(c); 250.730(a); 250.802(a); 250.803(a); 250.833; 250.873(b); 250.874(g); 250.1002(b). (R) API Standard 6AV1, Validation of Safety and Shutdown Valves for Sandy Service, Third Edition, July 2018; into §§ 250.802(a) and (c); 250.833; 250.873(b); 250.874(g). (S) API Standard 6AV2, Installation, Maintenance, and Repair of Surface Safety Valves and Underwater Safety Valves Offshore; First Edition March 2014; Errata 1 August 2014; into §§ 250.820; 250.834; 250.836; 250.880(c). (T) API Specification 6D, Specification for Valves, Twenty-fifth Edition November 2021, Errata 1 December 2021, Errata 2 April 2022, Addendum 1 April 2023; into § 250.1002(b). (U) ANSI/API Specification 11D1, Packers and Bridge Plugs, Third Edition, April 2015; Errata 1, August 2019; into §§ 250.518(e); 250.619(e); 250.1703. (V) ANSI/API Specification 14A, Specification for Subsurface Safety Valve Equipment, Eleventh Edition, October 2005, reaffirmed June 2012; into §§ 250.802; 250.803(a). (W) ANSI/API Recommended Practice 14B, Design, Installation, Operation, Test, and Redress of Subsurface Safety Valve Systems, Sixth Edition, September 2015; into §§ 250.802(b); 250.803(a); 250.814(d); 250.828(c); 250.880(c). (X) API Recommended Practice 14C, Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Seventh Edition, March 2001, reaffirmed: March 2007; into §§ 250.125(a); 250.841(a); 250.842(a); 250.850; 250.852(a); 250.855, 250.856(a); 250.858(a); 250.862(e); 250.865(a); 250.867(a); 250.869(a) through (c); 250.872(a); 250.873(a); 250.874(a); 250.880(b) and (c); 250.1002(d); 250.1004(b). (Y) API Recommended Practice 14E, Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1991; reaffirmed, January 2013; into §§ 250.841(b); 250.842(a). (Z) API Recommended Practice 14F, Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations, Upstream Segment, Fifth Edition, July 2008, reaffirmed: April 2013; into §§ 250.114(c); 250.842(c); 250.862(e). (AA) API Recommended Practice 14FZ, Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 Locations, Second Edition, May 2013; into §§ 250.114(c); 250.842(c); 250.862(e). (BB) API Recommended Practice 14G, Fire Prevention and Control on Fixed Open-type Offshore Production Platforms, Fourth Edition, April 2007; Reaffirmed, January 2013; into §§ 250.859(a); 250.862(e); 250.880(c). (CC) API Recommended Practice 14J, Design and Hazards Analysis for Offshore Production Facilities, Second Edition, May 2001; reaffirmed: January 2013; into §§ 250.800(b) and (c); 250.842(c); 250.901(a) and (d). (DD) ANSI/API Specification 16A, Specification for Drill-through Equipment, Third Edition June 2004, reaffirmed August 2010; into § 250.730. (EE) ANSI/API Specification 16C, Specification for Choke and Kill Systems, First Edition, January 1993, reaffirmed July 2010; into § 250.730. (FF) API Specification 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment, Second Edition, July 2004, reaffirmed August 2013; into § 250.730. (GG) API Specification 17D, Specification for Subsea Wellhead and Tree Equipment, Third Edition, October 2021, Errata 1, December 2021, Addendum 1, December 2022; into §§ 250.518(c); 250.619(c); 250.730(a). (HH) API Recommended Practice 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems, Second Edition, June 2013; Errata, January 2014; into § 250.734(a). (II) API Specification 17J, Specification for Unbonded Flexible Pipe, Fourth Edition, May 2014, Errata 1 September 2016, Errata 2 May 2017, Addendum 1 October 2017, reaffirmed March 2021; into §§ 250.852(e); 250.1002(b); 250.1007(a). (JJ) API Specification 20E, Alloy and Carbon Steel Bolting for Use in the Petroleum and Natural Gas Industries, Second Edition, February 2017, Addendum 1 September 2018, Addendum 2 March 2019, Errata 1 November 2021, Errata 2 May 2022; into § 250.730(a). (KK) API Specification 20F, Corrosion-resistant Bolting for Use in the Petroleum and Natural Gas Industries; Second Edition, May 2018, Errata 1 October 2020, Addendum 1 November 2021; into § 250.730(a). (LL) API Standard 53, Well Control Equipment Systems for Drilling Wells, Fifth Edition, December 2018; into §§ 250.730(a); 250.734(a); 250.735(a); 250.736(d); 250.737(d); 250.739(a). (MM) API Recommended Practice 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deepwater Wells, First Edition, September 2002; into § 250.415. (NN) API Standard 65—Part 2, Isolating Potential Flow Zones During Well Construction; Second Edition, December 2010; into §§ 250.415(f); 250.420(a). (OO) API Recommended Practice 75, Recommended Practice for Development of a Safety and Environmental Management Program for Offshore Operations and Facilities, Third Edition, May 2004, reaffirmed May 2008; into §§ 250.1900; 250.1902; 250.1903; 250.1909; 250.1920. (PP) API Recommended Practice 90, Annular Casing Pressure Management for Offshore Wells, First Edition, August 2006; into § 250.519. (ii) 500-599. (A) API Recommended Practice 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, Third Edition, December 2012; Errata January 2014, into §§ 250.114(a); 250.459; 250.842(a); 250.862(a) and (e); 250.872(a). (B) API Recommended Practice 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, August 2013; into §§ 250.114(a); 250.459; 250.842(a); 250.862(a) and (e); 250.872(a). (C) API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Tenth Edition, May 2014, Addendum 1, May 2017; into § 250.851(a). (D) API 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, Fourth Edition, February 2016, Addendum 1, May 2017; into § 250.841(b). (iii) 2500-2599. (A) API Standard 2555, Method for Liquid Calibration of Tanks, First Edition, September 1966, reaffirmed May 2014; into § 250.1202(a). (B) API Recommended Practice 2556, Recommended Practice for Correcting Gauge Tables for Incrustation, Second Edition, August 1993, reaffirmed November 2013; into § 250.1202(a). (iv) A-Q. (A) ANSI/API Specification Q1, Specification for Quality Management System Requirements for Manufacturing Organizations for the Petroleum and Natural Gas Industry, Ninth Edition, June 2013; Errata, February 2014; Errata 2, March 2014; Addendum 1, June 2016; into §§ 250.730; 250.801(b) and (c); (B) [Reserved] (v) Bulletins. (A) API Bulletin 92L, Drilling Ahead Safely with Lost Circulation in the Gulf of Mexico, First Edition, August 2015; into § 250.427(b). (B) [Reserved] (f) American Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, NJ 07007-2900; phone: 1-800-843-2763; website: www.asme.org: (1) 2017 ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers, 2017 Edition, July 1, 2017; into § 250.851(a). (2) 2017 ASME Boiler and Pressure Vessel Code, Section IV, Rules for Construction of Heating Boilers, 2017 Edition, July 1, 2017; into § 250.851(a). (3) ASME Boiler and Pressure Vessel Code (BPVC), Section VIII, Rules for Construction of Pressure Vessels; into § 250.851(a)—as follows: (i) ASME BPVC.VIII.1-2021, Division 1, 2021 Edition, July 1, 2021. (ii) 2017 ASME BPVC, Division 2: Alternative Rules, 2017 Edition, July 1, 2017. (iii) 2017 ASME BPVC, Division 3: Alternative Rules for Construction of High Pressure Vessels, 2017 Edition, July 1, 2017. (g) ASTM, International (ASTM), 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428-2959; phone: 1-877-909-2786; website: www.astm.org: (1) ASTM C33-07, approved December 15, 2007, Standard Specification for Concrete Aggregates; into § 250.901. (2) ASTM C94/C 94M-07, approved January 1, 2007, Standard Specification for Ready-Mixed Concrete; into § 250.901. (3) ASTM C150-07, approved May 1, 2007, Standard Specification for Portland Cement; into § 250.901. (4) ASTM C330-05, approved December 15, 2005, Standard Specification for Lightweight Aggregates for Structural Concrete; into § 250.901. (5) ASTM C595-08, approved January 1, 2008, Standard Specification for Blended Hydraulic Cements; into § 250.901. (h) American Welding Society (AWS), AWS Codes, 8669 NW 36 Street, #130, Miami, FL 33126; phone: 800-443-9353; website: www.aws.org: (1) AWS D1.1:2000, Structural Welding Code—Steel, 17th Edition, October 18, 1999; into § 250.901. (2) AWS D1.4-98, Structural Welding Code—Reinforcing Steel, 1998 Edition; into § 250.901. (3) AWS D3.6M:1999, Specification for Underwater Welding (1999); into § 250.901. (i) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite 1370, Houston, TX 77056; phone: 832-495-4925; website: www.centerforoffshoresafety.org: (1) COS Safety Publication COS-2-01, Qualification and Competence Requirements for Audit Teams and Auditors Performing Third-party SEMS Audits of Deepwater Operations, First Edition, Effective Date October 2012; into §§ 250.1900; 250.1903; 250.1904; 250.1921. (2) COS Safety Publication COS-2-03, Requirements for Third-party SEMS Auditing and Certification of Deepwater Operations, First Edition, Effective Date October 2012; into §§ 250.1900; 250.1903; 250.1904; 250.1920. (3) COS Safety Publication COS-2-04, Requirements for Accreditation of Audit Service Providers Performing SEMS Audits and Certification of Deepwater Operations, First Edition, Effective Date October 2012; into §§ 250.1900; 250.1903; 250.1904; 250.1922. (j) GPA Midstream Association, 6060 S American Plaza St E, Suite 700, Tulsa, Oklahoma 74135; phone: (918) 493-3872. fax: (918) 493-3875; email: news@GPAmidstream.org: (1) GPA Midstream Standard 2198-16 (GPA Standard 2198-16), Selection, Preparation, Validation, Care and Storage of Natural Gas and Natural Gas Liquids Reference Standard Blends, Revised August 2016; into § 250.1203(b). (2) GPA Midstream Standard 2261-20 (GPA Standard 2261-20), Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, Copyright 2019; into § 250.1203(b). (3) GPA Standard 2286-14, Method for the Extended Analysis of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas Chromatography, Revised 2014; into § 250.1203(b). (k) International Organization for Standardization (ISO), 1, ch. de la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; phone: 41-22-749-01-11; website: www.iso.org: (1) ISO/IEC 17011:2017(E), Conformity assessment—Requirements for accreditation bodies accrediting conformity assessment bodies, Second Edition 2017-11 (ISO/IEC 17011); into §§ 250.1900(a); 250.1903; 250.1904(d); 250.1922. (2) ISO/IEC 17021-1, Conformity assessment—Requirements for bodies providing audit and certification of management systems—Part 1: Requirements, First Edition, June 2015; into § 250.730(d). (l) National Association of Corrosion Engineers (NACE) International, NACE Standards, Park Ten Place, Houston, TX 77084; phone: 281-228-6200; website: www.nace.org: (1) NACE Standard MR0175-2003, Standard Material Requirements, Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments, Revised January 17, 2003; into §§ 250.490; 250.518(a); 250.619(a); 250.901. (2) NACE Standard RP0176-2003, Standard Recommended Practice, Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production; into § 250.901.

§ 250.199 Paperwork Reduction Act statements—information collection. (a) OMB has approved the information collection requirements in part 250 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of this section lists the subpart in the rule requiring the information and its title, provides the OMB control number, and summarizes the reasons for collecting the information and how BSEE uses the information. The associated BSEE forms required by this part are listed at the end of this table with the relevant information. (b) Respondents are OCS oil, gas, and sulphur lessees and operators. The requirement to respond to the information collections in this part is mandated under the Act (43 U.S.C. 1331 et seq.) and the Act's Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are also required to obtain or retain a benefit or may be voluntary. Proprietary information will be protected under § 250.197, Data and information to be made available to the public or for limited inspection; parts 30 CFR Parts 251, 252; and the Freedom of Information Act (5 U.S.C. 552) and its implementing regulations at 43 CFR part 2. (c) The Paperwork Reduction Act of 1995 requires us to inform the public that an agency may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number. (d) Send comments regarding any aspect of the collections of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Bureau of Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 20166. (e) BSEE is collecting this information for the reasons given in the following table:

§ 250.200 Definitions. 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.

§ 250.201 What plans and information must I submit before I conduct any activities on my lease or unit? (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.

§ 250.202 How must I protect the rights of the Federal government? (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.

§ 250.203 Are there special requirements if my well affects an adjacent property? 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.

§ 250.204 Requirements for high pressure high temperature (HPHT) barrier equipment. 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).

§ 250.205 [Reserved]

§ 250.206 What equipment does BSEE consider to be a barrier? 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.

§ 250.207 How must barrier systems be used? 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.

§ 250.208 How must I conduct activities under an approved EP, DPP, or DOCD? (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.

§ 250.209 What must I do to conduct activities under the 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.

§ 250.210 Do I have to conduct post-approval monitoring? 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.

§ 250.211 What are my new or unusual technology failure reporting requirements? 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).

§§ 250.212-250.219 [Reserved]

§ 250.220 What is the DWOP process? (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.

§ 250.221 When must I use the DWOP process? (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.

§§ 250.222-250.224 [Reserved]

§ 250.225 What are the types of Conceptual Plans that I must submit? 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.

§ 250.226 When and how must I submit each applicable Conceptual Plan? 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:

§ 250.227 What must the Project Conceptual Plan contain? 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.

§ 250.228 What must the New or Unusual Technology Conceptual Plan contain? (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.

§ 250.229 What must the New or Unusual Technology Barrier Equipment Conceptual Plan include? 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.

§ 250.230 When are you required to submit an I3P Report? 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.

§ 250.231 What are your requirements for the Independent Third Party (I3P) nomination? 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.

§ 250.232 What are the I3P review requirements for Conceptual Plan reviews? 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.

§ 250.233 General requirements for any I3P Report. 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.

§ 250.234 [Reserved]

§ 250.235 When and how must I submit the DWOP? (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.

§ 250.236 What information must I submit with the DWOP? Your DWOP must contain the following information, as applicable:

§ 250.237 What general information must my DWOP include? 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.

§ 250.238 What well or completions information must my DWOP include? 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.

§ 250.239 What structural information must my DWOP include? 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.

§ 250.240 What production safety system information must my DWOP include? 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.

§ 250.241 What subsea systems and pipeline information must my DWOP include? (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.

§ 250.242 What New or Unusual Technology information must my DWOP include? 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.

§§ 250.243-250.244 [Reserved]

§ 250.245 May I combine the Project Conceptual Plan and the DWOP? 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.

§ 250.246 When must I revise my DWOP? 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.

§ 250.247 When must I supplement my DWOP? 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.

§ 250.248 What information must I include in my 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.

§ 250.300 Pollution prevention. (a) During the exploration, development, production, and transportation of oil and gas or sulphur, the lessee shall take measures to prevent unauthorized discharge of pollutants into the offshore waters. The lessee shall not create conditions that will pose unreasonable risk to public health, life, property, aquatic life, wildlife, recreation, navigation, commercial fishing, or other uses of the ocean. (1) When pollution occurs as a result of operations conducted by or on behalf of the lessee and the pollution damages or threatens to damage life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), or the marine, coastal, or human environment, the control and removal of the pollution to the satisfaction of the District Manager shall be at the expense of the lessee. Immediate corrective action shall be taken in all cases where pollution has occurred. Corrective action shall be subject to modification when directed by the District Manager. (2) If the lessee fails to control and remove the pollution, the Director, in cooperation with other appropriate Agencies of Federal, State, and local governments, or in cooperation with the lessee, or both, shall have the right to control and remove the pollution at the lessee's expense. Such action shall not relieve the lessee of any responsibility provided for by law. (b)(1) The District Manager may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Manager may also restrict the use of components that could cause unreasonable degradation to the marine environment. No petroleum-based substances, including diesel fuel, may be added to the drilling mud system without prior approval of the District Manager. For Arctic OCS exploratory drilling, you must capture all petroleum-based mud to prevent its discharge into the marine environment. The Regional Supervisor may also require you to capture, during your Arctic OCS exploratory drilling operations, all water-based mud from operations after completion of the hole for the conductor casing to prevent its discharge into the marine environment, based on various factors including, but not limited to: (i) The proximity of your exploratory drilling operation to subsistence hunting and fishing locations; (ii) The extent to which discharged mud may cause marine mammals to alter their migratory patterns in a manner that impedes subsistence users' access to, or use of, those resources, or increases the risk of injury to subsistence users; or (iii) The extent to which discharged mud may adversely affect marine mammals, fish, or their habitat. (2) You must obtain approval from the District Manager of the method you plan to use to dispose of drill cuttings, sand, and other well solids. For Arctic OCS exploratory drilling, you must capture all cuttings from operations that utilize petroleum-based mud to prevent their discharge into the marine environment. The Regional Supervisor may also require you to capture, during your Arctic OCS exploratory drilling operations, all cuttings from operations that utilize water-based mud after completion of the hole for the conductor casing to prevent their discharge into the marine environment, based on various factors including, but not limited to: (i) The proximity of your exploratory drilling operation to subsistence hunting and fishing locations; (ii) The extent to which discharged cuttings may cause marine mammals to alter their migratory patterns in a manner that impedes subsistence users' access to, or use of, those resources, or increases the risk of injury to subsistence users; or (iii) The extent to which discharged cuttings may adversely affect marine mammals, fish, or their habitat. (3) All hydrocarbon-handling equipment for testing and production such as separators, tanks, and treaters shall be designed, installed, and operated to prevent pollution. Maintenance or repairs which are necessary to prevent pollution of offshore waters shall be undertaken immediately. (4) Curbs, gutters, drip pans, and drains shall be installed in deck areas in a manner necessary to collect all contaminants not authorized for discharge. Oil drainage shall be piped to a properly designed, operated, and maintained sump system which will automatically maintain the oil at a level sufficient to prevent discharge of oil into offshore waters. All gravity drains shall be equipped with a water trap or other means to prevent gas in the sump system from escaping through the drains. Sump piles shall not be used as processing devices to treat or skim liquids but may be used to collect treated-produced water, treated-produced sand, or liquids from drip pans and deck drains and as a final trap for hydrocarbon liquids in the event of equipment upsets. Improperly designed, operated, or maintained sump piles which do not prevent the discharge of oil into offshore waters shall be replaced or repaired. (5) On artificial islands, all vessels containing hydrocarbons shall be placed inside an impervious berm or otherwise protected to contain spills. Drainage shall be directed away from the drilling rig to a sump. Drains and sumps shall be constructed to prevent seepage. (6) Disposal of equipment, cables, chains, containers, or other materials into offshore waters is prohibited. (c) Materials, equipment, tools, containers, and other items used in the Outer Continental Shelf (OCS) which are of such shape or configuration that they are likely to snag or damage fishing devices shall be handled and marked as follows: (1) All loose material, small tools, and other small objects shall be kept in a suitable storage area or a marked container when not in use and in a marked container before transport over offshore waters; (2) All cable, chain, or wire segments shall be recovered after use and securely stored until suitable disposal is accomplished; (3) Skid-mounted equipment, portable containers, spools or reels, and drums shall be marked with the owner's name prior to use or transport over offshore waters; and (4) All markings must clearly identify the owner and must be durable enough to resist the effects of the environmental conditions to which they may be exposed. (d) Any of the items described in paragraph (c) of this section that are lost overboard shall be recorded on the facility's daily operations report, as appropriate, and reported to the District Manager.

§ 250.301 Inspection of facilities. Drilling and production facilities shall be inspected daily or at intervals approved or prescribed by the District Manager to determine if pollution is occurring. Necessary maintenance or repairs shall be made immediately. Records of such inspections and repairs shall be maintained at the facility or at a nearby manned facility for 2 years.

§ 250.400 General requirements. Drilling operations must be conducted in a safe manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the Outer Continental Shelf (OCS), including any mineral deposits (in areas leased and not leased), the National security or defense, or the marine, coastal, or human environment. In addition to the requirements of this subpart, you must also follow the applicable requirements of subpart G of this part.

§§ 250.401-250.403 [Reserved]

§ 250.404 What are the requirements for the crown block? You must have a crown block safety device that prevents the traveling block from striking the crown block. You must check the device for proper operation at least once per week and after each drill-line slipping operation and record the results of this operational check in the driller's report.

§ 250.405 What are the safety requirements for diesel engines used on a drilling rig? You must equip each diesel engine with an air intake device to shut down the diesel engine in the event of a runaway. (a) For a diesel engine that is not continuously manned, you must equip the engine with an automatic shutdown device; (b) For a diesel engine that is continuously manned, you may equip the engine with either an automatic or remote manual air intake shutdown device; (c) You do not have to equip a diesel engine with an air intake device if it meets one of the following criteria: (1) Starts a larger engine; (2) Powers a firewater pump; (3) Powers an emergency generator; (4) Powers a BOP accumulator system; (5) Provides air supply to divers or confined entry personnel; (6) Powers temporary equipment on a nonproducing platform; (7) Powers an escape capsule; or (8) Powers a portable single-cylinder rig washer.

§ 250.406 [Reserved]

§ 250.407 What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas, sulphur, and water in the formations penetrated by logging, formation sampling, or well testing.

§ 250.408 May I use alternative procedures or equipment during drilling operations? You may use alternative procedures or equipment during drilling operations after receiving approval from the District Manager. You must identify and discuss your proposed alternative procedures or equipment in your Application for Permit to Drill (APD) (Form BSEE-0123) (see § 250.414(h)). Procedures for obtaining approval are described in § 250.141 of this part.

§ 250.409 May I obtain departures from these drilling requirements? The District Manager may approve departures from the drilling requirements specified in this subpart. You may apply for a departure from drilling requirements by writing to the District Manager. You should identify and discuss the departure you are requesting in your APD (see § 250.414(h)).

§ 250.410 How do I obtain approval to drill a well? You must obtain written approval from the District Manager before you begin drilling any well or before you sidetrack, bypass, or deepen a well. To obtain approval, you must: (a) Submit the information required by §§ 250.411 through 250.418; (b) Include the well in your approved Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD); (c) Meet the oil spill financial responsibility requirements for offshore facilities as required by 30 CFR part 553; and (d) Submit the following to the District Manager: (1) An original and two complete copies of Form BSEE-0123, Application for Permit to Drill (APD), and Form BSEE-0123S, Supplemental APD Information Sheet; (2) A separate public information copy of forms BSEE-0123 and BSEE-0123S that meets the requirements of § 250.186; and (3) Payment of the service fee listed in § 250.125.

§ 250.411 What information must I submit with my application? In addition to forms BSEE-0123 and BSEE-0123S, you must include the information required in this subpart and subpart G of this part, including the following:

§ 250.412 What requirements must the location plat meet? The location plat must: (a) Have a scale of 1:24,000 (1 inch = 2,000 feet); (b) Show the surface and subsurface locations of the proposed well and all the wells in the vicinity; (c) Show the surface and subsurface locations of the proposed well in feet or meters from the block line; (d) Contain the longitude and latitude coordinates, and either Universal Transverse Mercator grid-system coordinates or state plane coordinates in the Lambert or Transverse Mercator Projection system for the surface and subsurface locations of the proposed well; and (e) State the units and geodetic datum (including whether the datum is North American Datum 27 or 83) for these coordinates. If the datum was converted, you must state the method used for this conversion, since the various methods may produce different values.

§ 250.413 What must my description of well drilling design criteria address? Your description of well drilling design criteria must address: (a) Pore pressures; (b) Formation fracture gradients, adjusted for water depth; (c) Potential lost circulation zones; (d) Drilling fluid weights; (e) Casing setting depths; (f) Maximum anticipated surface pressures. For this section, maximum anticipated surface pressures are the pressures that you reasonably expect to be exerted upon a casing string and its related wellhead equipment. In calculating maximum anticipated surface pressures, you must consider: drilling, completion, and producing conditions; drilling fluid densities to be used below various casing strings; fracture gradients of the exposed formations; casing setting depths; total well depth; formation fluid types; safety margins; and other pertinent conditions. You must include the calculations used to determine the pressures for the drilling and the completion phases, including the anticipated surface pressure used for designing the production string; (g) A single plot containing curves for estimated pore pressures, formation fracture gradients, proposed drilling fluid weights (surface and downhole), planned safe drilling margin, and casing setting depths in true vertical measurements; (h) A summary report of the shallow hazards site survey that describes the geological and manmade conditions if not previously submitted; and (i) Permafrost zones, if applicable.

§ 250.414 What must my drilling prognosis include? Your drilling prognosis must include a brief description of the procedures you will follow in drilling the well. This prognosis includes but is not limited to the following: (a) Projected plans for coring at specified depths; (b) Projected plans for logging; (c) Planned safe drilling margin that is between the estimated pore pressure and the lesser of estimated fracture gradients or casing shoe pressure integrity test and that is based on a risk assessment consistent with expected well conditions and operations. (1) Your safe drilling margin must also include use of equivalent downhole mud weight that is: (i) Greater than the estimated pore pressure; and (ii) Except as provided in paragraph (c)(2) of this section, a minimum of 0.5 pound per gallon below the lower of the casing shoe pressure integrity test or the lowest estimated fracture gradient. (2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this section, you may use an equivalent downhole mud weight as specified in your APD, provided that you submit adequate documentation (such as risk modeling data, off-set well data, analog data, seismic data) to justify the alternative equivalent downhole mud weight. You may submit such justification in advance of your full APD, and BSEE may consider such justification for approval when submitted. Any such approval will be contingent upon your confirmation in the APD that your plans and the information underlying your approved justification have not changed. (3) When determining the pore pressure and lowest estimated fracture gradient for a specific interval, you must consider related off-set and analogous well behavior observations, if available. (d) Estimated depths to the top of significant marker formations; (e) Estimated depths to significant porous and permeable zones containing fresh water, oil, gas, or abnormally pressured formation fluids; (f) Estimated depths to major faults; (g) Estimated depths of permafrost, if applicable; (h) A list and description of all requests for using alternate procedures or departures from the requirements of this subpart in one place in the APD. You must explain how the alternate procedures afford an equal or greater degree of protection, safety, or performance, or why the departures are requested; (i) Projected plans for well testing (refer to § 250.460); (j) The type of wellhead system and liner hanger system to be installed and a descriptive schematic, which includes but is not limited to pressure ratings, dimensions, valves, load shoulders, and locking mechanisms, if applicable; and (k) Any additional information required by the District Manager needed to clarify or evaluate your drilling prognosis.

§ 250.415 What must my casing and cementing programs include? Your casing and cementing programs must include: (a) The following well design information: (1) Hole sizes; (2) Bit depths (including measured and true vertical depth (TVD)); (3) Casing information, including sizes, weights, grades, collapse and burst values, types of connection, and setting depths (measured and TVD) for all sections of each casing interval; and (4) Locations of any installed rupture disks (indicate if burst or collapse and rating); (b) Casing design safety factors for tension, collapse, and burst with the assumptions made to arrive at these values; (c) Type and amount of cement (in cubic feet) planned for each casing string; (d) In areas containing permafrost, setting depths for conductor and surface casing based on the anticipated depth of the permafrost. Your program must provide protection from thaw subsidence and freezeback effect, proper anchorage, and well control; (e) A statement of how you evaluated the best practices included in API Recommended Practice 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deep Water Wells (incorporated by reference, see § 250.198), if you drill a well in water depths greater than 500 feet and are in either of the following two areas: (1) An “area with an unknown shallow water flow potential” is a zone or geologic formation where neither the presence nor absence of potential for a shallow water flow has been confirmed. (2) An “area known to contain a shallow water flow hazard” is a zone or geologic formation for which drilling has confirmed the presence of shallow water flow; and (f) A written description of how you evaluated the best practices included in API Standard 65—Part 2, Isolating Potential Flow Zones During Well Construction, Second Edition (incorporated by reference, see § 250.198). Your written description must identify the mechanical barriers and cementing practices you will use for each casing string (reference API Standard 65—Part 2, Sections 4 and 5).

§ 250.416 What must I include in the diverter description? You must include in the diverter description: (a) A description of the diverter system and its operating procedures; (b) A schematic drawing of the diverter system (plan and elevation views) that shows: (1) The size of the element installed in the diverter housing; (2) Spool outlet internal diameter(s); (3) Diverter-line lengths and diameters; burst strengths and radius of curvature at each turn; and (4) Valve type, size, working pressure rating, and location.

§ 250.417 [Reserved]

§ 250.418 What additional information must I submit with my APD? You must include the following with the APD: (a) Rated capacities of the drilling rig and major drilling equipment, if not already on file with the appropriate District office; (b) A drilling fluids program that includes the minimum quantities of drilling fluids and drilling fluid materials, including weight materials, to be kept at the site; (c) A proposed directional plot if the well is to be directionally drilled; (d) A Hydrogen Sulfide Contingency Plan (see § 250.490), if applicable, and not previously submitted; (e) A welding plan (see §§ 250.109 to 250.113) if not previously submitted; (f) In areas subject to subfreezing conditions, evidence that the drilling equipment, BOP systems and components, diverter systems, and other associated equipment and materials are suitable for operating under such conditions; (g) A request for approval, if you plan to wash out or displace cement to facilitate casing removal upon well abandonment. Your request must include a description of how far below the mudline you propose to displace cement and how you will visually monitor returns; (h) Certification of your casing and cementing program as required in § 250.420(a)(7); and (i) Such other information as the District Manager may require. (j) For Arctic OCS exploratory drilling operations, you must provide the information required by § 250.470.

§ 250.420 What well casing and cementing requirements must I meet? You must case and cement all wells. Your casing and cementing programs must meet the applicable requirements of this subpart and of subpart G of this part. (a) Casing and cementing program requirements. Your casing and cementing programs must: (1) Properly control formation pressures and fluids; (2) Prevent the direct or indirect release of fluids from any stratum through the wellbore into offshore waters; (3) Prevent communication between separate hydrocarbon-bearing strata; (4) Protect freshwater aquifers from contamination; (5) Support unconsolidated sediments; (6) Provide adequate centralization consistent with the guidelines of API Standard 65—Part 2 (incorporated by reference, see § 250.198); and (7)(i) Include a certification signed by a registered professional engineer that the casing and cementing design is appropriate for the purpose for which it is intended under expected wellbore conditions, and is sufficient to satisfy the tests and requirements of this section and § 250.423. Submit this certification with your APD (Form BSEE-0123). (ii) You must have the registered professional engineer involved in the casing and cementing design process. (iii) The registered professional engineer must be registered in a state of the United States and have sufficient expertise and experience to perform the certification. (b) Casing requirements. (1) You must design casing (including liners) to withstand the anticipated stresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal effects; and combinations thereof. (2) The casing design must include safety measures that ensure well control during drilling and safe operations during the life of the well. (3) On all wells that use subsea BOP stacks, you must include two independent barriers, including one mechanical barrier, in each annular flow path (examples of barriers include, but are not limited to, primary cement job and seal assembly). For the final casing string (or liner if it is your final string), you must install one mechanical barrier in addition to cement to prevent flow in the event of a failure in the cement. A dual float valve, by itself, is not considered a mechanical barrier. These barriers cannot be modified prior to or during completion or abandonment operations. The BSEE District Manager may approve alternative options under § 250.141. You must submit documentation of this installation to BSEE in the End-of-Operations Report (Form BSEE-0125). (4) If you need to substitute a different size, grade, or weight of casing than what was approved in your APD, you must contact the District Manager for approval prior to installing the casing. (c) Cementing requirements. (1) You must design and conduct your cementing jobs so that cement composition, placement techniques, and waiting times ensure that the cement placed behind the bottom 500 feet of casing attains a minimum compressive strength of 500 psi before drilling out the casing or before commencing completion operations. (If a liner is used refer to § 250.421(f)). (2) You must use a weighted fluid during displacement to maintain an overbalanced hydrostatic pressure during the cement setting time, except when cementing casings or liners in riserless hole sections.

§ 250.421 What are the casing and cementing requirements by type of casing string? The table in this section identifies specific design, setting, and cementing requirements for casing strings and liners. For the purposes of subpart D, the casing strings in order of normal installation are as follows: drive or structural, conductor, surface, intermediate, and production casings (including liners). The District Manager may approve or prescribe other casing and cementing requirements where appropriate.

§ 250.422 When may I resume drilling after cementing? (a) After cementing surface, intermediate, or production casing (or liners), you may resume drilling after the cement has been held under pressure for 12 hours. For conductor casing, you may resume drilling after the cement has been held under pressure for 8 hours. One acceptable method of holding cement under pressure is to use float valves to hold the cement in place. (b) If you plan to nipple down your diverter or BOP stack during the 8- or 12-hour waiting time, you must determine, before nippling down, when it will be safe to do so. You must base your determination on a knowledge of formation conditions, cement composition, effects of nippling down, presence of potential drilling hazards, well conditions during drilling, cementing, and post cementing, as well as past experience.

§ 250.423 What are the requirements for casing and liner installation? You must ensure proper installation of casing in the subsea wellhead or liner in the liner hanger. (a) You must ensure that the latching mechanisms or lock down mechanisms are engaged upon successfully installing the casing string. (b) If you run a liner that has a latching mechanism or lock down mechanism, you must ensure that the latching mechanisms or lock down mechanisms are engaged upon successfully installing the liner. (c) You must perform a pressure test on the casing seal assembly to ensure proper installation of casing or liner. You must perform this test for the intermediate and production casing strings or liners. (1) You must submit for approval with your APD, test procedures and criteria for a successful test. (2) You must document all your test results and make them available to BSEE upon request.

§§ 250.424-250.426 [Reserved]

§ 250.427 What are the requirements for pressure integrity tests? You must conduct a pressure integrity test below the surface casing or liner and all intermediate casings or liners. The District Manager may require you to run a pressure-integrity test at the conductor casing shoe if warranted by local geologic conditions or the planned casing setting depth. You must conduct each pressure integrity test after drilling at least 10 feet but no more than 50 feet of new hole below the casing shoe. You must test to either the formation leak-off pressure or to an equivalent drilling fluid weight if identified in an approved APD. (a) You must use the pressure integrity test and related hole-behavior observations, such as pore-pressure test results, gas-cut drilling fluid, and well kicks to adjust the drilling fluid program and the setting depth of the next casing string. You must record all test results and hole-behavior observations made during the course of drilling related to formation integrity and pore pressure in the driller's report. (b) While drilling, you must maintain the safe drilling margin identified in § 250.414. When you cannot maintain the safe drilling margin, you must: (1) Suspend drilling operations and submit proposed remedial actions to the District Manager. The District Manager must review and approve your proposed remedial actions, which may include limited drilling through a lost circulation zone; or (2) Notify the District Manager and take further action in accordance with API Bulletin 92L (incorporated by reference, see § 250.198), if appropriate. You must submit a revised permit documenting any responsive actions taken.

§ 250.428 What must I do in certain cementing and casing situations? The table in this section describes actions that lessees must take when certain situations occur during casing and cementing activities.

§ 250.430 When must I install a diverter system? You must install a diverter system before you drill a conductor or surface hole. The diverter system consists of a diverter sealing element, diverter lines, and control systems. You must design, install, use, maintain, and test the diverter system to ensure proper diversion of gases, water, drilling fluid, and other materials away from facilities and personnel.

§ 250.431 What are the diverter design and installation requirements? You must design and install your diverter system to: (a) Use diverter spool outlets and diverter lines that have a nominal diameter of at least 10 inches for surface wellhead configurations and at least 12 inches for floating drilling operations; (b) Use dual diverter lines arranged to provide for downwind diversion capability; (c) Use at least two diverter control stations. One station must be on the drilling floor. The other station must be in a readily accessible location away from the drilling floor; (d) Use only remote-controlled valves in the diverter lines. All valves in the diverter system must be full-opening. You may not install manual or butterfly valves in any part of the diverter system; (e) Minimize the number of turns (only one 90-degree turn allowed for each line for bottom-founded drilling units) in the diverter lines, maximize the radius of curvature of turns, and target all right angles and sharp turns; (f) Anchor and support the entire diverter system to prevent whipping and vibration; and (g) Protect all diverter-control instruments and lines from possible damage by thrown or falling objects.

§ 250.432 How do I obtain a departure to diverter design and installation requirements? The table below describes possible departures from the diverter requirements and the conditions required for each departure. To obtain one of these departures, you must have discussed the departure in your APD and received approval from the District Manager.

§ 250.433 What are the diverter actuation and testing requirements? When you install the diverter system, you must actuate the diverter sealing element, diverter valves, and diverter-control systems and control stations. You must also flow-test the vent lines. (a) For drilling operations with a surface wellhead configuration, you must actuate the diverter system at least once every 24-hour period after the initial test. After you have nippled up on conductor casing, you must pressure-test the diverter-sealing element and diverter valves to a minimum of 200 psi. While the diverter is installed, you must conduct subsequent pressure tests within 7 days after the previous test. (b) For floating drilling operations with a subsea BOP stack, you must actuate the diverter system within 7 days after the previous actuation. For subsequent testing, you may partially actuate the diverter element and a flow test is not required. (c) You must alternate actuations and tests between control stations.

§ 250.434 What are the recordkeeping requirements for diverter actuations and tests? You must record the time, date, and results of all diverter actuations and tests in the driller's report. In addition, you must: (a) Record the diverter pressure test on a pressure chart; (b) Require your onsite representative to sign and date the pressure test chart; (c) Identify the control station used during the test or actuation; (d) Identify problems or irregularities observed during the testing or actuations and record actions taken to remedy the problems or irregularities; and (e) Retain all pressure charts and reports pertaining to the diverter tests and actuations at the facility for the duration of drilling the well.

§§ 250.440-250.451 [Reserved]

§ 250.452 What are the real-time monitoring requirements for Arctic OCS exploratory drilling operations? (a) When conducting exploratory drilling operations on the Arctic OCS, you must gather and monitor real-time data using an independent, automatic, and continuous monitoring system capable of recording, storing, and transmitting data regarding the following: (1) The BOP control system; (2) The well's fluid handling systems on the rig; and (3) The well's downhole conditions as monitored by a downhole sensing system, when such a system is installed. (b) During well operations, you must transmit the data identified in paragraph (a) of this section as they are gathered, barring unforeseeable or unpreventable interruptions in transmission, and have the capability to monitor the data onshore, using qualified personnel. Onshore personnel who monitor real-time data must have the capability to contact rig personnel during operations. After well operations, you must store the data at a designated location for recordkeeping purposes as required in §§ 250.740 and 250.741. You must provide BSEE with access to your real-time monitoring data onshore upon request.

§ 250.455 What are the general requirements for a drilling fluid program? You must design and implement your drilling fluid program to prevent the loss of well control. This program must address drilling fluid safe practices, testing and monitoring equipment, drilling fluid quantities, and drilling fluid-handling areas.

§ 250.456 What safe practices must the drilling fluid program follow? Your drilling fluid program must include the following safe practices: (a) Before starting out of the hole with drill pipe, you must properly condition the drilling fluid. You must circulate a volume of drilling fluid equal to the annular volume with the drill pipe just off-bottom. You may omit this practice if documentation in the driller's report shows: (1) No indication of formation fluid influx before starting to pull the drill pipe from the hole; (2) The weight of returning drilling fluid is within 0.2 pounds per gallon (1.5 pounds per cubic foot) of the drilling fluid entering the hole; and (3) Other drilling fluid properties are within the limits established by the program approved in the APD. (b) Record each time you circulate drilling fluid in the hole in the driller's report; (c) When coming out of the hole with drill pipe, you must fill the annulus with drilling fluid before the hydrostatic pressure decreases by 75 psi, or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. You must calculate the number of stands of drill pipe and drill collars that you may pull before you must fill the hole. You must also calculate the equivalent drilling fluid volume needed to fill the hole. Both sets of numbers must be posted near the driller's station. You must use a mechanical, volumetric, or electronic device to measure the drilling fluid required to fill the hole; (d) You must run and pull drill pipe and downhole tools at controlled rates so you do not swab or surge the well; (e) When there is an indication of swabbing or influx of formation fluids, you must take appropriate measures to control the well. You must circulate and condition the well, on or near-bottom, unless well or drilling-fluid conditions prevent running the drill pipe back to the bottom; (f) You must calculate and post near the driller's console the maximum pressures that you may safely contain under a shut-in BOP for each casing string. The pressures posted must consider the surface pressure at which the formation at the shoe would break down, the rated working pressure of the BOP stack, and 70 percent of casing burst (or casing test as approved by the District Manager). As a minimum, you must post the following two pressures: (1) The surface pressure at which the shoe would break down. This calculation must consider the current drilling fluid weight in the hole; and (2) The lesser of the BOP's rated working pressure or 70 percent of casing-burst pressure (or casing test otherwise approved by the District Manager); (g) You must install an operable drilling fluid-gas separator and degasser before you begin drilling operations. You must maintain this equipment throughout the drilling of the well; (h) Before pulling drill-stem test tools from the hole, you must circulate or reverse-circulate the test fluids in the hole. If circulating out test fluids is not feasible, you may bullhead test fluids out of the drill-stem test string and tools with an appropriate kill weight fluid; (i) When circulating, you must test the drilling fluid at least once each tour, or more frequently if conditions warrant. Your tests must conform to industry-accepted practices and include density, viscosity, and gel strength; hydrogenion concentration; filtration; and any other tests the District Manager requires for monitoring and maintaining drilling fluid quality, prevention of downhole equipment problems and for kick detection. You must record the results of these tests in the drilling fluid report; and (j) In areas where permafrost and/or hydrate zones are present or may be present, you must control drilling fluid temperatures to drill safely through those zones.

§ 250.457 What equipment is required to monitor drilling fluids? Once you establish drilling fluid returns, you must install and maintain the following drilling fluid-system monitoring equipment throughout subsequent drilling operations. This equipment must have the following indicators on the rig floor: (a) Pit level indicator to determine drilling fluid-pit volume gains and losses. This indicator must include both a visual and an audible warning device; (b) Volume measuring device to accurately determine drilling fluid volumes required to fill the hole on trips; (c) Return indicator devices that indicate the relationship between drilling fluid-return flow rate and pump discharge rate. This indicator must include both a visual and an audible warning device; and (d) Gas-detecting equipment to monitor the drilling fluid returns. The indicator may be located in the drilling fluid-logging compartment or on the rig floor. If the indicators are only in the logging compartment, you must continually man the equipment and have a means of immediate communication with the rig floor. If the indicators are on the rig floor only, you must install an audible alarm.

§ 250.458 What quantities of drilling fluids are required? (a) You must use, maintain, and replenish quantities of drilling fluid and drilling fluid materials at the drill site as necessary to ensure well control. You must determine those quantities based on known or anticipated drilling conditions, rig storage capacity, weather conditions, and estimated time for delivery. (b) You must record the daily inventories of drilling fluid and drilling fluid materials, including weight materials and additives in the drilling fluid report. (c) If you do not have sufficient quantities of drilling fluid and drilling fluid material to maintain well control, you must suspend drilling operations.

§ 250.459 What are the safety requirements for drilling fluid-handling areas? You must classify drilling fluid-handling areas according to API Recommended Practice 500 (incorporated by reference, see § 250.198); or API Recommended Practice 505 (incorporated by reference, see § 250.198). In areas where dangerous concentrations of combustible gas may accumulate, you must install and maintain a ventilation system and gas monitors. Drilling fluid-handling areas must have the following safety equipment: (a) A ventilation system capable of replacing the air once every 5 minutes or 1.0 cubic feet of air-volume flow per minute, per square foot of area, whichever is greater. In addition: (1) If natural means provide adequate ventilation, then a mechanical ventilation system is not necessary; (2) If a mechanical system does not run continuously, then it must activate when gas detectors indicate the presence of 1 percent or more of combustible gas by volume; and (3) If discharges from a mechanical ventilation system may be hazardous, then you must maintain the drilling fluid-handling area at a negative pressure. You must protect the negative pressure area by using at least one of the following: a pressure-sensitive alarm, open-door alarms on each access to the area, automatic door-closing devices, air locks, or other devices approved by the District Manager; (b) Gas detectors and alarms except in open areas where adequate ventilation is provided by natural means. You must test and recalibrate gas detectors quarterly. No more than 90 days may elapse between tests; (c) Explosion-proof or pressurized electrical equipment to prevent the ignition of explosive gases. Where you use air for pressuring equipment, you must locate the air intake outside of and as far as practicable from hazardous areas; and (d) Alarms that activate when the mechanical ventilation system fails.

§ 250.460 What are the requirements for conducting a well test? (a) If you intend to conduct a well test, you must include your projected plans for the test with your APD (form BSEE-0123) or in an Application for Permit to Modify (APM) (form BSEE-0124). Your plans must include at least the following information: (1) Estimated flowing and shut-in tubing pressures; (2) Estimated flow rates and cumulative volumes; (3) Time duration of flow, buildup, and drawdown periods; (4) Description and rating of surface and subsurface test equipment; (5) Schematic drawing, showing the layout of test equipment; (6) Description of safety equipment, including gas detectors and fire-fighting equipment; (7) Proposed methods to handle or transport produced fluids; and (8) Description of the test procedures. (b) You must give the District Manager at least 24-hours notice before starting a well test.

§ 250.461 What are the requirements for directional and inclination surveys? For this subpart, BSEE classifies a well as vertical if the calculated average of inclination readings does not exceed 3 degrees from the vertical. (a) Survey requirements for a vertical well. (1) You must conduct inclination surveys on each vertical well and record the results. Survey intervals may not exceed 1,000 feet during the normal course of drilling; (2) You must also conduct a directional survey that provides both inclination and azimuth, and digitally record the results in electronic format: (i) Within 500 feet of setting surface or intermediate casing; (ii) Within 500 feet of setting any liner; and (iii) When you reach total depth. (b) Survey requirements for a directional well. You must conduct directional surveys on each directional well and digitally record the results. Surveys must give both inclination and azimuth at intervals not to exceed 500 feet during the normal course of drilling. Intervals during angle-changing portions of the hole may not exceed 180 feet. (c) Measurement while drilling. You may use measurement-while-drilling technology if it meets the requirements of this section. (d) Composite survey requirements. (1) Your composite directional survey must show the interval from the bottom of the conductor casing to total depth. In the absence of conductor casing, the survey must show the interval from the bottom of the drive or structural casing to total depth; and (2) You must correct all surveys to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north after making the magnetic-to-true-north correction. Surveys must show the magnetic and grid corrections used and include a listing of the directionally computed inclinations and azimuths. (e) If you drill within 500 feet of an adjacent lease, the Regional Supervisor may require you to furnish a copy of the well's directional survey to the affected leaseholder. This could occur when the adjoining leaseholder requests a copy of the survey for the protection of correlative rights.

§ 250.462 What are the source control, containment, and collocated equipment requirements? For drilling operations using a subsea BOP or surface BOP on a floating facility, you must have the ability to control or contain a blowout event at the sea floor. (a) To determine your required source control and containment capabilities you must do the following: (1) Consider a scenario of the wellbore fully evacuated to reservoir fluids, with no restrictions in the well. (2) Evaluate the performance of the well as designed to determine if a full shut-in can be achieved without having reservoir fluids broach to the sea floor. If your evaluation indicates that the well can only be partially shut-in, then you must determine your ability to flow and capture the residual fluids to a surface production and storage system. (b) You must have access to and the ability to deploy Source Control and Containment Equipment (SCCE) and all other necessary supporting and collocated equipment to regain control of the well. SCCE means the capping stack, cap-and-flow system, containment dome, and/or other subsea and surface devices, equipment, and vessels, which have the collective purpose to control a spill source and stop the flow of fluids into the environment or to contain fluids escaping into the environment based on the determinations outlined in paragraph (a) of this section. This SCCE, supporting equipment, and collocated equipment may include, but is not limited to, the following: (1) Subsea containment and capture equipment, including containment domes and capping stacks; (2) Subsea utility equipment including hydraulic power sources and hydrate control equipment; (3) Collocated equipment including dispersant injection equipment; (4) Riser systems; (5) Remotely operated vehicles (ROVs); (6) Capture vessels; (7) Support vessels; and (8) Storage facilities. (c) You must submit a description of your source control and containment capabilities to the Regional Supervisor and receive approval before BSEE will approve your APD, Form BSEE-0123. The description of your containment capabilities must contain the following: (1) Your source control and containment capabilities for controlling and containing a blowout event at the seafloor; (2) A discussion of the determination required in paragraph (a) of this section; and (3) Information showing that you have access to and the ability to deploy all equipment required by paragraph (b) of this section. (d) You must contact the District Manager and Regional Supervisor for reevaluation of your source control and containment capabilities if your: (1) Well design changes; or (2) Approved source control and containment equipment is out of service. (e) You must maintain, test, and inspect the source control, containment, and collocated equipment identified in the following table according to these requirements:

§ 250.463 Who establishes field drilling rules? (a) The District Manager may establish field drilling rules different from the requirements of this subpart when geological and engineering information shows that specific operating requirements are appropriate. You must comply with field drilling rules and nonconflicting requirements of this subpart. The District Manager may amend or cancel field drilling rules at any time. (b) You may request the District Manager to establish, amend, or cancel field drilling rules.

§ 250.465 When must I submit an Application for Permit to Modify (APM) or an End of Operations Report to BSEE? (a) You must submit an APM (form BSEE-0124) or an End of Operations Report (form BSEE-0125) and other materials to the Regional Supervisor as shown in the following table. You must also submit a public information copy of each form. (b) If you intend to perform any of the actions specified in paragraph (a)(1) of this section, you must meet the following additional requirements: (1) Your APM (Form BSEE-0124) must contain a detailed statement of the proposed work that would materially change from the approved APD. The submission of your APM must be accompanied by payment of the service fee listed in § 250.125; (2) Your form BSEE-0124 must include the present status of the well, depth of all casing strings set to date, well depth, present production zones and productive capability, and all other information specified; and (3) Within 30 days after completing this work, you must submit an End of Operations Report (EOR), Form BSEE-0125, as required under § 250.744.

§§ 250.466-250.469 [Reserved]

§ 250.470 What additional information must I submit with my APD for Arctic OCS exploratory drilling operations? In addition to complying with all other applicable requirements included in this part, you must provide with your APD all of the following information pertaining to your proposed Arctic OCS exploratory drilling: (a) A detailed description of: (1) The environmental, meteorological, and oceanic conditions you expect to encounter at the well site(s); (2) How you will prepare your equipment, materials, and drilling unit for service in the conditions identified in paragraph (a)(1) of this section, and how your drilling unit will be in compliance with the requirements of § 250.713. (b) A detailed description of all operations necessary in Arctic OCS conditions to transition the rig from being under way to conducting drilling operations and from ending drilling operations to being under way, as well as any anticipated repair and maintenance plans for the drilling unit and equipment. You should include, among other things, a description of how you plan to: (1) Recover the subsea equipment, including the marine riser and the lower marine riser package; (2) Recover the BOP; (3) Recover the auxiliary sub-sea controls and template; (4) Lay down the drill pipe and secure the drill pipe and marine riser; (5) Secure the drilling equipment; (6) Transfer the fluids for transport or disposal; (7) Secure ancillary equipment like the draw works and lines; (8) Refuel or transfer fuel; (9) Offload waste; (10) Recover the Remotely Operated Vehicles; (11) Pick up the oil spill prevention booms and equipment; and (12) Offload the drilling crew. (c) A description of well-specific drilling objectives, timelines, and updated contingency plans for temporary abandonment of the well, including but not limited to the following: (1) When you will spud the particular well (i.e., begin drilling operations at the well site) identified in the APD; (2) How long you will take to drill the well; (3) Anticipated depths and geologic targets, with timelines; (4) When you expect to set and cement each string of casing; (5) When and how you would log the well; (6) Your plans to test the well; (7) When and how you intend to abandon the well, including specifically addressing your plans for how to move the rig off location and how you will meet the requirements of § 250.720(c); (8) A description of what equipment and vessels will be involved in the process of temporarily abandoning the well due to ice; and (9) An explanation of how you will integrate these elements into your overall program. (d) A detailed description of your weather and ice forecasting capability for all phases of the drilling operation, including: (1) How you will ensure your continuous awareness of potential weather and ice hazards at, and during transition between, wells; (2) Your plans for managing ice hazards and responding to weather events; and (3) Verification that you have the capabilities described in your BOEM-approved EP. (e) A detailed description of how you will comply with the requirements of § 250.472. (f) A statement that you own, or have a contract with a provider for, source control and containment equipment (SCCE), which is capable of controlling and/or containing a worst case discharge, as described in your BOEM-approved EP, when proposing to use a MODU to conduct exploratory drilling operations on the Arctic OCS. The following information must be included in your SCCE submittal: (1) A detailed description of your or your contractor's SCCE capability to stop or contain flow from an out-of-control well, including your operating assumptions and limitations; your access to and ability to deploy, in accordance with § 250.471, all necessary SCCE; and your ability to evaluate the performance of the well design to determine how you can achieve a full shut-in without having reservoir fluids discharged into the environment; (2) An inventory of the local and regional SCCE, supplies, and services that you own or for which you have a contract with a provider. You must identify each supplier of such equipment and services and provide their locations and telephone numbers; (3) Where applicable, proof of contracts or membership agreements with cooperatives, service providers, or other contractors who will provide you with the necessary SCCE or related supplies and services if you do not possess them. The contract or membership agreement must include provisions for ensuring the availability of the personnel and/or equipment on a 24-hour per day basis while you are drilling below or working below the surface casing; (4) A detailed description of the procedures you plan to use to inspect, test, and maintain your SCCE; and (5) A detailed description of your plan to ensure that all members of your operating team, who are responsible for operating the SCCE, have received the necessary training to deploy and operate such equipment in Arctic OCS conditions and demonstrate ongoing proficiency in source control operations. You must also identify and include the dates of prior and planned training. (g) Where it does not conflict with other requirements of this subpart, and except as provided in paragraphs (g)(1) through (11) of this section, you must comply with the requirements of ANSI/API Recommended Practice 2N (incorporated by reference, see § 250.198), and provide a detailed description of how you will utilize the best practices included in ANSI/API Recommended Practice 2N during your exploratory drilling operations. You are not required to incorporate the following sections of ANSI/API Recommended Practice 2N into your drilling operations: (1) Sections 6.6.3 through 6.6.4; (2) The foundation recommendations in Section 8.4; (3) Section 9.6; (4) The recommendations for permanently moored systems in Section 9.7; (5) The recommendations for pile foundations in Section 9.10; (6) Section 12; (7) Section 13.2.1; (8) Sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through 13.8.2.7; (9) Sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8; (10) Sections 14 through 16; and (11) Section 18.

§ 250.471 What are the requirements for Arctic OCS source control and containment? You must meet the following requirements for all exploration wells drilled on the Arctic OCS: (a) If you use a MODU when drilling below or working below the surface casing, you must have access to the following SCCE capable of stopping or capturing the flow of an out-of-control well: (1) A capping stack, positioned to ensure that it will arrive at the well location within 24 hours after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section; (2) A cap and flow system, positioned to ensure that it will arrive at the well location within 7 days after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section. The cap and flow system must be designed to capture at least the amount of hydrocarbons equivalent to the calculated worst case discharge rate referenced in your BOEM-approved EP; and (3) A containment dome, positioned to ensure that it will arrive at the well location within 7 days after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section. The containment dome must have the capacity to pump fluids without relying on buoyancy. (b) You must conduct a monthly stump test of dry-stored capping stacks. If you use a pre-positioned capping stack, you must conduct a stump test prior to each installation on each well. (c) As required by § 250.465(a), if you propose to change your well design, you must submit an APM. For Arctic OCS operations, your APM must include a reevaluation of your SCCE capabilities for any new Worst Case Discharge (WCD) rate, and a demonstration that your SCCE capabilities will meet the criteria in § 250.470(f) under the changed well design. (d) You must conduct tests or exercises of your SCCE, including deployment of your SCCE, when directed by the Regional Supervisor. (e) You must maintain records pertaining to testing, inspection, and maintenance of your SCCE for at least 10 years and make the records available to any authorized BSEE representative upon request. (f) You must maintain records pertaining to the use of your SCCE during testing, training, and deployment activities for at least 3 years and make the records available to any authorized BSEE representative upon request. (g) Upon a loss of well control, you must initiate transit of all SCCE identified in paragraph (a) of this section to the well. (h) You must deploy and use SCCE when directed by the Regional Supervisor. (i) Operators may request approval of alternate procedures or equipment to the SCCE requirements of subparagraph (a) of this section in accordance with § 250.141. The operator must show and document that the alternate procedures or equipment will provide a level of safety and environmental protection that will meet or exceed the level of safety and environmental protection required by BSEE regulations, including demonstrating that the alternate procedures or equipment will be capable of stopping or capturing the flow of an out-of-control well.

§ 250.472 What are the relief rig requirements for the Arctic OCS? (a) In the event of a loss of well control, the Regional Supervisor may direct you to drill a relief well using the relief rig able to kill and permanently plug an out-of-control well as described in your APD. Your relief rig must comply with all other requirements of this part pertaining to drill rig characteristics and capabilities, and it must be able to drill a relief well under anticipated Arctic OCS conditions. (b) When you are drilling below or working below the surface casing during Arctic OCS exploratory drilling operations, you must have access to a relief rig, different from your primary drilling rig, staged in a location such that it can arrive on site, drill a relief well, kill and abandon the original well, and abandon the relief well prior to expected seasonal ice encroachment at the drill site, but no later than 45 days after the loss of well control. (c) Operators may request approval of alternative compliance measures to the relief rig requirement in accordance with § 250.141. The operator must show and document that the alternate compliance measure will meet or exceed the level of safety and environmental protection required by BSEE regulations, including demonstrating that the alternate compliance measure will be able to kill and permanently plug an out-of-control well.

§ 250.473 What must I do to protect health, safety, property, and the environment while operating on the Arctic OCS? In addition to the requirements set forth in § 250.107, when conducting exploratory drilling operations on the Arctic OCS, you must protect health, safety, property, and the environment by using the following: (a) Equipment and materials that are rated or de-rated for service under conditions that can be reasonably expected during your operations; and (b) Measures to address human factors associated with weather conditions that can be reasonably expected during your operations including, but not limited to, provision of proper attire and equipment, construction of protected work spaces, and management of shifts.

§ 250.490 Hydrogen sulfide. (a) What precautions must I take when operating in an H2S area? You must: (1) Take all necessary and feasible precautions and measures to protect personnel from the toxic effects of H2S and to mitigate damage to property and the environment caused by H2S. You must follow the requirements of this section when conducting drilling, well-completion/well-workover, and production operations in zones with H2S present and when conducting operations in zones where the presence of H2S is unknown. You do not need to follow these requirements when operating in zones where the absence of H2S has been confirmed; and (2) Follow your approved contingency plan. (b) Definitions. Terms used in this section have the following meanings: Facility means a vessel, a structure, or an artificial island used for drilling, well-completion, well-workover, and/or production operations. H2S absent means: (1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H2S in concentrations that could potentially result in atmospheric concentrations of 20 ppm or more of H2S; or (2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an absence of H2S throughout the area to be drilled. H2S present means that drilling, logging, coring, testing, or producing operations have confirmed the presence of H2S in concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of H2S. H2S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2S has been confirmed. Well-control fluid means drilling mud and completion or workover fluid as appropriate to the particular operation being conducted. (c) Classifying an area for the presence of H2S. You must: (1) Request and obtain an approved classification for the area from the Regional Supervisor before you begin operations. Classifications are “H2S absent,” H2S present,” or “H2S unknown”; (2) Submit your request with your application for permit to drill; (3) Support your request with available information such as geologic and geophysical data and correlations, well logs, formation tests, cores and analysis of formation fluids; and (4) Submit a request for reclassification of a zone when additional data indicate a different classification is needed. (d) What do I do if conditions change? If you encounter H2S that could potentially result in atmospheric concentrations of 20 ppm or more in areas not previously classified as having H2S present, you must immediately notify BSEE and begin to follow requirements for areas with H2S present. (e) What are the requirements for conducting simultaneous operations? When conducting any combination of drilling, well-completion, well-workover, and production operations simultaneously, you must follow the requirements in the section applicable to each individual operation. (f) Requirements for submitting an H2S Contingency Plan. Before you begin operations, you must submit an H2S Contingency Plan to the District Manager for approval. Do not begin operations before the District Manager approves your plan. You must keep a copy of the approved plan in the field, and you must follow the plan at all times. Your plan must include: (1) Safety procedures and rules that you will follow concerning equipment, drills, and smoking; (2) Training you provide for employees, contractors, and visitors; (3) Job position and title of the person responsible for the overall safety of personnel; (4) Other key positions, how these positions fit into your organization, and what the functions, duties, and responsibilities of those job positions are; (5) Actions that you will take when the concentration of H2S in the atmosphere reaches 20 ppm, who will be responsible for those actions, and a description of the audible and visual alarms to be activated; (6) Briefing areas where personnel will assemble during an H2S alert. You must have at least two briefing areas on each facility and use the briefing area that is upwind of the H2S source at any given time; (7) Criteria you will use to decide when to evacuate the facility and procedures you will use to safely evacuate all personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H2S alerts, describe the types of H2S emergencies during which you consider the risk of helicopter activity to be acceptable and the precautions you will take during the flights; (8) Procedures you will use to safely position all vessels attendant to the facility. Indicate where you will locate the vessels with respect to wind direction. Include the distance from the facility and what procedures you will use to safely relocate the vessels in an emergency; (9) How you will provide protective-breathing equipment for all personnel, including contractors and visitors; (10) The agencies and facilities you will notify in case of a release of H2S (that constitutes an emergency), how you will notify them, and their telephone numbers. Include all facilities that might be exposed to atmospheric concentrations of 20 ppm or more of H2S; (11) The medical personnel and facilities you will use if needed, their addresses, and telephone numbers; (12) H2S detector locations in production facilities producing gas containing 20 ppm or more of H2S. Include an “H2S Detector Location Drawing” showing: (i) All vessels, flare outlets, wellheads, and other equipment handling production containing H2S; (ii) Approximate maximum concentration of H2S in the gas stream; and (iii) Location of all H2S sensors included in your contingency plan; (13) Operational conditions when you expect to flare gas containing H2S including the estimated maximum gas flow rate, H2S concentration, and duration of flaring; (14) Your assessment of the risks to personnel during flaring and what precautionary measures you will take; (15) Primary and alternate methods to ignite the flare and procedures for sustaining ignition and monitoring the status of the flare (i.e., ignited or extinguished); (16) Procedures to shut off the gas to the flare in the event the flare is extinguished; (17) Portable or fixed sulphur dioxide (SO2)-detection system(s) you will use to determine SO2 concentration and exposure hazard when H2S is burned; (18) Increased monitoring and warning procedures you will take when the SO2 concentration in the atmosphere reaches 2 ppm; (19) Personnel protection measures or evacuation procedures you will initiate when the SO2 concentration in the atmosphere reaches 5 ppm; (20) Engineering controls to protect personnel from SO2; and (21) Any special equipment, procedures, or precautions you will use if you conduct any combination of drilling, well-completion, well-workover, and production operations simultaneously. (g) Training program: (1) When and how often do employees need to be trained? All operators and contract personnel must complete an H2S training program to meet the requirements of this section: (i) Before beginning work at the facility; and (ii) Each year, within 1 year after completion of the previous class. (2) What training documentation do I need? For each individual working on the platform, either: (i) You must have documentation of this training at the facility where the individual is employed; or (ii) The employee must carry a training completion card. (3) What training do I need to give to visitors and employees previously trained on another facility? (i) Trained employees or contractors transferred from another facility must attend a supplemental briefing on your H2S equipment and procedures before beginning duty at your facility; (ii) Visitors who will remain on your facility more than 24 hours must receive the training required for employees by paragraph (g)(4) of this section; and (iii) Visitors who will depart before spending 24 hours on the facility are exempt from the training required for employees, but they must, upon arrival, complete a briefing that includes: (A) Information on the location and use of an assigned respirator; practice in donning and adjusting the assigned respirator; information on the safe briefing areas, alarm system, and hazards of H2S and SO2; and (B) Instructions on their responsibilities in the event of an H2S release. (4) What training must I provide to all other employees? You must train all individuals on your facility on the: (i) Hazards of H2S and of SO2 and the provisions for personnel safety contained in the H2S Contingency Plan; (ii) Proper use of safety equipment which the employee may be required to use; (iii) Location of protective breathing equipment, H2S detectors and alarms, ventilation equipment, briefing areas, warning systems, evacuation procedures, and the direction of prevailing winds; (iv) Restrictions and corrective measures concerning beards, spectacles, and contact lenses in conformance with ANSI Z88.2, American National Standard for Respiratory Protection (as specified in § 250.198); (v) Basic first-aid procedures applicable to victims of H2S exposure. During all drills and training sessions, you must address procedures for rescue and first aid for H2S victims; (vi) Location of: (A) The first-aid kit on the facility; (B) Resuscitators; and (C) Litter or other device on the facility. (vii) Meaning of all warning signals. (5) Do I need to post safety information? You must prominently post safety information on the facility and on vessels serving the facility (i.e., basic first-aid, escape routes, instructions for use of life boats, etc.). (h) Drills—(1) When and how often do I need to conduct drills on H2S safety discussions on the facility? You must: (i) Conduct a drill for each person at the facility during normal duty hours at least once every 7-day period. The drills must consist of a dry-run performance of personnel activities related to assigned jobs. (ii) At a safety meeting or other meetings of all personnel, discuss drill performance, new H2S considerations at the facility, and other updated H2S information at least monthly. (2) What documentation do I need? You must keep records of attendance for: (i) Drilling, well-completion, and well-workover operations at the facility until operations are completed; and (ii) Production operations at the facility or at the nearest field office for 1 year. (i) Visual and audible warning systems: (1) How must I install wind direction equipment? You must install wind-direction equipment in a location visible at all times to individuals on or in the immediate vicinity of the facility. (2) When do I need to display operational danger signs, display flags, or activate visual or audible alarms? (i) You must display warning signs at all times on facilities with wells capable of producing H2S and on facilities that process gas containing H2S in concentrations of 20 ppm or more. (ii) In addition to the signs, you must activate audible alarms and display flags or activate flashing red lights when atmospheric concentration of H2S reaches 20 ppm. (3) What are the requirements for signs? Each sign must be a high-visibility yellow color with black lettering as follows: (4) May I use existing signs? You may use existing signs containing the words “Danger-Hydrogen Sulfide-H2S,” provided the words “Poisonous Gas. Do Not Approach if Red Flag is Flying” or “Red Lights are Flashing” in lettering of a minimum of 7 inches in height are displayed on a sign immediately adjacent to the existing sign. (5) What are the requirements for flashing lights or flags? You must activate a sufficient number of lights or hoist a sufficient number of flags to be visible to vessels and aircraft. Each light must be of sufficient intensity to be seen by approaching vessels or aircraft any time it is activated (day or night). Each flag must be red, rectangular, a minimum width of 3 feet, and a minimum height of 2 feet. (6) What is an audible warning system? An audible warning system is a public address system or siren, horn, or other similar warning device with a unique sound used only for H2S. (7) Are there any other requirements for visual or audible warning devices? Yes, you must: (i) Illuminate all signs and flags at night and under conditions of poor visibility; and (ii) Use warning devices that are suitable for the electrical classification of the area. (8) What actions must I take when the alarms are activated? When the warning devices are activated, the designated responsible persons must inform personnel of the level of danger and issue instructions on the initiation of appropriate protective measures. (j) H2S-detection and H2S monitoring equipment: (1) What are the requirements for an H2S detection system? An H2S detection system must: (i) Be capable of sensing a minimum of 10 ppm of H2S in the atmosphere; and (ii) Activate audible and visual alarms when the concentration of H2S in the atmosphere reaches 20 ppm. (2) Where must I have sensors for drilling, well-completion, and well-workover operations? You must locate sensors at the: (i) Bell nipple; (ii) Mud-return line receiver tank (possum belly); (iii) Pipe-trip tank; (iv) Shale shaker; (v) Well-control fluid pit area; (vi) Driller's station; (vii) Living quarters; and (viii) All other areas where H2S may accumulate. (3) Do I need mud sensors? The District Manager may require mud sensors in the possum belly in cases where the ambient air sensors in the mud-return system do not consistently detect the presence of H2S. (4) How often must I observe the sensors? During drilling, well-completion and well-workover operations, you must continuously observe the H2S levels indicated by the monitors in the work areas during the following operations: (i) When you pull a wet string of drill pipe or workover string; (ii) When circulating bottoms-up after a drilling break; (iii) During cementing operations; (iv) During logging operations; and (v) When circulating to condition mud or other well-control fluid. (5) Where must I have sensors for production operations? On a platform where gas containing H2S of 20 ppm or greater is produced, processed, or otherwise handled: (i) You must have a sensor in rooms, buildings, deck areas, or low-laying deck areas not otherwise covered by paragraph (j)(2) of this section, where atmospheric concentrations of H2S could reach 20 ppm or more. You must have at least one sensor per 400 square feet of deck area or fractional part of 400 square feet; (ii) You must have a sensor in buildings where personnel have their living quarters; (iii) You must have a sensor within 10 feet of each vessel, compressor, wellhead, manifold, or pump, which could release enough H2S to result in atmospheric concentrations of 20 ppm at a distance of 10 feet from the component; (iv) You may use one sensor to detect H2S around multiple pieces of equipment, provided the sensor is located no more than 10 feet from each piece, except that you need to use at least two sensors to monitor compressors exceeding 50 horsepower; (v) You do not need to have sensors near wells that are shut in at the master valve and sealed closed; (vi) When you determine where to place sensors, you must consider: (A) The location of system fittings, flanges, valves, and other devices subject to leaks to the atmosphere; and (B) Design factors, such as the type of decking and the location of fire walls; and (vii) The District Manager may require additional sensors or other monitoring capabilities, if warranted by site specific conditions. (6) How must I functionally test the H2S Detectors? (i) Personnel trained to calibrate the particular H2S detector equipment being used must test detectors by exposing them to a known concentration in the range of 10 to 30 ppm of H2S. (ii) If the results of any functional test are not within 2 ppm or 10 percent, whichever is greater, of the applied concentration, recalibrate the instrument. (7) How often must I test my detectors? (i) When conducting drilling, drill stem testing, well-completion, or well-workover operations in areas classified as H2S present or H2S unknown, test all detectors at least once every 24 hours. When drilling, begin functional testing before the bit is 1,500 feet (vertically) above the potential H2S zone. (ii) When conducting production operations, test all detectors at least every 14 days between tests. (iii) If equipment requires calibration as a result of two consecutive functional tests, the District Manager may require that H2S-detection and H2S-monitoring equipment be functionally tested and calibrated more frequently. (8) What documentation must I keep? (i) You must maintain records of testing and calibrations (in the drilling or production operations report, as applicable) at the facility to show the present status and history of each device, including dates and details concerning: (A) Installation; (B) Removal; (C) Inspection; (D) Repairs; (E) Adjustments; and (F) Reinstallation. (ii) Records must be available for inspection by BSEE personnel. (9) What are the requirements for nearby vessels? If vessels are stationed overnight alongside facilities in areas of H2S present or H2S unknown, you must equip vessels with an H2S-detection system that activates audible and visual alarms when the concentration of H2S in the atmosphere reaches 20 ppm. This requirement does not apply to vessels positioned upwind and at a safe distance from the facility in accordance with the positioning procedure described in the approved H2S Contingency Plan. (10) What are the requirements for nearby facilities? The District Manager may require you to equip nearby facilities with portable or fixed H2S detector(s) and to test and calibrate those detectors. To invoke this requirement, the District Manager will consider dispersion modeling results from a possible release to determine if 20 ppm H2S concentration levels could be exceeded at nearby facilities. (11) What must I do to protect against SO2 if I burn gas containing H2S? You must: (i) Monitor the SO2concentration in the air with portable or strategically placed fixed devices capable of detecting a minimum of 2 ppm of SO2; (ii) Take readings at least hourly and at any time personnel detect SO2 odor or nasal irritation; (iii) Implement the personnel protective measures specified in the H2S Contingency Plan if the SO2 concentration in the work area reaches 2 ppm; and (iv) Calibrate devices every 3 months if you use fixed or portable electronic sensing devices to detect SO2. (12) May I use alternative measures? You may follow alternative measures instead of those in paragraph (j)(11) of this section if you propose and the Regional Supervisor approves the alternative measures. (13) What are the requirements for protective-breathing equipment? In an area classified as H2S present or H2S unknown, you must: (i) Provide all personnel, including contractors and visitors on a facility, with immediate access to self-contained pressure-demand-type respirators with hoseline capability and breathing time of at least 15 minutes. (ii) Design, select, use, and maintain respirators in conformance with ANSI Z88.2 (as specified in § 250.198). (iii) Make available at least two voice-transmission devices, which can be used while wearing a respirator, for use by designated personnel. (iv) Make spectacle kits available as needed. (v) Store protective-breathing equipment in a location that is quickly and easily accessible to all personnel. (vi) Label all breathing-air bottles as containing breathing-quality air for human use. (vii) Ensure that vessels attendant to facilities carry appropriate protective-breathing equipment for each crew member. The District Manager may require additional protective-breathing equipment on certain vessels attendant to the facility. (viii) During H2S alerts, limit helicopter flights to and from facilities to the conditions specified in the H2S Contingency Plan. During authorized flights, the flight crew and passengers must use pressure-demand-type respirators. You must train all members of flight crews in the use of the particular type(s) of respirator equipment made available. (ix) As appropriate to the particular operation(s), (production, drilling, well-completion or well-workover operations, or any combination of them), provide a system of breathing-air manifolds, hoses, and masks at the facility and the briefing areas. You must provide a cascade air-bottle system for the breathing-air manifolds to refill individual protective-breathing apparatus bottles. The cascade air-bottle system may be recharged by a high-pressure compressor suitable for providing breathing-quality air, provided the compressor suction is located in an uncontaminated atmosphere. (k) Personnel safety equipment: (1) What additional personnel-safety equipment do I need? You must ensure that your facility has: (i) Portable H2S detectors capable of detecting a 10 ppm concentration of H2S in the air available for use by all personnel; (ii) Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated areas; (iii) Chalkboards and/or note pads for communication purposes located on the rig floor, shale-shaker area, the cement-pump rooms, well-bay areas, production processing equipment area, gas compressor area, and pipeline-pump area; (iv) Bull horns and flashing lights; and (v) At least three resuscitators on manned facilities, and a number equal to the personnel on board, not to exceed three, on normally unmanned facilities, complete with face masks, oxygen bottles, and spare oxygen bottles. (2) What are the requirements for ventilation equipment? You must: (i) Use only explosion-proof ventilation devices; (ii) Install ventilation devices in areas where H2S or SO2 may accumulate; and (iii) Provide movable ventilation devices in work areas. The movable ventilation devices must be multidirectional and capable of dispersing H2S or SO2 vapors away from working personnel. (3) What other personnel safety equipment do I need? You must have the following equipment readily available on each facility: (i) A first-aid kit of appropriate size and content for the number of personnel on the facility; and (ii) At least one litter or an equivalent device. (l) Do I need to notify BSEE in the event of an H2S release? You must notify BSEE without delay in the event of a gas release which results in a 15-minute time-weighted average atmospheric concentration of H2S of 20 ppm or more anywhere on the OCS facility. You must report these gas releases to the District Manager immediately by oral communication, with a written follow-up report within 15 days, pursuant to §§ 250.188 through 250.190. (m) Do I need to use special drilling, completion and workover fluids or procedures? When working in an area classified as H2S present or H2S unknown: (1) You may use either water- or oil-base muds in accordance with § 250.300(b)(1). (2) If you use water-base well-control fluids, and if ambient air sensors detect H2S, you must immediately conduct either the Garrett-Gas-Train test or a comparable test for soluble sulfides to confirm the presence of H2S. (3) If the concentration detected by air sensors in over 20 ppm, personnel conducting the tests must don protective-breathing equipment conforming to paragraph (j)(13) of this section. (4) You must maintain on the facility sufficient quantities of additives for the control of H2S, well-control fluid pH, and corrosion equipment. (i) Scavengers. You must have scavengers for control of H2S available on the facility. When H2S is detected, you must add scavengers as needed. You must suspend drilling until the scavenger is circulated throughout the system. (ii) Control pH. You must add additives for the control of pH to water-base well-control fluids in sufficient quantities to maintain pH of at least 10.0. (iii) Corrosion inhibitors. You must add additives to the well-control fluid system as needed for the control of corrosion. (5) You must degas well-control fluids containing H2S at the optimum location for the particular facility. You must collect the gases removed and burn them in a closed flare system conforming to paragraph (q)(6) of this section. (n) What must I do in the event of a kick? In the event of a kick, you must use one of the following alternatives to dispose of the well-influx fluids giving consideration to personnel safety, possible environmental damage, and possible facility well-equipment damage: (1) Contain the well-fluid influx by shutting in the well and pumping the fluids back into the formation. (2) Control the kick by using appropriate well-control techniques to prevent formation fracturing in an open hole within the pressure limits of the well equipment (drill pipe, work string, casing, wellhead, BOP system, and related equipment). The disposal of H2S and other gases must be through pressurized or atmospheric mud-separator equipment depending on volume, pressure and concentration of H2S. The equipment must be designed to recover well-control fluids and burn the gases separated from the well-control fluid. The well-control fluid must be treated to neutralize H2S and restore and maintain the proper quality. (o) Well testing in a zone known to contain H2S. When testing a well in a zone with H2S present, you must do all of the following: (1) Before starting a well test, conduct safety meetings for all personnel who will be on the facility during the test. At the meetings, emphasize the use of protective-breathing equipment, first-aid procedures, and the Contingency Plan. Only competent personnel who are trained and are knowledgeable of the hazardous effects of H2S must be engaged in these tests. (2) Perform well testing with the minimum number of personnel in the immediate vicinity of the rig floor and with the appropriate test equipment to safely and adequately perform the test. During the test, you must continuously monitor H2S levels. (3) Not burn produced gases except through a flare which meets the requirements of paragraph (q)(6) of this section. Before flaring gas containing H2S, you must activate SO2 monitoring equipment in accordance with paragraph (j)(11) of this section. If you detect SO2 in excess of 2 ppm, you must implement the personnel protective measures in your H2S Contingency Plan, required by paragraph (f) of this section. You must also follow the requirements of § 250.1164. You must pipe gases from stored test fluids into the flare outlet and burn them. (4) Use downhole test tools and wellhead equipment suitable for H2S service. (5) Use tubulars suitable for H2S service. You must not use drill pipe for well testing without the prior approval of the District Manager. Water cushions must be thoroughly inhibited in order to prevent H2S attack on metals. You must flush the test string fluid treated for this purpose after completion of the test. (6) Use surface test units and related equipment that is designed for H2S service. (p) Metallurgical properties of equipment. When operating in a zone with H2S present or when the concentration of H2S in the produced fluid may exceed 0.05 psi partial pressure of H2S, you must use equipment that is constructed of materials with metallurgical properties that resist or prevent sulfide stress cracking (also known as hydrogen embrittlement, stress corrosion cracking, or H2S embrittlement), chloride-stress cracking, hydrogen-induced cracking, and other failure modes. You must do all of the following: (1) Use tubulars and other equipment, casing, tubing, drill pipe, couplings, flanges, and related equipment that is designed for H2S service. (2) Use BOP system components, wellhead, pressure-control equipment, and related equipment exposed to H2S-bearing fluids in conformance with NACE Standard MR0175-03 (as specified in § 250.198). (3) Use temporary downhole well-security devices such as retrievable packers and bridge plugs that are designed for H2S service. (4) When producing in zones bearing H2S, use equipment constructed of materials capable of resisting or preventing sulfide stress cracking. (5) Keep the use of welding to a minimum during the installation or modification of a production facility. Welding must be done in a manner that ensures resistance to sulfide stress cracking. (q) General requirements when operating in an H2S zone: (1) Coring operations. When you conduct coring operations in H2S-bearing zones, all personnel in the working area must wear protective-breathing equipment at least 10 stands in advance of retrieving the core barrel. Cores to be transported must be sealed and marked for the presence of H2S. (2) Logging operations. You must treat and condition well-control fluid in use for logging operations to minimize the effects of H2S on the logging equipment. (3) Stripping operations. Personnel must monitor displaced well-control fluid returns and wear protective-breathing equipment in the working area when the atmospheric concentration of H2S reaches 20 ppm or if the well is under pressure. (4) Gas-cut well-control fluid or well kick from H2S-bearing zone. If you decide to circulate out a kick, personnel in the working area during bottoms-up and extended-kill operations must wear protective-breathing equipment. (5) Drill- and workover-string design and precautions. Drill- and workover-strings must be designed consistent with the anticipated depth, conditions of the hole, and reservoir environment to be encountered. You must minimize exposure of the drill- or workover-string to high stresses as much as practical and consistent with well conditions. Proper handling techniques must be taken to minimize notching and stress concentrations. Precautions must be taken to minimize stresses caused by doglegs, improper stiffness ratios, improper torque, whip, abrasive wear on tool joints, and joint imbalance. (6) Flare system. The flare outlet must be of a diameter that allows easy nonrestricted flow of gas. You must locate flare line outlets on the downside of the facility and as far from the facility as is feasible, taking into account the prevailing wind directions, the wake effects caused by the facility and adjacent structure(s), and the height of all such facilities and structures. You must equip the flare outlet with an automatic ignition system including a pilot-light gas source or an equivalent system. You must have alternate methods for igniting the flare. You must pipe to the flare system used for H2S all vents from production process equipment, tanks, relief valves, burst plates, and similar devices. (7) Corrosion mitigation. You must use effective means of monitoring and controlling corrosion caused by acid gases (H2S and CO2) in both the downhole and surface portions of a production system. You must take specific corrosion monitoring and mitigating measures in areas of unusually severe corrosion where accumulation of water and/or higher concentration of H2S exists. (8) Wireline lubricators. Lubricators which may be exposed to fluids containing H2S must be of H2S-resistant materials. (9) Fuel and/or instrument gas. You must not use gas containing H2S for instrument gas. You must not use gas containing H2S for fuel gas without the prior approval of the District Manager. (10) Sensing lines and devices. Metals used for sensing line and safety-control devices which are necessarily exposed to H2S-bearing fluids must be constructed of H2S-corrosion resistant materials or coated so as to resist H2S corrosion. (11) Elastomer seals. You must use H2S-resistant materials for all seals which may be exposed to fluids containing H2S. (12) Water disposal. If you dispose of produced water by means other than subsurface injection, you must submit to the District Manager an analysis of the anticipated H2S content of the water at the final treatment vessel and at the discharge point. The District Manager may require that the water be treated for removal of H2S. The District Manager may require the submittal of an updated analysis if the water disposal rate or the potential H2S content increases. (13) Deck drains. You must equip open deck drains with traps or similar devices to prevent the escape of H2S gas into the atmosphere. (14) Sealed voids. You must take precautions to eliminate sealed spaces in piping designs (e.g., slip-on flanges, reinforcing pads) which can be invaded by atomic hydrogen when H2S is present.

§ 250.500 General requirements. Well-completion operations must be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS, including any mineral deposits (in areas leased and not leased), the National security or defense, or the marine, coastal, or human environment. In addition to the requirements of this subpart, you must also follow the applicable requirements of subpart G of this part.

§ 250.501 Definition. When used in this subpart, the following term shall have the meaning given below: Well-completion operations means the work conducted to establish the production of a well after the production-casing string has been set, cemented, and pressure-tested.

§ 250.502 [Reserved]

§ 250.503 Emergency shutdown system. When well-completion operations are conducted on a platform where there are other hydrocarbon-producing wells or other hydrocarbon flow, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station.

§ 250.504 Hydrogen sulfide. When a well-completion operation is conducted in zones known to contain hydrogen sulfide (H2S) or in zones where the presence of H2S is unknown (as defined in § 250.490 of this part), the lessee shall take appropriate precautions to protect life and property on the platform or completion unit, including, but not limited to operations such as blowing the well down, dismantling wellhead equipment and flow lines, circulating the well, swabbing, and pulling tubing, pumps, and packers. The lessee shall comply with the requirements in § 250.490 of this part as well as the appropriate requirements of this subpart.

§ 250.505 Subsea completions. No subsea well completion shall be commenced until the lessee obtains written approval from the District Manager in accordance with § 250.513 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will adequately control the well and permit safe production operations.

§§ 250.506-250.508 [Reserved]

§ 250.509 Well-completion structures on fixed platforms. Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the proposed operations. Prior to moving a well-completion rig or equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of platform, and previous stresses to the platform.

§ 250.510 Diesel engine air intakes. Diesel engine air intakes must be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines that are continuously attended must be equipped with either remote operated manual or automatic-shutdown devices. Diesel engines that are not continuously attended must be equipped with automatic-shutdown devices.

§ 250.511 Traveling-block safety device. All units being used for well-completion operations that have both a traveling block and a crown block must be equipped with a safety device that is designed to prevent the traveling block from striking the crown block. The device must be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check must be entered in the operations log.

§ 250.512 Field well-completion rules. When geological and engineering information available in a field enables the District Manager to determine specific operating requirements, field well-completion rules may be established on the District Manager's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-completion rules have been established, well-completion operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-completion rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.

§ 250.513 Approval and reporting of well-completion operations. (a) No well-completion operation may begin until the lessee receives written approval from the District Manager. If completion is planned and the data are available at the time you submit the Application for Permit to Drill and Supplemental APD Information Sheet (Forms BSEE-0123 and BSEE-0123S), you may request approval for a well-completion on those forms (see §§ 250.410 through 250.418 of this part). If the District Manager has not approved the completion or if the completion objective or plans have significantly changed, you must submit an Application for Permit to Modify (Form BSEE-0124) for approval of such operations. (b) You must submit the following with Form BSEE-0124 (or with Form BSEE-0123; Form BSEE-0123S): (1) A brief description of the well-completion procedures to be followed, a statement of the expected surface pressure, and type and weight of completion fluids; (2) A schematic drawing of the well showing the proposed producing zone(s) and the subsurface well-completion equipment to be used; (3) For multiple completions, a partial electric log showing the zones proposed for completion, if logs have not been previously submitted; (4) All applicable information required in § 250.731. (5) When the well-completion is in a zone known to contain H2S or a zone where the presence of H2S is unknown, information pursuant to § 250.490 of this part; and (6) Payment of the service fee listed in § 250.125. (c) Within 30 days after completion, you must submit to the District Manager an End of Operations Report (Form BSEE-0125), including a schematic of the tubing and subsurface equipment. (d) You must submit public information copies of Form BSEE-0125 according to § 250.186.

§ 250.514 Well-control fluids, equipment, and operations. (a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-completion operations and shall not be left unattended at any time unless the well is shut in and secured. (b) The following well-control-fluid equipment shall be installed, maintained, and utilized: (1) A fill-up line above the uppermost BOP; (2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and (3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device. (c) When coming out of the hole with drill pipe, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hole shall be utilized.

§§ 250.515-250.517 [Reserved]

§ 250.518 Tubing and wellhead equipment. (a) No tubing string may be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use. (1) The tubing string must be evaluated for burst, collapse, and axial loads with appropriate safety factors and material design factors for the pressure and temperature environments of the completion, production, shut-in, and injection load cases. (2) The tubing string materials must be appropriate for the environment. You must follow NACE Standard MR0175-2003 (incorporated by reference, see § 250.198) when H2S concentration may equal or exceed 0.05 psi partial pressure. (3) The tubing string threaded connectors must be appropriate for the loads identified in paragraph (a)(1) of this section. (b) When the tree is installed, you must equip wells to monitor for casing pressure according to the following chart: * Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing hanger, and a surface christmas tree. (c) You must design and test the wellhead, tree, and related equipment in accordance with API Specification 6A (incorporated by reference, see § 250.198) or API Specification 17D (incorporated by reference, see § 250.198), as applicable. The wellhead, tree, and related equipment must have a pressure rating greater than the maximum anticipated surface pressure and must be designed, installed, operated, maintained, and tested to achieve and maintain pressure containment and pressure control. (1) Newly completed dry trees (e.g., fixed, hybrid, or mudline suspension) for production or injection wells must be equipped with a minimum of one master valve and one surface safety valve (SSV), installed above the master valve, in the vertical run of the tree. (2) Newly completed subsea production or injection wells must be equipped with a minimum of one USV installed in the horizontal or vertical run of the tree (e.g., vertical or horizontal subsea trees). (3) Newly completed wells with a mudline suspension conversion to a subsea tree must have a minimum of two casing strings tied back and sealed below the tubing head. At a minimum, the production casing and the next outer casing must be tied back to the wellhead, to ensure annular isolation. (d) You must install, maintain, and test surface and subsurface safety equipment in accordance with the applicable requirements in subpart H of this part. (e) When installed, packers and bridge plugs must meet the following: (1) The uppermost permanently installed packer and all permanently installed bridge plugs qualified as mechanical barriers must comply with ANSI/API Specification 11D1 (incorporated by reference, see § 250.198); (2) The production packer must be set at a depth that will allow for a column of weighted fluids to be placed above the packer that will exert a hydrostatic force greater than or equal to the force created by the reservoir pressure below the packer; (3) The production packer must be set as close as practically possible to the perforated interval; and (4) The production packer must be set at a depth that is within the cemented interval of the selected casing section. (f) Your APM must include a description and calculations for how you determined the production packer setting depth. (g) You must have two independent barriers, one being mechanical, in the exposed center wellbore prior to removing the tree and/or well control equipment.

§ 250.519 What are the requirements for casing pressure management? Once you install your wellhead, you must meet the casing pressure management requirements of API Recommended Practice 90 (incorporated by reference, see § 250.198) and the requirements of §§ 250.519 through 250.531. If there is a conflict between API Recommended Practice 90 and the casing pressure requirements of this subpart, you must follow the requirements of this subpart.

§ 250.520 How often do I have to monitor for casing pressure? You must monitor for casing pressure in your well according to the following table:

§ 250.521 When do I have to perform a casing diagnostic test? (a) You must perform a casing diagnostic test within 30 days after first observing or imposing casing pressure according to the following table: (b) You are exempt from performing a diagnostic pressure test for the production casing on a well operating under active gas lift.

§ 250.522 How do I manage the thermal effects caused by initial production on a newly completed or recompleted well? A newly completed or recompleted well often has thermal casing pressure during initial startup. Bleeding casing pressure during the startup process is considered a normal and necessary operation to manage thermal casing pressure; therefore, you do not need to evaluate these operations as a casing diagnostic test. After 30 days of continuous production, the initial production startup operation is complete and you must perform casing diagnostic testing as required in §§ 250.521 and 250.523.

§ 250.523 When do I have to repeat casing diagnostic testing? Casing diagnostic testing must be repeated according to the following table:

§ 250.524 How long do I keep records of casing pressure and diagnostic tests? Records of casing pressure and diagnostic tests must be kept at the field office nearest the well for a minimum of 2 years. The last casing diagnostic test for each casing or riser must be retained at the field office nearest the well until the well is abandoned.

§ 250.525 When am I required to take action from my casing diagnostic test? You must take action if you have any of the following conditions: (a) Any fixed platform well with a casing pressure exceeding its maximum allowable wellhead operating pressure (MAWOP); (b) Any fixed platform well with a casing pressure that is greater than 100 psig and that cannot bleed to 0 psig through a 1/2-inch needle valve within 24 hours, or is not bled to 0 psig during a casing diagnostic test; (c) Any well that has demonstrated tubing/casing, tubing/riser, casing/casing, riser/casing, or riser/riser communication; (d) Any well that has sustained casing pressure (SCP) and is bled down to prevent it from exceeding its MAWOP, except during initial startup operations described in § 250.522; (e) Any hybrid well with casing or riser pressure exceeding 100 psig; or (f) Any subsea well with a casing pressure 100 psig greater than the external hydrostatic pressure at the subsea wellhead.

§ 250.526 What do I submit if my casing diagnostic test requires action? Within 14 days after you perform a casing diagnostic test requiring action under § 250.525:

§ 250.527 What must I include in my notification of corrective action? The following information must be included in the notification of corrective action: (a) Lessee or Operator name; (b) Area name and OCS block number; (c) Well name and API number; and (d) Casing diagnostic test data.

§ 250.528 What must I include in my casing pressure request? The following information must be included in the casing pressure request: (a) API number; (b) Lease number; (c) Area name and OCS block number; (d) Well number; (e) Company name and mailing address; (f) All casing, riser, and tubing sizes, weights, grades, and MIYP; (g) All casing/riser calculated MAWOPs; (h) All casing/riser pre-bleed down pressures; (i) Shut-in tubing pressure; (j) Flowing tubing pressure; (k) Date and the calculated daily production rate during last well test (oil, gas, basic sediment, and water); (l) Well status (shut-in, temporarily abandoned, producing, injecting, or gas lift); (m) Well type (dry tree, hybrid, or subsea); (n) Date of diagnostic test; (o) Well schematic; (p) Water depth; (q) Volumes and types of fluid bled from each casing or riser evaluated; (r) Type of diagnostic test performed: (1) Bleed down/buildup test; (2) Shut-in the well and monitor the pressure drop test; (3) Constant production rate and decrease the annular pressure test; (4) Constant production rate and increase the annular pressure test; (5) Change the production rate and monitor the casing pressure test; and (6) Casing pressure and tubing pressure history plot; (s) The casing diagnostic test data for all casing exceeding 100 psig; (t) Associated shoe strengths for casing shoes exposed to annular fluids; (u) Concentration of any H2S that may be present; (v) Whether the structure on which the well is located is manned or unmanned; (w) Additional comments; and (x) Request date.

§ 250.529 What are the terms of my casing pressure request? Casing pressure requests are approved by the Regional Supervisor, Field Operations, for a term to be determined by the Regional Supervisor on a case-by-case basis. The Regional Supervisor may impose additional restrictions or requirements to allow continued operation of the well.

§ 250.530 What if my casing pressure request is denied? (a) If your casing pressure request is denied, then the operating company must submit plans for corrective action to the respective District Manager within 30 days of receiving the denial. The District Manager will establish a specific time period in which this corrective action will be taken. You must notify the respective District Manager within 30 days after completion of your corrected action. (b) You must submit the casing diagnostic test data to the appropriate Regional Supervisor, Field Operations, within 14 days of completion of the diagnostic test required under § 250.523(e).

§ 250.531 When does my casing pressure request approval become invalid? A casing pressure request becomes invalid when: (a) The casing or riser pressure increases by 200 psig over the approved casing pressure request pressure; (b) The approved term ends; (c) The well is worked-over, side-tracked, redrilled, recompleted, or acid stimulated; (d) A different casing or riser on the same well requires a casing pressure request; or (e) A well has more than one casing operating under a casing pressure request and one of the casing pressure requests become invalid, then all casing pressure requests for that well become invalid.

§ 250.600 General requirements. Well-workover operations must be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the Outer Continental Shelf (OCS) including any mineral deposits (in areas leased and not leased), the National security or defense, or the marine, coastal, or human environment. In addition to the requirements of this subpart, you must also follow the applicable requirements of subpart G of this part.

§ 250.601 Definitions. When used in this subpart, the following terms shall have the meanings given below: Expected surface pressure means the highest pressure predicted to be exerted upon the surface of a well. In calculating expected surface pressure, you must consider reservoir pressure as well as applied surface pressure. Routine operations mean any of the following operations conducted on a well with the tree installed: (a) Cutting paraffin; (b) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves which can be removed by wireline operations; (c) Bailing sand; (d) Pressure surveys; (e) Swabbing; (f) Scale or corrosion treatment; (g) Caliper and gauge surveys; (h) Corrosion inhibitor treatment; (i) Removing or replacing subsurface pumps; (j) Through-tubing logging (diagnostics); (k) Wireline fishing; and (l) Setting and retrieving other subsurface flow-control devices. (m) Acid treatments. Workover operations mean the work conducted on wells after the initial completion for the purpose of maintaining or restoring the productivity of a well.

§ 250.602 [Reserved]

§ 250.603 Emergency shutdown system. When well-workover operations are conducted on a well with the tree removed, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station, except when there is no other hydrocarbon-producing well or other hydrocarbon flow on the platform.

§ 250.604 Hydrogen sulfide. When a well-workover operation is conducted in zones known to contain hydrogen sulfide (H2S) or in zones where the presence of H2S is unknown (as defined in § 250.490 of this part), the lessee shall take appropriate precautions to protect life and property on the platform or rig, including but not limited to operations such as blowing the well down, dismantling wellhead equipment and flow lines, circulating the well, swabbing, and pulling tubing, pumps and packers. The lessee shall comply with the requirements in § 250.490 of this part as well as the appropriate requirements of this subpart.

§ 250.605 Subsea workovers. No subsea well-workover operation including routine operations shall be commenced until the lessee obtains written approval from the District Manager in accordance with § 250.613 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will maintain adequate control of the well and permit continued safe production operations.

§§ 250.606-250.608 [Reserved]

§ 250.609 Well-workover structures on fixed platforms. Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the operations proposed. Prior to moving a well-workover rig or well-servicing equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of the platform, and previous stresses to the platform.

§ 250.610 Diesel engine air intakes. You must equip diesel engine air intakes with a device to shut down the diesel engine in the event of runaway. Diesel engines that are continuously attended must be equipped with remotely operated, manual, or automatic shutdown devices. Diesel engines that are not continuously attended must be equipped with automatic shutdown devices.

§ 250.611 Traveling-block safety device. You must equip all units being used for well-workover operations that have both a traveling block and a crown block with a safety device that is designed to prevent the traveling block from striking the crown block. You must check the device for proper operation weekly and after each drill-line slipping operation. You must enter the results of the operational check in the operations log.

§ 250.612 Field well-workover rules. When geological and engineering information available in a field enables the District Manager to determine specific operating requirements, field well-workover rules may be established on the District Manager's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-workover rules have been established, well-workover operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-workover rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.

§ 250.613 Approval and reporting for well-workover operations. (a) No well-workover operation except routine ones, as defined in § 250.601 of this part, shall begin until the lessee receives written approval from the District Manager. Approval for these operations must be requested on Form BSEE-0124, Application for Permit to Modify. (b) You must submit the following with Form BSEE-0124: (1) A brief description of the well-workover procedures to be followed, a statement of the expected surface pressure, and type and weight of workover fluids; (2) When changes in existing subsurface equipment are proposed, a schematic drawing of the well showing the zone proposed for workover and the workover equipment to be used; (3) All information required in § 250.731. (4) Where the well-workover is in a zone known to contain H2S or a zone where the presence of H2S is unknown, information pursuant to § 250.490 of this part; and (5) Payment of the service fee listed in § 250.125. (c) The following additional information shall be submitted with Form BSEE-0124 if completing to a new zone is proposed: (1) Reason for abandonment of present producing zone including supportive well test data, and (2) A statement of anticipated or known pressure data for the new zone. (d) Within 30 days after completing the well-workover operation, except routine operations, Form BSEE-0124, Application for Permit to Modify, shall be submitted to the District Manager, showing the work as performed. In the case of a well-workover operation resulting in the initial recompletion of a well into a new zone, a Form BSEE-0125, End of Operations Report, shall be submitted to the District Manager and shall include a new schematic of the tubing subsurface equipment if any subsurface equipment has been changed.

§ 250.614 Well-control fluids, equipment, and operations. The following requirements apply during all well-workover operations with the tree removed: (a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-workover operations and shall not be left unattended at anytime unless the well is shut in and secured. (b) When coming out of the hole with drill pipe or a workover string, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe or workover string, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe or workover string and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hold shall be utilized. (c) The following well-control-fluid equipment shall be installed, maintained, and utilized: (1) A fill-up line above the uppermost BOP; (2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and (3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.

§§ 250.615-250.618 [Reserved]

§ 250.619 Tubing and wellhead equipment. The lessee shall comply with the following requirements during well-workover operations with the tree removed: (a) No tubing string may be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use. (1) The tubing string must be evaluated for burst, collapse, and axial loads with appropriate safety factors and material design factors for the pressure and temperature environments of the completion, production, shut-in, and injection load cases. (2) The tubing string materials must be appropriate for the environment. You must follow NACE Standard MR0175-2003 (incorporated by reference, see § 250.198) when H2S concentration may equal or exceed 0.05 psi partial pressure. (3) The tubing string threaded connectors must be appropriate for the loading identified in paragraph (a)(1) of this section. (b) When reinstalling the tree, you must: (1) Equip wells to monitor for casing pressure according to the following chart: * Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing hanger, and a surface christmas tree. (2) Follow the casing pressure management requirements in subpart E of this part. (c) You must design and test the wellhead, tree, and related equipment in accordance with API Specification 6A (incorporated by reference in § 250.198) or API Specification 17D (incorporated by reference, see § 250.198), as applicable. The wellhead, tree, and related equipment must have a pressure rating greater than the shut-in tubing pressure and must be designed, installed, operated, maintained, and tested so as to achieve and maintain pressure containment and pressure control. (1) Dry trees (e.g., fixed, hybrid, or mudline suspension) for production or injection wells must be equipped with a minimum of one master valve and one surface safety valve (SSV), installed above the master valve, in the vertical run of the tree. (2) Subsea production or injection wells must be equipped with a minimum of one USV installed in the horizontal or vertical run of the tree (for vertical or horizontal subsea trees). (3) Wells with a mudline suspension conversion to a subsea tree must have a minimum of two casing strings tied back and sealed below the tubing head. At minimum, the production casing and the next outer casing must be tied back to the wellhead, to ensure annular isolation. (d) You must install, maintain, and test surface and subsurface safety equipment in accordance with the applicable requirements in subpart H of this part. (e) If you pull and reinstall packers and bridge plugs, you must meet the following requirements: (1) The uppermost permanently installed packer and all permanently installed bridge plugs qualified as mechanical barriers must comply with ANSI/API Specification 11D1 (incorporated by reference, see § 250.198). (2) The production packer must be set at a depth that will allow for a column of weighted fluids to be placed above the packer that will exert a hydrostatic force greater than or equal to the force created by the reservoir pressure below the packer; (3) The production packer must be set as close as practically possible to the perforated interval; and (4) The production packer must be set at a depth that is within the cemented interval of the selected casing section. (f) Your APM must include a description and calculations for how you determined the production packer setting depth. (g) You must have two independent barriers, one being mechanical, in the exposed center wellbore prior to removing the tree and/or well control equipment.

§ 250.620 Wireline operations. The lessee shall comply with the following requirements during routine, as defined in § 250.601 of this part, and nonroutine wireline workover operations: (a) Wireline operations shall be conducted so as to minimize leakage of well fluids. Any leakage that does occur shall be contained to prevent pollution. (b) All wireline perforating operations and all other wireline operations where communication exists between the completed hydrocarbon-bearing zone(s) and the wellbore shall use a lubricator assembly containing at least one wireline valve. (c) When the lubricator is initially installed on the well, it shall be successfully pressure tested to the expected shut-in surface pressure.

§ 250.700 What operations and equipment does this subpart cover? This subpart covers operations and equipment associated with drilling, completion, workover, and decommissioning activities. This subpart includes regulations applicable to drilling, completion, workover, and decommissioning activities in addition to applicable regulations contained in subparts D, E, F, and Q of this part unless explicitly stated otherwise.

§ 250.701 May I use alternate procedures or equipment during operations? You may use alternate procedures or equipment during operations after receiving approval as described in § 250.141. You must identify and discuss your proposed alternate procedures or equipment in your Application for Permit to Drill (APD) (Form BSEE-0123) (see § 250.414(h)) or your Application for Permit to Modify (APM) (Form BSEE-0124). Procedures for obtaining approval of alternate procedures or equipment are described in § 250.141.

§ 250.702 May I obtain departures from these requirements? You may apply for a departure from these requirements as described in § 250.142. Your request must include a justification showing why the departure is necessary. You must identify and discuss the departure you are requesting in your APD (see § 250.414(h)) or your APM.

§ 250.703 What must I do to keep wells under control? You must take the necessary precautions to keep wells under control at all times, including: (a) Use recognized engineering practices to reduce risks to the lowest level practicable when monitoring and evaluating well conditions and to minimize the potential for the well to flow or kick; (b) Have a person onsite during operations who represents your interests and can fulfill your responsibilities; (c) Ensure that the toolpusher, operator's representative, or a member of the rig crew maintains continuous surveillance on the rig floor from the beginning of operations until the well is completed or abandoned, unless you have secured the well with blowout preventers (BOPs), bridge plugs, cement plugs, or packers; (d) Use personnel trained according to the provisions of subparts O and S of this part; (e) Use and maintain equipment and materials necessary to ensure the safety and protection of personnel, equipment, natural resources, and the environment; and (f) Use equipment that has been designed, tested, and rated for the maximum environmental and operational conditions to which it may be exposed while in service.

§ 250.710 What instructions must be given to personnel engaged in well operations? Prior to engaging in well operations, personnel must be instructed in: (a) Hazards and safety requirements. You must instruct your personnel regarding the safety requirements for the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment as required by subpart S of this part. The date and time of safety meetings must be recorded and available at the facility for review by BSEE representatives. (b) Well control. You must prepare a well-control plan for each well. Each well-control plan must contain instructions for personnel about the use of each well-control component of your BOP, procedures that describe how personnel will seal the wellbore and shear pipe before maximum anticipated surface pressure (MASP) conditions are exceeded, assignments for each crew member, and a schedule for completion of each assignment. You must keep a copy of your well-control plan on the rig at all times, and make it available to BSEE upon request. You must post a copy of the well-control plan on the rig floor.

§ 250.711 What are the requirements for well-control drills? You must conduct a weekly well-control drill with all personnel engaged in well operations. Your drill must familiarize personnel engaged in well operations with their roles and functions so that they can perform their duties promptly and efficiently as outlined in the well-control plan required by § 250.710. (a) Timing of drills. You must conduct each drill during a period of activity that minimizes the risk to operations. The timing of your drills must cover a range of different operations, including drilling with a diverter, on-bottom drilling, and tripping. The same drill may not be repeated consecutively with the same crew. (b) Recordkeeping requirements. For each drill, you must record the following in the daily report: (1) Date, time, and type of drill conducted; (2) The amount of time it took to be ready to close the diverter or use each well-control component of BOP system; and (3) The total time to complete the entire drill. (c) A BSEE ordered drill. A BSEE representative may require you to conduct a well-control drill during a BSEE inspection. The BSEE representative will consult with your onsite representative before requiring the drill.

§ 250.712 What rig unit movements must I report? (a) You must report the movement of all rig units on and off locations to the District Manager using Form BSEE-0144, Rig Movement Notification Report. Rig units include MODUs, platform rigs, snubbing units, wire-line units used for non-routine operations, and coiled tubing units. You must inform the District Manager 24 hours before: (1) The arrival of a rig unit on location; (2) The movement of a rig unit to another slot. For movements that will occur less than 24 hours after initially moving onto location (e.g., coiled tubing and batch operations), you may include your anticipated movement schedule on Form BSEE-0144; or (3) The departure of a rig unit from the location. (b) You must provide the District Manager with the rig name, lease number, well number, and expected time of arrival or departure. (c) If a MODU or platform rig is to be warm or cold stacked, you must inform the District Manager: (1) Where the MODU or platform rig is coming from; (2) The location where the MODU or platform rig will be positioned; (3) Whether the MODU or platform rig will be manned or unmanned; and (4) If the location for stacking the MODU or platform rig changes. (d) Prior to resuming operations after stacking, you must notify the appropriate District Manager of any construction, repairs, or modifications associated with the drilling package made to the MODU or platform rig. (e) If a drilling rig is entering OCS waters, you must inform the District Manager where the drilling rig is coming from. (f) If you change your anticipated date for initially moving on or off location by more than 24 hours, you must submit an updated Form BSEE-0144, Rig Movement Notification Report. (g) You are not required to report rig unit movements to and from the safe zone during the course of permitted operations. (h) If a rig unit is already on a well, you are not required to report any additional rig unit movements on that well.

§ 250.713 What must I provide if I plan to use a mobile offshore drilling unit (MODU) for well operations? If you plan to use a MODU for well operations, you must provide: (a) Fitness requirements. Information and data to demonstrate the MODU's capability to perform at the proposed location. This information must include the maximum environmental and operational conditions that the MODU is designed to withstand, including the minimum air gap necessary for both hurricane and non-hurricane seasons. If sufficient environmental information and data are not available at the time you submit your APD or APM, the District Manager may approve your APD or APM, but require you to collect and report this information during operations. Under this circumstance, the District Manager may revoke the approval of the APD or APM if information collected during operations shows that the MODU is not capable of performing at the proposed location. (b) Foundation requirements. Information to show that site-specific soil and oceanographic conditions are capable of supporting the proposed bottom-founded MODU. If you provided sufficient site-specific information in your EP, DPP, or DOCD submitted to BOEM for that well location and conditions, you may reference that information. The District Manager may require you to conduct additional surveys and soil borings before approving the APD or APM if additional information is needed to make a determination that the conditions are capable of supporting the MODU, or equipment installed on a subsea wellhead. For a moored rig, you must submit a plat of the rig's anchor pattern approved in your EP, DPP, or DOCD in your APD or APM. (c) For frontier areas. (1) If the design of the MODU you plan to use in a frontier area is unique or has not been proven for use in the proposed environment, the District Manager may require you to submit a third-party review of the MODU design. If required, you must obtain a third-party review of your MODU similar to the process outlined in §§ 250.915 through 250.918. You may submit this information before submitting an APD or APM. (2) If you plan to conduct operations in a frontier area, you must have a contingency plan that addresses design and operating limitations of the MODU. Your plan must identify the actions necessary to maintain safety and prevent damage to the environment. Actions must include the suspension, curtailment, or modification of operations to remedy various operational or environmental situations (e.g., vessel motion, riser offset, anchor tensions, wind speed, wave height, currents, icing or ice-loading, settling, tilt or lateral movement, resupply capability). (d) Additional documentation. You must provide the current Certificate of Inspection (for U.S.-flag vessels) or Certificate of Compliance (for foreign-flag vessels) from the USCG and Certificate of Classification. You must also provide current documentation of any operational limitations imposed by an appropriate classification society. (e) Dynamically positioned MODU. If you use a dynamically positioned MODU, you must include in your APD or APM your contingency plan for moving off location in an emergency situation. At a minimum, your plan must address emergency events caused by storms, currents, station-keeping failures, power failures, and losses of well control. The District Manager may require your plan to include additional events that may require movement of the MODU and other information needed to clarify or further address how the MODU will respond to emergencies or other events. (f) Inspection of MODU. The MODU must be available for inspection by the District Manager before commencing operations and at any time during operations. (g) Current monitoring. For water depths greater than 400 meters (1,312 feet), you must include in your APD or APM: (1) A description of the specific current speeds that will cause you to implement rig shutdown, move-off procedures, or both; and (2) A discussion of the specific measures you will take to curtail rig operations and move off location when such currents are encountered. You may use criteria, such as current velocities, riser angles, watch circles, and remaining rig power to describe when these procedures or measures will be implemented.

§ 250.714 Do I have to develop a dropped objects plan? If you use a floating rig unit in an area with subsea infrastructure, you must develop a dropped objects plan and make it available to BSEE upon request. This plan must be updated as the infrastructure on the seafloor changes. Your plan must include: (a) A description and plot of the path the rig will take while running and pulling the riser; (b) A plat showing the location of any subsea wells, production equipment, pipelines, and any other identified debris; (c) Modeling of a dropped object's path with consideration given to metocean conditions for various material forms, such as a tubular (e.g., riser or casing) and box (e.g., BOP or tree); (d) Communications, procedures, and delegated authorities established with the production host facility to shut-in any active subsea wells, equipment, or pipelines in the event of a dropped object; and (e) Any additional information required by the District Manager as appropriate to clarify, update, or evaluate your dropped objects plan.

§ 250.715 Do I need a global positioning system (GPS) for all MODUs? All MODUs must have a minimum of two functioning GPS transponders at all times, and you must provide to BSEE real-time access to the GPS data prior to and during each hurricane season. (a) The GPS must be capable of monitoring the position and tracking the path in real-time if the MODU moves from its location during a severe storm. (b) You must install and protect the tracking system's equipment to minimize the risk of the system being disabled. (c) You must place the GPS transponders in different locations for redundancy to minimize risk of system failure. (d) Each GPS transponder must be capable of transmitting data for at least 7 days after a storm has passed. (e) If the MODU is moved off location in the event of a storm, you must immediately begin to record the GPS location data. (f) You must contact the Regional Office and allow real-time access to the MODU location data. When you contact the Regional Office, provide the following: (1) Name of the lessee and operator with contact information; (2) MODU name; (3) Initial date and time; and (4) How you will provide GPS real-time access.

§ 250.720 When and how must I secure a well? (a) Whenever you interrupt operations, you must notify the District Manager. Before moving off the well, you must have two independent barriers installed, at least one of which must be a mechanical barrier, as approved by the District Manager. You must install the barriers at appropriate depths within a properly cemented casing string or liner. Before removing a subsea BOP stack or surface BOP stack on a mudline suspension well, you must conduct a negative pressure test in accordance with § 250.721. (1) The events that would cause you to interrupt operations and notify the District Manager include, but are not limited to, the following: (i) Evacuation of the rig crew; (ii) Inability to keep the rig on location; (iii) Repair to major rig or well-control equipment; (iv) Observed flow outside the well's casing (e.g., shallow water flow or bubbling); or (v) Impending National Weather Service-named tropical storm or hurricane. (2) The District Manager may approve alternate procedures or barriers, in accordance with § 250.141, if you do not have time to install the required barriers or if special circumstances occur. (3) If you unlatch the BOP or LMRP: (i) Upon relatch of the BOP, you must test according to § 250.734(b)(2), or (ii) Upon relatch of the LMRP, you must test according to § 250.734(b)(3); and (iii) You must submit a revised permit with a written statement from an independent third party certifying that the previous certification under § 250.731(c) remains valid and receive District Manager approval before resuming operations. (b) Before you displace kill-weight fluid from the wellbore and/or riser, thereby creating an underbalanced state, you must obtain approval from the District Manager. To obtain approval, you must submit with your APD or APM your reasons for displacing the kill-weight fluid and provide detailed step-by-step written procedures describing how you will safely displace these fluids. The step-by-step displacement procedures must address the following: (1) Number and type of independent barriers, as described in § 250.420(b)(3), that are in place for each flow path that requires such barriers; (2) Tests you will conduct to ensure integrity of independent barriers; (3) BOP procedures you will use while displacing kill-weight fluids; and (4) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore. (c) For Arctic OCS exploratory drilling operations, in addition to the requirements of paragraphs (a) and (b) of this section: (1) If you move your drilling rig off a well prior to completion or permanent abandonment, you must ensure that any equipment left on, near, or in a wellbore that has penetrated below the surface casing is positioned in a manner to: (i) Protect the well head; and (ii) Prevent or minimize the likelihood of compromising the down-hole integrity of the well or the effectiveness of the well plugs. (2) In areas of ice scour you must use a well mudline cellar or an equivalent means of minimizing the risk of damage to the well head and wellbore. BSEE may approve an equivalent means that will meet or exceed the level of safety and environmental protection provided by a mudline cellar if the operator can show that utilizing a mudline cellar would compromise the stability of the rig, impede access to the well head during a well control event, or otherwise create operational risks. (d) You must have the equipment used solely for intervention operations (e.g., tree interface tools) identified, readily available, properly maintained, and available for BSEE inspection upon request. This equipment is required for subsea completed wells with a tree installed, that meet the following conditions: (1) Have a shut-in tubing pressure that is greater than the hydrostatic pressure of the water column, or (2) Are not capable of having the annulus monitored.

§ 250.721 What are the requirements for pressure testing casing and liners? (a) You must test each casing string that extends to the wellhead according to the following table: (b) You must test each drilling liner and liner-top to a pressure at least equal to the anticipated leak-off pressure of the formation below that liner shoe, or subsequent liner shoes if set. You must conduct this test before you continue operations in the well. (c) You must test each production liner and liner-top to a minimum of 500 psi above the formation fracture pressure at the casing shoe into which the liner is lapped. (d) The District Manager may approve or require other casing test pressures as appropriate under the circumstances to ensure casing integrity. (e) If you plan to produce a well, you must: (1) For a well that is fully cased and cemented, pressure test the entire well to maximum anticipated shut-in tubing pressure, not to exceed 70% of the burst rating limit of the weakest component before perforating the casing or liner; or (2) For an open-hole completion, pressure test the entire well to maximum anticipated shut-in tubing pressure, not to exceed 70% of the burst rating limit of the weakest component before you drill the open-hole section. (f) You may not resume operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test, or if there is another indication of a leak, you must submit to the District Manager for approval your proposed plans to re-cement, repair the casing or liner, or run additional casing/liner to provide a proper seal. Your submittal must include a PE certification of your proposed plans. (g) You must perform a negative pressure test on all wells that use a subsea BOP stack or wells with mudline suspension systems. (1) You must perform a negative pressure test on your final casing string or liner. This test must be conducted after setting your second barrier just above the shoe track, but prior to conducting any completion operations. (2) You must perform a negative pressure test prior to unlatching the BOP at any point in the well. The negative pressure test must be performed on those components, at a minimum, that will be exposed to the negative differential pressure that will occur when the BOP is disconnected. (3) The District Manager may require you to perform additional negative pressure tests on other casing strings or liners (e.g., intermediate casing string or liner) or on wells with a surface BOP stack as appropriate to demonstrate casing or liner integrity. (4) You must submit for approval with your APD or APM, test procedures and criteria for a successful negative pressure test. If any of your test procedures or criteria for a successful test change, you must submit for approval the changes in a revised APD or APM. (5) You must document all your test results and make them available to BSEE upon request. (6) If you have any indication of a failed negative pressure test, such as, but not limited to, pressure buildup or observed flow, you must immediately investigate the cause. If your investigation confirms that a failure occurred during the negative pressure test, you must: (i) Correct the problem and immediately notify the appropriate District Manager; and (ii) Submit a description of the corrective action taken and receive approval from the appropriate District Manager for the retest. (7) You must have two barriers in place, as described in § 250.420(b)(3), at any time and for any well, prior to performing the negative pressure test. (8) You must include documentation of the successful negative pressure test in the End-of-Operations Report (Form BSEE-0125).

§ 250.722 What are the requirements for prolonged operations in a well? If wellbore operations continue within a casing or liner for more than 30 days from the previous pressure test of the well's casing or liner, you must: (a) Stop operations as soon as practicable, and evaluate the effects of the prolonged operations on continued operations and the life of the well. At a minimum, you must: (1) Evaluate the well casing with a pressure test, caliper tool, or imaging tool. On a case-by-case basis, the District Manager may require a specific method of evaluation of the effects on the well casing of prolonged operations; and (2) Report the results of your evaluation to the District Manager and obtain approval of those results before resuming operations. Your report must include calculations that indicate the well's integrity is above the minimum safety factors, if an imaging tool or caliper is used. District Manager approval is not required to resume operations if you conducted a successful pressure test as approved in your permit. You must document the successful pressure test in the WAR. (b) If well integrity has deteriorated to a level below minimum safety factors, you must: (1) Obtain approval from the District Manager to begin repairs or install additional casing. To obtain approval, you must also provide a PE certification showing that he or she reviewed and approved the proposed changes; (2) Repair the casing or run another casing string; and (3) Perform a pressure test after the repairs are made or additional casing is installed and report the results to the District Manager as specified in § 250.721.

§ 250.723 What additional safety measures must I take when I conduct operations on a platform that has producing wells or has other hydrocarbon flow? You must take the following safety measures when you conduct operations with a rig unit on or jacked-up over a platform with producing wells or that has other hydrocarbon flow: (a) The movement of rig units and related equipment on and off a platform or from well to well on the same platform, including rigging up and rigging down, must be conducted in a safe manner; (b) You must install an emergency shutdown station for the production system near the rig operator's console; (c) You must shut-in all producible wells located in the affected wellbay below the surface and at the wellhead when: (1) You move a rig unit or related equipment on and off a platform. This includes rigging up and rigging down activities within 500 feet of the affected platform; (2) You move or skid a rig unit between wells on a platform; or (3) A MODU moves within 500 feet of a platform. You may resume production once the MODU is in place, secured, and ready to begin operations. (d) All wells in the same well-bay which are capable of producing hydrocarbons must be shut-in below the surface with a pump-through-type tubing plug and at the surface with a closed master valve prior to moving rig units and related equipment, unless otherwise approved by the District Manager. (1) A closed surface-controlled subsurface safety valve of the pump-through-type may be used in lieu of the pump-through-type tubing plug provided that the surface control has been locked out of operation. (2) The well to which a rig unit or related equipment is to be moved must be equipped with a back-pressure valve prior to removing the tree and installing and testing the BOP system. (3) The well from which a rig unit or related equipment is to be moved must be equipped with a back pressure valve prior to removing the BOP system and installing the production tree. (e) Coiled tubing units, snubbing units, or wireline units may be moved onto and off of a platform without shutting in wells.

§ 250.724 What are the real-time monitoring requirements? (a) When conducting well operations with a subsea BOP or with a surface BOP on a floating facility, or when operating in an high pressure high temperature (HPHT) environment, you must gather and monitor real-time well data using an independent, automatic, and continuous monitoring system capable of recording, storing, and transmitting data regarding the following: (1) The BOP control system; (2) The well's active fluid circulating system; and (3) The well's downhole conditions with the bottom hole assembly tools (if any tools are installed). (b) You must transmit these data as they are gathered, barring unforeseeable or unpreventable interruptions in transmission, and have the capability to monitor the data, using qualified personnel in accordance with a real-time monitoring plan, as provided in paragraph (c) of this section. (c) You must develop and implement a real-time monitoring plan. Your real-time monitoring plan, and all real-time monitoring data, must be made available to BSEE upon request. Your real-time monitoring plan must include the following: (1) A description of your real-time monitoring capabilities, including the types of the data collected; (2) A description of how your real-time monitoring data will be transmitted during operations, how the data will be labeled and monitored by qualified personnel, and how the data will be stored as required in §§ 250.740 and 250.741; (3) A description of your procedures for providing BSEE access, upon request, to your real-time monitoring data; (4) The qualifications of the personnel monitoring the data; (5) Your procedures for, and methods of, communication between rig personnel and the monitoring personnel; and (6) Actions to be taken if you lose any real-time monitoring capabilities or communications between rig personnel and monitoring personnel, and a protocol for how you will respond to any significant and/or prolonged interruption of monitoring capabilities or communications, including your protocol for notifying BSEE of any significant and/or prolonged interruptions.

§ 250.730 What are the general requirements for BOP systems and system components? (a) You must ensure that the BOP system and system components are designed, installed, maintained, inspected, tested, and used properly to ensure well control. The working-pressure rating of each BOP component (excluding annular(s)) must exceed MASP as defined for the operation. For a subsea BOP, the MASP must be determined at the mudline. The BOP system includes the BOP stack, control system, and any other associated system(s) and equipment. The BOP system and individual components must be able to perform their expected functions and be compatible with each other. Your BOP system must be capable of closing and sealing the wellbore to the well's MASP at all times, except as otherwise specified in the BOP system requirements of this subpart. The BOP system must be capable of closing and sealing without losing ram closure time and sealing integrity due to the corrosiveness, volume, and abrasiveness of any fluids in the wellbore that the BOP system may encounter. Your BOP system must meet the following requirements: (1) The BOP requirements of API Standard 53 (incorporated by reference, see § 250.198) and the requirements of §§ 250.733 through 250.739. If there is a conflict between API Standard 53 and the requirements of this subpart, you must follow the requirements of this subpart. (2) The provisions of the following industry standards (all incorporated by reference, see § 250.198) that apply to BOP systems: (i) API Specification 6A; (ii) ANSI/API Specification 16A; (iii) ANSI/API Specification 16C; (iv) API Specification 16D; (v) API Specification 17D; (vi) API Specification 20E; and (vii) API Specification 20F. (3) For surface and subsea BOPs, the pipe and variable bore rams installed in the BOP stack must be capable of effectively closing and sealing on the tubular body of any drill pipe, workstring, and tubing (excluding tubing with exterior control lines and flat packs) in the hole under MASP, as defined for the operation, at the proposed regulator settings of the BOP control system. (4) The current set of approved schematic drawings must be available on the rig and at an onshore location. If you make any modifications to the BOP or control system that will require changes to your BSEE-approved schematic drawings, you must suspend operations until you obtain approval from the District Manager. (b) You must ensure that the design, fabrication, maintenance, and repair of your BOP system is in accordance with the requirements contained in this part, applicable Original Equipment Manufacturer's (OEM) recommendations unless otherwise directed by BSEE, and recognized engineering practices. The training and qualification of repair and maintenance personnel must meet or exceed applicable OEM training recommendations unless otherwise directed by BSEE. (c) You must follow the failure reporting procedures contained in API Standard 53 (incorporated by reference, see § 250.198) and: (1) You must provide a written notice of equipment failure to the Office of Offshore Regulatory Programs (OORP) Chief, any third party designated by BSEE pursuant to paragraph (c)(4) of this section, and the manufacturer of such equipment within 30 days after the discovery and identification of the failure. A failure is any condition that prevents the equipment from meeting the functional specification. (2) You must start an investigation and a failure analysis within 90 days of the failure to determine the cause of the failure and complete the investigation and the failure analysis within 120 days after initiation. You also must document the results and any corrective action. You must submit the analysis report to the OORP Chief, any third party designated by BSEE pursuant to paragraph (c)(4) of this section, and the manufacturer. If you cannot complete the investigation and analysis within the specified time, you must submit an extension request detailing when and how you will complete the investigation and analysis to BSEE for approval. You must submit the extension request to the OORP Chief. (3) If the equipment manufacturer notifies you that it has changed the design of the equipment that failed or if you have changed operating or repair procedures as a result of a failure, then you must, within 30 days of such changes, report the design change or modified procedures in writing to the OORP Chief, and any third party designated by BSEE pursuant to paragraph (c)(4) of this section. (4) Submit notices and reports to the Chief, Office of Offshore Regulatory Programs; Bureau of Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, Virginia 20166. BSEE may designate a third party to also receive the data and reports. If BSEE designates a third party, you must submit the data and reports to the designated third party as well. (d) If you plan to use a BOP stack manufactured after the effective date of this regulation, you must use one manufactured pursuant to an ANSI/API Specification Q1 (incorporated by reference, see § 250.198) quality management system. Such quality management system must be certified by an entity that meets the requirements of ISO/IEC 17021-1 (incorporated by reference, see § 250.198). (1) BSEE may consider accepting equipment manufactured under quality assurance programs other than ANSI/API Spec. Q1, provided you submit a request to the Chief, OORP for approval, containing relevant information about the alternative program. (2) You must submit this request to the Chief, OORP; Bureau of Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, Virginia 20166.

§ 250.731 What information must I submit for BOP systems and system components? For any operation that requires the use of a BOP, you must include the information listed in this section with your applicable APD, APM, or other submittal. You are required to submit this information only once for each well, unless the information changes from what you provided in an earlier approved submission or you have moved off location from the well. After you have submitted this information for a particular well, subsequent APMs or other submittals for the well should reference the approved submittal containing the information required by this section and confirm that the information remains accurate and that you have not moved off location from that well. If the information changes or you have moved off location from the well, you must submit updated information in your next submission.

§ 250.732 What are the independent third party requirements for BOP systems and system components? (a) Prior to beginning any operation requiring the use of any BOP, you must submit verification by an independent third party and supporting documentation as required by this paragraph to the appropriate District Manager and Regional Supervisor. (b) The independent third party must be a technical classification society, a licensed professional engineering firm, or a registered professional engineer capable of providing the required certifications and verifications. You must submit the independent third party qualifications to BSEE with the associated permit application (e.g., APD and APM). BSEE will evaluate the submitted qualifications to ensure they meet the regulatory requirements for permit approval. (c) Before you begin any operations in an HPHT environment, as defined by § 250.105, with the proposed equipment, you must include the following in your applicable permit: (1) The I3P certification required in § 250.731(c); (2) A description of any new or unusual technology being used; (3) A reference to the previously approved associated New or Unusual Technology Barrier Equipment Conceptual Plan; (4) The final report and statements in accordance with § 250.232(c); and (5) The fit for service statement required in § 250.230. You may not deploy your proposed BOP systems and related equipment that will or may be exposed to an HPHT environment until BSEE approves the New or Unusual Technology Barrier Equipment Conceptual Plan and appropriate permits (e.g., APD and APM). (d) You must make all documentation that demonstrates compliance with the requirements of this section available to BSEE upon request.

§ 250.733 What are the requirements for a surface BOP stack? (a) When you drill or conduct operations with a surface BOP stack, you must install the BOP system before drilling or conducting operations to deepen the well below the surface casing and after the well is deepened below the surface casing point. The surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs, consisting of one annular BOP, one BOP equipped with blind shear rams, and two BOPs equipped with pipe rams. (1) The blind shear rams must be capable of shearing at any point along the tubular body of any drill pipe (excluding tool joints, bottom-hole tools, and bottom hole assemblies that include heavy-weight pipe or collars), workstring, tubing and associated exterior control lines, and any electric-, wire-, and slick-line that is in the hole and sealing the wellbore after shearing. Prior to April 29, 2021, if your blind shear rams are unable to cut any electric-, wire-, or slick-line under MASP as defined for the operation and seal the wellbore, you must use an alternative cutting device capable of shearing the lines before closing the BOP. This device must be available on the rig floor during operations that require their use. (2) The two BOPs equipped with pipe rams must be capable of closing and sealing on the tubular body of any drill pipe, workstring, and tubing under MASP, as defined for the operation, except for tubing with exterior control lines and flat packs, a bottom hole assembly that includes heavy-weight pipe or collars, and bottom-hole tools. (b) If you plan to use a surface BOP on a floating production facility you must: (1) On new floating production facilities installed after April 29, 2021, that include a surface BOP, or when you replace an entire surface BOP stack on an existing floating production facility, follow the BOP requirements in § 250.734(a)(1). (2) For risers installed after July 28, 2016, use a dual bore riser configuration before drilling or operating in any hole section or interval where hydrocarbons are, or may be, exposed to the well. The dual bore riser must meet the design requirements of API Recommended Practice 2RD (incorporated by reference, see § 250.198), including appropriate design for the maximum anticipated operating and environmental conditions. (i) For a dual bore riser configuration, the annulus between the risers must be monitored for pressure during operations. You must describe in your APD or APM your annulus monitoring plan and how you will secure the well in the event a leak is detected. (ii) The inner riser for a dual riser configuration is subject to the requirements at § 250.721 for testing the casing or liner. (c) You must install separate side outlets on the BOP stack for the kill and choke lines. If your stack does not have side outlets, you must install a drilling spool with side outlets. The outlet valves must hold pressure from both directions. (d) You must install a choke and a kill line on the BOP stack. You must equip each line with two full-bore, full-opening valves, one of which must be remote-controlled. On the kill line, you may install a check valve and a manual valve instead of the remote-controlled valve. To use this configuration, both manual valves must be readily accessible and you must install the check valve between the manual valves and the pump. (e) Additional requirements for surface BOP systems used in well-completion, workover, and decommissioning operations. The minimum BOP system for well-completion, workover, and decommissioning operations must meet the appropriate standards from the following table:

§ 250.734 What are the requirements for a subsea BOP system? (a) When you drill or conduct operations with a subsea BOP system, you must install the BOP system before drilling to deepen the well below the surface casing or before conducting operations if the well is already deepened beyond the surface casing point. The District Manager may require you to install a subsea BOP system before drilling or conducting operations below the conductor casing if proposed casing setting depths or local geology indicate the need. The following table outlines your requirements. (b) If you suspend operations to make repairs to any part of the subsea BOP system, you must stop operations at a safe downhole location. Before resuming operations you must: (1) Submit a revised permit with a written statement from an independent third party documenting the repairs and certifying that the previous certification in § 250.731(c) remains valid; (2) Upon relatch of the BOP, perform an initial subsea BOP test in accordance with § 250.737(d)(4), including deadman in accordance with § 250.737(d)(12)(vi). If repairs take longer than 30 days, once the BOP is on deck, you must test in accordance with the requirements of § 250.737; (3) Upon relatch of the LMRP, you must test according to the following: (i) Pressure test riser connector/gasket in accordance with § 250.737(b) and (c); (ii) Pressure test choke and kill stabs at LMRP/BOP interface in accordance with § 250.737(b) and (c); (iii) Full function test of both pods and both control panels; (iv) Verify acoustic pod communication (if equipped); and (v) Deadman test with pressure test in accordance with § 250.737(d)(12)(vi). (4) Receive approval from the District Manager. (c) If you plan to drill a new well with a subsea BOP, you do not need to submit with your APD the verifications required by this subpart for the open water drilling operation. Before drilling out the surface casing, you must submit for approval a revised APD, including the verifications required in this subpart.

§ 250.735 What associated systems and related equipment must all BOP systems include? All BOP systems must include the following associated systems and related equipment: (a) An accumulator system, as specified in API Standard 53 (incorporated by reference, see § 250.198). Your accumulator system must have the fluid volume capacity and appropriate pre-charge pressures in accordance with API Standard 53. If you supply the accumulator regulators by rig air and do not have a secondary source of pneumatic supply, you must equip the regulators with manual overrides or other devices to ensure capability of hydraulic operations if rig air is lost; (b) An automatic backup to the primary accumulator-charging system. The power source must be independent from the power source for the primary accumulator-charging system. The independent power source must possess sufficient capability to close and hold closed all BOP components under MASP conditions as defined for the operation; (c) At least two full BOP control stations. One station must be on the rig floor. You must locate the other station in a readily accessible location away from the rig floor; (d) The choke line(s) installed above the bottom well-control ram; (e) The kill line must be installed beneath at least one well-control ram, and may be installed below the bottom ram; (f) A fill-up line above the uppermost BOP; (g) Locking devices for all BOP sealing rams (i.e., blind shear rams, pipe rams and variable bore rams), as follows: (1) For subsea BOPs, hydraulic locking devices must be installed on all sealing rams; (2) For surface BOPs: (i) Remotely-operated locking devices must be installed on blind shear rams no later than April 29, 2019; (ii) Manual or remotely-operated locking devices must be installed on pipe rams and variable bore rams; and (h) A wellhead assembly with a RWP that exceeds the maximum anticipated wellhead pressure.

§ 250.736 What are the requirements for choke manifolds, kelly-type valves inside BOPs, and drill string safety valves? (a) Your BOP system must include a choke manifold that is suitable for the anticipated surface pressures, anticipated methods of well control, the surrounding environment, and the corrosiveness, volume, and abrasiveness of drilling fluids and well fluids that you may encounter. (b) Choke manifold components must have a RWP at least as great as the RWP of the ram BOPs. If your choke manifold has buffer tanks downstream of choke assemblies, you must install isolation valves on any bleed lines. (c) Valves, pipes, flexible steel hoses, and other fittings upstream of the choke manifold must have a RWP at least as great as the RWP of the ram BOPs. (d) You must use the following BOP equipment with a RWP and temperature of at least as great as the working pressure and temperature of the ram BOP during all operations: (1) The applicable kelly-type valves as described in API Standard 53 (incorporated by reference, see § 250.198); (2) On a top-drive system equipped with a remote-controlled valve, a strippable kelly-type valve must be installed below the remote-controlled valve; (3) An inside BOP in the open position located on the rig floor. You must be able to install an inside BOP for each size connection in the pipe; (4) A drill string safety valve in the open position located on the rig floor. You must have a drill-string safety valve available for each size connection in the pipe; (5) When running casing, a safety valve in the open position available on the rig floor to fit the casing string being run in the hole. For subsea BOPs, the safety valve must be available on the rig floor if the length of casing being run exceeds the water depth, which would result in the casing being across the BOP stack and the rig floor prior to crossing over to the drill pipe running string; (6) All required manual and remote- controlled kelly-type valves, drill-string safety valves, and comparable-type valves (i.e., kelly-type valve in a top-drive system) that are essentially full opening; and (7) A wrench to fit each manual valve. Each wrench must be readily accessible to the drilling crew.

§ 250.737 What are the BOP system testing requirements? Your BOP system (this includes the choke manifold, kelly-type valves, inside BOP, and drill string safety valve) must meet the following testing requirements: (a) Pressure test frequency. You must pressure test your BOP system: (1) When installed; (2) Before 14 days have elapsed since your last BOP pressure test, or 30 days since your last blind shear ram BOP pressure test. You must begin to test your BOP system before midnight on the 14th day (or 30th day for your blind shear rams) following the conclusion of the previous test; (3) Before drilling out each string of casing or a liner. You may omit this pressure test requirement if you did not remove the BOP stack to run the casing string or liner, the required BOP test pressures for the next section of the hole are not greater than the test pressures for the previous BOP test, and the time elapsed between tests has not exceeded 14 days (or 30 days for blind shear rams). You must indicate in your APD which casing strings and liners meet these criteria; (4) In lieu of meeting the schedule established in paragraph (a)(2) of this section, you may request that BSEE approve a 21-day BOP testing frequency. To obtain BSEE approval, you must submit a request to the appropriate BSEE Regional Supervisor, District Field Operations. Your request must demonstrate that you have developed a BOP health monitoring plan that includes certain system capabilities. As long as your plan is consistent with recognized engineering and industry practice, BSEE will approve your request if it includes the following: (i) Condition monitoring tools, including continuous surveillance of sensor readings from the BOP control system, real-time condition analysis and displays, functional pressure signal analysis, historical sensor data; (ii) Failure propagation analysis; (iii) A failure tracking and resolution system that includes detailed failure reports and identification of recurring problems; and (iv) Submission of quarterly reports of the data collected pursuant to paragraphs (a)(4)(i)(iii) to the BSEE Regional Supervisor, District Field Operations. (5) The District Manager may require more frequent testing if conditions or your BOP performance warrant. (b) Pressure test procedures. When you pressure test the BOP system, you must conduct a low-pressure test and a high-pressure test for each BOP component (excluding test rams and non-sealing shear rams). You must begin each test by conducting the low-pressure test then transition to the high-pressure test. Each individual pressure test must hold pressure long enough to demonstrate the tested component(s) holds the required pressure. The table in this paragraph (b) outlines your pressure test requirements. (c) Duration of pressure test. Each test must hold the required pressure for 5 minutes, which must be recorded on a chart not exceeding 4 hours, or on a digital recorder. However, for surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if recorded on a chart not exceeding 4 hours, or on a digital recorder. The recorded test pressures must be within the middle half of the chart range, i.e., cannot be within the lower or upper one-fourth of the chart range. If the equipment does not hold the required pressure during a test, you must correct the problem and retest the affected component(s). (d) Additional test requirements. You must meet the following additional BOP testing requirements: (e) Prior to conducting any shear ram tests in which you will shear pipe, you must notify the District Manager at least 72 hours in advance, to ensure that a BSEE representative will have access to the location to witness any testing.

§ 250.738 What must I do in certain situations involving BOP equipment or systems? The table in this section describes actions that you must take when certain situations occur with BOP systems.

§ 250.739 What are the BOP maintenance and inspection requirements? (a) You must maintain and inspect your BOP system to ensure that the equipment functions as designed. The BOP maintenance and inspections must meet or exceed any OEM recommendations, recognized engineering practices, and industry standards incorporated by reference into the regulations of this subpart, including API Standard 53 (incorporated by reference, see § 250.198). You must document how you met or exceeded the provisions of API Standard 53, maintain complete records to ensure the traceability of BOP stack equipment beginning at fabrication, and record the results of your BOP inspections and maintenance actions. You must make all records available to BSEE upon request. (b) A major, detailed inspection of the well control system components (including but not limited to riser, BOP, LMRP, and control pods) must be performed every 5 years. This major inspection may be performed in phased intervals. You must track and document all system and component inspection dates. These records must be available on the rig. An independent third party is required to review the inspection results and must compile a detailed report of the inspection results, including descriptions of any problems and how they were corrected. You must make these reports available to BSEE upon request. This major inspection must be performed every 5 years from the following applicable dates, whichever is later: (1) The date the equipment owner accepts delivery of a new build drilling rig with a new BOP system; (2) The date the new, repaired, or remanufactured equipment is initially installed into the system; or (3) The date of the last 5 year inspection for the component. (c) You must visually inspect your surface BOP system on a daily basis. You must visually inspect your subsea BOP system, marine riser, and wellhead at least once every 3 days if weather and sea conditions permit. You may use cameras to inspect subsea equipment. (d) You must ensure that all personnel maintaining, inspecting, or repairing BOPs, or critical components of the BOP system, are trained in accordance with applicable training requirements in subpart S of this part, any applicable OEM criteria, recognized engineering practices, and industry standards incorporated by reference in this subpart. (e) You must make all records available to BSEE upon request. You must ensure that the rig unit owner maintains the BOP maintenance, inspection, and repair records on the rig unit for 2 years from the date the records are created or for a longer period if directed by BSEE. You must ensure that all equipment schematics, maintenance, inspection, and repair records are located at an onshore location for the service life of the equipment.

§ 250.740 What records must I keep? You must keep a daily report consisting of complete, legible, and accurate records for each well. You must keep records onsite while well operations continue. After completion of operations, you must keep all operation and other well records for the time periods shown in § 250.741 at a location of your choice, except as required in § 250.746. The records must contain complete information on all of the following: (a) Well operations, all testing conducted, and any real-time monitoring data as required by § 250.724; (b) Descriptions of formations penetrated; (c) Content and character of oil, gas, water, and other mineral deposits in each formation; (d) Kind, weight, size, grade, and setting depth of casing; (e) All well logs and surveys run in the wellbore; (f) Any significant malfunction or problem; and (g) All other information required by the District Manager as appropriate to ensure compliance with the requirements of this section and to enable BSEE to determine that the well operations are consistent with conservation of natural resources and protection of safety and the environment on the OCS.

§ 250.741 How long must I keep records? You must keep records for the time periods shown in the following table.

§ 250.742 What well records am I required to submit? You must submit to BSEE copies of logs or charts of electrical, radioactive, sonic, and other well logging operations; directional and vertical well surveys; velocity profiles and surveys; and analysis of cores. Each Region will provide specific instructions for submitting well logs and surveys.

§ 250.743 What are the well activity reporting requirements? (a) For operations in the BSEE Gulf of America (GOA) OCS Region, you must submit Form BSEE-0133, Well Activity Report (WAR), to the District Manager on a weekly basis. The reporting week is defined as beginning on Sunday (12 a.m.) and ending on the following Saturday (11:59 p.m.). This reporting week corresponds to a week (Sunday through Saturday) on a standard calendar. Report any well operations that extend past the end of this weekly reporting period on the next weekly report. The reporting period for the weekly report is never longer than 7 days, but could be less than 7 days for the first reporting period and the last reporting period for a particular well operation. Submit each WAR and accompanying Form BSEE-0133S, Open Hole Data Report, to the BSEE GOA-OCS Region no later than close of business on the Friday immediately after the closure of the reporting week. The District Manager may require more frequent submittal of the WAR on a case-by-case basis. (b) For operations in the Pacific or Alaska OCS Regions, you must submit Form BSEE-0133, WAR, to the District Manager on a daily basis. (c) The WAR must include a description of the operations conducted, any abnormal or significant events that affect the permitted operation each day within the report from the time you begin operations to the time you end operations, any verbal approval received, the well's as-built drawings, casing, fluid weights, shoe tests, test pressures at surface conditions, and any other information concerning well activities required by the District Manager. For casing cementing operations, indicate type of returns (i.e., full, partial, or none). If partial or no returns are observed, you must indicate how you determined the top of cement. For each report, indicate the operation status for the well at the end of the reporting period. On the final WAR, indicate the status of the well (completed, temporarily abandoned, permanently abandoned, or drilling suspended) and the date you finished such operations.

§ 250.744 What are the end of operation reporting requirements? (a) Within 30 days after completing operations, except routine operations as defined in § 250.601, you must submit Form BSEE-0125, End of Operations Report (EOR), to the District Manager. The EOR must include: a listing, with top and bottom depths, of all hydrocarbon zones and other zones of porosity encountered with any cored intervals; details on any drill-stem and formation tests conducted; documentation of successful negative pressure testing on wells that use a subsea BOP stack or wells with mudline suspension systems; and an updated schematic of the full wellbore configuration. The schematic must be clearly labeled and show all applicable top and bottom depths, locations and sizes of all casings, cut casing or stubs, casing perforations, casing rupture discs (indicate if burst or collapse and rating), cemented intervals, cement plugs, mechanical plugs, perforated zones, completion equipment, production and isolation packers, alternate completions, tubing, landing nipples, subsurface safety devices, and any other information required by the District Manager regarding the end of well operations. The EOR must indicate the status of the well (completed, temporarily abandoned, permanently abandoned, or drilling suspended) and the date of the well status designation. The well status date is subject to the following: (1) For surface well operations and riserless subsea operations, the operations end date is subject to the discretion of the District Manager; and (2) For subsea well operations, the operations end date is considered to be the date the BOP is disconnected from the wellhead unless otherwise specified by the District Manager. (b) You must submit public information copies of Form BSEE-0125 according to § 250.186(b).

§ 250.745 What other well records could I be required to submit? The District Manager or Regional Supervisor may require you to submit copies of any or all of the following well records: (a) Well records as specified in § 250.740; (b) Paleontological interpretations or reports identifying microscopic fossils by depth and/or washed samples of drill cuttings that you normally maintain for paleontological determinations. The Regional Supervisor may issue a Notice to Lessees that sets forth the manner, timeframe, and format for submitting this information; (c) Service company reports on cementing, perforating, acidizing, testing, or other similar services; or (d) Other reports and records of operations.

§ 250.746 What are the recordkeeping requirements for casing, liner, and BOP tests, and inspections of BOP systems and marine risers? You must record the time, date, and results of all casing and liner pressure tests. You must also record pressure tests, actuations, and inspections of the BOP system, system components, and marine riser in the daily report described in § 250.740. In addition, you must: (a) Record test pressures on pressure charts or digital recorders; (b) Require your onsite lessee representative, designated rig or contractor representative, and pump operator to sign and date the pressure charts or digital recordings and daily reports as correct; (c) Document on the daily report the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. For subsea BOP systems, you must also record the closing times for annular and ram BOPs. You may reference a BOP test plan if it is available at the facility; (d) Identify on the daily report the control station and pod used during the test (identifying the pod does not apply to coiled tubing and snubbing units); (e) Identify on the daily report any problems or irregularities observed during BOP system testing and record actions taken to remedy the problems or irregularities. Any leaks associated with the BOP or control system during testing must be documented in the WAR. If any problems that cannot be resolved promptly are observed during testing, operations must be suspended until the District Manager determines that you may continue; and (f) Retain all records, including pressure charts, daily reports, and referenced documents pertaining to tests, actuations, and inspections at the rig unit for the duration of the operation. After completion of the operation, you must retain all the records listed in this section for a period of 2 years at the rig unit. You must also retain the records at the lessee's field office nearest the facility or at another location available to BSEE. You must make all the records available to BSEE upon request.

§ 250.750 What are the coiled tubing requirements? (a) For coiled tubing operations, you must follow the applicable requirements of this subpart and you must meet the following minimum requirements for the BOP system: (1) BOP system components must be in the following order from the top down: (2) You may use a set of hydraulically-operated combination rams for the blind rams and shear rams. (3) You may use a set of hydraulically-operated combination rams for the hydraulic two-way slip rams and the hydraulically-operated pipe rams. (4) You must attach a dual check valve assembly to the coiled tubing connector at the downhole end of the coiled tubing string for all coiled tubing operations. If you plan to conduct operations without downhole check valves, you must describe alternate procedures and equipment in Form BSEE-0124, Application for Permit to Modify and have it approved by the District Manager. (5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves and at least one of the valves must be remotely controlled. You may use a manual valve instead of the remotely controlled valve on the kill line if you install a check valve between the two full-opening manual valves and the pump or manifold. The valves must have a working pressure rating equal to or greater than the working pressure rating of the connection to which they are attached, and you must install them between the well control stack and the choke or kill line. For operations with expected surface pressures greater than 3,500 psi, the kill line must be connected to a pump or manifold. You must not use the kill line inlet on the BOP stack for taking fluid returns from the wellbore. (6) You must have a hydraulic-actuating system that provides sufficient accumulator capacity to close-open-close each component in the BOP stack. This cycle must be completed with at least 200 psi above the pre-charge pressure, without assistance from a charging system. (7) All connections used in the surface BOP system from the tree to the uppermost required ram must be flanged, including the connections between the well control stack and the first full-opening valve on the choke line and the kill line. (b) BSEE considers all coiled tubing operations to be non-routine.

§ 250.751 Coiled tubing testing requirements. You must test the coiled tubing unit in accordance with § 250.737(a), (b), (c), (d)(9), and (d)(10). You must successfully pressure test the dual check valves to the rated working pressure of the connector, the rated working pressure of the dual check valve, expected surface pressure, or the collapse pressure of the coiled tubing, whichever is less. The test interval for coiled tubing operations must include a 10 minute high-pressure test for the coiled tubing string.

§ 250.760 What are the snubbing requirements? (a) For snubbing operations, you must follow the applicable requirements of this subpart and have the following minimum BOP-system components: (1) One set of pipe rams hydraulically operated, (2) Two sets of stripper-type pipe rams hydraulically operated with spacer spool, (3) An inside BOP or a spring-loaded, back-pressure safety valve in the open position located on the rig floor, and (4) An essentially full-opening, work-string safety valve in the open position must be maintained on the rig floor at all times and a wrench to fit the work-string safety valve must be readily available. (5) Proper connections must be readily available for inserting valves in the work string. (b) Test the snubbing unit in accordance with § 250.737(a), (b), and (c).

§ 250.800 General. (a) You must design, install, use, maintain, and test production safety equipment in a manner to ensure the safety and protection of the human, marine, and coastal environments. For production safety systems operated in subfreezing climates, you must use equipment and procedures that account for floating ice, icing, and other extreme environmental conditions that may occur in the area. Before you commence production on a new production facility: (1) BSEE must approve your production safety system application, as required in § 250.842. (2) You must request a preproduction inspection by notifying the District Manager at least 72 hours before you plan to commence initial production, as required under § 250.880(a)(1). (b) For all new production systems on fixed leg platforms, you must comply with API Recommended Practice 14J (incorporated by reference, see § 250.198); (c) For all new floating production systems (FPSs) (e.g., column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); and spars), you must: (1) Comply with API Recommended Practice 14J; (2) Meet the production riser standards of API Recommended Practice 2RD (incorporated by reference, see § 250.198), provided that you may not install single bore production risers from floating production facilities; (3) Design all stationkeeping (i.e., anchoring and mooring) systems for floating production facilities to meet the standards of API Recommended Practice 2SK and API Recommended Practice 2SM (both incorporated by reference, see § 250.198); and (4) Design stationkeeping (i.e., anchoring and mooring) systems for floating facilities to meet the structural requirements of §§ 250.900 through 250.921. (d) If there are any conflicts between the documents incorporated by reference and the requirements of this subpart, you must follow the requirements of this subpart. (e) You may use alternate procedures or equipment during operations after receiving approval from the District Manager. You must present your proposed alternate procedures or equipment as required by § 250.141. (f) You may apply for a departure from the operating requirements of this subpart as provided by § 250.142. Your written request must include a justification showing why the departure is necessary and appropriate.

§ 250.801 Safety and pollution prevention equipment (SPPE) certification. (a) SPPE equipment. You must install only safety and pollution prevention equipment (SPPE) considered certified under paragraph (b) of this section or accepted under paragraph (c) of this section. BSEE considers the following equipment to be types of SPPE: (1) Surface safety valves (SSV) and actuators, including those installed on injection wells capable of natural flow; (2) Boarding shutdown valves (BSDV) and their actuators. For subsea wells, the BSDV is the surface equivalent of an SSV on a surface well; (3) Underwater safety valves (USV) and actuators; (4) Subsurface safety valves (SSSV) and associated safety valve locks and landing nipples; and (5) Gas lift shutdown valves (GLSDV) and their actuators associated with subsea systems. (b) Certification of SPPE. SPPE that is manufactured and marked pursuant to ANSI/API Specification Q1 (incorporated by reference, see § 250.198), is considered as certified SPPE under this part. All other SPPE is considered as not certified, unless approved in accordance with paragraph (c) of this section. (c) Accepting SPPE manufactured under other quality assurance programs. BSEE may exercise its discretion to accept SPPE manufactured under a quality assurance program other than ANSI/API Specification Q1, provided that the alternative quality assurance program is verified as equivalent to ANSI/API Specification Q1 by an appropriately qualified entity and that the operator submits a request to BSEE containing relevant information about the alternative program and receives BSEE approval. In addition, an operator may request that BSEE accept SPPE that is marked with a third-party certification mark other than the API monogram. All requests under this paragraph should be submitted to the Chief, Office of Offshore Regulatory Programs; Bureau of Safety and Environmental Enforcement; VAE-ORP; 45600 Woodland Road, Sterling, VA 20166.

§ 250.802 Requirements for SPPE. (a) All SSVs, BSDVs, USVs, and GLSDVs and their actuators must meet all of the specifications contained in API Specification 6A and API Standard 6AV1 (both incorporated by reference, see § 250.198). (b) All SSSVs and their actuators must meet all of the specifications and recommended practices of ANSI/API Specification 14A and ANSI/API Recommended Practice 14B, including all annexes (both incorporated by reference, see § 250.198). Subsurface-controlled SSSVs are not allowed on subsea wells. (c) Requirements derived from the documents incorporated in this section for SSVs, BSDVs, SSSVs, USVs, GLSDVs, and their actuators, include, but are not limited to, the following: (1) You must ensure that each device is designed to function in the conditions to which it may be exposed; including temperature, pressure, flow rates, and environmental conditions. (i) The device design must be tested by an independent test agency according to the test requirements in the appropriate standard for that device (API Standard 6AV1 or ANSI/API Specification 14A), as identified in paragraphs (a) and (b) of this section. (ii) You must maintain a description of the process you used to ensure the device is designed to function as required in paragraphs (a) and (c)(1) of this section and provide that description to BSEE upon request. (iii) If you remove any SPPE from service and install the device at a different location, you must have a qualified third party review and certify that each device will function as designed under the conditions to which it may be exposed. (2) All materials and parts must meet the original equipment manufacturer specifications and acceptance criteria. (3) The device must pass applicable validation tests and functional tests performed by an API-licensed test agency. (4) You must have requalification testing performed following manufacture design changes. (5) You must comply with and document all manufacturing, traceability, quality control, and inspection requirements. (6) You must follow specified installation, testing, and repair protocols. (7) You must use only qualified parts, procedures, and personnel to repair or redress equipment. (d) You must install and use SPPE according to the following table. (e) You must retain all documentation related to the manufacture, installation, testing, repair, redress, and performance of the SPPE until 1 year after the date of decommissioning of the equipment.

§ 250.803 What SPPE failure reporting procedures must I follow? (a) You must follow the failure reporting requirements contained in section 10.20.7.4 of API Specification 6A (incorporated by reference, see § 250.198) for SSVs, BSDVs, GLSDVs and USVs. You must follow the failure reporting requirements contained in section 7.10 of ANSI/API Specification 14A and Annex F of ANSI/API Recommended Practice 14B (both incorporated by reference, see § 250.198) for SSSVs. Within 30 days after the discovery and identification of the failure, you must provide a written notice of equipment failure to the manufacturer of such equipment and to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. A failure is any condition that prevents the equipment from meeting the functional specification or purpose. (b) You must ensure that an investigation and a failure analysis are performed within 120 days of the failure to determine the cause of the failure. If the investigation and analyses are performed by an entity other than the manufacturer, you must ensure that the analysis report is submitted to the manufacturer and to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. You must also ensure that the results of the investigation and any corrective action are documented in the analysis report. (c) If the equipment manufacturer notifies you that it has changed the design of the equipment that failed or if you have changed operating or repair procedures as a result of a failure, then you must, within 30 days of such changes, report the design change or modified procedures in writing to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. (d) BSEE may designate a third party to receive the data required by paragraphs (a) through (c) of this section on behalf of BSEE. If BSEE designates a third party, you must submit the information required in this section to the designated third party, as directed by BSEE.

§ 250.804 [Reserved]

§ 250.805 Hydrogen sulfide. (a) In zones known to contain hydrogen sulfide (H2S) or in zones where the presence of H2S is unknown, as defined in § 250.490, you must conduct production operations in accordance with that section and other relevant requirements of this subpart. (b) You must receive approval through the DWOP process (§§ 250.286 through 250.295) for production operations in HPHT environments known to contain H2S or in HPHT environments where the presence of H2S is unknown.

§§ 250.806-250.809 [Reserved]

§ 250.810 Dry tree subsurface safety devices—general. For wells using dry trees or for which you intend to install dry trees, you must equip all tubing installations open to hydrocarbon-bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless, after you submit a request containing a justification, the District Manager determines the well to be incapable of natural flow. You must install flow couplings above and below the subsurface safety devices. These subsurface safety devices include the following devices and any associated safety valve lock and landing nipple: (a) An SSSV, including either: (1) A surface-controlled SSSV; or (2) A subsurface-controlled SSSV. (b) An injection valve. (c) A tubing plug. (d) A tubing/annular subsurface safety device.

§ 250.811 Specifications for SSSVs—dry trees. All surface-controlled and subsurface-controlled SSSVs, safety valve locks, and landing nipples installed in the OCS must conform to the requirements specified in §§ 250.801 through 250.803.

§ 250.812 Surface-controlled SSSVs—dry trees. You must equip all tubing installations open to a hydrocarbon-bearing zone that is capable of natural flow with a surface-controlled SSSV, except as specified in §§ 250.813, 250.815, and 250.816. (a) The surface controls must be located on the site or at a BSEE-approved remote location. You may request District Manager approval to situate the surface controls at a remote location. (b) You must equip dry tree wells not previously equipped with a surface-controlled SSSV, and dry tree wells in which a surface-controlled SSSV has been replaced with a subsurface-controlled SSSV, with a surface-controlled SSSV when the tubing is first removed and reinstalled.

§ 250.813 Subsurface-controlled SSSVs. You may submit an APM or a request to the District Manager for approval to equip a dry tree well with a subsurface-controlled SSSV in lieu of a surface-controlled SSSV, if the subsurface-controlled SSSV is installed in a well equipped with a surface-controlled SSSV that has become inoperable and cannot be repaired without removal and reinstallation of the tubing. If you remove and reinstall the tubing, you must equip the well with a surface-controlled SSSV.

§ 250.814 Design, installation, and operation of SSSVs—dry trees. You must design, install, and operate (including repair, maintain, and test) an SSSV to ensure its reliable operation. (a) You must install the SSSV at a depth at least 100 feet below the mudline within 2 days after production is established. When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis. (b) The well must not be open to flow while the SSSV is inoperable, except when flowing the well is necessary for a particular operation such as cutting paraffin or performing other routine operations as defined in § 250.601. (c) Until the SSSV is installed, the well must be attended in the immediate vicinity so that any necessary emergency actions can be taken while the well is open to flow. During testing and inspection procedures, the well must not be left unattended while open to production unless you have installed a properly operating SSSV in the well. (d) You must design, install, maintain, inspect, repair, and test all SSSVs in accordance with ANSI/API Recommended Practice 14B (incorporated by reference, see § 250.198). For additional SSSV testing requirements, refer to § 250.880.

§ 250.815 Subsurface safety devices in shut-in wells—dry trees. (a) You must equip all new dry tree completions (perforated but not placed on production) and completions that are shut-in for a period of 6 months with one of the following: (1) A pump-through-type tubing plug; (2) A surface-controlled SSSV, provided the surface control has been rendered inoperative; or (3) An injection valve capable of preventing backflow. (b) When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, and paraffin problems, the District Manager must approve the setting depth of the subsurface safety device for a shut-in well on a case-by-case basis.

§ 250.816 Subsurface safety devices in injection wells—dry trees. You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.

§ 250.817 Temporary removal of subsurface safety devices for routine operations. (a) You may remove a wireline- or pumpdown-retrievable subsurface safety device without further authorization or notice, for a routine operation that does not require BSEE approval of a Form BSEE-0124, Application for Permit to Modify (APM). For a list of these routine operations, see § 250.601. The removal period must not exceed 15 days. (b) Prior to removal, you must identify the well by placing a sign on the wellhead stating that the subsurface safety device was removed. You must note the removal of the subsurface safety device in the records required by § 250.890. If the master valve is open, you must ensure that a trained person (see § 250.891) is in the immediate vicinity to attend the well and take any necessary emergency actions. (c) You must monitor a platform well when a subsurface safety device has been removed, but a person does not need to remain in the well-bay area continuously if the master valve is closed. If the well is on a satellite structure, it must be attended by a support vessel, or a pump-through plug must be installed in the tubing at least 100 feet below the mudline and the master valve must be closed, unless otherwise approved by the appropriate District Manager. (d) You must not allow the well to flow while the subsurface safety device is removed, except when it is necessary for the particular operation for which the SSSV is removed. The provisions of this paragraph are not applicable to the testing and inspection procedures specified in § 250.880.

§ 250.818 Additional safety equipment—dry trees. (a) You must equip all tubing installations that have a wireline- or pumpdown-retrievable subsurface safety device with a landing nipple, with flow couplings or other protective equipment above and below it to provide for the setting of the device. (b) The control system for all surface-controlled SSSVs must be an integral part of the platform emergency shutdown system (ESD). (c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location. Surface-controlled SSSVs must close in response to shut-in signals from the ESD and in response to the fire loop or other fire detection devices.

§ 250.819 Specification for surface safety valves (SSVs). All wellhead SSVs and their actuators must conform to the requirements specified in §§ 250.801 through 250.803.

§ 250.820 Use of SSVs. You must install, maintain, inspect, repair, and test all SSVs in accordance with API Standard 6AV2 (incorporated by reference, see § 250.198). If any SSV does not operate properly, or if any gas and/or liquid fluid flow is observed during the leakage test as described in § 250.880, then you must shut-in all sources to the SSV and repair or replace the valve before resuming production.

§ 250.821 Emergency action and safety system shutdown—dry trees. (a) If your facility is impacted or will potentially be impacted by an emergency situation (e.g., an impending National Weather Service-named tropical storm or hurricane, ice events, or post-earthquake), you must: (1) Properly install a subsurface safety device on any well that is not yet equipped with a subsurface safety device and that is capable of natural flow, as soon as possible, with due consideration being given to personnel safety. (2) You must shut-in (by closing the SSV and the surface-controlled SSSV) the following types of wells: (i) All oil wells, and (ii) All gas wells requiring compression. (b) Closure of the SSV must not exceed 45 seconds after automatic detection of an abnormal condition or actuation of an ESD. The surface-controlled SSSV must close within 2 minutes after the shut-in signal has closed the SSV. The District Manager must approve any alternative design-delayed closure time of greater than 2 minutes based on the mechanical/production characteristics of the individual well.

§§ 250.822-250.824 [Reserved]

§ 250.825 Subsea tree subsurface safety devices—general. (a) For wells using subsea (wet) trees or for which you intend to install subsea trees, you must equip all tubing installations open to hydrocarbon-bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency. You must also install flow couplings above and below the subsurface safety devices. For instances where the well at issue is incapable of natural flow, you may seek District Manager approval for using alternative procedures or equipment, if you propose to use a subsea safety system that is not capable of shutting off the flow from the well in the event of an emergency. Subsurface safety devices include the following and any associated safety valve lock and landing nipple: (1) A surface-controlled SSSV; (2) An injection valve; (3) A tubing plug; and (4) A tubing/annular subsurface safety device. (b) After installing the subsea tree, but before the rig or installation vessel leaves the area, you must test all valves and sensors to ensure that they are operating as designed and meet all the conditions specified in this subpart.

§ 250.826 Specifications for SSSVs—subsea trees. All SSSVs, safety valve locks, and landing nipples installed on the OCS must conform to the requirements specified in §§ 250.801 through 250.803 and any Deepwater Operations Plan (DWOP) required by §§ 250.286 through 250.295.

§ 250.827 Surface-controlled SSSVs—subsea trees. You must equip all tubing installations open to a hydrocarbon-bearing zone that is capable of natural flow with a surface-controlled SSSV, except as specified in §§ 250.829 and 250.830. The surface controls must be located on the host facility.

§ 250.828 Design, installation, and operation of SSSVs—subsea trees. You must design, install, and operate (including repair, maintain, and test) an SSSV to ensure its reliable operation. (a) You must install the SSSV at a depth at least 100 feet below the mudline. When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis. (b) The well must not be open to flow while an SSSV is inoperable, unless specifically approved by the District Manager in an APM. (c) You must design, install, maintain, inspect, repair, and test all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and ANSI/API Recommended Practice 14B (incorporated by reference, see § 250.198). For additional SSSV testing requirements, refer to § 250.880.

§ 250.829 Subsurface safety devices in shut-in wells—subsea trees. (a) You must equip all new subsea tree completions (perforated but not placed on production) and completions shut-in for a period of 6 months with one of the following: (1) A pump-through-type tubing plug; (2) An injection valve capable of preventing backflow; or (3) A surface-controlled SSSV, provided the surface control has been rendered inoperative. For purposes of this section, a surface-controlled SSSV is considered inoperative if, for a direct hydraulic control system, you have bled the hydraulics from the control line and have isolated it from the hydraulic control pressure. If your controls employ an electro-hydraulic control umbilical and the hydraulic control pressure to the individual well cannot be isolated, a surface-controlled SSSV is considered inoperative if you perform the following: (i) Disable the control function of the surface-controlled SSSV within the logic of the programmable logic controller which controls the subsea well; (ii) Place a pressure alarm high on the control line to the surface-controlled SSSV of the subsea well; and (iii) Close the USV and at least one other tree valve on the subsea well. (b) When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, and paraffin problems, the District Manager must approve the setting depth of the subsurface safety device for a shut-in well on a case-by-case basis.

§ 250.830 Subsurface safety devices in injection wells—subsea trees. You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.

§ 250.831 Alteration or disconnection of subsea pipeline or umbilical. If a necessary alteration or disconnection of the pipeline or umbilical of any subsea well would affect your ability to monitor casing pressure or to test any subsea valves or equipment, you must contact the appropriate District Office at least 48 hours in advance and submit a repair or replacement plan to conduct the required monitoring and testing. You must not alter or disconnect until the repair or replacement plan is approved.

§ 250.832 Additional safety equipment—subsea trees. (a) You must equip all tubing installations that have a wireline- or pump down-retrievable subsurface safety device installed after May 31, 1988, with a landing nipple, with flow couplings, or other protective equipment above and below it to provide for the setting of the device. (b) The control system for all surface-controlled SSSVs must be an integral part of the platform ESD. (c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location.

§ 250.833 Specification for underwater safety valves (USVs). All USVs, including those designated as primary or secondary, and any alternate isolation valve (AIV) that acts as a USV, if applicable, and their actuators, must conform to the requirements specified in §§ 250.801 through 250.803. A production master or wing valve may qualify as a USV under API Specification 6A and API Standard 6AV1 (both incorporated by reference, see § 250.198). (a) Primary USV (USV1). You must install and designate one USV on a subsea tree as the USV1. The USV1 must be located upstream of the choke valve. As provided in paragraph (b) of this section, you must inform BSEE if the primary USV designation changes. (b) Secondary USV (USV2). You may equip your tree with two or more valves qualified to be designated as a USV, one of which may be designated as the USV2. If the USV1 fails to operate properly or exhibits a leakage rate greater than allowed in § 250.880, you must notify the appropriate District Office and designate the USV2 or another qualified valve (e.g., an AIV) that meets all the requirements of this subpart for USVs as the USV1. The USV2 must be located upstream of the choke.

§ 250.834 Use of USVs. You must install, maintain, inspect, repair, and test any valve designated as the primary USV in accordance with this subpart, your DWOP (as specified in §§ 250.286 through 250.295), and API Standard 6AV2 (incorporated by reference, see § 250.198). For additional USV testing requirements, refer to § 250.880.

§ 250.835 Specification for all boarding shutdown valves (BSDVs) associated with subsea systems. You must install a BSDV on the pipeline boarding riser. All new BSDVs and any BSDVs removed from service for remanufacturing or repair and their actuators installed on the OCS must meet the requirements specified in §§ 250.801 through 250.803. In addition, you must: (a) Ensure that the internal design pressure(s) of the pipeline(s), riser(s), and BSDV(s) is fully rated for the maximum pressure of any input source and complies with the design requirements set forth in subpart J, unless BSEE approves an alternate design. (b) Use a BSDV that is fire rated for 30 minutes, and is pressure rated for the maximum allowable operating pressure (MAOP) approved in your pipeline application. (c) Locate the BSDV within 10 feet of the first point of access to the boarding pipeline riser (i.e., within 10 feet of the edge of platform if the BSDV is horizontal, or within 10 feet above the first accessible working deck, excluding the boat landing and above the splash zone, if the BSDV is vertical). (d) Install a temperature safety element (TSE) and locate it within 5 feet of each BSDV.

§ 250.836 Use of BSDVs. You must install, inspect, maintain, repair, and test all new BSDVs, as well as all BSDVs that you remove from service for remanufacturing or repair, in accordance with API Standard 6AV2 (incorporated by reference, see § 250.198) for SSVs. If any BSDV does not operate properly or if any gas fluid and/or liquid fluid flow is observed during the leakage test, as described in § 250.880, you must shut-in all sources to the BSDV and immediately repair or replace the valve.

§ 250.837 Emergency action and safety system shutdown—subsea trees. (a) If your facility is impacted or will potentially be impacted by an emergency situation (e.g., an impending National Weather Service-named tropical storm or hurricane, ice events, or post-earthquake), you must shut-in all subsea wells unless otherwise approved by the District Manager. A shut-in is defined as a closed BSDV, USV, GLSDV, and surface-controlled SSSV. (b) When operating a mobile offshore drilling unit (MODU) or other type of workover or intervention vessel in an area with subsea infrastructure, you must: (1) Suspend production from all wells that could be affected by a dropped object, including upstream wells that flow through the same pipeline; or (2) Establish direct, real-time communications between the MODU or other type of workover or intervention vessel and the production facility control room and develop a dropped objects plan, as required in § 250.714. If an object is dropped, you must immediately secure the well directly under the MODU or other type of workover or intervention vessel while simultaneously communicating with the platform to shut-in all affected wells. You must also maintain without disruption, and continuously verify, communication between the production facility and the MODU or other type of workover or intervention vessel. If communication is lost between the MODU or other type of workover or intervention vessel and the platform for 20 or more minutes, you must shut-in all wells that could be affected by a dropped object. (c) In the event of an emergency, you must operate your production system according to the valve closure times in the applicable tables in §§ 250.838 and 250.839 for the following conditions: (1) Process upset. In the event an upset in the production process train occurs downstream of the BSDV, you must close the BSDV in accordance with the applicable tables in §§ 250.838 and 250.839. You may reopen the BSDV to blow down the pipeline to prevent hydrates, provided you have secured the well(s) and ensured adequate protection. (2) Pipeline pressure safety high and low (PSHL) sensor. In the event that either a high or a low pressure condition is detected by a PSHL sensor located upstream of the BSDV, you must secure the affected well and pipeline, and all wells and pipelines associated with a dual or multi pipeline system, by closing the BSDVs, USVs, and surface-controlled SSSVs in accordance with the applicable tables in §§ 250.838 and 250.839. You must obtain approval from the appropriate District Manager to resume production in the unaffected pipeline(s) of a dual or multi pipeline system. If the PSHL sensor activation was a false alarm, you may return the wells to production without contacting the appropriate District Manager. (3) ESD/TSE (platform). In the event of an ESD activation that is initiated because of a platform ESD or platform TSE not associated with the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in accordance with the applicable tables in §§ 250.838 and 250.839. (4) Subsea ESD (platform) or BSDV TSE. In the event of an emergency shutdown activation that is initiated by the host platform due to an abnormal condition subsea, or a TSE associated with the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in accordance with the applicable tables in §§ 250.838 and 250.839. (5) Subsea ESD (MODU). In the event of an ESD activation that is initiated by a dropped object from a MODU or other type of workover or intervention vessel, you must secure all wells in the proximity of the MODU or other type of workover or intervention vessel by closing the USVs and surface-controlled SSSVs in accordance with the applicable tables in §§ 250.838 and 250.839. You must notify the appropriate District Manager before resuming production. (d) Following an ESD or fire, you must bleed your low pressure (LP) and high pressure (HP) hydraulic systems in accordance with the applicable tables in §§ 250.838 and 250.839 to ensure that the valves are locked out of service and cannot be reopened inadvertently.

§ 250.838 What are the maximum allowable valve closure times and hydraulic bleeding requirements for an electro-hydraulic control system? (a) If you have an electro-hydraulic control system, you must: (1) Design the subsea control system to meet the valve closure times listed in paragraphs (b) and (d) of this section or your approved DWOP; and (2) Verify the valve closure times upon installation. The District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV. (b) You must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP as long as communication is maintained with the platform or with the MODU or other type of workover vessel: Valve Closure Timing, Electro-Hydraulic Control System (c) If you have an electro-hydraulic control system and experience a loss of communications (EH Loss of Comms), you must comply with the following: (1) If you can meet the EH Loss of Comms valve closure timing conditions specified in the table in paragraph (d) of this section, you must notify the appropriate District Office within 12 hours of detecting the loss of communication. (2) If you cannot meet the EH Loss of Comms valve closure timing conditions specified in the table in paragraph (d) of this section, you must notify the appropriate District Office immediately after detecting the loss of communication. You must shut-in production by initiating a bleed of the low pressure (LP) hydraulic system or the high pressure (HP) hydraulic system within 120 minutes after loss of communication. You must bleed the other hydraulic system within 180 minutes after loss of communication. (3) You must obtain approval from the appropriate District Manager before continuing to produce after loss of communication when you cannot meet the EH Loss of Comms valve closure times specified in the table in paragraph (d) of this section. In your request, include an alternate valve closure timing table that your system is able to achieve. The appropriate District Manager may also approve an alternate hydraulic bleed schedule to allow for hydrate mitigation and orderly shut-in. (d) If you experience a loss of communications, you must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP: Valve Closure Timing, Electro-Hydraulic Control System With Loss of Communication

§ 250.839 What are the maximum allowable valve closure times and hydraulic bleeding requirements for a direct-hydraulic control system? (a) If you have a direct-hydraulic control system, you must: (1) Design the subsea control system to meet the valve closure times listed in this section or your approved DWOP; and (2) Verify the valve closure times upon installation. The District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV. (b) You must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP: Valve Closure Timing, Direct-Hydraulic Control System

§ 250.840 Design, installation, and maintenance—general. You must design, install, and maintain all production facilities and equipment including, but not limited to, separators, treaters, pumps, heat exchangers, fired components, wellhead injection lines, compressors, headers, and flowlines in a manner that is efficient, safe, and protects the environment.

§ 250.841 Platforms. (a) You must protect all platform production facilities with a basic and ancillary surface safety system designed, analyzed, installed, tested, and maintained in operating condition in accordance with the provisions of Recommended Practice 14C (incorporated by reference, see § 250.198). If you use processing components other than those for which Safety Analysis Checklists are included in Recommended Practice 14C, you must utilize the analysis technique and documentation specified in Recommended Practice 14C to determine the effects and requirements of these components on the safety system. Safety device requirements for pipelines are contained in § 250.1004. (b) You must design, install, inspect, repair, test, and maintain in operating condition all platform production process piping in accordance with Recommended Practice 14E and API 570 (both incorporated by reference, see § 250.198). The District Manager may approve temporary repairs to facility piping on a case-by-case basis for a period not to exceed 30 days. (c) If you plan to make a modification to any production safety system that also involves a major modification to the platform structure, you must follow the requirements in § 250.900(b)(2). A major modification to a platform structure is defined in § 250.900(b)(2).

§ 250.842 Approval of safety systems design and installation features. (a) Before you install or modify a production safety system, you must submit a production safety system application to the District Manager. The District Manager must approve your production safety system application before you commence production through or otherwise use the new or modified system. The application must include the design documentation prescribed as follows: (b) You must develop and maintain the following design documents and make them available to BSEE upon request: (c) In the production safety system application, you must also certify the following: (1) That all electrical systems were designed according to Recommended Practice 14F or Recommended Practice 14FZ, as applicable (incorporated by reference, see § 250.198); (2) That the design documents for the mechanical and electrical systems that you are required to submit under paragraph (a) of this section are sealed by a licensed professional engineer. For modified systems, only the modifications are required to be sealed by a licensed professional engineer(s). The professional engineer must be licensed in a State or Territory of the United States and have sufficient expertise and experience to perform the duties; and (3) That a hazards analysis was performed in accordance with § 250.1911 and Recommended Practice 14J (incorporated by reference, see § 250.198), and that you have a hazards analysis program in place to assess potential hazards during the operation of the facility. (d) Within 90 days after placing new or modified production safety systems in service, you must submit to the District Manager the as-built diagrams for the new or modified production safety systems outlined in paragraphs (a)(1), (2), and (3) of this section. You must certify in an accompanying letter that the as-built design documents have been reviewed for compliance with applicable regulations and accurately represent the new or modified system as installed. The drawings must be clearly marked “as-built.” (e) You must maintain approved and supporting design documents required under paragraphs (a) and (b) of this section at your offshore field office nearest the OCS facility or at other locations conveniently available to the District Manager. These documents must be made available to BSEE upon request and must be retained for the life of the facility. All approved designs are subject to field verifications.

§§ 250.843-250.849 [Reserved]

§ 250.850 Production system requirements—general. You must comply with the production safety system requirements in §§ 250.851 through 250.872, in addition to the practices contained in API Recommended Practice 14C (incorporated by reference, see § 250.198).

§ 250.851 Pressure vessels (including heat exchangers) and fired vessels. (a) Pressure vessels (including heat exchangers) and fired vessels supporting production operations must meet the requirements in the following table: (b) Operating pressure ranges. You must use pressure recording devices to establish the new operating pressure ranges of pressure vessels at any time that the normalized system pressure changes by 50 psig or 5 percent. Once system pressure has stabilized, pressure recording devices must be utilized to establish the new operating pressure ranges. The pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long. You must maintain the pressure recording information you used to determine current operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager for as long as the information is valid. (c) Pressure shut-in sensors must be set according to the following table (initial set points for pressure sensors must be set utilizing gauge readings and engineering design):

§ 250.852 Flowlines/Headers. (a) You must: (1) Equip flowlines from wells with both PSH and PSL sensors. You must locate these sensors in accordance with section A.1 of APR Recommended Practice 14 C (incorporated by reference, see § 250.198). (2) Use pressure recording devices to establish the new operating pressure ranges of flowlines at any time when the normalized system pressure changes by 50 psig or 5 percent, whichever is higher. The pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long. (3) Maintain the most recent pressure recording information you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager for as long as the information is valid. (b) Flowline shut-in sensors must meet the requirements in the following table (initial set points for pressure sensors must be set using gauge readings and engineering design): (c) If a well flows directly to a pipeline before separation, the flowline and valves from the well located upstream of and including the header inlet valve(s) must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the flowline is protected by one of the following: (1) A relief valve which vents into the platform flare scrubber or some other location approved by the District Manager. You must design the platform flare scrubber to handle, without liquid-hydrocarbon carryover to the flare, the maximum-anticipated flow of hydrocarbons that may be relieved to the vessel; or (2) Two SSVs with independent PSH sensors connected to separate relays and sensing points and installed with adequate volume upstream of any block valve to allow sufficient time for the SSVs to close before exceeding the maximum allowable working pressure. Each independent PSH sensor must close both SSVs along with any associated flowline PSL sensor. If the maximum shut-in pressure of a dry tree satellite well(s) is greater than 1 1/2 times the maximum allowable pressure of the pipeline, a pressure safety valve (PSV) of sufficient size and relief capacity to protect against any SSV leakage or fluid hammer effect may be required by the District Manager. The PSV must be installed upstream of the host platform boarding valve and vent into the platform flare scrubber or some other location approved by the District Manager. (d) If a well flows directly to the pipeline from a header without prior separation, the header, the header inlet valves, and pipeline isolation valve must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the header is protected by the safety devices as outlined in paragraph (c) of this section. (e) If you are installing flowlines constructed of unbonded flexible pipe on a floating platform, you must: (1) Review the manufacturer's Design Methodology Verification Report and the independent verification agent's (IVA) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements of API Specification 17J (incorporated by reference, see § 250.198); (2) Determine that the unbonded flexible pipe is suitable for its intended purpose; (3) Submit to the District Manager the manufacturer's design specifications for the unbonded flexible pipe; and (4) Submit to the District Manager a statement certifying that the pipe is suitable for its intended use and that the manufacturer has complied with the IVA requirements of API Specification 17J (incorporated by reference, see § 250.198). (f) Automatic pressure or flow regulating choking devices must not prevent the normal functionality of the process safety system that includes, but is not limited to, the flowline pressure safety devices and the SSV. (g) You may install a single flow safety valve (FSV) on the platform to protect multiple subsea pipelines or wells that tie into a single pipeline riser provided that you install an FSV for each riser on the platform and test it in accordance with the criteria prescribed in § 250.880(c)(2)(v). (h) You may install a single PSHL sensor on the platform to protect multiple subsea pipelines that tie into a single pipeline riser provided that you install a PSHL sensor for each riser on the platform and locate it upstream of the BSDV.

§ 250.853 Safety sensors. You must ensure that: (a) All shutdown devices, valves, and pressure sensors function in a manual reset mode; (b) Sensors with integral automatic reset are equipped with an appropriate device to override the automatic reset mode; (c) All pressure sensors are equipped to permit testing with an external pressure source; and (d) All level sensors are equipped to permit testing through an external bridle on all new vessel installations where possible, depending on the type of vessel for which the level sensor is used.

§ 250.854 Floating production units equipped with turrets and turret-mounted systems. (a) For floating production units equipped with an auto slew system, you must integrate the auto slew control system with your process safety system allowing for automatic shut-in of the production process, including the sources (subsea wells, subsea pumps, etc.) and releasing of the buoy. Your safety system must immediately initiate a process system shut-in according to §§ 250.838 and 250.839 and release the buoy to prevent hydrocarbon discharge and damage to the subsea infrastructure when the following are encountered: (1) Your buoy is clamped, (2) Your auto slew mode is activated, and (3) You encounter a ship heading/position failure or an exceedance of the rotational tolerances of the clamped buoy. (b) For floating production units equipped with swivel stack arrangements, you must equip the portion of the swivel stack containing hydrocarbons with a leak detection system. Your leak detection system must be tied into your production process surface safety system allowing for automatic shut-in of the system. Upon seal system failure and detection of a hydrocarbon leak, your surface safety system must immediately initiate a process system shut-in according to §§ 250.838 and 250.839.

§ 250.855 Emergency shutdown (ESD) system. The ESD system must conform to the requirements of Appendix C, section C1, of API Recommended Practice 14C (incorporated by reference, see § 250.198), and the following: (a) The manually operated ESD valve(s) must be quick-opening and non-restricted to enable the rapid actuation of the shutdown system. Electronic ESD stations must be wired as de-energize to trip circuits or as supervised circuits. Because of the key role of the ESD system in the platform safety system, all ESD components must be of high quality and corrosion resistant and stations must be uniquely identified. Only ESD stations at the boat landing may utilize a loop of breakable synthetic tubing in lieu of a valve or electric switch. This breakable loop is not required to be physically located on the boat landing, but must be accessible from a vessel adjacent to or attached to the facility. (b) You must maintain a schematic of the ESD that indicates the control functions of all safety devices for the platforms on the platform, at your field office nearest the OCS facility, or at another location conveniently available to the District Manager, for the life of the facility.

§ 250.856 Engines. (a) Engine exhaust. You must equip all engine exhausts to comply with the insulation and personnel protection requirements of API Recommended Practice 14C, section 4.2 (incorporated by reference, see § 250.198). You must equip exhaust piping from diesel engines with spark arresters. (b) Diesel engine air intake. You must equip diesel engine air intakes with a device to shut down the diesel engine in the event of runaway (i.e., overspeed). You must equip diesel engines that are continuously attended with either remotely operated manual or automatic shutdown devices. You must equip diesel engines that are not continuously attended with automatic shutdown devices. The following diesel engines do not require a shutdown device: Engines for fire water pumps; engines on emergency generators; engines that power BOP accumulator systems; engines that power air supply for confined entry personnel; temporary equipment on non-producing platforms; booster engines whose purpose is to start larger engines; and engines that power portable single cylinder rig washers.

§ 250.857 Glycol dehydration units. (a) You must install a pressure relief system or an adequate vent on the glycol regenerator (reboiler) to prevent over pressurization. The discharge of the relief valve must be vented in a nonhazardous manner. (b) You must install the FSV on the dry glycol inlet to the glycol contact tower as near as practical to the glycol contact tower. (c) You must install the shutdown valve (SDV) on the wet glycol outlet from the glycol contact tower as near as practical to the glycol contact tower.

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