Title 30—Mineral Resources--Volume 1
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 Mexico means all OCS areas of the Gulf of Mexico the BOEM Director decides are adjacent to the State of Florida. The Eastern Gulf of Mexico 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.
H 2 S absent means:
(1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H 2 S in concentrations that could potentially result in atmospheric concentrations of 20 ppm or more of H 2 S; or
(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an absence of H 2 S throughout the area to be drilled.
H 2 S present means drilling, logging, coring, testing, or producing operations have confirmed the presence of H 2 S in concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of H 2 S.
H 2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H 2 S 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 Mexico means all OCS areas of the Gulf of Mexico except those the BOEM Director decides are adjacent to the State of Florida. The Western Gulf of Mexico 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 RP 2D (as incorporated by reference in § 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 Spec 2C (as incorporated by reference in § 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.
§ 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 RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2 (as incorporated by reference in § 250.198), or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2 (as incorporated by reference in § 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 RP 14F, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1, and Division 2 Locations (as incorporated by reference in § 250.198), or API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1, and Zone 2 Locations (as incorporated by reference in § 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 Mexico 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 GOM 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 § 250.1603 (SOP only), 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 (H 2 S) 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 e-mail (for activities in the BSEE GOM OCS Region, use Form BSEE-0132) as soon as possible when evacuation occurs. In lieu of submitting your statistics by fax or e-mail, 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 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. 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: http://www.concrete.org; phone: 248-848-3700:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced Concrete, 1995; incorporated by reference at § 250.901.
(2) ACI 318R-95, Commentary on Building Code Requirements for Reinforced Concrete, 1995; incorporated by reference at § 250.901.
(3) ACI 357R-84, Guide for the Design and Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997, incorporated by reference at § 250.901.
(b) American Gas Association (AGA Reports), 400 North Capitol Street NW, Suite 450, Washington, DC 20001, http://www.aga.org; phone: 202-824-7000;
(1) AGA Report No. 7—Measurement of Natural Gas by Turbine Meters; Revised February 2006; incorporated by reference at § 250.1203(b);
(2) AGA Report No. 9—Measurement of Gas by Multipath Ultrasonic Meters; Second Edition, April 2007; incorporated by reference at § 250.1203(b);
(3) AGA Report No. 10—Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases; Copyright 2003; incorporated by reference at § 250.1203(b).
(c) American Institute of Steel Construction, Inc. (AISC), AISC Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802; http://www.aisc.org; phone: 312-670-2400:
(1) ANSI/AISC 360-05, Specification for Structural Steel Buildings, incorporated by reference at § 250.901.
(2) [Reserved]
(d) American National Standards Institute (ANSI), http.www./webstore.ansi.org/; phone: 212-642-4900:
(1) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings, incorporated by reference at § 250.1002;
(2) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping Systems, incorporated by reference at § 250.1002;
(3) ANSI Z88.2-1992, American National Standard for Respiratory Protection, incorporated by reference at § 250.490.
(e) American Petroleum Institute (API), API Recommended Practices (RP), Specs, Standards, Manual of Petroleum Measurement Standards (MPMS) chapters, 1220 L Street, NW, Washington, DC 20005-4070; http://www.api.org; phone: 202-682-8000:
(1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Tenth Edition, May 2014; Addendum 1, May 2017; incorporated by reference at §§ 250.851(a) and 250.1629(b);
(2) API 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, Fourth Edition, February 2016; Addendum 1, May 2017; incorporated by reference at § 250.841(b).
(3) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore Structures for Hurricane Conditions, May 2007; incorporated by reference at § 250.901;
(4) API Bulletin 2INT-EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurricane Conditions, May 2007; incorporated by reference at § 250.901;
(5) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico, May 2007; incorporated by reference at § 250.901;
(6) API Bulletin 92L, Drilling Ahead Safely with Lost Circulation in the Gulf of Mexico, First Edition, August 2015; incorporated by reference at § 250.427(b);
(7) API MPMS Chapter 1—Vocabulary, Second Edition, July 1994; incorporated by reference at § 250.1201;
(8) 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; incorporated by reference at § 250.1202;
(9) 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); incorporated by reference at § 250.1202;
(10) API MPMS Chapter 3—Tank Gauging, Section 1A—Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005; incorporated by reference at § 250.1202;
(11) 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; incorporated by reference at § 250.1202;
(12) API MPMS Chapter 4—Proving Systems, Section 1—Introduction, Third Edition, February 2005; reaffirmed June 2014; incorporated by reference at § 250.1202;
(13) API MPMS Chapter 4—Proving Systems, Section 2—Displacement Provers, Third Edition, September 2003; incorporated by reference at § 250.1202;
(14) API MPMS Chapter 4—Proving Systems, Section 4—Tank Provers, Second Edition, May 1998, reaffirmed May 2015; incorporated by reference at § 250.1202;
(15) API MPMS Chapter 4—Proving Systems, Section 5—Master-Meter Provers, Second Edition, May 2000, reaffirmed, August 2005; incorporated by reference at § 250.1202;
(16) API MPMS Chapter 4—Proving Systems, Section 6—Pulse Interpolation, Second Edition, May 1999; Errata April 2007; reaffirmed October 2013; incorporated by reference at § 250.1202;
(17) API MPMS Chapter 4—Proving Systems, Section 7—Field Standard Test Measures, Second Edition, December 1998; reaffirmed 2003; incorporated by reference at § 250.1202;
(18) API MPMS Chapter 4—Proving Systems, Section 8—Operation of Proving Systems; First Edition, reaffirmed March 2007; incorporated by reference at § 250.1202(a), (f), and (g);
(19) API MPMS Chapter 5—Metering, Section 1—General Considerations for Measurement by Meters, Fourth Edition, September 2005; incorporated by reference at § 250.1202;
(20) API MPMS Chapter 5—Metering, Section 2—Measurement of Liquid Hydrocarbons by Displacement Meters, Third Edition, September 2005; reaffirmed July 2015; incorporated by reference at § 250.1202;
(21) API MPMS Chapter 5—Metering, Section 3—Measurement of Liquid Hydrocarbons by Turbine Meters, Fifth Edition, September 2005; reaffirmed August 1, 2014; incorporated by reference at § 250.1202;
(22) API MPMS Chapter 5—Metering, Section 4—Accessory Equipment for Liquid Meters, Fourth Edition, September 2005; reaffirmed August 2015; incorporated by reference at § 250.1202;
(23) API MPMS Chapter 5—Metering, Section 5—Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, August 2005; reaffirmed August 2015; incorporated by reference at § 250.1202;
(24) API MPMS Chapter 5—Metering, Section 6—Measurement of Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002; reaffirmed November 2013; incorporated by reference at § 250.1202;
(25) API MPMS Chapter 5—Metering, Section 8—Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters Using Transit Time Technology; First Edition, February 2005; incorporated by reference at § 250.1202(a);
(26) API MPMS Chapter 6—Metering Assemblies, Section 1—Lease Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; reaffirmed May 2012; incorporated by reference at § 250.1202;
(27) API MPMS Chapter 6—Metering Assemblies, Section 6—Pipeline Metering Systems, Second Edition, May 1991; reaffirmed December 2017; incorporated by reference at § 250.1202;
(28) API MPMS Chapter 6—Metering Assemblies, Section 7—Metering Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed March 2018; incorporated by reference at § 250.1202;
(29) API MPMS Chapter 7—Temperature Determination, First Edition, June 2001; reaffirmed, March 2007; incorporated by reference at § 250.1202;
(30) API MPMS Chapter 8—Sampling, Section 1—Standard Practice for Manual Sampling of Petroleum and Petroleum Products, Third Edition, October 1995; reaffirmed, March 2006; incorporated by reference at § 250.1202;
(31) API MPMS Chapter 8—Sampling, Section 2—Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products, Second Edition, October 1995; reaffirmed, June 2005; incorporated by reference at § 250.1202;
(32) API MPMS Chapter 9—Density Determination, Section 1—Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, Second Edition, December 2002; reaffirmed October 2005; incorporated by reference at § 250.1202(a) and (l);
(33) API MPMS Chapter 9—Density Determination, Section 2—Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer, Second Edition, March 2003; incorporated by reference at § 250.1202;
(34) 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; incorporated by reference at § 250.1202;
(35) API MPMS Chapter 10—Sediment and Water, Section 2—Standard Test Method for Water in Crude Oil by Distillation, Second Edition, November 2007; incorporated by reference at § 250.1202;
(36) API MPMS Chapter 10—Sediment and Water, Section 3—Standard Test Method for Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure), Third Edition, May 2008; incorporated by reference at § 250.1202;
(37) API MPMS Chapter 10—Sediment and Water, Section 4—Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure), Third Edition, December 1999; incorporated by reference at § 250.1202;
(38) API MPMS Chapter 10—Sediment and Water, Section 9—Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration, Second Edition, December 2002; reaffirmed 2005; incorporated by reference at § 250.1202;
(39) 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; incorporated by reference at § 250.1202;
(40) 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; incorporated by reference at § 250.1202;
(41) 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 (incorporating Addendum 1, September 2007); incorporated by reference at § 250.1202(a), (g), and (l);
(42) 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; incorporated by reference at § 250.1202;
(43) 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; incorporated by reference at § 250.1202;
(44) 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; incorporated by reference at § 250.1202;
(45) 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 Reports; First Edition, October 1998, reaffirmed March 2014; incorporated by reference at § 250.1202(a) and (g);
(46) 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; incorporated by reference at § 250.1202(a), (f), and (g);
(47) API MPMS Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 1—General Equations and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed, January 2003; incorporated by reference at § 250.1203;
(48) API MPMS Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 2—Specification and Installation Requirements, Fourth Edition, April 2000; reaffirmed March 2006; incorporated by reference at § 250.1203;
(49) API MPMS Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters; Part 3—Natural Gas Applications; Third Edition, August 1992; Errata March 1994, reaffirmed, February 2009; incorporated by reference at § 250.1203;
(50) 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; incorporated by reference at § 250.1203;
(51) API MPMS Chapter 14—Natural Gas Fluids Measurement, Section 6—Continuous Density Measurement, Second Edition, April 1991; reaffirmed, February 2006; incorporated by reference at § 250.1203;
(52) API MPMS Chapter 14—Natural Gas Fluids Measurement, Section 8—Liquefied Petroleum Gas Measurement, Second Edition, July 1997; reaffirmed, March 2006; incorporated by reference at § 250.1203;
(53) API MPMS Chapter 20—Section 1—Allocation Measurement, First Edition, September 1993; reaffirmed October 2006; incorporated by reference at § 250.1202;
(54) API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 1—Electronic Gas Measurement, First Edition, August 1993; reaffirmed, July 2005; incorporated by reference at § 250.1203;
(55) 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; incorporated by reference at § 250.1202(a);
(56) 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; incorporated by reference at § 250.1202(a);
(57) API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design, Twenty-first Edition, December 2000; Errata and Supplement 1, December 2002; Errata and Supplement 2, September 2005; Errata and Supplement 3, October 2007; incorporated by reference at §§ 250.901, 250.908, 250.919, and 250.920;
(58) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth Edition, May 2007; incorporated by reference at § 250.108;
(59) API RP 2FPS, RP for Planning, Designing, and Constructing Floating Production Systems; First Edition, March 2001; incorporated by reference at § 250.901;
(60) API RP 2I, In-Service Inspection of Mooring Hardware for Floating Structures; Third Edition, April 2008; incorporated by reference at § 250.901(a) and (d);
(61) ANSI/API RP 2N, Third Edition, “Recommended Practice for Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions”, Third Edition, April 2015; incorporated by reference at § 250.470(g);
(62) API RP 2RD, Recommended Practice for Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; incorporated by reference at §§ 250.733, 250.800(c), 250.901(a), (d), and 250.1002(b);
(63) API RP 2SK, Design and Analysis of Stationkeeping Systems for Floating Structures, Third Edition, October 2005, Addendum, May 2008, reaffirmed June 2015; incorporated by reference at §§ 250.800(c) and 250.901(a) and (d);
(64) API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by reference at §§ 250.800(c) and 250.901(a) and (d);
(65) API RP 2T, Recommended Practice for Planning, Designing, and Constructing Tension Leg Platforms, Second Edition, August 1997; incorporated by reference at § 250.901(a) and (d);
(66) ANSI/API RP 14B, Design, Installation, Operation, Test, and Redress of Subsurface Safety Valve Systems, Sixth Edition, September 2015; incorporated by reference at §§ 250.802(b), 250.803(a), 250.814(d), 250.828(c), and 250.880(c);
(67) API RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Seventh Edition, March 2001, reaffirmed: March 2007; incorporated by reference at §§ 250.125(a), 250.292(j), 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), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
(68) API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1991; reaffirmed, January 2013; incorporated by reference at §§ 250.841(b), 250.842(a), and 250.1628(b) and (d);
(69) API RP 14F, Recommended Practice for 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; incorporated by reference at §§ 250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
(70) API RP 14FZ, Recommended Practice for 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; incorporated by reference at §§ 250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
(71) API RP 14G, Recommended Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms, Fourth Edition, April 2007; Reaffirmed, January 2013; incorporated by reference at §§ 250.859(a), 250.862(e), 250.880(c), and 250.1629(b);
(72) API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, Second Edition, May 2001; reaffirmed: January 2013; incorporated by reference at §§ 250.800(b) and (c), 250.842(c), and 250.901(a) and (d);
(73) API RP 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems, Second Edition, June 2013; Errata, January 2014; incorporated by reference at § 250.734(a);
(74) API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deepwater Wells, First Edition, September 2002; incorporated by reference at § 250.415;
(75) API RP 75, Recommended Practice for Development of a Safety and Environmental Management Program for Offshore Operations and Facilities, Third Edition, May 2004, reaffirmed May 2008; incorporated by reference at §§ 250.1900, 250.1902, 250.1903, 250.1909, 250.1920;
(76) API RP 86, API Recommended Practice for Measurement of Multiphase Flow; First Edition, September 2005; incorporated by reference at §§ 250.1202(a) and 250.1203(b);
(77) API RP 90, Annular Casing Pressure Management for Offshore Wells, First Edition, August 2006; incorporated by reference at § 250.519;
(78) API RP 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, incorporated by reference at §§ 250.114(a), 250.459, 250.842(a), 250.862(a) and (e), 250.872(a), 250.1628(b) and (d), and 250.1629(b);
(79) API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition, November 1997; reaffirmed, August 2013; incorporated by reference at §§ 250.114(a), 250.459, 250.842(a), 250.862(a) and (e), 250.872(a), 250.1628(b) and (d), and 250.1629(b);
(80) API RP 2556, Recommended Practice for Correcting Gauge Tables for Incrustation, Second Edition, August 1993; reaffirmed November 2003; incorporated by reference at § 250.1202;
(81) API Spec. 2C, Specification for Offshore Pedestal Mounted Cranes, Sixth Edition, March 2004, Effective Date: September 2004; incorporated by reference at § 250.108;
(82) ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment, Twentieth Edition, October 2010; Addendum 1, November 2011; Errata 2, November 2011; Addendum 2, November 2012; Addendum 3, March 2013; Errata 3, June 2013; Errata 4, August 2013; Errata 5, November 2013; Errata 6, March 2014; Errata 7, December 2014; Errata 8, February 2016; Addendum 4, June 2016; Errata 9, June 2016; Errata 10, August 2016; incorporated by reference at §§ 250.518(c), 250.619(c), 250.730, 250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g); 250.1002(b).
(83) API Spec. 6AV1, Specification for Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, Second Edition, February 2013; incorporated by reference at §§ 250.802(a), 250.833, 250.873(b), and 250.874(g);
(84) API STD 6AV2, Installation, Maintenance, and Repair of Surface Safety Valves and Underwater Safety Valves Offshore; First Edition, March 2014; Errata 1, August 2014; incorporated by reference at §§ 250.820, 250.834, 250.836, and 250.880(c)
(85) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-third Edition, April 2008; Effective Date: October 1, 2008, Errata 1, June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum 1, October 2009; Contains API Monogram Annex as Part of U.S. National Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas industries—Pipeline transportation systems—Pipeline valves; incorporated by reference at § 250.1002(b);
(86) ANSI/API Spec. 11D1, Packers and Bridge Plugs, Third Edition, April 2015; including Errata 1, August 2019; incorporated by reference at §§ 250.518(e), 250.619(e); 250.1703.
(87) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve Equipment, Eleventh Edition, October 2005, reaffirmed, June 2012; incorporated by reference at §§ 250.802 and 250.803(a);
(88) ANSI/API Spec. 16A, Specification for Drill-through Equipment, Third Edition, June 2004, reaffirmed August 2010; incorporated by reference at § 250.730;
(89) ANSI/API Spec. 16C, Specification for Choke and Kill Systems, First Edition, January 1993, reaffirmed July 2010; incorporated by reference at § 250.730;
(90) API Spec. 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment, Second Edition, July 2004, reaffirmed August 2013; incorporated by reference at § 250.730;
(91) ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment, Second Edition, Reaffirmed November 2018; Addendum 1, September 2015; Errata, September 2011; Errata 2, January 2012; Errata 3, June 2013; Errata 4, July 2013; Errata 5, October 2013; Errata 6, August 2015; Errata 7, October 2015; incorporated by reference at §§ 250.518(c); 250.619(c); 250.730.
(92) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008, incorporated by reference at §§ 250.852(e), 250.1002(b), and 250.1007(a).
(93) ANSI/API Spec. 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; incorporated by reference at §§ 250.730 and 250.801(b) and (c);
(94) API Standard 53, Blowout Prevention Equipment Systems for Drilling Wells, Fourth Edition, November 2012, Addendum 1, July 2016, incorporated by reference at §§ 250.730, 250.734, 250.735, 250.736, 250.737, and 250.739;
(95) API Standard 65—Part 2, Isolating Potential Flow Zones During Well Construction; Second Edition, December 2010; incorporated by reference at §§ 250.415(f) and 250.420(a);
(96) API Standard 2552, USA Standard Method for Measurement and Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, October 2007; incorporated by reference at § 250.1202;
(97) API Standard 2555, Method for Liquid Calibration of Tanks, First Edition, September 1966; reaffirmed March 2002; incorporated by reference at § 250.1202;
(f) American Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, NJ 07007-2900; http://www.asme.org; phone: 1-800-843-2763.
(1) 2017 ASME Boiler and Pressure Vessel Code (BPVC), Section I, Rules for Construction of Power Boilers, 2017 Edition, July 1, 2017, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(2) 2017 ASME Boiler and Pressure Vessel Code, Section IV, Rules for Construction of Heating Boilers, 2017 Edition, July 1, 2017, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(3) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Division 1, 2017 Edition; July 1, 2017, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(4) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Division 2: Alternative Rules, 2017 Edition, July 1, 2017, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(5) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Division 3: Alternative Rules for Construction of High Pressure Vessels, 2017 Edition, July 1, 2017, incorporated by reference at §§ 250.851(a) and 250.1629(b).
(g) American Society for Testing and Materials (ASTM), ASTM Standards, 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428-2959; http://www.astm.org; phone: 1-877-909-2786:
(1) ASTM Standard C 33-07, approved December 15, 2007, Standard Specification for Concrete Aggregates; incorporated by reference at § 250.901;
(2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard Specification for Ready-Mixed Concrete; incorporated by reference at § 250.901;
(3) ASTM Standard C 150-07, approved May 1, 2007, Standard Specification for Portland Cement; incorporated by reference at § 250.901;
(4) ASTM Standard C 330-05, approved December 15, 2005, Standard Specification for Lightweight Aggregates for Structural Concrete; incorporated by reference at § 250.901;
(5) ASTM Standard C 595-08, approved January 1, 2008, Standard Specification for Blended Hydraulic Cements; incorporated by reference at § 250.901;
(h) American Welding Society   (AWS), AWS Codes, 8669 NW 36 Street, #130, Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
(1) AWS D1.1:2000, Structural Welding Code—Steel, 17th Edition, October 18, 1999; incorporated by reference at § 250.901;
(2) AWS D1.4-98, Structural Welding Code—Reinforcing Steel, 1998 Edition; incorporated by reference at § 250.901;
(3) AWS D3.6M:1999, Specification for Underwater Welding (1999); incorporated by reference at § 250.901.
(i) National Association of Corrosion Engineers (NACE) International, NACE Standards, Park Ten Place, Houston, TX 77084; http://www.nace.org; phone: 281-228-6200:
(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; incorporated by reference at §§ 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; incorporated by reference at § 250.901.
(j) International Organization for Standardization (ISO), 1, ch. de la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; www.iso.org; phone: 41-22-749-01-11:
(1) ISO/IEC (International Electrotechnical Commission) 17011, Conformity assessment—General requirements for accreditation bodies accrediting conformity assessment bodies, First edition 2004-09-01; Corrected version 2005-02-15; incorporated by reference at §§ 250.1900, 250.1903, 250.1904, and 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, incorporated by reference at § 250.730(d).
(3) [Reserved]
(k) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite 1370, Houston, TX 77056; www.centerforoffshoresafety.org; phone: 832-495-4925.
(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; incorporated by reference at §§ 250.1900, 250.1903, 250.1904, and 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; incorporated by reference at §§ 250.1900, 250.1903, 250.1904, and 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; incorporated by reference at §§ 250.1900, 250.1903, 250.1904, and 250.1922.
§ 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 (H 2 S), Carbon dioxide (CO 2 ), 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 RP 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deep Water Wells (as incorporated by reference in § 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 (as incorporated by reference in § 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 (as incorporated by reference in § 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 (as incorporated by reference in § 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.