Title 30—Mineral Resources--Volume 1
PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF
§ 250.458   What quantities of drilling fluids are required?
(a) You must use, maintain, and replenish quantities of drilling fluid and drilling fluid materials at the drill site as necessary to ensure well control. You must determine those quantities based on known or anticipated drilling conditions, rig storage capacity, weather conditions, and estimated time for delivery.
(b) You must record the daily inventories of drilling fluid and drilling fluid materials, including weight materials and additives in the drilling fluid report.
(c) If you do not have sufficient quantities of drilling fluid and drilling fluid material to maintain well control, you must suspend drilling operations.
§ 250.459   What are the safety requirements for drilling fluid-handling areas?
You must classify drilling fluid-handling areas according to API 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 1, Zone 0, Zone 1, and Zone 2 (as incorporated by reference in § 250.198). In areas where dangerous concentrations of combustible gas may accumulate, you must install and maintain a ventilation system and gas monitors. Drilling fluid-handling areas must have the following safety equipment:
(a) A ventilation system capable of replacing the air once every 5 minutes or 1.0 cubic feet of air-volume flow per minute, per square foot of area, whichever is greater. In addition:
(1) If natural means provide adequate ventilation, then a mechanical ventilation system is not necessary;
(2) If a mechanical system does not run continuously, then it must activate when gas detectors indicate the presence of 1 percent or more of combustible gas by volume; and
(3) If discharges from a mechanical ventilation system may be hazardous, then you must maintain the drilling fluid-handling area at a negative pressure. You must protect the negative pressure area by using at least one of the following: a pressure-sensitive alarm, open-door alarms on each access to the area, automatic door-closing devices, air locks, or other devices approved by the District Manager;
(b) Gas detectors and alarms except in open areas where adequate ventilation is provided by natural means. You must test and recalibrate gas detectors quarterly. No more than 90 days may elapse between tests;
(c) Explosion-proof or pressurized electrical equipment to prevent the ignition of explosive gases. Where you use air for pressuring equipment, you must locate the air intake outside of and as far as practicable from hazardous areas; and
(d) Alarms that activate when the mechanical ventilation system fails.
§ 250.460   What are the requirements for conducting a well test?
(a) If you intend to conduct a well test, you must include your projected plans for the test with your APD (form BSEE-0123) or in an Application for Permit to Modify (APM) (form BSEE-0124). Your plans must include at least the following information:
(1) Estimated flowing and shut-in tubing pressures;
(2) Estimated flow rates and cumulative volumes;
(3) Time duration of flow, buildup, and drawdown periods;
(4) Description and rating of surface and subsurface test equipment;
(5) Schematic drawing, showing the layout of test equipment;
(6) Description of safety equipment, including gas detectors and fire-fighting equipment;
(7) Proposed methods to handle or transport produced fluids; and
(8) Description of the test procedures.
(b) You must give the District Manager at least 24-hours notice before starting a well test.
§ 250.461   What are the requirements for directional and inclination surveys?
For this subpart, BSEE classifies a well as vertical if the calculated average of inclination readings does not exceed 3 degrees from the vertical.
(a) Survey requirements for a vertical well. (1) You must conduct inclination surveys on each vertical well and record the results. Survey intervals may not exceed 1,000 feet during the normal course of drilling;
(2) You must also conduct a directional survey that provides both inclination and azimuth, and digitally record the results in electronic format:
(i) Within 500 feet of setting surface or intermediate casing;
(ii) Within 500 feet of setting any liner; and
(iii) When you reach total depth.
(b) Survey requirements for a directional well. You must conduct directional surveys on each directional well and digitally record the results. Surveys must give both inclination and azimuth at intervals not to exceed 500 feet during the normal course of drilling. Intervals during angle-changing portions of the hole may not exceed 180 feet.
(c) Measurement while drilling. You may use measurement-while-drilling technology if it meets the requirements of this section.
(d) Composite survey requirements. (1) Your composite directional survey must show the interval from the bottom of the conductor casing to total depth. In the absence of conductor casing, the survey must show the interval from the bottom of the drive or structural casing to total depth; and
(2) You must correct all surveys to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north after making the magnetic-to-true-north correction. Surveys must show the magnetic and grid corrections used and include a listing of the directionally computed inclinations and azimuths.
(e) If you drill within 500 feet of an adjacent lease, the Regional Supervisor may require you to furnish a copy of the well's directional survey to the affected leaseholder. This could occur when the adjoining leaseholder requests a copy of the survey for the protection of correlative rights.
§ 250.462   What are the source control, containment, and collocated equipment requirements?
For drilling operations using a subsea BOP or surface BOP on a floating facility, you must have the ability to control or contain a blowout event at the sea floor.
(a) To determine your required source control and containment capabilities you must do the following:
(1) Consider a scenario of the wellbore fully evacuated to reservoir fluids, with no restrictions in the well.
(2) Evaluate the performance of the well as designed to determine if a full shut-in can be achieved without having reservoir fluids broach to the sea floor. If your evaluation indicates that the well can only be partially shut-in, then you must determine your ability to flow and capture the residual fluids to a surface production and storage system.
(b) You must have access to and the ability to deploy Source Control and Containment Equipment (SCCE) and all other necessary supporting and collocated equipment to regain control of the well. SCCE means the capping stack, cap-and-flow system, containment dome, and/or other subsea and surface devices, equipment, and vessels, which have the collective purpose to control a spill source and stop the flow of fluids into the environment or to contain fluids escaping into the environment based on the determinations outlined in paragraph (a) of this section. This SCCE, supporting equipment, and collocated equipment may include, but is not limited to, the following:
(1) Subsea containment and capture equipment, including containment domes and capping stacks;
(2) Subsea utility equipment including hydraulic power sources and hydrate control equipment;
(3) Collocated equipment including dispersant injection equipment;
(4) Riser systems;
(5) Remotely operated vehicles (ROVs);
(6) Capture vessels;
(7) Support vessels; and
(8) Storage facilities.
(c) You must submit a description of your source control and containment capabilities to the Regional Supervisor and receive approval before BSEE will approve your APD, Form BSEE-0123. The description of your containment capabilities must contain the following:
(1) Your source control and containment capabilities for controlling and containing a blowout event at the seafloor;
(2) A discussion of the determination required in paragraph (a) of this section; and
(3) Information showing that you have access to and the ability to deploy all equipment required by paragraph (b) of this section.
(d) You must contact the District Manager and Regional Supervisor for reevaluation of your source control and containment capabilities if your:
(1) Well design changes; or
(2) Approved source control and containment equipment is out of service.
(e) You must maintain, test, and inspect the source control, containment, and collocated equipment identified in the following table according to these requirements:
§ 250.463   Who establishes field drilling rules?
(a) The District Manager may establish field drilling rules different from the requirements of this subpart when geological and engineering information shows that specific operating requirements are appropriate. You must comply with field drilling rules and nonconflicting requirements of this subpart. The District Manager may amend or cancel field drilling rules at any time.
(b) You may request the District Manager to establish, amend, or cancel field drilling rules.
§ 250.465   When must I submit an Application for Permit to Modify (APM) or an End of Operations Report to BSEE?
(a) You must submit an APM (form BSEE-0124) or an End of Operations Report (form BSEE-0125) and other materials to the Regional Supervisor as shown in the following table. You must also submit a public information copy of each form.
(b) If you intend to perform any of the actions specified in paragraph (a)(1) of this section, you must meet the following additional requirements:
(1) Your APM (Form BSEE-0124) must contain a detailed statement of the proposed work that would materially change from the approved APD. The submission of your APM must be accompanied by payment of the service fee listed in § 250.125;
(2) Your form BSEE-0124 must include the present status of the well, depth of all casing strings set to date, well depth, present production zones and productive capability, and all other information specified; and
(3) Within 30 days after completing this work, you must submit an End of Operations Report (EOR), Form BSEE-0125, as required under § 250.744.
§§ 250.466-250.469   [Reserved]
§ 250.470   What additional information must I submit with my APD for Arctic OCS exploratory drilling operations?
In addition to complying with all other applicable requirements included in this part, you must provide with your APD all of the following information pertaining to your proposed Arctic OCS exploratory drilling:
(a) A detailed description of:
(1) The environmental, meteorological, and oceanic conditions you expect to encounter at the well site(s);
(2) How you will prepare your equipment, materials, and drilling unit for service in the conditions identified in paragraph (a)(1) of this section, and how your drilling unit will be in compliance with the requirements of § 250.713.
(b) A detailed description of all operations necessary in Arctic OCS conditions to transition the rig from being under way to conducting drilling operations and from ending drilling operations to being under way, as well as any anticipated repair and maintenance plans for the drilling unit and equipment. You should include, among other things, a description of how you plan to:
(1) Recover the subsea equipment, including the marine riser and the lower marine riser package;
(2) Recover the BOP;
(3) Recover the auxiliary sub-sea controls and template;
(4) Lay down the drill pipe and secure the drill pipe and marine riser;
(5) Secure the drilling equipment;
(6) Transfer the fluids for transport or disposal;
(7) Secure ancillary equipment like the draw works and lines;
(8) Refuel or transfer fuel;
(9) Offload waste;
(10) Recover the Remotely Operated Vehicles;
(11) Pick up the oil spill prevention booms and equipment; and
(12) Offload the drilling crew.
(c) A description of well-specific drilling objectives, timelines, and updated contingency plans for temporary abandonment of the well, including but not limited to the following:
(1) When you will spud the particular well ( i.e., begin drilling operations at the well site) identified in the APD;
(2) How long you will take to drill the well;
(3) Anticipated depths and geologic targets, with timelines;
(4) When you expect to set and cement each string of casing;
(5) When and how you would log the well;
(6) Your plans to test the well;
(7) When and how you intend to abandon the well, including specifically addressing your plans for how to move the rig off location and how you will meet the requirements of § 250.720(c);
(8) A description of what equipment and vessels will be involved in the process of temporarily abandoning the well due to ice; and
(9) An explanation of how you will integrate these elements into your overall program.
(d) A detailed description of your weather and ice forecasting capability for all phases of the drilling operation, including:
(1) How you will ensure your continuous awareness of potential weather and ice hazards at, and during transition between, wells;
(2) Your plans for managing ice hazards and responding to weather events; and
(3) Verification that you have the capabilities described in your BOEM-approved EP.
(e) A detailed description of how you will comply with the requirements of § 250.472.
(f) A statement that you own, or have a contract with a provider for, source control and containment equipment (SCCE), which is capable of controlling and/or containing a worst case discharge, as described in your BOEM-approved EP, when proposing to use a MODU to conduct exploratory drilling operations on the Arctic OCS. The following information must be included in your SCCE submittal:
(1) A detailed description of your or your contractor's SCCE capability to stop or contain flow from an out-of-control well, including your operating assumptions and limitations; your access to and ability to deploy, in accordance with § 250.471, all necessary SCCE; and your ability to evaluate the performance of the well design to determine how you can achieve a full shut-in without having reservoir fluids discharged into the environment;
(2) An inventory of the local and regional SCCE, supplies, and services that you own or for which you have a contract with a provider. You must identify each supplier of such equipment and services and provide their locations and telephone numbers;
(3) Where applicable, proof of contracts or membership agreements with cooperatives, service providers, or other contractors who will provide you with the necessary SCCE or related supplies and services if you do not possess them. The contract or membership agreement must include provisions for ensuring the availability of the personnel and/or equipment on a 24-hour per day basis while you are drilling below or working below the surface casing;
(4) A detailed description of the procedures you plan to use to inspect, test, and maintain your SCCE; and
(5) A detailed description of your plan to ensure that all members of your operating team, who are responsible for operating the SCCE, have received the necessary training to deploy and operate such equipment in Arctic OCS conditions and demonstrate ongoing proficiency in source control operations. You must also identify and include the dates of prior and planned training.
(g) Where it does not conflict with other requirements of this subpart, and except as provided in paragraphs (g)(1) through (11) of this section, you must comply with the requirements of API RP 2N, Third Edition “Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions” (incorporated by reference as specified in § 250.198), and provide a detailed description of how you will utilize the best practices included in API RP 2N during your exploratory drilling operations. You are not required to incorporate the following sections of API RP 2N into your drilling operations:
(1) Sections 6.6.3 through 6.6.4;
(2) The foundation recommendations in Section 8.4;
(3) Section 9.6;
(4) The recommendations for permanently moored systems in Section 9.7;
(5) The recommendations for pile foundations in Section 9.10;
(6) Section 12;
(7) Section 13.2.1;
(8) Sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through 13.8.2.7;
(9) Sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
(10) Sections 14 through 16; and
(11) Section 18.
§ 250.471   What are the requirements for Arctic OCS source control and containment?
You must meet the following requirements for all exploration wells drilled on the Arctic OCS:
(a) If you use a MODU when drilling below or working below the surface casing, you must have access to the following SCCE capable of stopping or capturing the flow of an out-of-control well:
(1) A capping stack, positioned to ensure that it will arrive at the well location within 24 hours after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section;
(2) A cap and flow system, positioned to ensure that it will arrive at the well location within 7 days after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section. The cap and flow system must be designed to capture at least the amount of hydrocarbons equivalent to the calculated worst case discharge rate referenced in your BOEM-approved EP; and
(3) A containment dome, positioned to ensure that it will arrive at the well location within 7 days after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section. The containment dome must have the capacity to pump fluids without relying on buoyancy.
(b) You must conduct a monthly stump test of dry-stored capping stacks. If you use a pre-positioned capping stack, you must conduct a stump test prior to each installation on each well.
(c) As required by § 250.465(a), if you propose to change your well design, you must submit an APM. For Arctic OCS operations, your APM must include a reevaluation of your SCCE capabilities for any new Worst Case Discharge (WCD) rate, and a demonstration that your SCCE capabilities will meet the criteria in § 250.470(f) under the changed well design.
(d) You must conduct tests or exercises of your SCCE, including deployment of your SCCE, when directed by the Regional Supervisor.
(e) You must maintain records pertaining to testing, inspection, and maintenance of your SCCE for at least 10 years and make the records available to any authorized BSEE representative upon request.
(f) You must maintain records pertaining to the use of your SCCE during testing, training, and deployment activities for at least 3 years and make the records available to any authorized BSEE representative upon request.
(g) Upon a loss of well control, you must initiate transit of all SCCE identified in paragraph (a) of this section to the well.
(h) You must deploy and use SCCE when directed by the Regional Supervisor.
(i) Operators may request approval of alternate procedures or equipment to the SCCE requirements of subparagraph (a) of this section in accordance with § 250.141. The operator must show and document that the alternate procedures or equipment will provide a level of safety and environmental protection that will meet or exceed the level of safety and environmental protection required by BSEE regulations, including demonstrating that the alternate procedures or equipment will be capable of stopping or capturing the flow of an out-of-control well.
§ 250.472   What are the relief rig requirements for the Arctic OCS?
(a) In the event of a loss of well control, the Regional Supervisor may direct you to drill a relief well using the relief rig able to kill and permanently plug an out-of-control well as described in your APD. Your relief rig must comply with all other requirements of this part pertaining to drill rig characteristics and capabilities, and it must be able to drill a relief well under anticipated Arctic OCS conditions.
(b) When you are drilling below or working below the surface casing during Arctic OCS exploratory drilling operations, you must have access to a relief rig, different from your primary drilling rig, staged in a location such that it can arrive on site, drill a relief well, kill and abandon the original well, and abandon the relief well prior to expected seasonal ice encroachment at the drill site, but no later than 45 days after the loss of well control.
(c) Operators may request approval of alternative compliance measures to the relief rig requirement in accordance with § 250.141. The operator must show and document that the alternate compliance measure will meet or exceed the level of safety and environmental protection required by BSEE regulations, including demonstrating that the alternate compliance measure will be able to kill and permanently plug an out-of-control well.
§ 250.473   What must I do to protect health, safety, property, and the
environment while operating on the Arctic OCS?
In addition to the requirements set forth in § 250.107, when conducting exploratory drilling operations on the Arctic OCS, you must protect health, safety, property, and the environment by using the following:
(a) Equipment and materials that are rated or de-rated for service under conditions that can be reasonably expected during your operations; and
(b) Measures to address human factors associated with weather conditions that can be reasonably expected during your operations including, but not limited to, provision of proper attire and equipment, construction of protected work spaces, and management of shifts.
§ 250.490   Hydrogen sulfide.
(a) What precautions must I take when operating in an H 2 S area? You must:
(1) Take all necessary and feasible precautions and measures to protect personnel from the toxic effects of H 2 S and to mitigate damage to property and the environment caused by H 2 S. You must follow the requirements of this section when conducting drilling, well-completion/well-workover, and production operations in zones with H 2 S present and when conducting operations in zones where the presence of H 2 S is unknown. You do not need to follow these requirements when operating in zones where the absence of H 2 S has been confirmed; and
(2) Follow your approved contingency plan.
(b) Definitions. Terms used in this section have the following meanings:
Facility means a vessel, a structure, or an artificial island used for drilling, well-completion, well-workover, and/or production operations.
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 that 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.
Well-control fluid means drilling mud and completion or workover fluid as appropriate to the particular operation being conducted.
(c) Classifying an area for the presence of H 2 S. You must:
(1) Request and obtain an approved classification for the area from the Regional Supervisor before you begin operations. Classifications are “H 2 S absent,” H 2 S present,” or “H 2 S unknown”;
(2) Submit your request with your application for permit to drill;
(3) Support your request with available information such as geologic and geophysical data and correlations, well logs, formation tests, cores and analysis of formation fluids; and
(4) Submit a request for reclassification of a zone when additional data indicate a different classification is needed.
(d) What do I do if conditions change? If you encounter H 2 S that could potentially result in atmospheric concentrations of 20 ppm or more in areas not previously classified as having H 2 S present, you must immediately notify BSEE and begin to follow requirements for areas with H 2 S present.
(e) What are the requirements for conducting simultaneous operations? When conducting any combination of drilling, well-completion, well-workover, and production operations simultaneously, you must follow the requirements in the section applicable to each individual operation.
(f) Requirements for submitting an H 2 S Contingency Plan. Before you begin operations, you must submit an H 2 S Contingency Plan to the District Manager for approval. Do not begin operations before the District Manager approves your plan. You must keep a copy of the approved plan in the field, and you must follow the plan at all times. Your plan must include:
(1) Safety procedures and rules that you will follow concerning equipment, drills, and smoking;
(2) Training you provide for employees, contractors, and visitors;
(3) Job position and title of the person responsible for the overall safety of personnel;
(4) Other key positions, how these positions fit into your organization, and what the functions, duties, and responsibilities of those job positions are;
(5) Actions that you will take when the concentration of H 2 S in the atmosphere reaches 20 ppm, who will be responsible for those actions, and a description of the audible and visual alarms to be activated;
(6) Briefing areas where personnel will assemble during an H 2 S alert. You must have at least two briefing areas on each facility and use the briefing area that is upwind of the H 2 S source at any given time;
(7) Criteria you will use to decide when to evacuate the facility and procedures you will use to safely evacuate all personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H 2 S alerts, describe the types of H 2 S emergencies during which you consider the risk of helicopter activity to be acceptable and the precautions you will take during the flights;
(8) Procedures you will use to safely position all vessels attendant to the facility. Indicate where you will locate the vessels with respect to wind direction. Include the distance from the facility and what procedures you will use to safely relocate the vessels in an emergency;
(9) How you will provide protective-breathing equipment for all personnel, including contractors and visitors;
(10) The agencies and facilities you will notify in case of a release of H 2 S (that constitutes an emergency), how you will notify them, and their telephone numbers. Include all facilities that might be exposed to atmospheric concentrations of 20 ppm or more of H 2 S;
(11) The medical personnel and facilities you will use if needed, their addresses, and telephone numbers;
(12) H 2 S detector locations in production facilities producing gas containing 20 ppm or more of H 2 S. Include an “H 2 S Detector Location Drawing” showing:
(i) All vessels, flare outlets, wellheads, and other equipment handling production containing H 2 S;
(ii) Approximate maximum concentration of H 2 S in the gas stream; and
(iii) Location of all H 2 S sensors included in your contingency plan;
(13) Operational conditions when you expect to flare gas containing H 2 S including the estimated maximum gas flow rate, H 2 S concentration, and duration of flaring;
(14) Your assessment of the risks to personnel during flaring and what precautionary measures you will take;
(15) Primary and alternate methods to ignite the flare and procedures for sustaining ignition and monitoring the status of the flare ( i.e., ignited or extinguished);
(16) Procedures to shut off the gas to the flare in the event the flare is extinguished;
(17) Portable or fixed sulphur dioxide (SO 2 )-detection system(s) you will use to determine SO 2 concentration and exposure hazard when H 2 S is burned;
(18) Increased monitoring and warning procedures you will take when the SO 2 concentration in the atmosphere reaches 2 ppm;
(19) Personnel protection measures or evacuation procedures you will initiate when the SO 2 concentration in the atmosphere reaches 5 ppm;
(20) Engineering controls to protect personnel from SO 2 ; and
(21) Any special equipment, procedures, or precautions you will use if you conduct any combination of drilling, well-completion, well-workover, and production operations simultaneously.
(g) Training program: (1) When and how often do employees need to be trained? All operators and contract personnel must complete an H 2 S training program to meet the requirements of this section:
(i) Before beginning work at the facility; and
(ii) Each year, within 1 year after completion of the previous class.
(2) What training documentation do I need? For each individual working on the platform, either:
(i) You must have documentation of this training at the facility where the individual is employed; or
(ii) The employee must carry a training completion card.
(3) What training do I need to give to visitors and employees previously trained on another facility?
(i) Trained employees or contractors transferred from another facility must attend a supplemental briefing on your H 2 S equipment and procedures before beginning duty at your facility;
(ii) Visitors who will remain on your facility more than 24 hours must receive the training required for employees by paragraph (g)(4) of this section; and
(iii) Visitors who will depart before spending 24 hours on the facility are exempt from the training required for employees, but they must, upon arrival, complete a briefing that includes:
(A) Information on the location and use of an assigned respirator; practice in donning and adjusting the assigned respirator; information on the safe briefing areas, alarm system, and hazards of H 2 S and SO 2 ; and
(B) Instructions on their responsibilities in the event of an H 2 S release.
(4) What training must I provide to all other employees? You must train all individuals on your facility on the:
(i) Hazards of H 2 S and of SO 2 and the provisions for personnel safety contained in the H 2 S Contingency Plan;
(ii) Proper use of safety equipment which the employee may be required to use;
(iii) Location of protective breathing equipment, H 2 S detectors and alarms, ventilation equipment, briefing areas, warning systems, evacuation procedures, and the direction of prevailing winds;
(iv) Restrictions and corrective measures concerning beards, spectacles, and contact lenses in conformance with ANSI Z88.2, American National Standard for Respiratory Protection (as specified in § 250.198);
(v) Basic first-aid procedures applicable to victims of H 2 S exposure. During all drills and training sessions, you must address procedures for rescue and first aid for H 2 S victims;
(vi) Location of:
(A) The first-aid kit on the facility;
(B) Resuscitators; and
(C) Litter or other device on the facility.
(vii) Meaning of all warning signals.
(5) Do I need to post safety information? You must prominently post safety information on the facility and on vessels serving the facility ( i.e., basic first-aid, escape routes, instructions for use of life boats, etc. ).
(h) Drills. (1) When and how often do I need to conduct drills on H 2 S safety discussions on the facility? You must:
(i) Conduct a drill for each person at the facility during normal duty hours at least once every 7-day period. The drills must consist of a dry-run performance of personnel activities related to assigned jobs.
(ii) At a safety meeting or other meetings of all personnel, discuss drill performance, new H 2 S considerations at the facility, and other updated H 2 S information at least monthly.
(2) What documentation do I need? You must keep records of attendance for:
(i) Drilling, well-completion, and well-workover operations at the facility until operations are completed; and
(ii) Production operations at the facility or at the nearest field office for 1 year.
(i) Visual and audible warning systems: (1) How must I install wind direction equipment? You must install wind-direction equipment in a location visible at all times to individuals on or in the immediate vicinity of the facility.
(2) When do I need to display operational danger signs, display flags, or activate visual or audible alarms?
(i) You must display warning signs at all times on facilities with wells capable of producing H 2 S and on facilities that process gas containing H 2 S in concentrations of 20 ppm or more.
(ii) In addition to the signs, you must activate audible alarms and display flags or activate flashing red lights when atmospheric concentration of H 2 S reaches 20 ppm.
(3) What are the requirements for signs? Each sign must be a high-visibility yellow color with black lettering as follows:
(4) May I use existing signs? You may use existing signs containing the words “Danger-Hydrogen Sulfide-H 2 S,” provided the words “Poisonous Gas. Do Not Approach if Red Flag is Flying” or “Red Lights are Flashing” in lettering of a minimum of 7 inches in height are displayed on a sign immediately adjacent to the existing sign.
(5) What are the requirements for flashing lights or flags? You must activate a sufficient number of lights or hoist a sufficient number of flags to be visible to vessels and aircraft. Each light must be of sufficient intensity to be seen by approaching vessels or aircraft any time it is activated (day or night). Each flag must be red, rectangular, a minimum width of 3 feet, and a minimum height of 2 feet.
(6) What is an audible warning system? An audible warning system is a public address system or siren, horn, or other similar warning device with a unique sound used only for H 2 S.
(7) Are there any other requirements for visual or audible warning devices? Yes, you must:
(i) Illuminate all signs and flags at night and under conditions of poor visibility; and
(ii) Use warning devices that are suitable for the electrical classification of the area.
(8) What actions must I take when the alarms are activated? When the warning devices are activated, the designated responsible persons must inform personnel of the level of danger and issue instructions on the initiation of appropriate protective measures.
(j) H 2 S-detection and H 2 S monitoring equipment: (1) What are the requirements for an H 2 S detection system? An H 2 S detection system must:
(i) Be capable of sensing a minimum of 10 ppm of H 2 S in the atmosphere; and
(ii) Activate audible and visual alarms when the concentration of H 2 S in the atmosphere reaches 20 ppm.
(2) Where must I have sensors for drilling, well-completion, and well-workover operations? You must locate sensors at the:
(i) Bell nipple;
(ii) Mud-return line receiver tank (possum belly);
(iii) Pipe-trip tank;
(iv) Shale shaker;
(v) Well-control fluid pit area;
(vi) Driller's station;
(vii) Living quarters; and
(viii) All other areas where H 2 S may accumulate.
(3) Do I need mud sensors? The District Manager may require mud sensors in the possum belly in cases where the ambient air sensors in the mud-return system do not consistently detect the presence of H 2 S.
(4) How often must I observe the sensors? During drilling, well-completion and well-workover operations, you must continuously observe the H 2 S levels indicated by the monitors in the work areas during the following operations:
(i) When you pull a wet string of drill pipe or workover string;
(ii) When circulating bottoms-up after a drilling break;
(iii) During cementing operations;
(iv) During logging operations; and
(v) When circulating to condition mud or other well-control fluid.
(5) Where must I have sensors for production operations? On a platform where gas containing H 2 S of 20 ppm or greater is produced, processed, or otherwise handled:
(i) You must have a sensor in rooms, buildings, deck areas, or low-laying deck areas not otherwise covered by paragraph (j)(2) of this section, where atmospheric concentrations of H 2 S could reach 20 ppm or more. You must have at least one sensor per 400 square feet of deck area or fractional part of 400 square feet;
(ii) You must have a sensor in buildings where personnel have their living quarters;
(iii) You must have a sensor within 10 feet of each vessel, compressor, wellhead, manifold, or pump, which could release enough H 2 S to result in atmospheric concentrations of 20 ppm at a distance of 10 feet from the component;
(iv) You may use one sensor to detect H 2 S around multiple pieces of equipment, provided the sensor is located no more than 10 feet from each piece, except that you need to use at least two sensors to monitor compressors exceeding 50 horsepower;
(v) You do not need to have sensors near wells that are shut in at the master valve and sealed closed;
(vi) When you determine where to place sensors, you must consider:
(A) The location of system fittings, flanges, valves, and other devices subject to leaks to the atmosphere; and
(B) Design factors, such as the type of decking and the location of fire walls; and
(vii) The District Manager may require additional sensors or other monitoring capabilities, if warranted by site specific conditions.
(6) How must I functionally test the H 2 S Detectors? (i) Personnel trained to calibrate the particular H 2 S detector equipment being used must test detectors by exposing them to a known concentration in the range of 10 to 30 ppm of H 2 S.
(ii) If the results of any functional test are not within 2 ppm or 10 percent, whichever is greater, of the applied concentration, recalibrate the instrument.
(7) How often must I test my detectors? (i) When conducting drilling, drill stem testing, well-completion, or well-workover operations in areas classified as H 2 S present or H 2 S unknown, test all detectors at least once every 24 hours. When drilling, begin functional testing before the bit is 1,500 feet (vertically) above the potential H 2 S zone.
(ii) When conducting production operations, test all detectors at least every 14 days between tests.
(iii) If equipment requires calibration as a result of two consecutive functional tests, the District Manager may require that H 2 S-detection and H 2 S-monitoring equipment be functionally tested and calibrated more frequently.
(8) What documentation must I keep? (i) You must maintain records of testing and calibrations (in the drilling or production operations report, as applicable) at the facility to show the present status and history of each device, including dates and details concerning:
(A) Installation;
(B) Removal;
(C) Inspection;
(D) Repairs;
(E) Adjustments; and
(F) Reinstallation.
(ii) Records must be available for inspection by BSEE personnel.
(9) What are the requirements for nearby vessels? If vessels are stationed overnight alongside facilities in areas of H 2 S present or H 2 S unknown, you must equip vessels with an H 2 S-detection system that activates audible and visual alarms when the concentration of H 2 S in the atmosphere reaches 20 ppm. This requirement does not apply to vessels positioned upwind and at a safe distance from the facility in accordance with the positioning procedure described in the approved H 2 S Contingency Plan.
(10) What are the requirements for nearby facilities? The District Manager may require you to equip nearby facilities with portable or fixed H 2 S detector(s) and to test and calibrate those detectors. To invoke this requirement, the District Manager will consider dispersion modeling results from a possible release to determine if 20 ppm H 2 S concentration levels could be exceeded at nearby facilities.
(11) What must I do to protect against SO 2 if I burn gas containing H 2 S? You must:
(i) Monitor the SO 2 concentration in the air with portable or strategically placed fixed devices capable of detecting a minimum of 2 ppm of SO 2 ;
(ii) Take readings at least hourly and at any time personnel detect SO 2 odor or nasal irritation;
(iii) Implement the personnel protective measures specified in the H 2 S Contingency Plan if the SO 2 concentration in the work area reaches 2 ppm; and
(iv) Calibrate devices every 3 months if you use fixed or portable electronic sensing devices to detect SO 2 .
(12) May I use alternative measures? You may follow alternative measures instead of those in paragraph (j)(11) of this section if you propose and the Regional Supervisor approves the alternative measures.
(13) What are the requirements for protective-breathing equipment? In an area classified as H 2 S present or H 2 S unknown, you must:
(i) Provide all personnel, including contractors and visitors on a facility, with immediate access to self-contained pressure-demand-type respirators with hoseline capability and breathing time of at least 15 minutes.
(ii) Design, select, use, and maintain respirators in conformance with ANSI Z88.2 (as specified in § 250.198).
(iii) Make available at least two voice-transmission devices, which can be used while wearing a respirator, for use by designated personnel.
(iv) Make spectacle kits available as needed.
(v) Store protective-breathing equipment in a location that is quickly and easily accessible to all personnel.
(vi) Label all breathing-air bottles as containing breathing-quality air for human use.
(vii) Ensure that vessels attendant to facilities carry appropriate protective-breathing equipment for each crew member. The District Manager may require additional protective-breathing equipment on certain vessels attendant to the facility.
(viii) During H 2 S alerts, limit helicopter flights to and from facilities to the conditions specified in the H 2 S Contingency Plan. During authorized flights, the flight crew and passengers must use pressure-demand-type respirators. You must train all members of flight crews in the use of the particular type(s) of respirator equipment made available.
(ix) As appropriate to the particular operation(s), (production, drilling, well-completion or well-workover operations, or any combination of them), provide a system of breathing-air manifolds, hoses, and masks at the facility and the briefing areas. You must provide a cascade air-bottle system for the breathing-air manifolds to refill individual protective-breathing apparatus bottles. The cascade air-bottle system may be recharged by a high-pressure compressor suitable for providing breathing-quality air, provided the compressor suction is located in an uncontaminated atmosphere.
(k) Personnel safety equipment: (1) What additional personnel-safety equipment do I need? You must ensure that your facility has:
(i) Portable H 2 S detectors capable of detecting a 10 ppm concentration of H 2 S in the air available for use by all personnel;
(ii) Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated areas;
(iii) Chalkboards and/or note pads for communication purposes located on the rig floor, shale-shaker area, the cement-pump rooms, well-bay areas, production processing equipment area, gas compressor area, and pipeline-pump area;
(iv) Bull horns and flashing lights; and
(v) At least three resuscitators on manned facilities, and a number equal to the personnel on board, not to exceed three, on normally unmanned facilities, complete with face masks, oxygen bottles, and spare oxygen bottles.
(2) What are the requirements for ventilation equipment? You must:
(i) Use only explosion-proof ventilation devices;
(ii) Install ventilation devices in areas where H 2 S or SO 2 may accumulate; and
(iii) Provide movable ventilation devices in work areas. The movable ventilation devices must be multidirectional and capable of dispersing H 2 S or SO 2 vapors away from working personnel.
(3) What other personnel safety equipment do I need? You must have the following equipment readily available on each facility:
(i) A first-aid kit of appropriate size and content for the number of personnel on the facility; and
(ii) At least one litter or an equivalent device.
(l) Do I need to notify BSEE in the event of an H 2 S release? You must notify BSEE without delay in the event of a gas release which results in a 15-minute time-weighted average atmospheric concentration of H 2 S of 20 ppm or more anywhere on the OCS facility. You must report these gas releases to the District Manager immediately by oral communication, with a written follow-up report within 15 days, pursuant to §§ 250.188 through 250.190.
(m) Do I need to use special drilling, completion and workover fluids or procedures? When working in an area classified as H 2 S present or H 2 S unknown:
(1) You may use either water- or oil-base muds in accordance with § 250.300(b)(1).
(2) If you use water-base well-control fluids, and if ambient air sensors detect H 2 S, you must immediately conduct either the Garrett-Gas-Train test or a comparable test for soluble sulfides to confirm the presence of H 2 S.
(3) If the concentration detected by air sensors in over 20 ppm, personnel conducting the tests must don protective-breathing equipment conforming to paragraph (j)(13) of this section.
(4) You must maintain on the facility sufficient quantities of additives for the control of H 2 S, well-control fluid pH, and corrosion equipment.
(i) Scavengers. You must have scavengers for control of H 2 S available on the facility. When H 2 S is detected, you must add scavengers as needed. You must suspend drilling until the scavenger is circulated throughout the system.
(ii) Control pH. You must add additives for the control of pH to water-base well-control fluids in sufficient quantities to maintain pH of at least 10.0.
(iii) Corrosion inhibitors. You must add additives to the well-control fluid system as needed for the control of corrosion.
(5) You must degas well-control fluids containing H 2 S at the optimum location for the particular facility. You must collect the gases removed and burn them in a closed flare system conforming to paragraph (q)(6) of this section.
(n) What must I do in the event of a kick? In the event of a kick, you must use one of the following alternatives to dispose of the well-influx fluids giving consideration to personnel safety, possible environmental damage, and possible facility well-equipment damage:
(1) Contain the well-fluid influx by shutting in the well and pumping the fluids back into the formation.
(2) Control the kick by using appropriate well-control techniques to prevent formation fracturing in an open hole within the pressure limits of the well equipment (drill pipe, work string, casing, wellhead, BOP system, and related equipment). The disposal of H 2 S and other gases must be through pressurized or atmospheric mud-separator equipment depending on volume, pressure and concentration of H 2 S. The equipment must be designed to recover well-control fluids and burn the gases separated from the well-control fluid. The well-control fluid must be treated to neutralize H 2 S and restore and maintain the proper quality.
(o) Well testing in a zone known to contain H 2 S. When testing a well in a zone with H 2 S present, you must do all of the following:
(1) Before starting a well test, conduct safety meetings for all personnel who will be on the facility during the test. At the meetings, emphasize the use of protective-breathing equipment, first-aid procedures, and the Contingency Plan. Only competent personnel who are trained and are knowledgeable of the hazardous effects of H 2 S must be engaged in these tests.
(2) Perform well testing with the minimum number of personnel in the immediate vicinity of the rig floor and with the appropriate test equipment to safely and adequately perform the test. During the test, you must continuously monitor H 2 S levels.
(3) Not burn produced gases except through a flare which meets the requirements of paragraph (q)(6) of this section. Before flaring gas containing H 2 S, you must activate SO 2 monitoring equipment in accordance with paragraph (j)(11) of this section. If you detect SO 2 in excess of 2 ppm, you must implement the personnel protective measures in your H 2 S Contingency Plan, required by paragraph (f) of this section. You must also follow the requirements of § 250.1164. You must pipe gases from stored test fluids into the flare outlet and burn them.
(4) Use downhole test tools and wellhead equipment suitable for H 2 S service.
(5) Use tubulars suitable for H 2 S service. You must not use drill pipe for well testing without the prior approval of the District Manager. Water cushions must be thoroughly inhibited in order to prevent H 2 S attack on metals. You must flush the test string fluid treated for this purpose after completion of the test.
(6) Use surface test units and related equipment that is designed for H 2 S service.
(p) Metallurgical properties of equipment. When operating in a zone with H 2 S present or when the concentration of H 2 S in the produced fluid may exceed 0.05 psi partial pressure of H 2 S, you must use equipment that is constructed of materials with metallurgical properties that resist or prevent sulfide stress cracking (also known as hydrogen embrittlement, stress corrosion cracking, or H 2 S embrittlement), chloride-stress cracking, hydrogen-induced cracking, and other failure modes. You must do all of the following:
(1) Use tubulars and other equipment, casing, tubing, drill pipe, couplings, flanges, and related equipment that is designed for H 2 S service.
(2) Use BOP system components, wellhead, pressure-control equipment, and related equipment exposed to H 2 S-bearing fluids in conformance with NACE Standard MR0175-03 (as specified in § 250.198).
(3) Use temporary downhole well-security devices such as retrievable packers and bridge plugs that are designed for H 2 S service.
(4) When producing in zones bearing H 2 S, use equipment constructed of materials capable of resisting or preventing sulfide stress cracking.
(5) Keep the use of welding to a minimum during the installation or modification of a production facility. Welding must be done in a manner that ensures resistance to sulfide stress cracking.
(q) General requirements when operating in an H 2 S zone: (1) Coring operations. When you conduct coring operations in H 2 S-bearing zones, all personnel in the working area must wear protective-breathing equipment at least 10 stands in advance of retrieving the core barrel. Cores to be transported must be sealed and marked for the presence of H 2 S.
(2) Logging operations. You must treat and condition well-control fluid in use for logging operations to minimize the effects of H 2 S on the logging equipment.
(3) Stripping operations. Personnel must monitor displaced well-control fluid returns and wear protective-breathing equipment in the working area when the atmospheric concentration of H 2 S reaches 20 ppm or if the well is under pressure.
(4) Gas-cut well-control fluid or well kick from H 2 S-bearing zone. If you decide to circulate out a kick, personnel in the working area during bottoms-up and extended-kill operations must wear protective-breathing equipment.
(5) Drill- and workover-string design and precautions. Drill- and workover-strings must be designed consistent with the anticipated depth, conditions of the hole, and reservoir environment to be encountered. You must minimize exposure of the drill- or workover-string to high stresses as much as practical and consistent with well conditions. Proper handling techniques must be taken to minimize notching and stress concentrations. Precautions must be taken to minimize stresses caused by doglegs, improper stiffness ratios, improper torque, whip, abrasive wear on tool joints, and joint imbalance.
(6) Flare system. The flare outlet must be of a diameter that allows easy nonrestricted flow of gas. You must locate flare line outlets on the downside of the facility and as far from the facility as is feasible, taking into account the prevailing wind directions, the wake effects caused by the facility and adjacent structure(s), and the height of all such facilities and structures. You must equip the flare outlet with an automatic ignition system including a pilot-light gas source or an equivalent system. You must have alternate methods for igniting the flare. You must pipe to the flare system used for H 2 S all vents from production process equipment, tanks, relief valves, burst plates, and similar devices.
(7) Corrosion mitigation. You must use effective means of monitoring and controlling corrosion caused by acid gases (H 2 S and CO 2 ) in both the downhole and surface portions of a production system. You must take specific corrosion monitoring and mitigating measures in areas of unusually severe corrosion where accumulation of water and/or higher concentration of H 2 S exists.
(8) Wireline lubricators. Lubricators which may be exposed to fluids containing H 2 S must be of H 2 S-resistant materials.
(9) Fuel and/or instrument gas. You must not use gas containing H 2 S for instrument gas. You must not use gas containing H 2 S for fuel gas without the prior approval of the District Manager.
(10) Sensing lines and devices. Metals used for sensing line and safety-control devices which are necessarily exposed to H 2 S-bearing fluids must be constructed of H 2 S-corrosion resistant materials or coated so as to resist H 2 S corrosion.
(11) Elastomer seals. You must use H 2 S-resistant materials for all seals which may be exposed to fluids containing H 2 S.
(12) Water disposal. If you dispose of produced water by means other than subsurface injection, you must submit to the District Manager an analysis of the anticipated H 2 S content of the water at the final treatment vessel and at the discharge point. The District Manager may require that the water be treated for removal of H 2 S. The District Manager may require the submittal of an updated analysis if the water disposal rate or the potential H 2 S content increases.
(13) Deck drains. You must equip open deck drains with traps or similar devices to prevent the escape of H 2 S gas into the atmosphere.
(14) Sealed voids. You must take precautions to eliminate sealed spaces in piping designs (e.g., slip-on flanges, reinforcing pads) which can be invaded by atomic hydrogen when H 2 S is present.
§ 250.500   General requirements.
Well-completion operations must be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS, including any mineral deposits (in areas leased and not leased), the National security or defense, or the marine, coastal, or human environment. In addition to the requirements of this subpart, you must also follow the applicable requirements of subpart G of this part.
§ 250.501   Definition.
When used in this subpart, the following term shall have the meaning given below:
Well-completion operations means the work conducted to establish the production of a well after the production-casing string has been set, cemented, and pressure-tested.
§ 250.502   [Reserved]
§ 250.503   Emergency shutdown system.
When well-completion operations are conducted on a platform where there are other hydrocarbon-producing wells or other hydrocarbon flow, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station.
§ 250.504   Hydrogen sulfide.
When a well-completion operation is conducted in zones known to contain hydrogen sulfide (H 2 S) or in zones where the presence of H 2 S is unknown (as defined in § 250.490 of this part), the lessee shall take appropriate precautions to protect life and property on the platform or completion unit, including, but not limited to operations such as blowing the well down, dismantling wellhead equipment and flow lines, circulating the well, swabbing, and pulling tubing, pumps, and packers. The lessee shall comply with the requirements in § 250.490 of this part as well as the appropriate requirements of this subpart.
§ 250.505   Subsea completions.
No subsea well completion shall be commenced until the lessee obtains written approval from the District Manager in accordance with § 250.513 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will adequately control the well and permit safe production operations.
§§ 250.506-250.508   [Reserved]
§ 250.509   Well-completion structures on fixed platforms.
Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the proposed operations. Prior to moving a well-completion rig or equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of platform, and previous stresses to the platform.
§ 250.510   Diesel engine air intakes.
Diesel engine air intakes must be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines that are continuously attended must be equipped with either remote operated manual or automatic-shutdown devices. Diesel engines that are not continuously attended must be equipped with automatic-shutdown devices.
§ 250.511   Traveling-block safety device.
All units being used for well-completion operations that have both a traveling block and a crown block must be equipped with a safety device that is designed to prevent the traveling block from striking the crown block. The device must be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check must be entered in the operations log.
§ 250.512   Field well-completion rules.
When geological and engineering information available in a field enables the District Manager to determine specific operating requirements, field well-completion rules may be established on the District Manager's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-completion rules have been established, well-completion operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-completion rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.
§ 250.513   Approval and reporting of well-completion operations.
(a) No well-completion operation may begin until the lessee receives written approval from the District Manager. If completion is planned and the data are available at the time you submit the Application for Permit to Drill and Supplemental APD Information Sheet (Forms BSEE-0123 and BSEE-0123S), you may request approval for a well-completion on those forms (see §§ 250.410 through 250.418 of this part). If the District Manager has not approved the completion or if the completion objective or plans have significantly changed, you must submit an Application for Permit to Modify (Form BSEE-0124) for approval of such operations.
(b) You must submit the following with Form BSEE-0124 (or with Form BSEE-0123; Form BSEE-0123S):
(1) A brief description of the well-completion procedures to be followed, a statement of the expected surface pressure, and type and weight of completion fluids;
(2) A schematic drawing of the well showing the proposed producing zone(s) and the subsurface well-completion equipment to be used;
(3) For multiple completions, a partial electric log showing the zones proposed for completion, if logs have not been previously submitted;
(4) All applicable information required in § 250.731.
(5) When the well-completion is in a zone known to contain H 2 S or a zone where the presence of H 2 S is unknown, information pursuant to § 250.490 of this part; and
(6) Payment of the service fee listed in § 250.125.
(c) Within 30 days after completion, you must submit to the District Manager an End of Operations Report (Form BSEE-0125), including a schematic of the tubing and subsurface equipment.
(d) You must submit public information copies of Form BSEE-0125 according to § 250.186.
§ 250.514   Well-control fluids, equipment, and operations.
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-completion operations and shall not be left unattended at any time unless the well is shut in and secured.
(b) The following well-control-fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
(c) When coming out of the hole with drill pipe, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hole shall be utilized.
§§ 250.515-250.517   [Reserved]
§ 250.518   Tubing and wellhead equipment.
(a) No tubing string may be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(1) The tubing string must be evaluated for burst, collapse, and axial loads with appropriate safety factors and material design factors for the pressure and temperature environments of the completion, production, shut-in, and injection load cases.
(2) The tubing string materials must be appropriate for the environment. You must follow NACE Standard MR0175-2003 (incorporated by reference in § 250.198) when H 2 S concentration may equal or exceed 0.05 psi partial pressure.
(3) The tubing string threaded connectors must be appropriate for the loads identified in paragraph (a)(1) of this section.
(b) When the tree is installed, you must equip wells to monitor for casing pressure according to the following chart:
* Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing hanger, and a surface christmas tree.
(c) You must design and test the wellhead, tree, and related equipment in accordance with ANSI/API Spec. 6A (incorporated by reference in § 250.198) or ANSI/API Spec. 17D (incorporated by reference in § 250.198), as applicable. The wellhead, tree, and related equipment must have a pressure rating greater than the maximum anticipated surface pressure and must be designed, installed, operated, maintained, and tested to achieve and maintain pressure containment and pressure control.
(1) Newly completed dry trees ( e.g., fixed, hybrid, or mudline suspension) for production or injection wells must be equipped with a minimum of one master valve and one surface safety valve (SSV), installed above the master valve, in the vertical run of the tree.
(2) Newly completed subsea production or injection wells must be equipped with a minimum of one USV installed in the horizontal or vertical run of the tree ( e.g., vertical or horizontal subsea trees).
(3) Newly completed wells with a mudline suspension conversion to a subsea tree must have a minimum of two casing strings tied back and sealed below the tubing head. At a minimum, the production casing and the next outer casing must be tied back to the wellhead, to ensure annular isolation.
(d) You must install, maintain, and test surface and subsurface safety equipment in accordance with the applicable requirements in subpart H of this part.
(e) When installed, packers and bridge plugs must meet the following:
(1) The uppermost permanently installed packer and all permanently installed bridge plugs qualified as mechanical barriers must comply with ANSI/API Spec. 11D1 (as incorporated by reference in § 250.198);
(2) The production packer must be set at a depth that will allow for a column of weighted fluids to be placed above the packer that will exert a hydrostatic force greater than or equal to the force created by the reservoir pressure below the packer;
(3) The production packer must be set as close as practically possible to the perforated interval; and
(4) The production packer must be set at a depth that is within the cemented interval of the selected casing section.
(f) Your APM must include a description and calculations for how you determined the production packer setting depth.
(g) You must have two independent barriers, one being mechanical, in the exposed center wellbore prior to removing the tree and/or well control equipment.
§ 250.519   What are the requirements for casing pressure management?
Once you install your wellhead, you must meet the casing pressure management requirements of API RP 90 (as incorporated by reference in § 250.198) and the requirements of §§ 250.519 through 250.531. If there is a conflict between API RP 90 and the casing pressure requirements of this subpart, you must follow the requirements of this subpart.
§ 250.520   How often do I have to monitor for casing pressure?
You must monitor for casing pressure in your well according to the following table:
§ 250.521   When do I have to perform a casing diagnostic test?
(a) You must perform a casing diagnostic test within 30 days after first observing or imposing casing pressure according to the following table:
(b) You are exempt from performing a diagnostic pressure test for the production casing on a well operating under active gas lift.
§ 250.522   How do I manage the thermal effects caused by initial production on a newly completed or recompleted well?
A newly completed or recompleted well often has thermal casing pressure during initial startup. Bleeding casing pressure during the startup process is considered a normal and necessary operation to manage thermal casing pressure; therefore, you do not need to evaluate these operations as a casing diagnostic test. After 30 days of continuous production, the initial production startup operation is complete and you must perform casing diagnostic testing as required in §§ 250.521 and 250.523.
§ 250.523   When do I have to repeat casing diagnostic testing?
Casing diagnostic testing must be repeated according to the following table:
§ 250.524   How long do I keep records of casing pressure and diagnostic tests?
Records of casing pressure and diagnostic tests must be kept at the field office nearest the well for a minimum of 2 years. The last casing diagnostic test for each casing or riser must be retained at the field office nearest the well until the well is abandoned.
§ 250.525   When am I required to take action from my casing diagnostic test?
You must take action if you have any of the following conditions:
(a) Any fixed platform well with a casing pressure exceeding its maximum allowable wellhead operating pressure (MAWOP);
(b) Any fixed platform well with a casing pressure that is greater than 100 psig and that cannot bleed to 0 psig through a 1/2 -inch needle valve within 24 hours, or is not bled to 0 psig during a casing diagnostic test;
(c) Any well that has demonstrated tubing/casing, tubing/riser, casing/casing, riser/casing, or riser/riser communication;
(d) Any well that has sustained casing pressure (SCP) and is bled down to prevent it from exceeding its MAWOP, except during initial startup operations described in § 250.522;
(e) Any hybrid well with casing or riser pressure exceeding 100 psig; or
(f) Any subsea well with a casing pressure 100 psig greater than the external hydrostatic pressure at the subsea wellhead.
§ 250.526   What do I submit if my casing diagnostic test requires action?
Within 14 days after you perform a casing diagnostic test requiring action under § 250.525:
§ 250.527   What must I include in my notification of corrective action?
The following information must be included in the notification of corrective action:
(a) Lessee or Operator name;
(b) Area name and OCS block number;
(c) Well name and API number; and
(d) Casing diagnostic test data.
§ 250.528   What must I include in my casing pressure request?
The following information must be included in the casing pressure request:
(a) API number;
(b) Lease number;
(c) Area name and OCS block number;
(d) Well number;
(e) Company name and mailing address;
(f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
(g) All casing/riser calculated MAWOPs;
(h) All casing/riser pre-bleed down pressures;
(i) Shut-in tubing pressure;
(j) Flowing tubing pressure;
(k) Date and the calculated daily production rate during last well test (oil, gas, basic sediment, and water);
(l) Well status (shut-in, temporarily abandoned, producing, injecting, or gas lift);
(m) Well type (dry tree, hybrid, or subsea);
(n) Date of diagnostic test;
(o) Well schematic;
(p) Water depth;
(q) Volumes and types of fluid bled from each casing or riser evaluated;
(r) Type of diagnostic test performed:
(1) Bleed down/buildup test;
(2) Shut-in the well and monitor the pressure drop test;
(3) Constant production rate and decrease the annular pressure test;
(4) Constant production rate and increase the annular pressure test;
(5) Change the production rate and monitor the casing pressure test; and
(6) Casing pressure and tubing pressure history plot;
(s) The casing diagnostic test data for all casing exceeding 100 psig;
(t) Associated shoe strengths for casing shoes exposed to annular fluids;
(u) Concentration of any H 2 S that may be present;
(v) Whether the structure on which the well is located is manned or unmanned;
(w) Additional comments; and
(x) Request date.
§ 250.529   What are the terms of my casing pressure request?
Casing pressure requests are approved by the Regional Supervisor, Field Operations, for a term to be determined by the Regional Supervisor on a case-by-case basis. The Regional Supervisor may impose additional restrictions or requirements to allow continued operation of the well.
§ 250.530   What if my casing pressure request is denied?
(a) If your casing pressure request is denied, then the operating company must submit plans for corrective action to the respective District Manager within 30 days of receiving the denial. The District Manager will establish a specific time period in which this corrective action will be taken. You must notify the respective District Manager within 30 days after completion of your corrected action.
(b) You must submit the casing diagnostic test data to the appropriate Regional Supervisor, Field Operations, within 14 days of completion of the diagnostic test required under § 250.523(e).
§ 250.531   When does my casing pressure request approval become invalid?
A casing pressure request becomes invalid when:
(a) The casing or riser pressure increases by 200 psig over the approved casing pressure request pressure;
(b) The approved term ends;
(c) The well is worked-over, side-tracked, redrilled, recompleted, or acid stimulated;
(d) A different casing or riser on the same well requires a casing pressure request; or
(e) A well has more than one casing operating under a casing pressure request and one of the casing pressure requests become invalid, then all casing pressure requests for that well become invalid.
§ 250.600   General requirements.
Well-workover operations must be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the Outer Continental Shelf (OCS) including any mineral deposits (in areas leased and not leased), the National security or defense, or the marine, coastal, or human environment. In addition to the requirements of this subpart, you must also follow the applicable requirements of subpart G of this part.
§ 250.601   Definitions.
When used in this subpart, the following terms shall have the meanings given below:
Expected surface pressure means the highest pressure predicted to be exerted upon the surface of a well. In calculating expected surface pressure, you must consider reservoir pressure as well as applied surface pressure.
Routine operations mean any of the following operations conducted on a well with the tree installed:
(a) Cutting paraffin;
(b) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves which can be removed by wireline operations;
(c) Bailing sand;
(d) Pressure surveys;
(e) Swabbing;
(f) Scale or corrosion treatment;
(g) Caliper and gauge surveys;
(h) Corrosion inhibitor treatment;
(i) Removing or replacing subsurface pumps;
(j) Through-tubing logging (diagnostics);
(k) Wireline fishing; and
(l) Setting and retrieving other subsurface flow-control devices.
(m) Acid treatments.
Workover operations mean the work conducted on wells after the initial completion for the purpose of maintaining or restoring the productivity of a well.
§ 250.602   [Reserved]
§ 250.603   Emergency shutdown system.
When well-workover operations are conducted on a well with the tree removed, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station, except when there is no other hydrocarbon-producing well or other hydrocarbon flow on the platform.
§ 250.604   Hydrogen sulfide.
When a well-workover operation is conducted in zones known to contain hydrogen sulfide (H 2 S) or in zones where the presence of H 2 S is unknown (as defined in § 250.490 of this part), the lessee shall take appropriate precautions to protect life and property on the platform or rig, including but not limited to operations such as blowing the well down, dismantling wellhead equipment and flow lines, circulating the well, swabbing, and pulling tubing, pumps and packers. The lessee shall comply with the requirements in § 250.490 of this part as well as the appropriate requirements of this subpart.
§ 250.605   Subsea workovers.
No subsea well-workover operation including routine operations shall be commenced until the lessee obtains written approval from the District Manager in accordance with § 250.613 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will maintain adequate control of the well and permit continued safe production operations.
§§ 250.606-250.608   [Reserved]
§ 250.609   Well-workover structures on fixed platforms.
Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the operations proposed. Prior to moving a well-workover rig or well-servicing equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of the platform, and previous stresses to the platform.
§ 250.610   Diesel engine air intakes.
You must equip diesel engine air intakes with a device to shut down the diesel engine in the event of runaway. Diesel engines that are continuously attended must be equipped with remotely operated, manual, or automatic shutdown devices. Diesel engines that are not continuously attended must be equipped with automatic shutdown devices.
§ 250.611   Traveling-block safety device.
You must equip all units being used for well-workover operations that have both a traveling block and a crown block with a safety device that is designed to prevent the traveling block from striking the crown block. You must check the device for proper operation weekly and after each drill-line slipping operation. You must enter the results of the operational check in the operations log.
§ 250.612   Field well-workover rules.
When geological and engineering information available in a field enables the District Manager to determine specific operating requirements, field well-workover rules may be established on the District Manager's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-workover rules have been established, well-workover operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-workover rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.
§ 250.613   Approval and reporting for well-workover operations.
(a) No well-workover operation except routine ones, as defined in § 250.601 of this part, shall begin until the lessee receives written approval from the District Manager. Approval for these operations must be requested on Form BSEE-0124, Application for Permit to Modify.
(b) You must submit the following with Form BSEE-0124:
(1) A brief description of the well-workover procedures to be followed, a statement of the expected surface pressure, and type and weight of workover fluids;
(2) When changes in existing subsurface equipment are proposed, a schematic drawing of the well showing the zone proposed for workover and the workover equipment to be used;
(3) All information required in § 250.731.
(4) Where the well-workover is in a zone known to contain H 2 S or a zone where the presence of H2S is unknown, information pursuant to § 250.490 of this part; and
(5) Payment of the service fee listed in § 250.125.
(c) The following additional information shall be submitted with Form BSEE-0124 if completing to a new zone is proposed:
(1) Reason for abandonment of present producing zone including supportive well test data, and
(2) A statement of anticipated or known pressure data for the new zone.
(d) Within 30 days after completing the well-workover operation, except routine operations, Form BSEE-0124, Application for Permit to Modify, shall be submitted to the District Manager, showing the work as performed. In the case of a well-workover operation resulting in the initial recompletion of a well into a new zone, a Form BSEE-0125, End of Operations Report, shall be submitted to the District Manager and shall include a new schematic of the tubing subsurface equipment if any subsurface equipment has been changed.
§ 250.614   Well-control fluids, equipment, and operations.
The following requirements apply during all well-workover operations with the tree removed:
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-workover operations and shall not be left unattended at anytime unless the well is shut in and secured.
(b) When coming out of the hole with drill pipe or a workover string, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe or workover string, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe or workover string and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hold shall be utilized.
(c) The following well-control-fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
§§ 250.615-250.618   [Reserved]
§ 250.619   Tubing and wellhead equipment.
The lessee shall comply with the following requirements during well-workover operations with the tree removed:
(a) No tubing string may be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(1) The tubing string must be evaluated for burst, collapse, and axial loads with appropriate safety factors and material design factors for the pressure and temperature environments of the completion, production, shut-in, and injection load cases.
(2) The tubing string materials must be appropriate for the environment. You must follow NACE Standard MR0175-2003 (incorporated by reference in § 250.198) when H 2 S concentration may equal or exceed 0.05 psi partial pressure.
(3) The tubing string threaded connectors must be appropriate for the loading identified in paragraph (a)(1) of this section.
(b) When reinstalling the tree, you must:
(1) Equip wells to monitor for casing pressure according to the following chart:
* Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing hanger, and a surface christmas tree.
(2) Follow the casing pressure management requirements in subpart E of this part.
(c) You must design and test the wellhead, tree, and related equipment in accordance with ANSI/API Spec. 6A (incorporated by reference in § 250.198) or ANSI/API Spec. 17D (incorporated by reference in § 250.198), as applicable. The wellhead, tree, and related equipment must have a pressure rating greater than the shut-in tubing pressure and must be designed, installed, operated, maintained, and tested so as to achieve and maintain pressure containment and pressure control.
(1) Dry trees ( e.g., fixed, hybrid, or mudline suspension) for production or injection wells must be equipped with a minimum of one master valve and one surface safety valve (SSV), installed above the master valve, in the vertical run of the tree.
(2) Subsea production or injection wells must be equipped with a minimum of one USV installed in the horizontal or vertical run of the tree (for vertical or horizontal subsea trees).
(3) Wells with a mudline suspension conversion to a subsea tree must have a minimum of two casing strings tied back and sealed below the tubing head. At minimum, the production casing and the next outer casing must be tied back to the wellhead, to ensure annular isolation.
(d) You must install, maintain, and test surface and subsurface safety equipment in accordance with the applicable requirements in subpart H of this part.
(e) If you pull and reinstall packers and bridge plugs, you must meet the following requirements:
(1) The uppermost permanently installed packer and all permanently installed bridge plugs qualified as mechanical barriers must comply with ANSI/API Spec. 11D1 (as incorporated by reference in § 250.198).
(2) The production packer must be set at a depth that will allow for a column of weighted fluids to be placed above the packer that will exert a hydrostatic force greater than or equal to the force created by the reservoir pressure below the packer;
(3) The production packer must be set as close as practically possible to the perforated interval; and
(4) The production packer must be set at a depth that is within the cemented interval of the selected casing section.
(f) Your APM must include a description and calculations for how you determined the production packer setting depth.
(g) You must have two independent barriers, one being mechanical, in the exposed center wellbore prior to removing the tree and/or well control equipment.
§ 250.620   Wireline operations.
The lessee shall comply with the following requirements during routine, as defined in § 250.601 of this part, and nonroutine wireline workover operations:
(a) Wireline operations shall be conducted so as to minimize leakage of well fluids. Any leakage that does occur shall be contained to prevent pollution.
(b) All wireline perforating operations and all other wireline operations where communication exists between the completed hydrocarbon-bearing zone(s) and the wellbore shall use a lubricator assembly containing at least one wireline valve.
(c) When the lubricator is initially installed on the well, it shall be successfully pressure tested to the expected shut-in surface pressure.
§ 250.700   What operations and equipment does this subpart cover?
This subpart covers operations and equipment associated with drilling, completion, workover, and decommissioning activities. This subpart includes regulations applicable to drilling, completion, workover, and decommissioning activities in addition to applicable regulations contained in subparts D, E, F, and Q of this part unless explicitly stated otherwise.
§ 250.701   May I use alternate procedures or equipment during operations?
You may use alternate procedures or equipment during operations after receiving approval as described in § 250.141. You must identify and discuss your proposed alternate procedures or equipment in your Application for Permit to Drill (APD) (Form BSEE-0123) (see § 250.414(h)) or your Application for Permit to Modify (APM) (Form BSEE-0124). Procedures for obtaining approval of alternate procedures or equipment are described in § 250.141.
§ 250.702   May I obtain departures from these requirements?
You may apply for a departure from these requirements as described in § 250.142. Your request must include a justification showing why the departure is necessary. You must identify and discuss the departure you are requesting in your APD (see § 250.414(h)) or your APM.
§ 250.703   What must I do to keep wells under control?
You must take the necessary precautions to keep wells under control at all times, including:
(a) Use recognized engineering practices to reduce risks to the lowest level practicable when monitoring and evaluating well conditions and to minimize the potential for the well to flow or kick;
(b) Have a person onsite during operations who represents your interests and can fulfill your responsibilities;
(c) Ensure that the toolpusher, operator's representative, or a member of the rig crew maintains continuous surveillance on the rig floor from the beginning of operations until the well is completed or abandoned, unless you have secured the well with blowout preventers (BOPs), bridge plugs, cement plugs, or packers;
(d) Use personnel trained according to the provisions of subparts O and S of this part;
(e) Use and maintain equipment and materials necessary to ensure the safety and protection of personnel, equipment, natural resources, and the environment; and
(f) Use equipment that has been designed, tested, and rated for the maximum environmental and operational conditions to which it may be exposed while in service.
§ 250.710   What instructions must be given to personnel engaged in well operations?
Prior to engaging in well operations, personnel must be instructed in:
(a) Hazards and safety requirements. You must instruct your personnel regarding the safety requirements for the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment as required by subpart S of this part. The date and time of safety meetings must be recorded and available at the facility for review by BSEE representatives.
(b) Well control. You must prepare a well-control plan for each well. Each well-control plan must contain instructions for personnel about the use of each well-control component of your BOP, procedures that describe how personnel will seal the wellbore and shear pipe before maximum anticipated surface pressure (MASP) conditions are exceeded, assignments for each crew member, and a schedule for completion of each assignment. You must keep a copy of your well-control plan on the rig at all times, and make it available to BSEE upon request. You must post a copy of the well-control plan on the rig floor.
§ 250.711   What are the requirements for well-control drills?
You must conduct a weekly well-control drill with all personnel engaged in well operations. Your drill must familiarize personnel engaged in well operations with their roles and functions so that they can perform their duties promptly and efficiently as outlined in the well-control plan required by § 250.710.
(a) Timing of drills. You must conduct each drill during a period of activity that minimizes the risk to operations. The timing of your drills must cover a range of different operations, including drilling with a diverter, on-bottom drilling, and tripping. The same drill may not be repeated consecutively with the same crew.
(b) Recordkeeping requirements. For each drill, you must record the following in the daily report:
(1) Date, time, and type of drill conducted;
(2) The amount of time it took to be ready to close the diverter or use each well-control component of BOP system; and
(3) The total time to complete the entire drill.
(c) A BSEE ordered drill. A BSEE representative may require you to conduct a well-control drill during a BSEE inspection. The BSEE representative will consult with your onsite representative before requiring the drill.
§ 250.712   What rig unit movements must I report?
(a) You must report the movement of all rig units on and off locations to the District Manager using Form BSEE-0144, Rig Movement Notification Report. Rig units include MODUs, platform rigs, snubbing units, wire-line units used for non-routine operations, and coiled tubing units. You must inform the District Manager 24 hours before:
(1) The arrival of a rig unit on location;
(2) The movement of a rig unit to another slot. For movements that will occur less than 24 hours after initially moving onto location (e.g., coiled tubing and batch operations), you may include your anticipated movement schedule on Form BSEE-0144; or
(3) The departure of a rig unit from the location.
(b) You must provide the District Manager with the rig name, lease number, well number, and expected time of arrival or departure.
(c) If a MODU or platform rig is to be warm or cold stacked, you must inform the District Manager:
(1) Where the MODU or platform rig is coming from;
(2) The location where the MODU or platform rig will be positioned;
(3) Whether the MODU or platform rig will be manned or unmanned; and
(4) If the location for stacking the MODU or platform rig changes.
(d) Prior to resuming operations after stacking, you must notify the appropriate District Manager of any construction, repairs, or modifications associated with the drilling package made to the MODU or platform rig.
(e) If a drilling rig is entering OCS waters, you must inform the District Manager where the drilling rig is coming from.
(f) If you change your anticipated date for initially moving on or off location by more than 24 hours, you must submit an updated Form BSEE-0144, Rig Movement Notification Report.
(g) You are not required to report rig unit movements to and from the safe zone during the course of permitted operations.
(h) If a rig unit is already on a well, you are not required to report any additional rig unit movements on that well.
§ 250.713   What must I provide if I plan to use a mobile offshore drilling unit (MODU) for well operations?
If you plan to use a MODU for well operations, you must provide:
(a) Fitness requirements. Information and data to demonstrate the MODU's capability to perform at the proposed location. This information must include the maximum environmental and operational conditions that the MODU is designed to withstand, including the minimum air gap necessary for both hurricane and non-hurricane seasons. If sufficient environmental information and data are not available at the time you submit your APD or APM, the District Manager may approve your APD or APM, but require you to collect and report this information during operations. Under this circumstance, the District Manager may revoke the approval of the APD or APM if information collected during operations shows that the MODU is not capable of performing at the proposed location.
(b) Foundation requirements. Information to show that site-specific soil and oceanographic conditions are capable of supporting the proposed bottom-founded MODU. If you provided sufficient site-specific information in your EP, DPP, or DOCD submitted to BOEM for that well location and conditions, you may reference that information. The District Manager may require you to conduct additional surveys and soil borings before approving the APD or APM if additional information is needed to make a determination that the conditions are capable of supporting the MODU, or equipment installed on a subsea wellhead. For a moored rig, you must submit a plat of the rig's anchor pattern approved in your EP, DPP, or DOCD in your APD or APM.
(c) For frontier areas. (1) If the design of the MODU you plan to use in a frontier area is unique or has not been proven for use in the proposed environment, the District Manager may require you to submit a third-party review of the MODU design. If required, you must obtain a third-party review of your MODU similar to the process outlined in §§ 250.915 through 250.918. You may submit this information before submitting an APD or APM.
(2) If you plan to conduct operations in a frontier area, you must have a contingency plan that addresses design and operating limitations of the MODU. Your plan must identify the actions necessary to maintain safety and prevent damage to the environment. Actions must include the suspension, curtailment, or modification of operations to remedy various operational or environmental situations (e.g., vessel motion, riser offset, anchor tensions, wind speed, wave height, currents, icing or ice-loading, settling, tilt or lateral movement, resupply capability).
(d) Additional documentation. You must provide the current Certificate of Inspection (for U.S.-flag vessels) or Certificate of Compliance (for foreign-flag vessels) from the USCG and Certificate of Classification. You must also provide current documentation of any operational limitations imposed by an appropriate classification society.
(e) Dynamically positioned MODU. If you use a dynamically positioned MODU, you must include in your APD or APM your contingency plan for moving off location in an emergency situation. At a minimum, your plan must address emergency events caused by storms, currents, station-keeping failures, power failures, and losses of well control. The District Manager may require your plan to include additional events that may require movement of the MODU and other information needed to clarify or further address how the MODU will respond to emergencies or other events.
(f) Inspection of MODU. The MODU must be available for inspection by the District Manager before commencing operations and at any time during operations.
(g) Current monitoring. For water depths greater than 400 meters (1,312 feet), you must include in your APD or APM:
(1) A description of the specific current speeds that will cause you to implement rig shutdown, move-off procedures, or both; and
(2) A discussion of the specific measures you will take to curtail rig operations and move off location when such currents are encountered. You may use criteria, such as current velocities, riser angles, watch circles, and remaining rig power to describe when these procedures or measures will be implemented.
§ 250.714   Do I have to develop a dropped objects plan?
If you use a floating rig unit in an area with subsea infrastructure, you must develop a dropped objects plan and make it available to BSEE upon request. This plan must be updated as the infrastructure on the seafloor changes. Your plan must include:
(a) A description and plot of the path the rig will take while running and pulling the riser;
(b) A plat showing the location of any subsea wells, production equipment, pipelines, and any other identified debris;
(c) Modeling of a dropped object's path with consideration given to metocean conditions for various material forms, such as a tubular (e.g., riser or casing) and box (e.g., BOP or tree);
(d) Communications, procedures, and delegated authorities established with the production host facility to shut-in any active subsea wells, equipment, or pipelines in the event of a dropped object; and
(e) Any additional information required by the District Manager as appropriate to clarify, update, or evaluate your dropped objects plan.
§ 250.715   Do I need a global positioning system (GPS) for all MODUs?
All MODUs must have a minimum of two functioning GPS transponders at all times, and you must provide to BSEE real-time access to the GPS data prior to and during each hurricane season.
(a) The GPS must be capable of monitoring the position and tracking the path in real-time if the MODU moves from its location during a severe storm.
(b) You must install and protect the tracking system's equipment to minimize the risk of the system being disabled.
(c) You must place the GPS transponders in different locations for redundancy to minimize risk of system failure.
(d) Each GPS transponder must be capable of transmitting data for at least 7 days after a storm has passed.
(e) If the MODU is moved off location in the event of a storm, you must immediately begin to record the GPS location data.
(f) You must contact the Regional Office and allow real-time access to the MODU location data. When you contact the Regional Office, provide the following:
(1) Name of the lessee and operator with contact information;
(2) MODU name;
(3) Initial date and time; and
(4) How you will provide GPS real-time access.
§ 250.720   When and how must I secure a well?
(a) Whenever you interrupt operations, you must notify the District Manager. Before moving off the well, you must have two independent barriers installed, at least one of which must be a mechanical barrier, as approved by the District Manager. You must install the barriers at appropriate depths within a properly cemented casing string or liner. Before removing a subsea BOP stack or surface BOP stack on a mudline suspension well, you must conduct a negative pressure test in accordance with § 250.721.
(1) The events that would cause you to interrupt operations and notify the District Manager include, but are not limited to, the following:
(i) Evacuation of the rig crew;
(ii) Inability to keep the rig on location;
(iii) Repair to major rig or well-control equipment;
(iv) Observed flow outside the well's casing (e.g., shallow water flow or bubbling); or
(v) Impending National Weather Service-named tropical storm or hurricane.
(2) The District Manager may approve alternate procedures or barriers, in accordance with § 250.141, if you do not have time to install the required barriers or if special circumstances occur.
(3) If you unlatch the BOP or LMRP:
(i) Upon relatch of the BOP, you must test according to § 250.734(b)(2), or
(ii) Upon relatch of the LMRP, you must test according to § 250.734(b)(3); and
(iii) You must submit a revised permit with a written statement from an independent third party certifying that the previous certification under § 250.731(c) remains valid and receive District Manager approval before resuming operations.
(b) Before you displace kill-weight fluid from the wellbore and/or riser, thereby creating an underbalanced state, you must obtain approval from the District Manager. To obtain approval, you must submit with your APD or APM your reasons for displacing the kill-weight fluid and provide detailed step-by-step written procedures describing how you will safely displace these fluids. The step-by-step displacement procedures must address the following:
(1) Number and type of independent barriers, as described in § 250.420(b)(3), that are in place for each flow path that requires such barriers;
(2) Tests you will conduct to ensure integrity of independent barriers;
(3) BOP procedures you will use while displacing kill-weight fluids; and
(4) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore.
(c) For Arctic OCS exploratory drilling operations, in addition to the requirements of paragraphs (a) and (b) of this section:
(1) If you move your drilling rig off a well prior to completion or permanent abandonment, you must ensure that any equipment left on, near, or in a wellbore that has penetrated below the surface casing is positioned in a manner to:
(i) Protect the well head; and
(ii) Prevent or minimize the likelihood of compromising the down-hole integrity of the well or the effectiveness of the well plugs.
(2) In areas of ice scour you must use a well mudline cellar or an equivalent means of minimizing the risk of damage to the well head and wellbore. BSEE may approve an equivalent means that will meet or exceed the level of safety and environmental protection provided by a mudline cellar if the operator can show that utilizing a mudline cellar would compromise the stability of the rig, impede access to the well head during a well control event, or otherwise create operational risks.
(d) You must have the equipment used solely for intervention operations (e.g., tree interface tools) identified, readily available, properly maintained, and available for BSEE inspection upon request. This equipment is required for subsea completed wells with a tree installed, that meet the following conditions:
(1) Have a shut-in tubing pressure that is greater than the hydrostatic pressure of the water column, or
(2) Are not capable of having the annulus monitored.
§ 250.721   What are the requirements for pressure testing casing and liners?
(a) You must test each casing string that extends to the wellhead according to the following table:
(b) You must test each drilling liner and liner-top to a pressure at least equal to the anticipated leak-off pressure of the formation below that liner shoe, or subsequent liner shoes if set. You must conduct this test before you continue operations in the well.
(c) You must test each production liner and liner-top to a minimum of 500 psi above the formation fracture pressure at the casing shoe into which the liner is lapped.
(d) The District Manager may approve or require other casing test pressures as appropriate under the circumstances to ensure casing integrity.
(e) If you plan to produce a well, you must:
(1) For a well that is fully cased and cemented, pressure test the entire well to maximum anticipated shut-in tubing pressure, not to exceed 70% of the burst rating limit of the weakest component before perforating the casing or liner; or
(2) For an open-hole completion, pressure test the entire well to maximum anticipated shut-in tubing pressure, not to exceed 70% of the burst rating limit of the weakest component before you drill the open-hole section.
(f) You may not resume operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test, or if there is another indication of a leak, you must submit to the District Manager for approval your proposed plans to re-cement, repair the casing or liner, or run additional casing/liner to provide a proper seal. Your submittal must include a PE certification of your proposed plans.
(g) You must perform a negative pressure test on all wells that use a subsea BOP stack or wells with mudline suspension systems.
(1) You must perform a negative pressure test on your final casing string or liner. This test must be conducted after setting your second barrier just above the shoe track, but prior to conducting any completion operations.
(2) You must perform a negative pressure test prior to unlatching the BOP at any point in the well. The negative pressure test must be performed on those components, at a minimum, that will be exposed to the negative differential pressure that will occur when the BOP is disconnected.
(3) The District Manager may require you to perform additional negative pressure tests on other casing strings or liners (e.g., intermediate casing string or liner) or on wells with a surface BOP stack as appropriate to demonstrate casing or liner integrity.
(4) You must submit for approval with your APD or APM, test procedures and criteria for a successful negative pressure test. If any of your test procedures or criteria for a successful test change, you must submit for approval the changes in a revised APD or APM.
(5) You must document all your test results and make them available to BSEE upon request.
(6) If you have any indication of a failed negative pressure test, such as, but not limited to, pressure buildup or observed flow, you must immediately investigate the cause. If your investigation confirms that a failure occurred during the negative pressure test, you must:
(i) Correct the problem and immediately notify the appropriate District Manager; and
(ii) Submit a description of the corrective action taken and receive approval from the appropriate District Manager for the retest.
(7) You must have two barriers in place, as described in § 250.420(b)(3), at any time and for any well, prior to performing the negative pressure test.
(8) You must include documentation of the successful negative pressure test in the End-of-Operations Report (Form BSEE-0125).
§ 250.722   What are the requirements for prolonged operations in a well?
If wellbore operations continue within a casing or liner for more than 30 days from the previous pressure test of the well's casing or liner, you must:
(a) Stop operations as soon as practicable, and evaluate the effects of the prolonged operations on continued operations and the life of the well. At a minimum, you must:
(1) Evaluate the well casing with a pressure test, caliper tool, or imaging tool. On a case-by-case basis, the District Manager may require a specific method of evaluation of the effects on the well casing of prolonged operations; and
(2) Report the results of your evaluation to the District Manager and obtain approval of those results before resuming operations. Your report must include calculations that indicate the well's integrity is above the minimum safety factors, if an imaging tool or caliper is used. District Manager approval is not required to resume operations if you conducted a successful pressure test as approved in your permit. You must document the successful pressure test in the WAR.
(b) If well integrity has deteriorated to a level below minimum safety factors, you must:
(1) Obtain approval from the District Manager to begin repairs or install additional casing. To obtain approval, you must also provide a PE certification showing that he or she reviewed and approved the proposed changes;
(2) Repair the casing or run another casing string; and
(3) Perform a pressure test after the repairs are made or additional casing is installed and report the results to the District Manager as specified in § 250.721.
§ 250.723   What additional safety measures must I take when I conduct operations on a platform that has producing wells or has other hydrocarbon flow?
You must take the following safety measures when you conduct operations with a rig unit on or jacked-up over a platform with producing wells or that has other hydrocarbon flow:
(a) The movement of rig units and related equipment on and off a platform or from well to well on the same platform, including rigging up and rigging down, must be conducted in a safe manner;
(b) You must install an emergency shutdown station for the production system near the rig operator's console;
(c) You must shut-in all producible wells located in the affected wellbay below the surface and at the wellhead when:
(1) You move a rig unit or related equipment on and off a platform. This includes rigging up and rigging down activities within 500 feet of the affected platform;
(2) You move or skid a rig unit between wells on a platform; or
(3) A MODU moves within 500 feet of a platform. You may resume production once the MODU is in place, secured, and ready to begin operations.
(d) All wells in the same well-bay which are capable of producing hydrocarbons must be shut-in below the surface with a pump-through-type tubing plug and at the surface with a closed master valve prior to moving rig units and related equipment, unless otherwise approved by the District Manager.
(1) A closed surface-controlled subsurface safety valve of the pump-through-type may be used in lieu of the pump-through-type tubing plug provided that the surface control has been locked out of operation.
(2) The well to which a rig unit or related equipment is to be moved must be equipped with a back-pressure valve prior to removing the tree and installing and testing the BOP system.
(3) The well from which a rig unit or related equipment is to be moved must be equipped with a back pressure valve prior to removing the BOP system and installing the production tree.
(e) Coiled tubing units, snubbing units, or wireline units may be moved onto and off of a platform without shutting in wells.
§ 250.724   What are the real-time monitoring requirements?
(a) When conducting well operations with a subsea BOP or with a surface BOP on a floating facility, or when operating in an high pressure high temperature (HPHT) environment, you must gather and monitor real-time well data using an independent, automatic, and continuous monitoring system capable of recording, storing, and transmitting data regarding the following:
(1) The BOP control system;
(2) The well's active fluid circulating system; and
(3) The well's downhole conditions with the bottom hole assembly tools (if any tools are installed).
(b) You must transmit these data as they are gathered, barring unforeseeable or unpreventable interruptions in transmission, and have the capability to monitor the data, using qualified personnel in accordance with a real-time monitoring plan, as provided in paragraph (c) of this section.
(c) You must develop and implement a real-time monitoring plan. Your real-time monitoring plan, and all real-time monitoring data, must be made available to BSEE upon request. Your real-time monitoring plan must include the following:
(1) A description of your real-time monitoring capabilities, including the types of the data collected;
(2) A description of how your real-time monitoring data will be transmitted during operations, how the data will be labeled and monitored by qualified personnel, and how the data will be stored as required in §§ 250.740 and 250.741;
(3) A description of your procedures for providing BSEE access, upon request, to your real-time monitoring data;
(4) The qualifications of the personnel monitoring the data;
(5) Your procedures for, and methods of, communication between rig personnel and the monitoring personnel; and
(6) Actions to be taken if you lose any real-time monitoring capabilities or communications between rig personnel and monitoring personnel, and a protocol for how you will respond to any significant and/or prolonged interruption of monitoring capabilities or communications, including your protocol for notifying BSEE of any significant and/or prolonged interruptions.
§ 250.730   What are the general requirements for BOP systems and system components?
(a) You must ensure that the BOP system and system components are designed, installed, maintained, inspected, tested, and used properly to ensure well control. The working-pressure rating of each BOP component (excluding annular(s)) must exceed MASP as defined for the operation. For a subsea BOP, the MASP must be determined at the mudline. The BOP system includes the BOP stack, control system, and any other associated system(s) and equipment. The BOP system and individual components must be able to perform their expected functions and be compatible with each other. Your BOP system must be capable of closing and sealing the wellbore to the well's MASP at all times, except as otherwise specified in the BOP system requirements of this subpart. The BOP system must be capable of closing and sealing without losing ram closure time and sealing integrity due to the corrosiveness, volume, and abrasiveness of any fluids in the wellbore that the BOP system may encounter. Your BOP system must meet the following requirements:
(1) The BOP requirements of API Standard 53 (incorporated by reference in § 250.198) and the requirements of §§ 250.733 through 250.739. If there is a conflict between API Standard 53 and the requirements of this subpart, you must follow the requirements of this subpart.
(2) The provisions of the following industry standards (all incorporated by reference in § 250.198) that apply to BOP systems:
(i) ANSI/API Spec. 6A;
(ii) ANSI/API Spec. 16A;
(iii) ANSI/API Spec. 16C;
(iv) API Spec. 16D; and
(v) ANSI/API Spec. 17D.
(3) For surface and subsea BOPs, the pipe and variable bore rams installed in the BOP stack must be capable of effectively closing and sealing on the tubular body of any drill pipe, workstring, and tubing (excluding tubing with exterior control lines and flat packs) in the hole under MASP, as defined for the operation, at the proposed regulator settings of the BOP control system.
(4) The current set of approved schematic drawings must be available on the rig and at an onshore location. If you make any modifications to the BOP or control system that will require changes to your BSEE-approved schematic drawings, you must suspend operations until you obtain approval from the District Manager.
(b) You must ensure that the design, fabrication, maintenance, and repair of your BOP system is in accordance with the requirements contained in this part, applicable Original Equipment Manufacturer's (OEM) recommendations unless otherwise directed by BSEE, and recognized engineering practices. The training and qualification of repair and maintenance personnel must meet or exceed applicable OEM training recommendations unless otherwise directed by BSEE.
(c) You must follow the failure reporting procedures contained in API Standard 53 (incorporated by reference in § 250.198) and:
(1) You must provide a written notice of equipment failure to the Office of Offshore Regulatory Programs (OORP) Chief, any third party designated by BSEE pursuant to paragraph (c)(4) of this section, and the manufacturer of such equipment within 30 days after the discovery and identification of the failure. A failure is any condition that prevents the equipment from meeting the functional specification.
(2) You must start an investigation and a failure analysis within 90 days of the failure to determine the cause of the failure and complete the investigation and the failure analysis within 120 days after initiation. You also must document the results and any corrective action. You must submit the analysis report to the OORP Chief, any third party designated by BSEE pursuant to paragraph (c)(4) of this section, and the manufacturer. If you cannot complete the investigation and analysis within the specified time, you must submit an extension request detailing when and how you will complete the investigation and analysis to BSEE for approval. You must submit the extension request to the OORP Chief.
(3) If the equipment manufacturer notifies you that it has changed the design of the equipment that failed or if you have changed operating or repair procedures as a result of a failure, then you must, within 30 days of such changes, report the design change or modified procedures in writing to the OORP Chief, and any third party designated by BSEE pursuant to paragraph (c)(4) of this section.
(4) Submit notices and reports to the Chief, Office of Offshore Regulatory Programs; Bureau of Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, Virginia 20166. BSEE may designate a third party to also receive the data and reports. If BSEE designates a third party, you must submit the data and reports to the designated third party as well.
(d) If you plan to use a BOP stack manufactured after the effective date of this regulation, you must use one manufactured pursuant to an ANSI/API Spec. Q1 (as incorporated by reference in § 250.198) quality management system. Such quality management system must be certified by an entity that meets the requirements of ISO/IEC 17021-1 (as incorporated by reference in § 250.198).
(1) BSEE may consider accepting equipment manufactured under quality assurance programs other than ANSI/API Spec. Q1, provided you submit a request to the Chief, OORP for approval, containing relevant information about the alternative program.
(2) You must submit this request to the Chief, OORP; Bureau of Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, Virginia 20166.
§ 250.731   What information must I submit for BOP systems and system components?
For any operation that requires the use of a BOP, you must include the information listed in this section with your applicable APD, APM, or other submittal. You are required to submit this information only once for each well, unless the information changes from what you provided in an earlier approved submission or you have moved off location from the well. After you have submitted this information for a particular well, subsequent APMs or other submittals for the well should reference the approved submittal containing the information required by this section and confirm that the information remains accurate and that you have not moved off location from that well. If the information changes or you have moved off location from the well, you must submit updated information in your next submission.
§ 250.732   What are the independent third party requirements for BOP systems and system components?
(a) Prior to beginning any operation requiring the use of any BOP, you must submit verification by an independent third party and supporting documentation as required by this paragraph to the appropriate District Manager and Regional Supervisor.
(b) The independent third party must be a technical classification society, a licensed professional engineering firm, or a registered professional engineer capable of providing the required certifications and verifications. You must submit the independent third party qualifications to BSEE with the associated permit application (e.g., APD and APM). BSEE will evaluate the submitted qualifications to ensure they meet the regulatory requirements for permit approval.
(c) Before you begin any operations in an HPHT environment, as defined by § 250.105, with the proposed equipment, you must include the following in your applicable permit:
(1) The I3P certification required in § 250.731(c);
(2) A description of any new or unusual technology being used;
(3) A reference to the previously approved associated New or Unusual Technology Barrier Equipment Conceptual Plan;
(4) The final report and statements in accordance with § 250.232(c); and
(5) The fit for service statement required in § 250.230.
You may not deploy your proposed BOP systems and related equipment that will or may be exposed to an HPHT environment until BSEE approves the New or Unusual Technology Barrier Equipment Conceptual Plan and appropriate permits ( e.g., APD and APM).
(d) You must make all documentation that demonstrates compliance with the requirements of this section available to BSEE upon request.
§ 250.733   What are the requirements for a surface BOP stack?
(a) When you drill or conduct operations with a surface BOP stack, you must install the BOP system before drilling or conducting operations to deepen the well below the surface casing and after the well is deepened below the surface casing point. The surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs, consisting of one annular BOP, one BOP equipped with blind shear rams, and two BOPs equipped with pipe rams.
(1) The blind shear rams must be capable of shearing at any point along the tubular body of any drill pipe (excluding tool joints, bottom-hole tools, and bottom hole assemblies that include heavy-weight pipe or collars), workstring, tubing and associated exterior control lines, and any electric-, wire-, and slick-line that is in the hole and sealing the wellbore after shearing. Prior to April 29, 2021, if your blind shear rams are unable to cut any electric-, wire-, or slick-line under MASP as defined for the operation and seal the wellbore, you must use an alternative cutting device capable of shearing the lines before closing the BOP. This device must be available on the rig floor during operations that require their use.
(2) The two BOPs equipped with pipe rams must be capable of closing and sealing on the tubular body of any drill pipe, workstring, and tubing under MASP, as defined for the operation, except for tubing with exterior control lines and flat packs, a bottom hole assembly that includes heavy-weight pipe or collars, and bottom-hole tools.
(b) If you plan to use a surface BOP on a floating production facility you must:
(1) On new floating production facilities installed after April 29, 2021, that include a surface BOP, or when you replace an entire surface BOP stack on an existing floating production facility, follow the BOP requirements in § 250.734(a)(1).
(2) For risers installed after July 28, 2016, use a dual bore riser configuration before drilling or operating in any hole section or interval where hydrocarbons are, or may be, exposed to the well. The dual bore riser must meet the design requirements of API RP 2RD (as incorporated by reference in § 250.198), including appropriate design for the maximum anticipated operating and environmental conditions.
(i) For a dual bore riser configuration, the annulus between the risers must be monitored for pressure during operations. You must describe in your APD or APM your annulus monitoring plan and how you will secure the well in the event a leak is detected.
(ii) The inner riser for a dual riser configuration is subject to the requirements at § 250.721 for testing the casing or liner.
(c) You must install separate side outlets on the BOP stack for the kill and choke lines. If your stack does not have side outlets, you must install a drilling spool with side outlets. The outlet valves must hold pressure from both directions.
(d) You must install a choke and a kill line on the BOP stack. You must equip each line with two full-bore, full-opening valves, one of which must be remote-controlled. On the kill line, you may install a check valve and a manual valve instead of the remote-controlled valve. To use this configuration, both manual valves must be readily accessible and you must install the check valve between the manual valves and the pump.
(e) Additional requirements for surface BOP systems used in well-completion, workover, and decommissioning operations. The minimum BOP system for well-completion, workover, and decommissioning operations must meet the appropriate standards from the following table:
§ 250.734   What are the requirements for a subsea BOP system?
(a) When you drill or conduct operations with a subsea BOP system, you must install the BOP system before drilling to deepen the well below the surface casing or before conducting operations if the well is already deepened beyond the surface casing point. The District Manager may require you to install a subsea BOP system before drilling or conducting operations below the conductor casing if proposed casing setting depths or local geology indicate the need. The following table outlines your requirements.
(b) If you suspend operations to make repairs to any part of the subsea BOP system, you must stop operations at a safe downhole location. Before resuming operations you must:
(1) Submit a revised permit with a written statement from an independent third party documenting the repairs and certifying that the previous certification in § 250.731(c) remains valid;
(2) Upon relatch of the BOP, perform an initial subsea BOP test in accordance with § 250.737(d)(4), including deadman in accordance with § 250.737(d)(12)(vi). If repairs take longer than 30 days, once the BOP is on deck, you must test in accordance with the requirements of § 250.737;
(3) Upon relatch of the LMRP, you must test according to the following:
(i) Pressure test riser connector/gasket in accordance with § 250.737(b) and (c);
(ii) Pressure test choke and kill stabs at LMRP/BOP interface in accordance with § 250.737(b) and (c);
(iii) Full function test of both pods and both control panels;
(iv) Verify acoustic pod communication (if equipped); and
(v) Deadman test with pressure test in accordance with § 250.737(d)(12)(vi).
(4) Receive approval from the District Manager.
(c) If you plan to drill a new well with a subsea BOP, you do not need to submit with your APD the verifications required by this subpart for the open water drilling operation. Before drilling out the surface casing, you must submit for approval a revised APD, including the verifications required in this subpart.
§ 250.735   What associated systems and related equipment must all BOP systems include?
All BOP systems must include the following associated systems and related equipment:
(a) An accumulator system (as specified in API Standard 53, incorporated by reference in § 250.198). Your accumulator system must have the fluid volume capacity and appropriate pre-charge pressures in accordance with API Standard 53. If you supply the accumulator regulators by rig air and do not have a secondary source of pneumatic supply, you must equip the regulators with manual overrides or other devices to ensure capability of hydraulic operations if rig air is lost;
(b) An automatic backup to the primary accumulator-charging system. The power source must be independent from the power source for the primary accumulator-charging system. The independent power source must possess sufficient capability to close and hold closed all BOP components under MASP conditions as defined for the operation;
(c) At least two full BOP control stations. One station must be on the rig floor. You must locate the other station in a readily accessible location away from the rig floor;
(d) The choke line(s) installed above the bottom well-control ram;
(e) The kill line must be installed beneath at least one well-control ram, and may be installed below the bottom ram;
(f) A fill-up line above the uppermost BOP;
(g) Locking devices for all BOP sealing rams ( i.e. , blind shear rams, pipe rams and variable bore rams), as follows:
(1) For subsea BOPs, hydraulic locking devices must be installed on all sealing rams;
(2) For surface BOPs:
(i) Remotely-operated locking devices must be installed on blind shear rams no later than April 29, 2019;
(ii) Manual or remotely-operated locking devices must be installed on pipe rams and variable bore rams; and
(h) A wellhead assembly with a RWP that exceeds the maximum anticipated wellhead pressure.
§ 250.736   What are the requirements for choke manifolds, kelly-type valves inside BOPs, and drill string safety valves?
(a) Your BOP system must include a choke manifold that is suitable for the anticipated surface pressures, anticipated methods of well control, the surrounding environment, and the corrosiveness, volume, and abrasiveness of drilling fluids and well fluids that you may encounter.
(b) Choke manifold components must have a RWP at least as great as the RWP of the ram BOPs. If your choke manifold has buffer tanks downstream of choke assemblies, you must install isolation valves on any bleed lines.
(c) Valves, pipes, flexible steel hoses, and other fittings upstream of the choke manifold must have a RWP at least as great as the RWP of the ram BOPs.
(d) You must use the following BOP equipment with a RWP and temperature of at least as great as the working pressure and temperature of the ram BOP during all operations:
(1) The applicable kelly-type valves as described in API Standard 53 (incorporated by reference in § 250.198);
(2) On a top-drive system equipped with a remote-controlled valve, a strippable kelly-type valve must be installed below the remote-controlled valve;
(3) An inside BOP in the open position located on the rig floor. You must be able to install an inside BOP for each size connection in the pipe;
(4) A drill string safety valve in the open position located on the rig floor. You must have a drill-string safety valve available for each size connection in the pipe;
(5) When running casing, a safety valve in the open position available on the rig floor to fit the casing string being run in the hole. For subsea BOPs, the safety valve must be available on the rig floor if the length of casing being run exceeds the water depth, which would result in the casing being across the BOP stack and the rig floor prior to crossing over to the drill pipe running string;
(6) All required manual and remote- controlled kelly-type valves, drill-string safety valves, and comparable-type valves ( i.e. , kelly-type valve in a top-drive system) that are essentially full opening; and
(7) A wrench to fit each manual valve. Each wrench must be readily accessible to the drilling crew.
§ 250.737   What are the BOP system testing requirements?
Your BOP system (this includes the choke manifold, kelly-type valves, inside BOP, and drill string safety valve) must meet the following testing requirements:
(a) Pressure test frequency. You must pressure test your BOP system:
(1) When installed;
(2) Before 14 days have elapsed since your last BOP pressure test, or 30 days since your last blind shear ram BOP pressure test. You must begin to test your BOP system before midnight on the 14th day (or 30th day for your blind shear rams) following the conclusion of the previous test;
(3) Before drilling out each string of casing or a liner. You may omit this pressure test requirement if you did not remove the BOP stack to run the casing string or liner, the required BOP test pressures for the next section of the hole are not greater than the test pressures for the previous BOP test, and the time elapsed between tests has not exceeded 14 days (or 30 days for blind shear rams). You must indicate in your APD which casing strings and liners meet these criteria;
(4) In lieu of meeting the schedule established in paragraph (a)(2) of this section, you may request that BSEE approve a 21-day BOP testing frequency. To obtain BSEE approval, you must submit a request to the appropriate BSEE Regional Supervisor, District Field Operations. Your request must demonstrate that you have developed a BOP health monitoring plan that includes certain system capabilities. As long as your plan is consistent with recognized engineering and industry practice, BSEE will approve your request if it includes the following:
(i) Condition monitoring tools, including continuous surveillance of sensor readings from the BOP control system, real-time condition analysis and displays, functional pressure signal analysis, historical sensor data;
(ii) Failure propagation analysis;
(iii) A failure tracking and resolution system that includes detailed failure reports and identification of recurring problems; and
(iv) Submission of quarterly reports of the data collected pursuant to paragraphs (a)(4)(i)(iii) to the BSEE Regional Supervisor, District Field Operations.
(5) The District Manager may require more frequent testing if conditions or your BOP performance warrant.
(b) Pressure test procedures. When you pressure test the BOP system, you must conduct a low-pressure test and a high-pressure test for each BOP component (excluding test rams and non-sealing shear rams). You must begin each test by conducting the low-pressure test then transition to the high-pressure test. Each individual pressure test must hold pressure long enough to demonstrate the tested component(s) holds the required pressure. The table in this paragraph (b) outlines your pressure test requirements.
(c) Duration of pressure test. Each test must hold the required pressure for 5 minutes, which must be recorded on a chart not exceeding 4 hours, or on a digital recorder. However, for surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if recorded on a chart not exceeding 4 hours, or on a digital recorder. The recorded test pressures must be within the middle half of the chart range, i.e., cannot be within the lower or upper one-fourth of the chart range. If the equipment does not hold the required pressure during a test, you must correct the problem and retest the affected component(s).
(d) Additional test requirements. You must meet the following additional BOP testing requirements:
(e) Prior to conducting any shear ram tests in which you will shear pipe, you must notify the District Manager at least 72 hours in advance, to ensure that a BSEE representative will have access to the location to witness any testing.
§ 250.738   What must I do in certain situations involving BOP equipment or systems?
The table in this section describes actions that you must take when certain situations occur with BOP systems.
§ 250.739   What are the BOP maintenance and inspection requirements?
(a) You must maintain and inspect your BOP system to ensure that the equipment functions as designed. The BOP maintenance and inspections must meet or exceed any OEM recommendations, recognized engineering practices, and industry standards incorporated by reference into the regulations of this subpart, including API Standard 53 (incorporated by reference in § 250.198). You must document how you met or exceeded the provisions of API Standard 53, maintain complete records to ensure the traceability of BOP stack equipment beginning at fabrication, and record the results of your BOP inspections and maintenance actions. You must make all records available to BSEE upon request.
(b) A major, detailed inspection of the well control system components (including but not limited to riser, BOP, LMRP, and control pods) must be performed every 5 years. This major inspection may be performed in phased intervals. You must track and document all system and component inspection dates. These records must be available on the rig. An independent third party is required to review the inspection results and must compile a detailed report of the inspection results, including descriptions of any problems and how they were corrected. You must make these reports available to BSEE upon request. This major inspection must be performed every 5 years from the following applicable dates, whichever is later:
(1) The date the equipment owner accepts delivery of a new build drilling rig with a new BOP system;
(2) The date the new, repaired, or remanufactured equipment is initially installed into the system; or
(3) The date of the last 5 year inspection for the component.
(c) You must visually inspect your surface BOP system on a daily basis. You must visually inspect your subsea BOP system, marine riser, and wellhead at least once every 3 days if weather and sea conditions permit. You may use cameras to inspect subsea equipment.
(d) You must ensure that all personnel maintaining, inspecting, or repairing BOPs, or critical components of the BOP system, are trained in accordance with applicable training requirements in subpart S of this part, any applicable OEM criteria, recognized engineering practices, and industry standards incorporated by reference in this subpart.
(e) You must make all records available to BSEE upon request. You must ensure that the rig unit owner maintains the BOP maintenance, inspection, and repair records on the rig unit for 2 years from the date the records are created or for a longer period if directed by BSEE. You must ensure that all equipment schematics, maintenance, inspection, and repair records are located at an onshore location for the service life of the equipment.
§ 250.740   What records must I keep?
You must keep a daily report consisting of complete, legible, and accurate records for each well. You must keep records onsite while well operations continue. After completion of operations, you must keep all operation and other well records for the time periods shown in § 250.741 at a location of your choice, except as required in § 250.746. The records must contain complete information on all of the following:
(a) Well operations, all testing conducted, and any real-time monitoring data as required by § 250.724;
(b) Descriptions of formations penetrated;
(c) Content and character of oil, gas, water, and other mineral deposits in each formation;
(d) Kind, weight, size, grade, and setting depth of casing;
(e) All well logs and surveys run in the wellbore;
(f) Any significant malfunction or problem; and
(g) All other information required by the District Manager as appropriate to ensure compliance with the requirements of this section and to enable BSEE to determine that the well operations are consistent with conservation of natural resources and protection of safety and the environment on the OCS.
§ 250.741   How long must I keep records?
You must keep records for the time periods shown in the following table.
§ 250.742   What well records am I required to submit?
You must submit to BSEE copies of logs or charts of electrical, radioactive, sonic, and other well logging operations; directional and vertical well surveys; velocity profiles and surveys; and analysis of cores. Each Region will provide specific instructions for submitting well logs and surveys.
§ 250.743   What are the well activity reporting requirements?
(a) For operations in the BSEE Gulf of Mexico (GOM) OCS Region, you must submit Form BSEE-0133, Well Activity Report (WAR), to the District Manager on a weekly basis. The reporting week is defined as beginning on Sunday (12 a.m.) and ending on the following Saturday (11:59 p.m.). This reporting week corresponds to a week (Sunday through Saturday) on a standard calendar. Report any well operations that extend past the end of this weekly reporting period on the next weekly report. The reporting period for the weekly report is never longer than 7 days, but could be less than 7 days for the first reporting period and the last reporting period for a particular well operation. Submit each WAR and accompanying Form BSEE-0133S, Open Hole Data Report, to the BSEE GOM OCS Region no later than close of business on the Friday immediately after the closure of the reporting week. The District Manager may require more frequent submittal of the WAR on a case-by-case basis.
(b) For operations in the Pacific or Alaska OCS Regions, you must submit Form BSEE-0133, WAR, to the District Manager on a daily basis.
(c) The WAR must include a description of the operations conducted, any abnormal or significant events that affect the permitted operation each day within the report from the time you begin operations to the time you end operations, any verbal approval received, the well's as-built drawings, casing, fluid weights, shoe tests, test pressures at surface conditions, and any other information concerning well activities required by the District Manager. For casing cementing operations, indicate type of returns ( i.e. , full, partial, or none). If partial or no returns are observed, you must indicate how you determined the top of cement. For each report, indicate the operation status for the well at the end of the reporting period. On the final WAR, indicate the status of the well (completed, temporarily abandoned, permanently abandoned, or drilling suspended) and the date you finished such operations.
§ 250.744   What are the end of operation reporting requirements?
(a) Within 30 days after completing operations, except routine operations as defined in § 250.601, you must submit Form BSEE-0125, End of Operations Report (EOR), to the District Manager. The EOR must include: a listing, with top and bottom depths, of all hydrocarbon zones and other zones of porosity encountered with any cored intervals; details on any drill-stem and formation tests conducted; documentation of successful negative pressure testing on wells that use a subsea BOP stack or wells with mudline suspension systems; and an updated schematic of the full wellbore configuration. The schematic must be clearly labeled and show all applicable top and bottom depths, locations and sizes of all casings, cut casing or stubs, casing perforations, casing rupture discs (indicate if burst or collapse and rating), cemented intervals, cement plugs, mechanical plugs, perforated zones, completion equipment, production and isolation packers, alternate completions, tubing, landing nipples, subsurface safety devices, and any other information required by the District Manager regarding the end of well operations. The EOR must indicate the status of the well (completed, temporarily abandoned, permanently abandoned, or drilling suspended) and the date of the well status designation. The well status date is subject to the following:
(1) For surface well operations and riserless subsea operations, the operations end date is subject to the discretion of the District Manager; and
(2) For subsea well operations, the operations end date is considered to be the date the BOP is disconnected from the wellhead unless otherwise specified by the District Manager.
(b) You must submit public information copies of Form BSEE-0125 according to § 250.186(b).
§ 250.745   What other well records could I be required to submit?
The District Manager or Regional Supervisor may require you to submit copies of any or all of the following well records:
(a) Well records as specified in § 250.740;
(b) Paleontological interpretations or reports identifying microscopic fossils by depth and/or washed samples of drill cuttings that you normally maintain for paleontological determinations. The Regional Supervisor may issue a Notice to Lessees that sets forth the manner, timeframe, and format for submitting this information;
(c) Service company reports on cementing, perforating, acidizing, testing, or other similar services; or
(d) Other reports and records of operations.
§ 250.746   What are the recordkeeping requirements for casing, liner, and BOP tests, and inspections of BOP systems and marine risers?
You must record the time, date, and results of all casing and liner pressure tests. You must also record pressure tests, actuations, and inspections of the BOP system, system components, and marine riser in the daily report described in § 250.740. In addition, you must:
(a) Record test pressures on pressure charts or digital recorders;
(b) Require your onsite lessee representative, designated rig or contractor representative, and pump operator to sign and date the pressure charts or digital recordings and daily reports as correct;
(c) Document on the daily report the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. For subsea BOP systems, you must also record the closing times for annular and ram BOPs. You may reference a BOP test plan if it is available at the facility;
(d) Identify on the daily report the control station and pod used during the test (identifying the pod does not apply to coiled tubing and snubbing units);
(e) Identify on the daily report any problems or irregularities observed during BOP system testing and record actions taken to remedy the problems or irregularities. Any leaks associated with the BOP or control system during testing must be documented in the WAR. If any problems that cannot be resolved promptly are observed during testing, operations must be suspended until the District Manager determines that you may continue; and
(f) Retain all records, including pressure charts, daily reports, and referenced documents pertaining to tests, actuations, and inspections at the rig unit for the duration of the operation. After completion of the operation, you must retain all the records listed in this section for a period of 2 years at the rig unit. You must also retain the records at the lessee's field office nearest the facility or at another location available to BSEE. You must make all the records available to BSEE upon request.
§ 250.750   What are the coiled tubing requirements?
(a) For coiled tubing operations, you must follow the applicable requirements of this subpart and you must meet the following minimum requirements for the BOP system:
(1) BOP system components must be in the following order from the top down:
(2) You may use a set of hydraulically-operated combination rams for the blind rams and shear rams.
(3) You may use a set of hydraulically-operated combination rams for the hydraulic two-way slip rams and the hydraulically-operated pipe rams.
(4) You must attach a dual check valve assembly to the coiled tubing connector at the downhole end of the coiled tubing string for all coiled tubing operations. If you plan to conduct operations without downhole check valves, you must describe alternate procedures and equipment in Form BSEE-0124, Application for Permit to Modify and have it approved by the District Manager.
(5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves and at least one of the valves must be remotely controlled. You may use a manual valve instead of the remotely controlled valve on the kill line if you install a check valve between the two full-opening manual valves and the pump or manifold. The valves must have a working pressure rating equal to or greater than the working pressure rating of the connection to which they are attached, and you must install them between the well control stack and the choke or kill line. For operations with expected surface pressures greater than 3,500 psi, the kill line must be connected to a pump or manifold. You must not use the kill line inlet on the BOP stack for taking fluid returns from the wellbore.
(6) You must have a hydraulic-actuating system that provides sufficient accumulator capacity to close-open-close each component in the BOP stack. This cycle must be completed with at least 200 psi above the pre-charge pressure, without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to the uppermost required ram must be flanged, including the connections between the well control stack and the first full-opening valve on the choke line and the kill line.
(b) BSEE considers all coiled tubing operations to be non-routine.
§ 250.751   Coiled tubing testing requirements.
You must test the coiled tubing unit in accordance with § 250.737(a), (b), (c), (d)(9), and (d)(10). You must successfully pressure test the dual check valves to the rated working pressure of the connector, the rated working pressure of the dual check valve, expected surface pressure, or the collapse pressure of the coiled tubing, whichever is less. The test interval for coiled tubing operations must include a 10 minute high-pressure test for the coiled tubing string.
§ 250.760   What are the snubbing requirements?
(a) For snubbing operations, you must follow the applicable requirements of this subpart and have the following minimum BOP-system components:
(1) One set of pipe rams hydraulically operated,
(2) Two sets of stripper-type pipe rams hydraulically operated with spacer spool,
(3) An inside BOP or a spring-loaded, back-pressure safety valve in the open position located on the rig floor, and
(4) An essentially full-opening, work-string safety valve in the open position must be maintained on the rig floor at all times and a wrench to fit the work-string safety valve must be readily available.
(5) Proper connections must be readily available for inserting valves in the work string.
(b) Test the snubbing unit in accordance with § 250.737(a), (b), and (c).
§ 250.800   General.
(a) You must design, install, use, maintain, and test production safety equipment in a manner to ensure the safety and protection of the human, marine, and coastal environments. For production safety systems operated in subfreezing climates, you must use equipment and procedures that account for floating ice, icing, and other extreme environmental conditions that may occur in the area. Before you commence production on a new production facility:
(1) BSEE must approve your production safety system application, as required in § 250.842.
(2) You must request a preproduction inspection by notifying the District Manager at least 72 hours before you plan to commence initial production, as required under § 250.880(a)(1).
(b) For all new production systems on fixed leg platforms, you must comply with API RP 14J (incorporated by reference as specified in § 250.198);
(c) For all new floating production systems (FPSs) (e.g., column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); and spars), you must:
(1) Comply with API RP 14J;
(2) Meet the production riser standards of API RP 2RD (incorporated by reference as specified in § 250.198), provided that you may not install single bore production risers from floating production facilities;
(3) Design all stationkeeping ( i.e., anchoring and mooring) systems for floating production facilities to meet the standards of API RP 2SK and API RP 2SM (both incorporated by reference as specified in § 250.198); and
(4) Design stationkeeping ( i.e., anchoring and mooring) systems for floating facilities to meet the structural requirements of §§ 250.900 through 250.921.
(d) If there are any conflicts between the documents incorporated by reference and the requirements of this subpart, you must follow the requirements of this subpart.
(e) You may use alternate procedures or equipment during operations after receiving approval from the District Manager. You must present your proposed alternate procedures or equipment as required by § 250.141.
(f) You may apply for a departure from the operating requirements of this subpart as provided by § 250.142. Your written request must include a justification showing why the departure is necessary and appropriate.
§ 250.801   Safety and pollution prevention equipment (SPPE) certification.
(a) SPPE equipment. You must install only safety and pollution prevention equipment (SPPE) considered certified under paragraph (b) of this section or accepted under paragraph (c) of this section. BSEE considers the following equipment to be types of SPPE:
(1) Surface safety valves (SSV) and actuators, including those installed on injection wells capable of natural flow;
(2) Boarding shutdown valves (BSDV) and their actuators. For subsea wells, the BSDV is the surface equivalent of an SSV on a surface well;
(3) Underwater safety valves (USV) and actuators;
(4) Subsurface safety valves (SSSV) and associated safety valve locks and landing nipples; and
(5) Gas lift shutdown valves (GLSDV) and their actuators associated with subsea systems.
(b) Certification of SPPE. SPPE that is manufactured and marked pursuant to ANSI/API Spec. Q1 (incorporated by reference as specified in § 250.198), is considered as certified SPPE under this part. All other SPPE is considered as not certified, unless approved in accordance with paragraph (c) of this section.
(c) Accepting SPPE manufactured under other quality assurance programs. BSEE may exercise its discretion to accept SPPE manufactured under a quality assurance program other than ANSI/API Spec. Q1, provided that the alternative quality assurance program is verified as equivalent to API Spec. Q1 by an appropriately qualified entity and that the operator submits a request to BSEE containing relevant information about the alternative program and receives BSEE approval. In addition, an operator may request that BSEE accept SPPE that is marked with a third-party certification mark other than the API monogram. All requests under this paragraph should be submitted to the Chief, Office of Offshore Regulatory Programs; Bureau of Safety and Environmental Enforcement; VAE-ORP; 45600 Woodland Road, Sterling, VA 20166.
§ 250.802   Requirements for SPPE.
(a) All SSVs, BSDVs, USVs, and GLSDVs and their actuators must meet all of the specifications contained in ANSI/API Spec. 6A and API Spec. 6AV1 (both incorporated by reference in § 250.198).
(b) All SSSVs and their actuators must meet all of the specifications and recommended practices of ANSI/API Spec. 14A and ANSI/API RP 14B, including all annexes (both incorporated by reference as specified in § 250.198). Subsurface-controlled SSSVs are not allowed on subsea wells.
(c) Requirements derived from the documents incorporated in this section for SSVs, BSDVs, SSSVs, USVs, GLSDVs, and their actuators, include, but are not limited to, the following:
(1) You must ensure that each device is designed to function in the conditions to which it may be exposed; including temperature, pressure, flow rates, and environmental conditions.
(i) The device design must be tested by an independent test agency according to the test requirements in the appropriate standard for that device (API Spec. 6AV1 or ANSI/API Spec. 14A), as identified in paragraphs (a) and (b) of this section.
(ii) You must maintain a description of the process you used to ensure the device is designed to function as required in paragraphs (a) and (c)(1) of this section and provide that description to BSEE upon request.
(iii) If you remove any SPPE from service and install the device at a different location, you must have a qualified third party review and certify that each device will function as designed under the conditions to which it may be exposed.
(2) All materials and parts must meet the original equipment manufacturer specifications and acceptance criteria.
(3) The device must pass applicable validation tests and functional tests performed by an API-licensed test agency.
(4) You must have requalification testing performed following manufacture design changes.
(5) You must comply with and document all manufacturing, traceability, quality control, and inspection requirements.
(6) You must follow specified installation, testing, and repair protocols.
(7) You must use only qualified parts, procedures, and personnel to repair or redress equipment.
(d) You must install and use SPPE according to the following table.
(e) You must retain all documentation related to the manufacture, installation, testing, repair, redress, and performance of the SPPE until 1 year after the date of decommissioning of the equipment.
§ 250.803   What SPPE failure reporting procedures must I follow?
(a) You must follow the failure reporting requirements contained in section 10.20.7.4 of ANSI/API Spec. 6A for SSVs, BSDVs, GLSDVs and USVs. You must follow the failure reporting requirements contained in section 7.10 of ANSI/API Spec. 14A and Annex F of ANSI/API RP 14B for SSSVs (all incorporated by reference in § 250.198). Within 30 days after the discovery and identification of the failure, you must provide a written notice of equipment failure to the manufacturer of such equipment and to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. A failure is any condition that prevents the equipment from meeting the functional specification or purpose.
(b) You must ensure that an investigation and a failure analysis are performed within 120 days of the failure to determine the cause of the failure. If the investigation and analyses are performed by an entity other than the manufacturer, you must ensure that the analysis report is submitted to the manufacturer and to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. You must also ensure that the results of the investigation and any corrective action are documented in the analysis report.
(c) If the equipment manufacturer notifies you that it has changed the design of the equipment that failed or if you have changed operating or repair procedures as a result of a failure, then you must, within 30 days of such changes, report the design change or modified procedures in writing to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section.
(d) BSEE may designate a third party to receive the data required by paragraphs (a) through (c) of this section on behalf of BSEE. If BSEE designates a third party, you must submit the information required in this section to the designated third party, as directed by BSEE.
§ 250.804   [Reserved]
§ 250.805   Hydrogen sulfide.
(a) In zones known to contain hydrogen sulfide (H 2 S) or in zones where the presence of H 2 S is unknown, as defined in § 250.490, you must conduct production operations in accordance with that section and other relevant requirements of this subpart.
(b) You must receive approval through the DWOP process (§§ 250.286 through 250.295) for production operations in HPHT environments known to contain H 2 S or in HPHT environments where the presence of H 2 S is unknown.
§§ 250.806-250.809   [Reserved]
2
§ 250.810   Dry tree subsurface safety devices—general.
For wells using dry trees or for which you intend to install dry trees, you must equip all tubing installations open to hydrocarbon-bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless, after you submit a request containing a justification, the District Manager determines the well to be incapable of natural flow. You must install flow couplings above and below the subsurface safety devices. These subsurface safety devices include the following devices and any associated safety valve lock and landing nipple:
(a) An SSSV, including either:
(1) A surface-controlled SSSV; or
(2) A subsurface-controlled SSSV.
(b) An injection valve.
(c) A tubing plug.
(d) A tubing/annular subsurface safety device.
§ 250.811   Specifications for SSSVs—dry trees.
All surface-controlled and subsurface-controlled SSSVs, safety valve locks, and landing nipples installed in the OCS must conform to the requirements specified in §§ 250.801 through 250.803.
§ 250.812   Surface-controlled SSSVs—dry trees.
You must equip all tubing installations open to a hydrocarbon-bearing zone that is capable of natural flow with a surface-controlled SSSV, except as specified in §§ 250.813, 250.815, and 250.816.
(a) The surface controls must be located on the site or at a BSEE-approved remote location. You may request District Manager approval to situate the surface controls at a remote location.
(b) You must equip dry tree wells not previously equipped with a surface-controlled SSSV, and dry tree wells in which a surface-controlled SSSV has been replaced with a subsurface-controlled SSSV, with a surface-controlled SSSV when the tubing is first removed and reinstalled.
§ 250.813   Subsurface-controlled SSSVs.
You may submit an APM or a request to the District Manager for approval to equip a dry tree well with a subsurface-controlled SSSV in lieu of a surface-controlled SSSV, if the subsurface-controlled SSSV is installed in a well equipped with a surface-controlled SSSV that has become inoperable and cannot be repaired without removal and reinstallation of the tubing. If you remove and reinstall the tubing, you must equip the well with a surface-controlled SSSV.
§ 250.814   Design, installation, and operation of SSSVs—dry trees.
You must design, install, and operate (including repair, maintain, and test) an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the mudline within 2 days after production is established. When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis.
(b) The well must not be open to flow while the SSSV is inoperable, except when flowing the well is necessary for a particular operation such as cutting paraffin or performing other routine operations as defined in § 250.601.
(c) Until the SSSV is installed, the well must be attended in the immediate vicinity so that any necessary emergency actions can be taken while the well is open to flow. During testing and inspection procedures, the well must not be left unattended while open to production unless you have installed a properly operating SSSV in the well.
(d) You must design, install, maintain, inspect, repair, and test all SSSVs in accordance with ANSI/API RP 14B (incorporated by reference in § 250.198). For additional SSSV testing requirements, refer to § 250.880.
§ 250.815   Subsurface safety devices in shut-in wells—dry trees.
(a) You must equip all new dry tree completions (perforated but not placed on production) and completions that are shut-in for a period of 6 months with one of the following:
(1) A pump-through-type tubing plug;
(2) A surface-controlled SSSV, provided the surface control has been rendered inoperative; or
(3) An injection valve capable of preventing backflow.
(b) When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, and paraffin problems, the District Manager must approve the setting depth of the subsurface safety device for a shut-in well on a case-by-case basis.
§ 250.816   Subsurface safety devices in injection wells—dry trees.
You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.
§ 250.817   Temporary removal of subsurface safety devices for routine operations.
(a) You may remove a wireline- or pumpdown-retrievable subsurface safety device without further authorization or notice, for a routine operation that does not require BSEE approval of a Form BSEE-0124, Application for Permit to Modify (APM). For a list of these routine operations, see § 250.601. The removal period must not exceed 15 days.
(b) Prior to removal, you must identify the well by placing a sign on the wellhead stating that the subsurface safety device was removed. You must note the removal of the subsurface safety device in the records required by § 250.890. If the master valve is open, you must ensure that a trained person (see § 250.891) is in the immediate vicinity to attend the well and take any necessary emergency actions.
(c) You must monitor a platform well when a subsurface safety device has been removed, but a person does not need to remain in the well-bay area continuously if the master valve is closed. If the well is on a satellite structure, it must be attended by a support vessel, or a pump-through plug must be installed in the tubing at least 100 feet below the mudline and the master valve must be closed, unless otherwise approved by the appropriate District Manager.
(d) You must not allow the well to flow while the subsurface safety device is removed, except when it is necessary for the particular operation for which the SSSV is removed. The provisions of this paragraph are not applicable to the testing and inspection procedures specified in § 250.880.
§ 250.818   Additional safety equipment—dry trees.
(a) You must equip all tubing installations that have a wireline- or pumpdown-retrievable subsurface safety device with a landing nipple, with flow couplings or other protective equipment above and below it to provide for the setting of the device.
(b) The control system for all surface-controlled SSSVs must be an integral part of the platform emergency shutdown system (ESD).
(c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location. Surface-controlled SSSVs must close in response to shut-in signals from the ESD and in response to the fire loop or other fire detection devices.
§ 250.819   Specification for surface safety valves (SSVs).
All wellhead SSVs and their actuators must conform to the requirements specified in §§ 250.801 through 250.803.
§ 250.820   Use of SSVs.
You must install, maintain, inspect, repair, and test all SSVs in accordance with API STD 6AV2 (incorporated by reference in § 250.198). If any SSV does not operate properly, or if any gas and/or liquid fluid flow is observed during the leakage test as described in § 250.880, then you must shut-in all sources to the SSV and repair or replace the valve before resuming production.
§ 250.821   Emergency action and safety system shutdown—dry trees.
(a) If your facility is impacted or will potentially be impacted by an emergency situation (e.g., an impending National Weather Service-named tropical storm or hurricane, ice events, or post-earthquake), you must:
(1) Properly install a subsurface safety device on any well that is not yet equipped with a subsurface safety device and that is capable of natural flow, as soon as possible, with due consideration being given to personnel safety.
(2) You must shut-in (by closing the SSV and the surface-controlled SSSV) the following types of wells:
(i) All oil wells, and
(ii) All gas wells requiring compression.
(b) Closure of the SSV must not exceed 45 seconds after automatic detection of an abnormal condition or actuation of an ESD. The surface-controlled SSSV must close within 2 minutes after the shut-in signal has closed the SSV. The District Manager must approve any alternative design-delayed closure time of greater than 2 minutes based on the mechanical/production characteristics of the individual well.
§§ 250.822-250.824   [Reserved]
§ 250.825   Subsea tree subsurface safety devices—general.
(a) For wells using subsea (wet) trees or for which you intend to install subsea trees, you must equip all tubing installations open to hydrocarbon-bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency. You must also install flow couplings above and below the subsurface safety devices. For instances where the well at issue is incapable of natural flow, you may seek District Manager approval for using alternative procedures or equipment, if you propose to use a subsea safety system that is not capable of shutting off the flow from the well in the event of an emergency. Subsurface safety devices include the following and any associated safety valve lock and landing nipple:
(1) A surface-controlled SSSV;
(2) An injection valve;
(3) A tubing plug; and
(4) A tubing/annular subsurface safety device.
(b) After installing the subsea tree, but before the rig or installation vessel leaves the area, you must test all valves and sensors to ensure that they are operating as designed and meet all the conditions specified in this subpart.
§ 250.826   Specifications for SSSVs—subsea trees.
All SSSVs, safety valve locks, and landing nipples installed on the OCS must conform to the requirements specified in §§ 250.801 through 250.803 and any Deepwater Operations Plan (DWOP) required by §§ 250.286 through 250.295.
§ 250.827   Surface-controlled SSSVs—subsea trees.
You must equip all tubing installations open to a hydrocarbon-bearing zone that is capable of natural flow with a surface-controlled SSSV, except as specified in §§ 250.829 and 250.830. The surface controls must be located on the host facility.
§ 250.828   Design, installation, and operation of SSSVs—subsea trees.
You must design, install, and operate (including repair, maintain, and test) an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the mudline. When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth on a case-by-case basis.
(b) The well must not be open to flow while an SSSV is inoperable, unless specifically approved by the District Manager in an APM.
(c) You must design, install, maintain, inspect, repair, and test all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and ANSI/API RP 14B (incorporated by reference in § 250.198). For additional SSSV testing requirements, refer to § 250.880.
§ 250.829   Subsurface safety devices in shut-in wells—subsea trees.
(a) You must equip all new subsea tree completions (perforated but not placed on production) and completions shut-in for a period of 6 months with one of the following:
(1) A pump-through-type tubing plug;
(2) An injection valve capable of preventing backflow; or
(3) A surface-controlled SSSV, provided the surface control has been rendered inoperative. For purposes of this section, a surface-controlled SSSV is considered inoperative if, for a direct hydraulic control system, you have bled the hydraulics from the control line and have isolated it from the hydraulic control pressure. If your controls employ an electro-hydraulic control umbilical and the hydraulic control pressure to the individual well cannot be isolated, a surface-controlled SSSV is considered inoperative if you perform the following:
(i) Disable the control function of the surface-controlled SSSV within the logic of the programmable logic controller which controls the subsea well;
(ii) Place a pressure alarm high on the control line to the surface-controlled SSSV of the subsea well; and
(iii) Close the USV and at least one other tree valve on the subsea well.
(b) When warranted by conditions, such as unstable bottom conditions, permafrost, hydrate formation, and paraffin problems, the District Manager must approve the setting depth of the subsurface safety device for a shut-in well on a case-by-case basis.
§ 250.830   Subsurface safety devices in injection wells—subsea trees.
You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.
§ 250.831   Alteration or disconnection of subsea pipeline or umbilical.
If a necessary alteration or disconnection of the pipeline or umbilical of any subsea well would affect your ability to monitor casing pressure or to test any subsea valves or equipment, you must contact the appropriate District Office at least 48 hours in advance and submit a repair or replacement plan to conduct the required monitoring and testing. You must not alter or disconnect until the repair or replacement plan is approved.
§ 250.832   Additional safety equipment—subsea trees.
(a) You must equip all tubing installations that have a wireline- or pump down-retrievable subsurface safety device installed after May 31, 1988, with a landing nipple, with flow couplings, or other protective equipment above and below it to provide for the setting of the device.
(b) The control system for all surface-controlled SSSVs must be an integral part of the platform ESD.
(c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location.
§ 250.833   Specification for underwater safety valves (USVs).
All USVs, including those designated as primary or secondary, and any alternate isolation valve (AIV) that acts as a USV, if applicable, and their actuators, must conform to the requirements specified in §§ 250.801 through 250.803. A production master or wing valve may qualify as a USV under ANSI/API Spec. 6A and API Spec. 6AV1 (both incorporated by reference in § 250.198).
(a) Primary USV (USV1). You must install and designate one USV on a subsea tree as the USV1. The USV1 must be located upstream of the choke valve. As provided in paragraph (b) of this section, you must inform BSEE if the primary USV designation changes.
(b) Secondary USV (USV2). You may equip your tree with two or more valves qualified to be designated as a USV, one of which may be designated as the USV2. If the USV1 fails to operate properly or exhibits a leakage rate greater than allowed in § 250.880, you must notify the appropriate District Office and designate the USV2 or another qualified valve (e.g., an AIV) that meets all the requirements of this subpart for USVs as the USV1. The USV2 must be located upstream of the choke.
§ 250.834   Use of USVs.
You must install, maintain, inspect, repair, and test any valve designated as the primary USV in accordance with this subpart, your DWOP (as specified in §§ 250.286 through 250.295), and API STD 6AV2 (incorporated by reference in § 250.198). For additional USV testing requirements, refer to § 250.880.
§ 250.835   Specification for all boarding shutdown valves (BSDVs) associated with subsea systems.
You must install a BSDV on the pipeline boarding riser. All new BSDVs and any BSDVs removed from service for remanufacturing or repair and their actuators installed on the OCS must meet the requirements specified in §§ 250.801 through 250.803. In addition, you must:
(a) Ensure that the internal design pressure(s) of the pipeline(s), riser(s), and BSDV(s) is fully rated for the maximum pressure of any input source and complies with the design requirements set forth in subpart J, unless BSEE approves an alternate design.
(b) Use a BSDV that is fire rated for 30 minutes, and is pressure rated for the maximum allowable operating pressure (MAOP) approved in your pipeline application.
(c) Locate the BSDV within 10 feet of the first point of access to the boarding pipeline riser ( i.e., within 10 feet of the edge of platform if the BSDV is horizontal, or within 10 feet above the first accessible working deck, excluding the boat landing and above the splash zone, if the BSDV is vertical).
(d) Install a temperature safety element (TSE) and locate it within 5 feet of each BSDV.
§ 250.836   Use of BSDVs.
You must install, inspect, maintain, repair, and test all new BSDVs, as well as all BSDVs that you remove from service for remanufacturing or repair, in accordance with API STD 6AV2 (incorporated by reference in § 250.198) for SSVs. If any BSDV does not operate properly or if any gas fluid and/or liquid fluid flow is observed during the leakage test, as described in § 250.880, you must shut-in all sources to the BSDV and immediately repair or replace the valve.
§ 250.837   Emergency action and safety system shutdown—subsea trees.
(a) If your facility is impacted or will potentially be impacted by an emergency situation (e.g., an impending National Weather Service-named tropical storm or hurricane, ice events, or post-earthquake), you must shut-in all subsea wells unless otherwise approved by the District Manager. A shut-in is defined as a closed BSDV, USV, GLSDV, and surface-controlled SSSV.
(b) When operating a mobile offshore drilling unit (MODU) or other type of workover or intervention vessel in an area with subsea infrastructure, you must:
(1) Suspend production from all wells that could be affected by a dropped object, including upstream wells that flow through the same pipeline; or
(2) Establish direct, real-time communications between the MODU or other type of workover or intervention vessel and the production facility control room and develop a dropped objects plan, as required in § 250.714. If an object is dropped, you must immediately secure the well directly under the MODU or other type of workover or intervention vessel while simultaneously communicating with the platform to shut-in all affected wells. You must also maintain without disruption, and continuously verify, communication between the production facility and the MODU or other type of workover or intervention vessel. If communication is lost between the MODU or other type of workover or intervention vessel and the platform for 20 or more minutes, you must shut-in all wells that could be affected by a dropped object.
(c) In the event of an emergency, you must operate your production system according to the valve closure times in the applicable tables in §§ 250.838 and 250.839 for the following conditions:
(1) Process upset. In the event an upset in the production process train occurs downstream of the BSDV, you must close the BSDV in accordance with the applicable tables in §§ 250.838 and 250.839. You may reopen the BSDV to blow down the pipeline to prevent hydrates, provided you have secured the well(s) and ensured adequate protection.
(2) Pipeline pressure safety high and low (PSHL) sensor. In the event that either a high or a low pressure condition is detected by a PSHL sensor located upstream of the BSDV, you must secure the affected well and pipeline, and all wells and pipelines associated with a dual or multi pipeline system, by closing the BSDVs, USVs, and surface-controlled SSSVs in accordance with the applicable tables in §§ 250.838 and 250.839. You must obtain approval from the appropriate District Manager to resume production in the unaffected pipeline(s) of a dual or multi pipeline system. If the PSHL sensor activation was a false alarm, you may return the wells to production without contacting the appropriate District Manager.
(3) ESD/TSE (platform). In the event of an ESD activation that is initiated because of a platform ESD or platform TSE not associated with the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in accordance with the applicable tables in §§ 250.838 and 250.839.
(4) Subsea ESD (platform) or BSDV TSE. In the event of an emergency shutdown activation that is initiated by the host platform due to an abnormal condition subsea, or a TSE associated with the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in accordance with the applicable tables in §§ 250.838 and 250.839.
(5) Subsea ESD (MODU). In the event of an ESD activation that is initiated by a dropped object from a MODU or other type of workover or intervention vessel, you must secure all wells in the proximity of the MODU or other type of workover or intervention vessel by closing the USVs and surface-controlled SSSVs in accordance with the applicable tables in §§ 250.838 and 250.839. You must notify the appropriate District Manager before resuming production.
(d) Following an ESD or fire, you must bleed your low pressure (LP) and high pressure (HP) hydraulic systems in accordance with the applicable tables in §§ 250.838 and 250.839 to ensure that the valves are locked out of service and cannot be reopened inadvertently.
§ 250.838   What are the maximum allowable valve closure times and hydraulic bleeding requirements for an electro-hydraulic control system?
(a) If you have an electro-hydraulic control system, you must:
(1) Design the subsea control system to meet the valve closure times listed in paragraphs (b) and (d) of this section or your approved DWOP; and
(2) Verify the valve closure times upon installation. The District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV.
(b) You must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP as long as communication is maintained with the platform or with the MODU or other type of workover vessel:
Valve Closure Timing, Electro-Hydraulic Control System
(c) If you have an electro-hydraulic control system and experience a loss of communications (EH Loss of Comms), you must comply with the following:
(1) If you can meet the EH Loss of Comms valve closure timing conditions specified in the table in paragraph (d) of this section, you must notify the appropriate District Office within 12 hours of detecting the loss of communication.
(2) If you cannot meet the EH Loss of Comms valve closure timing conditions specified in the table in paragraph (d) of this section, you must notify the appropriate District Office immediately after detecting the loss of communication. You must shut-in production by initiating a bleed of the low pressure (LP) hydraulic system or the high pressure (HP) hydraulic system within 120 minutes after loss of communication. You must bleed the other hydraulic system within 180 minutes after loss of communication.
(3) You must obtain approval from the appropriate District Manager before continuing to produce after loss of communication when you cannot meet the EH Loss of Comms valve closure times specified in the table in paragraph (d) of this section. In your request, include an alternate valve closure timing table that your system is able to achieve. The appropriate District Manager may also approve an alternate hydraulic bleed schedule to allow for hydrate mitigation and orderly shut-in.
(d) If you experience a loss of communications, you must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP:
Valve Closure Timing, Electro-Hydraulic Control System With Loss of Communication
§ 250.839   What are the maximum allowable valve closure times and hydraulic bleeding requirements for a direct-hydraulic control system?
(a) If you have a direct-hydraulic control system, you must:
(1) Design the subsea control system to meet the valve closure times listed in this section or your approved DWOP; and
(2) Verify the valve closure times upon installation. The District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV.
(b) You must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP:
Valve Closure Timing, Direct-Hydraulic Control System
§ 250.840   Design, installation, and maintenance—general.
You must design, install, and maintain all production facilities and equipment including, but not limited to, separators, treaters, pumps, heat exchangers, fired components, wellhead injection lines, compressors, headers, and flowlines in a manner that is efficient, safe, and protects the environment.
§ 250.841   Platforms.
(a) You must protect all platform production facilities with a basic and ancillary surface safety system designed, analyzed, installed, tested, and maintained in operating condition in accordance with the provisions of API RP 14C (incorporated by reference as specified in § 250.198). If you use processing components other than those for which Safety Analysis Checklists are included in API RP 14C, you must utilize the analysis technique and documentation specified in API RP 14C to determine the effects and requirements of these components on the safety system. Safety device requirements for pipelines are contained in § 250.1004.
(b) You must design, install, inspect, repair, test, and maintain in operating condition all platform production process piping in accordance with API RP 14E and API 570 (both incorporated by reference as specified in § 250.198). The District Manager may approve temporary repairs to facility piping on a case-by-case basis for a period not to exceed 30 days.
(c) If you plan to make a modification to any production safety system that also involves a major modification to the platform structure, you must follow the requirements in § 250.900(b)(2). A major modification to a platform structure is defined in § 250.900(b)(2).
§ 250.842   Approval of safety systems design and installation features.
(a) Before you install or modify a production safety system, you must submit a production safety system application to the District Manager. The District Manager must approve your production safety system application before you commence production through or otherwise use the new or modified system. The application must include the design documentation prescribed as follows:
(b) You must develop and maintain the following design documents and make them available to BSEE upon request:
(c) In the production safety system application, you must also certify the following:
(1) That all electrical systems were designed according to API RP 14F or API RP 14FZ, as applicable (incorporated by reference in § 250.198);
(2) That the design documents for the mechanical and electrical systems that you are required to submit under paragraph (a) of this section are sealed by a licensed professional engineer. For modified systems, only the modifications are required to be sealed by a licensed professional engineer(s). The professional engineer must be licensed in a State or Territory of the United States and have sufficient expertise and experience to perform the duties; and
(3) That a hazards analysis was performed in accordance with § 250.1911 and API RP 14J (incorporated by reference in § 250.198), and that you have a hazards analysis program in place to assess potential hazards during the operation of the facility.
(d) Within 90 days after placing new or modified production safety systems in service, you must submit to the District Manager the as-built diagrams for the new or modified production safety systems outlined in paragraphs (a)(1), (2), and (3) of this section. You must certify in an accompanying letter that the as-built design documents have been reviewed for compliance with applicable regulations and accurately represent the new or modified system as installed. The drawings must be clearly marked “as-built.”
(e) You must maintain approved and supporting design documents required under paragraphs (a) and (b) of this section at your offshore field office nearest the OCS facility or at other locations conveniently available to the District Manager. These documents must be made available to BSEE upon request and must be retained for the life of the facility. All approved designs are subject to field verifications.
§§ 250.843-250.849   [Reserved]
§ 250.850   Production system requirements—general.
You must comply with the production safety system requirements in §§ 250.851 through 250.872, in addition to the practices contained in API RP 14C (incorporated by reference as specified in § 250.198).
§ 250.851   Pressure vessels (including heat exchangers) and fired vessels.
(a) Pressure vessels (including heat exchangers) and fired vessels supporting production operations must meet the requirements in the following table:
(b) Operating pressure ranges. You must use pressure recording devices to establish the new operating pressure ranges of pressure vessels at any time that the normalized system pressure changes by 50 psig or 5 percent. Once system pressure has stabilized, pressure recording devices must be utilized to establish the new operating pressure ranges. The pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long. You must maintain the pressure recording information you used to determine current operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager for as long as the information is valid.
(c) Pressure shut-in sensors must be set according to the following table (initial set points for pressure sensors must be set utilizing gauge readings and engineering design):
§ 250.852   Flowlines/Headers.
(a) You must:
(1) Equip flowlines from wells with both PSH and PSL sensors. You must locate these sensors in accordance with section A.1 of API RP 14C (incorporated by reference as specified in § 250.198).
(2) Use pressure recording devices to establish the new operating pressure ranges of flowlines at any time when the normalized system pressure changes by 50 psig or 5 percent, whichever is higher. The pressure recording devices must document the pressure range over time intervals that are no less than 4 hours and no more than 30 days long.
(3) Maintain the most recent pressure recording information you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager for as long as the information is valid.
(b) Flowline shut-in sensors must meet the requirements in the following table (initial set points for pressure sensors must be set using gauge readings and engineering design):
(c) If a well flows directly to a pipeline before separation, the flowline and valves from the well located upstream of and including the header inlet valve(s) must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the flowline is protected by one of the following:
(1) A relief valve which vents into the platform flare scrubber or some other location approved by the District Manager. You must design the platform flare scrubber to handle, without liquid-hydrocarbon carryover to the flare, the maximum-anticipated flow of hydrocarbons that may be relieved to the vessel; or
(2) Two SSVs with independent PSH sensors connected to separate relays and sensing points and installed with adequate volume upstream of any block valve to allow sufficient time for the SSVs to close before exceeding the maximum allowable working pressure. Each independent PSH sensor must close both SSVs along with any associated flowline PSL sensor. If the maximum shut-in pressure of a dry tree satellite well(s) is greater than 1 1/2 times the maximum allowable pressure of the pipeline, a pressure safety valve (PSV) of sufficient size and relief capacity to protect against any SSV leakage or fluid hammer effect may be required by the District Manager. The PSV must be installed upstream of the host platform boarding valve and vent into the platform flare scrubber or some other location approved by the District Manager.
(d) If a well flows directly to the pipeline from a header without prior separation, the header, the header inlet valves, and pipeline isolation valve must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the header is protected by the safety devices as outlined in paragraph (c) of this section.
(e) If you are installing flowlines constructed of unbonded flexible pipe on a floating platform, you must:
(1) Review the manufacturer's Design Methodology Verification Report and the independent verification agent's (IVA) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements of ANSI/API Spec. 17J (incorporated by reference in § 250.198);
(2) Determine that the unbonded flexible pipe is suitable for its intended purpose;
(3) Submit to the District Manager the manufacturer's design specifications for the unbonded flexible pipe; and
(4) Submit to the District Manager a statement certifying that the pipe is suitable for its intended use and that the manufacturer has complied with the IVA requirements of ANSI/API Spec. 17J (incorporated by reference in § 250.198).
(f) Automatic pressure or flow regulating choking devices must not prevent the normal functionality of the process safety system that includes, but is not limited to, the flowline pressure safety devices and the SSV.
(g) You may install a single flow safety valve (FSV) on the platform to protect multiple subsea pipelines or wells that tie into a single pipeline riser provided that you install an FSV for each riser on the platform and test it in accordance with the criteria prescribed in § 250.880(c)(2)(v).
(h) You may install a single PSHL sensor on the platform to protect multiple subsea pipelines that tie into a single pipeline riser provided that you install a PSHL sensor for each riser on the platform and locate it upstream of the BSDV.
§ 250.853   Safety sensors.
You must ensure that:
(a) All shutdown devices, valves, and pressure sensors function in a manual reset mode;
(b) Sensors with integral automatic reset are equipped with an appropriate device to override the automatic reset mode;
(c) All pressure sensors are equipped to permit testing with an external pressure source; and
(d) All level sensors are equipped to permit testing through an external bridle on all new vessel installations where possible, depending on the type of vessel for which the level sensor is used.
§ 250.854   Floating production units equipped with turrets and turret-mounted systems.
(a) For floating production units equipped with an auto slew system, you must integrate the auto slew control system with your process safety system allowing for automatic shut-in of the production process, including the sources (subsea wells, subsea pumps, etc. ) and releasing of the buoy. Your safety system must immediately initiate a process system shut-in according to §§ 250.838 and 250.839 and release the buoy to prevent hydrocarbon discharge and damage to the subsea infrastructure when the following are encountered:
(1) Your buoy is clamped,
(2) Your auto slew mode is activated, and
(3) You encounter a ship heading/position failure or an exceedance of the rotational tolerances of the clamped buoy.
(b) For floating production units equipped with swivel stack arrangements, you must equip the portion of the swivel stack containing hydrocarbons with a leak detection system. Your leak detection system must be tied into your production process surface safety system allowing for automatic shut-in of the system. Upon seal system failure and detection of a hydrocarbon leak, your surface safety system must immediately initiate a process system shut-in according to §§ 250.838 and 250.839.
§ 250.855   Emergency shutdown (ESD) system.
The ESD system must conform to the requirements of Appendix C, section C1, of API RP 14C (incorporated by reference as specified in § 250.198), and the following:
(a) The manually operated ESD valve(s) must be quick-opening and non-restricted to enable the rapid actuation of the shutdown system. Electronic ESD stations must be wired as de-energize to trip circuits or as supervised circuits. Because of the key role of the ESD system in the platform safety system, all ESD components must be of high quality and corrosion resistant and stations must be uniquely identified. Only ESD stations at the boat landing may utilize a loop of breakable synthetic tubing in lieu of a valve or electric switch. This breakable loop is not required to be physically located on the boat landing, but must be accessible from a vessel adjacent to or attached to the facility.
(b) You must maintain a schematic of the ESD that indicates the control functions of all safety devices for the platforms on the platform, at your field office nearest the OCS facility, or at another location conveniently available to the District Manager, for the life of the facility.
§ 250.856   Engines.
(a) Engine exhaust. You must equip all engine exhausts to comply with the insulation and personnel protection requirements of API RP 14C, section 4.2 (incorporated by reference as specified in § 250.198). You must equip exhaust piping from diesel engines with spark arresters.
(b) Diesel engine air intake. You must equip diesel engine air intakes with a device to shut down the diesel engine in the event of runaway ( i.e., overspeed). You must equip diesel engines that are continuously attended with either remotely operated manual or automatic shutdown devices. You must equip diesel engines that are not continuously attended with automatic shutdown devices. The following diesel engines do not require a shutdown device: Engines for fire water pumps; engines on emergency generators; engines that power BOP accumulator systems; engines that power air supply for confined entry personnel; temporary equipment on non-producing platforms; booster engines whose purpose is to start larger engines; and engines that power portable single cylinder rig washers.
§ 250.857   Glycol dehydration units.
(a) You must install a pressure relief system or an adequate vent on the glycol regenerator (reboiler) to prevent over pressurization. The discharge of the relief valve must be vented in a nonhazardous manner.
(b) You must install the FSV on the dry glycol inlet to the glycol contact tower as near as practical to the glycol contact tower.
(c) You must install the shutdown valve (SDV) on the wet glycol outlet from the glycol contact tower as near as practical to the glycol contact tower.