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Section 1 General Provisions 1.1 Well blowouts are the most serious accidents that threaten the safety of offshore oil operations and cause the greatest losses. To prevent and control well blowouts in offshore oil operations. These well control requirements are formulated in accordance with the \"Regulations on Safety Management of Offshore Oil Operations by the Ministry of Petroleum Industry of the People’s Republic of China\". 1.2 Wellbore blowouts are roughly divided into drilling-related blowouts and non-drilling-related blowouts. According to statistical analyses of foreign data, drilling-related blowouts account for 64%, while non-drilling-related blowouts account for 36%; therefore, in addition to paying close attention to drilling-related blowouts, it is also essential to focus on preventing non-drilling-related blowouts. 1.3 **Supervise and inspect the well control activities of the operators and contracting companies;** if necessary, inspectors may also examine the company’s management and implementation of well control measures. 1.4 Emergency plans are an important part of well control operations. The well control measures established by operators and contractors should be specific and detailed in order to enhance the ability to control blowouts and prevent situations from worsening. 1.5 These well control requirements shall come into effect as of April 1, 1989. Section 2 Drilling Operations 2.1 General Requirements Before the drilling equipment is deployed, reliable geological data on the seabed must be available; particular attention should be paid to the presence of shallow gas in the operation area. If such gas is present, effective measures must be taken. The installation, maintenance, and testing of blowout preventers and related equipment must meet the requirements of well control. 2.1.1 Blowout prevention equipment: The blowout preventer assembly shall consist of one to two ring-type blowout preventers and a specified number of ram-type blowout preventers. The closing size of the rams in the ram-type blowout preventers must match the size of the drill pipes or tubes being used. The rated operating pressure of the blowout preventers must be higher than the expected wellhead pressure during drilling. The rated working pressure of the blowout preventer must be no less than 703 kilograms per square centimeter (10,000 pounds per square inch). The BOP stack control system should be equipped with: 2.1.1.1 A hydraulic control system, whose accumulator fluid pressure should be maintained at 197 kilograms per square centimeter (2800 pounds per square inch); the volume of fluid in the accumulator should be sufficient to provide 1.5 times the amount of fluid required to close all the BOP components. Moreover, the minimum pressure when the accumulator provides 1.5 times its volume is 98 kilograms per square centimeter (1400 pounds per square inch). The accumulator unit must be equipped with two sets of hydraulic power sources; either set can independently restore the hydraulic pressure in the accumulator unit to close all blowout preventers and maintain sufficient energy to keep them in that closed state. The gate-type blowout preventer should have a locking device. 2.1.1.2 In addition to a main control panel installed on the drill floor, another auxiliary control panel is placed in a location away from the drill floor for easier operation. 2.1.1.3 If there is no side flange on the BOP body, a drilling tee must be installed to connect the kill line and the throttle line. 2.1.1.4 Two hydraulic control valves shall be installed on the well killing pipeline and the throttle pipeline respectively; the main control valves located near both sides of the blowout preventer body are always in the open position, while the other valve shall be a control valve. On semi-submersible or fixed platforms, the main control valve of the blowout preventer can be a manual valve. 2.1.1.5 Each BOP stack shall be equipped with a throttle manifold and a well control manifold that correspond to the rated operating pressure of that BOP stack. 2.1.1.6 The operating pressure of all types of bypass valves, fittings, and pressure pipelines (or flexible pipelines) in the BOP stack shall be equal to the rated operating pressure of the BOP stack. 2.1.1.7 Try to install an automatic grouting system, with the grouting pipeline connected to the wellhead. 2.1.2 Auxiliary equipment: The following various auxiliary devices shall be provided and kept in good working condition throughout the entire operation period. 2.1.2.1 A upper plug should be installed on the kelly below the faucet, and a lower plug should be installed on the kelly below that. The wrenches suitable for operating the valve cocks should be placed in a fixed location on the drill floor, so that drilling crew members can access them easily at any time. 2.1.2.2 During drilling operations, an \"internal blowout preventer\" suitable for the drill pipes should be available on the drill floor; it is important to maintain it regularly and ensure it remains in good working condition. 2.1.2.3 When running casing, the size of the BOP ram should match that of the casing being run, and a circulation joint matching the threads of the casing to be run should be prepared. 2.1.2.4 The rubber seals used in the blowout preventer shall be maintained and stored in accordance with the manufacturer’s technical specifications. Each type of seal should be marked with its expiration date and operating conditions. Seals that are expired or do not meet the technical specifications must not be installed in blowout preventers. 2.2 Requirements for subsea BOP stacks: 2.2.1 Pipelines: A shunt system 2.2.2 Surface casing and intermediate casing: One to two annular BOPs ； Two double-plate BOPs ； One of the gate pairs is a full-seal shear gate blowout preventer ； (If a composite drill string is used, one of the two blowout preventers should be equipped with a gate to seal larger drill pipes, while the other blowout preventer should have a gate to seal smaller drill pipes.) An underwater blowout preventer assembly is fitted with an underwater accumulator to facilitate the rapid supply of hydraulic energy nearby, enabling the quick opening and closing of the various blowout preventers and their gates. To ensure reliability, underwater BOPs should employ a dual control box system that serves as a backup for one another; while one control box system is in use, the other must remain in good working condition as a backup. If the BOP assembly needs to be repaired or replaced, it is necessary to ensure the safety of the wellbore; this should be done as soon as possible after casing has been run and cemented, before the cement plug is penetrated. If necessary, a cement plug can be inserted or a bridge plug can be placed before carrying out the repair or replacement. 2.3 Requirements for surface BOP stacks: Minimum requirements for general surface BOP stacks (suitable for jackup drilling platforms and fixed platforms): 2.3.1 Flow control devices: A diversion system (to be installed in cases of shallow gas or unclear geological conditions). 2.3.2 Surface casing: One annular BOP. 2.3.3 Intermediate casing: One annular BOP ； Two-plate BOP ； A fully enclosed (or shearfully enclosed) blowout preventer ； (If a combined drill string is used, two gate-type blowout preventers to seal larger drill pipes and one gate-type blowout preventer to seal smaller drill pipes must be installed.) 2.4 Pressure testing, movement, inspection, maintenance, and operational drills of the BOP system: All BOP units must undergo a low-pressure test at 14-35 kg/cm² (200-500 psi) before being subjected to a high-pressure test. When drilling in high-pressure and complex areas, the blowout preventer assembly should undergo a full-pressure (rated operating pressure) test as a whole before installation or after replacing major components. All pressure testing data for blowout preventers must be recorded in the drilling log. The original records or copies of the pressure testing should be kept on the drilling rig. 2.4.1 Sequence of pressure testing for blowout preventers: 2.4.1.1 Before and after installation ； 2.4.1.2 After each cementing, before drilling the cement plug ； 2.4.1.3 Pressure testing shall be carried out at least once per week, with an interval of no more than seven days between tests. The control panel can be replaced and put into use within seven days; if well operations prevent the pressure testing of the blowout preventer, the interval between pressure tests can exceed seven days. However, pressure testing must be carried out immediately once the well resumes normal operation, and the reason for the delay should be recorded in the drilling log. In drilling operations, the factors that generally hinder the pressure testing of blowout preventers are stick sticking and pressure control tasks. Pressure testing should be carried out at staggered intervals to give every drilling crew member the opportunity to operate the blowout prevention equipment. When drilling low-pressure production wells, the drilling supervisor may appropriately extend the pressure testing period depending on the specific circumstances. 2.4.1.4 If part of the entire system needs to be disassembled for repair, pressure testing must be carried out after the repair. 2.4.1.5 When testing the BOP stack installed on the casing head, a pressure testing plug or sealing assembly must be inserted, and the test pressure shall not exceed 70% of the casing’s internal pressure resistance strength. 2.4.2 Pressure testing of surface BOPs: The ram BOPs and the corresponding control equipment, including the choke manifold, shall be pressure-tested in sections at 70% of the rated operating pressure of the BOP assembly, or at 70% of the internal pressure resistance strength of the casing, whichever is lower. The pressure testing of the annular BOP shall be conducted at no more than 50% of its rated operating pressure, or at 70% of the minimum internal pressure resistance strength of the casing – whichever is lower. 2.4.3 Pressure testing of subsea BOP assemblies: Subsea BOPs and all related well control equipment are pressure-tested with water on a test bench up to their rated operating pressure, whereas the annular BOP is pressure-tested to no more than 50% of its rated operating pressure. After the BOP stack is installed on the seabed, the control equipment and the BOP ram that correspond to the drill string must be tested in accordance with the regulations for testing BOP stacks on the surface. 2.4.4 Operations of the surface BOP: The following are the minimum number of operations required: 2.4.4.1 The ram BOP shall be operated once per day. To prevent damage to the gate seal, it is not necessary to apply the full control pressure to the drill pipe; it is sufficient to ensure that normal operation is indicated. 2.4.4.2 The operation of the fully enclosed ram BOP is carried out after each drill lift; if there are multiple drill lifts per day, it is sufficient to perform this operation once a day. 2.4.4.3 It can be performed once in conjunction with the weekly pressure test. 2.4.4.4 Regarding the control panel, after the drill string is pulled out of the wellbore, it is switched once for each lift and lower movement of the drill string. If one of the two control panels loses its operational capability, drilling operations can only resume once that capability is restored. 2.4.4.5 The valves of the throttle manifold, kelly plug, and drill pipe \"inner BOP\" shall be operated once a week. 2.4.5 Operations of subsea BOPs: Except for the gate BOP which operates once a day, the number of operations of subsea BOPs is the same as that of surface BOPs. To prevent damage to the gate seal, it is not necessary to apply the full control pressure to seal the drill pipe. Use only a low pressure to seal the drill pipe. It just needs to be ensured that the gate plate can move properly. For the gate-type blowout preventer, the two control panels alternate in operation once for each drill cycle; even if there are multiple drill cycles per day, it operates only once. During the weekly pressure test, the shear ram BOPs cannot operate simultaneously. The entire hydraulic system should be operated alternately by two control panels. 2.4.6 Inspection and Maintenance: The entire BOP system, the water isolation (guide) pipes, and the associated equipment shall be inspected and maintained in accordance with the procedures recommended by the manufacturer. The BOP system and isolation (guide) pipes shall be visually inspected at least once a day whenever sea conditions and weather permit; the inspection of underwater equipment can be carried out using tools such as underwater television. 2.4.7 BOP Operation Drills*: All drilling personnel must receive training in BOP operation drills, and they should be familiar with the BOP equipment before starting drilling operations. The operation is performed every seven days. All operations related to the spray preventer must be recorded in the drilling log. 2.5 Slurry: 2.5.1 Slurry monitoring and testing equipment: 2.5.1.1 Slurry tank level gauge, which shall include both acoustic and optical alarm devices. 2.5.1.2 The gas detection device is installed in the mud logging room, while its alarm devices are located on the drill floor and in the mud logging room respectively. 2.5.1.3 Slurry return indicator and slurry volume measuring device. 2.5.1.4 Slurry property testing instruments. 2.5.2 Mud volume 2.5.2.1 Before starting drilling, a table showing the relationship between well depth and the minimum required amount of mud materials should be calculated and posted in the drilling supervision room. The table includes weighting materials, which should be stored as much as possible on the drilling equipment to ensure proper well control. When the demand for mud exceeds the storage capacity of the drilling equipment, a backup plan must be put in place to supply additional mud in emergency situations to meet the needs. 2.5.2.2 The daily storage amount of mud materials (including weighting materials) shall be recorded and kept on the drilling rig; if the storage amount falls below the minimum level specified in the plan, drilling operations must be halted. 2.5.2.3 Before starting to lift the drill string, there should be no signs of formation fluids entering the well. The specific gravity of imported and exported mud is essentially the same. When the specific gravity of the returned mud is 0.024 g/cm3 or more lower than that of the incoming mud, the mud in the annular space should be circulated to the surface, and the mud properties should be checked for gas or liquid intrusion and treated accordingly. 2.5.2.4 When lifting the drill string, mud should be pumped into the well. Mud should be added either before the static liquid level in the well drops and the hydrostatic pressure falls by 75 pounds per square inch (5.1 kilograms per square centimeter), or after every 5 drill string sections are lifted; the procedure that results in a smaller decrease in static pressure shall be followed. Before retrieving the drill pipe testing tool from the well, the mud in the well should be circulated or back-circulated. 2.5.2.5 When pumping mud during tripping, it should be measured at least using a measuring tank, and the actual amount pumped in must be recorded. 2.6 Management personnel: 2.6.1 Management and supervision – Representatives of the operators and contractors shall manage and supervise drilling operations around the clock. 2.6.2 Qualifications for well control personnel: The following personnel must possess a well control training certificate issued by the CNOOC Training Center or the Western South China Sea Petroleum Company Training Center, as well as relevant foreign training institutions. 2.6.2.1 Drilling ship (platform) manager ； 2.6.2.2 Drilling Supervisor ； 2.6.2.3 Drilling Engineer and Subsea Equipment Technician ； 2.6.2.4 Drilling Team Leader ； 2.6.2.5 Driller ； 2.6.2.6 Assistant Driller ； 2.6.2.7 Derrick worker. Certified personnel must undergo recertification training every 4 years, and update their training annually if necessary. 2.6.3 To facilitate inspections, a safety inspection checklist for blowout prevention systems is recommended; its details are provided in the attachment. Section 3 Completion, Testing, and Workover Operations 3.1 Develop an operation plan and an emergency plan prior to the operations. 3.2 Equipment used for well completion, testing, and overhauls must be equipped with appropriate blowout preventers and their control systems. 3.3 The properties of the mud and the mud materials used in completion, testing, and workover operations should be stocked and inspected as planned. 3.4 The following personnel must hold a well control qualification certificate: 3.4.1 Responsible manager or testing engineer ； 3.4.2 Shift Supervisor ； 3.4.3 Senior workover technicians and senior testing technicians. 3.5 The requirements regarding well control during completion, testing, and overhauling operations shall be implemented in accordance with the regulations applicable to drilling operations. Section 4 Production Operations 4.1 Oil and gas production wells with self-priming and self-overflowing capabilities should be equipped with downhole packers to seal the annulus between the tubing and casing. At a depth of 30 meters or greater beneath the sea floor, all oil pipes should be equipped with downhole safety valves. 4.1.1 Subsurface safety valves with on-water control: They should be tested on-site upon new installation or reinstallation, and subsequent testing intervals must not exceed 6 months. If they do not function properly, they should be removed, repaired, replaced, reinstalled, and tested again to ensure they remain in good working condition at all times. 4.1.2 Subsea-controlled downhole safety valves: Subsea-controlled downhole safety valves should be installed on the tubing of each well in single-well satellite wells or multi-well platforms for seabed completion. As needed, it should be removed, repaired, replaced, reinstalled, and retested to ensure it remains in good working condition at all times. 4.1.3 Ground safety valves: They should always be kept in good working condition. 4.1.4 Equipped with a suitable wellhead pressure measurement and blowout prevention box. 4.2 Emergency shutdown system: Platform managers, shift supervisors, and chief operators must have a thorough understanding of the emergency shutdown system, be able to operate it and conduct inspections on it, to ensure that this system remains in good working condition at all times for emergency use. 4.3 For each type of underwater safety device that has been installed, the operator shall keep records and documents related to installation, commissioning, etc., in both offshore and onshore offices for reference. Appendix: BOP System Safety Inspection Checklist 1. Casing procedure and design basis? What are the results of the cementing quality tests and the formation fracture pressure test data? 2. Mud program and design basis? 3. Is a diagram showing the status of the blowout prevention system (including the BOP stack, pipelines, valves, and manifolds) displayed on the drilling rig? What is the rated operating pressure for each component of this system? Is the process reasonable? 4. Can the drill pipe be forced down into the well between the BOPs? 5. Are there internal blowout preventers for drill pipes and drill collars on the drill floor? ； Kerb bit plug wrench and appropriate safety valve? 6. Is the throttle pipeline securely fixed? 7. Are the pipeline connections of the offshore BOP stack secure, and are they easy to adjust? 8. Is the mud injection pipeline separate from the well killing pipeline? 9. During the drilling up process, can the flow indication and discharge condition of the mud at the mud outlet be seen on the drill floor? 10. Is the mud pump stroke counter on the drill floor accurate and sensitive? 11. Is the pressure testing plug suitable for BOP pressure testing in good condition? 12. Does Inoue have spare steel rings and vulnerable parts? 13. Is the blowout preventer maintained according to the standard maintenance procedures? 14. Can all blowout preventers be closed within 19 seconds or less after the pump is stopped, with 50% of the hydraulic fluid remaining in the accumulator at a pressure of 98 kg/cm² (1400 psi)? 15. Was the cable blowout preventer box pressurized to the maximum expected pressure? 16. Is there a regulation regarding the injection of mud when pulling out several drill pipes, and when pulling out drill collars, is an amount 4 to 5 times normal injected? 17. Is a chart showing the number of drill strings to be pulled out and the amount of mud to be pumped posted on the drilling rig? 18. Does the drilling crew know the procedures to handle well leakage or pumping issues that occur during drilling and tripping? 19. Does the blowout prevention scenario* include records of scenarios related to the drill string at the bottom of the well, during drilling and tripping, as well as after drilling is completed? What measures should be taken after the above situation occurs? 20. Are there appropriate well control work charts available on the drill floor? Will the drilling crew use it? 21. What is the maximum allowable wellhead pressure for shutting down a well? Does the drilling team know? 22. Can the well be shut down quickly while monitoring and controlling the casing pressure? 23. Do the drilling supervisor, drill operator, and drilling crew have a thorough understanding of well control methods and the operation and maintenance of equipment? 24. Are the lighting and electrical systems explosion-proof? 25. Does the derrick worker have a descent device for escaping? 26. Are the fire-fighting equipment placed in appropriate locations? 27. Is the mud pool level indicator checked every time the drill is started or stopped? Note: Drilling equipment refers to drilling ships and fixed drilling platforms