General requirements

  1. Tested Blowout Prevention Equipment (BOPE) shall be installed for drilling operations below the surface casing shoe.
  2. The Blowout Preventer (BOP) stack and wellhead in place at any point during the course of the well, shall be of sufficient working pressure and temperature rating to contain the maximum allowable surface pressure and temperature from total depth of the current open hole section.
  3. The maximum allowable wellhead pressure shall take into account a gas column to surface for exploration and appraisal wells. whilst for development wells reservoir fluid shall be used.
  4. In balanced drilling, conventional and hydraulic workover operations involving static fluid column designs, the designated company representative shall be present prior to each trip to flow and loss check the well and then directly observe the trip until satisfied the wellbore fluid level is stable and the hole fill volume is correct.
  5. In unconventional operations without static fluid levels, the designated company representative shall observe the pre—trip well conditions and assure themselves that the well will behave in accordance with expected norms for the planned operations.
  6. After completing all well kills or well testing operations. the designated company representative shall be present to flow and loss check the well and directly observe the trip until such time as they are satisfied that the wellbore fluid level is stable and/or the hole is safe to trip prior to pulling out of the hole.
  7. Kick detection, diverter, circulating, stripping, and shut-in drills shall be held regularly until the designated company representative is satisfied that each crew demonstrates suitable BP standards.
  8. Thereafter kick detection and shut-in drills shall be performed at a minimum of once per week per crew and be reported in the Daily Report form.
  9. A shut-in method shall be established, communicated and practiced which minimizes influx and impact to the wellbore. Line and valve configurations shall be planned, communicated and regularly checked by the driller or service unit operator and position confirmed with the BP well site leader or his designate.
  10. The driller/operator is responsible for and authorized to shut the well in. The designated company representative shall be the only person authorized to initiate opening the well as part or conclusion of well control measures.
  11. Except during under balanced drilling, a drilling well kick sheet shall be maintained and updated for immediate use in the event of a well control event.
  12. A well control incident report shall be completed and documented within the Traction reporting system following any well control incident.
  13. At least one contingent barrier i.e. down hole float valve shall be included on any casing string run through a hydrocarbon-bearing formation.
  14. Differential fill float equipment shall not be used on casing strings which are to be run through potential hydrocarbon-bearing zones. This policy may be relaxed after a documented risk assessment and approval of the Business Unit (BU) well control Technical Authority (TA) or designate.
  15. Auto fill float equipment shall be tripped prior to running through any hydrocarbon bearing zone.
  16. For all exploration, High Pressure High Temperature (HPHT) and H2S appraisal wells, a well specific Well Control Response Guide shall be prepared.
  17. A well control interface/bridging document shall be prepared with the appropriate contractor to ensure there is clear understanding of responsibilities and which reference documents and procedures will be used in a well control situation.
  18. Each BU shall ensure that well control response guides are maintained in every supporting OC and base office and emergency drills are regularly conducted and reported. These guides shall address the availability of a means of quickly evacuating the well site and responding to an event.
  19. During well construction and maintenance activities, operations shall be conducted with one active barrier and one contingent barrier installed to address critical operational risks and contain the well.
  20. During conventional drilling, completions and well work activities the active barrier shall normally be a stable fluid column and the contingent barrier shall be the blowout preventer (BOP) equipment or tree. During under-balanced drilling, wireline, snubbing and coil tubing intervention activities, the active barrier shall normally be a dynamic mechanical sealing device and the contingent barrier shall be the BOP or tree.


  • BP Drilling and Well Operations Practice manual