Well Control Checklist (Example)

Below is Well Control Checklist for Land Drilling/Workover units.

Equipment Compliance

1. BOP stack up configuration covering all pipe sizes planned to be run in hole Confirm type of Shear rams installed as per programme requirement.

2. BOP function tested & BOP pressure tested

3. BOP drawdown tested

4. Standpipe manifold including individual valve seats tested

5. Choke manifold including individual valves and choke lines tested

6. 1 x class 2 kelly cock and 1 x gray valves on rig floor, including crossovers for all connections on drillstring and BHA. Successfully pressure tested from below. Backup 1 x class 2 kelly cock and 1 x gray valve on site and pressure tested.

7. Top drive IBOPs successfully tested from below. Confirm last re-dress < 1 year.

8. Casing successfully tested as per drilling programme topsheet. Confirm test pressure.

9. SOV’s installed on A and B annulus and tested to SWP or 85% of casing burst.

10. WH and SOV certs sighted and SWP and sour rating (DD-NL or EE-NL) confirmed. (if applicable)

11. All pressure gauges have a valid pressure calibration certificate. Standpipe pressure gauges are all Max working pressure

12. Digitial / analogue gauges are calibrated at low pressure and full scale.

13. All pressure transducers on choke side are sour rated with H2S elastomers for the hammer union seal. (if applicable)

14. Pit level systems are operational with sensors on all pits. Ensure that mud weight in / out digital sensor is operational. Verify Drillers PVT active allocation / alarms / flo-sho alarms / EKDS alarms.

15. Kick detection equipment and alarms such as flow meters, level indicators and associated gauges, alarms, recorders and controls working correctly. Confirm
    

    1. EKDS set for +/- 50,

    2. PVT for +/- 1-m3.

    3. Flo-Show for +/- 5%.

    4. Alarms set and tested.

    5. EKDS to be calibrated at low flow and high flowrate ie 100lpm / 1100lpm.

    6. Return flow meter (flo-sho) not to fluctuate more than +/- 3% and sensitivity set at minimum 30% for 1000lpm flow.

16. Gas sensors calibrated and function tested.

17. Confirm minimum Barite & Calcium Carbonate based LCM

18. H2S contingency support company and contractor BA sets charged and ready for use in dedicated locations. Cascade system function tested. Drilling contractor has air compressor and air quality test kit, and re-filling own bottles (H2S contingency support company not to fill Drilling Contractor bottles)

19. Poor boy degasser flushed and contents known. PBDG pressure gauge readable from remote choke panel.

20. Vacuum degasser checked and confirmed operational (-5 to -15psi on gauge, test vacuum by opening valve and observing suction when unit is running)

21. SCRs taken with planned drilling mud (including HP unit as per WWI in HP section)

22. Calibration of pressurised mud weight balance witnessed.

23. Correct wearbushing is installed.

24. Confirmed latest valid copy of Drilling Programme including pore pressure available and used by all on site.

Procedure Compliance

1. Fluid gradient in line with specifications in programme, list overbalance to minimum / expected / maximum pore pressure.

2. Barrier diagrams for all operations – drilling, running liner, open hole logging, running completion with 1/2 gauge or SSSV control lines from drilling programme posted in DSV office and drillfloor.

3. Verify with rig leadership team (SWE / FSWE / DSV / DS / TP / NTP) that any required MOCs are approved and MOC listed mitigations are in place. Provide copy of latest PMS backlog from drilling contractor.

4. Close-in scenarios and choke manifold set-up (hard shut-in) agreed and displayed.

5. Confirm agreed kill method.

6. Operator and contractor kick sheets to be updated and cross checked before drilling the reservoir. If deviated well (ie > ca.10 deg) use a deviated kill graph.

7. Annular minimum closing pressure vs pipe OD graphs and VBR maximum hang off weight vs pipe OD graphs are posted at BOP panels.

8. Poor boy degasser chart of maximum working pressure vs mud weight displayed. Completed Operator PBDG capacity spreadsheet displayed.

9. Emergency Response Procedures available and understood by all. Well Control Contingency Plan and Firefly Manuals on site (DSV and TP office)

10. SIMOPS Procedures available and understood by all.

11. Check communications equipment functionality:
    

    1. can change from group to direct mode on radio /

    2. can call telephone from radio /

    3. can switch radio to satellite mode /

    4. satellite phone has minimum 150 OMR credit

12. Review expected and potential subsurface scenarios and required well control actions with TP / Driller / Mud Logger / Ops Eng (ie number of floaters / risk of losses / risk of supercharging / picking section TD). Discuss the same in pre-section meeting on rig. Note that in event of loss / gain event shut in and think and discuss with town.

13. Strip drill performed or list planned dates (for all crews)

14. Trip drill performed or list planned dates (for all crews)

15. Pit drill performed or list planned dates (for all crews)

16. EKDS drill performed or list planned dates (for all crews)

People

1. All TP / Drillers / AD / DSVs have valid IWCF

2. All DSV’s are FLB compliant

3. All safety critical positions have attended licensing where required