Well Control Drills and Operational Checklists

Readiness must be demonstrated

Well control drills develop and maintain crew competence and check that the required equipment is ready. The syllabus includes pit, trip, strip, choke and diverter drills and an accumulator test. These activities have different purposes: recognising a gain, responding during a trip, managing pipe through barriers, controlling pressure, diverting shallow gas and demonstrating stored hydraulic capacity. A drill should test its intended skill without creating an unplanned well control hazard.

The applicable operations manual, well programme and standards define the schedule, permitted simulation and acceptance criteria. A syllabus reference to an API standard is not itself a universal interval or permission to actuate equipment on unsuitable tubulars. Brief the exercise, identify the current barrier configuration and establish stop conditions. Separate simulated indications from real ones so a genuine event is never dismissed as part of the drill.

Use a checklist to verify critical dependencies

A useful checklist confirms both equipment and procedure. Equipment checks include the correct BOP elements, available control pressure, valves and flow routes, pressure gauges, trip tank, pit and flow monitoring, internal safety valves, crossovers and communications. Procedure checks include the current space-out reference, response sequence, responsible roles, weak-point limit and emergency alternatives. A tick beside “BOP ready” is too vague if the crew has not checked what can actually seal today's assembly.

Before a non-shearable or non-sealable item crosses the BOP, identify it and its planned position, perform the required flow check and establish a means of well closure. A qualified ram may seal the pipe body but not the adjacent tool joint. A shear ram may cut one grade and weight of pipe but not another. The checklist must refer to the current capability data and assembly tally. If the planned movement removes the available closure option, use the approved risk and change process before proceeding.

Pit and trip drills

A pit drill tests recognition of a specified gain or increased returns and the correct communication and response. The driller should identify the deviation, suspend the relevant operation, use the instructed shut-in sequence and verify the simulated or actual barrier function. The observer records detection and response, but speed alone is not success if the wrong function is selected or a flow path remains open.

A trip drill starts with the correct displacement baseline. The crew compares expected fill or returns with the simulated actual result, stops movement, communicates and evaluates flow as instructed. It checks that the safety valve and crossover are available for the string in use and that the current tubular can be sealed. A drill that uses drillpipe assumptions while casing is at the BOP tests the wrong readiness.

Strip, choke and diverter drills

A strip drill tests barrier transfer, space-out, displacement measurement and pressure control using a safe approved arrangement. Ram-to-ram practice should include chamber equalisation and verification of the receiving barrier. A choke drill tests pump-and-choke coordination through startup, a rate change and shutdown. Record whether the operator maintains the instructed pressure while recognising deviations rather than simply following a memorised choke position.

A diverter drill checks that the vent route is available before the packing element seals, that the correct outlet is selected and that interlocks work as designed. It also tests communication, fluid-supply preparation and monitoring for leaks or erosion. On a floating rig, include the relevant riser and marine coordination duties. Function feedback alone does not prove that an obstructed vent will pass the required flow.

Recognise a weak-point limit being exceeded

MAASP is tied to an assumed fluid profile and weak point. During a kill, influx and fluid positions change that relationship. The crew must know the approved dynamic limits and compare predicted pressures and volumes with actual readings. A decrease in returns, unexpected annulus-pressure decline followed by a drillpipe-pressure decline, or unplanned extra choke closure needed to maintain drillpipe pressure can indicate losses. These observations require immediate communication and the contingency response.

Do not infer that a lower casing pressure always means improved safety. If fluid is being lost through a weak formation, pressure can fall while the well becomes less controlled. Conversely, gas above the weak point may change the permissible surface pressure from the original mud-only value. A drill should ask the candidate to explain the pressure at the weak point and the volume balance, not merely compare one gauge with yesterday's number.

Accumulator tests and learning records

An accumulator drawdown test checks the stored fluid and pressure available for the specified function sequence with the recharge pumps isolated as instructed. Record starting and ending pressure, function times and volumes, and compare with the applicable minimum pressure and sequence criteria. A final pressure above a generic number is inadequate if a required ram needs more pressure to close against the anticipated well pressure.

After any drill, record the scenario, equipment configuration, observed actions, deficiencies and corrective actions. Verify that the equipment and valve line-up are restored to the intended operating state. Changes to a well control procedure require the appropriate Management of Change review. A productive debrief identifies a concrete improvement—such as a missing crossover, misunderstood gauge or unclear call—then confirms the improvement in a later authorised exercise.

Drill purposes