IWCF Level 3 DWC key terms

An unintended influx of formation fluid into the wellbore because the bottomhole pressure is lower than the pore pressure of an exposed permeable formation. If not controlled it can escalate into a blowout.

The fluid, whether gas, oil, water or a mixture, that enters the wellbore from the formation during a kick. Its type and volume determine how the well is circulated and killed.

An uncontrolled flow of formation fluid from the wellbore to surface. It results when kicks are not detected or not controlled, and it is the primary hazard the well control barrier system is designed to prevent.

Keeping bottomhole pressure above formation pore pressure using the hydrostatic pressure of a correctly weighted and maintained column of drilling fluid. It is the first line of defence against a kick.

Using mechanical barriers, principally the blowout preventer stack and its closing equipment, to contain formation pressure when primary control by hydrostatic pressure has failed or is being restored.

The pressure exerted at a given depth by the weight of the fluid column above it. It depends on fluid density and true vertical depth, and it is the main component of bottomhole pressure.

The pressure of the fluids contained in the pores of a subsurface formation. It is also called pore pressure, and it must be balanced or exceeded by bottomhole pressure to prevent flow into the well.

The pressure of fluid within the pore spaces of rock. Normal pore pressure follows a hydrostatic gradient with depth, while abnormal pore pressure is higher or lower than that expected gradient.

The total pressure acting on the formation at the bottom of the well. It equals the sum of hydrostatic pressure and any applied surface pressure, and it governs whether the well flows or stays static.

The condition where bottomhole pressure exceeds formation pore pressure, so fluid tends to flow from the wellbore into the formation. It is the normal condition during drilling and prevents kicks.

The condition where bottomhole pressure is lower than formation pore pressure, allowing formation fluid to flow into the wellbore. It is the direct cause of a kick and must be corrected quickly.

The density of the drilling fluid, usually expressed in pounds per gallon, kilograms per cubic metre or specific gravity. It is adjusted to provide the hydrostatic pressure needed for primary well control.

The pressure exerted by a unit depth of drilling fluid, typically expressed in psi per foot or bar per metre. It is used with true vertical depth to calculate hydrostatic pressure.

The effective mud density that includes both the static mud weight and the extra pressure from annular friction losses while circulating. It is higher than the static mud weight and affects fracture and kick margins.

The effective mud density at a given depth when the well is static, derived from hydrostatic pressure and true vertical depth. It is the reference value used for shut-in pressure calculations and kick analysis.

The deliberate closing of the well, using the blowout preventers and choke, to stop flow and allow stable pressures to be read. Correct shut-in procedure is essential for safe kick control.

A shut-in performed by closing the blowout preventer with the choke already closed, so no flow is taken through the choke. It minimises influx volume and is the preferred method on many rigs.

A shut-in procedure in which the choke is opened, the blowout preventer is closed, and then the choke is closed to route flow through the choke line. It allows some additional influx compared with a hard shut-in.

The stabilised pressure read on the drill pipe after the well is shut in. It represents the difference between formation pressure and the hydrostatic pressure of the mud in the drill string.

The stabilised pressure read on the casing or annulus after shut-in. It reflects the pressure needed to balance the formation minus the hydrostatic pressure of the mud and influx in the annulus.

The mud density required to balance formation pressure when the well is static. It is calculated from the shut-in drill pipe pressure plus the original mud hydrostatic pressure, divided by true vertical depth.

A prepared calculation form used during well control operations. It records pressures, volumes, pump rates and the schedule of casing pressure and stroke counts used to keep bottomhole pressure constant while killing the well.

A well kill technique in which the influx is first circulated out using the original mud weight, then the well is circulated with kill mud. It uses constant drill pipe pressure and does not require a kill mud wait.

A well kill technique in which kill mud is mixed and then pumped while the influx is circulated out in a single circulation. It generally gives lower casing pressures than the driller's method.

A reduced pump rate, typically one quarter to one half of normal, used for killing the well and measuring circulating pressures. It keeps annular friction losses low and manageable during well control operations.

The circulating pressure measured at the slow circulating rate before a kill, recorded for the drill pipe and casing. It is used together with shut-in pressures to build the kill schedule.

The pump pressure required to circulate fluid through the system at a given rate. During a kill it is adjusted as kill mud enters the drill string so bottomhole pressure stays constant.

The pressure lost to friction as fluid flows up the annulus. It adds to bottomhole pressure while circulating and must be accounted for in equivalent circulating density and kill calculations.

A variable restriction in the flow line used to control the pressure held on the annulus while fluid is circulated. Adjusting the choke maintains the required bottomhole pressure during a kill.

An arrangement of valves, chokes and piping that routes flow from the well to the choke and then to the mud gas separator or pit. It allows controlled pressure release during well control operations.

The high-pressure line that carries fluid from the choke manifold back to the well, or in some configurations from the pumps to the wellhead. It forms part of the circulation path during a kill.

The assembly of blowout preventers, including annular and ram types, installed on the wellhead. It provides the mechanical barrier used to close the well and control formation pressure.

A blowout preventer with a flexible rubber element that seals around the drill pipe or closes on an open hole. It allows pipe to be moved or stripped through it while maintaining a seal.

A blowout preventer using steel rams that close across the wellbore. Pipe rams seal around a specific pipe size, blind rams close an empty hole, and shear rams cut the pipe to seal the well.

A ram-type blowout preventer fitted with blades that cut through drill pipe and then seal the wellbore. It is used as a last resort when other barriers cannot be closed.

A physical or operational feature that prevents formation fluid from reaching surface, such as mud hydrostatic pressure, casing, cement or a closed blowout preventer. Multiple independent barriers are required.

The maximum influx volume that can be taken into the well and still be circulated out safely without fracturing the weakest exposed formation. It depends on pore pressure, fracture pressure and mud weight.

A test performed after drilling out casing to determine the pressure at which the formation begins to take fluid. The result defines the maximum mud weight and kick tolerance for the next section.

A pressure test of the formation below casing, similar to a leak-off test but taken to a higher pressure to confirm the shoe can withstand the planned mud weight. It verifies the barrier at the casing shoe.

The pressure at which a formation will crack and begin to accept fluid. Exceeding it causes lost circulation, which lowers hydrostatic pressure and can allow a kick to develop.

The loss of drilling fluid into a formation because the pressure in the wellbore exceeds the fracture pressure. It reduces the mud column and hydrostatic pressure, increasing kick risk.

An increase in the volume of mud in the surface pits that indicates fluid is entering the well from the formation. It is a primary kick indicator and is measured against expected pit levels.

A deliberate pause in drilling with pumps off to see whether the well continues to flow. A positive flow check confirms a kick and triggers shut-in procedures.

A vessel that removes free gas from the mud returns before the mud reaches the pits. It protects the rig and personnel from gas hazards during a kick and allows safer circulation.

Drilling fluid whose density is reduced by entrained gas from the formation. It lowers hydrostatic pressure slightly, but the effect is usually small and must not be confused with a genuine influx.

Moving pipe into or out of a closed well through an annular preventer while allowing controlled flow to maintain bottomhole pressure. It is used when the pipe cannot be pulled or the well must be kept closed.