IWCF Level 1 key terms

The set of practices, procedures and equipment used to keep formation fluids from entering the wellbore uncontrolled, and to bring any influx safely to surface.

Keeping formation fluids in the reservoir by maintaining a mud column whose hydrostatic pressure slightly exceeds formation pore pressure during normal operations.

The use of blowout prevention equipment, such as the BOP stack, to shut in the well and control pressure after primary control has failed.

Special techniques used when the well cannot be controlled by normal circulation or shut-in, such as bullheading, stripping, or pumping lost circulation material.

The pressure of fluids contained in the pore spaces of a rock at a given depth; it pushes outward on the wellbore and must be balanced by the mud column.

The pressure exerted by fluids trapped within the pores of a formation, also called formation fluid pressure; it is the pressure the mud must balance.

The total pressure at a given depth caused by the weight of all rock and fluids above it; it limits how high pore pressure can rise before fracturing occurs.

The pressure at which a formation will crack and start to take fluid; exceeding it causes lost circulation and can create a path for formation fluids to migrate.

The pressure exerted by a stationary column of fluid due to its weight, increasing with depth and with the density of the fluid.

The rate at which pressure changes with depth, usually expressed in psi per foot or bar per metre; a normal gradient is about 0.465 psi/ft for fresh water.

The density of the drilling fluid, measured in pounds per gallon, kilograms per cubic metre, or expressed as an equivalent specific gravity.

A way of expressing any pressure at a given depth as the density of mud that would produce the same pressure at that depth.

An unintended flow of formation fluid into the wellbore because the mud column pressure is lower than formation pressure; it must be detected and controlled quickly.

The volume of formation fluid that has entered the wellbore; its size and type determine how the well is brought back under control.

An uncontrolled flow of formation fluids to surface or into another formation, occurring when well control is lost and the BOP equipment cannot contain the pressure.

A large valve-like device installed at the wellhead that can be closed to seal the wellbore around drill pipe, tubing, or an open hole to prevent flow.

The assembly of blowout preventers, spools, and valves mounted on the wellhead that provides the main barrier against uncontrolled flow from the well.

A BOP component with a flexible rubber element that can close and seal around almost any shape or size of pipe, or close on an open hole.

A BOP component that uses two opposing steel rams to close off the wellbore; rams may be blind, pipe, or shear types.

A ram preventer whose two blocks close against each other to seal an open wellbore with no pipe present.

A ram preventer fitted with cutting blades that can shear through drill pipe and then seal the wellbore, used as a last-resort barrier.

A system of valves and adjustable chokes connected to the BOP that lets operators control the rate of flow out of a shut-in well while circulating out an influx.

An adjustable or fixed restriction in the flow line used to control back pressure on the well and regulate the rate at which fluids are released.

Closing the BOP and choke to stop flow from the well so that stabilized pressures can be read and used to plan the kill operation.

The stabilized pressure read on the drill pipe after the well is shut in; it reflects the difference between formation pressure and the mud hydrostatic pressure.

The stabilized pressure read on the casing annulus after shut-in; it includes the drill pipe pressure plus the pressure exerted by the influx in the annulus.

The mud density required to balance formation pressure, calculated from the original mud weight plus the shut-in drill pipe pressure converted to an equivalent density.

Drilling fluid prepared at the kill weight or slightly heavier, used to circulate out an influx and restore primary well control.

The controlled process of pumping kill mud while holding back pressure with the choke, moving the influx to surface and replacing the light mud in the well.

A well-killing technique in which the influx is circulated out first using the original mud weight, then kill mud is pumped around the well.

A well-killing technique in which kill mud is prepared first and then pumped in one circulation, removing the influx while simultaneously increasing mud density.

Pumping fluid into the well against formation pressure to force the influx back into the formation, often used when the string is plugged or off bottom.

Moving pipe into or out of a shut-in well through closed BOP elements while controlling pressure with the choke, used when the string must be run back to bottom.

An increase in the volume of mud in the surface pits that cannot be explained by normal operations, often the first surface sign that the well is flowing.

A deliberate pause in operations to observe whether the well continues to flow with the pumps off, used to confirm or rule out a kick.

Drilling fluid that contains gas bubbles from the formation, which lowers its density and can indicate an influx, though it may also come from drilled gas.

The loss of drilling fluid into a formation through fractures or vugs, which lowers the mud column and can allow formation fluids to enter the well.

The maximum influx volume, or equivalent mud weight increase, that a well can safely take before the resulting pressure would fracture the weakest exposed formation.

A pressure test in which the well is pressurised to confirm the formation and casing shoe can withstand the planned mud weight and kick tolerance.