IWCF Level 4 Drilling key terms

An unintended influx of formation fluid into the wellbore, caused when formation pore pressure exceeds the pressure exerted by the drilling fluid column. If not detected and controlled early, it can escalate into a blowout.

An uncontrolled flow of formation fluids from the wellbore to the surface. It results from a kick that is not contained by well control equipment or procedures and can cause fire, injury, and loss of the rig.

The volume of formation fluid that has entered the wellbore. It is detected by pit gain, flow checks, or changes in pump pressure and is the physical evidence that a kick is occurring.

The pressure of fluids contained within the pore spaces of a rock formation. It acts against the wellbore and is the pressure that drilling fluid hydrostatic pressure must balance or exceed.

The pressure of fluids trapped in the pores of subsurface rock. Normally it equals hydrostatic pressure of formation water, but it can be abnormal (higher or lower) and must be predicted and monitored during drilling.

The pressure exerted at any depth by the weight of a static fluid column. It depends on fluid density and true vertical depth, and it is the primary barrier that prevents formation fluids from entering the wellbore.

The density of the drilling fluid, usually expressed in pounds per gallon, pounds per cubic foot, or specific gravity. It determines hydrostatic pressure and is adjusted to keep the well overbalanced.

The pressure increase per unit of true vertical depth produced by a given drilling fluid density, commonly expressed in psi per foot or kPa per metre. It allows quick comparison of mud, pore, and fracture pressures.

The pressure at which a formation breaks down and begins to accept fluid, creating or extending fractures. Exceeding it can cause lost circulation and loss of the primary barrier.

The fracture pressure expressed per unit of true vertical depth, typically in psi per foot. It defines the upper limit of mud weight that can be used at a given depth without fracturing the formation.

A test performed after drilling a short section of new formation, in which pressure is applied to the shut-in well until the formation begins to take fluid. It establishes the fracture pressure at the casing shoe.

A pressure test of the formation at the casing shoe to a predetermined value, usually below the expected fracture pressure. It confirms the well can withstand the planned mud weight without proving the exact leak-off point.

The maximum influx volume, of a specified fluid, that the well can take without the resulting shut-in pressure exceeding the formation fracture pressure at the casing shoe. It indicates how much margin exists.

The highest annular surface pressure that can be applied without fracturing the formation at the casing shoe. It is calculated from the fracture gradient at the shoe and the current mud weight.

The bottom end of a casing string, usually the shallowest point where the formation is exposed. It is commonly the weakest point in the open hole and is used as the reference depth for fracture pressure limits.

The formation immediately below the casing shoe that supports the casing and is exposed to wellbore pressure. Its integrity, tested by LOT or FIT, sets the upper limit for mud weight in the next hole section.

A well condition in which the hydrostatic pressure of the drilling fluid exceeds formation pore pressure. It prevents influx but can cause lost circulation or formation damage if excessive.

A well condition in which formation pore pressure exceeds the pressure exerted by the drilling fluid column. It allows formation fluids to enter the wellbore and is a direct precursor to a kick.

Extra mud weight added above the required balance pressure to compensate for the loss of hydrostatic pressure caused by swabbing when pulling pipe. It provides a safety buffer against kicks during trips.

A reduction in bottomhole pressure caused by the upward movement of pipe or tools in the wellbore, which acts like a piston. Excessive swabbing can reduce pressure below pore pressure and induce a kick.

An increase in bottomhole pressure caused by the downward movement of pipe or tools in the wellbore. Excessive surge can fracture the formation and cause lost circulation.

The loss of drilling fluid into a formation, usually through fractures or high-permeability zones. It lowers the fluid level in the annulus, reduces hydrostatic pressure, and can allow a kick to occur.

The effective density exerted on the formation while the mud is circulating, combining mud weight with the additional pressure from annular friction losses. High ECD can fracture formations even when static mud weight is acceptable.

The effective density exerted on the formation when the mud is static, equal to the true mud weight plus any trapped pressure effects. It is the static counterpart used when comparing with ECD.

The pressure required to overcome friction as drilling fluid flows up the annulus. It adds to hydrostatic pressure and raises ECD, and it is affected by flow rate, mud properties, and annular clearance.

The pump pressure measured while circulating at a reduced rate, usually one-quarter to one-half of normal. It is used to calculate the pressure losses needed for the wait-and-weight and driller's methods.

The circulating pressure at a selected slow pump rate used for well killing, measured before the influx occurs. It provides the reference for adjusting pump pressure as kill mud is circulated.

The stabilized pressure read on the drill pipe gauge after the well is shut in. It equals the difference between formation pore pressure and the hydrostatic pressure of the mud in the drill string.

The stabilized pressure read on the casing gauge after the well is shut in. It reflects the pressure required to balance the formation plus the additional pressure caused by the influx in the annulus.

The act of closing the blowout preventer and stopping circulation to contain an influx and allow pressures to stabilize. Proper shut-in procedure is the first response to a kick.

A shut-in procedure in which the well is closed with the choke or adjustable valve open first, then the choke is closed slowly. It limits pressure surges on the formation and equipment.

A shut-in procedure in which the blowout preventer is closed with the choke already shut. It is fast but can impose a pressure surge on the formation and is generally used only in specific circumstances.

The drilling fluid density required to balance formation pore pressure so that no further influx occurs. It is calculated from the SIDPP and the current mud weight and is used in the wait-and-weight method.

A well kill technique in which the influx is circulated out first using the original mud weight, then the well is weighted up and circulated. It removes the influx quickly but requires two circulations.

A well kill technique in which kill mud is prepared and then pumped to circulate out the influx in a single circulation. It usually results in lower casing shoe pressures than the driller's method.

An adjustable valve used to control the rate of flow from the annulus while maintaining back pressure on the well during a kill. It is the primary tool for holding casing pressure within limits.

The pipe connecting the blowout preventer stack to the choke manifold. Its friction pressure adds to the pressure seen on the casing gauge and must be accounted for in kill calculations.

An arrangement of valves, chokes, and gauges that receives flow from the BOP stack and routes it to the choke, mud-gas separator, or pit. It provides controlled release of wellbore fluids during a kill.

A large valve or assembly of valves installed at the wellhead to seal the wellbore and control pressures. It is the main mechanical barrier for containing kicks and preventing blowouts.

A BOP component with a flexible elastomeric element that seals around any shape of pipe or closes on an open hole. It is versatile but generally rated to lower pressures than ram preventers.

A BOP component that uses hydraulically driven steel rams to seal the wellbore, either around pipe or across an open hole. Different ram types include blind, pipe, and shear rams.

A ram preventer designed to cut through drill pipe and then seal the wellbore. It is used when pipe must be severed, for example to close the well in an emergency.

A high-pressure line connected to the wellhead or BOP stack that allows kill-weight mud to be pumped into the well during well control operations. It is part of the circulating system for killing a well.

A vessel that removes gas from the returning drilling fluid before it reaches the pits. It allows gas-cut mud to be safely vented while the liquid phase is recovered and returned to the system.

Drilling fluid that contains entrained gas, which reduces its density and therefore its hydrostatic pressure. It is a warning sign that formation gas has entered the wellbore.

An increase in the volume of drilling fluid in the surface pits, indicating that formation fluid has entered the wellbore. It is one of the most reliable early indicators of a kick.

A procedure in which the pumps are stopped and the well is observed for continued flow from the annulus. Flow with the pumps off indicates an influx and requires the well to be shut in.

The operation of pulling drill pipe out of or running it into the wellbore. Trips are a high-risk period for kicks because of swab and surge pressures and because the well is not being circulated.

A sudden increase in the rate of penetration, often caused by drilling into a softer or higher-pressure formation. It is an early warning sign that a kick may be developing.

Observable indicators that an influx may be occurring, including pit gain, flow with pumps off, drilling break, gas cut mud, and reduced pump pressure. Recognizing them early allows prompt shut-in.

The use of drilling fluid hydrostatic pressure to prevent formation fluids from entering the wellbore. It is the first line of defense against a kick and relies on maintaining adequate mud weight.

The use of blowout preventers and related equipment to contain formation fluids when primary well control has failed. It includes shutting in the well and circulating out an influx.

A physical or procedural element that prevents formation fluids from flowing uncontrolled into the wellbore or to surface. Well control philosophy requires at least two independent barriers during operations.

The pump pressure required to circulate drilling fluid through the system at a given rate. It changes with mud properties and flow rate and is used to monitor well conditions during a kill.

The pressure measured at the standpipe on the rig floor, representing the total pump pressure needed to circulate mud through the drill string, bit, and annulus. It is a key indicator during well control operations.

The pressure measured at the choke manifold during a kill, used to control back pressure on the annulus. It is adjusted to keep bottomhole pressure constant as the influx is circulated out.

The total pressure acting at the bottom of the wellbore, equal to hydrostatic pressure plus any applied surface pressure. It must be kept at or above pore pressure to prevent influx and below fracture pressure to avoid losses.