IWCF Level 2 Drilling key terms

The pressure exerted at any point by the weight of the fluid column above it, depending only on true vertical depth and fluid density, not on the shape or volume of the wellbore.

The vertical distance measured from the rotary table or datum straight down to the point of interest in the well. Used for all pressure calculations because hydrostatic pressure depends on vertical height only.

The distance measured along the actual path of the wellbore from the datum to the point of interest. Differs from true vertical depth in deviated or horizontal wells and is used to position tools and pipe.

The pressure of fluids contained in the pore spaces of a rock at a given depth. It is the pressure the wellbore fluid must balance to prevent influx from entering the hole.

The pressure of fluid trapped within the pores of a formation, also called formation fluid pressure. Normal pore pressure follows a hydrostatic gradient; abnormal pore pressure is higher or lower than that gradient.

The pressure at which a formation begins to crack and accept fluid. It sets the upper limit of mud weight that can be used at a given depth without inducing losses.

Formation pressure that departs from the normal hydrostatic gradient for that depth. It may be overpressured, requiring heavier mud, or underpressured, which risks losses and differential sticking.

The total pressure exerted at a depth by the weight of all rock and fluid above it. It is the absolute upper bound on formation pressure and defines the maximum possible fracture gradient.

The mud density that would produce a given pressure at a given true vertical depth, usually expressed in pounds per gallon or specific gravity. It lets pressures from different depths be compared on one scale.

The range of mud densities between pore pressure and fracture pressure at a given depth. Staying inside this window balances formation fluids without breaking the rock down.

Extra mud density added above pore pressure to offset the loss of hydrostatic pressure caused by pulling pipe out of the hole. It compensates for the swab effect during trips.

A record kept while pulling pipe that tracks the volume of mud needed to fill the hole against the number of stands pulled. Discrepancies warn of a kick or of losses.

An unintended flow of formation fluid into the wellbore, caused when formation pressure exceeds the pressure exerted by the mud column. If not controlled, it can escalate into a blowout.

An uncontrolled release of formation fluids from the wellbore to the surface or into another formation. It results when a kick is not detected or not controlled in time.

Keeping formation fluids in place using the hydrostatic pressure of the drilling fluid column. It is the first and preferred barrier against influxes, ahead of any mechanical device.

The use of mechanical barriers such as blowout preventers and the choke system to contain formation pressure when primary well control is lost. It stops the flow after a kick has entered the well.

A large valve assembly at the wellhead that can close around or over the drill string to seal the wellbore. It is the key secondary well control device during drilling and intervention.

A BOP element with a rubber sealing element that closes around almost any shape of pipe or the open hole. It can seal the annulus while allowing pipe to be moved.

A BOP element that closes by driving two steel rams together across the wellbore. Rams may be blind, blind-shear, or pipe rams sized for a specific pipe diameter.

A system of valves and adjustable chokes that controls the rate of flow from the well while allowing pressure to be held on the annulus. It is central to killing a well.

An adjustable or fixed restriction used to control flow rate and back pressure on the annulus. Adjusting the choke lets the driller hold casing pressure while circulating out a kick.

Closing the well in by stopping the pumps and closing the BOP and choke so that pressure can stabilize and be read. The resulting pressures are used to plan the kill.

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

The stabilized pressure read on the casing annulus after shut-in. It includes the influx pressure plus mud hydrostatic and is used together with SIDPP to identify the influx type.

The formation fluid that has entered the wellbore during a kick. It may be gas, oil, water, or a mixture, and its type affects how pressures behave while it is circulated out.

The mud density required to balance formation pressure after a kick, calculated from the shut-in drill pipe pressure and the current mud weight. It restores primary well control once circulated.

A pre-prepared form used to record pressures, pump rates, and volumes during well killing, and to calculate the pressure schedule to follow while circulating the influx out.

The pump pressure measured while circulating at a reduced, fixed rate through the choke line. It is used to build the pressure schedule for killing the well.

The pump pressure needed to move fluid through the circulating system at a given rate. It comprises friction losses in the surface lines, drill string, bit, and annulus.

A test performed after drilling a short section of new hole to determine the pressure at which the formation begins to take fluid. It confirms the fracture pressure for the next casing shoe.

The loss of drilling fluid into a formation because the pressure in the wellbore exceeds the fracture pressure. It reduces hydrostatic pressure and can allow a kick to develop.

The reduction in bottomhole pressure caused by pulling pipe upward, which acts like a piston and draws fluid from the formation. Excessive swab can trigger a kick.

The increase in bottomhole pressure caused by running pipe into the hole or by starting pumps too quickly. Excessive surge can fracture the formation and cause losses.

A deliberate pause in operations with pumps off to see whether the well continues to flow. Any continued flow indicates an influx and requires the well to be shut in.

Any physical or operational element that prevents formation fluid from reaching the surface, such as mud, casing, cement, or a BOP. Well control relies on having at least two independent barriers.

Any operation performed on a well after it has been drilled and completed, to maintain, repair, or improve production. It includes wireline, coiled tubing, and snubbing work.

A method of running tools or sensors into a well on a thin steel cable, either slickline or braided electric line. It is used for logging, perforating, and setting or retrieving devices.

A continuous length of flexible steel pipe run into a well from a reel, used for circulation, cleanout, and stimulation without making up joints. It can operate in live wells with pressure control equipment.

Moving pipe into or out of a well that is under pressure, using a snubbing unit and blowout preventers to control the well. It is used when wellbore pressure would otherwise push the pipe out.

The stack of devices used during intervention to contain well pressure around wire, cable, or pipe, including blowout preventers, lubricators, and stuffing boxes. It provides the secondary barrier during the job.

A tubular pressure vessel mounted on top of the wellhead that allows tools to be run into a live well while keeping pressure contained. Its length must match the longest tool being used.