Drilling Glossary

The space between the drill string and the wellbore wall (or between concentric casing strings) through which drilling fluid returns to surface.

The lower portion of the drill string including bit, stabilizers, drill collars, and subs; provides weight on bit and directional control.

The total pressure exerted at the bottom of the wellbore, equal to hydrostatic pressure of the fluid column plus any applied surface pressure.

The cutting tool at the bottom of the drill string that breaks rock. Types include roller cone, PDC (polycrystalline diamond compact), and diamond impregnated.

A stack of mechanical valves (annular and ram type) installed on the wellhead to seal the wellbore and prevent uncontrolled fluid flow.

Pumping fluid into the well against formation pressure to force reservoir fluids back into the formation, often during kill operations.

Large-diameter steel pipe run into a wellbore and cemented in place to stabilize the hole, isolate formations, and protect groundwater.

Pumping cement slurry into the annulus between casing and wellbore to seal formations, support the casing, and isolate zones.

A high-pressure line connecting the wellhead to the choke manifold, used to route returning fluid during well control operations.

An arrangement of valves and chokes used to control backpressure while circulating influx out of the well during a kill operation.

The process of pumping drilling fluid down the drill string and back up the annulus to carry cuttings to surface and maintain wellbore pressure.

Thick-walled, heavy steel tubulars placed in the BHA above the bit to provide weight on bit (WOB) and keep the drill string in tension.

Heavy seamless steel pipe that transmits rotation and fluid from the surface to the BHA; the main body of the drill string.

A engineered fluid circulated in the wellbore to lift cuttings, control formation pressure, cool the bit, and stabilize the wellbore.

The effective mud density during circulation, equal to static mud weight plus frictional pressure loss in the annulus expressed as density.

Operations to recover a lost or stuck object (fish) from the wellbore using tools such as overshots, spears, and junk baskets.

The pressure exerted by fluids within the rock pores of a formation; normal pressure equals a full column of formation water.

The pressure gradient at which a formation fractures and begins to accept fluid; the upper pressure limit for the open hole section.

The thixotropic shear strength of drilling mud that suspends cuttings and weighting material when circulation stops.

Closing a BOP ram around the drill pipe to suspend the string in the wellhead, typically during well control or emergency disconnect.

The pressure exerted by a column of fluid at rest, calculated as mud density × true vertical depth × a constant (0.052 psi/ft·ppg).

An unwanted entry of formation fluid (oil, gas, or water) into the wellbore caused by formation pressure exceeding bottom hole pressure.

A single length of drill pipe, casing, or tubing (commonly ~30 ft for drill pipe) connected together to form the string.

A square or hexagonal drive section that transmits rotation from the rotary table to the drill string (legacy systems); replaced by top drive on modern rigs.

The maximum formation influx volume that can be safely circulated out without exceeding the fracture pressure of the weakest open formation.

A high-pressure line from the mud pumps to the wellhead used to pump kill-weight mud into the well during well control operations.

The mud density required to balance formation pressure and kill the well, equal to current mud weight plus SIDPP equivalent density.

A casing string that does not extend all the way to surface but is hung from the bottom of the previous casing string.

The loss of drilling fluid into weak or fractured formations instead of returning to surface; treated with lost-circulation material (LCM).

A pressure-containing pipe run above a closed wellhead to allow tools to be run into a live (pressured) well safely.

Maximum Allowable Annular Surface Pressure — the highest surface pressure allowed on the annulus before the weakest formation fractures.

The total length of the wellbore along its actual drilled path, always greater than or equal to true vertical depth in deviated wells.

A positive displacement downhole motor powered by mud flow that rotates the bit without rotating the entire drill string; used for directional drilling.

The density of drilling fluid, measured in ppg (pounds per gallon) or SG; primary means of controlling formation pressure.

Measurement/Logging While Drilling — downhole sensors transmitting real-time survey and formation data to surface via mud pressure pulses or EM signals.

The accumulation of cuttings or debris around the drill string in the annulus that restricts or blocks fluid flow.

An increase in active mud pit volume indicating formation fluid has entered the wellbore — a primary kick warning sign.

A large-diameter pipe connecting a subsea wellhead to a floating rig to convey drilling fluid and the drill string; enables BOP operation at the surface.

A reduced pump rate used during well control to limit circulating friction; the corresponding pressure is recorded for kill sheet calculations.

Shut-In Casing Pressure — the stabilized surface pressure on the annulus after shut-in, affected by influx type and density.

Shut-In Drill Pipe Pressure — the stabilized surface pressure on the drill pipe after the well is shut in, indicating the underbalance against formation pressure.

A BHA component with blades that centralizes the drill string and controls hole deviation and bit trajectory.

A section of drill pipe made up of typically three joints (~90 ft) that is tripped as a single unit during round trips.

Pressure effects from moving the drill string: surge increases pressure (pumping fluid ahead), swab decreases pressure (pulling fluid up) and can induce a kick.

A motorized unit on the rig that rotates the drill string from above, replacing the kelly and rotary table; enables drilling with stands.

A small calibrated mud tank used to accurately monitor volume changes while tripping pipe, critical for detecting gains or losses.

Smaller-diameter pipe run inside casing to serve as the production conduit for produced fluids from the reservoir to surface.

The vertical depth of a point in the wellbore below the rotary table, projected from the measured (along-hole) depth; used for pressure calculations.

A well control technique that removes gas influx from the well without circulation by bleeding mud while maintaining constant bottom hole pressure.

The downward force applied to the drill bit through the drill collars to make the bit cut rock effectively.

A measure of the mud's resistance to initial flow under stress; high yield point improves cuttings carrying capacity but increases circulating pressure.