Oil and gas glossary

Pumping acid to dissolve near-well damage or to dissolve the rock itself.

A scale of how light or heavy a crude oil or condensate is. It rises as the liquid gets lighter.

Water-bearing rock in pressure communication with the hydrocarbon column.

Adding energy so a well can produce after the reservoir can no longer lift the fluids on its own at the wanted rate.

A sucker-rod pump: a surface unit lifts and drops a rod string that drives a plunger pump at the bottom of the tubing.

The stack of valves on the wellhead that can close the well if the mud column no longer holds the formation.

The tools on the bottom of the drill string, below the drill pipe.

Pressure in the well at a stated depth, almost always opposite the reservoir or at a downhole gauge.

The pressure, at reservoir temperature, at which the first free gas comes out of an oil as the oil is depressured.

The density of the formation, grains and pore fluids together, from a density log.

The pressure difference between the non-wetting and the wetting fluid across their interface in the pores.

Steel pipe run into the well and cemented in place to hold the hole open and to isolate formations.

The bottom end of a casing string.

A restriction, usually at the wellhead, that sets the flowing wellhead pressure and therefore the rate.

The hardware and the work that make a drilled well ready to produce or inject.

Formation water that was already in the pores when the trap filled.

A forecast of future rate from the way past rate has fallen with time or with cumulative production.

The drill string held against the borehole wall by the difference between mud pressure and a lower pore pressure.

How sharply the wellbore turns, over a standard course length.

The distance from a well to the no-flow boundary of the volume it drains.

The fluid circulated down the drill string and up the annulus while drilling.

A multistage centrifugal pump run on the tubing and driven by a downhole electric motor.

Methods aimed at oil that primary depletion and a plain waterflood would leave behind.

The density of a static mud column that would exert the same pressure as the mud does while it is circulating.

The total volume a well, reservoir, or field is expected to produce over its life, including what has already been produced.

A fracture across which the rock on one side has moved relative to the other.

The pressure at reservoir depth while the well is producing.

The fraction of the pore volume that one fluid occupies.

Extra resistance to flow in the rock or the completion within a short distance of the wellbore.

Reservoir volume occupied by a fluid divided by the volume that same fluid occupies at surface conditions.

The wellbore pressure, per unit of true vertical depth, at which the formation fractures and starts to take drilling fluid.

A log of natural radioactivity along the borehole.

Artificial lift that injects gas into the tubing to lighten the column so the reservoir can flow.

The depth where a gas cap sits on the oil column.

Produced gas rate divided by produced oil rate, both at surface conditions.

A sand-control completion that places sized gravel around a screen so formation sand bridges on the gravel.

A fracture opened by pumping fluid into a zone faster than the rock can accept it, then kept open so the well can flow.

The relationship between bottomhole flowing pressure and the rate a well can deliver.

Injection rate divided by how far the injection bottomhole pressure sits above reservoir pressure.

The water saturation that further displacement by oil or gas will not reduce, at the capillary pressures that matter.

Formation fluid flowing into the well because pressure in the wellbore has fallen below the pore pressure.

Drilling fluid leaving the wellbore into the formation instead of returning to the pits.

An inventory that makes produced volumes, injected volumes, and the pressure change consistent with fluid expansion and aquifer influx.

Distance along the wellbore from the surface depth reference to a point in the well.

The smaller of the two horizontal principal stresses in the earth at a depth.

The mobility of the displacing fluid divided by the mobility of the fluid being pushed.

The density of the drilling fluid.

The thickness of reservoir that passes the cutoffs and is counted in the hydrocarbons in place.

Net thickness divided by the gross thickness of the same interval.

A porosity estimate from the hydrogen in the formation.

Finding a well's rate by matching what the reservoir can deliver to what the tubing and surface system can carry.

The vertical stress from the weight of the rocks and their fluids above a depth.

A seal between the tubing and the casing that isolates the annulus from the producing or injection interval.

A tunnel from the wellbore through casing and cement into the formation, so fluid can enter or leave.

How readily a rock lets fluid pass through it for a given viscosity and pressure gradient.

The part of a mud's flow resistance that rises in proportion to how fast the mud is sheared.

The ratio of sideways strain to lengthwise strain when a rock is loaded along one axis.

The pressure of the fluid in the pore space of the rock.

The fraction of a rock's bulk volume that is pore space rather than solid grain.

Reading permeability, skin, and reservoir limits from the way pressure changes with time after a rate change.

The liquid rate a well delivers for each unit of pressure drawdown.

Solid grains pumped into a hydraulic fracture to hold it open after treating pressure is released.

Laboratory measurement of how a reservoir fluid changes volume, phase, and viscosity with pressure and temperature.

How quickly the bit is deepening the hole.

The fraction of the oil or gas initially in place that is produced, or expected to be produced.

The effective permeability to one fluid divided by a reference permeability, usually the absolute permeability.

Oil and gas expected to be produced commercially from a stated date forward, under stated prices, costs, and a development plan.

A body of subsurface rock porous and permeable enough to store hydrocarbons and to give them up to a well.

The oil saturation left after a displacement, once oil no longer flows as a connected phase.

A log of how strongly the formation resists electrical current.

Keeping formation sand in the formation instead of in the wellbore, the tubing, and the surface kit.

A layer whose pores will not let the hydrocarbon column beneath it pass.

The fraction of the bulk rock treated as shale.

A dimensionless number from a well test that describes extra pressure drop at the sandface compared with an undamaged open hole in the same rock.

The gas, measured at standard surface conditions, dissolved in one stock-tank barrel of oil at a stated reservoir pressure and temperature.

A rock rich enough in organic matter, and buried hot enough for long enough, to have generated oil or gas.

The pressure on the mud as it is pumped into the drill string, read at the standpipe.

The pressure in the drainage volume when the well is shut in and the transients have died out, or the average pressure used for that volume.

A treatment whose purpose is a higher rate from the same reservoir, usually by cutting skin or by adding a fracture.

The volume of oil in the reservoir before production, counted as stock-tank barrels rather than reservoir barrels.

A configuration of rock that stops migrating hydrocarbons and lets them accumulate.

Pulling the drill string out of the hole, or running it back in.

The vertical distance from the depth reference on the rig down to a point in the well.

The removable pipe inside the production casing that carries produced or injected fluids.

The pressure at the top of the tubing, at the wellhead.

How strongly a fluid resists flow.

The fraction of the produced liquid that is water.

The fraction of pore volume filled with water.

The depth where the oil column gives way to water.

Injection of water to hold reservoir pressure up and to push oil toward producers.

The compressive force applied to the bit.

Keeping formation fluids from flowing to surface in an uncontrolled way, and removing a kick once one has entered.

A continuous record of a rock or fluid property against depth in a borehole.

Whether the hole stays close to bit size while it is drilled, instead of caving in or fracturing.

Which fluid preferentially coats the grain surface: water, oil, or neither cleanly.

The extra resistance a mud keeps, in the Bingham model, as the shear rate falls.

Stiffness: the axial stress needed to produce a given axial strain while the rock is still elastic.