PE Petroleum key terms

The fraction of a rock's bulk volume that is occupied by void space, expressed as a percentage or decimal. It indicates how much fluid a reservoir rock can store.

A measure of a rock's ability to transmit fluid through its connected pore spaces, usually reported in millidarcies or darcies. Higher values mean fluid flows more easily under a given pressure gradient.

The ratio of the effective permeability of one phase at a given saturation to the rock's absolute permeability. It describes how easily oil, water, or gas flows when several phases share the pore space.

The pressure difference across the interface between two immiscible fluids in a pore, caused by interfacial tension and wetting preference. It controls fluid distribution and the height of the transition zone above a free-water level.

The pressure at which the first bubble of gas comes out of solution from oil as pressure is lowered at reservoir temperature. Below this pressure, gas evolves and oil properties change.

The volume of gas dissolved in a unit volume of oil at reservoir conditions, reported at standard surface conditions. It varies with pressure and temperature and is needed for material balance and rate calculations.

The ratio of the volume a barrel of oil occupies at reservoir conditions to the volume it occupies at stock-tank conditions. It accounts for dissolved gas and thermal expansion.

A volumetric accounting method that equates the original fluids in a reservoir to the fluids remaining plus those produced, allowing for expansion, rock and water compressibility, and water influx. It estimates hydrocarbons in place and drive indices.

The fraction of original hydrocarbons in place that can be economically produced, expressed as a percentage. It reflects drive mechanism, rock and fluid properties, well spacing, and development strategy.

The injection of water into a reservoir through injection wells to maintain pressure and displace oil toward producing wells. It is the most widely applied secondary recovery method.

The ratio of the mobility of the displacing fluid to that of the displaced fluid, where mobility is permeability divided by viscosity. Values above one favor viscous fingering and poor volumetric sweep.

A method of forecasting future production by fitting a mathematical trend such as exponential, hyperbolic, or harmonic decline to historical rate data, then extrapolating to an economic limit.

A dimensionless number representing extra pressure drop near the wellbore caused by formation damage or by stimulation, compared with an ideal undamaged well. Positive values indicate damage; negative values indicate improvement.

The density of a drilling fluid, commonly expressed in pounds per gallon or pounds per cubic foot. It sets the hydrostatic pressure that balances formation pore pressure and prevents fluid influx.

The pressure of fluids contained within the pore spaces of a formation at depth. Knowing it is essential for selecting mud weight and casing depths to avoid kicks and lost circulation.

The pressure per unit depth at which a formation will crack and begin accepting fluid. It sets the upper limit on mud weight and defines the safe drilling window between pore pressure and fracture pressure.

An unintended influx of formation fluid such as gas, oil, or water into the wellbore because the mud column's hydrostatic pressure is below pore pressure. If not controlled, it can escalate into a blowout.

A stack of large valves installed at the wellhead that can close around, seal off, or shear the drill pipe to shut in the wellbore and stop uncontrolled flow of formation fluids.

A series of steel pipes run into the wellbore and cemented in place to support the borehole wall, isolate formations, and provide a conduit for fluids. Common types are surface, intermediate, and production casing.

The placement of cement slurry in the annulus between casing and borehole wall, pumped down the casing and circulated upward, to provide zonal isolation and mechanical support for the casing.

The effective mud density that includes the additional pressure from annular friction while mud is circulating, added to the static hydrostatic pressure. It constrains drilling rate in narrow pressure windows.

The loss of drilling fluid into a formation through fractures, vugs, or highly permeable rock, so that returns at surface decrease. It lowers hydrostatic pressure and can allow a kick.

The rate at which a wellbore changes direction, usually expressed in degrees per 100 feet or per 30 meters of measured depth. High values increase torque and drag and can cause key seating.

The process of creating holes through casing, cement, and into the formation, typically using shaped-charge guns, so that reservoir fluids can enter the wellbore.

A completion technique in which sized sand or gravel is placed in the annulus around a screen to filter formation sand while allowing fluids to flow. It controls sand production in unconsolidated reservoirs.

A stimulation treatment in which fluid is pumped above the formation's breakdown pressure to create a fracture, and proppant is placed to keep the fracture open and improve flow toward the well.

A systematic method of evaluating pressure drops across each component of the production system from reservoir to separator, and finding the flow rate at which inflow matches outflow.

A curve or equation describing how the flow rate from the reservoir into a well varies with bottomhole flowing pressure. It is used to match well deliverability with lift and tubing performance.

Any mechanical or gas-injection method used to add energy to fluids in a well so they can be produced when natural reservoir pressure is insufficient to lift them to surface.

An artificial lift method in which high-pressure gas is injected into the tubing to lighten the fluid column and reduce bottomhole flowing pressure, allowing the reservoir to produce at a higher rate.

A multistage centrifugal pump run on a downhole motor and power cable, installed on the tubing to lift large volumes of fluid from moderate to deep wells.

A restriction, usually at the wellhead, used to control production rate and to hold a deliberate backpressure on the reservoir. It may be a fixed bean or an adjustable valve.

A pressure vessel that separates wellstream fluids into gas, oil, and water streams by gravity settling, often aided by internals such as baffles, weirs, or coalescing elements.

The fraction of produced liquid that is water, expressed as a percentage of total liquid volume. A rising water cut is a key indicator of reservoir and completion performance.

The assembly of valves, spools, and fittings mounted on the wellhead that controls flow from the well and provides access for operations such as injection, logging, or intervention.

A dispersion of one immiscible liquid in another, such as water droplets in crude oil, stabilized by natural surfactants. Emulsions must be broken to meet crude oil quality specifications.

A mineral deposit such as calcium carbonate or barium sulfate that precipitates from produced water and accumulates on tubulars and equipment, restricting flow and reducing heat transfer.

The practice of driving a device called a pig through a pipeline to clean it, inspect it, or separate batches of product. It helps maintain flow efficiency and pipeline integrity.

The removal of water vapor from natural gas, often by glycol absorption or a solid desiccant, to prevent hydrate formation and corrosion in pipelines and processing equipment.