Oil & Gas Glossary 1.0

A manifold system of valves, usually situated at the power source, which may be operated manually (or by remote control) to direct pressurized fluid to closing devices at wellhead.

Prevention of formation fluid flow by maintaining a hydrostatic pressure equal to or greater than formation pressure

Repressuring of an oil-field to maintain original pressure. The use of water flooding or natural gas recycling during primary recovery to provide additional formation pressure and displacement energy that can supplement and conserve natural reservoir drives. Although commonly begun during primary production, pressure maintenance methods are often considered to be a form of enhanced oil recovery.

The control valves, pressure gauges, and chokes assembled at the top of a well to control the flow of oil and gas after the well has been drilled and completed.

1. a pipe connection around a valve or other control mechanism that is installed to permit passage of fluid through the line while adjustments or repairs are being made on the control.

A system of controls, convenient to the driller, which can be used selectively to actuate valves at the master control panel.

A well drilled near and deflected into a well that is out of control, making it possible to bring the wild well under control. See wild well.

A station containing equipment to control and regulate operations in the field.

The section of a drawworks drum grooved for angle control and in which the wire rope crosses over to start a new wrap. Also called an angle-control section.

A generic term, originally a trademark name, used to describe a stage tool, used in selective zone primary cementing.

A rubber plug used in primary cementing operations to displace cement slurry from the casing into the borehole annulus.

The application of a liquid slurry of cement and water to various points inside or outside the casing. See primary cementing, secondary cementing.

The first stage of oil production in which natural reservoir drives are used to recover oil, although some form of artificial lift may be required to exploit declining reservoir drives.

The cementing operation that takes place immediately after the casing has been run into the hole. It provides a protective sheath around the casing, segregates the producing formation, and prevents the undesirable migration of fluids.

A worker on a drilling or workover rig, subordinate to the driller, whose primary work station is on the rig floor. On rotary drilling rigs, there are at least two and usually three or more rotary helpers on each crew. Sometimes called floor man, roughneck, or rig crewman.

Abbreviation: perforating depth control log

(2) to control the quality of the natural gas to be marketed.

Any cementing operation after the primary cementing operation. Secondary cementing includes a plug-back job, in which a plug of cement is positioned at a specific point in the well and allowed to set. Wells are plugged to shut off bottom water or to reduce the depth of the well for other reasons.

A surface device used in pressure control for slickline.

The foundation on which the derrick or mast and usually the drawworks sit. It contains space for storage and well-control equipment.

A well that has blown out of control and from which oil, water, or gas is escaping with great force to the surface. Also called a gusher.

Usually a single well drilled offshore by a mobile offshore drilling unit to produce hydrocarbons from the outer fringes of a reservoir that cannot be produced by primary development wells drilled from a permanent drilling structure (as a platform rig). Sometimes, several satellite wells will be drilled to exploit marginal reservoirs and avoid the enormous expense of erecting a platform.

A method of improved recovery in which water is injected into a reservoir to remove additional quantities of oil that have been left behind after primary recovery. Waterflooding usually involves the injection of water through wells specially set up for water injection and the removal of water and oil from production wells drilled adjacent to the injection wells.

A surface device used in slickline operations to keep the line lubricated and provide grease for pressure control

A surface device used in slickline operations to keep the line lubricated and provide grease for pressure control

The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.

A synthetic high-molecular-weight polymer of acrylonitrile used primarily as a fluid loss control agent

Part of a computer system that contains manual controls--switches and devices to start, stop, measure, monitor or signal what is taking place.

A string of tubing used to produce the well, providing well control and energy conservation.

Commonly referred to as snubbing; running of tool and/or pulling of tubing under well pressure.

A device with a restricted opening placed in the lower end of the tubing to control the rate of flow. See choke.

To control a blowout by placing a very strong valve on the wellhead. See blowout.

A system whereby the end devices in the field (switches, valves, gauges, alarms, etc.) are controlled by a program placed in the computer.

A small hydraulic line used to communicate fluid from the surface to a downhole tool, such as a subsurface safety valve.

In well-control operations, closing the BOP's with the choke and HCR, or fail-safe, valves open. Compare hard shut-in.

Well-control fluid that has been reduced in density or unit weight as a result of entrainment of less-dense formation fluids or air

A flow-control device employing a ball with a rotating mechanism to open or close the tubing medium.

An organization whose function is to establish standards and recommended practices for the field of corrosion control.

In a well-control operation, closing the BOP without first opening an alternate flow path up the choke line. When the BOP is closed, pressure in the annulus cannot be read on the casing pressure gauge.

An extension from the blowout preventer assembly used to direct control the flow of well fluids from the annulus to the choke.

Low-solids fluid or drilling mud used when a well is being completed. it is selected not only for its ability to control formation pressure, but also for the properties that minimize formation damage.

Materials added to the mud in varying amounts to control or prevent lost circulation. Classified as fiber, flake, or granular.

Materials added to the mud in varying amounts to control or prevent lost circulation. Classified as fiber, flake, or granular.

An extension of a retrievable tool, i.e., a retrievable bridge plug, used to set and release the tool.

A variation of squeeze cementing for wells with two producing zones in which (1) the upper fluid sand is perforated; (2) tubing is run with a packer, and the packer is set between the two perforated intervals; (3) water is circulated between the two zones to remove as much mud as possible from the channel; (4) cement is pumped through the channel and circulated; (5) the packer is released and picked up above the upper perforation, a low squeeze pressure is applied, and the excess cement is circulated out. The process is applicable where there is communication behind the pipe between the two producing zones because of channeling of the primary cement or where there is essentially no cement in the annulus.

1. a large valve located on the Christmas tree and used to control the flow of oil and gas from a well. Also called master gate. 2. the blind or blank rams of a blowout preventer (obsolete).

A permanent packer, drillable in nature, capable of withstanding extreme working pressures, for remedial work. It has a positive flow-control valve built in.

The assembly of pumps, valves, lines, accumulators, and other items necessary to open and close the blowout preventer equipment. Also called closing unit.

Controls, usually located near the driller's position on the rig floor, that are manipulated to open and close the blowout preventers. See blowout preventer.

A screen joint placed opposite perforations in sand control

The force exerted by a body of fluid at rest. It increases directly with the density and the depth of the fluid and is expressed in pounds per square inch or kilopascals. The hydrostatic pressure of fresh water is 0.433 pounds per square inch per foot of depth (9.792 kilopascals per meter). In drilling, the term refers to the pressure exerted by the drilling fluid in the wellbore. In a water drive field, the term refers to the pressure that may furnish the primary energy for production.

2. to dose the blowout preventers on a well to control a kick. The blowout preventers close off the annulus so that pressure from below cannot flow to the surface.

Any method by which large amounts of sand in a sandy formation are prevented from entering the wellbore. Sand in the wellbore can cause plugging and premature wear of well equipment. See gravel pack, sand consolidation, screen liner.

A set of controls, usually placed on the rig floor, that is manipulated to control the amount of drilling fluid being circulated through the choke manifold. This procedure is necessary when a kick is being circulated out of a well. See choke manifold.

An arrangement of piping and special valves, called chokes. In drilling, mud is circulated through a choke manifold when the blowout preventers are closed. In well testing, a choke manifold attached to the wellhead allows flow and pressure control for test components downstream.

A method of killing a well in which the mud level in the pits is held constant while the choke size is reduced and the pump speed slowed. It is not effective, and therefore, is not recommended, because casing pressure increases to the point at which the formation fractures or casing ruptures, and control of the well is lost.

A part of the brake mechanism consisting of a flexible steel band lined with a material that grips a drum when tightened. On a drilling rig, the brake band acts on the flanges of the drawworks drum to control the lowering of the traveling block and its load of drill pipe, casing, or tubing.

A device used to control the rate of flow in a line to open or shut off a line completely, or to serve as an automatic or semiautomatic safety device. Those used extensively include the check valve, gate valve, globe valve, needle valve, plug valve, and pressure relief valve.

A method of improved oil recovery in which chemicals dissolved in water are pumped into a reservoir through injection wells to mobilize off left behind after primary or secondary recovery and to move it toward production wells. The chemical solution includes surfactants or surfactant-forming chemicals that reduce the interfacial and capillary forces between oil and water, releasing the oil and carrying it out of the pores where it has been trapped. The solution may also contain cosurfactants to match the viscosity of the solution to that of the oil to stabilize the solution and to prevent its absorption by reservoir rock. An electrolyte is often added to aid in adjusting viscosity. Injection of the chemical solution is followed by a slug of water thickened with a polymer, which pushes the released oil through the reservoir, decreases the effective permeability of established channels so that new channels are opened, and serves as a mobility buffer between the chemical solution and the final injection of water.

A globe valve that contains a sharp, pointed, needle-like plug that is driven into and out of a cone-shaped seat to control accurately a relatively small rate of fluid flow. In a fuel injector, the fuel pressure forces the needle valve off its seat to allow injection.

A special type of nuclear log that measures the depth of each casing collar. Knowing the depth of the collars makes it easy to determine the exact depth of the formation to be perforated by correlating casing-collar depth with formation depth.

An item of production equipment used to separate liquid components of the well stream from gaseous elements. Separators are either vertical or horizontal and either cylindrical or spherical in shape. Separation is accomplished principally by gravity, the heavier liquids falling to the bottom and the gas rising to the top. A float valve or other liquid-level control regulates the level of oil in the bottom of the separator.

A device that stores hydraulic fluid under pressure in special containers and provides a method to open and close the blowout preventers quickly and reliably. Usually, compressed air and hydraulic pressure provide the opening and closing force in the unit. See blowout preventer.

A method of killing a well that has kicked, in which the choke size is adjusted to maintain a constant casing pressure. This method does not work unless the kick is all or nearly all salt water. if the kick is gas, this method will not maintain a constant bottomhole pressure, because gas expands as it rises in the annulus. In any case, it is not a recommended well-control procedure.

A workover performed with a continuous steel tube, normally 3/4 inch to 1 inch outside diameter, which is run into the well in one piece inside the normal tubing. Lengths of the tubing up to 16,000 feet are stored on the surface on a reel in a manner similar to that used for wireline. The unit is rigged up over the wellhead. The tubing is injected through a control head that seals off the tubing and makes a pressure-tight connection. A unique feature of the unit is that it allows continuous circulation while it is being lowered into the hole.