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.

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.

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

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

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.

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.

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 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.

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.

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

A secondary-cementing operation in which a plug of cement is positioned at a specific point in the well and allowed to set.

The forcing of cement slurry by pressure to specified points in a well to cause seals at the points of squeeze. It is a secondary cementing method that is used to isolate a producing formation, seal off water, repair casing leaks, and so forth.

Intentional deviation of a wellbore from the vertical. Although wellbores are normally drilled vertically, it is sometimes necessary or advantageous to drill at an angle from the vertical. Controlled directional drilling makes is possible to reach subsurface areas laterally remote from the point where the bit enters the earth. It often involves the use of turbodrills, Dyna-Drills, whipstocks, or other deflecting rods.

A self-propelled floating offshore drilling unit that is a ship constructed to permit a well to e drilled from it. Although not as stable as semisubmersible, drill ships are capable of drilling exploratory wells in deep, remote waters. See floating offshore drilling rig.

An oil-recovery process which involves the injection of a solvent followed by a displacing fluid. - A method of secondary recovery of fluids from a reservoir by injection of fluids that are miscible with the reservoir fluids.

A self-propelled floating offshore drilling unit that is a ship constructed to permit a well to be drilled from it. While not as stable as Semisubmersible, drill ships are capable of drilling exploratory wells in deep, remote waters. They may have a ship hull, a catamaran hull, or a trimaran hull. See floating offshore drilling rig.

Abbreviation: perforating depth control log

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

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.

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

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

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

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.

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.

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

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.

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.

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

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

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.

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.

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

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).

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

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

A screen joint placed opposite perforations in sand control

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.

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 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.