Oil & Gas Glossary 1.0

Abbreviation: emergency shut down, an automated platform system to shut in an SCSSV and/or SSV

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

Pressure of the annular fluid on the casing at the surface when a well is shut in.

Gas that enters the wellbore when the mud pump is shut down and pipe is being pulled from the wellbore. The gas may enter because of the reduction in bottomhole pressure when the pump is shut down, because of swabbing, or because of both.

Pressure of the annular fluid on the casing at the surface when a well is shut in

The average pressure within the reservoir at any given time. Determination of this value is best made by bottomhole pressure measurements with adequate shut-in time. If a shut-in period long enough for the reservoir pressure to stabilize is impractical, then various techniques of analysis by pressure buildup or drawdown tests are available to determine static reservoir pressure.

A test that measures the reservoir pressure of the well, obtained at a specific depth or at the midpoint of the producing zone. A flowing bottomhole pressure test measures pressure while the well continues to flow; a shut-in bottomhole pressure test measures pressure after the well has been shut in for a specified period of time. See bottomhole pressure, bottomhole pressure gauge.

Pressure at the top of a well when it is shut in.

A bottomhole pressure test that measures pressure after the well has been shut in for a specified period of time. See bottomhole pressure test.

Said of a well when it is shut in or temporarily not able to produce.

1. to shut in a well temporarily that is capable of producing oil or gas.

A well capable of producing oil or gas, but temporarily shut in.

A large valve used to shut in a well.

Abbreviation: shut-in casing pressure

To shut off lower formation in a well bore.

To close values on a well so that it stops producing; said of a well on which the valves are closed.

Abbreviation: shut-in drill pipe pressure, used in drilling reports.

1. the process of raising the drill stem out of the wellbore when the well is shut in on a kick.

A hinged closure mechanism operating in a pivot manner, used to shut off tubing flow.

Balls made of nylon, hard rubber, or both and used to shut off perforations through which excessive fluid is being lost.

An integral part of a blowout preventer, which serves as the closing element on an open hole. Its ends do not fit around the drill pipe but seal against each other and shut off the space below completely. See ram

Temporarily shut in but not plugged.

Pressure at the bottom of a well that is shut in.

A sleeve designed to shut off tubing-to-annulus flow should the sliding sleeve become inoperative.

1. a condition sometimes encountered in a pumping well when dissolved gas, released from solution during the upstroke of the plunger, appears as free gas between the valves. If the gas pressure is sufficient, the standing valve is locked shut, and no fluid enter the tubing.

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 device used to direct fluid flowing from a well away from the drilling rig. When a kick is encountered at shallow depths, the well often cannot be shut in safely; therefore, a diverter is used to allow the well to flow through a side outlet (a diverter line).

A poppet spring-loaded subsurface valve run in on wireline, landed in a profile, to shut the well if injection ceases.

The pressure at the bottom of a well when the surface valves on the well are completely closed. It is caused by formation fluids at the bottom of the well.

1. the process of lowering the drill stem into the wellbore when the well is shut in on a kick and when the weight of the drill stem is sufficient to overcome the force of well pressure.

A mechanically operated (tubing rotation) valve u used to shut off formation pressure above a packer, thus testing all connections form the packer to the tree.

A method of determining the amount of pressure that is allowed to appear on the casing pressure gauge as a kick is circulated out of a well. In general, it is determined by slowly pumping mud into the well while it is shut in and observing the pressure at which the formation begins to take mud.

A liquid, usually salt water or oil, but sometimes mud, used in a well when a packer is between the tubing and the casing. Packer fluid must be heavy enough to shut off the pressure of the formation being produced, must not stiffen or settle out of suspension over long periods of time, and must be noncorrosive.

The level to which fluid rises in a well when the well is shut in.

A special device placed in a string of tubing that can be operated by a wireline tool to open or close orifices to permit circulation between the tubing and the annulus. It may also be used to open or shut off production from various intervals in a well. Also called circulation sleeve.

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.

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 device that controls the rate of flow of fluid in a line or opens or shuts off the flow of fluid completely. When open, the sealing surface of the valve is moved away from a seat; when closed, the sealing surface contacts the seat to shut off flow. The direction of movement of the valve is usually perpendicular to the seat. Popper valves are used extensively as pneumatic (air) controls on drilling rigs and as intake and exhausts valves in most internal-combustion engines.

A formation fluid sampling device, actually run on conductor line rather than wireline, that also logs flow and shut-in pressure in rock near the borehole. A spring mechanism holds a pad firmly against the sidewall while a piston creates a vacuum in a test chamber. Formation fluids enter the tes5t chamber through a valve in the pad. A recorder logs the rate at which the test chamber is filled. Fluids may also be drawn to fill a sampling chamber. Wireline formation tests may be done any number of times during one tip in the hole, so they are very useful in formation testing.