Oil & Gas Glossary 1.0

Abbreviation: polished bore receptacle, a section in the casing string to facilitate landing of the production tubing (casing).

A tube extending the effective packer seal bore; used where excessive tubing expansion or contraction is anticipated.

A casing sub containing a seal bore and a left-handed thread, run as a crossover between casing sizes, to provide a tubing anchor.

Tubular components attached to the bottom of a packer to extend it bore.

Extensions of the producing string with seals to travel within a packer bore and/or extensions.

Term to describe the passage entry of seal assemblies into a packer seal bore not locking into place.

Sealing members at the production tubing for landing inside the packer's seal bore.

A piece of downhole equipment, consisting of a sealing device, a holding or setting device, and an inside passage for fluids, used to block the flow of fluids through the annular space between the tubing and the wall of the wellbore by sealing off the space between them. It is usually made up in the tubing string some distance above the producing zone. A packing element expands to prevent fluid flow except through the inside bore of the packer and into the tubing. Packers are classified according to configuration, use, and method of setting and whether or not they are retrievable (that is, whether they can be removed when necessary, or whether they must be milled or drilled out and thus destroyed).

A packer equipped with friction blocks or drag springs and slips and designed so that rotation of the pipe unlatches the slips. The friction springs prevent the slips from turning with the pipe and assist in advancing the slips up a tapered sleeve to engage the wail of the outside pipe as weight is put on the packer. Also called a wall-hook packer. See packer.

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.

A squeeze cementing method in which a packer is set to form a seal between the working string (the pipe down which cement is pumped) and the casing. Another packer or a cement plug is set below the point to be squeeze-cemented. By setting packers, the squeeze point is isolated from the rest of the well. See packer, squeeze cementing.

A sub with a ball seat run on top of a hydraulically set packer to set the packer.

A special-purpose packer placed in the casing to permit a sidetrack operation.

An accessory or integral part of a packer used to limit the packer's upward movement under pressure.

A drillable service packer, a retainer.

A type of gravel pack where the wells production packer is removed and a service packer is run in with the gravel pack assembly. After packing, the service tool is retrieved and the production packer rerun.

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.

Spring-loaded buttons on a packer that provide friction with casing to retard movement of one section of a packer while another section rotates for setting.

A type of packer used for open-hole work, with inflatable packing elements

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

Any packer designed to make a seal between the tubing and the casing during production

A packer used for the well completion method of gravel packing.

Clogged by sand entering the well bore with the oil.

To shut off lower formation in a well bore.

The lowering of pipe or tubing into the bore of a downhole tool.

Two packers separated by a spacer of variable length. A straddle packer may be used to isolate sections of open hole to be treated or tested or to isolate certain areas of perforated casing from the rest of the perforated section.

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.

To bore a hole in the earth, usually to find and remove subsurface formation fluids such as oil and gas.

Application of hydraulic pressure to the reservoir formation to create fractures through which oil or gas may move to the well bore.

A sub with a glass blockage in the bore, used to isolate a surge chamber in gravel packing or perforation cleaning operations.

A compression-set packer

A component of a packer to which the tubing is connected.

The area above a packer between casing ID and tubing OD

A special tool with a rubber packer or lead seal that is used to repair casing. When casing is damaged downhole, a cut is made below the damaged casing, the damaged casing and the casing above it are pulled from the well, and the damaged casing is removed from the casing string. The tool is made up and lowered into the well on the casing until it engages the top of the casing that remains in the well, and a rubber packer or lead seal in the tool forms a seal with the casing that is in the well. The casing-patch tool is an over-shot-like device and is sometimes called a casing overshot.

The conventional method of formation testing. The basic drill stem test tool consists of a packer or packers, valve or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on the drill string to the zone to be tested. The packer or packers are set to isolate the zone from the drilling fluid column. The valves or ports are then opened to allow for formation flow while the recorders chart static pressures. A sampling chamber traps dean formation fluids at the end of the test. Analysis of the pressure charts is an important part of formation testing.

A generic term to describe a retrievable service packer.

(v) to place a packer in the wellbore and activate it so that it forms a seal between the tubing and the casing.

A component of a downhole tool, such as a packer, used to wedge slips into the casing wall.

An emergency mechanism component enabling the retrieval of a packer (or tubing) if stuck.

A cutoff pup joint below a packer used as a fluid entry device and/or seal assemblies guide

Position the correct number of feet or joints of pipe from the packer to the surface tree, or from the rig floor to the stack.

To take rams out of a blowout preventer and replace them with rams of a different size or type. When the size of a drill pipe is changed, the size of the pipe rams must be changed to ensure that they seal around the pipe when closed (unless variable-bore pipe rams are in use).

The set of dense rubber, washer-shaped pieces encircling a packer, which are designed to expand against casing or formation face to seal off the annulus.

A bradenhead pack; no packer, very limited pack pressure capability.

A retrievable or drillable packer in which sufficient pipe weight is not available to set the tool in compression.

An accessory employed above a packer, to permit annulus-to-tubing circulation or vice versa.

A squeeze cement job with open perfs above the packer.

A device made up in the drill stem and lowered into the well to allow the casing and blowout preventers to b pressure-tested. The sealing device is cup-shaped and is therefore called a cup.

1. a pipe run in a well blow a packer.

A device employed with a packer to surge, or clean, open perforations; also called surge disk.

A temporary plug set of a PSA, landed in a production packer to convert it to a bridge plug.

A device that holds the lower end of a tubing string in place by means of slips, used to prevent tubing movement when no packer is present.

A fluid-pressure test of the casing. Also called a cup test.

A heavy-mandrel service squeeze tool with on-off tool used in drilling operations during storm interruptions.

A device to provide running the tubing dry with a packer released by elevating tubing pressure, thereby opening the tubing to formation pressure.

See packer test.

The tool man; a packer hand; a service company hand.

A single well that produces from two separate formation at the same time. Production from each zone is segregated by running two tubing strings with packers inside the single string of production casing, or by running one tubing string with a packer through one zone while the other is produced through the annulus. In a miniaturized dual completion, two separate 4 1/2-inch or smaller casing strings are run and cemented in the same wellbore.

A method of stimulating production by opening new flow channels in the rock surrounding a production well. Often call a frac job. Under extremely high hydraulic pressure, a fluid (such as distillate, diesel fuel, crude oil, dilute hydrochloric acid, water, or kerosene) is pumped downward through production tubing or drill pipe and forced out below a packer or between two packers. The pressure causes cracks to open in the formation, and the fluid penetrates the formation through the cracks. Sand grains, aluminum pellets, walnut shells, or similar materials (propping agents) are carried in suspension by the fluid into the cracks. When the pressure is released at the surface, the fracturing fluid returns to the well. The cracks partially close on the pellets, leaving channels for oil to flow around them to the well. See explosive fracturing, hydraulic fracturing.