IWCF WIPC Level 2 key terms

The set of operations and equipment that turns a drilled hole into a producing or injecting well, including casing, tubing, packers, and the wellhead. It links the reservoir to surface facilities.

The assembled tubular system run into the well to convey fluids, including tubing joints, packers, flow-control devices, and accessories. It is designed for the well's pressure, temperature, and corrosion conditions.

Pipe installed inside casing that carries produced fluids to surface or injects fluids into the reservoir. Its size and grade are chosen to suit flow rate, pressure, and corrosion service.

Steel pipe cemented into the wellbore to seal formations, prevent collapse, and provide a pressure barrier. Multiple casing strings of decreasing size are run as the well is drilled deeper.

A downhole sealing device that isolates the annulus between tubing and casing, directing flow and protecting casing from pressure or corrosive fluids. It may be retrievable or permanent.

The space between two concentric tubulars, most commonly between tubing and casing, or between casing strings. It can be used for circulation, monitoring, or gas lift.

The surface equipment at the top of the well that supports casing and tubing and provides pressure sealing and access points. It is the foundation for the christmas tree.

An assembly of valves and fittings on the wellhead that controls flow from the well and provides access for intervention. It includes master valves, wing valves, and a swab valve.

A primary valve on the christmas tree that isolates the well from surface flowlines and intervention equipment. It is normally the first barrier operated when securing the well.

A pressure-containing element that prevents uncontrolled flow of well fluids, such as a closed valve, cemented casing, or packer. Barriers are classified as primary or secondary and verified before operations.

The practice of managing formation pressure with hydrostatic pressure and barriers to prevent kicks, blowouts, and lost circulation. It relies on monitoring pit volume, flow, and pressure.

An unintended influx of formation fluid into the wellbore caused by formation pressure exceeding the hydrostatic pressure of the column. It must be detected early and circulated out under controlled conditions.

The pressure exerted by a column of fluid at a given depth, calculated from fluid density and true vertical depth. It is the primary means of balancing formation pressure.

The pressure of fluids within the pore spaces of a rock at a given depth. Knowing it is essential for selecting mud weight and designing barriers for completion and intervention work.

The stabilized pressure measured at surface after closing the well in, recorded as casing pressure and tubing pressure. It is used to calculate formation pressure and kill fluid requirements.

A set of blowout preventers and associated valves installed at the wellhead to close the wellbore in an emergency. It provides annular and ram sealing for different operations.

A blowout preventer with a rubber sealing element that closes around pipe of various sizes or seals an open hole. It is typically the first BOP used to control flow.

A blowout preventer ram that closes on a specific pipe size to seal the annulus while pipe is in the hole. It cannot seal an open hole and must match the pipe diameter.

A blowout preventer ram that closes across an open wellbore with no pipe present, sealing the full bore. Blind-shear rams can also cut pipe while sealing.

The process of placing cement slurry in the annulus to support casing, isolate zones, and provide a hydraulic seal. It is a key barrier in completion and abandonment operations.

The creation of holes through casing and cement into the reservoir to allow fluids to flow. It is commonly done with shaped-charge guns run on wireline or tubing.

Techniques used to prevent formation sand from entering the wellbore and damaging equipment. Common methods include gravel packing, screens, and resin consolidation.

A sand-control completion where sized gravel is placed around a screen in the annulus to filter formation sand. It is common in unconsolidated reservoirs with high production rates.

A slotted or wire-wrapped tubular placed in the completion to retain formation sand while allowing fluids to pass. It is often combined with gravel packing.

A continuous length of flexible steel pipe spooled on a reel, used for well intervention without making up joints. It enables circulation, milling, logging, and stimulation in live wells.

The coiled tubing unit component that grips and pushes or pulls the tubing into and out of the well against pressure. It works with the stripper and BOP to maintain well control.

A sealing element in coiled tubing and snubbing operations that seals around moving pipe to contain well pressure. It is a dynamic barrier that must be monitored for wear.

A method of conveying tools into a well on a wire or cable, either slickline for mechanical work or electric line for powered tools. It is used for logging, perforating, and setting plugs.

A small-diameter solid wire used to run mechanical tools such as gauges, plugs, and valves into a well. It provides no electrical power or data transmission.

A multi-strand wireline that is stronger than slickline and can conduct electricity for powered tools. It is used for heavy-duty logging, perforating, and fishing operations.

A pressure-rated tubular section above the wellhead that allows wireline or coiled tubing tools to be inserted or removed while the well is live. Its length must exceed the tool string.

The insertion or removal of pipe into a live, pressured well using a snubbing unit when well pressure would otherwise push the pipe out. It is used for workovers and completions under pressure.

A specialized rig with hydraulic jacks and slips that forces pipe into or out of a well against pressure. It includes a BOP stack, stripper, and work basket.

Any operation performed on a well after completion to maintain, restore, or improve production, such as logging, stimulation, or workover. It may be done with wireline, coiled tubing, or snubbing.

The wellhead system installed on the seabed that supports casing and provides a connection point for the subsea BOP and tree. It is accessed by a marine riser or intervention vessel.

A valve assembly installed on a subsea wellhead to control production or injection flow. It may be vertical or horizontal and is operated remotely from surface.

A large tubular conduit connecting the subsea wellhead or BOP to a floating vessel, providing a path for tools and fluids. It must accommodate vessel motion and pressure loads.

A dense fluid pumped into a well to balance formation pressure and stop a kick or control the well. Its density is selected from calculated formation pressure and true vertical depth.

A downhole or surface component such as a valve, choke, or sliding sleeve that regulates fluid flow rate or direction. It allows zonal isolation and production management.

The fluid placed in the annulus above a packer to provide hydrostatic pressure and protect casing. It is selected for density, corrosion inhibition, and compatibility with formation fluids.