IWCF Glossary

The first closable valve in the production flow path of an HXT. The PMV is located at the side of the tubing hanger. It is remotely opened and fail-safe close.

A component used to isolate the annulus and secure the bottom of the production tubing. Usually a permanent packer that must be milled out to be removed. Also known as ‘completion packer’.

A vessel that knocks out unwanted solids and fluids from the hydrocarbon flow stream before they enter into the production system.

A remotely opened and fail-safe close valve in the production flow path of Xmas Tree. The PWV is located outboard (downstream) of the master valve(s) to provide a well barrier.

The rate at which a variable speed pump is running, usually expressed as the number of strokes per minute for a positive displacement pump. Also known as ‘pump speed’.

A contingency in snubbing operations. If the BHA check valves fail, the pump-down plug can be pumped down the workstring to land and latch into a nipple profile to prevent well fluids flowing up the workstring.

Pipe or tubing that is shorter than standard joint length.

A set of coiled tubing BOPs that incorporate blind rams, shear rams, slip rams and pipe rams.

PCE pipe connections that are made up by hand and use an ‘o ring’ seal.

A type of coiled tubing stripper that is energised with opposing rams. Stripper elements can be replaced when coiled tubing is in the well.

A light located on a remote BOP control panel that indicates the position of a 3-position/ 4-way valve associated with the selected ram-type BOP.

A device designed to keep the rams of a BOP in the closed position.

Common term for drilling rate, usually expressed in units of ft/hour or m/hour.

Source: API STD 65:2

Maximum internal pressure that equipment is designed to contain or control under normal operating conditions. Also known as ‘rated pressure’.

Source: API SPEC 16D

The actual pressure exiting the regulator in the subsea BOP control system. The pressure value is transmitted to surface (readback pressure gauge).

A valve that isolates the coiled tubing reel from the surface pipework.

Device that is built into a hydraulic or pneumatic system to relieve (dump) any excess pressure.

Source: API SPEC 16D

An unmanned vehicle for offshore subsea use.

Source: API RP 59

An unmanned vehicle for offshore subsea use.

Source: API RP 59

1. Reservoir (rock) is a subsurface formation with sufficient porosity and permeability to store, preserve and transmit formation fluids. Usually this refers to sedimentary rock covered by impermeable capping formation.
2. A storage and a source of fluid supply. For example, storage tank for BOP control system fluid

Source: API SPEC 16D

The fluid contained within the porous or fractured rock formations, which could be oil, gas, water, or any combination of these.

The pressure at the top perforation or top of the reservoir.

A type of packer that be easily run and retrieved. Unlike permanent packers, retrievable packers are designed to be removed or repositioned once their function has been completed.

Pumping fluids down the annulus, taking returns back up the drillpipe, completion tubing, workstring or coiled tubing.

The study of the flow of matter, primarily in a liquid or gas state. Drilling fluid rheology is adjusted by the addition of chemicals or dilution to maintain the required pumping characteristics.

The work area, located within the base of the derrick, in which the rig crew conducts operations related to the construction or repair of a well.

A metal seal used in flanged connections between pipes, valves, or fittings. They are typically circular and are placed between two flange faces to create a seal when the flanges are bolted together.

A ring groove is a closely dimensioned groove cut into the face of a pipe flange. Together with a gasket, a groove helps create a seal between parts.

The additional fluid density added to drilling fluid density that allows bottomhole pressure (BHP) to remain unchanged as a riser is removed.

Bushing that rotationally connects the rotary table to the drillstring kelly bar, the top of which is commonly used as vertical reference for the drill floor.

Source: API RP 16Q

A device through which passes the bit and drill string and that transmits rotational action to the kelly. Normally located in the centre of the drill floor.

Source: API RP 59

The assembly on a coiled tubing reel that connects the pumping units with the coiled tubing reel during deployment. Also known as ‘swivel’.

The process of removing the drillstring from the wellbore and running it back in the hole, usually to the same depth.

Extra overbalance applied to compensate for any uncertainties. This aims to avoid underbalance.

The secondary barrier is a second well barrier that prevents flow from a source.

Well control relying on BOP components, well control methods, and the remaining hydrostatic pressure within the well.

A casing check valve that is held in the open position to allow drilling fluid to enter the interior of casing as it is run in the hole, eliminating the need to fill the casing from the top. Can be conventional flapper type or dart activated. Also known as ‘auto-fill float’.

A shale shaker is part of the solids control equipment used to remove cutting from drilling fluid returns. It is a vibrating unit in to which shake shaker screens are fitted, that act as a sieve, separating large solids and cuttings from fluid.

A meshed sieve that separates and filters out solid particles from the drilling fluid. See ‘Shale shaker’.

Gas pockets or entrapped gas below impermeable layers at shallow depths. It is generally encountered in well sections before installing the BOP.

Source: ISO:19905 – 1:202

A BOP that will cut pipe and provide a pressure seal (a combination of a shear ram and a blind ram). It has cutting and sealing limitations depending on ram design.

A tool that can cut tubing or wireline.

The stabilised annulus pressure measured at surface of a shut-in well.

The stabilised drillpipe pressure measured at surface of a shut-in well.

The steps performed to secure a well safely after the detection of flow.

The pressure at the Xmas Tree when the well is not flowing. Also known as ‘closed in tubing head pressure (CITHP)’ or ‘shut-in wellhead pressure (SIWHP)’ .

A valve with two or more supply ports and only one outlet port. Note: When fluid is flowing through one of the supply ports the internal shuttle seals off the other inlet port(s) and allows flow to the outlet port only.

Source: API SPEC 16D

A type of coiled tubing stripper that provides a way to replace the stripper element when coiled tubing is in the well.

Valves located on the outlets of the BOP or wellhead spools. When on the BOP stack, they are normally the connection to the choke and kill lines.

A completion component with an off-set pocket. This allows the installation of flow devices that communicate with the annulus but does not restrict access through the completion. When a gas-lift valve is installed in the side pocket, it is known as a ‘gas-lift mandrel’.

Operations that occur when two or more potentially conflicting activities are being executed in the same location at the same time.

Single strand wireline that is used to deploy tools and equipment in and out of the well.

A BOP configured with blind rams that close and seal around slickline.

A device within a completion that can be opened or closed to provide a communication path into the ‘A’ annulus.

The process where new drilling line is unspooled from the storage reel and slipped through the crown block and traveling block sheaves and drawworks spool.

A BOP component that when functioned will grip and hold tubulars.

A quantity of fluid that has a greater density than the circulated fluid within a well, intended to increase hydrostatic pressure within a tubular and lower the fluid level within it so that the removal of the tubular from the well can be done ‘dry’.

Running or pulling a closed end workstring or coiled tubing into or from a well when the well pressure is greater than the weight of the workstring (pipe light).

The process of positioning the drillstring to ensure correct placement of tool joints and certain drillstring components so that BOPs will not close against a tool joint.

The 90-degree shoulder of a device used to connect threaded tubulars (a collar).

A full-opening safety valve (FOSV) used to close off the workstring when there is flow observed. The internal diameter must be at least as large as the workstring internal diameter. Also known as ‘stabbing valve’.

The connected pipe segments stored vertically within the derrick.

A vertical pipe which joins the rotary hose to the circulating system.

A fluid injected into the reservoir designed to help increase well productivity.

An element that seals around coiled tubing or a workstring during live well deployment. The stripper allows the movement of the tubular without allowing the escape of hydrocarbons to atmosphere.

The assembly used in snubbing operations when there is low well pressure. Positioned at the top of the BOP stack. The workstring is deployed through the stripper bowl. The stripper element (or elastomer, packer, rubber) within the stripper bowl provides the seal.

The consumable sealing component in a stripper assembly that conforms to the outside diameter of a tubular or wireline while moving into or out of a well to create a seal. Also known as a ‘stripper elastomer’, ‘stripper element’.

The process of running a tubular workstring into or out of the well under pressure when the weight of the workstring is sufficient to overcome the force of well pressure.

An exercise to ensure the rig floor crew knows the correct procedures and equipment operation to lower pipe into or pull pipe out of a pressurised well through a closed BOP.

Similar to a trip sheet, it is used to predict expected pressures and bleed volumes during stripping operations.

A tank used during stripping operations to accurately measure the fluid volume bled off at the choke manifold.

A device designed to seal around slickline to contain well fluids within the pressure control equipment (PCE) during intervention operations.

The valves used in subsea BOP equipment. When operated by pilot pressure they direct the flow of the regulated hydraulic fluid to one side of the BOP, valve or connector operating piston and vent the hydraulic fluid from the other side of the piston to sea.

One of two assemblies of subsea valves and regulators that direct hydraulic control pressure and operating fluid to the appropriate BOP function. Also known as a ‘subsea pod’. There are two pods that are differentiated by colour, yellow and blue.

A remotely-controlled wireline lubricator system installed onto the subsea Xmas Tree at the seabed for riserless openwater wireline interventions from Light Well Intervention Vessels.

Part of the SSTTA, which isolates the well from the TBIRS with or without WL and coiled tubing present.

Source: API STD 17G

A device installed within a completion that will isolate the well below surface in an emergency.

The part of the well from the bottom perforation to total depth (TD).

The first large diameter pipe that is set, cemented, and pressure tested, which then enables the installation of the BOP stack.

The surface flow head (SFH) or surface test tree (STT) is a well barrier element installed at the top of the TBIRS or OWIRS that mimics a vertical Xmas Tree. It has actuated and fail-safe isolation valves, flow and kill side outlets and swab valve access for wireline or CT. It is suspended from the top drive using long bails or a coiled tubing lift frame. A dualbore SFT is used when a dualbore TBIRS or dualbore OWIRS is being used with a dualbore subsea Xmas Tree.

The pressure at surface that initiates formation breakdown.

Pressure required to move fluid from the pump to the drillstring at a given flow rate.

Same as SFH. The SFH or STT is a well barrier element installed at the top of the TBIRS or OWIRS that mimics a vertical Xmas Tree. It has actuated and fail-safe isolation valves, flow and kill side outlets and swab valve access for wireline or CT. It is suspended from the top drive using long bails or a coiled tubing lift frame. A dualbore SFT is used when a dualbore TBIRS or dualbore OWIRS is being used with a dualbore subsea Xmas Tree.

A rapid increase in pressure downhole that occurs when drill stem is lowered too fast or when the mud pump is brought up to speed after starting. Also known as ‘surge pressure’.

Source: API RP 59

The cover for the access into the well at the top of the Xmas Tree. Also known as ‘tree cap’.

The hydrostatic pressure reduction value during the upward movement of tubulars and/or tools at a given speed.

The uppermost inline valve of a Xmas Tree. This valve allows entry into the well for intervention tools.

Reducing the hydrostatic pressure in the wellbore during the upward movement of tubulars and/or tools.

Source: API STD 53

A workstring that consists of two or more sizes or weights of tubulars, with the larger size at the top.

A telescopic device located at the top of a marine riser in a subsea BOP application that allows for continuous changes in riser length due to vessel movement while maintaining a fluid flow path to the surface. Also known as ‘slip joint’ or ‘telescopic joint’.

An auxiliary gate added to the Xmas Tree to use as a work valve. Either to protect the Xmas Tree gates or because there are failures in the Xmas Tree gates.

The connection point located on the lower slip joint section between the riser tensioner system and marine riser of a floating rig to prevent the riser from buckling.

A tool run into the well on a drillpipe that allows the wellhead and BOP arrangement to be tested on a drilling operation. It is landed on a profile in the wellhead and can be released to allow blind and shear ram testing. Also known as ‘plug type tester’.

A rod installed into a braided line BOP during pressure testing. This rod takes the place of the cable to prevent a flow path through the braided line BOPs.

Vessel that separates and measures produced well fluids.

Riser system located inside the subsea BOPs and marine riser, that
provides a well barrier and conduit between the subsea wellhead or HXT and a
floating rig at surface. It can be used for the installation and retrieval
of the upper completion, for well intervention, well tests, and flowbacks.

Source: API STD 17G

A mechanical device positioned at the top of e-line PCE designed to latch the toolstring when returning the tools to surface after an intervention.

The combination of wireline tools that are run into a well to perform an intervention.

A hydraulic or electric motor driving the rotary motion of the tool string from the swivel. Note: Used in place of a rotary table, kelly, and kelly bushing.

Source: API RP 67

The shallow sections of the well, usually drilled before installing the BOP.