IWCF Glossary

A control device that has 3 positions and gives 4 direction selection for flow which directs pressurised fluid to the open or close lines.

The process of permanently closing and sealing a well to make it permanently inoperative. Subsurface/surface isolation intends to prevent any undesired communication between any distinct zones and fluid movement out of a well using validated well barriers.

A flow of fluid containing solid particles which has the potential to cause damage/erosion to pipework/equipment.

An individual vessel that contains hydraulic fluid under pressure. It is fitted with an internal bladder to enable a pre-charge pressure to be applied to the hydraulic fluid using nitrogen gas.

The fluid volume recoverable from the accumulator system between the system rated working pressure and the minimum operating pressure.

Source: API SPEC 16D

A test conducted to ensure that the accumulator has the capacity to function the required number of cycles of the valve or valves that it is associated with.

An initial nitrogen gas charge pressure in an accumulator, which is further compressed when the hydraulic fluid is pumped into the accumulator, storing potential energy.

Source: API SPEC 16D

The mud pit on a rig that is lined up to support the ongoing drilling operation. The active pit in use.

A device that can connect and disconnect the completion tubing to and from the production packer. It is attached by setting down weight and disconnected by right hand rotation.

Blowout preventer that uses an elastomeric sealing element to seal around tubulars and assemblies that are of different sizes or seal off a well when there are no tubulars across the BOP stack.

The pressure from the hydraulic control unit required to close an annular BOP.

The pressure applied by the accumulator unit to the annular preventer. This is a regulated value depending on the manufacturer requirements for drillpipe size and observed wellbore pressure.

The item of equipment on an accumulator unit that enables the pressure to the annular BOP to be changed from full accumulator pressure to an operator chosen value.

The volume per unit length surrounding one tubular placed inside another. Also known as ‘annulus capacity’.

The space around a downhole tool in relation to the workstring or wellbore.

The elastomeric seals within an annular BOP. Also known as ‘annular packing element’.

The master valve in the annulus bore.

A doughnut shaped, rubber/elastomer element that effects a seal in an annular preventer or diverter. Also known as ‘annular element’ or ‘annular sealing element’.

Source: API RP 64

Circulating pressure created by friction when fluid moves in the annulus between the drillstring and casing or openhole. It is regarded as a loss because the pressure is applied at surface by the mud pumps to overcome this friction value with fluid returned at the surface flow line. Also know as ‘annulus pressure loss (APL)’.

A type of subsurface safety valve used in a gas-lifted well which isolates the ‘A’ annulus if there is sudden decrease in gas-lift pressure.

The speed of the fluid movement outside of the drillstring, workstring/coiled tubing/completion tubing during circulation.

The fluid that fills the annulus. Normally inhibited, filtered and designed to be compatible with tubulars and well fluids.

The surface pressures between casing strings.

Underground layer of water-bearing permeable rock or unconsolidated materials (gravel, sand, or silt) from which groundwater can be extracted.

The natural flow of reservoir fluids to the surface due the vertical height of the fluid source being higher than the rig floor.

The absolute pressure of the atmosphere at a given location and time.

System designed to automatically shut in the wellbore in the event of a disconnect of the lower marine riser package (LMRP).

Source: API STD 53

Flow moving in the opposite direction to the intended flow, caused by differences in pressure, displacement, or temperature effects.

The pressure resulting from restriction of fluid flow downstream.

Source: API RP 16Q

A baseline volume of gas measured in the drilling fluid returns at the flowline. This gas comes from the drilled rocks.

The point during a live well workover where the weight of the workstring in the well equals the force of the well pressure.

A device that operates automatically when wireline parts at surface to contain well flow. Also known as an internal blowout preventer (IBOP).

An assembly located underneath the diverter housing of a floating rig as well as on top of a subsea stack. It reduces bending forces at the BOP stack and allows the rig some degree of lateral movement at the surface. Also known as a ‘flex joint’.

A component of the bottomhole assembly (BHA) that is activated by pumping or dropping a ball through the workstring. It lands onto a seat in the BHA and after pressure is applied, the sub separates. This is used when the BHA has become stuck, allowing the workstring to be retrieved back to surface.

Natural barium sulphate (BaSO4) is used for increasing the density of drilling fluids.

Source: API RP 13C

Settling of weighting materials used in drilling fluid in a well, which can occur both when the well fluids are static and during circulation due to gravitational forces.

A physical element that, when combined with other barrier elements, will create a barrier envelope that will prevent flow.

A combination of barrier elements that together prevent flow.

When a strand of braided wire is peeled off as the braided line or electric line is pulled through the grease injection head. This single strand bunches under the grease injection head like a bird’s nest as more wire is pulled through.

The part of the bit that has an opening for drilling fluid to exit. The size of the bit nozzle is usually referred to by its diameter.

A sub, usually with two box connections, is used to connect the bit to the drillstring.

Source: API RP 7G

A component of a pressure containment system used to drain fluids and reduce or remove pressure.

Closing and sealing component in a ram BOP that seals the open wellbore. It does not have shearing capability. For intervention operations, blind rams are designed to close and seal on slickline.

Uncontrolled flow of well fluids or formation fluids from the wellbore to the surface or into lower-pressured subsurface zones (underground blowout).

Source: API STD 53

Mud boost lines are used as conduits for drilling fluid which is pumped into the riser just above the subsea BOP stack to increase annular circulating velocities.

The abbreviation of the term ‘blowout preventer’. A closing or shearing device used to prevent the unplanned flow of well fluids during drilling or interventions. It is located at the wellhead or Xmas Tree.

The pump lined up from the fluid reservoir to the accumulator bottles that is designed to ensure that the required working pressures are maintained.

A BOP component that stores hydraulic fluid under pressure sufficient to operate BOP functions if there is a power failure.

A closing and sealing component in a ram blowout preventer that first shears certain tubulars in the wellbore and then seals the bore, or acts as a blind ram if there is no tubular in the wellbore. Note: Other common names for this ram include shearing, blind shear, blind shear rams or blind/shear rams.

The system of pumps, valves, accumulators, fluid storage and mixing equipment, manifold, piping, hoses, control panels and other items necessary to hydraulically operate the BOP equipment.

Source: API SPEC 16D

System of pumps, valves, accumulators, fluid storage and other items necessary to hydraulically operate the BOP equipment. Also known as the ‘BOP control system’.

Panel containing an array of switches, push buttons, lights, valves, graphical user interfaces, pressure gauges, and/or meters used to control or monitor BOP functions, pressures, and alarms.

Source: API STD 53

A pair of opposing rams that cut the wire, tubular or workstring.

The assembly of well control equipment including BOPs, spools and valves connected to the wellhead or Xmas Tree.

A rod that mechanically locks slickline BOP rams in place after they have been hydraulically closed.

A ram installed in the lowest cavity of a subsea BOP stack that is designed to hold pressure from above and seals around the drillstring. It allows for BOP testing without having to use a fullbore test plug. Also known as ‘inverted test ram’.

The assembly of tools deployed into a well on drillpipe, workstring, coiled tubing or wireline to perform the planned operation.

The pressure at the bottom of the well, for example pressure exerted by a column of fluid or the formation pressure.

The process of circulating fluids at the bottom of the well to the surface. Usually defined as a time or volume measurement.

A gas law that states that the pressure and volume of a gas have an inverse relationship. For example, if the volume increases, the pressure decreases.

Wireline with multiple strands used during intervention operations. Also known as ‘braided cable’.

A BOP configured to close and seal around braided wireline, including electric line.

A part of a hydraulically operated stripper or stuffing box that keeps the sealing element in place to allow it to function correctly.

A plug set in casing or tubing to provide a well barrier. It can be installed using workstring, coiled tubing or wireline.

Water-based fluid containing dissolved salts. It can be used to increase density, inhibit formation damage and/or prevent freezing.

Venting of fluids to the surface or to the seabed through channels external to the casing.

Source API SPEC 16D

The practice of placing a person to check visually for any shallow gas flows to surface during tophole operations on an offshore installation.

Forcing fluids into the formation while pumping into a shut-in well without taking returns. Also known as ‘bullheading’.

A type of on/off valve that is used to direct or redirect the flow of fluids within a system. It allows the full accumulator pressure to be placed on the manifold.

Tubular string run into a well to support the wellbore and the surrounding formations. Casing also is used to isolate zones.

The internal casing volume for each unit of measurement, for example barrels per foot (bbl/ft) or litres per metre (l/m).

Pressure between the casing and the tubing, the casing and the drillpipe or between two casing strings.

A reinforced steel sub connected to the bottom of the casing string designed to guide the casing past irregularities in the open hole. It is rounded in shape at the bottom and includes a drillable float valve.

The pressure applied to the formation directly below the last casing shoe. Used as a pressure limit reference during well control operations to ensure the integrity of the well and the formation.

A tool that can evaluate the quality and integrity of cement behind casing.

A high pressure pump unit that is used to pump cement into the well. It is the preferred pump to use for pressure testing well control equipment and formation strength tests.

An isolation device that allows cementing or stimulation of a lower zone while protecting the annulus above.

The cement being pumped before it has set.

Slowly pulling 10-15 stands of drillpipe out of the well and returning it back to bottom to ensure the well is taking and displacing the correct amount of fluid. This confirms that the well is not flowing due to swabbing or losing fluid to the formation due to surging effects.

An additive included in completion or pumped fluids to prevent corrosion, hydrate formation, scale or bacteria build up.

A valve set in a side pocket mandrel (SPM) that opens when ‘A’ annulus pressure is applied and allows chemical injection into the tubing.

A ‘V’ shaped seal used on well isolation tools.

A series of ‘V’ shaped seals that prevent flow and hold pressure from the direction that they are facing.

A device used to restrict and control the rate of flow of liquids and/or gas.

The practice of coordinating pump and choke operations for the crew to gain proficiency for well control operations. Usually done after a casing string has been set, cemented, and pressure tested.

The high-pressure piping between BOP, Xmas Tree or wellhead outlets and the choke manifold.

The additional pressure induced when circulating fluid through the choke line with the BOP closed compared to up the riser with the BOP open.

Assembly of valves, chokes, gauges, and lines used to control the rate of flow and pressure from the well.

A line on the choke manifold that bypasses the chokes. When used, it allows for the well to be circulated with minimum back-pressure. Also referred to as a ‘panic line.

Source: API STD 53

The location in a well where the fluids are circulated and start being returned to surface.

Pump pressure during circulation of fluids.

Pump pressure required to circulate kill-rate volume under non-kick conditions. Also know as ‘kill rate circulating pressure’.

Source: API RP 59

The complete flow path that the fluid travels from the mud pits, down the drillpipe, and back up the annulus until it returns back to the mud pits.

Ensuring the well is clear of solids and debris to avoid damage to the reservoir or production equipment and avoid issues related to completion installation.

The volume of fluid a tubular will displace if lowered into fluid with the lower end of the pipe closed, so no fluid enters inside the tube. It is metal displacement plus the tubular capacity.

The pressure required to close a hydraulically actuated device.

The area of the operating piston exposed to the close operating pressure, divided by the cross-sectional area of the piston shaft exposed to well bore pressure.

A continuous length of pipe used for well interventions. Uses include pumping, stimulation, production logging, cementation and working in deviated wells.

The device that connects the coiled tubing to the bottomhole assembly (BHA).

Used to deploy long strings into a well, usually perforating guns. The length of these long strings cannot be accommodated within standard PCE lubricator length.