IWCF Glossary

A valve that is functioned open or closed by applying hydraulic pressure into the valve mechanism. Also known as ‘hydraulically operated valve’.

A means of retrieving and running workstrings in and out of a well without the need for a traditional rig. A piston jack moves pipe in and out of the well through a BOP stack. This unit can also perform string running and retrieval in a live well. When working on a live well, this can be known as ‘a snubbing unit’

Highly toxic, flammable, corrosive gas sometimes found in hydrocarbon-bearing formations.

Source: API STD 53

Hydrostatic pressure of a fluid column sufficient to prevent formation fluid influx into the wellbore.

Source: API RP 96

The pressure at any point in a static vertical column of fluid caused by the weight of fluid above that point.

Testing a barrier by reducing the pressure on one side of the barrier and monitoring for build up. Also known as ‘negative pressure’ test.

Formation fluids (oil, gas, brine or water) that enter the well bore when the well hydrostatic pressure is below the formation pressure.

The vertical height of an influx volume at any given point of a wellbore.

Drillpipe pressure required for initial circulation at the selected kill rate while holding casing pressure at the shut in value. This is equal to kill rate circulating pressure plus shut-in drillpipe pressure (SIDPP).

The component of a coiled tubing rig-up that pushes and pulls the coil in and out of the well. Chains rotate against the coiled tubing moving it up or down.

Device that can be installed in the drillstring that acts as a check valve, allowing drilling fluid to be circulated down the string but preventing back flow.

Source: API STD 53

Note: A device that is installed in the drillstring to allow fluid to flow in one direction only. This is classed as a tested barrier in API 53 table C. Generally it is installed on top of the DPSV after the well has been made secure in preparation for stripping into the well.

Testing equipment to ensure it can contain the required pressure

A string that is set between the surface casing and production casing

The ITC is used in HXT’s, installed above the tubing hanger to provide the landing profile for the upper crown plug. Note that some designs of HXT, often called ‘enhanced HXT’ do not use an ITC, instead they have two crown plugs installed in an extended tubing hanger neck.

The conduit between the Xmas Tree and the BOPs in the pressure control equipment rig up. In intervention scenarios, described as ‘riser’.

A system for controlling subsea equipment during subsea completion and interventions. IWOCS uses hydraulic/electric/fibre optics, with a surface control unit and umbilical connecting with equipment such as Xmas Tree, subsea test tree, intervention BOP and completion.

The mechanism within a hydraulic workover unit that moves the workstring in and out of the well.

The square, hexagonal or other shaped steel pipe connecting the swivel to the drillpipe. The kelly moves through the kelly bushings, rotary table and rotates the drillstring.

Source: API RP 54

An unexpected, unplanned influx of formation fluids or gas into the wellbore. Without corrective measure, this condition can result in a blowout.

A measurable or observed change confirming that a kick is already happening or has happened.

The calculated maximum volume of an influx that the well can take and be circulated out without exceeding the MAASP.

A condition or observation that suggests a kick might occur if corrective actions aren’t taken.

A wireline (slickline) tool that installs and retrieves valves from a side pocket mandrel (SPM).

A fluid with a greater hydrostatic pressure than the reservoir pressure.

The high-pressure piping between the pumps and BOP outlets or wellhead outlets that allows fluid to be pumped into the well or annulus with the BOP closed during well control operations.

How quickly the kill fluid is injected into the well, usually expressed in strokes per minute. Also known as ‘kill rate’.

A document used to record, calculate and verify the data required to perform a well control operation.

The surface equipment required to conduct a well kill.

The hydrostatic pressure applied by each unit of depth (psi/ft, bar/m) that will overbalance the formation pressure when applied in a vertical column.

The valve on a Xmas Tree or surface test tree that is lined up to the kill pump during operations.

A tubing string component with a machined internal profile to accommodate a lock mandrel.

The point at which fluids are escaping past a failed barrier element.

A procedure used to determine the wellbore pressure required to initiate a fracture in the open or exposed formations.

Source: API STD 65: 2

Casing string that is suspended inside a previously installed casing string using a liner hanger. It does not extend to the wellhead.

The part of the wellbore where the liner is inside the previous section of casing.

A fluid column which provides hydrostatic back pressure to prevent flow of gases through the mud gas separator (MGS).

A device designed to hold and anchor tools in place within a completion landing nipple.

Tools that gather downhole information.

A section of a openhole where drilling fluid will flow into the formation. This can lead to a decrease in the surface fluid level and result in a reduction of hydrostatic pressure in the wellbore.

Solids designed to prevent fluid flow into reservoirs so the well will maintain a column of kill weight fluid.

A piece of temporary pipework that is designed to close off flow or isolate a flow path. A ball type valve that requires a 1/4 turn to close or open fully.

Upper section of a subsea BOP stack that is the interface between the lower stack and drilling riser, typically consisting of a hydraulic connector, annular BOP, ball/flex joint, riser adapter, jumper lines for the choke, kill, and auxiliary lines, and subsea control pods.

Source: API RP 16Q

The lowest in-line gate valve of a Xmas Tree, always a manually-operated valve.

The lower master valve in the production bore of the subsea vertical tree.

Used for intervention, flowing or vertical tree installation. It contains a series of isolation and cutting valves as part of, or in addition to, the emergency disconnect package (EDP).

Source: API RP 96

The lower set of rams that provide the primary barrier element when running or retrieving a workstring using the ‘ram to ram’ deployment method. Used during a snubbing / hydraulic workover operation.

Unitized assembly that interfaces with the tree upper connection and allows sealing of the tree vertical bore(s).

Source: API SPEC 17D

A method used on gas wells when circulating and bullheading is not possible. Fluid is injected into the well at pre-determined volumes and pressures, gas is then vented in equal volumes until the well is full of fluid and all of the gas has been removed.

Pressure control equipment between the BOPs and the primary sealing device during intervention operations.

Valve assembly situated below the surface tree and used to isolate the reservoir from the environment when deploying long WL/coiled tubing tool assemblies and to permit pressure testing of the upper portion of the landing string in the TBIRS or riser joints in the OWIRS.

Source: API STD 17G

A documented process that assesses risks and mitigations and approves a new plan when there are changes to the operation.

Tubular conduit made up of a series of independent joints coupled together to serve as an extension of the wellbore from the BOP stack on the wellhead to a floating drilling rig. Also known as ‘riser’ or ‘drilling riser’ or ‘marine riser’.

Source: API RP 16Q

A safety device designed to prevent accidental operation of BOP functions. Usually, a button that must be pressed at the same time as the selected function.

The greatest pressure that an annulus can contain, as measured at the wellhead, without compromising the integrity of any element of that annulus, including any exposed open-hole formations.

Source: ISO:6530-1 2017

The maximum density of drilling fluid that can be used during drilling operations without inducing losses to the formation. Usually calculated using leak off test (LOT) data.

The calculated pressure at each stage of an operation, considering the density of fluids in the well, that can be present at surface without causing integrity failure.

The highest surface pressure predicted to be encountered while the well control equipment is installed.

Source: API STD 53

The distance between two points along the length of the wellbore. This measurement differs from the true vertical depth of the well in all but vertical wells. This measurement is used for calculating well volumes.

A subset of physical barriers that features mechanical equipment: not set cement or a hydrostatic fluid column.

Source: API STD 65:2

The volume of steel (generally applied to tubulars) per unit length calculated as the cross sectional area difference between the internal and external diameters. Also known as ‘open end displacement’.

This is a tool used to remove restrictions in the well.

A vessel capable of engaging in drilling or well workover operations for the exploration or exploitation of subsea resources.

Source: API RP 54

A vessel in which gas is removed from the drilling fluid returns that are taken through the choke manifold during well control operations.

System utilizing electrical or optical conductors such that on each conductor multiple distinct functions are independently operated by dedicated serialized coded commands.

Source: API SPEC 16D

An O-shaped elastomeric seal.

The OIM is the most senior manager of an offshore platform or rig, responsible for operational safety and for the health, safety, and welfare of all personnel on board.

Riser system that provides a conduit between the subsea well and the surface vessel that can be used for the installation and retrieval of subsea trees, well intervention, well tests, and flowbacks.

Source: API STD 17G

The space within the well below set casing, usually expressed as a volume per unit of length, such as barrels per foot (bbl/ft) or cubic metre per metre (m3/m).

Pressure the process system experiences during normal operation, including normal variations. Also known as ‘working pressure’.

Source: API STD 521

A condition where the pressure in the wellbore is higher than the formation pressure. For a downhole well barrier, overbalance refers to a higher pressure above the barrier.

A component of a grease injection head that enables a pressure seal to be regained if there is a leak.

Device with an expandable element used for blocking fluid (liquid or gas) communication through the annular space between conduits by sealing off the space between them. It can be run on the outside of a casing string or as a full bore plug using a workstring.

The annular sealing device in an annular BOP or diverter. Also, the elastomer packing element used in valves or lubricators to effect a seal.

Source: API RP 64

A set of seals designed to hold pressure within a polished bore. For example, the seals on a wireline plug.

An explosive device that creates holes in the casing or liner to allow communication between the reservoir and the wellbore.

Holes created in the casing or liner and surrounding reservoir through which hydrocarbons are produced.

Material included within a fluid pumping programme. For example, a viscous fluid, designed to pick up solids, or a lost circulation material (LCM), designed to block perforations.

Hydraulic pressure contained within small diameter lines that operate the sub-plate mounted (SPM) valves in a subsea BOP system.

When the workstring being deployed in a live well is of insufficient weight to overcome the well pressure and requires slips to prevent it being ejected.

A closing and sealing component in a ram blowout preventer that seals around the outside diameter of a tubular in the wellbore.

Source: API STD 53

An exercise conducted to ensure the rig crew reacts to a simulated gain of drilling fluid. The crew needs to complete the required steps up to, but not including, closing the BOPs.

A device that combines all of the individual pit volume indicators and registers the total drilling fluid volume in the various tanks.

Source: API STD 53

A device with a honed internal diameter (ID) sealing surface for landing a production tubing seal assembly or tie back casing.

Source: API STD 65:2

See float. Ported float has a small hole in it to allow pressure (not flow) to communicate up the drillstring to allow the shut-in drillpipe pressure (SIDPP) to be monitored when shut in.

The ported slick joint is part of the subsea test tree used in TBIRS operations. Drilling BOP pipe rams are closed around the outside of the ported slick joint to provide a well barrier. The wall of the slick joint is ported with multiple axial gun-drilled holes to allow hydraulic control functions below the SSTT.

The initial pressure of gas added to a hydraulic cylinder before it is filled with hydraulic fluid. Usually applies to accumulator bottles and pulsation dampeners.

Temporary equipment installed onto a live well to allow intervention operations to take place.

The pressure per unit of vertical depth or the change in pressure per unit distance.

A hydraulic device that reduces and maintains the supplied pressure to a desired (regulated) pressure.

The pressure range to avoid exceeding formation strength or allowing further influx to enter the well.

A procedure that applies pressure to a system to assess that it can safely handle expected pressure without leaks or failures.

A safety device designed to protect a system by releasing excess pressure.

A system used to stage long BHAs into a live well when they are too long to be contained within the surface PCE. For example, perforating guns.

The first well barrier that prevents flow from a source.

Prevention of formation fluid flow by maintaining a hydrostatic pressure equal to or greater than formation pressure.

Source: API RP 59

A casing string that is set, cemented, and pressure tested at the reservoir interval and within which the primary completion components are installed.

A Xmas Tree gate valve that leads to the production flow line.

A tubular string that is positioned across the reservoir.

An intervention tool that is run to the reservoir to assess flow performance.

A system of pipes and valves used to control the flow of produced fluids from all wells on location to a common gathering point or processing facility.