When formation pressure exceeds what is normal or expected. Overpressure or excess pressure may become an issue during drilling by being uncontrollable.
The portion of a wellbore that lies above the mudline — the depth at which the casing or well structure is suspended at or below the seabed in offshore operations.
The measurement of pressure based on a zero pressure vacuum.
The distance or difference between the measurement and the real value of the property being measured. *See also Precision.*
Structured review or de-brief process for analyzing what happened.
The vertical distance between the RKB and mean sea level.
The arrangement of opened and closed components required to pressure test a particular system.
The largest U.S. trade association representing the oil and natural gas industry, focused on standards development, advocacy, and certification.
An emergency shut-in system designed to close the high-pressure blind shear ram using subsea batteries and hydraulic reservoirs called accumulators. This action should occur without human intervention and electrical or hydraulic power from the rig. Emergency disconnect is most likely used when station keeping failure occurs.
A large valve used to control wellbore fluids. In this type of valve, the sealing element resembles a large rubber doughnut that is mechanically squeezed inward to seal on either pipe (drill collar, drillpipe, casing, or tubing) or the open hole. The ability to seal on a variety of pipe sizes is one advantage the annular blowout preventer has over the ram blowout preventer. Most blowout preventer (BOP) stacks contain at least one annular BOP at the top of the BOP stack, and one or more ram-type preventers below.
The space between two tubular strings or between a string of casing and the formation.
A downhole completion component installed in the production tubing string that provides hydraulically controlled communication between the tubing bore and the annulus.
Application for Permit to Drill — A document filed with the Bureau of Land Management once a leaseholder, operator or designated agent identifies an oil and gas deposit on a federal lease.
American Petroleum Institute Standard 53 is the guiding document for testing blowout preventer equipment systems in international oil and gas operations on land and marine drilling rigs. API Standard 53 provides requirements for installing and testing surface and subsea blowout preventer (BOP) systems in Sections 6.5.3 and 7.6.5. Some common requirements from the standard for both surface and subsea BOP pressure tests include: – All blowout prevention components that can be exposed to well pressure shall be tested first to a low pressure between 250 psi to 350 psi (1.72 MPa to 2.41 MPa) and then to a high pressure. – When performing the low-pressure test, a higher pressure shall not be applied and bled down to the low test pressure. The higher pressure can initiate a seal that continues to seal after the pressure is lowered, therefore misrepresenting a low-pressure condition. – A stabilized low and high test pressure shall be maintained for at least 5 minutes with no visible leakage. The allowable test pressure tolerance above rated working pressure shall be 5 percent of rated working pressure or 3.45 MPa (500 psi), whichever is less.
Form required when there are changes to be made to the approved APD
The practical application of scientific, engineering, and technological principles to design, implement, and optimize oil and gas well systems for improved performance, efficiency, and economic return
A budgetary document, usually prepared by the operator.
A dense mineral used to increase the density (weight) of drilling fluids to maintain well control and prevent a blowout.
Common unit of flow rate
*See Well Barrier Element.*
An abbreviation for oilfield barrel, a volume of 42 US gallons [0.16 m3].
The depth below the mud line — which is the interface between the seabed and the water column — in a well.
To equalize or relieve pressure from a vessel or system. At the conclusion of high-pressure tests or treatments, the pressure within the treatment lines and associated systems must be bled off safely to enable subsequent phases of the operation to continue.
A blowout preventer (BOP) closing element designed to close on an empty annulus space to provide isolation or sealing of the wellbore. A blind ram is normally used when there is not piping/tubing in the BOP stack as they are not designed to seal on these components.
A blowout preventer (BOP) closing element fitted with hardened tool steel blades designed to cut the drillpipe or tubing when the BOP is closed, and then fully close to provide isolation or sealing of the wellbore. A shear ram is normally used as a last resort to regain pressure control of a well that is flowing. Once the pipe is cut (or sheared) by the shear rams, it is usually left hanging in the BOP stack, and kill operations become more difficult. The joint of drillpipe or tubing is destroyed in the process, but the rest of the string is unharmed by the operation of shear rams.
A loss of well control that occurs when formation fluid pressure overcomes drilling fluid pressure and formation fluids (water, oil, gas or a mixture of all) flow to the surface unrestrained, causing damage to equipment and the well.
(or blowout prevention equipment) A set of valves at the top of a well that may be closed if the drilling crew loses control of formation fluids. A typical BOP stack might consist of one to six ram-type preventers and one or two annular-type preventers. A typical stack configuration has the ram preventers on the bottom and the annular preventers at the top. The configuration of the stack preventers is optimized to provide maximum pressure integrity, safety and flexibility in the event of a well control incident. Since BOPs are critically important to the safety of the crew, the rig and the wellbore itself, BOPs are inspected, tested and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type and legal requirements.
*See control pod.*
*See control systems.*
BOP real-time monitoring is the gathering and monitoring of real-time BOP data using an independent, automatic, and continuous monitoring system capable of recording, storing, and transmitting data regarding the BOP control system. Sensory data accessed from the BOP Control system and supporting Control systems (Surface and Subsea) is streamed from the Rig. This data can be digital or analog tags that are produced from the OEM control system. Some examples of this data will be pressure, temperature, position, ground fault leakage, flow, alarms, faults, emergency modes, and PLC heartbeats. Real-Time BOP control system and supporting control systems data is transmitted from the rig to remote real-time monitoring using an internet connection via cloud based software and stored redundantly at a local secured server and remote data center. The real-time data feeds are properly maintained. BOP control system and supporting control system data is broken down into individual signals and referred to as “tags”. These tags are labeled with specific OEM preferred addressing sequencing and Nomenclatures. Once the OEM labeled tags reach the IPT Global remote real-time monitoring center they are verified with active correlating functions, pressures, positions, etc. BOP analysts are seasoned Senior Subsea Engineers and/or Subsea Supervisors (who have been rigorously trained by WCSE RTM SMEs) monitor this data in real-time using IPT Global’s Digital Twin displays. Clients are provided with remote access to this data in real-time. All BOP real-time data received is backed up and stored.
The lower portion of the drill string consisting of the drill bit and any combination of tools included heavy weight drill collars, stabilizers, reamers, MWD,LWD jewelry, etc.
The pressure, usually measured in pounds per square inch (psi), at the bottom of the hole.
An aqueous fluid mixed with salts used for workover or as a completion fluid.
Title 30 Code of Federal Regulations 250.724 states real-time monitoring requirements for subsea BOPs, a surface BOP on a floating facility, or a BOP operating in a high-pressure high-temperature (HPHT) environment. The CFR lists the requirements for an independent, automatic, and continuous monitoring system capable of recording, storing, and transmitting data.
The Bureau of Safety and Environmental Enforcement promotes compliance with safety and environmental standards through regular inspections and other monitoring activities. BSEE’s responsibilities include assessments of emerging or improved technologies, inspection and regulation of offshore facilities, and collaboration with industry to improve oil and gas recovery and ensure accurate production measurement.
Title 30 Code of Federal Regulations 250.446 specifies BOP maintenance and inspection requirements, including the length of time that records must be kept.
Bureau of Safety and Environmental Enforcement (BSEE) regulation 30 CFR 250.448 prescribes specific testing requirements for operations in the Gulf of Mexico.
Large-diameter pipe lowered into an open hole and cemented in place. Casing is usually manufactured from plain carbon steel that is heat-treated to varying strengths, but may be specially fabricated of stainless steel, aluminum, titanium, fiberglass and other materials. The casing forms a major structural component of the wellbore and serves several important functions: – preventing the formation wall from caving into the wellbore – isolating the different formations to prevent the flow or crossflow of formation fluid – providing a means of maintaining control of formation fluids and pressure as the well is drilled The casing string provides a means of securing surface pressure control equipment and downhole production equipment, such as the drilling blowout preventer (BOP). Casing is available in a range of sizes and material grades.
The casing head is an adapter between the first casing string and the BOP stack (during drilling and exploration) or the wellhead during production.
A liner is a casing string that does not extend back to the wellhead but is hung from another casing string. Liners are used instead of full casing strings as indicated in the well design and also to improve hydraulic performance when drilling deeper.
A ram component in a blowout preventer that is capable of shearing or cutting casing.
A drillable/millable plug that can be quickly and reliable set to isolate a section of the well.
In oilfield operations, cement is used to seal the space between the casing and the borehole wall which is called the annular. Cement is an important element for well control since it prevents high-pressure formation fluid from escaping the borehole through the annular space.
Type of control line/capillary line.
Enable injection of chemicals in application in the production string.
Check valve that prevents an influx of produced fluids inside the control line/capillary line.
Can be associated with manifold, lines, and valves. The choke line is used to restrict the flow of whatever fluid may be in the system during production or drilling to reduce the fluid pressure to atmospheric. Kill lines are used to pump (usually heavier weight) fluid “kill weight fluid” used to control the well under a kick (influx). Or circumstances where the well is trying to flow.
A set of valves used to control and divert fluids, such as drilling fluid from and to the choke and kill lines.
A high-pressure pipe leading from an outlet on the BOP stack to the backpressure choke and associated manifold. During well-control operations, the fluid under pressure in the wellbore flows out of the well through the choke line to the choke, reducing the fluid pressure to atmospheric pressure.
Also called a production tree or simply “the tree”, a Christmas Tree is the stack of valves, chokes, gauges, and fittings installed on top of a producing wellhead to control, monitor, and direct the flow of oil, gas, or other hydrocarbons from the well.
A circular chart recorder (CCR) is a data acquisition tool that plots data points onto a uniformly rotating circular chart over a timed interval based on a signal received, which is proportional to a measured parameter (e.g., pressure). Conventional CCRs simply plot pressure and do not analyze the rate of change in pressure, which can be used to differentiate between thermal influences and a leak in a pressurized component.
Pumping drilling mud through the fluid system, which includes the drill string, borehole, and back to the mud tanks at the surface.
A loss of drilling fluid into the formation that occurs when the hydrostatic pressure of the drilling fluid exceeds the formation pressure.
A very long continuous length of small-diameter pipe which is supplied spooled on a large reel. It is used for interventions in oil and gas wells and sometimes as production tubing in depleted gas wells.
Also known as well completions, an operation involving the installation of production casing and equipment in order to bring the well into production from one or more zones.
Any operation that is carried out on a n oil or gas well during or at the end of it’s production life, which alters the state of the well.
The capacity of fluids to be reduced in volume, usually under pressure.
Referring to pipe/tubing and component sections when exposed to oil and gas production environments. Sometimes referred as “Chrome” due to the high chrome content.
Joint two different size pipes/threads.
A record or schedule that documents the daily payment or work rate for employees who are paid on a day rate basis.
Driller’s control panel. A system that allows the driller to see the status of the equipment during a well drilling operation, as well as send commands and receive information from surface and downhole equipment. The control panel usually includes warning lights and pressure gauges, as well as knobs and buttons that give the driller the information and control necessary for his/her job.
*See AMF Automatic Mode Function.*
Drilling operations in water between 1,000 and 5,000 ft. Any operations in water deeper than 5,000 ft is referred to as ultra-deep water.
The Deepwater Horizon was a semi-submersible drilling rig that experienced a blowout on April 20, 2010 in the Gulf of Mexico. The blowout was due to the expansion of high- pressure methane gas from the well that rose onto the drilling rig, where it ignited and exploded, engulfing the platform. Eleven workers died in the explosion and 94 crew members were rescued. The central cause of the blowout was failure of a cement barrier allowing hydrocarbons to flow up the wellbore, through the riser and onto the rig, resulting in the explosion.
The degree of consistency of a substance measured by the quantity of mass per unit volume. Also used to reference mud gradient (mud weight).
In general, it is the comparison (subtraction) between two pressures affecting the same element from two opposite sides, such as a pipe, a pressurized container, or even between two sections of pipe.
In terms of fluids, the volume of fluid moved when a tool is immersed on it, or the volume of fluid moved by the appearance of another fluid replacing it.
Where joints of pipe are assembled and run. Directly under the Derrick.
A fluid used during drilling operations with the purpose of maintaining hydrostatic pressure in the borehole while drilling. It is a very important element of well control, since it prevents formation fluids from flowing.
A special fluid designed exclusively for drilling through the reservoir section of a wellbore.
The process of creating a hole in the earth using a drill bit, typically for the purpose of exploring or producing oil, gas, or other resources.
Tubular steel conduit used on drilling rigs to allow drilling fluid to be pumped down the hole, through the bit, and up the annulus. Drillpipe is typically 27 ft. (8.2 m) to 32 ft. (9.8 m) long but is also made in longer lengths.
Analysis of a low-pressure (LP) test followed by analysis of a high-pressure (HP) test. The test attempt passes only if analyses of both the LP and HP tests pass.
Rigs that maintain their position by means of active thrusters and GPS systems.
Height above a permanent depth reference, usually Ground Level (GL) or Mean Sea Level (MSL).
Emergency system designed for a rapid shut-in and subsequent disconnection from the well in sudden situations (A mechanism used in the offshore drilling and work-over of oil/gas wells designed for use in an emergency, when the MODU or WIV needs to quickly disconnect and moved away from the well.) EDS is most likely used when station keeping failure occurs.
Prevents escalation of events, stop hydrocarbon flow, depressurized/blowdown.
The apparent Fluid Density which results from adding annular friction to the actual fluid density in the well. The effective density exerted by a circulating fluid against the formation that takes into account the pressure gradient in the annulus above the point of being circulated.
Is the weight of the fluid felt by the formation when circulating with a certain mud weight and holding back pressure.
Valves located on the choke and kill lines that are designed to automatically close if a failure occurs.
Component installed near the bottom of the casing string on which cement plug land during the primary cement operation. It’s s short length of casing fitted with a check valve. (sometimes tested).
The temporary pause of drilling operations to monitor whether the well is static or flowing.
Regulates the flow or pressure of a fluid
*See compressibility.*
*See density, fluid weight.*
In oilfield operations, the density of a fluid is commonly known as the fluid weight, not strictly a weight. As indicated by the density definition, it is a weight divided by a volume.
The change in formation properties during the process of drilling or when exposed to drilling fluids. For example, the solids present in the drilling fluid can plug the natural pores in the rock formation reducing permeability. Damage can also occur deeper into the formation when the hydrostatic pressure of the drilling fluid is much higher than the formation pressure causing the fluid to invade deep into the formation, altering its natural properties.
A test to determine the strength or fracture pressure of the open formation, usually conducted immediately after drilling below a new casing shoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure up to the design pressure. The purpose of the FIT is to ensure that formation below the casing shoe will not be broken while drilling the next section with higher BHP, or when circulating gas influx in a well control situation.
The pressure of the fluid within a reservoir caused by the overburden of the rock and the weight of the fluids present on it. It could be simply equivalent to hydrostatic pressure in some cases. However, in other cases it could be lower than hydrostatic due to depletion of the reservoir, or higher than hydrostatic when impermeable rocks are compacted and prevent fluids from escaping.
Ball valve designed for high pressure conditions and it can hold pressure from both directions. It’s called “full opening” because when the ball valve is open the flow path through the valve has a smooth inner diameter.
A series of tests that validate the basic function of BOP stack components.
A measurement of pressure based on a zero at atmospheric pressure.
The elevation of the ground, usually measured as the distance to MSL — Mean Sea Level.
A downhole filter designed to prevent the unwanted production of unwanted formation sands from entering the production string.
Part of the Atlantic Ocean bordered by the southeast coast of the United States and the east coast of Mexico. It is also known as the Gulf of America, a name adopted by the U.S. federal government in January 2025.
A leading global provider of products and services to the energy industry, specializing in oil and gas exploration and production.
HSSE stands for Health, Safety, Security, and Environment — a management framework companies use to protect people, safeguard assets, and minimize environmental impact.
Specialized systems designed to generate and control pressures from about 5,000 to 30,000 psi for hydrostatic or pneumatic testing of BOPs, valves, pipelines, wellheads, and other pressure-rated equipment.
A specialized assembly of valves, fittings, and pressure-containing components installed at the surface of an oil or gas well to contain and control the extreme pressures encountered in the wellbore.
A horizontal tree (HXT) is a subsea tree with flow control valves arranged horizontally outside the vertical bore of the tree. Horizontal trees are manufactured as a single bore and include a cylindrical bore protector (removable sleeve) that covers the internals of the subsea tree.
A set of mechanical components that can be actuated or operated using hydraulic fluid and pressure.
The pressure caused by a column of fluid at a certain depth. Hydrostatic pressure increases with depth and/or fluid density.
A check valve installed in the drill string that allows drilling fluid to be pumped down but prevents fluid from flowing back.
Inflow (negative) tests are commonly performed in onshore and offshore drilling operations to ensure that temporary and permanent barriers — packers, seal assemblies, cement plugs, and surface-controlled subsurface safety valves (SCSSVs) — will hold against formation pressure from below. The inflow test procedure typically includes pressurization from above during fluid displacement with lower density fluid followed by a pressure stabilization period. Pressure is then bled down in a series of staged pressure tests before the final inflow test is performed. For the final inflow test, the hydrostatic pressure above the barrier is reduced until it is less than the formation pressure. This “underbalance” condition creates a negative differential pressure across the barrier from below, which is why it is commonly called a negative test. The underbalanced condition is held for a specified period to ensure the integrity of the barrier. 44H Integrity *See well integrity.*
The internal bore measurement of a tubular component — such as casing, tubing, drill pipe, or pipeline — taken across its internal circular cross-section
Some well barrier elements may be particularly important and are identified as integrity critical elements because they provide a principal integrity barrier based on a specific well design or operation. An item is identified as an integrity critical element based on a risk assessment performed during the design of the well and updated by the asset during the well lifetime as the well utility and conditions change. Defining an item as an integrity critical element has an impact on the design, selection, installation and maintenance of that item to ensure it performs as a well barrier during the well’s lifecycle. ISO documentation sets out the technical, operational and organizational requirements for the management of well integrity through the installation, management and monitoring of these as integrity critical elements. HH
Umbilical which contains multiple control lines/capillary lines to provide operation/actuating pressure.
A large diameter base pipe or casing that is drilled or jetted into place to carry the weight of the wellhead and keep the well from caving in.
A drilling method that uses a pump to force a flow of seawater down a drillpipe and out a narrow nozzle to make a “jet” of water that loosens the sediment on the seafloor. HK HHH Kick In oilfield operations, a well control situation in which the pressure of the formation fluid overcomes the drilling fluid pressure, causing an influx of formation fluid into a well.
A procedure which helps integrate accepted safety and health principles and practices into a particular task or job operations.
Connects the rotary table to the Kelly on the rig floor. Used as a datum for measured depth.
Set inside the casing or open hole used when sidetracking a well.
In oilfield operations, this refers to stopping a well kick, usually by pumping heavy drilling fluid (kill weight mud — KWM) into the borehole to increase the hydrostatic pressure and overcome the formation pressure.
A high-pressure line from the mud pumps to a connection below a BOP that allows fluid to be pumped into the well or annulus with the BOP closed during well control operations.
Refers the disassembling and laying down drill pipe or other wellbore components.
The process of detecting the location of a leak in a pipeline. In onshore operations, this can be done by external detection or by using material balance leak detection systems. In offshore operations, the task is more difficult because of the lack of inlet flow-rate measurements and the considerable solubility of natural gas in seawater at high pressures and low temperatures (seafloor level).
The magnitude of pressure exerted on a formation that causes fluid to be forced into the formation. Also used to describe pressure decay rate.
This term is normally associated with a test to determine the strength of the rock. During the test, a real-time plot of injected fluid versus fluid pressure is plotted. The initial stable portion of this plot for most wellbores is a straight line within the limits of the measurements. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or creating a space by fracturing the rock. The results of the leak off test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leak off test result.
*See casing liner.*
The assembly located at the bottom of the drilling riser that includes a BOP connector.
A mechanism installed in a high-pressure wellhead to lock the production casing hanger and seal assembly to wellhead housing so that uplift forces generated during hydrocarbon production dislocate the casing hanger and seal assembly.
Assists in landing out the production tubing and tubing hanger during a completion.
Specifically designed additives that lower the volume of filtrate that passes through a filter medium. Used to prevent loss circulation.
A ram-type blowout preventer (BOP) element installed in the lower section of a BOP stack.
The Macondo Prospect (Mississippi Canyon Block 252, abbreviated MC252) is an oil and gas prospect in the United States Exclusive Economic Zone of the Gulf of Mexico, off the coast of Louisiana. The prospect was the site of the Deepwater Horizon drilling rig explosion in April 2010 that led to a major oil spill in the region.
Referred to connecting equipment, e.g. m/u 9.635” liner and RIH
A structured, integrated framework that enables organizations to define, achieve, and maintain performance goals while managing the broad and significant range of risks inherent in upstream and downstream activities — from exploration and construction to production, transportation, and decommissioning.
A configuration of valves installed downstream of the mud pumps to divert the flow of drilling fluids toward the drill ine or drillstring.
A document that contains information on the potential health effects of exposure to a chemical.
The maximum pressure that can be applied to the annulus of a well at the surface before the formation just below the casing shoe begins to fracture or leak off.
The highest surface pressure that can be safely applied to the wellbore without causing integrity failure of the well’s casing or surface equipment.
The highest pressure that the weakest part of a pressure vessel or system can safely withstand at a specified operating temperature.
The actual length of the bore hole including and horizontal deviations.
Typically refers to measurements taken in the wellbore inclination from vertical and magnetic direction from north. Creates a three-dimensional plot of the path of the wellbore.
Prevents fluid loss to formation after completing initial gravel pack ops, isolates formations during up-hole operations, and used as a barrier in a well suspension system (often called FS2)
Procedural-based misalignment occurs when the planned line-up for a particular test does not agree with the components that were actually tested.
Large vessels (semi-submersibles, drilling vessels, jackups, submersibles, ultra-deepwater units, etc.) that are designed to be used in the exploration and drilling operations of oil and gas.
A communication protocol used for transmitting information over serial lines between electronic devices for use with programmable logic controllers (PLCs).
Minimum Required Test Pressure. Each component has a pressure, which varies based on the current operation, to which the component must be tested to ensure that the component can seal and control the well in the event of an active kick.
Mean Sea Level is the average level of the surface of a body of water.
A casing suspension system that allows a well to be drilled using a surface BOP, surface wellhead and surface drilling equipment.
A system that uses electrical or optical conductors in a subsea umbilical cable. On each conductor, multiple distinct functions are independently operated by dedicated serialized coded commands.
Maximum working pressure. Sometimes maximum rated working pressure (MRWP). Each component has a pressure to which must not be exceeded during a test. This is to prevent the failure of a component during testing
Negative tests, or inflow tests, are conducted to verify the integrity of well barriers in the direction of potential flow, subjecting a barrier to a negative pressure differential, while monitoring for signs of a leak.
In oilfield operations, when pressure of the fluid in the reservoir is equivalent to hydrostatic pressure. HHO
The person responsible for the rig and it’s personnel.
The section of the well that has been recently drilled where casing has not been installed and where the formation is exposed to the drilling fluids.
The amount of pressure in a system during normal conditions.
The external cross-sectional dimension of a tubular component such as casing or tubing. It is measured from one external edge of the pipe wall to the opposite external edge along a line bisecting the cross-section.
(oilfield definition) A device that can be run into a wellbore with a smaller initial outside diameter that then expands externally to seal the wellbore. Packers employ flexible, elastomeric elements that expand.
A specialized sensor system installed as part of a well’s completion string and left in place for the life of the well to provide continuous, real-time monitoring of downhole pressure and, often, temperature.
The act of lifting a tubular component — such as drill pipe, casing, or a bottomhole assembly — from the pipe rack or catwalk and raising it into the derrick or to the rig floor.
A type of blowout preventer with a sealing component that closes the annular space between the drill pipe’s outside and the wellbore.
A structured, step-by-step roadmap that outlines how an organization will achieve its strategic goals, manage risks, and respond to operational, regulatory, and market challenges.
A programmable electronic device used in industrial automation to provide logic and sequencing controls for machinery.
A downhole device used to isolate zones, they can be drillable or retrievable.
The stage in the lifecycle of a well when it is prepared to be closed permanently. This is usually decided when there is no economic future for the well. Cement and bridge plugs are set in the well and a series of pressure tests are carried out to ensure the integrity of the plug and the well. HHH Pod *See control pod.*
During completions, a seal assembly is run on the bottom of the production tubing and lands in the PBR above the production packer.
Pore pressure: the pressure of the subsurface formation fluids, commonly expressed as the density of fluid required in the wellbore to balance pore pressure. Fracture Gradient: the pressure required to induce fractures in a rock at a given depth. Usually plotted against each other vs. depth, where mud weight is greater than the pore pressure and less than the fracture gradient.
The distance or difference between multiple measurements carried out with the same tool and on the same object. This is different from “accuracy” since accuracy is the difference between the measurement and the real value of the property being measured.
The force applied perpendicularly to a surface area. In oilfield operations, pressure is one of the main properties that must be watched closely to preserve the integrity of multiple systems (i.e., hydrostatic pressure in the borehole, hydraulic pressure in equipment, formation pressure in the reservoir, etc.).
All hardware and systems used to maintain control of wellbore pressure and prevent the uncontrolled release of formation fluids such as oil, gas, or brine.
A measuring device which converts an applied pressure into an electrical signal that is converted to a pressure measurement.
P/T refers to Pressure–Temperature conditions, which are used to describe the thermodynamic state of reservoir fluids.
*See also well barrier element.* The first set of well barrier elements that prevents flow from a source of inflow, ie., drilling fluid.
A device used to control the flow of fluids produced from wells.
A well test used to evaluate whether a well’s completion fluid will flow back through the production screen or cause plugging.
Subsea tree valves regulate production from the well and allow tools for subsurface work to be lowered through the tubing.
The process of removing the drill string, bottomhole assembly (BHA), or other downhole equipment from the wellbore. Also commonly referred to as “tripping out”.
Combination of quality assurance, the process or set up of process used to measure and assure the quality of a product, and quality control, the process of meeting product and services to consumer expectations.
A centralized control facility where engineers, drilling specialists, and other operational staff monitor and manage drilling or production activities in real time.
Serves as a downhole barrier that can be set inside tubing or casing. Used to isolate upper wellbore from production or the lower wellbore from treatments conducted on the upper wellbore.
In oilfield operations, the return flow of fluids outside the drill pipe which carries cuttings up to the surface and into a settling pit.
the on-site assembly and preparation of a drilling rig or well servicing equipment to make it ready for operations.
Adapter that connects the rotary table to the drill string kelly bar, the top of which is commonly used as vertical reference for the drill floor. HHH ROC Rate of change in pressure, typically measured in psi/min.
Rate of penetration, a measure of drilling speed, usually measured in feet/hr or meters/hr. HH ROV Remotely operated vehicle, which is a surface-operated unmanned robotic vehicle used to do mechanical work underwater.
The controlled process of lowering drill pipe, casing, tubing, or other equipment into a wellbore during drilling operations..
A diagram that represents the elements of a system using graphic symbols.
A surface-controlled subsurface safety valve is a downhole safety valve that is operated from surface facilities through a control line strapped to the external surface of the production tubing.
Saltwater from the ocean that is either intentionally brought in for operational use or produced as a byproduct of extraction processes.
The second set of well barrier elements that prevents flow from the potential source of inflow. *See also well barrier element.*
Used to properly seal assembly entry into a production packer or polished bore receptacle (PBR).
*See control pod.*
The pressure at the bottom of the well when it is closed. It is usually the hydrostatic pressure caused by the fluid in the well and any other additional external pressure applied to the fluid.
The pressure at the top of the well when it is closed. If the shut-in pressure is zero, it means that the well is perfectly balanced by the hydrostatic pressure of the fluid opposing the formation pressure.
The controlled lowering of a drill string, tubing, or casing into the wellbore under specific operational conditions.
An electromechanical device used for controlling hydraulic or pneumatic function or signal.
As defined in ISO 16530-1: **Basis of Design Phase** identifies the probable safety and environmental exposure to surface and subsurface hazards and risks that can be encountered during the well lifecycle. Once identified, these hazards and risks are assessed such that control methods of design and operation can be developed in subsequent phases of the well lifecycle. **Design Phase** identifies the controls that are to be incorporated into the well design, such that appropriate barriers can be established to manage the identified safety and environmental hazards. The design addresses the expected, or forecasted, changes during the well lifecycle and ensures that the required barriers in the well’s design are based on risk exposure to people and the environment. **Construction Phase** defines the required or recommended elements to be constructed (including rework/repair) and verification tasks to be performed in order to achieve the intended design. It addresses any variations from the design which require a revalidation against the identified hazards and risks. **Operational Phase** defines the requirements or recommendations and methods for managing well integrity during operation. **Intervention Phase** (including work-over) defines the minimum requirements or recommendations for assessing well barriers prior to, and after, any well intervention that involves breaking the established well barrier containment system. **Abandonment Phase** defines the requirements or recommendations for permanently abandoning a well.
An independent display unit used in data acquisition or control environments that operates separately from the primary human–machine interface (HMI).
Module consisting of Drilling Digital Transducers (DDTMs) that communicates with the SEM for control, communications and data-gathering.
A pressure test for a BOP at the surface.
Contains electronics, instrumentation, and hydraulics for safe and efficient operations of a subsea tree valves, chokes.
A subsea tree monitors and controls the production of a subsea well.
An invert emulsion mud with synthetic oil as the external phase instead of oil, which makes it more environmentally acceptable than oil-based muds for use in offshore drilling.
The specific depth in a well — usually expressed as True Vertical Depth (TVD) or Measured Depth (MD) — that a drilling program is designed to reach.
*See test pressure.*
The act of compensating for the effects of temperature in a measurement. Temperature compensation is intended to eliminate the effects of temperature on the measurement, producing an accurate reading. In oilfield operations, pressure and temperature are usually dependent variables and one affects the other, so it is common to have a pressure measurement being corrected by temperature.
A vertically moored floating structure normally used for the offshore production of oil or gas and is suited for water depths greater than 1000’
Fluids used to pressurize a system for a BOP pressure test; typically the drilling fluid.
The minimum required pressure the current test’s analysis must maintain as part of the analysis criteria.
The rheological properties of drilling fluids (e.g., density, volume) that are related to pressure and temperature.
A physical phenomenon in which a measured physical property is affected not only by the current temperature but also by the history of exposure to temperature.
A Full Opening Safety Valve, or ball valve, that can hold pressure from both sides. TIW is a brand name from Texas Iron Works.
Remote BOP control panel usually located in the OIM / toolpusher’s office.
The measured depth where the cement slurry ends in the annulus after a casing job.
The depth of the upper end of a liner string in a wellbore.
The depth of the bottom of the well — the deepest point reached during drilling operations.
A device that converts electrical signals caused by a physical exposure to perturbation (temperature, pressure, vibration) into a measurement. *See also pressure transducer.*
Pressure that gets isolated by a closing component, such as a valve.
Installed on top of the Christmas tree for quick access to the tubing wellbore.
Device used to run, retrieve and mechanically release the Christmas tree. Also used for pressure testing Christmas tree.
The pulling of the drill string (or other tubulars) from the wellbore as part of a trip operation.
The measurement of a straight line perpendicularly downwards from a horizontal plane. Measurement from the surface to the bottom of the borehole, does not include any horizontal deviation.
Type of control lines used for downhole pressure temperature gauges.
A device attached to the topmost tubing joint in the wellhead to support the tubing string.
A specialized device used to lift, position, and maneuver the tubing hanger before it is run into the wellhead or subsea tree.
The pressure measured inside the production tubing at the tubing hanger.
Used to install, land, and lock a tubing hanger in a wellhead or subsea tree while managing control lines safely.
Device used to run, land and lock the tubing hanger inside the wellhead, tubing spool or subsea tree.
Devise for mounting tubing string at the head of a flowing or gas-lift well. It as also used for a conduct of various production operations. Makes possible the suspension for several tubing strings, to installed BOP equipment and seals annuls between the tubing string and the casing string.
A short, flanged pressure vessel in the wellhead stack that supports and seals the production tubing string while providing pressure containment and annular access between the tubing and the innermost casing.
A retrievable safety valve that provides well protection against pressure drop and system failure in wireline and thru-tubing operations; typically controlled from the surface with a hydraulic control line.
A specialized oilfield operation that involves the handling, inspection, and running of production tubing into a wellbore during completion or workover operations.
Refers to a situation where the formation pressure is larger than the hydrostatic pressure produced by the drilling fluids. During an inflow (negative) test, this is the condition at which there is a negative differential pressure (hydrostatic pressure < formation pressure) across the well barrier from below.
A specialized component in a blowout preventer (BOP) system that is designed to seal around the outside diameter of a specific size of drill pipe to close the annular space between the wellbore and the pipe.
A VBR enables a ram-type BOP to close and seal around a range of pipe sizes.
Vertical Christmas trees have all valves arranged vertically. EW
A downtime classification used in offshore and remote operations when scheduled activities are suspended due to adverse weather conditions such as high winds, rough seas, or lightning.
A retrievable cylindrical device protecting the internal surfaces of wellhead equipment and the top of the last suspended casing.
An annulus is the space between two concentric objects in a well. A completed well has at least two annuli. One annulus is the space between the production tubing and the smallest casing string, and the other annulus is located between different casing strings.
Any item/fluid located as part of the wellbore/drilling equipment which acts as either a primary or secondary barrier between the wellbore and the external environment. These WBEs must be capable of maintaining control of the well in the event of a kick. Typically, WBEs are items such as fluid, casing string, BOP elements, and packers.
Ensuring the safety and integrity of the well by preventing formation fluids from escaping through the borehole.
Formal documents that define the features, characteristics, process conditions, boundaries, and exclusions required to ensure a well’s equipment, systems, or processes perform as intended under operational conditions.
Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the lifecycle of a well
A borehole used to extract oil or gas.
The removal of debris, scale, sand, cement, or other fill material from inside a wellbore to restore optimal flow conditions and prepare the well for production or injection.
A division of Halliburton and a manufacturer of intelligent completion technology to the upstream oil industry.
The surface set of valves, adapters and mechanisms that help ensure the pressure of the well is controlled.
Wellsite Information Transfer Specification (WITS) is a recommended communications format used by the oil and gas drilling industry for the transfer of well site data from one computer system to another.
The maximum internal pressure to which a piece of equipment is designed to operate safely during normal service conditions.
This is the process of repairing or doing maintenance on a well with the purpose of prolonging its economic life or to replace damaged equipment. HY
*See control pod.*