When formation pressure exceeds what is normal or expected. Overpressure or excess pressure may become an issue during drilling by being uncontrollable.
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.
The vertical distance between the RKB and mean sea level.
The arrangement of opened and closed components required to pressure test a particular system.
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.
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:
A dense mineral used to increase the density (weight) of drilling fluids to maintain well control and prevent a blowout.
See Well Barrier Element.
An abbreviation for oilfield barrel, a volume of 42 US gallons [0.16 m3].
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.
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:
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.
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.
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.
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.
The capacity of fluids to be reduced in volume, usually under pressure.
A blue or yellow pod (point of distribution) that serves as a redundant control system used to function components on the BOP.
Short for “Data Acquisition.” DAQ could refer to a method, a device or both in charge of gathering or collecting data from sensors and/or transducers, and unloading the data into a database or files that could be used for data processing or analysis. The oilfield industry and many others have Data Acquisition systems, and they are collectively known as DAQ.
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.
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.
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.
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.
Valves located on the choke and kill lines that are designed to automatically close if a failure occurs.
The temporary pause of drilling operations to monitor whether the well is static or flowing.
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.
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 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.
See well integrity.
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.
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.
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.
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.
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.
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.
A configuration of valves installed downstream of the mud pumps to divert the flow of drilling fluids toward the drill line or drillstring.
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.
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.
(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 type of blowout preventer with a sealing component that closes the annular space between the drill pipe’s outside and the wellbore.
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.
See control pod.
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.).
A measuring device which converts an applied pressure into an electrical signal that is converted to a pressure measurement.
See also well barrier element, the first set of well barrier elements that prevents flow from a source of inflow, i.e., drilling fluid.
A device used to control the flow of fluids produced from wells.
Subsea tree valves regulate production from the well and allow tools for subsurface work to be lowered through the tubing.
In oilfield operations, the return flow of fluids outside the drill pipe which carries cuttings up to the surface and into a settling pit.
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.
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.
Remotely operated vehicle, which is a surface-operated unmanned robotic vehicle used to do mechanical work underwater.
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.
The second set of well barrier elements that prevents flow from the potential source of inflow. See also well barrier element.
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.
An electromechanical device used for controlling hydraulic or pneumatic function or signal
As defined in ISO 16530-1
The “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 life cycle. 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 life cycle.
The “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 life cycle and ensures that the required barriers in the well’s design are based on risk exposure to people and the environment.
The “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.
The “Operational Phase” defines the requirements or recommendations and methods for managing well integrity during operation.
The “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.
The “Abandonment Phase” defines the requirements or recommendations for permanently abandoning a well.
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.
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.
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.
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.
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.
A device attached to the topmost tubing joint in the wellhead to support the tubing string.
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 VBR enables a ram-type BOP to close and seal around a range of pipe sizes.
Vertical Christmas trees have all valves arranged vertically.
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 WBE 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.
Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the lifecycle of a well.
See Stages of well lifecycle.
A borehole used to extract oil or gas.
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.
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.
See control pod.
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