Oil and Gas Terms Beginning with “F”

In seismic surveying or processing, the use of a function of frequency rather than time to express an independent variable or measurement. In contrast, in the time domain, variables are expressed as a function of time instead of frequency.

An iterative computer algorithm to perform the Fourier transform of digitized waveforms rapidly.

A set of mathematical formulas used to convert a time function, such as a seismic trace, to a function in the frequencydomain (Fourier analysis) and back (Fourier synthesis). The function is expressed as a convergent trigonometric series, similar to that first formulated by French mathematician Jean-Baptiste-Joseph, Baron Fourier (1768 to 1830). The Fourier transform is used extensively in signalprocessing to design filters and remove coherent noise. Many filtering operations are performed in the frequency domain. The Fourier transform has applications in image analysis and in pattern recognition in geological systems.

A method for obtaining quantitative mineralogical analysis of a rock sample by measuring the effect of midrange infrared radiation transmitted through the sample.

A vertical or horizontal separator used mainly to remove any free water that can cause problems such as corrosion and formation of hydrates or tight emulsions, which are difficult to break.A free-water knockout is commonly called a three-phase separator because it can separate gas, oil and free water. The liquids that are discharged from the free-water knockout are further treated in vessels called treaters. Free-water knockout is abbreviated as FWKO.

The principle that the path taken by a ray of light from one point to another is that which takes the minimum time (or the maximum time in select cases), named for its discoverer, French mathematician Pierre de Fermat (1601 to 1665). Snell's law and the laws of reflection and refraction follow from Fermat's principle. Fermat's principle also applies to seismic waves.

Primarily used as a safety measure to prevent the accumulation of gases that could pose a hazard. Also used to manage small volumes of waste gas.

A mathematical algorithm designed by geometrician and physicist Baron J.B.J. Fourier to determine the frequencydistribution within a wave pattern as a series of sine waves. Fourier analysis is also used to study any series of repeated signals or patterns. This analysis is sometimes used to study patterns in images such as thin sections, and in geostatistics and log analysis.

The process of reconstructing a function of time or space from its sinusoidal components determined in Fourier analysis.

A set of mathematical formulas used to convert a time function, such as a seismictrace, to a function in the frequencydomain (Fourier analysis) and back (Fourier synthesis). The function is expressed as a convergent trigonometric series, similar to that first formulated by French mathematician Jean-Baptiste-Joseph, Baron Fourier (1768 to 1830). The Fourier transform is used extensively in signalprocessing to design filters and remove coherent noise. Many filtering operations are performed in the frequency domain. The Fourier transform has applications in image analysis and in pattern recognition in geological systems.

A technique for quantitative mineralogical analysis of a sample of rock by measuring the effect of midrange infrared radiation transmitted through the sample. This radiation excites vibrations in the chemical bonds within the mineral molecules at particular frequencies characteristic of each bond. The transmitted radiation is compared with the spectral standards for a wide variety of minerals to determine the abundance of each mineral in the sample. Typically, a core plug is ground finely and a small (approximately 1 g) representative sample selected and dispersed in a potassium bromide matrix for the measurement.

A frequency- and range-dependent area of a reflector from which most of the energy of a reflection is returned and arrival times differ by less than half a period from the first break, named for French physicist Augustin-Jean Fresnel (1788 to 1827). Waves with such arrival times will interfere constructively and so be detected as a single arrival. Subsurface features smaller than the Fresnel zone usually cannot be detected using seismic waves.

A single-vessel technique of acquiring marineseismic data at a complete range of azimuths by towing streamers in a circular path.

The use of frequency (abbreviated as f) and wavenumber (k, the reciprocal of wavelength) as the reference framework, obtained by using the Fourier transform over time and space.

A graphical technique to distinguish subsets of data according to their direction and velocity by plotting and contouring frequency and wavenumber.

The characteristics of a rock unit that reflect its origin and permit its differentiation from other rock units around it. Facies usually are characterized using all the geological characteristics known for that rock unit. In reservoir characterization and reservoir simulation, the facies properties that are most important are the petrophysical characteristics that control the fluid behavior in the facies. Electrofacies and other multivariate techniques are often used to determine these characteristics. Rock types rather than facies are more likely to be used in reservoir simulation.

The act of modeling a reservoir using knowledge of the facies that make up the reservoir and the depositional environments that the facies represent. The depositional characteristics will suggest rules concerning the geometries of the facies and the possible relationships between facies, especially where the facies have been related to each other within a stratigraphic sequence or a cyclothem. Facies modeling is often an important component of geostatistical reservoir characterization and facilitates construction of superior reservoir models for complex reservoirs.

The trend along which a particular geological feature is likely, such as a sand fairway or a hydrocarbon fairway. Prediction of conceptual fairways helps explorationists develop prospects. Along a sand fairway, for example, sand was transported and, presumably, was deposited, allowing an interpretation of the presence of reservoir rock in the fairway.

The measurement and analysis of pressure data taken after an injection well is shut in. These data are often the easiest transient well-test data to obtain. Wellhead pressure rises during injection, and if the well remains full of liquid after shut-in of an injector, the pressure can be measured at the surface, and bottomhole pressures can be calculated by adding the pressure from the hydrostatic column to the wellhead pressure. Since most water-injection wells are fractured during injection, and injection wells often go on vacuum, the fluid level can fall below the surface. Dealing with this complication requires reverting to bottomhole pressure gauges or sonic devices.

A technique for acquiring seismicrefraction data around local, high-velocity features such as salt domes by using a fan or arc-shaped geophonearray around a central shotpoint. The data from the fan-shaped array are calibrated against a control profile acquired some distance from the anomalous feature.

Water that is far from the clay surface, as distinct from clay-bound water (or "near" water). The term is used in the dual-water model. It includes the capillary-bound water and the free water.

The party that acquires the rights to drill and earn an assignment of the leasehold interest, receiving a farm-in.

The party that originally owns the leasehold interest and assigns the farmout.

A contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party in exchange for fulfilling contractually specified conditions. The farmout agreement often stipulates that the other party must drill a well to a certain depth, at a specified location, within a certain time frame; furthermore, the well typically must be completed as a commercial producer to earn an assignment. The assignor of the interest usually reserves a specified overriding royalty interest, with the option to convert the overriding royalty interest to a specified working interest upon payout of drilling and production expenses, otherwise known as a back-in after payout (BIAPO).

An iterative computer algorithm to perform the Fourier transform of digitized waveforms rapidly.

The rapid rate of diffusion of molecules in pore fluids during a nuclear magnetic resonance (NMR) measurement. In fast diffusion, the hydrogen within a certain volume diffuses fast enough that only one T2 peak is observed for the whole volume. This is the case in a single pore, because the surface relaxation is not strong enough for observation of separate T2 peaks, for example, for water near the surface of a grain and water in the middle of the pore. Fast diffusion is also considered to occur between most clay- and capillary-bound water, between normal pores and micropores within some carbonates, and in some other systems.

A formation where the velocity of the compressional wave traveling through the borehole fluid is less than the velocity of the shear wave through the surrounding formation. In such conditions a shear head wave is generated, so that standard techniques based on monopole transducers can be used to measure formation shear velocity.In hard formations, several normal modes are excited in addition to the Stoneley and leaky modes.

An early signal in a cement-bond log. In some formations, particularly carbonates of low porosity, it is possible that the first acoustic signal to arrive at the receiver passes through the formation rather than through the casing, and hence its amplitude is unrelated to the cement bond. This manifests itself by a shortening of the transmitter-to-receiver traveltime and by anomalous patterns on the variable-density log. In such cases, it may be assumed that the cement bond is good, as the signal would be unlikely to be transmitted through the formation with sufficient amplitude to be detected if cement bond were poor.

A neutron interaction in which the neutron is absorbed by the target nuclei, which then emit nuclear particles such as alpha or beta particles, gamma rays, protons or additional neutrons. Fast neutron reactions have a small probability of occurrence relative to the other principal interactions, except at high neutron energy.

A type of organic acid derived from animal and vegetable fats and oils. Fatty acids are the raw materials used in the manufacture of many drilling-fluid additives, such as emulsifiers, oil-wetting agents and lubricants. Tall-oil fatty acids are distilled from conifer trees. Animal and vegetable fats and oils are triglycerides, which are hydrolyzed to give fatty acids (and glycerol). Fatty acids from animals are mostly saturated acids, having single bonds between carbon atoms. Tall oils and vegetable oils yield both saturated and unsaturated (double- and triple-bond) fatty acids.

A salt formed when a fatty acid reacts with a metal oxide or hydroxide. Fatty acids and lime, Ca(OH)2, form emulsifiers for oil muds. Fatty acids reacted with sodium hydroxide [NaOH] or potassium hydroxide [KOH] are laundry soaps, some used as foamers for air drilling. Fatty acids and aluminum hydroxide form soaps used as greases and as defoamer chemicals.

A salt formed when a fatty acid reacts with a metal oxide or hydroxide. Fatty acids and lime, Ca(OH)2, form emulsifiers for oil muds. Fatty acids reacted with sodium hydroxide [NaOH] or potassium hydroxide [KOH] are laundry soaps, some used as foamers for air drilling. Fatty acids and aluminum hydroxide form soaps used as greases and as defoamer chemicals.

What Is a Fault? A fault is a planar or curved fracture in brittle rock across which the two opposing blocks have moved relative to each other, driven by tectonic stress. Fault geometry, displacement magnitude, and sealing capacity determine whether a fault creates a reservoir trap or fragments a producing formation, directly shaping exploration strategy and well placement decisions worldwide. Key Takeaways Faults are classified by the relative movement direction of the hanging wall and footwall: normal (extensional), reverse and thrust (compressional), and strike-slip (lateral shear). Anderson's theory of faulting links each fault type to a specific orientation of the three principal compressive stresses, allowing geologists to predict fault style from regional stress data. Fault sealing capacity, governed by fault gouge composition, clay smear ratio, and cataclasis intensity, controls whether hydrocarbons accumulate against or migrate through a fault surface. Growth faults in the Gulf of Mexico, Niger Delta, and other passive margins thicken the hanging wall sequence syn-depositionally, creating rollover anticlines that host billions of barrels of recoverable oil and gas. Reservoir compartmentalization by sub-seismic faults is a leading cause of production underperformance relative to volumetric models, making fault characterization a critical input to field development planning. How Faults Form and Move Faults initiate when applied stress exceeds the shear strength of rock, typically following the Mohr-Coulomb failure criterion: shear stress at failure equals cohesion plus normal stress multiplied by the coefficient of internal friction. Once initiated, a fault propagates along a plane oriented approximately 30 degrees to the maximum principal compressive stress (sigma-1) in intact rock, though pre-existing weaknesses such as bedding planes, earlier joints, or prior fault surfaces can capture later displacement at steeper or shallower angles. The zone of crushed and ground rock flanking the main slip surface, termed the fault zone or damage zone, may range from a few centimetres in a minor fault to hundreds of metres in a major plate boundary structure. Fault displacement accumulates episodically. Each seismic slip event advances the fault tip and adds to the cumulative throw, which is the vertical component of displacement, and heave, the horizontal component. On growth faults active during sedimentation, sediment supply fills accommodation space in the hanging wall more rapidly than on the footwall, producing thick syn-kinematic sequences that taper abruptly across the fault plane. Geologists identify this pattern on seismic reflection data as progressive unconformities, wedge-shaped reflector packages, and rollover anticlines that form as the hanging wall bends to maintain contact with a listric (concave-upward) fault surface. Throw ranges from millimetres on hairline fractures to more than 10 km (33,000 ft) on major crustal structures such as the Wasatch Fault in Utah or the East African Rift system. Fault Classification and Anderson's Theory E.M. Anderson's 1905 and 1942 analyses established the theoretical basis for relating fault type to the orientation of the three principal stresses: sigma-1 (maximum), sigma-2 (intermediate), and sigma-3 (minimum). Because the Earth's surface is a free boundary that cannot sustain shear traction, one principal stress is always approximately vertical (sigma-v). The three fundamental fault modes follow directly: in a normal fault regime, sigma-1 is vertical and sigma-3 is horizontal, so the hanging wall slides down the dipping fault plane under the weight of overburden; dip angles typically range from 55 to 70 degrees. In a reverse fault regime, sigma-1 is horizontal and sigma-3 is vertical, driving the hanging wall up and over the footwall; dip angles are commonly 30 to 60 degrees. Where the dip of a reverse fault shallows below roughly 30 degrees the structure is termed a thrust fault, and where it is nearly horizontal it is an overthrust or detachment. In a strike-slip regime, sigma-1 and sigma-3 are both horizontal and sigma-2 is vertical; fault planes are near-vertical and displacement is lateral. Oblique-slip faults combine dip-slip and strike-slip components, occurring where the remote stress field is not perfectly aligned with the fault surface or where two fault sets intersect. Transtensional basins develop where plates diverge obliquely, while transpressional settings produce positive flower structures with upthrown central blocks. Reactivated faults present particularly complex kinematics: a Permian normal fault in the Williston Basin of North Dakota may invert during later Laramide compression, becoming a reverse fault that traps hydrocarbons on its steepened flank. Fault Anatomy: Key Components Understanding fault architecture is essential for predicting both trap integrity and production behaviour. The principal slip surface is the main movement horizon, often polished to a slickenside with linear striations (slickenlines) that record the net slip direction. Surrounding the principal slip surface is the fault core, typically 0.001 to 1 m (0.003 to 3.3 ft) thick, composed of fault gouge (clay-rich ultracataclasite), breccia, and ultracataclasite. The broader damage zone extends tens to hundreds of metres into the host rock and contains minor faults, fractures, veins, and folds that accommodate the strain incompatibilities around the main structure. Beyond the damage zone lies the protolith, the undisturbed host rock. The hanging wall is the fault block that rests above an inclined fault plane; in a normal fault the hanging wall has moved down, in a reverse fault it has moved up. The footwall is the block beneath the fault plane. The fault scarp is the topographic expression of recent movement, preserved where erosion has not obliterated the offset surface trace. Fault throw refers to the vertical displacement between equivalent stratigraphic markers on opposing fault blocks, while heave is the horizontal separation. Net slip is the vector sum along the fault plane, measured between markers that were once in contact. Fault Seals and Hydrocarbon Trap Integrity A fault functions as a hydrocarbon trap only if the fault surface or the strata juxtaposed across it prevent lateral migration of oil and gas. Three principal sealing mechanisms operate in practice. Fault gouge sealing occurs where clay minerals, fault rock comminution products, or authigenic minerals precipitated in the fault zone reduce permeability to a value low enough to hold a hydrocarbon column. Shale Gouge Ratio (SGR) and Clay Smear Potential (CSP) are the most widely used predictive algorithms: SGR equals the net volume of shale in the faulted interval divided by the throw, and empirical calibration suggests SGR values above 0.18 to 0.20 commonly support sealed columns. Clay smear sealing arises when ductile clay or shale layers are smeared continuously along the fault plane as it propagates through interbedded lithologies, a process modelled by the Shale Smear Factor (SSF). Cataclastic sealing occurs in clean, high-porosity sandstones where grain crushing and pore collapse create a low-permeability cataclastic fault rock capable of withstanding column heights of several hundred metres. Juxtaposition sealing requires that the reservoir sandstone on one side of the fault is placed against an impermeable shale or tight carbonate on the other side: no clay-rich fault rock is needed because there is simply no connected pore network across the fault plane. Column height supported by juxtaposition seals can be estimated geometrically from Allan maps (fault plane projection diagrams), which plot the stratigraphy of both fault blocks onto the fault surface to identify sand-on-sand windows that represent potential migration pathways. Fault seal failure, whether by hydraulic fracturing of the gouge layer (breach pressure exceeded) or by re-activation during burial and uplift, is a primary risk in fault-bounded prospects and drives the need for dynamic fault seal analysis in basin models. Fast Facts The North Sea Central Graben, formed by Late Jurassic-Early Cretaceous rifting, contains over 50 significant fault-bounded oil and gas accumulations. Fault throws on the bounding normal faults reach 3,000 m (9,843 ft) in places, with individual fields such as Forties, Brent, and Ekofisk hosting recoverable reserves exceeding 1 billion barrels of oil equivalent, underscoring the global importance of fault traps in prolific petroleum systems. Fault Types in Major Petroleum Provinces The Alberta Foothills and Rocky Mountain Front Range of Canada host some of the world's best-documented thrust and fold-and-thrust belt hydrocarbon systems. The Foothills trend from the US border north to Peace River contains a stack of east-directed thrust sheets that have translated Devonian and Mississippian carbonate reservoirs eastward by as much as 100 km (62 mi), placing them against impermeable shale seals in the hanging wall of structures such as the Turner Valley and Jumping Pound fields. The Alberta Energy Regulator (AER) requires operators to disclose fault interpretation maps in well licence applications and in hydraulic fracturing notifications under Directive 083, particularly where faults intersect aquifers or approach the surface. Fault-induced seismicity monitoring is mandated under the AER Subsurface Order No. 2 framework, and induced seismic events above M2.0 require mandatory reporting. In the United States, normal faults dominate the extensional Basin and Range province of Nevada and Utah, where half-graben fills host both geothermal and petroleum targets. The Gulf of Mexico passive margin is characterized by large listric growth faults soled out in overpressured shales; the Corsair and Clemente-Tomas fault trends in the Texas continental shelf contain rollover anticlines with cumulative production exceeding 2 billion barrels. The Bureau of Ocean Energy Management (BOEM) requires fault mapping and seismic hazard assessment as part of every Geological and Geophysical (G&G) permit for offshore exploration, with fault reactivation risk a specific consideration in the G&G data review. Strike-slip faults define the Western Transverse Ranges of California; the San Andreas Fault system accommodates roughly 35 mm (1.4 in) of right-lateral slip per year and has generated fold-and-thrust structures in its restraining bends that trap oil in the Ventura, Los Angeles, and Midway-Sunset fields. In the Middle East, the Zagros Mountains of Iran and Iraq represent the world's most productive fold-and-thrust belt, hosting fields such as Ghawar (Saudi Arabia, on the Arabian Platform), Marun, Aghajari, and Kirkuk. The Zagros detachment thrusts moved Palaeozoic and Mesozoic carbonates northeastward onto the Arabian foreland, creating doubly plunging anticlines that trap supergiant reserves. Strike-slip faults including the Kazerun and Main Recent Fault systems segment the Zagros, and their intersection with fold axes creates complex compartmentalization in reservoirs such as the Asmari Formation limestone. The National Iranian Oil Company (NIOC) and Iraq's Ministry of Oil require detailed fault analysis in all field development plans submitted for technical review. On the Norwegian Continental Shelf, normal faults associated with the Viking Graben and Horda Platform control the geometry of Jurassic Brent Group sandstone reservoirs in fields such as Statfjord, Gullfaks, and Oseberg. The Norwegian Petroleum Directorate (now Sodir, the Norwegian Offshore Directorate) mandates fault interpretation and uncertainty reporting in both exploration well applications (PUD sections) and field development plans (PDOs) submitted under the Petroleum Act. Sodir's NPD-DISKOS database archives interpreted fault polygons from thousands of 3D seismic surveys, enabling basin-scale fault pattern analysis. Fault-controlled compartments in Gullfaks resulted in a lower-than-predicted recovery factor from individual reservoir units, illustrating how sub-seismic faults affect long-term production profiles. In Australia, the Carnarvon Basin on the Northwest Shelf hosts normal fault-bounded horsts and half-grabens that trap Jurassic-Cretaceous reservoirs in fields such as Rankin, North West Shelf LNG, and Gorgon. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) requires fault characterization as part of the Environment Plan (EP) submitted for each well, specifically addressing fault-related geohazards including shallow gas accumulations, overpressure risk, and wellbore stability in fault zones. The Cooper Basin of South Australia and Queensland contains reactivated basement faults that control structural highs hosting the Moomba, Big Lake, and Tirrawarra gas fields.

A type of structuralhydrocarbontrap in which closure is controlled by the presence of at least one fault surface.

Ownership of the entire and absolute right or interest to use or exploit a tract of land from the center of the earth to the stars, including the air, surface and minerals.

[alkali feldspar (K,Na)AlSi3O8][plagioclase feldspar NaAlSi3O8 - CaAl2Si2O8]A group of rock-forming silicate minerals that are essential constituents of igneous rocks and are common in sandstones. Feldspar can weather to form clay minerals. Feldspar can occur in all three major rock types and forms approximately 60% of the crust of the Earth.

Pertaining to minerals or igneous rocks composed of minerals such as quartz and feldspar that are relatively light in color and density. The word comes from the terms feldspar and silica. Granite is a felsic igneous rock. (Compare with mafic.)

A graphical display of three-dimensional data and interpretations in two-dimensional perspective view. Geologic cross sections can be displayed in a network to form a fence diagram. Stratigraphic changes can be displayed clearly in fence diagrams.

A corrosion by-product [FeS2] formed when hydrogen sulfide [H2S] contacts the iron [Fe] present in steel.Ferrous sulfide is a black crystalline material at bottomhole conditions. However, when it contacts air at surface, it will be converted into iron oxide, which is a red-brown compound. Ferrous sulfide is also called iron sulfide.

A type of lost circulation material that is long, slender and flexible and occurs in various sizes and lengths of fiber. Fiber LCM is added to mud and placed downhole to help retard mud loss into fractures or highly permeable zones. Ideally, fiber LCM should be insoluble and inert to the mud system in which it is used. Examples are cedar bark, shredded cane stalks, mineral fiber and hair. Often, granular, flake and fiber LCM are mixed together into an LCM pill and pumped into the well next to the zone of fluid loss to seal the formation that is taking mud from the system.

A type of lost circulation material that is long, slender and flexible and occurs in various sizes and lengths of fiber. Fiber LCM is added to mud and placed downhole to help retard mud loss into fractures or highly permeable zones. Ideally, fiber LCM should be insoluble and inert to the mud system in which it is used. Examples are cedar bark, shredded cane stalks, mineral fiber and hair. Often, granular, flake and fiber LCM are mixed together into an LCM pill and pumped into the well next to the zone of fluid loss to seal the formation that is taking mud from the system.

The surface area above a subsurface hydrocarbon accumulation.

A magnetic tape containing data recorded in the field, abbreviated FT.

A cement system used to provide zonal isolation across generally nonproductive zones located above the zones of interest. The fill cement is also called the lead cement.

A pipe-shaped housing that protects the firing head of a tubing-conveyed perforating gun. It is used to accommodate or deflect debris that might fall toward the firing head while running into the hole or while on depth before shooting.

To remove undesirable portions of data during seismicprocessing to increase the signal-to-noise ratio of seismic data. Filtering can eliminate certain frequencies, amplitudes or other information.

The residue deposited on a permeable medium when a slurry, such as a drilling fluid, is forced against the medium under a pressure. Filtrate is the liquid that passes through the medium, leaving the cake on the medium. Drilling muds are tested to determine filtration rate and filter-cake properties. Cake properties such as cake thickness, toughness, slickness and permeability are important because the cake that forms on permeable zones in the wellbore can cause stuck pipe and other drilling problems. Reduced oil and gas production can result from reservoirdamage when a poor filter cake allows deep filtrate invasion. A certain degree of cake buildup is desirable to isolate formations from drilling fluids. In openhole completions in high-angle or horizontal holes, the formation of an external filter cake is preferable to a cake that forms partly inside the formation. The latter has a higher potential for formation damage.

A subjective description of a filtercake, especially its toughness, slickness and hardness. A mud engineer makes these observations, which are recorded on the mud report along with filtrate volume and cake thickness. With increasing experience, the engineer's observations can become less subjective.

A measurement of the thickness of the filtercake, usually recorded in 32nds-inch. Under dynamic conditions, filter-cake thickness depends on rate of deposition versus erosion caused by fluid circulation and mechanical abrasion by the rotating drillstring. Typically, the filter cake will reach an equilibrium thickness in the wellbore. In laboratory tests, however, filter cake is built under static conditions with no erosion.

(noun) The plural of filter medium. The porous materials — including woven screens, sintered metals, gravel packs, sand, diatomaceous earth, and synthetic membranes — through which a fluid is passed to remove suspended solids and particulate matter in drilling, completion, and production operations.

A permeable material used in a filtration device through which filtrate passes and on which the filter cake is deposited, commonly a specifically designed filter paper or permeable disk used in a static filter press that meets API standards. The filter medium can be the cylindrical, permeable core or disk used in a dynamic filtration test or permeable rock downhole on which a filter cake is deposited in a wellbore.

A pressurized cell, fitted with a filter medium, used for evaluating filtration characteristics of a drilling fluid while it is either static or stirred (to simulate circulation) in the test cell. Generally, either low-pressure, low-temperature or high-pressure, high-temperature devices are used.

A subjective description of a filter cake, especially its toughness, slickness and hardness. A mud engineer makes these observations, which are recorded on the mud report along with filtrate volume and cake thickness. With increasing experience, the engineer's observations can become less subjective.

A measurement of the thickness of the filter cake, usually recorded in 32nds-inch. Under dynamic conditions, filter-cake thickness depends on rate of deposition versus erosion caused by fluid circulation and mechanical abrasion by the rotating drillstring. Typically, the filter cake will reach an equilibrium thickness in the wellbore. In laboratory tests, however, filter cake is built under static conditions with no erosion.

A completion or workover fluid that has been treated to remove debris and fine particles that may cause near-wellbore damage if allowed to enter the reservoirformation.

Devices for selecting or excluding data from a data stream or data set. These devices may be physical (for example to tune an electrical circuit to a particular frequency) or a mathematical algorithm. Mathematical filters take many forms, some of which are used in oilfield data analysis and interpretation. Examples include statistical techniques, geostatistical techniques, clustering, conditional algorithm, etc. A simple example of a conditional algorithm might include using a caliper to determine whether a borehole was rugose, thus requiring special log interpretation through the rugose interval.

The liquid that passes through a filter cake from a slurry held against the filter medium, driven by differential pressure. Dynamic or static filtration can produce a filtrate.

The downward vertical movement of filtrate with time after invasion. In hydrocarbon zones, the filtrate is heavier than the formation fluid. Therefore, in a vertical well, gravity causes the filtrate to sink to the bottom of a permeable zone, while the hydrocarbons move back to the borehole at the top. In a horizontal well, the mud filtrate will sink below the well, leaving hydrocarbons above it. The amount of movement depends, among other factors, on the time since invasion, the fluid mobilities and the difference in fluid densities.In water zones, the direction of movement depends on the relative densities of filtrate and formation water. In the more usual case of fresh filtrate and salty formation water, the filtrate will move upwards.

A chemical or isotopic marker that is uniformly distributed in the continuous phase of a drilling, coring, drill-in or completion fluid and used to later identify the filtrate in cores or in fluids sampled from permeablestrata. A tracer must become a part of the filtrate, remaining in true solution and moving with the filtrate into permeable zones. It must not be a component in the strata that is expected to migrate, be adsorbed on clays, or degraded. It should be measurable in trace amounts and safe to handle. Examples of filtrate tracers include: (1) Radioactively tagged compounds (isotopes of elements). Tritium, a weakly-emitting radioisotope of hydrogen, can be a safe and effective tracer in both oil and water (as T2O) muds. It is measured by scintillation counts. (2) Bromide or iodide compounds are practical to use because they do not occur naturally in most muds or reservoirs. They are detectable in small amounts by electron-capture gas chromatography. (3) Fatty acids (or their derivatives) normally present in an oil-mud emulsifier can serve as oil-filtrate tracers and are analyzed by gas chromatography. (4) Nitrate (NO3-) anion, added as sodium, potassium or calcium nitrate, is one of the earliest tracers used. It is limited by being difficult to analyze and lost by degradation.

The volume of mudfiltrate measured after 30 minutes in API static filtration tests. The volume and cake thickness are the two data points in the test.

The process of separating components of a slurry by leaving the suspended solids as filter cake on a filter medium while the liquid passes through. The process can be either static or dynamic.

The final flow sequence in a drillstem test. The initial shut-in period is usually followed immediately by an extended period of flow. The well is then shut in for the final buildup period. Data obtained during the final buildup period are analyzed to determine permeability thickness, kh, and skin effect, s. Final flow periods commonly range from 4 to 24 hours, and final buildup periods from 6 to 48 hours.

The production rate just prior to shut-in for a buildup test.

The pressure determined at the formation face just prior to shut-in for a buildup test. This value is required to determine the skin effect.

The final buildup sequence in a drillstem test. The initial shut-in period is usually followed immediately by an extended period of flow. The well is then shut in for the final buildup period. Data obtained during this period are analyzed to determine permeability thickness, kh, and skin effect, s. Final flow periods commonly range from 4 to 24 hours, and final buildup periods from 6 to 48 hours.

A particle size term referring in the strict sense (API Bulletin 13C) to any particle in the size range 44 to 74 microns. More generally it is used to indicate any particle not removed by the shaker screens.

In a broad sense, very small particles, either in a mud or a mud additive sample.

The movement of fineclay, quartz particles or similar materials within the reservoirformation due to drag forces during production. Finesmigration may result from an unconsolidated or inherently unstable formation, or from use of an incompatible treatment fluid that liberates fine particles. Unlike sand migration that is best stabilized, the material mobilized in fines migration should be produced to avoid near-wellbore damage.Fines migration causes particles suspended in the produced fluid to bridge the pore throats near the wellbore, reducing well productivity. Fines can include different materials such as clays (phyllosilicates smaller than 4 microns) and silts (silicates or aluminosilicates with sizes ranging from 4 to 64 microns). Kaolinite and illite are the most common migrating clays.Damage created by fines usually is located within a radius of 3 to 5 ft [1 to 2 m] of the wellbore, but can also occur in gravel-pack completions. In sandstone formations, hydrofluoric acid [HF] mixtures are used to dissolve fines. In carbonate formations, the goal is not to dissolve but rather to disperse fines in the wormholes, so hydrochloric [HCl] acid is used as the treatment fluid.

The working platform approximately halfway up the derrick or mast in which the derrickman stores drillpipe and drill collars in an orderly fashion during trips out of the hole. The entire platform consists of a small section from which the derrickman works (called the monkeyboard), and several steel fingers with slots between them that keep the tops of the drillpipe in place.

A condition whereby the interface of two fluids, such as oil and water, bypasses sections of reservoir as it moves along, creating an uneven, or fingered, profile. Fingering is a relatively common condition in reservoirs with water-injection wells. The result of fingering is an inefficient sweeping action that can bypass significant volumes of recoverable oil and, in severe cases, an early breakthrough of water into adjacent production wellbores.

A planar crack penetrated by a well or propagated from a well by hydraulic fracturing with nonzero pressure drop in the fracture during production.

The solution to the diffusion equation that results when the well (inner) boundary condition is treated as a cylinder of finite radius instead of treating the well as a line source.

A method of thermal recovery in which a flame front is generated in the reservoir by igniting a fire at the sandface of an injection well. Continuous injection of air or other gas mixture with high oxygen content will maintain the flame front. As the fire burns, it moves through the reservoir toward production wells. Heat from the fire reduces oil viscosity and helps vaporize reservoir water to steam. The steam, hot water, combustion gas and a bank of distilled solvent all act to drive oil in front of the fire toward production wells.

A method of thermal recovery in which a flame front is generated in the reservoir by igniting a fire at the sandface of an injection well. Continuous injection of air or other gas mixture with high oxygen content will maintain the flame front. As the fire burns, it moves through the reservoir toward production wells. Heat from the fire reduces oil viscosity and helps vaporize reservoir water to steam. The steam, hot water, combustion gas and a bank of distilled solvent all act to drive oil in front of the fire toward production wells.

A mechanical or electronic device used to detonate perforating charges conveyed by tubing, drillpipe, coiled tubing or slickline. This term thus connotes any such device that is not initiated electrically from surface by wireline. A mechanical firing head consists of a percussion detonator that is struck by a firing pin. An electronic firing head is battery powered, to initiate an electric detonator. Electronic firing head systems are used with slickline, coiled tubing and TCP.

The earliest arrival of energy propagated from the energy source at the surface to the geophone in the wellbore in vertical seismic profiles and check-shot surveys, or the first indication of seismic energy on a trace. On land, first breaks commonly represent the base of weathering and are useful in making static corrections.

The depth of the first reliable reading of a curve on a log. For the typical bottom-to-top survey, the curve readings before the tool is picked up from the bottom of the hole are not reliable--they are straight lines that do not represent the formation at the depth indicated. With several logging tools in a tool string, the first reading of each curve will be at a different depth, depending on the measure point of each tool.

A condition of two fluids that are miscible that is, they form a single phase when mixed in any proportion when first brought into contact at a given pressure and temperature. In reservoir gasflooding, the injected gas composition, oil composition, temperature and the injection pressure determine the condition of first-contact miscibility. In contrast, fluids that develop miscibility after exchanging components have multiple-contact miscibility.

The surface electrode used as the reference electrode for the spontaneous potential (SP) measurement. The metal electrode is attached to the end of a long electric cable and typically placed in the mud pit, or, in the case of an offshore rig, in the sea. The SP is a measurement of the natural electrical potential between an electrode in the well and the fixed reference electrode on surface.

A slang term for a globule of partly hydrated polymer caused by poor dispersion during the mixing process (commonly a result of adding the product too fast). Fish eyes are typically 0.2 to 0.5 inches in size and consist of a granule of unhydrated polymer surrounded by a gelatinous covering of hydrated polymer, which prevents water from entering to complete the hydration process. Thus, once formed, fish eyes do not disperse and the product is removed on the shaker screens and wasted.

A series of multilateral well segments that trunk off a main horizontal well. The appearance closely resembles the ribs of a fish skeleton trunking off the main backbone.

What Is Fishing in Wellbore Operations? Fishing encompasses the engineering design and field execution of a downhole intervention to retrieve, mill, or bypass a lost, stuck, or dropped object in the wellbore, using specialized tools deployed on the drill pipe, coiled tubing, or wireline to grip, cut around, or grind the obstructing object so that drilling or production operations can resume. The object being recovered is universally called "the fish," regardless of its size or origin. Key Takeaways Fishing operations begin with a precise physical description of the fish: its outside diameter (OD), inside diameter (ID), top depth, orientation, and condition, typically confirmed with an impression block run before any retrieval tool is deployed. The overshot is the most widely used fishing tool worldwide, running over the outside of the fish and engaging it with an internal grapple; taper taps and spears are used when access to the fish's ID is more practical than its OD. Depth control accuracy is critical: the fishing tool must land within 1 m (3.3 ft) of the fish top to engage correctly; errors in stretch and temperature correction at depth can cause repeated mis-runs and add days of NPT. The break-even decision between continued fishing and sidetracking typically falls at three to five days of fishing time; beyond this threshold, the cost of the sidetrack is usually lower than continued remediation in most day-rate environments. Fishing operations are governed by national regulatory reporting frameworks in every major producing jurisdiction, and fishing time is classified as Non-Productive Time (NPT) in rig efficiency metrics tracked by the IADC, operators, and well insurance underwriters. How Fishing Operations Work A fishing operation begins the moment a piece of equipment is lost in the wellbore. The triggering event may be a drill string parting under excess tension or torsional fatigue, a mud motor or BHA becoming irretrievably stuck, a wireline or slickline breaking and leaving sinker bars and jars at depth, a drill pipe tool joint backing off due to improper torque makeup, or simply a hand tool or tong die falling down the hole during surface operations. The object that remains in the wellbore is the "fish," and every decision in the fishing operation flows from an accurate physical description of that fish. The first tool deployed in almost every fishing operation is the impression block: a short, heavy steel cylinder with a lead face, run to the fish top on the drill string and set down with controlled weight of 5,000 to 15,000 lb (22-67 kN). The lead is soft enough to take an impression of whatever it contacts, and when retrieved to surface, the shape imprinted in the lead tells the fishing engineer the fish's OD or ID, whether it is centered, whether the top is chamfered or squared, and whether there is angular offset from the wellbore axis. This information drives the selection of the primary fishing tool and its inside diameter (for overshots) or outside diameter (for spears and taper taps). Running a fishing tool without an impression block in an unfamiliar fish geometry is a recognized cause of secondary fish creation, where the fishing tool itself becomes stuck. Fishing string assembly follows a standard order from bottom to top: the fishing tool (overshot, spear, or taper tap), then a bumper sub or safety joint that allows the fishing tool to be released if it becomes stuck, then jars (mechanical or hydraulic), then a jar accelerator, then the drill string itself up to the surface. The jars must be correctly positioned above the expected stuck point so they can fire freely even if the fish holds the bottom of the string. The accelerator stores compressive energy to sharpen the jar impact, increasing the peak force delivered to the fish by 20 to 50% compared to the jar alone. Accurate jar placement requires knowing the free-point depth, which is determined by a free-point indicator tool run on wireline before the fishing assembly is made up. Fishing Across International Jurisdictions Canada (Alberta and British Columbia) In Alberta, the Alberta Energy Regulator (AER) Directive 036 requires operators to report drilling incidents including stuck-pipe and fishing operations that exceed thresholds defined in the directive. Extended fishing operations that require well suspension, abandonment, or a sidetrack must be authorized by the AER through a well suspension or abandonment application under the Oil and Gas Conservation Act (OGCA). The AER's Well Event and Reporting System (WERS) captures fishing NPT as a component of drilling performance data published in AER statistical reports. In British Columbia, the BC Energy Regulator (BCER) administers equivalent requirements under the Drilling and Production Regulation. Montney horizontal wells are the highest-frequency context for fishing operations in western Canada: the long laterals, complex BHA configurations, and high wellbore temperatures in the Montney tight silt create elevated risk of drill string failures and mud motor stator failures that require fishing runs. United States (Offshore and Onshore) BSEE administers fishing incident reporting for offshore operations under 30 CFR Part 250. In the Gulf of Mexico (GoM), operators must report any incident that results in significant stuck-pipe or fish left in the wellbore. BSEE requires that an approved drilling program address contingency procedures for stuck pipe and fishing, and any deviation from the approved program during a fishing operation must be reported. GoM deepwater fishing operations are among the most technically demanding in the world: bottom-hole temperatures in the Paleogene Wilcox trend can exceed 300°F (149°C), requiring HPHT-rated fishing tools with temperature-rated elastomers and metal-seal grapples. The American Petroleum Institute (API) publishes Recommended Practice 7G, "Recommended Practice for Drill Stem Design and Operating Limits," which provides guidance on drill pipe fatigue analysis relevant to assessing why a string parted and how to design the fishing assembly. Onshore, the Texas Railroad Commission (RRC) and the Oklahoma Corporation Commission (OCC) require reporting of wells where fish are left in place, which may affect well-spacing, plugging and abandonment (P&A) requirements, and future re-entry permissions. Australia NOPSEMA regulates offshore fishing operations in Australian waters under the OPGGS Act 2006. Operators must notify NOPSEMA of incidents resulting in significant NPT or wellbore integrity risk through the incident reporting framework. The Offshore Petroleum (Resource Management and Administration) Regulations 2011 require an approved well operations management plan (WOMP) that addresses contingency procedures, including fishing. Onshore, the relevant authority varies by state: the Department of Energy and Mining (South Australia) and Department of Resources (Queensland) regulate fishing in the Cooper Basin, where Permian Patchawarra Formation sandstones are drilled with a high frequency of fishing incidents due to hard, abrasive formations that cause elevated bit cone and stabilizer wear. The Cooper Basin's remote location and long logistics chain mean that specialized fishing tool inventories must be pre-positioned at the field workshop before spudding, as mobilizing tools from a metropolitan center to an outback location can add three to five days of NPT. Norway and the North Sea Ptil (Petroleum Safety Authority Norway) oversees well integrity and drilling incident investigation on the Norwegian Continental Shelf (NCS). The NORSOK D-010 standard, "Well Integrity in Drilling and Well Operations," is the primary technical reference for fishing as a component of well integrity risk management in Norway and is widely adopted across the UK North Sea as well. NORSOK D-010 Section 11 addresses stuck pipe, fishing, and sidetrack procedures with specific requirements for documentation, tool qualification, and risk assessment. Ptil requires operators to include fishing contingency planning in the well program and to investigate and report incidents where fish are left in the wellbore. In the UK sector, NSTA (North Sea Transition Authority) requirements under the Energy Act 2016 include well notification requirements for fishing operations that materially deviate from the approved well program. The Brent and Statfjord fields in the Northern North Sea have extensive fishing histories due to their mature infrastructure and the high frequency of re-entry and workover operations on aging wellstock, generating a significant body of North Sea fishing experience that has contributed to modern fishing tool design standards. Middle East (Saudi Arabia and UAE) Saudi Aramco's Well Engineering Manual (WEM) provides detailed procedures for fishing operations in Arab-D carbonate and Khuff Formation clastic and carbonate wells. The WEM specifies mandatory pre-fish characterization steps, approved fishing tool vendors, and escalation protocols if a first fishing run fails. High-pressure, high-temperature (HPHT) conditions in deep Jurassic wells at Ghawar require fishing tools qualified to 350°F (177°C) and 20,000 psi (1,379 bar), which narrows the available tool inventory significantly. Abu Dhabi National Oil Company (ADNOC) applies equivalent standards through its ADNOC-UPST Well Engineering Standards for offshore and onshore fishing in Abu Dhabi. Kuwait Oil Company (KOC) uses its Drilling Engineering Standards Manual for fishing contingencies in the Burgan Field, where unconsolidated Cretaceous Wara sands create a high frequency of sand sloughing and pack-off events that require combined fishing and junk milling approaches. Fast Facts Most common fish type: Drill pipe fish (parted string above or at a tool joint), accounting for approximately 40-50% of all fishing operations by frequency. Impression block lead hardness: Typically Brinell 4-6 (very soft), allowing impression from steel fish under 10,000-15,000 lb (44-67 kN) set-down weight. Overshot catch range: Standard overshots are sized to catch fish ODs from 2 3/8 in (60.3 mm) to 9 5/8 in (244.5 mm); most common sizes are 4-7 in (102-178 mm) for drill pipe fish. Fishing break-even time: 3 to 5 days of fishing NPT typically equals the cost of setting a cement plug and sidetracking, making five days the standard decision threshold. Junk mill WOB: 5,000 to 15,000 lb (22-67 kN) weight on bit for tungsten carbide insert (TCI) junk mills; higher WOB can fracture the mill face and create additional junk. Deepwater GoM rig day rates: $350,000 to $600,000/day for drillships; each day of fishing NPT adds this cost directly to the well AFE. Wireline fishing depth accuracy: Commercial free-point tools are accurate to ±50 ft (±15 m) in cased hole; differential stretch calculations refine this to ±10 ft (±3 m) in open hole.

(noun) A cylindrical fishing tool run on the end of a drillstring or wireline to engage and retrieve small lost objects or debris from the wellbore. The bell-shaped catching mechanism is lowered over the fish and uses friction, spring fingers, or a taper to grip and extract the item.

A diagram noting the major profiles and dimensions of tools and equipment run into a wellbore. A fishing diagram should be prepared for every tool operation, enabling contingency plans to be implemented efficiently if the tool string becomes stuck or lost.

The surface on which a fishing tool engages when retrieving tubing, tools or equipment stuck or lost in a wellbore. Tools and equipment that are temporarily installed in a wellbore are generally equipped with a specific fishing-neck profile to enable the running and retrieval tools to reliably engage and release.

What Is a Fishing Tool? A fishing tool is a specialized downhole device run on drillpipe or wireline to locate, grip, and retrieve equipment that becomes lost or stuck inside a wellbore. Operators deploy fishing tools across every drilling environment, from shallow onshore wells in Alberta's Montney formation to deepwater Gulf of Mexico and Norwegian North Sea high-pressure, high-temperature (HP/HT) wells. Key Takeaways A fishing tool grips, mills, or otherwise recovers any downhole object, called a "fish," that obstructs normal wellbore operations or cannot be retrieved through conventional means. Fishing tools divide into four principal classes: diagnostic tools, inside grappling devices (spears), outside grappling devices (overshots), and force intensifiers such as jars and bumper subs. The decision to fish rather than sidetrack the well involves a formal economics comparison; industry practice generally favors sidetracking when fishing operations exceed three to five days without recovering the fish. Regulators in Canada, the United States, Australia, and Norway require operators to report lost-in-hole incidents, and some jurisdictions mandate that the well not be abandoned while metallic debris remains in a producing zone. Service companies including Halliburton, Baker Hughes (part of Baker Hughes Company), NOV (National Oilwell Varco), and Weatherford International provide the full range of fishing tools, rental assemblies, and technical supervisors known as "fishermen." How a Fishing Tool Works Fishing operations begin with a diagnostic phase. The driller and company man review the drillstring inventory to determine what is in the hole, its outer diameter (OD) and inner diameter (ID), and its approximate depth. An impression block, a short steel sub fitted with a lead or soft-alloy face, is run to the fish top, pressed firmly against it, and retrieved. The lead face retains a negative impression of the fish profile, confirming whether the top is clean and centered, off-center, or collapsed. In modern wells, downhole cameras and ultrasonic imaging tools can supplement or replace the impression block, providing video feed or acoustic cross-sections that identify the fish condition and help the engineer select the correct grappling tool. Once the fish geometry is confirmed, the fishing engineer selects from the tool classes described below. Inside grappling devices such as spears enter the fish bore, expand, and latch onto the internal profile. Outside grappling devices called overshots slip over the outside of the fish and contract to grip its OD. Both are connected to a string of drill collars and drillpipe that transmits the mechanical load to surface. If straight overpull cannot free the fish, a jar assembly is added to the string. Hydraulic jars or mechanical jars deliver high-impact upward or downward blows measured in thousands of pounds-force. Hydraulic jars, for example, typically require a trip load of 20,000 to 50,000 lbf (89 to 222 kN) above normal string weight before the jar fires, delivering a short-duration impact force that can reach several hundred thousand pounds-force at the fish. Accelerators, also called bumper subs, are placed above the jar to add stored elastic energy to each stroke, increasing impact severity. When mechanical recovery fails after multiple jar runs, the engineer may order a washover operation. Washover pipe is a large-OD, thin-wall tubular run over the outside of the fish. A rotary shoe or mill at the bottom of the washover string grinds through any cement, debris, or formation that has packed around the fish, freeing it for subsequent grapple recovery. If the fish cannot be recovered at all, milling destroys it in place, grinding it into fine cuttings circulated to surface with drilling fluid. Milling is the last resort because it is slow, consuming expensive rig time, and may leave small fragments that complicate later completion operations. Fishing Tool Across International Jurisdictions Canada: Alberta Energy Regulator and Prairie Provinces In Alberta, the Alberta Energy Regulator (AER) governs lost-in-hole reporting under Directive 059 (Well Drilling and Completion Data Filing Requirements) and Directive 008 (Surface Casing Depth Requirements). Operators must report any equipment lost in the wellbore as part of their well completion or abandonment report. The AER requires that metallic debris in a wellbore not impair long-term zone isolation, meaning the licensee must demonstrate either successful recovery or adequate cement plug placement over the fish before the well is approved for abandonment. In the Montney play of northeast British Columbia and northwest Alberta, pad drilling with dozens of wells per surface location means a fishing incident on one well can delay the entire pad schedule, amplifying the economic urgency of fast recovery decisions. British Columbia's Oil and Gas Commission (OGC, now the Energy Regulator) follows analogous reporting requirements under the Drilling and Production Regulation. United States: BSEE Offshore and State Regulators Onshore The Bureau of Safety and Environmental Enforcement (BSEE) regulates offshore fishing operations on the US Outer Continental Shelf. Under 30 CFR Part 250, operators must report any wellbore incident, including lost tools, to the district manager within specific time windows. BSEE Notices to Lessees (NTLs) provide supplemental guidance on well control during fishing operations, emphasizing that the blowout preventer (BOP) must remain in a tested and operable condition throughout the fishing job. In the deepwater Gulf of Mexico, where a single rig day can cost $500,000 USD or more, the economics of fishing versus sidetracking are evaluated rapidly. Onshore, state oil and gas commissions (Texas Railroad Commission, Colorado OGCC, North Dakota Industrial Commission) require incident reporting at the well completion filing stage. Australia: NOPSEMA Australia's National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) requires titleholders operating under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 to maintain a Well Operations Management Plan (WOMP) that explicitly addresses well integrity during fishing operations. Any event that affects well integrity, including a fish left in hole that prevents proper zonal isolation, triggers a mandatory notification to NOPSEMA. NOPSEMA inspectors audit WOMPs for adequacy of contingency procedures, which must include fishing and milling plans for the most common failure scenarios on each well type. Norway: Sodir The Norwegian Offshore Directorate (Sodir, formerly the Norwegian Petroleum Directorate) and the Petroleum Safety Authority Norway (PTIL) jointly oversee well integrity on the Norwegian Continental Shelf. PTIL's Well Integrity Regulation and the NORSOK D-010 standard (Well Integrity in Drilling and Well Operations) define minimum requirements for the maintenance of well barriers during all drilling phases, including fishing. Under NORSOK D-010, operators must maintain at least one well barrier at all times, meaning that while a fish obstructs the wellbore, the BOP or a retrievable packer below the fish must serve as the primary barrier. Norwegian HP/HT wells in the Barents Sea and in fields such as Kristin and Kvitebjorn involve elevated wellbore temperatures (above 150 degrees Celsius, 302 degrees Fahrenheit) and pressures that make elastomer seal performance in fishing tools critical, often requiring metal-to-metal seal connections rated above 15,000 PSI (1,034 bar). Middle East: Saudi Aramco and Gulf Operator Standards In Saudi Arabia, Saudi Aramco's internal well engineering standards (SAES) govern fishing operations on its vast onshore and offshore portfolio. Aramco's deep sour gas wells in fields such as Hawtah and Khuff require corrosion-resistant fishing tool materials, including 13% chromium or duplex stainless steel components, because standard carbon steel spears and overshots degrade rapidly in hydrogen sulfide (H2S) environments. The Abu Dhabi National Energy Company (TAQA) and Abu Dhabi National Oil Company (ADNOC) follow similar protocols on offshore platforms in the Arabian Gulf, with fishing operations coordinated through their respective drilling departments and contracted to service companies under long-term agreements. Fast Facts A single lost bottom-hole assembly (BHA) in a deepwater Gulf of Mexico well can cost the operator between $3 million and $10 million USD in fishing time and potential sidetrack drilling, based on published industry case studies from the 2010s through 2020s. The global fishing tool services market was estimated at over $1.2 billion USD in annual revenue as of recent industry reports, driven by the complexity of horizontal and extended-reach wells. Impression blocks have been used in oil well fishing operations since the 1920s; modern lead-faced blocks remain the fastest, lowest-cost diagnostic method for straightforward fish identification.

(noun) A mathematical or statistical model whose parameters have been calibrated to match observed data from a reservoir, well test, or production history. Fitted models are used in reservoir simulation, decline curve analysis, and pressure transient interpretation to predict future performance.

A variogram or semivariogram is said to have been fitted after the best possible model has been applied to it.

An injection pattern in which four input or injection wells are located at the corners of a square and the production well sits in the center. The injection fluid, which is normally water, steam or gas, is injected simultaneously through the four injection wells to displace the oil toward the central production well.

A device used to control the flow of fluids by directing flow through a restriction or hole of a fixed size. The fluid characteristics and the pressure differential across the choke determine the flow rate through a fixed choke.

An acquisition technique commonly used in electromagnetic methods whereby the energy source or transmitter is kept in the same position, and detectors or receivers are moved to different spots to compile a profile or map.

A mark or marker applied to a sand line or similar wire rope to indicate a specific depth or as a means of indicating the end of the line is nearing surface during retrieval. The term may also be used for magnetic or physical marks applied to wireline or coiled tubing strings.

A joint of tubing or casing included in the string at a known position to provide a reference point for further operations. A short pup joint that registers clearly in a collar locator log is a common flag joint.

A type of lost-circulation material that is thin and flat in shape, with a large surface area. Flake LCM can be prepared in various sizes. It should be insoluble and inert to the mud system in which it is used. Its purpose is to seal off fluid loss zones in a well and help stop lost circulation. Mica flakes and pieces of plastic (cellophane) sheeting are commonly used. Often, granular, flake and fiber LCMs will be mixed into one LCMpill and pumped into the zone where losses are occurring.

A type of lost-circulation material that is thin and flat in shape, with a large surface area. Flake LCM can be prepared in various sizes. It should be insoluble and inert to the mud system in which it is used. Its purpose is to seal off fluid loss zones in a well and help stop lost circulation. Mica flakes and pieces of plastic (cellophane) sheeting are commonly used. Often, granular, flake and fiber LCMs will be mixed into one LCM pill and pumped into the zone where losses are occurring.

A connection profile used in pipe work and associated equipment to provide a means of assembling and disassembling components. Most oilfield flanges feature a bolt-hole pattern to allow the joint to be secured and a gasket profile to ensure a pressure-tight seal. The design and specification of a flange relates to the size and pressure capacity of the equipment to which it is fitted.

To finish an operation or process (slang).

A check valve that has a spring-loaded plate (or flapper) that may be pumped through, generally in the downhole direction, but closes if the fluid attempts to flow back through the drillstring to the surface. This reverse flow might be encountered either due to a U-tube effect when the bulk density of the mud in the annulus is higher than that inside the drillpipe, or a well control event.

An arrangement consisting of a vertical tower and burners used to burn combustible vapors. A flare is usually situated near a producing well or at a gas plant or refinery. A flare is also called a flare stack.

A vapor or gas that is burned through a pipe or burners.

The lowest temperature at which application of a flame to the test chamber of a tester causes vapors of the sample in the chamber to ignite. The test can be applied to base fluids being considered for use in an oil mud or a synthetic mud or to any flammable liquid to determine at what temperature an explosion hazard exists. Test methods, established by API and ASTM, include open-cup and closed-cup tests.

The situation in which 10-second and 10-minute gel strengths for a drilling mud have similar values. Flat gels indicates that the mud will remain pumpable with time if left static in the hole. However, if gel values are too low, baritesag or solids settling is likely.

A seismic section that has been redisplayed such that a reflection of interest not horizontal in the original display appears horizontal and flat. Such displays can shed light on geological conditions at the time a given sedimentarylayer accumulated.

A type of acoustic propagation along the borehole that is visualized as a shaking of the borehole across its diameter. The flexural mode is excited by a dipolesource, and measured by dipole receivers oriented in the same direction. Its speed is chiefly a function of the formation shear velocity, the borehole size and fluid velocity, and the frequency. It is used to estimate formation shear velocity, and is the only technique available in slow formations where shear velocity is less than borehole-fluid velocity. In this situation, shear head waves are not generated by a monopole source, so that standard monopole techniques cannot be used. The flexural wave is sensitive to properties of the altered zone, as well as to formation anisotropy, whether intrinsic or stress-induced.

What Is a Float Collar? A float collar is a short casing sub installed 1 to 2 joints above the guide shoe at the bottom of a casing string, containing an internal check valve that permits cement slurry to be pumped downward through the casing and into the annulus while preventing backflow of cement from the annulus back into the casing bore after displacement is complete. Key Takeaways The float collar's check valve arrests the U-tube effect: after pumping stops, the denser cement column in the annulus would otherwise drain back into the lighter mud or spacer inside the casing, diluting and contaminating the cement sheath before it sets. The float collar acts as the primary landing seat for the bottom wiper plug (displacement plug) pumped ahead of the cement slurry, separating the cement from the preceding spacer fluid and preventing slurry contamination. After the top wiper plug "bumps" the float collar, the resulting pressure increase at surface is the primary signal that displacement is complete; operators then apply the maximum allowable surface pressure to pressure-test the float valve for 10 to 15 minutes before releasing. Autofill (fill-up) float collars include a secondary mechanism that allows wellbore fluid to enter the casing while running in hole, reducing surge pressure on weak formations, and then converts to a standard float when a ball or plug is dropped. API Specification 10F (Performance Testing of Cementing Float Equipment) governs design, material, and pressure and temperature testing requirements for float collars and float shoes across the industry. How a Float Collar Works The float collar is positioned one to two joints above the guide shoe, a spacing of approximately 9 to 18 m (30 to 59 ft), to create a sump volume below the float collar. This sump catches any contaminated cement or debris that accumulates at the shoe during cementing and keeps it below the critical cemented interval, preventing it from being swept back up into the producing zone. The check valve inside the float collar body opens under downward hydraulic pressure when the cement slurry or displacement fluid is being pumped, allowing full flow through the casing bore. When pumping stops or reverses, differential pressure from the heavier annular cement column closes the valve, holding the cement column in place in the annulus while the cement hydrates and gains compressive strength. The cementing sequence with a float collar proceeds in a defined order. First, a bottom wiper plug (the "go-ahead" plug) is released from the cementing head at surface. This plug travels down the casing ahead of the cement slurry, wiping residual drilling fluid off the casing ID wall and separating the preceding spacer fluid from the cement. The bottom plug is a hollow plug fitted with a rupture membrane. When it reaches the float collar and lands on the seat, the pressure spike causes the membrane to rupture, opening a channel that allows cement slurry to flow through the plug and downward past the float valve, out the guide shoe, and up into the annulus. The cement slurry then fills the annulus upward from the shoe to the desired top-of-cement (TOC) depth. Once the calculated volume of cement slurry has been pumped, the top wiper plug (the "shut-off" plug) is released from the cementing head. The top plug is a solid plug that travels down the casing behind the cement slurry, pushed by displacement fluid (usually the same drilling fluid or a weighted kill-weight fluid), wiping the last of the cement from the casing ID. When the top plug seats on the float collar, no more fluid can pass through the valve. Pressure at the surface builds sharply (the "bump pressure"), and the surface pressure gauge shows a distinct inflection that confirms the top plug has landed. The operator then applies a test pressure, typically 3.5 to 7.0 MPa (500 to 1,000 psi) above displacement pressure, and holds it for 10 to 15 minutes. If the float collar's check valve is functioning correctly, pressure holds with less than 0.35 MPa (50 psi) bleed-off. Pressure holding confirms cement integrity below the float collar and allows the well to enter the wait-on-cement (WOC) period with confidence. Float Collar Across International Jurisdictions The float collar is recognized by well integrity regulations worldwide as a critical component of the primary cementing barrier system. Regulatory bodies across the major producing regions incorporate float collar design, testing, and operational requirements into their well program approval processes. Canada (Alberta): The Alberta Energy Regulator (AER) Directive 009 governs primary cementing requirements for all wells drilled under AER jurisdiction, including surface, intermediate, and production casing programs across the Western Canadian Sedimentary Basin. Directive 009 requires operators to document cementing program design, including float collar specification and position, as part of the well licensing and cementing report. For horizontal wells targeting the Montney siltstone in northeast British Columbia and northwest Alberta, AER and the BC Oil and Gas Commission (BC OGC) jointly issue technical requirements for multi-stage cementing programs where float collar function is critical at each stage. The Montney's low fracture gradient requires precise control of equivalent circulating density (ECD) during cementing, making autofill float collar technology common to manage surge and swab pressures while running long casing strings. After cementing, operators must file a cementing report with the AER confirming float collar landing and pressure test results. United States (Offshore and Onshore): Offshore, the Bureau of Safety and Environmental Management (BSEE) regulates cementing equipment under 30 CFR Part 250 Subpart B. Float collar requirements are embedded in the casing and cementing program submitted as part of the well drilling permit. The post-Macondo Well Control Rule (2016) heightened BSEE's focus on float equipment performance: the Macondo investigation found that the float collar was not properly tested and may not have converted, contributing to the blowout sequence. BSEE now mandates that operators document float collar pressure testing methodology and results in the well completion report. Onshore, state oil and gas commissions (the Texas Railroad Commission, Colorado OGCC, Wyoming OGC) have varying requirements; most require cementing job reports and may require cement bond logging in environmentally sensitive areas such as those overlying critical aquifers, where float collar performance and cement top-of-cement verification are closely scrutinized. Australia: The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) requires a Well Operations Management Plan (WOMP) for all offshore petroleum operations on the Australian continental shelf, including the prolific Carnarvon Basin, Browse Basin, and Bass Strait. The WOMP must identify all well barrier elements, of which the float collar is one, and define their design, testing, and acceptance criteria. NOPSEMA's well integrity guidelines align with NORSOK D-010 in treating cement as a primary barrier element. Float collar specifications for deepwater wells in the Carnarvon Basin, such as those drilled for Woodside's LNG operations, must be rated for the combination of water depth hydrostatic pressure, formation temperature at depth, and HPHT completion conditions characteristic of deepwater Triassic reservoirs. API 10F testing documentation is required as part of the equipment conformance record. Norway and the North Sea: NORSOK Standard D-010 (Well Integrity in Drilling and Well Operations, latest revision) classifies cement, including the float collar sub-system, as part of the first primary well barrier during cementing operations. D-010 requires all well barrier components to be documented and verified before the well can proceed to the next phase. The Norwegian Offshore Directorate (NOD) and the UK Health and Safety Executive (HSE) for UKCS operations require post-cementing pressure tests of the float collar system with defined acceptance criteria for pressure hold duration and bleed-off tolerance. In the North Sea's challenging HPHT environment, particularly in Eldfisk, Ekofisk, and Kristin field wells on the Norwegian Continental Shelf, float equipment must be rated to at least 138 MPa (20,000 psi) working pressure and temperatures exceeding 175 degrees C (347 degrees F). Premium float collar designs featuring high-chrome alloy seats and Viton or Aflas elastomer seals are standard in these environments. Middle East: Saudi Aramco Standard SAES-D-007 and Aramco Drilling Program standards specify float collar position, valve type, and pressure rating for all casing programs across the kingdom's fields. In the Ghawar anticline, the world's largest conventional oil field, horizontal completions targeting the Arab D carbonate reservoir routinely exceed 6,000 m (19,685 ft) measured depth, requiring float collar designs that can withstand the combined mechanical loads of running long horizontal casing strings and the hydrostatic and thermal cycling of HPHT completion operations. Kuwait Oil Company (KOC) and Abu Dhabi National Oil Company (ADNOC) maintain similar SAES-equivalent internal standards. In the UAE's offshore fields, including ADNOC's Upper Zakum field being developed with artificial island and extended-reach drilling technology, float collar placement relative to the liner hanger and stage cementing tools is a critical element of the completion design reviewed by ADNOC's Well Engineering teams. Fast Facts Standard position: 1 to 2 joints above the guide shoe, creating a sump of 9 to 18 m (30 to 59 ft) to contain shoe-end debris and contaminated cement. Plug landing confirmation: Top plug bump typically produces a 3.5 to 7.0 MPa (500 to 1,000 psi) surface pressure increase above displacement pressure; the signal must be unambiguous before WOC begins. Governing API standard: API Specification 10F, "Performance Testing of Cementing Float Equipment," defines test methodology at temperature, pressure, and differential load for all float collar and float shoe designs. Typical float collar ID: Matches casing drift ID to allow passage of perforation guns, wireline tools, and completion hardware after cementing. HPHT ratings: Standard float collars are rated to 69 MPa (10,000 psi) and 121 degrees C (250 degrees F); premium designs reach 138 MPa (20,000 psi) and 204 degrees C (400 degrees F) for deep HPHT wells. Float collar failure rate: Industry studies estimate float valve failures at 2 to 5% of jobs, most attributed to debris on the valve seat or improper installation; failure requires remedial squeeze cementing.

A full-sized length of casing placed at the bottom of the casing string that is usually left full of cement on the inside to ensure that good cement remains on the outside of the bottom of the casing. If cement were not left inside the casing in this manner, the risk of overdisplacing the cement (due to improper casing volume calculations, displacementmud volume measurements, or both) would be significantly higher. Hence, the well designer plans on a safety margin of cement left inside the casing to guarantee that the fluid left outside the casing is good-quality cement. A float collar is placed at the top of the float joint and a float shoe placed at the bottom to prevent reverse flow of cement back into the casing after placement. There can be one, two or three joints of casing used for this purpose.

A rounded profile component attached to the downhole end of a casing string. An integral check valve in the float shoe prevents reverse flow, or U-tubing, of cementslurry from the annulus into the casing or flow of wellbore fluids into the casing string as it is run. The float shoe also guides the casing toward the center of the hole to minimize hitting rock ledges or washouts as the casing is run into the wellbore. The float shoe reduces hook weight. With controlled or partial fill-up as the string is run, the casing string can be floated into position, avoiding the need for the rig to carry the entire weight of the casing string. The outer portions of the float shoe are made of steel and generally match the casing size and threads, although not necessarily the casing grade. The inside (including the taper) is usually made of cement or thermoplastic, since this material must be drilled out if the well is to be deepened beyond the casing point.

A coagulated mass of particles in a liquid. Flocs can occur naturally but often are generated from a dispersed colloidal system to which a flocculant chemical has been added. Clay particles and polymers in water can be flocculated to form flocs.

A chemical that causes a dispersed colloidal system (such as clay) to coagulate and form flocs. Most flocculants are either multivalent cations such as calcium, magnesium and aluminum, or long-chain polymers. High pH, high salinity and high temperature can also cause clay flocculation.

The aggregation of small particles into larger particles. In the context of heavy oil, asphaltenes are known to flocculate at the molecular level (before precipitation) and in the precipitated state. The extent of asphaltene flocculation changes with fluid composition, temperature and pressure. For precipitated asphaltenes, flocculation is also affected by the shear environment.

A surface exhibiting evidence of an abrupt increase in water depth, separating younger from older strata. The surface may also display evidence of minor submarine erosion. It forms in response to an increase in water depth and typically bounds parasequences. In sequence stratigraphic terminology, it replaces the older, more generic term "trangressive surface," although it is not a strict equivalent.This term is also used as a short version of the terms maximum flooding surface or marine flooding surface.

A type of deliverability test conducted in gas wells to generate a stabilized gas deliverability curve (IPR). In a flow-after-flow test, a well flows under a constant rate until it reaches stabilized conditions (pseudosteady state). After the stabilized rate and pressure are recorded, the rate is changed and the well flows until pressure stabilizes again. The same procedure is repeated three or four times. The stabilization requirement is an important limitation of this type of test, especially in low-permeability formations, which require longer stabilization times. This test is also known as a backpressure or four-point test.

The process of allowing fluids to flow from the well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production.

A test performed to ensure stable well conditions or the integrity of a plug, valve or flow-control device. In most cases, the flow check involves observing stable fluid levels or conditions for a prescribed period.

A relatively short, heavy-walled completion component installed in areas where turbulence is anticipated. The additional wall thickness prevents early failures due to erosion in the turbulent flow area. Flow couplings are typically installed above and below completion components, such as landing nipples, that may affect the flow.

The value that results when the actual productivity index is divided by the productivity index predicted from Darcy's law. Flow efficiency is greater than 1 in a stimulated well (skin 0).

A surface pipeline carrying oil, gas or water that connects the wellhead to a manifold or to production facilities, such as heater-treaters and separators.

A laboratory instrument for investigating the characteristics of fluid flow in pipes and for studying the response of productionlogging instruments to this flow. The fluids are circulated continuously in a loop, passing through one main measurement section that can be placed at different deviations from vertical through horizontal. Fluid properties, holdups and velocities can all be varied. Flow loops are essential for the study of multiphase flow and the development of new production logging measurements.

A model of a reservoir in which the steady-state flow and the advective transport are described in two or three dimensions by a computer program. A flow model is an essential component of a reservoir simulator. Flow models are often derived from the petrophysical characteristics of a reservoir (especially porosities and permeabilities) and then the model is adjusted and refined until it correctly predicts the reservoir's past behavior and can match the historical pressure and production data.

Part of a well test when the well is flowing. It is usually specified prior to tests to ensure that a stable flow situation has been reached, or that the pressure disturbance has reached far enough into the formation to allow determination of a representative value for kh, or that any nearby boundaries could be recognized in a subsequent buildup.

A recording of the in-situ rate of fluid flow at different depths in a well, normally one completed for production or injection. The flow profile is a log recorded in a unit such as barrels per day, or as a percentage of the total flow from the reservoir in a production well or into the reservoir in an injection well. In single-phase flow, the profile can be determined from a flowmeter. In multiphase flow, it is desirable to show the flow rates of each of the phases, in which case a holdup log and either a flowmeter or a phase velocity log are needed.

A description of the geometrical distribution of a multiphase fluid moving through a pipe. Many different terms are used to describe this distribution, the distinction between each one being qualitative and somewhat arbitrary. In vertical or moderately deviated pipes, the most common flow regimes for gas-liquid mixtures are bubble flow, dispersed bubble flow, plug flow, slug flow, froth flow, mist flow, churn flow and annular flow. For oil-water mixtures, the most common regimes are bubble flow, slug flow and emulsion flow. In horizontal wells, there may be stratified or wavy stratified flow in addition to many of the regimes observed in vertical wells.Two-phase flow regimes have often been presented as plots, or maps, with the phase velocities or functions of them on each axis. Earlier maps were named after their authors, for example Griffith-Wallis, Duns-Ros and Taitel-Dukler.

The dynamic simulation of fluids through a reservoirmodel over time. When the simulation correctly recreates the past reservoir performance, it is said to be "history matched," and a higher degree of confidence placed in its ability to predict the future fluid behavior in the reservoir.

A description of the geometrical distribution of a fluid moving through a pipe. The term is similar to the term flow regime, but is used to describe larger scale features in which there may be more than one flow regime. For example, in a deviated well there may be bubble flow of gas in oil in the uppermost part of the pipe, and water only in the lowest part.

A rock volume with identifiable fluid flow characteristics that can be modeled, including heterogeneity or anisotropy.

Gas-well tests, often required by law, in which one flow rate immediately follows another, with each flow period reaching stabilized flow. The bottomhole pressure at the end of each flow period is used to calculate gas-well deliverability.

Referring to a type of spinner flowmeter in which most or all of the fluid flow in the well is diverted over the spinner by a device such as a basket or a packer.

Folded structures associated with strike-slip faults. In areas where strike-slip faults occur in converging crust, or transpression, rocks are faulted upward in a positive flower structure. In areas of strike-slip faulting in diverging crust, or transtension, rocks drop down to form a negative flower structure. Flower structures can form hydrocarbon traps. The term "flower structure" reflects the resemblance of the structure to the petals of a flower in cross section.

A neutron porosity log recorded while the well is flowing to determine the gas-oil contact in the borehole. The log is often compared with a log run while the well is shut-in. The term was used in the1950s and 1960s but is now obsolete.

The pressure determined at the formation face during the flowing periods of a well test.

(noun) A well that produces oil, gas, or other reservoir fluids to the surface under natural reservoir pressure without the need for artificial lift equipment such as a beam pump, electric submersible pump, or gas lift system.

A surface pipeline carrying oil, gas or water that connects the wellhead to a manifold or to production facilities, such as heater-treaters and separators.

A pipe fitting with several lateral outlets for connecting flowlines from one or more wells. This connection directs flow to heater-treaters, separators or other devices.

A mud sample that exits directly out of the well from the annulus and is caught before it passes through the shale-shaker screens. A flowline mud sample contains drill cuttings entrained in the mud.

An instrument that measures the flow rate of fluids through a pipeline. There are several types of flowmeters, including the differential-pressuremeter, orifice meter, positive-displacement meter, vortex meter and multiphase meters.

The flow of oil, gas or water through a pipe.

The fluid sample from the wellhead that is used to analyze the composition of the flow. The term is analogous to the term flowline sample, except that it refers to the production part of the flowstream.

A gas generated by burning hydrocarbons with air; it is sometimes used as an enhanced oil recovery (EOR) injectant. The composition consists mainly of nitrogen, carbon dioxide, water vapor and excess oxygen with some impurities, such as carbon monoxide, nitrogen oxides and sulfur oxides. Generally, more carbon dioxide in the flue gas results in a better recovery factor for EOR. By contrast, using more nitrogen results in a lower recovery factor for EOR. However, high concentration of impurities, such as oxygen, nitrous oxides and carbon monoxide, can cause corrosion in productiontubulars and surface equipment.

A test, or series of tests, performed to check that no undesirable reactions occur with a specific fluid. The testing process may include checks for compatibility with other treating fluids, wellbore fluids, reservoir fluids and the reservoir formation. In extreme cases, the mixing of seemingly benign fluids can create significant reactions that may damage the reservoir permeability permanently.

The relative change in fluid volume related to a unit change in pressure. This is usually expressed as volume change per unit volume of fluid per psi of pressure change. Gas has higher compressibility than liquid (oil or water).

The interface that separates fluids of different densities in a reservoir. Horizontal contacts are usually assumed, although tilted contacts occur in some reservoirs. The contact between fluids is usually gradual rather than sharp, forming a transition zone of mixed fluid. A mixed-fluid reservoir will stratify according to fluid density, with gas at the top, oil in the middle, and water below. Production of fluids often perturbs the fluid contacts in a reservoir.

The movement of fluid through pores and fractures within permeable rocks in a reservoir. Generally, the fluid flow is assumed to follow Darcy's law, so the fluid flow may be simulated with a model of the reservoir.

A general term to describe the presence of a particular fluid in an undesirable area, such as the movement of drilling mud into a section of the reservoirformation.

The depth, or distance from surface, that the fluid in a well incapable of natural flow will reach under static conditions.

The leakage of the liquid phase of drilling fluid, slurry or treatment fluid containing solid particles into the formationmatrix. The resulting buildup of solid material or filter cake may be undesirable, as may the penetration of filtrate through the formation. Fluid-loss additives are used to control the process and avoid potential reservoirdamage.

The act or means of controlling (usually lowering) the volume of filtrate that passes through a filtermedium. Control of fluid loss for a mud is achieved by several means, one of which is by addition of fluid-loss-control materials to the mud system. Another is to change the mud chemistry to make the materials already present work better. Adding a claydeflocculant to freshwater mud typically improves fluid-loss control.

A group of mud additives specifically designed to lower the volume of filtrate that passes through a filtermedium. Specific materials are available for all types of water- and oil-base mud systems and are evaluated in static filtration tests or in various dynamic filtration tests.

A phenomenon that occurs when the downhole pump rate exceeds the production rate of the formation. It can also be due to the accumulation of low-pressure gas between the valves. On the downstroke of the pump, the gas is compressed, but the pressure inside the barrel does not open the traveling valve until the traveling valve strikes the liquid. Finally when the traveling valve opens, the weight on the rod string can suddenly drop thousands of pounds in a fraction of a second. This condition should be avoided because it causes extreme stresses, which can result in premature equipment failure. Slowing down the pumping unit, shortening the stroke length or installing a smaller bottom hole pump can correct this problem.

A tool run on wireline to obtain fluid samples and measure formation pressures. This device is also called a wireline formation tester.

A record of the density, or changes in density, of fluids in a production or injection well. Since gas, oil and water all have different densities, the log can determine the percentage, or holdup, of the different fluids, directly in the case of biphasic flow, and in combination with other measurements for triphasic flow. Fluid density is measured by a gradiomanometer or a nuclear fluid densimeter, and can also be derived from the depth derivative of a pressure sensor.

A chemical additive that alters fluid rheological properties to reduce friction created within the fluid as it flows through small-diameter tubulars or similar restrictions. Generally polymers, or similar friction reducing agents, add viscosity to the fluid, which reduces the turbulence induced as the fluid flows. Reductions in fluid friction of 50 to 60% are possible.

An in-situ measurement of the flow profile made by pumping different fluids down the tubing and casing and observing the interface between them. The fluids are normally both water, but one may be fresh and the other salty, or else one may contain some tracer, so that the interface can be detected by a production-logging tool. After the tubing is run to the bottom of the well, an interface is introduced by one of two methods. In the static method, the total flow rate is held constant and the relative flow rate of the two streams is changed. The location of the interface after each change is used to determine the flow profile. In the dynamic method, one fluid is pumped at different rates. The log was used in the 1950s and 1960s but is now used rarely, having been replaced by fluid-density logs and others.

A chemical additive used to control the loss of fluid to the formation through filtration. In cementing operations, loss of the aqueous phase can severely affect the performance of the slurry and set cement. In almost any operation, loss of fluid to the reservoir formation carries a high risk of permeabilitydamage.

The act or means of controlling (usually lowering) the volume of filtrate that passes through a filter medium. Control of fluid loss for a mud is achieved by several means, one of which is by addition of fluid-loss-control materials to the mud system. Another is to change the mud chemistry to make the materials already present work better. Adding a claydeflocculant to freshwater mud typically improves fluid-loss control.

A group of mud additives specifically designed to lower the volume of filtrate that passes through a filter medium. Specific materials are available for all types of water- and oil-base mud systems and are evaluated in static filtration tests or in various dynamic filtration tests.

An acid mixture that generates more hydrofluoric [HF] acid as the HF is consumed. In the field, fluoboric acid [HBF4] is easily prepared by mixing boric acid [H3BO3], ammonium bifluoride [NH3F.HF] and hydrochloric acid. Fluoboric acid was developed to counteract the shortcomings associated with mud-acid treatments. It is a retarded fluid that can penetrate deep into the reservoir before spending, especially at high temperatures, and does not contain high HF at any given time. Thus, it is less reactive than mud acid, but its total dissolving power is comparable:HBF4 + H3O --> HBF3OH + HF.The limited amount of HF at any given time decreases the probability of forming precipitates of fluosilicates, fluoaluminates or silica. Fluoboric acid provides permanent stabilization of clays and fines through reactions related to borate and fluoborate ions. For example, borosilicates coat and bind undissolved clays and fines, preventing further mobility of these particles that might plug the formation and impair production. Mud acid does not provide this coating feature. Fluoboric acid also eliminates water sensitivity and is especially recommended in formations containing potassium minerals.Fluoboric acid can be used as a preflush, an overflush or as a main stage in a sandstonematrixacidizing. As a main fluid, a fluoboric acid treatment requires a preflush (weak HCl acid or brine) and should not be overflushed to obtain the maximum stabilization effect in the critical matrix area. Fluoboric acid treatments are the only acid formulations that require long shut-in times because of their long reaction times.

A technique for imaging a core by moving a core between a source of X-rays and a fluorescent screen. The image on the screen is intensified and recorded by a video camera.

A type of tubing connection in which the internal or external surfaces are the same diameter throughout the tubing joint. Internal flush joints are most common, offering no restriction to fluid flow. Externally flush joints are typically used in more specialized applications, such as washover pipe for fishing operations, to allow adequate outer diameter (OD) clearance.

A high flow rate reached with a new well.

The volume close to the borehole wall in which all of the moveable fluids have been displaced by mudfiltrate. The flushed zone contains filtrate and the remaining hydrocarbons, the percentage of the former being the flushed-zone water saturation, Sxo. In simple models, the flushed zone and the invaded zone are synonymous.

The fraction of water in a given pore space in the flushed zone. It is expressed in volume/volume, percent or saturation units and is given the symbol Sxo. Unless otherwise stated, the pore space concerned is usually the effective porosity. If the pore space concerned is the total porosity, the saturation is more correctly known as the total flushed-zone water saturation; or if it is the effective porosity, the effective flushed-zone water saturation.

Pertaining to an environment of deposition by a river or running water. Fluvial deposits tend to be well sorted, especially in comparison with alluvial deposits, because of the relatively steady transport provided by rivers.

A distortion of the magnetic flux that has been introduced into a casing by a low-frequency electromagnet or permanent magnet. The principle of flux leakage is used to detect casing corrosion, since flux leakage is caused by rapid changes in the thickness of the casing and by pits and holes in either the internal or external wall. Flux leakage distorts the magnetic-flux lines and induces a signal into an electric coil moving past it. In-situ flux-leakage measurements make use of this effect by placing coils on or close to the casing wall, azimuthally distributed to cover the entire wall. The results are often combined with a high-frequency, eddy-current measurement, designed to detect flaws only on the inner wall.

The noncombustible residue from the burning of pulverized coal. Fly ash is pozzolanic and is frequently used to replace a portion of the cement and reduce its density.

The use of foam as a diverting agent during staged stimulation treatments. Stable foam is relatively viscous and the effect within a reservoirmatrix can be used to divert subsequent acid stages from the zones already treated. Following the treatment, the foam breaks, with little risk of formationdamage, to form a mixture of liquid and gaseous nitrogen that facilitates the cleanup process.

An enhanced oil recovery process in which foam is injected into a reservoir to improve the sweep efficiency of a driving fluid. Foam can be generated either in the reservoir pore space or at the surface before injection. Foam flooding mitigates sweep inhomogeneities such as those caused by layers with higher permeability than the surrounding formations, or those caused by gravity override.

A device fitted in surface treatment lines that helps distribute a liquid foamer phase in a stream of nitrogen gas. The foam generator creates a consistent mixture that becomes a stable foam under downhole pressure and temperature conditions.

A homogeneous, ultralightweight cement system consisting of base cement slurry, gas (usually nitrogen) and surfactants. Foamed cements are commonly used to cement wells that penetrate weak rocks or formations with low formation-fracture gradients.

An additive used in preparation of foam used as a drilling fluid. Drilling foam is water containing air or gas bubbles, much like shaving foam, and it must withstand high salinity, hard water, solids, entrained oil and high temperature. Foaming agents are usually nonionic surfactants and contain polymeric materials.

An oil-continuous foam that contains dispersed gas bubbles produced at the wellhead from heavy oil reservoirs under solution gas drive. The nature of the gas dispersions in oil distinguishes foamy oil behavior from conventional heavy oil. The gas that comes out of solution in the reservoir does not coalesce into large gas bubbles nor into a continuous flowing gas phase. Instead it remains as small bubbles entrained in the crude oil, keeping the effective oil viscosity low while providing expansive energy that helps drive the oil toward the producing well. Foamy oil accounts for unusually high production in heavy oil reservoirs under solution-gas drive.

A measure of the redundancy of common midpointseismic data, equal to the number of offset receivers that record a given data point or in a given bin and are added during stacking to produce a single trace. Typical values of fold for modern seismic data range from 60 to 240 for 2D seismic data, and 10 to 120 for 3D seismic data. The fold of 2D seismic data can be calculated by dividing the number of seismometer groups by twice the number of group intervals between shotpoints.

Variations in the properties of seismic data, encountered during processing, that are related to the acquisition geometry and distort the amplitude and phase of reflections. Also called acquisition footprint.

The amount of foreign personnel, material and services that working interest owners are permitted to employ, as defined under the terms of a concession when drilling and operating a well.

The simplest aldehyde, having the formula HCHO. Formaldehyde is used in aqueous solutions as a preservative. In muds, paraformaldehyde is added to protect against bacterial attack. The formaldehyde test determines the paraformaldehyde (bactericide) content of a drilling fluid by a P-alkalinity titration of a sulfite-oxidized mud filtrate.

A class of salts made from neutralization of formic acid with a metal hydroxide or oxide. Three alkali-metal formates are used in drilling, drill-in and completion fluids, (1) sodium formate, HCOO-Na+, (2) potassium formate, HCOO-K+ and (3) cesium formate, HCOO-Cs+. Clear solutions of each can reach densities of 1.32, 1.58 and 2.4 g/cm3, respectively. They are near neutral pH and meet HSE standards. Most formates can be mixed together over broad ranges of concentration or temperature without solubility or crystallization problems.

A general term for the rock around the borehole. In the context of formation evaluation, the term refers to the volume of rock seen by a measurement made in the borehole, as in a log or a well test. These measurements indicate the physical properties of this volume. Extrapolation of the properties beyond the measurement volume requires a geologicalmodel.

(noun) Any reduction in the natural permeability or productivity of a reservoir formation in the near-wellbore region, caused by drilling, completion, workover, or production operations. Common mechanisms include clay swelling, fines migration, emulsion blocking, scale deposition, and invasion of drilling fluid solids.

The measurement and analysis of formation and fluid properties through examination of formation cuttings or through the use of tools integrated into the bottomhole assembly while drilling, or conveyed on wireline or drillpipe after a borehole has been drilled. Formation evaluation is performed to assess the quantity and producibility of fluids from a reservoir. Formation evaluation guides wellsite decisions, such as placement of perforations and hydraulic fracture stages, and reservoir development and production planning.

The time that has elapsed between the bit first penetrating a formation and a log being recorded opposite the formation. In logging-while-drilling operations, this time is different for each log, since it depends on the drilling rate and the distance between the bit and the particular logging sensor.

The ratio of the resistivity of a rock filled with water (Ro) to the resistivity of that water (Rw). G.E. Archie postulated that the formation factor (F) was a constant independent of Rw and solely a function of pore geometry (the Archie equation I). It has since been shown that F is independent of Rw only for a certain class of petrophysically simple rocks (Archie rocks). In rocks with conductive minerals, such as shaly sands, there is a more complex dependence. In such cases, the ratio Ro/Rw is known as the apparent formation factor and may vary with Rw , temperature and the type of ion in solution. The intrinsic formation factor is then defined as F corrected for the effect of shale, or else the value of Ro/Rw at the limit of high salinity (low Rw ). The correction for the effect of shale depends on the saturation equation used, for example Waxman-Smits, dual water, SGS or CRMM. Unless otherwise stated, the term formation factor usually refers to the apparent formation factor.F has been related to porosity (phi) by several formulae (Archie, Humble and others) that have the general expression F = a / phim, where a is a constant and m the porosity exponent.

Any fluid that occurs in the pores of a rock. Strata containing different fluids, such as various saturations of oil, gas and water, may be encountered in the process of drilling an oil or gas well. Fluids found in the target reservoirformation are referred to as reservoir fluids.

Pressure above which injection of fluids will cause the rockformation to fracture hydraulically.

The pressure within the reservoirrock. The formation pressure value can be further categorized as relating to flowing well or shut-in conditions.

What Is Formation Water? Formation water occupies the pore spaces of a reservoir rock as naturally occurring brine, representing the connate water that saturated the formation before and after hydrocarbon migration. Its electrical resistivity, salinity, and ionic composition govern every resistivity-based water saturation calculation a petrophysicist performs, making it one of the most consequential fluids in reservoir evaluation. Key Takeaways Formation water is the naturally occurring brine trapped in reservoir pore space, typically dominated by sodium chloride at total dissolved solids (TDS) concentrations of 10,000 to 300,000 mg/L in petroleum reservoirs. The resistivity of formation water (Rw) is the critical input to Archie's equation (1942) for calculating water saturation (Sw); an error in Rw propagates directly into hydrocarbon-in-place estimates and economic decisions. Rw can be determined from direct water-sample analysis, the spontaneous potential (SP) log, Pickett crossplots, or published formation-water catalogs matched to geographic area and formation name. Formation water produced alongside hydrocarbons requires treatment, disposal, or reinjection; global produced water volumes exceed total oil production, making water management a dominant operational and environmental challenge. Naturally occurring radioactive material (NORM) co-precipitates with barium sulfate scale from formation water, creating regulated hazardous waste streams that operators must handle under jurisdiction-specific legislation. How Formation Water Works Formation water accumulates in sedimentary basins during compaction and diagenesis, acquiring its ionic signature from the host rock mineralogy, burial history, and geothermal regime. In most clastic reservoirs the dominant electrolyte is sodium chloride (NaCl), but calcium chloride (CaCl2), magnesium chloride (MgCl2), potassium chloride (KCl), and strontium chloride (SrCl2) contribute measurable concentrations depending on the formation age and diagenetic pathway. TDS in oilfield brines typically ranges from 10,000 mg/L (10 g/L) in shallow Tertiary sands to over 300,000 mg/L (300 g/L) in deep Permian or Cambrian carbonates, with some Devonian reef systems in Western Canada exceeding 350,000 mg/L. Because ionic concentration and temperature jointly determine electrical conductivity, Rw is always reported at a reference temperature, most commonly 25 degrees C (77 degrees F), and corrected to formation temperature before use in log interpretation. The relationship between salinity and resistivity is non-linear. At moderate salinities the Arps (1953) equation provides a working approximation: Rw(T2) = Rw(T1) x (T1 + 21.5) / (T2 + 21.5) for temperatures in degrees Celsius. At high salinities (above 100,000 mg/L NaCl equivalent) engineers use Schlumberger chart GEN-6 or equivalent ion-activity models to convert multi-ion water analyses into NaCl-equivalent resistivity. The Schofield conversion method translates a full ionic analysis, including Ca2+, Mg2+, K+, Na+, Cl-, SO42-, and HCO3-, into an NaCl-equivalent concentration (mg/L or ppm) from which Rw is then read directly. Most interpretive software packages, including Techlog, IP, and Interactive Petrophysics, automate this conversion, but petrophysicists reviewing frontier wells or unusual chemistries should check the method against published charts to avoid systematic bias. In the wellbore, formation water occupies two distinct saturation states. Irreducible or connate water (Swirr) is held in the smallest pore throats and adsorbed on clay surfaces by capillary forces; it is immobile at normal reservoir conditions and does not produce. Free water above Swirr is moveable and will co-produce with hydrocarbons once the well is perforated and placed on production. The transition from 100 percent water saturation at the free water level (FWL) to irreducible saturation at the top of the oil column defines the transition zone, whose thickness depends on capillary pressure, interfacial tension, and pore-size distribution. Understanding where formation water transitions to producible oil is central to perforating strategy and reserves booking under Society of Petroleum Engineers (SPE) PRMS guidelines. Formation Water Across International Jurisdictions Canada: Alberta Energy Regulator The Alberta Energy Regulator (AER) regulates produced water disposal and injection under the Environmental Protection and Enhancement Act (EPEA) and AER Directive 051 (Injection into Non-Potable Aquifers). In the Montney Formation of northwestern Alberta and northeastern British Columbia, produced water volumes are substantial, often exceeding 10 barrels of water per barrel of oil equivalent. Operators have developed dedicated produced water recycling infrastructure for hydraulic fracturing operations, significantly reducing freshwater withdrawals and trucking costs. The AER requires operators to report produced water volumes quarterly in their Water Disposal Volumes Report, and surface disposal to freshwater environments is prohibited. Deep saline aquifer injection into Class II analog disposal zones (primarily the Nisku and Wabamun formations) is the predominant disposal method. Devonian Leduc reef carbonates in the Pembina, Swan Hills, and Rainbow Lake fields produce high-TDS brine in the range of 80,000 to 180,000 mg/L, which must be trucked or piped to licensed injection facilities. United States: BSEE and EPA The Bureau of Safety and Environmental Enforcement (BSEE) governs offshore produced water management on the Outer Continental Shelf. The Environmental Protection Agency (EPA) administers the National Pollutant Discharge Elimination System (NPDES) for onshore discharges and the Underground Injection Control (UIC) Program for Class II disposal wells, which accept approximately 2 billion barrels (318 million cubic meters) of produced water per year nationwide. Offshore operators in the Gulf of Mexico may discharge produced water that meets the 29 mg/L monthly average oil-in-water limit under the EPA General NPDES Permit (GMG290000). Zero discharge applies to oil-based mud cuttings, but water-based operations have discharge pathways after treatment. Produced water reuse for agricultural irrigation is under active regulatory development in states including California, Colorado, and Pennsylvania, with TDS thresholds under discussion by the Water Research Foundation and state environmental agencies. Australia: NOPSEMA The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) requires operators to address produced water management in their Environment Plans (EP) submitted under the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009. The Bass Strait operations of Esso Australia (ExxonMobil) and BHP have historically reinjected produced water from the Gippsland Basin into the Latrobe aquifer for reservoir pressure support. Offshore Northwest Shelf operators (Woodside, Chevron, Shell) treat produced water to meet discharge limits, typically less than 30 mg/L oil-in-water, before overboard disposal. Australian onshore coal seam gas (CSG) operations in Queensland produce large volumes of low-salinity co-produced water from the Walloon Coal Measures; the Queensland Department of Environment and Science regulates beneficial use options including irrigation and aquifer recharge under the Water Act 2000. Middle East: Saudi Aramco and GCC Operations The Ghawar field in Saudi Arabia, the world's largest conventional oil field, produces formation water from the Arab-D reservoir at depths of approximately 1,800 to 2,200 metres (5,900 to 7,200 feet). Saudi Aramco recycles produced water through the Master Gas System injection program and the Qurayyah Seawater Treatment Plant for peripheral water injection; treated seawater and produced water are co-injected to maintain reservoir pressure. Formation water chemistry in the Arabian Basin is dominated by NaCl-CaCl2 brines at TDS concentrations of 150,000 to 220,000 mg/L, requiring robust scale inhibitor programs targeting calcium carbonate and barium sulfate. The Abu Dhabi National Energy Company (TAQA) and Abu Dhabi National Oil Company (ADNOC) operate similar produced water reinjection (PWRI) schemes in the Zakum and Bu Hasa fields, with the added complexity of managing near-surface freshwater aquifers protected under UAE Federal Law No. 24 of 1999. Norway: Sodir and North Sea Operations The Norwegian Offshore Directorate (Sodir, formerly NPD) and the Norwegian Environment Agency regulate produced water discharges on the Norwegian Continental Shelf (NCS) under the Pollution Control Act and OSPAR Convention commitments. Norway operates under a 30 mg/L dispersed oil limit for produced water discharge, but the OSPAR goal is zero harmful discharge, driving continuous improvement in produced water treatment technologies including de-oiling hydrocyclones, compact flotation units, and walnut shell filters. Equinor's Ekofisk operations in the chalk formation produce high-carbonate formation water with significant scaling tendency; chalk dissolution creates complex water chemistry that demands formation-specific Rw databases. Norwegian operators must report produced water volumes, composition, and treatment efficiency annually through the Petroleum Safety Authority Norway (Ptil) and Sodir reporting systems. Fast Facts Global produced water volume: Approximately 250 million barrels per day (39.7 million cubic metres per day), roughly 3 barrels of water for every barrel of oil produced worldwide. Rw range in petroleum reservoirs: 0.02 ohm-m (high-salinity Permian brine) to 5 ohm-m (low-salinity Tertiary sands and some carbonates). Dominant cation: Sodium (Na+) in most basins; calcium-dominated (CaCl2) brines occur in deeply buried formations in the Williston Basin, Permian Basin, and Western Canada Sedimentary Basin. Archie exponents: Cementation exponent m = 2.0 and saturation exponent n = 2.0 are default Archie values; clean consolidated sandstones typically fall between 1.8 and 2.3 for m. Temperature correction: Rw approximately halves for every 25 degrees C (45 degrees F) rise in temperature at moderate salinities.

An organic acid [HCOOH] used in oil- and gas-well stimulation treatments. Formic acid has an advantage over HCl in that formic acid is easier to inhibit against pipe corrosion at temperatures as high as 400°F [204°C]. Formic acid is intermediate in strength between hydrochloric acid [HCl] and acetic acid. Additionally, formic acid corrodes steel more uniformly than does HCl and causes less pitting.

The technique of determining what a given sensor would measure in a given formation and environment by applying a set of theoretical equations for the sensor response. Forward modeling is used to determine the general response of most electromagnetic logging measurements, unlike nuclear measurements whose response is determined mainly in laboratory experiments. Forward modeling is also used for interpretation, particularly in horizontal wells and complex environments. In this case, iterative forward modeling is used. The set of theoretical equations (the forward models) can be 1D, 2D or 3D. The more complex the geometry, the more factors can be modeled but the slower the computing time.

A laboratory test to determine the phase envelope between lean gas and oil by equilibrating a gas sample several times with fresh samples of oil. In a forward-contact test, light and intermediate components are stripped from the oil by multiple contacts with the gas. The test also indicates how many contacts are required before the gas with added components becomes miscible with the oil. The molar ratios at each contact step are typically designed using PVT simulation software that incorporates the fluid composition at each contact.

The practice of taking a model and calculating what the observed values should be, such as predicting the gravityanomaly around a saltdome using a gravity model or predicting the traveltime of a seismicwave from a source to a receiver using a velocity model.

Preserved remnants of plants or animals, such as skeletons, shells, casts or molds, tracks or borings, and feces.

Four-component (4C) borehole or marineseismic data are typically acquired using three orthogonally-oriented geophones and a hydrophone within an ocean-bottom sensor (deployed in node-type systems as well as cables). Provided the system is in contact with the seabed or the borehole wall, the addition of geophones allows measurement of shear (S) waves, whereas the hydrophone measures compressional (P) waves.

Three-dimensional (3D) seismic data acquired at different times over the same area to assess changes in a producing hydrocarbonreservoir with time. Changes may be observed in fluid location and saturation, pressure and temperature. 4D seismic data is one of several forms of time-lapse seismic data. Such data can be acquired on the surface or in a borehole.

Collective term for the personnel required to run a successful hydraulic fracturing operation. Members of the frac crew prepare the equipment on the wellsite prior to the operation, mix and pump the necessary chemicals and fluids during the frac job and render the wellsite location safe following the completion of the operation.

The primary fluid used in hydraulic fracturing operations. Several chemical additives generally will be added to the frac gel to form a treatment fluid specifically designed for the anticipated wellbore, reservoir and operating conditions.

The pressure gradient, generally stated in psi/ft [kPa/m], at which a specific formation interval breaks down and accepts fluid. Determining the frac gradient is a key requirement in designing and analyzing a hydraulic fracturing treatment.

A specialized perforating-gun system that contains shaped charges loaded at 0°, 60°, 120°, or 180° phase angles to provide a casingentrance hole of approximately 0.5 in. [1.3 cm], which is intended to be large enough for hydraulic fracturing operations.

A high-pressure, high-volume pump used in hydraulic fracturing treatments.

A high-pressure isolation valve fitted to the top of the wellhead on a well that is about to be hydraulically fractured. The frac valve can be closed to isolate the treating equipment from the wellbore.

A special mathematical geometry with properties that reproduce a pattern over a range of scales. They can contain some variations so that the patterns do not perfectly repeat. This geometry claims to represent many natural systems, including plant growth, geological deposition, coastlines and other geographical shapes. Fractal geometry has also led to the recent study of "Chaos Theory." This technology is sometimes used in geostatistical studies.Reference:Mandelbrot BB: The fractal geometry of nature. New York, Freeman, 1983.Hewett TA: "Fractal Methods for Fracture Characterization," in Yarus JM and Chambers RL (eds): Stochastic Modeling and Geostatistics, AAPG Computer Applications in Geology, no. 3. AAPG, Tulsa, Oklahoma, USA, 1994.

Analysis of a geometrical system using fractal mathematics. This analysis is sometimes used in geostatistics to describe depositional systems and other geological phenomena.

Networks that are described using the mathematics of fractals. These are useful for describing certain types of fracture systems.

A well-stimulation operation in which acid, usually hydrochloric [HCl], is injected into a carbonateformation at a pressure above the formation-fracturing pressure. Flowing acid tends to etch the fracture faces in a nonuniform pattern, forming conductive channels that remain open without a propping agent after the fracture closes.The length of the etched fracture limits the effectiveness of an acid-fracture treatment. The fracture length depends on acid leakoff and acid spending. If acid fluid-loss characteristics are poor, excessive leakoff will terminate fracture extension. Similarly, if the acid spends too rapidly, the etched portion of the fracture will be too short. The major problem in fracture acidizing is the development of wormholes in the fracture face; these wormholes increase the reactive surface area and cause excessive leakoff and rapid spending of the acid. To some extent, this problem can be overcome by using inert fluid-loss additives to bridge wormholes or by using viscosified acids. Fracture acidizing is also called acid fracturing or acid-fracture treatment.

Product of fracturepermeability times fracture width for a finite-conductivity fracture.

The factor used to determine formation fracturing pressure as a function of well depth in units of psi/ft. For example, a fracture gradient of 0.7 psi/ft [15.8 kPa/m] in a well with a true vertical depth of 8000 ft [2440 m] would predict a fracturing pressure of 5600 psi [38.6 MPa].

Radial distance from the wellbore to the outer tip of a fracture penetrated by the well or propagated from the well by hydraulic fracturing.

Patterns in multiple fractures that intersect with each other. Fractures are formed when rock is stressed or strained, as by the forces associated with plate-tectonic activity. When multiple fractures are propagated, they often form patterns that are referred to as fracture networks. These networks are studied using a number of mathematical and statistical techniques and may even be represented using fractals. Fracture networks may make an important contribution to both the storage (porosity) and the fluid flow rates (permeability or transmissability) of formations.

That portion of a dual-porosity reservoirs permeability that is associated with the secondary porosity created by open, natural fractures. In many of these reservoirs, fracture permeability can be the major controlling factor of the flow of fluids.

A type of secondary porosity produced by the tectonic fracturing of rock. Fractures themselves typically do not have much volume, but by joining preexisting pores, they enhance permeability significantly. In exceedingly rare cases, nonreservoir rocks such as granite can become reservoir rocks if sufficient fracturing occurs.

Analysis of a well that passes through a natural fracture or that has been hydraulically fractured. The fracture is treated as a slab of high permeability that is an effective extension of the actual wellbore. Flow is from the reservoir to the fracture and through the fracture to the well. The pressure-transient analysis for a fractured well can determine the fracture half-length and the fracture conductivity, as well as a fracture-face skin. The skin factor for the fracture is negative and usually ranges from -1.5 to -5, with an absolute minimum of -6 in rare cases. For effectively infinite-conductivity fractures, the apparent wellbore radius is half the fracture half-length, or xf/2.

A fluid injected into a well as part of a stimulation operation. Fracturing fluids for shale reservoirs usually contain water, proppant, and a small amount of nonaqueous fluids designed to reduce friction pressure while pumping the fluid into the wellbore. These fluids typically include gels, friction reducers, crosslinkers, breakers and surfactants similar to household cosmetics and cleaning products; these additives are selected for their capability to improve the results of the stimulation operation and the productivity of the well.

(noun) The downhole pressure at which a formation rock fractures and a hydraulic fracture initiates and propagates. Fracturing pressure is a function of the in-situ stress state, rock tensile strength, pore pressure, and the properties of the fracturing fluid, and must be exceeded to create the fracture network during stimulation treatments.

The volume of fluid (expressed in percent) that separates from a cementslurry when the slurry is left static. The free fluid can be measured as specified in API Recommended Practice 10B. Free fluid is also known as free water.

Gas that exists in the reservoir in the gaseous phase rather than in solution. As soon as formationpressure drops below the bubblepoint, gas is evolved. This is referred to as free gas while it is in the reservoir.

The depth at which a tubing or coiled tubing string that is stuck in the wellbore is free to move. When the tubing string must be cut to enable recovery, the free point should be known to ensure retrieval of the cut tubing. This enables remedial action to be taken to resolve the sticking mechanism on the portion of the string below the cut.

Water in the pore space that can flow under normal reservoir conditions. When used in connection with nuclear magnetic resonance (NMR) measurements, free water is all the water that is not clay bound, capillary bound or in mineral hydrates. The latter is in any case excluded as it relaxes too fast to be measured by NMR. When used in connection with the dual-water model, the term means the far water.

In gravity surveying, a correction of 0.3086 mGal/m [0.09406 mGal/ft] added to a measurement to compensate for the change in the gravitational field with height above sea level, assuming there is only air between the measurement station and sea level.

In a nuclear magnetic resonance measurement, the decay, or relaxation, caused by dephasing in an inhomogeneous magnetic field. Since this relaxation is not related to formation properties, it is unwanted and corrected by using the CPMG pulse sequence.

A wireline tool used to determine the free point on a stuck string. The free-point indicator operates by detecting stretch in the tubular when tension is applied at surface. If stretch is not detected, the string must be stuck above the tool; if stretch is detected, the string is free above the free-point indicator tool.

A vertical or horizontal separator used mainly to remove any free water that can cause problems such as corrosion and formation of hydrates or tight emulsions, which are difficult to break.A free-water knockout is commonly called a three-phase separator because it can separate gas, oil and free water. The liquids that are discharged from the free-water knockout are further treated in vessels called treaters. Free-water knockout is abbreviated as FWKO.

The rate of repetition of complete wavelengths of electrical signals, light, sound and seismic waves measured in cycles per second, or hertz, and symbolized by f. Typical recorded seismic frequencies are in the range of 5 to 100 hertz.

In seismic surveying or processing, the use of a function of frequency rather than time to express an independent variable or measurement. In contrast, in the time domain, variables are expressed as a function of time instead of frequency.

A core that is in the same state as when it was brought to the surface. A fresh core is sealed as soon as possible after retrieval from the well to minimize the loss of fluids and exposure to air. The term implies that the core is analyzed before being stored, after storage it is known as preserved core. Since the purpose is to minimize alteration, a fresh core has often been drilled with a bland mud, either water- or oil-base, but with a minimum of chemical additives and weighting material.

Water that is low in dissolved salt (< 2000 ppm).

In a gradiomanometer tool or pressure derivative calculation, the apparent increased fluid density observed due to frictional pressure losses along the tool and casing in a fast-flowing fluid. The magnitude of the correction depends on the flow rate, tool geometry and the casing size, and is negligible in most casings below about 2000 B/D [318 m3/d]. The fluid density will appear erroneously high unless this effect is corrected for.

An additive, generally in slurry or liquid form, used to reduce the friction forces experienced by tools and tubulars in the wellbore. Friction reducers are routinely used in horizontal and highly deviated wellbores where the friction forces limit the passage of tools along the wellbore.

A multiphase flow regime in near-vertical pipes in which large slugs of gas move up the center of the pipe, usually carrying small droplets of oil or water with them. Most of the remaining oil or water flows up along the pipe walls. The flow is relatively chaotic, producing a frothy mixture containing some large, elongated bubbles. Neither phase is continuous. Froth flow occurs at relatively high gas velocity and is similar to churn flow. As the gas velocity increases, it changes into annular flow.

A log or a recording in which the complete signal received at an acoustic transducer is recorded. With full-waveform recording, it is possible to determine the slowness not only of the first arrival but also of later arrivals. In boreholesoniclogging, these may be the shear, flexural and Stoneley waves. The waveforms are recorded by an array of receivers in an array-sonic tool, and processed with a suitable technique such as slowness-time coherence.

A description of the internal area and surfaces of a tool or tubular assembly through which there is an unimpeded internal diameter. In some cases, fullbore is used to describe the form of a nominal internal diameter that extends over the length of the tool or interval without any variation. In other applications, the term simply implies an ability to pass a ball or similar item of a stated drift diameter through the assembly.

A type of flowmeter in which the spinner blades are collapsed to pass through the tubing and other restrictions, and then opened up below to sense the full cross section of the casing or openhole. In this way, a much larger fraction of the flow is measured. Introduced in the 1970s, the fullbore spinner gives a better average flow velocity than a conventional flowmeter, particularly at low flow rates and with simple biphasic-flow regimes. However, when the flow structure is complex, such as with multiphase flow in highly deviated wells, the average flow velocity may not be meaningful.

Time, in seconds for one quart of mud to flow through a Marsh funnel. This is not a true viscosity, but serves as a qualitative measure of how thick the mud sample is. The funnel viscosity is useful only for relative comparisons.