Oil and Gas Terms Beginning with “S”

An elastic body wave in which particles oscillate perpendicular to the direction in which the wave propagates. S-waves are generated by most land seismic sources, but not by air guns. P-waves that impinge on an interface at non-normal incidence can produce S-waves, which in that case are known as converted waves. S-waves can likewise be converted to P-waves. S-waves, or shear waves, travel more slowly than P-waves and cannot travel through fluids because fluids do not support shear. Recording of S-waves requires receivers coupled to the solid Earth. Interpretation of S-waves can allow determination of rock properties such as fracture density and orientation, Poisson's ratio and rock type by crossplotting P-wave and S-wave velocities, and by other techniques.

A thermal production method for heavy oil that pairs a high-angle injection well with a nearby production well drilled along a parallel trajectory. The pair of high-angle wells is drilled with a vertical separation of about 5 m [16 ft]. Steam is injected into the reservoir through the upper well. As the steam rises and expands, it heats up the heavy oil, reducing its viscosity. Gravity forces the oil to drain into the lower well where it is produced.

Abbreviation for sodium acid pyrophosphate, a sequestering agent used to treat cement contamination and a deflocculant for low-temperature water muds.

A method for characterization of heavy oils based on fractionation, whereby a heavy oil sample is separated into smaller quantities or fractions, with each fraction having a different composition. Fractionation is based on the solubility of hydrocarbon components in various solvents used in this test. Each fraction consists of a solubility class containing a range of different molecular-weight species. In this method, the crude oil is fractionated to four solubility classes, referred to collectively as SARA: saturates, aromatics, resins, and asphaltenes. Saturates are generally iso- and cyclo-paraffins, while aromatics, resins, and asphaltenes form a continuum of molecules with increasing molecular weight, aromaticity, and heteroatom contents. Asphaltenes may also contain metals such as nickel and vanadium. This method is sometimes referred to as Asphaltene/Wax/Hydrate Deposition analysis.

Ratio of the volume percent synthetic fluid to the volume percent brine in a synthetic mud, where each is expressed as a percent of the total liquid in the mud. The SBR is calculated in an analogous way to the oil/brine ratio using data from the retort test.

Special core analysis laboratory.

(noun) Abbreviation for Statistical Curvature Analysis Technique. A directional survey analysis method used in wellbore trajectory planning and evaluation to identify systematic errors in directional survey measurements by comparing successive survey stations.

A form of corrosion in which susceptible types of metals will break by a combination of stress within the metal and the specific type of corrosion. Sulfide corrosion of ferrous alloys and chloride corrosion of stainless steels are two common type of SCC. When high-strength steel remains in contact with hydrogen sulfide (or sulfide ion) in a water-mud environment, sulfide SCC may occur. Tool joints, hardened parts of blowout preventers and valve trim are particularly susceptible to brittle failure caused by sulfide SCC. For this reason, along with toxicity risks of hydrogen sulfide gas, it is essential that water muds be kept entirely free of soluble sulfides and especially hydrogen sulfide at low pH.

A shear wave that is polarized so that its particle motion and direction of propagation are contained in a horizontal plane.

The force per unit area exerted at the bottom of a wellbore when it is closed at either the Christmas tree or the BOP stack. The SIBP is generated by a combination of the hydrostatic pressure from the weight of the liquid in the well and any additional applied pressure. The applied pressure component may be from the formation or from an external source at the surface.

The force per unit area exerted at the bottom of a wellbore when it is closed at either the Christmas tree or the BOP stack. The SIBP is generated by a combination of the hydrostatic pressure from the weight of the liquid in the well and any additional applied pressure. The applied pressure component may be from the formation or from an external source at the surface.

The surface force per unit area exerted at the top of a wellbore when it is closed at either the Christmas tree or the BOP stack. The pressure may be from the formation or an external and intentional source. The SIP may be zero, indicating that any open formations are effectively balanced by the hydrostatic column of fluid in the well. If the pressure is zero, the well is considered to be dead, and can normally be opened safely to the atmosphere.

Abbreviation for synthetic natural gas

An abbreviation of spontaneous potential.

Linear, anionicpolymer made from the monomer acrylic acid, CH2=CHCOO- H+. The acrylic acid groups are evenly spaced along the chain. Acrylic acid polymer neutralized with NaOH is sodium polyacrylate (SPA). Polyacrylates are best utilized in soft water with low salinity to achieve the best dispersion and full chain elongation. Even low concentrations of hardness ions, for example, Ca+2, precipitate polyacrylates. Low molecular-weight polyacrylates are used as clay deflocculants. High molecular weight polymers are used for fluid-loss control and as a clay extender. As an extender, SPA is added to bentonite at the grinding plant. It is also used at the rig in low-solids mud. Divalent cations can negate its benefits as a clay extender. SPA is highly efficient when used to flocculate colloids in native-solids muds, clear-water muds and wastewater cleanup. The polymer chain links together colloidal solids that can be removed by gravity settling in shallow pits or by applying hydrocyclone, centrifuge or filtration techniques.

A common anaerobic bacterium, commonly abbreviated SRB, that can convert sulfate ions, SO4-2, into S-2 and HS-, with the concomitant oxidation of a carbon source. The lignite, lignin, tannins, cellulose, starches and fatty acids found in many mud systems are carbon food sources for SRB. Where mud is stored, precautions should always be taken when handling or reconditioning water muds containing lignosulfonates, gypsum (sulfate sources) and starches, cellulose, xanthan gum and lignite (food sources). These muds can harbor SRB and can have high sulfide accumulations. Mud filtrate should be tested with the Garrett Gas Train to determine sulfide concentration in a stored mud, followed by treatments with caustic soda to raise pH and zinc-based scavengers to remove sulfides as ZnS. Before storage of mud, treatment with a bactericide can inhibit SRB growth. Also, circulating mud from time to time, with air entrainment, can retard development of anaerobic conditions.Anaerobic bacteria can convert the sulfate or sulfite present in water handling facilities to hydrogen sulfide [H2S]. This by-product, combined with iron, can form iron sulfide, a scale that is very difficult to remove. SRB occur naturally in surface waters, including seawater. Bacteria accumulation can lead to pitting of steel, and the buildup of H2S increases the corrosiveness of the water, thus increasing the possibility of hydrogen blistering or sulfide stresscracking.

A copolymer of polystyrene (containing sulfonate groups on the ring) and anhydrous maleic acid (a di-hydroxy acid). The sulfonated ring-structurepolymer component is anionic and usually low to moderate in chain length and molecular weight. As such, with negative groups on the structure (amount of negativity depending on degree of sulfonation), it is used as a claydeflocculant for bentonite-based water mud. It is especially stable to temperature up to around 400°F [204°C], and often used in high-density muds to stabilize rheology. Lignosulfonate is used for this purpose up to about 300°F [149°C] and then SSMA polymeric deflocculant is often phased into the mud system for drilling deeper and hotter zones.

A copolymer of polystyrene (containing sulfonate groups on the ring) and anhydrous maleic acid (a di-hydroxy acid). The sulfonated ring-structurepolymer component is anionic and usually low to moderate in chain length and molecular weight. As such, with negative groups on the structure (amount of negativity depending on degree of sulfonation), it is used as a claydeflocculant for bentonite-based water mud. It is especially stable to temperature up to around 400°F [204°C], and often used in high-density muds to stabilize rheology. Lignosulfonate is used for this purpose up to about 300°F [149°C] and then SSMA polymeric deflocculant is often phased into the mud system for drilling deeper and hotter zones.

A mnemonic for the static spontaneous potential.

Abbreviation for stock tank barrel.

A shear wave that is polarized so that its particle motion and direction of propagation occur in a vertical plane.

Ratio of the volume percent synthetic fluid to the volume percent water in a synthetic-base mud, where each is a percent of the total liquid in the mud. The SWR is calculated in an analogous way to the oil/brine ratio using data from the retort test.

A steel cable that has a clip on one end and a loop on the other, threaded through hanging equipment for security.

A form of fractal geometry based on a triangle. It has a fractal dimension D = ln 3/ln 2 = 1.58....A Sierpinski carpet uses a square instead of a triangle and has a fractal dimension D = ln 8/ln 3 = 1.89....

Conventional marineseismic data acquisition method using a single vessel to tow one or more seismic source arrays and streamers in a straight line as the vessel records seismic data. With this method, the angle between the source and receivers is narrow.

The mathematical description of refraction, or the physical change in the direction of a wavefront as it travels from one medium to another with a change in velocity and partial conversion and reflection of a P-wave to an S-wave at the interface of the two media. Snell's law, one of two laws describing refraction, was formulated in the context of light waves, but is applicable to seismic waves. It is named for Willebrord Snel (1580 to 1626), a Dutch mathematician. Snell's law can be written as:

The periodicities in the behavior of the Earth and its climate with respect to the sun. Some rhythms are caused by variations in the elliptically of the Earth's orbit, rotation of the semimajor axis of the Earth's orbit, variation on the tilt of the Earth's axis and rotation in the tilt of the Earth's axis. Most of these rhythms are predictable over the short term (up to hundreds of millions of years) but can become chaotic due to the influence of other planets (particularly massive Jupiter) or extra solar-system activity. The rhythms affect sea level and other factors that dictate the long-term behavior of depositional systems.

An apparatus for cleaning core samples using the distillation extraction method. In the Soxhlet apparatus (also called extractor, or chamber), the sample soaks in hot solvent that is periodically siphoned off, distilled and returned to the sample. The process continues until the siphoned-off solvent becomes clear. In the Soxhlet apparatus, the sample soaks in the solvent, while in the Dean-Stark apparatus, the solvent flows through the sample from top to bottom.

A device used during making up a string of pipe to align pin to box threads and prevent face damage.

A component of the Bottom Hole Assembly that helps keep the bit drilling straight through different rock formations.

The ability of fluid to move through a rock, as measured by the reduction in amplitude or increase in slowness of the acoustic Stoneley wave generated in the borehole. The velocity and amplitude of the Stoneley wave are reduced by the presence of mobile fluids in the formation. Physically, the effect can be seen as a coupling of the Stoneley energy into a formation wave known as the slow wave, as predicted by the Biot theory. The amount of reduction is a complicated function of this mobility (or permeability divided by viscosity), the properties of the borehole fluid, the pore fluid and the mudcake, the elastic properties of the rock and the frequency. Since all these factors are measured or estimated from logs, it is possible to determine formation mobility. In practice, the mobility needs to be reasonably high for the method to be accurate.

A type of large-amplitude interface, or surface, wave generated by a sonic tool in a borehole. Stoneley waves can propagate along a solid-fluid interface, such as along the walls of a fluid-filled borehole and are the main low-frequency component of signal generated by sonic sources in boreholes. Analysis of Stoneley waves can allow estimation of the locations of fractures and permeability of the formation. Stoneley waves are a major source of noise in vertical seismic profiles.

An assembly of heavy beams used as the foundation on which the derrick or mast and usually the drawworks sit.

Abbreviation for water saturation.

The dimensionless ratio of the weight of a material to that of the same volume of water. Most common minerals have specific gravities between 2 and 7.

An environment of coastal sedimentation characterized by arid or semiarid conditions above the level of high tide and by the absence of vegetation. Evaporites, eolian deposits and tidal-flood deposits are common in sabkhas.

A unit of measure for portland cement. In the United States, a sack refers the amount of cement that occupies a bulk volume of 1.0 ft3. For most portland cement, including API classes of cement, a sack weighs 94 pounds. The sack is the basis for slurry design calculations and is often abbreviated as sk.

A mechanical device attached to tool strings or flush surface tubulars as they are assembled or disassembled. The safety clamp prevents the tool string from being dropped downhole accidentally if the slips or elevators securing the string lose their grip.

A blank gun section or spacer installed between the top perforating-gun assembly and firing head in a TCP operation. The safety spacer serves to position the gun assembly a safe distance below the rig floor during arming and disarming operations. The spacer should be a minimum of 10 feet [3 m] in length. In some cases, a longer safety spacer will be required to ensure that the gun assembly is positioned safely below the living quarters or other occupied areas of the drilling rig.

Settling of particles in the annulus of a well, which can occur when the mud is static or being circulated. Because of the combination of secondary flow and gravitational forces, weighting materials can settle (sag) in a flowing mud in a high-angle well. If settling is prolonged, the upper part of a wellbore will lose mud density, which lessens the hydrostatic pressure in the hole, so an influx (a kick) of formation fluid can enter the well.

The product formed by neutralization of an acid and a base. The term is more specifically applied to sodium chloride. Neutralization is an important reaction in many aspects of mud control and treatment.

A mushroom-shaped or plug-shaped diapir made of salt, commonly having an overlying caprock. Salt domes form as a consequence of the relative buoyancy of salt when buried beneath other types of sediment. The salt flows upward to form salt domes, sheets, pillars and other structures. Hydrocarbons are commonly found around salt domes because of the abundance and variety of traps created by salt movement and the association with evaporite minerals that can provide excellent sealing capabilities.

A temporary plugging agent comprising graded granules of salt that form a physical or hydraulic barrier. The different grain sizes are prepared as a slurry for placement, then allowed to settle into a plug. The resulting plug typically provides good mechanical and hydraulic strength to enable safe treatment of an adjacent zone. On completion of the treatment, the temporary salt plug is easily removed by circulating a water-base fluid to dissolve the plug.

A type of refraction survey to help define a salt-sediment interface near a wellbore. The source is typically placed directly above the top of a salt dome and the receivers are placed at a number of locations within the borehole. This technique takes advantage of the fact that sound travels faster through the salt than the surrounding soft sediments, such as in the US Gulf Coast. This survey measures the fastest travel path, with part of its path through the salt. The resultant traveltimes are then inverted via a model to obtain a profile of the salt flanks relative to the borehole.

A type of reflectionsurvey to help define a salt-sediment interface near a wellbore.

An influx of formation water, usually salty and sometimes hard, into the mud in the wellbore. Saltwater flows contaminate freshwater or seawater muds, making it expensive, difficult and time-consuming to regain the mud properties. Influxes pose a lesser problem for saltwater muds. Saltwater contamination flocculates the bentonite clay in fresh- or seawater muds. Flocculated, thick, filtercake on a permeable zone frequently results in differential-pressure sticking.

A water mud containing varying amounts of dissolved sodium chloride, NaCl, as a major component. Undissolved salt may also be present in saturated salt muds to increase density beyond 10 lbm/gal or to act as a bridging agent over permeable zones. Starch and starch derivatives for fluid-loss control and xanthan gums for hole-cleaning are among the few highly effective additives for saltwater muds. Attapulgite and sepiolite are used in saltwater muds only for cuttings lifting. The primary use of saltwater mud is to drill salt strata that are prone to dissolution when exposed to other types of drilling fluid. A saturated salt mud is used to drill salt to prevent hole enlargement. In hot, plastic, salt zones, the hole may close inward unless extremely high mud weight is maintained. As an alternative to high mud weight, maintaining undersaturation in the fluid allows controlled leaching to offset hole closure by plastic flow. Sized salt particles in saturated saltwater muds are used, along with polymers, to bridge over permeable production zones. The salt can be removed later with a water flush. Salt solids can increase density beyond 10 lbm/gal, up to about 13 lbm/gal, if needed.

The number of data points or measurements per unit of time or distance.

The distance or time between data points or measurements.

The number of measurements per unit of time, or the inverse of the sample interval.

The error introduced by the sampling process caused by making measurements on only a limited portion of a formation.

The depth or time between successive measurements by a sensor. For measurements-while-drilling (MWD) logs, the sampling interval is most commonly a time. For wireline measurements, it is most commonly a depth.

A generic term used to describe small formation particles known as fines that may be produced with the reservoir fluid. Sand production generally is undesirable and, if severe, may require some remedial action to control or prevent production, such a gravel packing or sand consolidation.

A swabbing device used to clean up sand that has accumulated in the wellbore. Because sands abrasiveness is detrimental to the normal operation of production equipment, its production should be minimized. A sand bailer operates by creating a partial vacuum that sucks up the sand.

The process of removing sand or similar fill from a wellbore. Many wells produce sand that may accumulate and restrict production if not removed from the wellbore by the production fluid. Coiled tubing and snubbing units are routinely used for sand-cleanout operations, enabling the well condition to be treated without removing the completion equipment or even killing the well.

A means of controlling the undesirable production of sand from weak sandstone formations. Sand consolidation chemically binds the grains of sand that make up the formationmatrix while maintaining sufficient permeability to achieve viable production rates.

The installation of equipment or application of techniques to prevent migration of reservoirsand into the wellbore or near-wellbore area. In weak formations, sand control may be necessary to maintain the structure of the reservoir around the wellbore. In other formation types, the migration of sand and fines into the near wellbore area may severely restrict production. Each of these conditions requires different treatments. The principal sand-control techniques include gravel packing and sand consolidation.

A long cable, installed on most drilling and workover rigs, used when swabbing or bailing in the production tubing or wellbore tubulars. The sand line is typically stored and operated on a winch drum that is part of the rigdrawworks. The sand line is capable of significantly higher tensile forces than slickline or electric wireline.

The migration of formationsand caused by the flow of reservoir fluids. The production of sand is generally undesirable since it can restrict productivity, erodecompletion components, impede wellbore access, interfere with the operation of downhole equipment, and present significant disposal difficulties.

A test to determine the volume percent of solids in a mud that are retained on 200-mesh screen. A glass, sand-content tube with a tapered lower end and a 200-mesh screen are used in the test. The test measures percent solids above 74 micrometers, which include those that could be abrasive to pumps and piping. When performed according to the API protocol for water-base muds, the sand-content tube is filled to the first mark with mud. Water is added to the next mark and the tube is shaken. The diluted slurry is poured through the 200-mesh screen, discarding the liquid. The screen is washed and the residue on the screen is poured back into the tube. Volume percent "sand" is measured from divisions on the tapered tube.

A small pit, typically located immediately after the shaker screens, which is used as a settling pit to separate coarser solids that accidentally bypass the shakers. Mud enters the pit at one side and exits via an overflow at the other. Sand traps are dumped periodically to remove the settled solids, or alternatively the contents can be processed over a finescreen or with a centrifuge.

The physical interface between the formation and the wellbore. The diameter of the wellbore at the sandface is one of the dimensions used in production models to assess potential productivity.

A condition encountered during some hydraulic fracturing operations whereby the fracture cannot accept further sand or proppant and only the carrier fluid is injected into the formation. A sandout occurs when the concentration of proppant within the tubing string rapidly increases, creating a corresponding sudden increase in pump pressure.

A clastic sedimentary rock whose grains are predominantly sand-sized. The term is commonly used to imply consolidated sand or a rock made of predominantly quartz sand, although sandstones often contain feldspar, rock fragments, mica and numerous additional mineral grains held together with silica or another type of cement. The relatively high porosity and permeability of sandstones make them good reservoir rocks.

The study of and description of sandstones, including the mineral content. In matrix stimulation, only the mineral surfaces contacted by the stimulation fluid will be dissolved, so a petrographic study often helps anticipate the rocks response to fluid injection.Sandstone reservoirs are made of silicate grains such as quartz, feldspar, chert and mica, which are deposited as sand; secondary minerals may be deposited in the original pore spaces. Secondary quartz or carbonate minerals often bind sand grains together. Authigenic clays, mainly composed of silicon and aluminum, may also form in the pores.The reactivity of a given mineral depends on three factors: surface area, chemical composition and temperature. Clays have greater specific surface area compared with other matrix minerals, which makes them the most reactive components during well-stimulation operations.

A transform from raw log data chosen so that a log recorded in these units will give the correct porosity of the formation providing the matrix is pure quartz and the pores are filled with fresh water. The unit, which may be in vol/vol or p.u., is most commonly used for neutron porosity logs but may also be used for density and acoustic logs. The definition is strictly true only if all borehole and other environmental corrections have been applied.

Display ranges chosen for the density and neutron porosity logs such that the two curves will overlay at all porosity values providing the matrix is pure quartz and the pores are filled with fresh water. The most common overlay spans two tracks, with the density reading from 1.9 to 2.9 g/cm3, and the neutron in sandstone porosity units from 0.45 to ?0.15 vol/vol.

A platform on which surface multiphase pumps can be mounted and connected to subsea multiphase pumps.

A solution that contains as much dissolved materials as it can hold at a given temperature. Precipitation of some components will likely occur if a more soluble compound is introduced or if the temperature is changed.

The relative amount of water, oil and gas in the pores of a rock, usually as a percentage of volume.

An equation for calculating the water saturation from resistivity and other logs. There are many saturation equations. Practical equations are all extensions of the Archie equation, which is valid for a rock with very little clay, or very high salinity water, and with a regular porestructure. The majority deal with the problem of shaly sands, and can be divided into two main groups?those that treat the shale as a volume of conductive material (Vsh models), and those that analyze the effect of clay counter-ions. Vsh models take many forms. Typical examples are the Simandoux, laminated sand and Indonesian equations. The other group includes the Waxman-Smits, Dual Water and SGS equations. Most nonshaly sand equations deal with the problem of mixed pore types, for example combinations of fractures, isolated pores and intergranular pores.

The exponent, n, in the relation of water saturation, Sw, to resistivity index, I (I = Sw-n) for a sample of rock. It expresses the effect on the resistivity of desaturating the sample, or replacing water with a non-conductive fluid. In petrophysically simple, water-wet rocks (Archie rocks), n is constant for different values of Sw, and a single average n can be found for a particular reservoir or formation. A typical value is 2. In more complex rocks, n changes with Sw, although often being about 2 near Sw = 1. In rocks with conductive minerals, such as shaly sands, n becomes increasingly lower as Sw is reduced. This change is negligible for high-salinity waters, but increases as the salinity is reduced. In shaly-sand saturation equations, such as Waxman-Smits, dual water, SGS and CRMM, n is the intrinsic n, determined with high-salinity water or with the clay effects removed. The variation of I with Sw is then predicted, with varying success, by the different equations.In carbonates with multiple pore types, such as fractures, vugs, interparticle porosity and microporosity, n may change as each pore type is desaturated. A different n may be used for a different range of Sw. In all cases, n increases if any pores are oil-wet. Values up to 8 have been reported in very oil-wet rocks.

A unit equal to the percentage of a given fluid in the total volume of a pore space. The term is abbreviated to s.u. and lies between 0 and 100.

A short length of drill collar that has male threads on one end and female on the other. It is screwed onto the bottom of the kelly or topdrive and onto the rest of the drillstring. When the hole must be deepened, and pipe added to the drillstring, the threads are unscrewed between the saver sub and the rest of the drillstring, as opposed to between the kelly or topdrive and the saver sub. This means that the connection between the kelly or topdrive and the saver sub rarely is used, and suffers minimal wear and tear, whereas the lower connection is used in almost all cases and suffers the most wear and tear. The saver sub is expendable and does not represent a major investment. However, the kelly or topdrive component threads are spared by use of a saver sub, and those components represent a significant capital cost and considerable downtime when replaced.

A mineraldeposit that can occur in the tubing, the gravel pack, the perforations or the formation. Scale deposition occurs when the solution equilibrium of the water is disturbed by pressure and temperature changes, dissolved gases or incompatibility between mixing waters. Scale deposits are the most common and most troublesome damage problems in the oil field and can occur in both production and injection wells.All waters used in well operations can be potential sources of scale, including water used in waterflood operations and filtrate from completion, workover or treating fluids. Therefore, reduction of scale deposition is directly related to reduction of bad water production.

A chemical treatment used to control or prevent scale deposition in the production conduit or completion system. Scale-inhibitor chemicals may be continuously injected through a downhole injection point in the completion, or periodic squeeze treatments may be undertaken to place the inhibitor in the reservoirmatrix for subsequent commingling with produced fluids.Some scale-inhibitor systems integrate scale inhibitors and fracture treatments into one step, which guarantees that the entire well is treated with scale inhibitor. In this type of treatment, a high-efficiency scale inhibitor is pumped into the matrix surrounding the fracture face during leakoff. It adsorbs to the matrix during pumping until the fracture begins to produce water. As water passes through the inhibitor-adsorbed zone, it dissolves sufficient inhibitor to prevent scale deposition. The inhibitor is better placed than in a conventional scale-inhibitor squeeze, which reduces the retreatment cost and improves production.

A type of inhibition treatment used to control or prevent scale deposition. In a scale-inhibitorsqueeze, the inhibitor is pumped into a water-producing zone. The inhibitor is attached to the formationmatrix by chemical adsorption or by temperature-activated precipitation and returns with the produced fluid at sufficiently high concentrations to avoid scale precipitation. Some chemicals used in scale-inhibitor squeezes are phosphonated carboxylic acids or polymers.

A common well-intervention operation involving a wide variety of mechanical scale-inhibitor treatments and chemical options. Mechanical removal is done by means of a pig or by abrasive jetting that cuts scale but leaves the tubing untouched. Scale-inhibition treatments involve squeezing a chemical inhibitor into a water-producing zone for subsequent commingling with produced fluids, preventing further scale precipitation. Chemical removal is performed with different solvents according to the type of scale:· Carbonate scales such as calcium carbonate or calcite [CaCO3] can be readily dissolved with hydrochloric acid [HCl] at temperatures less than 250oF [121oC].· Sulfate scales such as gypsum [CaSO4·2H2O] or anhydrite [CaSO4] can be readily dissolved using ethylenediamine tetraacetic acid (EDTA). The dissolution of barytine [BaSO4] or strontianite [SrSO4] is much more difficult.· Chloride scales such as sodium chloride [NaCl] are easily dissolved with fresh water or weak acidic solutions, including HCl or acetic acid.· Iron scales such as iron sulfide [FeS] or iron oxide [Fe2O3] can be dissolved using HCl with sequestering or reducing agents to avoid precipitation of by-products, for example iron hydroxides and elemental sulfur.· Silica scales such as crystallized deposits of chalcedony or amorphous opal normally associated with steamflood projects can be dissolved with hydrofluoric acid [HF].

A type of inhibition treatment used to control or prevent scale deposition. In a scale-inhibitorsqueeze, the inhibitor is pumped into a water-producing zone. The inhibitor is attached to the formationmatrix by chemical adsorption or by temperature-activated precipitation and returns with the produced fluid at sufficiently high concentrations to avoid scale precipitation. Some chemicals used in scale-inhibitor squeezes are phosphonated carboxylic acids or polymers.

A perforating gun with a recess profile in the perforating gun body adjacent to the shaped charge. The scallop profile reduces the external burrs created as the perforating jet exits the gun body, thereby reducing the risk of hang-up or damage as the gun assembly is retrieved.

A graph in which data points are plotted but not connected. The x and y axes of the scattergram represent the two variables being plotted. Sometimes, the data points are coded by using color or symbols to represent a third dimension.

A treating chemical that is added to a drilling mud or other fluid to react with a contaminant to change the contaminant to a less harmful compound. If a contaminant is harmful at very low concentration, a scavenger must be able to remove the contaminant to an even lower concentration to ensure safety.

A device for measuring the number and energy of gamma rays. The device consists of a crystal and a photomultiplier. In the crystal, an incident gamma ray imparts energy to electrons through Compton scattering, photoelectric absorption and pair production. The electrons excite the detector crystal lattice. Crystal de-excitation emits visible or near-visible light, the scintillation, which is detected by the photomultiplier and transformed into an electrical pulse. The frequency and amplitude of the electric pulse are related to the number of gamma rays and their respective energy levels, and are recorded in a log. Scintillation detectors are used in all natural gamma ray, induced gamma ray and density logging devices.

To inspect an area or to monitor activity.

A brief report about a well from the time it is permitted through drilling and completion. A scout ticket typically includes the location, total depth, logs run, production status and formation tops.

(noun) A mechanical device run inside casing or tubing on drillpipe, wireline, or coiled tubing to remove scale, cement, rust, paraffin, or other deposits from the inner wall of the tubular, restoring full bore diameter and preparing the surface for subsequent operations such as logging, packer setting, or cementing.

Equipment placed in a pipeline for inserting or retrieving a pipeline scraper (pig).

A device for cleaning mud and mud filtercake off of the wellbore wall when cementing casing in the hole to ensure good contact and bonding between the cement and the wellbore wall. The scratcher is a simple device, consisting of a band of steel that fits around a joint of casing, and stiff wire fingers or cable loops sticking out in all directions around the band (360-degree coverage). A scratcher resembles a bottlebrush, but its diameter is greater than its height. Importantly, for scratchers to be effective, the casing must be moved. This movement may be reciprocal motion in and out of the wellbore, rotary motion, or both. In general, the more motion, the better the cement job will be.

(noun) A downhole filtering device installed across a producing interval to prevent the entry of formation sand into the wellbore while permitting the flow of reservoir fluids. Screens are manufactured in various configurations including wire-wrapped, premium mesh, and prepacked designs, and are a primary component of sand control completions.

A preliminary assessment of the suitability of a reservoir for a particular process or development methodology. The assessment compares the reservoir characteristics to a number of screening criteria. The criteria are developed by studying the reservoir characteristics of similar past projects and identifying the ones that influenced success or failure of the process or methodology, or are consistently present where the process or methodology succeeded or failed.

A condition encountered during some gravel-pack operations whereby the treatment area cannot accept further pack sand and a sudden increase in treatment pressure occurs. Under ideal conditions, this should signify that the entire void area has been successfully packed with sand. However, if screenout occurs early in the treatment, it may indicate an incomplete treatment and the presence of undesirable voids within the pack zone.

To remove impurities, water, liquid hydrocarbons or traces of other gases by passing the gas flowstream through a scrubber, a device in which the gas is mixed with a suitable liquid that absorbs or washes out the constituent to be removed.

A device to remove dirt, water, foreign matter, or undesired liquids that are part of the gas flowstream. Air can be used to absorb water; also an oil bath might be useful to remove dust, dirt or other liquids. A scrubber is used to protect downstream rotating equipment or to recover valuable liquids from gas.

Oil recovered from a knockout or scrubber device.

A type of receiver that can be positioned on the seafloor to acquire seismic data.

A relatively impermeable rock, commonly shale, anhydrite or salt, that forms a barrier or cap above and around reservoir rock such that fluids cannot migrate beyond the reservoir. A seal is a critical component of a complete petroleum system. The permeability of a seal capable of retaining fluids through geologic time is ~ 10-6 to 10-8 darcies.

A system of seals arranged on the component that engages in a sealbore to isolate the production-tubing conduit from the annulus. The seal assembly is typically longer than the sealbore to enable some movement of the components while maintaining an efficient seal.

A profiled completion component designed to accept a mating component equipped with a seal assembly. Completions are designed with seal receptacles to enable the production string to be removed without removing the packer or permanent completion components.

A polished bore designed to accept a seal assembly, such as may be used in a permanent production packer.

A type of production packer that incorporates a sealbore that accepts a seal assembly fitted to the bottom of the production tubing. The sealbore packer is often set on wireline to enable accurate depth correlation. For applications in which a large tubing movement is anticipated, as may be due to thermal expansion, the sealbore packer and seal assembly function as a slip joint.

The geological barriers that isolate fluid compartments within reservoirs or that hydraulically isolate reservoirs from each other. The seals may contain fluids (for example shales) but have very low permeability. The properties of seals can determine the height of hydrocarbon column trapped below them.

(noun) A short, internally profiled section of tubing installed in a completion string that provides a machined bore for setting and sealing flow-control devices such as plugs, blanking tools, and check valves. Unlike a landing nipple, a seating nipple accepts devices that seal by interference fit rather than a locking mechanism.

A water-base mud designed for offshore drilling whose make-up water is taken from the ocean. Sea water contains relatively low salinity, about 3 to 4 wt. % NaCl, but has a high hardness because of Mg+2 and Ca+2 ions. Hardness is removed from sea water by adding NaOH, which precipitates Mg+2 as Mg(OH)2, and by adding Na2CO3, which removes Ca+2 as CaCO3. Mud additives are the same as those used in freshwater mud-bentoniteclay, lignosulfonate, lignite, carboxymethylcellulose or polyanionic cellulose and caustic soda. XC polymer may also be used in place of bentonite. Higher concentrations of each additive are required because of salinity effects. Bentonite (if used) should be prehydrated in fresh water.

The movement of generated hydrocarbons into a reservoir after their expulsion, or primary migration, from a source rock.

The porosity created through alteration of rock, commonly by processes such as dolomitization, dissolution and fracturing.

The method used to sustain production levels at viable rates following a fall in flow rate as the efficiency of the primary production methods declines. Secondary production methods frequently involve an artificial-lift system or reservoir injection for pressure maintenance.

The second stage of hydrocarbonproduction during which an external fluid such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore.The most common secondary recovery techniques are gas injection and waterflooding. Normally, gas is injected into the gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form or enhanced recovery.The secondary recovery stage reaches its limit when the injected fluid (water or gas) is produced in considerable amounts from the production wells and the production is no longer economical. The successive use of primary recovery and secondary recovery in an oil reservoir produces about 15% to 40% of the original oil in place.

The term of an oil and gas lease in which the lease is held in force after expiration of the primary term. Production, operations, continuous drilling and/or shut-in royalty payments are often used to extend an oil and gas lease into its secondary term.

An indicator of the porosity that does not contribute to a sonic measurement of interval transit time. The transit time is little affected by vugs, fractures and other irregular events because the sonic wave finds a faster path around them. Spherical pores such as oomolds also have less effect on traveltime than oblate pores. Thus, when the sonic porosity is less than some measurement of the total porosity, the difference can be attributed to the presence of post-depositional, or secondary, porosity. The sonic porosity is usually derived from the Wyllie time-average equation, or some other suitable transform, and the total porosity taken as the density-neutron crossplot porosity.

The unconsolidated grains of minerals, organic matter or preexisting rocks, that can be transported by water, ice or wind, and deposited. The processes by which sediment forms and is transported occur at or near the surface of the Earth and at relatively low pressures and temperatures. Sedimentary rocks form from the accumulation and lithification of sediment. Sediments are classified according to size by the Udden-Wentworth scale.

One of the three main classes of rock (igneous, metamorphic and sedimentary). Sedimentary rocks are formed at the Earth's surface through deposition of sediments derived from weathered rocks, biogenic activity or precipitation from solution. Clastic sedimentary rocks such as conglomerates, sandstones, siltstones and shales form as older rocks weather and erode, and their particles accumulate and lithify, or harden, as they are compacted and cemented. Biogenic sedimentary rocks form as a result of activity by organisms, including coral reefs that become limestone. Precipitates, such as the evaporite minerals halite (salt) and gypsum can form vast thicknesses of rock as seawater evaporates. Sedimentary rocks can include a wide variety of minerals, but quartz, feldspar, calcite, dolomite and evaporite group and clay group minerals are most common because of their greater stability at the Earth's surface than many minerals that comprise igneous and metamorphic rocks. Sedimentary rocks, unlike most igneous and metamorphic rocks, can contain fossils because they form at temperatures and pressures that do not obliterate fossil remnants.

A depression in the crust of the Earth formed by plate tectonic activity in which sediments accumulate. Continued deposition can cause further depression or subsidence. Sedimentary basins, or simply basins, vary from bowl-shaped to elongated troughs. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, hydrocarbon generation can occur within the basin.

The process of separation of the components of a cementslurry during which the solids settle. Sedimentation is one of the characterizations used to define slurry stability.

Pertaining to waves of elastic energy, such as that transmitted by P-waves and S-waves, in the frequency range of approximately 1 to 100 Hz. Seismic energy is studied by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. "Seismic," used as an adjective, is preferable to "seismics," although "seismics" is used commonly as a noun.

(noun) The process of analysing seismic data to extract geological information about subsurface structures, stratigraphy, and rock properties. Seismic interpretation involves identifying and mapping reflectors, faults, unconformities, and stratigraphic features, and integrating these with well data to build geological models for exploration and development.

The comparison, simulation or representation of seismic data to define the limits of seismic resolution, assess the ambiguity of interpretation or make predictions. Generation of a synthetic seismogram from a well log and comparing the synthetic, or modeled trace, with seismic data is a common direct modeling procedure. Generating a set of pseudologs from seismic data is the process known as seismic inversion, a type of indirect modeling. Models can be developed to address problems of structure and stratigraphy prior to acquisition of seismic data and during the interpretation of the data. As Sheriff (1991) points out, agreement between data and a model does not prove that the model is correct, since there can be numerous models that agree with a given data set.

Traces recorded from a single shotpoint. Numerous seismic records are displayed together in a single seismic section.

A display of seismic data along a line, such a 2D seismic profile or a profile extracted from a volume of 3D seismic data. A seismic section consists of numerous traces with location given along the x-axis and two-way traveltime or depth along the y-axis. The section is called a depth section if the section has been converted from time to depth and a time section if this has not been done.

The seismic data recorded for one channel. A seismic trace represents the response of the elastic wavefield to velocity and density contrasts across interfaces of layers of rock or sediments as energy travels from a source through the subsurface to a receiver or receiver array.

A technique for acquiring a vertical seismicprofile that uses the noise of the drill bit as a source and receivers laid out along the ground or seabed; also called a drill-noise VSP. In deep water, the receiver arrays can be deployed vertically. Acquisition and processing are typically more challenging than in the more conventional types of VSPs, but the while-drilling technique can yield immediate time-depth information and, less frequently, reflection information. The information from a drill-noise VSP can be used to improve time-depth conversions while drilling, decide where to set casing in a well and evaluate drilling hazards, such as anomalousporepressure.

Traces recorded from a single shotpoint. Numerous seismograms are displayed together in a single seismic section.

A device or system that records the ground oscillations that make upexplorationseismic data or earthquakes, sometimes used incorrectly as a synonym for geophone. A seismograph can include amplifiers, receivers and a recording device (such as a computer disk or magnetic tape) to record seismograms. A crude seismograph was built in 1855 by Italian physicist Luigi Palmieri (1807 to 1896). The modern seismograph, which used a pendulum, was invented in 1880 by James Ewing, Thomas Gray and Sir John Milne.

The study of seismic or elastic waves, such as from earthquakes, explosions or other causes. Interpretation of the structure and composition of the Earth from artificially created seismic waves is a chief concern of seismologists exploring for hydrocarbons and other resources. English physicist John Mitchell (1724 to 1793) is known as the founder of seismology in part because of his observation that one can determine an earthquake's epicenter, or point of origin in the subsurface, by measuring the arrival time of earthquake waves at different locations. The invention of the modern seismograph in 1880 promoted further studies of earthquakes.

A device that records seismic energy in the form of ground motion and transforms it to an electrical impulse.

The technique of selectively firing successive perforating guns arranged in a multiple gun assembly. This method is used when several intervals are to be perforated in one run and when the gun assembly must be relocated before the guns are fired. The resulting perforation pattern is known as selective perforating.

A type of landing nipple designed to be run in a series throughout the wellbore. Two basic types of selective nipple system may be encountered, a nipple series in which the nipple design or profile determines the selectivity and one in which the running tool is used to find the target nipple.

A technique used to fire individual perforating guns when multiple guns have been run together in a single trip into the well. Selective firing is used to improve operational efficiency when several intervals are to be perforated.

A wireline tool to set and retrieve selectively set downhole equipment such as plugs and similar flow-control devices. The selective running tool enables equipment to be set in a target nipple that may be one of a series placed throughout the wellbore.

A quantitative measure of the coherence of seismic data from multiple channels that is equal to the energy of a stacked trace divided by the energy of all the traces that make up the stack. If data from all channels are perfectly coherent, or show continuity from trace to trace, the semblance has a value of unity.

What Is a Semisubmersible? A semisubmersible is a floating offshore drilling or production unit supported on large submerged pontoons connected to the main deck by a series of vertical columns and structural braces. The pontoon-and-column configuration produces a very low waterplane area, giving the vessel exceptional stability in rough seas and enabling continuous drilling operations in water depths from 300 metres to more than 3,600 metres (984 feet to 11,811 feet). Key Takeaways A semisubmersible floats on submerged pontoons ballasted with seawater, keeping the hull below the wave-action zone to minimise heave, pitch, and roll. The first semisubmersible, Blue Water Rig No. 1, was converted from a submersible unit by Shell engineer Bruce Collipp in 1961; the first purpose-built semi drilling rig was Ocean Driller, launched in 1963. Modern ultra-deepwater semis operate in water depths of 2,000 to 3,600 metres (6,562 to 11,811 feet) using either spread-mooring systems or Class DP-3 dynamic positioning with triple-redundant thrusters. A blowout preventer stack is landed on the seafloor wellhead and connected to the rig floor via a riser; the lower marine riser package (LMRP) allows emergency disconnect without well abandonment. Semisubmersibles are classified as Mobile Offshore Drilling Units (MODUs) and governed by IMO regulations, SOLAS, MARPOL Annex I, and flag-state requirements, with structural certification by classification societies such as ABS, DNV, Lloyd's Register, and Bureau Veritas. How a Semisubmersible Works A semisubmersible achieves its characteristic stability by flooding its lower pontoons with variable ballast water. When moving between locations, the pontoons are partially dewatered to raise the hull and reduce drag. Once on location, the ballast system pumps seawater back into the pontoons until the vessel reaches its designed operating draft, typically 20 to 30 metres (66 to 98 feet). At this draft, the wave-zone waterplane area is greatly reduced compared to a ship-shaped vessel, so ocean waves impart far less vertical force on the structure. Stability calculations follow IMO resolution MSC.235(82) for MODUs, which specifies intact and damage stability criteria including righting lever (GZ) curves, minimum metacentric height, and maximum allowable heel in damaged conditions. The drilling package sits on the main deck, elevated 30 to 45 metres (98 to 148 feet) above the waterline by the columns. A top drive system rotates the drill string through the rotary table. The bottom hole assembly incorporates logging-while-drilling and measurement-while-drilling tools that transmit formation data in real time via mud-pulse or electromagnetic telemetry. Drilling fluid circulates down the drill string, cools the bit, carries cuttings to surface, and manages wellbore pressure; mud weight is monitored continuously as a primary well control parameter. If a kick is detected, the driller activates the BOP stack on the seafloor, closing either ram preventers or the annular preventer to contain wellbore pressure while the well is circulated out. Deck variable load (DVL) is the total live load the main deck structure can carry above its operating draft, typically 5,000 to 10,000 short tons (4,536 to 9,072 metric tons) on a modern sixth-generation semi. DVL encompasses the drilling package, riser string, casing joints, bulk drilling fluid inventory, barite, cement, and provisions. Structural load analysis follows American Bureau of Shipping (ABS) Rules for Building and Classing Mobile Offshore Drilling Units or the equivalent DNV-OS-C201 standard. Crane capacity on modern semis ranges from 250 to 450 metric tons (276 to 496 short tons) per pedestal crane, permitting lifts of subsea equipment to and from the seafloor. Semisubmersible Rigs Across International Jurisdictions Regulatory frameworks for semisubmersibles vary by region, but all are grounded in the IMO Code for the Construction and Equipment of Mobile Offshore Drilling Units (MODU Code, 2009 edition). Flag states enforce the MODU Code through their maritime administrations; operators must also satisfy the requirements of the coastal state in whose waters the rig operates. United States Gulf of Mexico: The Bureau of Safety and Environmental Enforcement (BSEE) regulates MODUs under 30 CFR Part 250, Subpart D. Operators must submit a Drilling Permit and an Application for Permit to Drill (APD), demonstrating well control barriers, BOP certification per API Standard 53, and a well control response plan. The Macondo disaster of April 2010 involved the Transocean Deepwater Horizon, a fifth-generation semisubmersible operating in 1,524 metres (5,000 feet) of water in Mississippi Canyon Block 252. The resulting Deepwater Horizon Well Control Rule (30 CFR Part 250, Subpart G, 2016) tightened BOP testing intervals, required third-party verification of well control equipment, and mandated real-time monitoring of BOP status. Post-Macondo, BSEE also requires operators to demonstrate access to capping stack equipment capable of shutting in a well at maximum anticipated surface pressure. Norway and the North Sea: The Petroleum Safety Authority Norway (Ptil, Petroleumstilsynet) oversees drilling safety on the Norwegian Continental Shelf (NCS) under the Framework Regulations, Activities Regulations, and Facilities Regulations. NORSOK standard D-010 (Well Integrity in Drilling and Well Operations) is the primary technical reference for well barrier philosophy, BOP configuration, and emergency disconnect procedures on semis operating on the NCS. Norwegian regulations also require a Safety and Emergency Response Manual (SEREM) and independent verification of safety-critical equipment by a recognised body. Major semi operators on the NCS include Transocean (Transocean Enabler, Transocean Spitsbergen) and Odfjell Drilling (Deepsea Aberdeen, Deepsea Nordkapp). Australia: The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) administers offshore drilling safety under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGSA) and associated regulations. Operators drilling in Australian Commonwealth waters must submit a Well Operations Management Plan (WOMP) demonstrating two independent well barriers at all times, consistent with NOPSEMA's Well Integrity Guidelines. Semisubmersibles have been deployed in the Carnarvon Basin and Browse Basin for deepwater exploration by operators including Woodside Energy and Chevron. Water depths in these basins can reach 1,500 metres (4,921 feet) on the shelf edge and beyond. Canada (Atlantic Offshore): Offshore drilling east of Canada falls under joint provincial-federal regulators: the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) for the Newfoundland and Labrador shelf, and the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) for the Scotian Shelf. These boards enforce requirements under the Canada Oil and Gas Operations Act (COGOA) and provincial mirror legislation. Deepwater exploration wells on the Scotian Shelf, targeting Jurassic-age plays in water depths of 2,000 metres (6,562 feet) or more, have used semisubmersibles including the Stena DrillMAX. The Flemish Pass Basin off Newfoundland, developed by companies including Equinor (Bay du Nord), also requires semi operations in approximately 1,200 metres (3,937 feet) of water. Middle East and Caspian: While the Arabian Gulf is predominantly shallow and dominated by jackup rigs, deepwater activity exists in the Gulf of Oman, the Red Sea, and the Caspian Sea. ADNOC (Abu Dhabi National Oil Company) conducts deepwater exploration in the Gulf of Oman using floating units governed by the UAE's Federal Authority for Nuclear Regulation and emirate-level petroleum departments. In the Caspian, Azerbaijan's SOCAR and BP operate in water depths to 1,000 metres (3,281 feet) under the production sharing agreement (PSA) framework; semisubmersibles have been used for Shah Deniz and ACG development drilling. Fast Facts First semisubmersible: Blue Water Rig No. 1, converted by Bruce Collipp (Shell), 1961 First purpose-built semi: Ocean Driller, 1963 Typical operating draft: 20-30 m (66-98 ft) on station Ultra-deepwater rated depth: up to 3,600 m (11,811 ft) Maximum drilling depth (MD): typically 9,000-12,000 m (29,528-39,370 ft) Deck variable load (DVL): 5,000-10,000 short tons (4,536-9,072 metric tons) Pontoon count: typically 2 (catamaran-style); some designs use 3 Column count: typically 4-8 connecting pontoons to main deck Classification societies: ABS, DNV, Lloyd's Register, Bureau Veritas Structural Design and Motion Response The structural system of a semisubmersible consists of three primary elements: lower hulls (pontoons), vertical columns, and the main deck box structure. Pontoons are typically rectangular or circular in cross-section, 100 to 130 metres (328 to 427 feet) long, and house the ballast water tanks, void spaces, chain lockers, mud pits (on some designs), and machinery spaces. Columns, typically 10 to 15 metres (33 to 49 feet) in diameter, carry the deck loads in compression and transfer wave-induced shear forces to the pontoons. Diagonal braces and horizontal braces (fitted on older designs; many modern semis are braceless) provide global torsional stiffness. The main deck houses the drill floor, setback area, mud chemical storage, accommodation block, helideck, and utility spaces. Motion response is characterised by the Response Amplitude Operator (RAO), which describes the rig's heave, pitch, and roll amplitude per unit wave height as a function of wave frequency. Modern semis are engineered so that their natural heave period (typically 20 to 28 seconds) falls well outside the peak energy period of ocean waves (8 to 16 seconds), minimising resonant amplification. Classification societies require that the maximum single-amplitude heave in the 10-year return period storm remain below the limiting value for the marine riser; typical limits are 5 to 8 metres (16 to 26 feet) for a 533 mm (21-inch) marine drilling riser. Vortex-induced vibration (VIV) of the riser is managed by riser buoyancy modules and helical strakes that disrupt coherent vortex shedding. In severe conditions where heave exceeds riser limits, the driller must disconnect the LMRP and either move off location or wait for the weather to moderate. Station-keeping divides into two categories. Spread mooring uses 8 to 12 anchors deployed in a symmetrical radial pattern around the rig, each connected by a combination of studless chain (40 to 76 mm / 1.6 to 3.0 inches diameter), wire rope, or polyester rope. Polyester rope is preferred for water depths exceeding 1,500 metres (4,921 feet) because its lower unit weight reduces top tension. Dynamic positioning (DP) uses multiple azimuthing thrusters (typically 8 to 10, each rated at 3.5 to 5.5 MW) and acoustic position reference sensors (HIPAP, USBL), differential GPS (DGPS), and Artemis microwave radar to hold station within a radius of 2 to 4 percent of water depth. IMO MSC/Circ.645 defines DP Class 2 (two independent control systems) and DP Class 3 (triple redundancy with physical separation of all redundant components by an A60 fire/flood barrier); most ultra-deepwater semis operate to DP Class 3. The DP system must be capable of maintaining station in the 10-year storm without loss of position.

In matrixstimulation, a characteristic of rock that indicates the degree of reaction between the rock minerals and a given treating fluid. A formation is described as sensitive if a given stimulating fluid damages the formation. The detrimental reactions include disaggregation and collapse of the matrix, release of fines or formation of precipitates.Sensitivity depends on the overall reactivity of the formation minerals with the fluid; reactivity depends on the structure of the rock and the distribution of minerals within the rock.Sandstone sensitivity also depends on permeability; low-permeability formations are normally more sensitive than high-permeability sandstones for a given mineralogy because certain types of damage, such as formation of precipitates, are more harmful in small pore throats (as in low-permeability formations).

A cylindrical or spherical vessel used to separate oil, gas and water from the total fluid stream produced by a well. Separators can be either horizontal or vertical.Separators can be classified into two-phase and three-phase separators (commonly called free-water knockout). The two-phase type deals only with oil and gas, while the three-phase type handles oil, water and gas. Additionally, separators can be categorized according to their operating pressure. Low-pressure units handle pressures of 10 to 180 psi [69 to 1241 kPa]. Medium-pressure separators operate from 230 to 700 psi [1586 to 4826 kPa]. High-pressure units handle pressures of 975 to 1500 psi [6722 to 10,342 kPa].Gravity segregation is the main force that accomplishes the separation, which means the heaviest fluid settles to the bottom and the lightest fluid rises to the top. Additionally, inside the vessel, the degree of separation between gas and liquid will depend on the separator operating pressure, the residence time of the fluid mixture and the type of flow of the fluid. Turbulent flow allows more bubbles to escape than laminar flow.

The pressure required to force fluids to enter a separator.

The gas that remains after its separation from condensate.

A clay mineral with long, slender, needle-like structure, similar to attapulgite. It contains a mixture of fibrous and amorphous clay-like materials. API and ISO specifications exist for sepiolite used in drilling fluids.

A group of relatively conformable strata that represents a cycle of deposition and is bounded by unconformities or correlative conformities. Sequences are the fundamental unit of interpretation in sequence stratigraphy. Sequences comprise systems tracts.

A surface that separates older sequences from younger ones, commonly an unconformity (indicating subaerial exposure), but in limited cases a correlative conformable surface. A sequence boundary is an erosional surface that separates cycles of deposition.

What Is Sequence Stratigraphy? Sequence stratigraphy interprets basin-filling sedimentary successions in a framework of eustasy, tectonic subsidence, and sediment supply, dividing the rock record into genetically related packages called sequences bounded by unconformities or their correlative conformities. Geoscientists apply the method globally to predict reservoir and source rock distribution ahead of drilling, correlate wells across mature basins, and characterize trap geometry in frontier exploration from the Western Canadian Sedimentary Basin to the Norwegian Continental Shelf. Key Takeaways A depositional sequence is a relatively conformable succession of genetically related strata bounded at top and bottom by unconformities and their lateral equivalents, representing a complete cycle of relative sea-level rise and fall, subsidence, and sediment input; recognizing these boundaries in seismic data, wireline logs, and outcrop is the fundamental skill of sequence stratigraphic practice. Three systems tracts subdivide every sequence: the lowstand systems tract (LST) deposited when relative sea level is falling or at its lowest, the transgressive systems tract (TST) deposited during sea-level rise, and the highstand systems tract (HST) deposited when relative sea level is high and falling-stage progradation begins; each tract has a characteristic distribution of reservoir, seal, and source rock facies. Accommodation, the space available for sediment accumulation above the base level, is the master variable in sequence stratigraphy: it equals the sum of eustatic sea-level change and tectonic subsidence, meaning that rising sea level and basin subsidence both create accommodation, while sea-level fall and uplift destroy it. The method originated at Exxon Production Research in the 1960s and 1970s, culminating in the landmark 1977 AAPG Memoir 26 "Seismic Stratigraphy: Applications to Hydrocarbon Exploration" by Vail, Mitchum, Thompson, and colleagues, which introduced reflection termination patterns (onlap, offlap, toplap, downlap) that remain the primary seismic-scale sequence boundary recognition criteria today. Sequence stratigraphy directly guides reserve estimation by predicting reservoir geometry and continuity: lowstand basin-floor fans in the deepwater Gulf of Mexico have produced multi-billion-barrel fields, while condensed section shales in the transgressive systems tract are the source rocks for many of North America's most prolific conventional plays. How Sequence Stratigraphy Works Sequence stratigraphic analysis begins by identifying bounding surfaces in available data: unconformities visible on seismic as truncation or onlap of reflectors, maximum flooding surfaces recognizable as condensed sections rich in organic matter and marine microfossils, and transgressive surfaces marking the base of the first flooding event in each sequence. In a well dataset, a gamma-ray log shows the characteristic coarsening-upward motif of a highstand prograding delta as a progressively decreasing GR trend, while a transgressive systems tract appears as a retrogradational stack of cleaning-upward parasequences fining landward. The spontaneous potential and resistivity logs further define individual parasequences, the basic building blocks of systems tracts: a parasequence is a relatively conformable shallowing-upward succession bounded by marine flooding surfaces, typically a few meters to tens of meters thick. Multiple parasequences stack into parasequence sets that collectively define the lowstand, transgressive, and highstand tracts. Eustasy (global sea-level change driven by ocean volume changes and ice-volume fluctuations) and subsidence (basin deepening driven by thermal cooling, loading, or rifting) combine to control accommodation, defined as the vertical space between the depositional surface and base level. When accommodation is created faster than sediment can fill it, the shoreline retreats landward (transgression) and the basin fills with deeper-water facies. When sediment supply keeps pace with or exceeds accommodation creation, the shoreline advances seaward (progradation, characteristic of the highstand). When accommodation is destroyed by falling relative sea level, rivers incise valleys into exposed coastal plains and deltas, creating incised valley fills that serve as some of the world's most prolific stratigraphic traps. The Exxon group formalized these relationships in a conceptual model linking eustatic cycles of varying periodicity (first through fourth order cycles, ranging from tens of millions of years down to 100,000-year Milankovitch cycles) to observed seismic stratigraphic patterns, producing the global sea-level curve first published in AAPG Memoir 26 and refined continuously since. The practical workflow integrates seismic interpretation, well-log correlation, biostratigraphy (using microfossil assemblages to constrain water depth and age), and geochemistry (organic carbon content in condensed sections). In frontier basins with few wells, seismic stratigraphy dominates, using reflection termination patterns to delineate sequence boundaries and systems tract geometries across tens of kilometers. In mature fields such as the Montney in northeastern British Columbia, the Brent Group in the North Sea, or the Ghawar Arab formation in Saudi Arabia, dense well grids allow high-resolution sequence stratigraphic frameworks calibrated by dozens or hundreds of wireline logs, enabling reservoir unit correlation at the parasequence scale and direct mapping of net pay thickness. Sequence Stratigraphy Across International Jurisdictions In Canada, sequence stratigraphy underpins reservoir characterization and reserve estimation across the Western Canadian Sedimentary Basin (WCSB). The Montney Formation of northeastern British Columbia and northwestern Alberta is a world-class example of sequence stratigraphic control on unconventional reservoir quality. The Montney spans the Early Triassic and records multiple cycles of sea-level change that produced stacked packages of clean siltstones (lowstand and highstand reservoir facies) interbedded with tighter, argillaceous siltstones deposited in deeper, lower-energy settings. The BC Energy Regulator (BCER) and the AER require operators to submit wireline log databases, core descriptions, and formation evaluation reports that collectively support regional sequence stratigraphic frameworks used in resource assessments. The Duvernay Formation of central Alberta, a Late Devonian carbonate and organic shale, forms a sequence stratigraphic package that includes both the source rock (transgressive condensed section) and tight carbonate reservoir (lowstand and highstand flanks) within a single sequence, making it one of the most elegant self-sourced plays in North American exploration. Natural Resources Canada (NRCan) and provincial geological surveys publish regional sequence stratigraphic maps of the WCSB that operators incorporate into prospect evaluations. The Devonian Leduc reef complexes in Alberta, prolific conventional oil reservoirs, are controlled by carbonate platform growth patterns that sequence stratigraphy predicts as highstand aggradational banks, with incised valley fills in the overlying Wabamun and Winterburn groups forming additional trapping configurations. In the United States, sequence stratigraphy transformed deepwater exploration in the Gulf of Mexico. The Paleogene Wilcox, Miocene Mars-Ursa, and Pliocene to Pleistocene Auger and Cognac fairways all owe their discovery to recognition that lowstand turbidite fans deposited at the mouths of incised submarine canyons form sheet-like or lobate sand bodies with excellent reservoir properties beneath thick shale seals. The US Geological Survey (USGS) and the Bureau of Ocean Energy Management (BOEM) use sequence stratigraphic frameworks to define prospective fairways in frontier outer continental shelf (OCS) lease sales. Onshore, the Williston Basin's Bakken Formation is a textbook sequence stratigraphic play: the Lower and Upper Bakken Shales are condensed section source rocks deposited at maximum flooding, bracketing the Middle Bakken siltstone and carbonate reservoir deposited in a transgressive to highstand shallow marine setting. The USGS Bakken resource assessment, which estimated 7.4 billion barrels of technically recoverable oil in the Williston Basin, was grounded in sequence stratigraphic mapping of Middle Bakken reservoir continuity across North Dakota and Montana. The Texas Permian Basin's Wolfcamp and Dean sequences similarly reflect alternating lowstand carbonate turbidites and highstand carbonate platforms, and the Railroad Commission of Texas (RRC) recognizes these sequence-stratigraphic units in its official formation names. In Australia, sequence stratigraphy guides exploration in multiple world-class basins. The Cooper Basin of South Australia and Queensland is one of the most intensively studied basins in the Southern Hemisphere, with a sequence stratigraphic framework spanning Permian to Jurassic that defines the distribution of the Patchawarra, Tirrawarra, and Epsilon Formation gas reservoirs in fluvial to fluviodeltaic settings. Geoscience Australia and the South Australian Department for Energy and Mining publish open-access sequence stratigraphic data packages for the Cooper Basin. The Carnarvon Basin offshore Western Australia, home to the North West Shelf LNG developments at Barrow Island and the Jansz-Io field supplying Gorgon, is characterized by Jurassic to Cretaceous sequences including the Mungaroo Formation (major gas reservoir) deposited in a fluvial-deltaic to shallow marine setting. The Browse Basin to the north, still in active development planning, hosts the Ichthys and Browse LNG prospects in Jurassic deep-water turbidite and shelf carbonate sequences. NOPSEMA requires sequence stratigraphic support in environment plans and drilling programs for offshore frontier exploration. Geoscience Australia's basin studies program applies sequence stratigraphy to frontier Australian basins, including the Bight Basin and the Canning Basin, to characterize untested petroleum systems. In the Middle East, sequence stratigraphy is foundational to understanding the world's largest conventional oil accumulations. The Arab formation of Saudi Arabia, Kuwait, and the UAE is a Late Jurassic carbonate sequence with four members (Arab-A through Arab-D) each consisting of a progradational carbonate grainstone and packstone reservoir capped by an evaporite seal (the Hith anhydrite). The Arab-D member at Ghawar, the world's largest oil field, represents a highstand carbonate shoal complex that is mappable in exquisite detail using sequence stratigraphic methods applied to dense well grids compiled by Saudi Aramco. Sequence boundaries within the Jurassic Arab sequence correspond to exposure surfaces and paleokarst horizons that affect reservoir heterogeneity and fluid flow. The Cretaceous Mishrif Formation, a major reservoir in Iraq, Iran, Kuwait, and the UAE, is a reef and shoal complex deposited during transgressive and highstand systems tracts, with overlying Sarvak and Laffan shales providing regional seals. Abu Dhabi National Oil Company (ADNOC) applies high-resolution sequence stratigraphy to field development planning in the Rumaitha, Shanayel, and Bu Hasa fields to map reservoir architecture at inter-well scales, directly informing producer-injector placement for maximum sweep efficiency. In Norway and the wider North Sea, the Brent Group (Middle Jurassic) is the archetype of a sequence stratigraphically controlled deltaic reservoir. The Brent delta prograded northward into the Viking Graben during a mid-Jurassic highstand, depositing the Broom, Rannoch, Etive, Ness, and Tarbert formations. The Tarbert Formation, the uppermost Brent member, records transgressive reworking of the highstand delta top, and the overlying Heather Formation shales are transgressive condensed section seals. Major North Sea fields including Statfjord, Gullfaks, and Brent itself produce from Brent Group reservoir units whose geometry and connectivity were defined by sequence stratigraphic mapping using wireline logs and 3D seismic. Sodir (formerly the Norwegian Petroleum Directorate, NPD) maintains the comprehensive Norwegian Petroleum Directorate FactPages database, which includes biostratigraphic and lithostratigraphic data from all wells on the Norwegian Continental Shelf, providing the raw material for basin-wide sequence stratigraphic compilations. The Paleocene Forties and Maureen formations in the Central North Sea are lowstand submarine fan turbidite sands deposited during a major sequence boundary event, forming the reservoir for the Forties field and multiple satellite accumulations.

A procedure for estimating the reservoir characteristics between data points. Based on the idea of iterating from a first guess and refining through reduction of errors, the procedure generally transforms the model to normality, simulating the normally distributed transform, and then back-transforming to the original variable of interest.

(noun) A chemical additive that forms stable, soluble complexes with dissolved metal ions (such as calcium, magnesium, and iron) in drilling fluids, completion fluids, or produced water, preventing those ions from precipitating as insoluble scale or interfering with fluid performance. Common sequestering agents include EDTA, citric acid, and phosphonates.

A drilling mud filled open steel or earthen berm tank that is not stirred or circulated. By having mud slowly pass through such a container, most large drilling solids sink to the bottom, cleaning the mud somewhat. If the settling pit is small, as in the case of steel mud tanks, it must be cleaned out frequently as cuttings pile up on the bottom of the tank. In the early days of rotary drilling, some rigs had no more solids control than a large settling pit into which mud was discharged after coming back from the wellbore and suction for the mud pumps was taken at the other end of the pit. A major drawback to this type of "cleaning" is that solids intentionally put into the mud, such as barite, may settle to the bottom and be discarded rather than circulated back into the wellbore.

The separation of mineral and/or royalty interest from fee-simple title. Severance of interests is usually accomplished by reservation in a deed or assignment or by conveyance in mineral or royalty deed, assignment or lease.

Generally, an area of the Earth from which waves do not emerge or cannot be recorded. In seismology, the term is used to more specifically describe regions of the subsurface where P-waves and S-waves are difficult to detect, such as regions of the core at certain distances from the epicenter of an earthquake, or the point on the Earth's surface directly above an earthquake. Such zones were first observed in 1914 by Beno Gutenberg (1889 to 1960), an American geologist born in Germany. Because of the molten nature of the outer core, S-waves are especially difficult to detect at 103 to 142 degrees from the epicenter of an earthquake and not observable from 142 to 180 degrees from the epicenter. Areas below salt features are also called shadow zones because the high velocity of salt bends and traps energy, so seismic data quality beneath salt is generally poor unless special seismic processing is performed.

A fine-grained, impermeable, sedimentaryrock composed of clays and other minerals, usually with a high percentage of quartz. Shale is the most common, and certainly the most troublesome, rock type that must be drilled in order to reach oil and gas deposits. The characteristic that makes shales most troublesome to drillers is its water sensitivity, due in part to its clay content and the ionic composition of the clay. For this reason, oil-base drilling fluids are the mud of choice to drill the most water-sensitive shales.

The average reading of the spontaneous potential (SP) log opposite the shale layers in a well. Opposite shales, the SP is relatively constant and changes only slowly with depth. This is the shale baseline. The log is normally adjusted by the logging engineer to read near zero at the baseline. Sharp shifts in the baseline can sometimes be observed, for example when two permeable beds with different formation water salinities are separated by a shale that is not a perfect cationic membrane, or when the formation water salinity changes within a permeable bed.

Natural gas produced from shale formations.

The primary and probably most important device on the rig for removing drilled solids from the mud. This vibrating sieve is simple in concept, but a bit more complicated to use efficiently. A wire-cloth screen vibrates while the drilling fluid flows on top of it. The liquid phase of the mud and solids smaller than the wire mesh pass through the screen, while larger solids are retained on the screen and eventually fall off the back of the device and are discarded. Obviously, smaller openings in the screen clean more solids from the whole mud, but there is a corresponding decrease in flow rate per unit area of wire cloth. Hence, the drilling crew should seek to run the screens (as the wire cloth is called), as fine as possible, without dumping whole mud off the back of the shaker. Where it was once common for drilling rigs to have only one or two shale shakers, modern high-efficiency rigs are often fitted with four or more shakers, thus giving more area of wire cloth to use, and giving the crew the flexibility to run increasingly fine screens.

An explosive device that utilizes a cavity-effect explosive reaction to generate a high-pressure, high-velocity jet that creates a perforation tunnel. The shape of the explosive material and powdered metal lining determine the shape of the jet and performance characteristics of the charge. The extremely high pressure and velocity of the jet cause materials, such as steel, cement and rock formations, to flow plastically around the jet path, thereby creating the perforation tunnel.

A type of vertical seismicprofile in which the source is a shear-wave source rather than a compressional-wave source. Shear waves travel through the Earth at about half the speed of compressional waves and respond differently to fluid-filled rock, and so can provide different additional information about lithology and fluid content of hydrocarbon-bearing reservoirs.

An elastic constant for the ratio of shearstress to shear strain. The shear modulus is one of the Lame constants. It can be expressed mathematically as follows:

A short piece of brass or steel that is used to retain sliding components in a fixed position until sufficient force is applied to break the pin. Once the pin is sheared, the components can then move to operate or function the tool.

A blowout preventer (BOP) closing element fitted with hardened tool steel blades designed to cut the drillpipe when the BOP is closed. A shear ram is normally used as a last resort to regain pressure control of a well that is flowing. Once the drillpipe is cut (or sheared) by the shear rams, it is usually left hanging in the BOP stack, and kill operations become more difficult. The joint of drillpipe is destroyed in the process, but the rest of the drillstring is unharmed by the operation of shear rams.

The velocity gradient measured across the diameter of a fluid-flow channel, be it a pipe, annulus or other shape. Shear rate is the rate of change of velocity at which one layer of fluid passes over an adjacent layer. As an example, consider that a fluid is placed between two parallel plates that are 1.0 cm apart, the upper plate moving at a velocity of 1.0 cm/sec and the lower plate fixed. The fluid layer at the lower plate is not moving and the layer nearest the top plate is moving at 1.0 cm/sec. Halfway between the plate, a layer is moving at 0.5 cm/sec. The velocity gradient is the rate of change of velocity with distance from the plates. This simple case shows the uniform velocity gradient with shear rate (v1 - v2)/h = shear rate = (cm/sec)/(cm/1) = 1/sec. Hence, shear rate units are reciprocal seconds.

The bar or rod from which shear pins are cut for use in downhole slickline tools. Shear stock is prepared from carefully monitored materials to precise dimensions to ensure predictable and repeatable performance of shear pins.

The amount of deformation by shearing, in which parallel lines slide past each other in differing amounts. The measurement is expressed as the tangent of the change in angle between lines that were initially perpendicular.

Another term for gel strength in a fluid. Shear strength opposes the movement of mud, whether by pumping or movement of pipe in a wellbore. Excessive shear strength can develop after a mud has been quiescent in the hole at high temperature for a period of time. Shear strength can be measured according to procedures published by the API.

A test procedure published by the API that specifies the use of a shearometer tube and a set of weights to measure the shear strength of a mud (lbf/100 ft2 or kPa). The typical use for this test is for evaluation of a static-aged mud sample left at high temperature for several hours. The shear tube is placed on the surface of the gelled mud and weights are applied until the tube sinks to a marked depth. The applied weight indicates shear strength of the mud sample.Reference:Watkins TE and Nelson ME: "High Temperature Gellation of Drilling Fluids," Transactions of the AIME 193 (1953): 213-218.

The force per unit area required to sustain a constant rate of fluid movement. Mathematically, shear stress can be defined as: If a fluid is placed between two parallel plates spaced 1.0 cm apart, and a force of 1.0 dyne is applied to each square centimeter of the surface of the upper plate to keep it in motion, the shear stress in the fluid is 1 dyne/cm2 at any point between the two plates.

An item of pressure-control equipment often fitted to the wellhead during well-intervention operations on live wells. Most commonly associated with coiled tubing operations, the shear-seal BOP is a ram-type preventer that performs the dual functions of shearing or cutting the tubing string and then fully closing to provide isolation or sealing of the wellbore. Shear-seal BOPs are most commonly used in offshore or high-pressure applications where an additional contingency pressure barrier is required.

A test procedure published by the API that specifies the use of a shearometer tube and a set of weights to measure the shear strength of a mud (lbf/100 ft2 or kPa). The typical use for this test is for evaluation of a static-aged mud sample left at high temperature for several hours. The shear tube is placed on the surface of the gelled mud and weights are applied until the tube sinks to a marked depth. The applied weight indicates shear strength of the mud sample.Reference:Watkins TE and Nelson ME: "High Temperature Gellation of Drilling Fluids," Transactions of the AIME 193 (1953): 213-218.

A pulley. In oilfield usage, the term usually refers to either the pulleys permanently mounted on the top of the rig (the crown blocks), or the pulleys used for running wireline tools into the wellbore. In the case of the crown blocks, the drilling line, a heavy wire rope, is threaded between the crown blocks and the traveling blocks in a block and tackle arrangement to gain mechanical advantage. A relatively weak drilling line, with a breaking strength of perhaps 100,000 pounds [45,400 kg], may be used to lift much larger loads, perhaps in excess of one million pounds [454,000 kg]. During wireline operations, two sheaves are temporarily hung in the derrick, and the wireline is run from the logging truck through the sheaves and then down to the logging tool in the wellbore.

A luster, brightness or radiance. A sheen appears as a spectrum of colors and is commonly caused by a thin film on a surface that diffracts light. A film of diesel oil on water has a multicolored luster and is an indicator of an oil spill or oil slick.

A test intended to indicate the presence of free oil when drilling fluid, drilled cuttings, deck drainage, well treatment fluids, completion and workover fluids, produced water or sand or excess cementslurry are discharged into offshore waters. Two types of sheen tests are mandated by EPA under NPDES permits. The visual sheen test consists of an observation made when surface and atmospheric conditions permit watching the ocean water for a sheen around the point where the discharge entered the water. When the conditions do not permit visual observations, a static sheen test is mandated by NPDES permits and the protocol published by US EPA. This test uses sea water in a shallow pan (not more than 30 cm deep) with 1000 cm2 surface area. Either 15 cm3 of fresh mud or 15 g fresh cuttings are injected below the surface of the water. An observer watches for up to 1.0 hour for a silvery, metallic, colored or iridescent sheen. If sheen covers 50% of the area, the mud or cuttings cannot be discharged.Reference:Federal Register 57, no. 224 (November 19, 1992): 54652-57.Weintritt DJ, Qaisieh NS and Otto GH: "How To Improve Accuracy in the EPA Static Sheen Test," Oil & Gas Journal 91, no. 18 (May 3, 1993): 77-83.

Continental shelf, or the area at the edges of a continent from the shoreline to a depth of 200 m [660 ft], where the continental slope begins. The shelf is commonly a wide, flat area with a slight seaward slope. The term is sometimes used as a for platform.

A technique in nuclear magnetic resonance (NMR) logging based on the shift in the T2 distributions, or spectra, acquired with different echo spacings. The technique is usually used to detect gas or light oil. These fluids have a significant diffusion relaxation. A measurement made with a standard short echo spacing will give a signal from these fluids at a certain T2. A measurement made with a long echo spacing will cause more diffusion relaxation and a shorter T2. Other fluids, with minor contribution from diffusion, will not be changed. Gas and light oil can therefore be identified by the shift between the two T2 distributions.

A downhole tool used to adjust the position of sliding sleeves or similar production and completion equipment. Shifting tools are typically run on slickline, although they may be used with coiled tubing in deviated or horizontal wellbores. Shifting tools are generally prepared or dressed for use with a specific model and size of sliding sleeve, requiring careful selection of the appropriate shifting tool.

(noun) A guide fitting attached to the bottom of a casing string, liner, or other tubular that facilitates running the string into the wellbore by providing a rounded or tapered profile to deflect past ledges, dog legs, and borehole irregularities. A cement shoe (float shoe) also incorporates a check valve to prevent reverse flow of cement.

The space between the float or guide shoe and the landing or float collar. The principal function of this space is to ensure that the shoe is surrounded in high-quality cement and that any contamination that may bypass the top cement plug is safely contained within the shoe track.

To use a special acoustic device to determine the fluid level in a conduit or annular space. The principle of operation relies on accurately recording the time taken for a return echo to be bounced from the fluid in contained area.

To perforate a wellbore in preparation for production.

An abbreviated recovery of pipe out of, and then the replacement of same back into the wellbore. Such a trip is normally limited to 10 or 20 stands of drillpipe. Since the short trip is drillpipe only (no bottomhole assembly for the drilling crew to handle), and is limited in length, it can be accomplished quickly and sometimes results in additional information or improved operating conditions. A short trip often is used to gauge whether a hole is clean or whether the mud weight is sufficient to permit a full trip out of the hole.

Multiply-reflected seismic energy with a shorter travel path than long-path multiples. Short-path multiples tend to come from shallow subsurface phenomena or highly cyclical sedimentation and arrive soon after, and sometimes very near, the primary reflections. Short-path multiples are less obvious than most long-path multiples and are less easily removed by seismic processing.

The location of an explosive seismic source below the surface. Before acquisition of surface seismic data onshore using explosive sources such as dynamite, holes are drilled at shotpoints and dynamite is placed in the holes. The shotholes can be more than 50 m [164 ft] deep, although depths of 6 to 30 m [20 to 98 ft] are most common and depth is selected according to local conditions. With other "surface" sources, such as vibrators and shots from air shooting, the shots occur at the Earth's surface.

A surface detection technique to verify that perforating guns have fired. This technique typically employs sensors that detect vibration or hydraulic shock at surface, and is used with TCP operations.

One of a number of locations or stations at the surface of the Earth at which a seismicsource is activated.

A formationlayer above or below the layer being measured by a logging tool. The term is used in particular in resistivity logging to describe the layers above and below a reservoir. Some resistivity tools, such as induction and laterolog devices, can sense beds located tens of feet from the measure point and can be significantly affected by shoulder beds even when the reservoir is thick. The term is more commonly used for vertical wells, and is derived from the typical picture of resistivity log response across a reservoir: a high resistivity reservoir (the head) with two low-resistivity shales above and below (the shoulders). The term also may be used in horizontal wells, although in that context the term surrounding bed is more common. The term adjacent bed is used in both cases.

A surface observation of hydrocarbons, usually observed as florescent liquid on cuttings when viewed with an ultraviolet or black light (oil show) or increased gas readings from the mud logger's gas-detection equipment (gas show).

The force per unit area exerted at the bottom of a wellbore when it is closed at either the Christmas tree or the BOP stack. The SIBP is generated by a combination of the hydrostatic pressure from the weight of the liquid in the well and any additional applied pressure. The applied pressure component may be from the formation or from an external source at the surface.

The force per unit area exerted at the bottom of a wellbore when it is closed at either the Christmas tree or the BOP stack. The SIBP is generated by a combination of the hydrostatic pressure from the weight of the liquid in the well and any additional applied pressure. The applied pressure component may be from the formation or from an external source at the surface.

The surface force per unit area exerted at the top of a wellbore when it is closed at either the Christmas tree or the BOP stack. The pressure may be from the formation or an external and intentional source. The SIP may be zero, indicating that any open formations are effectively balanced by the hydrostatic column of fluid in the well. If the pressure is zero, the well is considered to be dead, and can normally be opened safely to the atmosphere.

A payment stipulated in the oil and gas lease, which royalty owners receive in lieu of actual production, when a gas well is shut-in due to lack of a suitable market, a lack of facilities to produce the product, or other cases defined within the shut-in provisions contained in the oil and gas lease.

A completion component that is used to house gas-lift valves and similar devices that require communication with the annulus. The design of a side-pocket mandrel is such that the installed components do not obstruct the production flow path, enabling access to the wellbore and completion components below.

A system for acoustic surveying most commonly deployed in marine environments and towed by a ship. The side-scan sonar generates a pulse on the order of 30 to 120 kHz that is reflected from the seafloor. Side-scan sonar records yield an image of the seafloor and shallow sediments.

A mineral composed of ferrous carbonate, FeCO3, and having 3.8 g/cm3specific gravity. It is found as an accessory mineral in some shales and carbonate rocks and also in some barite and hematite ores. FeCO3 is readily soluble in acids and breaks down slowly in alkaline muds, particularly at high temperature to form a gelatinous solid, Fe(OH)2, and soluble CO3-2 anions.Reference:Binder GG, Carlton LA and Garrett RL: "Evaluating Barite as a Source of Soluble Carbonate and Sulfide Contamination in Drilling Fluids," Journal of Petroleum Technology 33, no. 12 (December 1981): 2371-2376.

A type of event in 2D seismic data in which a feature out of the plane of a seismic section is apparent, such as an anticline, fault or other geologicstructure. A properly migrated 3D survey will not contain sideswipes.

A secondary wellbore drilled away from the original hole. It is possible to have multiple sidetracks, each of which might be drilled for a different reason.

Relating to being held against, or taken from, the side of the borehole. The term also describes a measurement that must be made by pressing the sonde against the side of the borehole in order to minimize borehole effects, as, for example, a sidewall epithermal neutron log.

A core taken from the side of the borehole, usually by a wireline tool. Sidewall cores may be taken using percussion or mechanical drilling. Percussion cores are taken by firing hollow bullets into the formation. The bullets are attached to the tool by fasteners, and are retrieved, along with the core inside, by pulling up the tool and the fasteners. Percussion coring tools typically hold 20 to 30 bullets, but two or three tools can be combined on one run in the hole. Mechanical tools use hollow rotary drills to cut and then pull out core plugs. Up to 75 plugs can be recovered on one run. With full recovery, cores from typical percussion tools are 1 in. [2.5 cm] in diameter by 1 3/4 in. [4.4 cm] long, while those from mechanical tools are 0.91 in. [2.3 cm] in diameter by 2 in. [5 cm] long. The latter are also known as rotary sidewall cores.

A technique for analyzing the grain-size distribution of a core sample. A cleaned, weighed core sample is disaggregated and agitated through a series of stacked screens with progressively smaller openings. The material left on each screen is weighed in order to give a distribution of quantity versus sieve size. Sieve analysis may be done dry, wet or a combination of both. Wet analysis is necessary for analyzing any clay fraction.

The macroscopic cross section for the absorption of thermal neutrons, or capture cross section, of a volume of matter, measured in capture units (c.u.). Sigma is also used as an adjective to refer to a log of this quantity. Sigma is the principal output of the pulsed neutron capture log, which is mainly used to determine water saturation behind casing. Thermal neutrons have about the same energy as that of the surrounding matter, typically less than 0.4 eV.

The portion of the seismicwave that contains desirable information. Noise is the undesirable information that typically accompanies the signal and can, to some extent, be filtered out of the data.

The ratio of desirable to undesirable (or total) energy. The signal-to-noise ratio can be expressed mathematically as S/N or S/(S+N), although S/N is more commonly used. The signal-to-noise ratio is difficult to quantify accurately because it is difficult to completely separate signal from noise. It also depends on how noise is defined.

A distinguishing feature of a waveform in a seismic event, such as shape, polarity, amplitude, frequency or phase. The signature of the seismic source waveform is of particular interest to geophysicists.

A step in seismic processing by which the signature of the seismic source in the seismic trace is changed to a known, shorter waveform by using knowledge of the source waveform. If the source waveform is known for each shot, then the process also minimizes variations between seismic records that result from changes in the source output.

[SiO2]A chemically resistant dioxide of silicon that occurs in crystalline (quartz), amorphous (opal) and cryptocrystalline (chert) forms.

A type of salt derived from silicic acid.

The anion, SiO4-4, found in solutions of sodium and potassium silicate, formed by dissolving silica or silicate minerals in NaOH or KOH solutions. Silicate anions form polysilicates, or colloidal silica gel.

A group of rock-forming minerals in which SiO4 tetrahedra combine with cations. Silicate minerals are the most abundant type of mineral. Olivine, pyroxene, amphibole, mica, quartz and feldspar are types of silicate minerals.

A type of shale-inhibitive water base drilling fluid that contains sodium silicate or potassium silicate polymeric ions. These ions adsorb on the shale surface and form a semipermeable osmotic membrane that prevents the transport of water and ions internal to the shale structure. This physicochemical barrier helps improve wellbore stability and provides in-gauge holes through troublesome shale sections that otherwise might require a nonaqueous drilling fluid. Silicate-gel drilling muds were first used in the 1930s to control problematic shales. In the 1990s, silicate nondispersed polymer drilling fluids were reintroduced to provide a high-performance shale-inhibitive water-base fluid, as an alternative to oil-base fluids. The highly inhibitive silicate fluid not only provides wellbore stability but also improves solids control performance with minimal environmental impact.

A group of seven hydrated forms of SiO2, including the following silicic acids: tetra, H2Si4O9, meta-di, H2Si2O5, meta-tri, H4Si3O8, meta, H2SiO3, ortho-tri, H8Si3O10, ortho-di, H6Si2O7 and ortho, H4SiO4. The latter formula is often written as Si(OH)4. Silicic acids and silicate anions polymerize through formation of multiple Si-O-Si bonds. The polysilic structure can be linear or cyclic and is not uniform in size.

Silica-based, noncarbonaceous sediments that are broken from preexisting rocks, transported elsewhere, and redeposited before forming another rock. Examples of common siliciclastic sedimentary rocks include conglomerate, sandstone, siltstone and shale. Carbonate rocks can also be broken and reworked to form other types of clastic sedimentary rocks.

A term used to describe particle whose size is between 2 and 74 micrometers (200 mesh).

A type of fold in which the thickness of the layers remains constant when measured parallel to the axial surface and the layers have the same wave shape, but the thickness along each layer varies. The folded layers tend to be thicker in the hinge of the fold and thinner along the limbs of the fold.

An event in which one deeper and one near-surface reflector, such as the base of weathering or the ocean floor, are involved. The seismic energy bounces twice from the deep reflector and only once from the shallow reflector, causing the multiple to appear at roughly twice the traveltime of the primary reflection.

A method for constructing a gridded reservoirmodel by iterative trial and error. The grid is initially populated randomly with a characteristic (such as facies) so that some property (such as a net/gross ratio) is correct. Then the grids are randomly swapped so that the property is preserved but another property (such as total length) is improved.

A term used mainly on offshore platforms, or installations with multiple wellheads, where more than one wellbore is being accessed, such as where a drilling rig, slickline unit or coiled tubing unit may be operating at the same time. Simultaneous operations generally have an impact on the installation safety procedures and contingency planning processes.

A function commonly used in seismic processing. Sinc x is the Fourier transform of a boxcar function, which is a function with a rectangular-shaped aperture.

A technique for interpreting the results from a spinner flowmeter using only one loggingrun over the zone of interest. Spinner speed is related to fluid velocity using laboratory-determined values for threshold velocity and spinner response. The single-pass method is generally considered inferior to the in-situ multipass or two-pass method. However, in highly deviated and horizontal wells, where the logging tools must be deployed using coiled tubing or a tractor, the cost of an additional pass is high. Single-pass interpretation, with improved spinner characterization, has therefore become more common in recent years.

Referring to a flow or other phenomenon with only one component, normally oil, water or gas.

The flow of a single-phase fluid, such as oil, water or gas, through porous media.

A technique for acquiring deviation information from a borehole on a slickline. In high-angle wells, a multishot technique is usually used instead.

The mixture of liquid samples taken from the upper, middle and lower sections of a storage tank. Normally the storage tanks (upright cylindrical or horizontal cylindrical tanks) in the oil field contain crude oil, water and emulsions.

Pertaining to a strike-slip or left-lateral fault in which the block across the fault moves to the left; also called a sinistral strike-slip fault. If it moves to the right, the relative motion is described as dextral. Counterclockwise rotation or spiraling is also described as sinistral.

Pertaining to a type of filter medium in which the particles are fused together to give a designed permeability. Sintered filters are used in the APIhigh-pressure, high-temperature filtration test above about 375°F [190°C] and in laboratory tests of formation damage. Large-scale sintered filters are also used to clean up clear brines after use.

A property or characteristic that has the form of a sine wave.

Calcium carbonate, such as limestone, marble or oyster shells, that has a specified minimum and maximum range of particle sizes and may also have a specified distribution of sizes. It is used as a bridging agent in drill-in, workover and completion fluids to positively seal permeable zones by plugging pores at the wellbore face. It has the additional advantage that it can be dissolved by acid treatment to clean up the zone afterwards.

NaCl solid particles that have a specified minimum and maximum range of particle sizes and may also have a specified distribution of sizes. Sized salt is used as a bridging agent in saturated saltwater systems used as drill-in, workover and completion fluids. Sized salt can positively seal permeable zones by plugging pores at the wellbore face. It is a preferred bridging agent because it can be dissolved by low-salinity water treatment to clean up the zone afterwards.

The degree to which a distribution has lost the bilateral symmetry of a normal distribution. Skewness is usually expressed qualitatively rather than quantitatively.

To slide the rig over, such as to move it from one well slot to another on a fixed offshore platform. This operation is accomplished by disconnecting the rigid attachments from the platform to the rig, and energizing large-capacity hydraulic cylinders that push the rig over greased steel skid beams.

The zone of reduced or enhanced permeability around a wellbore, often explained by formation damage and mud-filtrateinvasion during drilling or perforating, or by well stimulation.

The effective depth of penetration of an electromagnetic wave in a conductive medium. The skin depth is the distance in which the wave decays to 1/e (about 37%) of its value; it can be expressed as:

An increase or decrease in the pressure drop predicted with Darcy's law using the value of permeability thickness, kh, determined from a buildup or drawdown test. The difference is assumed to be caused by the "skin." Skin effect can be either positive or negative. The skin effect is termed positive if there is an increase in pressure drop, and negative when there is a decrease, as compared with the predicted Darcy pressure drop. A positive skin effect indicates extra flow resistance near the wellbore, and a negative skin effect indicates flow enhancement near the wellbore. The terms skin effect and skin factor are often used interchangeably. In this glossary, the term skin effect refers to the numerical value of the skin factor.

A numerical value used to analytically model the difference from the pressure drop predicted by Darcy's law due to skin. Typical values for the skin factor range from -6 for an infinite-conductivity massive hydraulic fracture to more than 100 for a poorly executed gravel pack. This value is highly dependent on the value of kh. For example, a 20-psi [138-kPa] total pressure drop related to skin effect could produce almost any skin factor, depending on the value of kh. For any given pressure drop from skin effect, the skin factor increases proportionally as kh increases.

A specially designed drilling rig capable of drilling directional wells.

A process used in seismic processing to stack, or sum, traces by shifting traces in time in proportion to their offset. This technique is useful in areas of dipping reflectors.

A single-strand wireline used to run and retrieve tools and flow-control equipment in oil and gas wells. The single round strand of wire passes through a stuffing box and pressure-control equipment mounted on the wellhead to enable slickline operations to be conducted safely on live wellbores.

The inclined plane below the vee-door that connects the rig floor to the catwalk. This part of the rig is simply a reinforced steel plate, and is used as a guide when dragging equipment or pipes up into the derrick or to the rig floor. Equipment rests against the slide as it is pulled up to the drill floor. The lower end of pipe is guided by the slide as it is pulled into the derrick.

A completion device that can be operated to provide a flow path between the production conduit and the annulus. Sliding sleeves incorporate a system of ports that can be opened or closed by a sliding component that is generally controlled and operated by slicklinetool string.

An inexact term describing a borehole (and associated casing program) significantly smaller than a standard approach, commonly a wellbore less than 6 in. in diameter. The slimhole concept has its roots in the observed correlation between well costs and volume of rock extracted. If one can extract less rock, then well costs should fall. One form of slimhole work involves using more or less conventional equipment and procedures, but simply reducing the hole and casing sizes for each hole interval. A second form involves technology used for exploration boreholes in the hard rock mining industry. In the mining rig operations, the drillstem serves a dual purpose. After the hole is drilled, the drillstem remains in the hole and is cemented in place. Then a new drillstem is used for the new hole section, and also cemented in place. The drillstring for mining rig operations is rotated like that for conventional oilfield rotary rig operations, but typically at a much higher speed.

A laboratory test used to estimate the minimum miscibility pressure (MMP) or minimum miscibility concentration (MMC) of a given injection solvent and reservoir oil. The slim tube is a long coiled tube filled with sand of a specific mesh size or similar porous media. The tube is saturated at the beginning of each test with reservoir fluid at a given temperature. Solvent injection is performed at several test pressures. Effluent production, density and composition are measured as functions of the injected volume. Oil recovery after injection of a specific number of pore volumes (PV) such as 1.2 PV of solvent is the test criterion for miscibility. Two trend lines appear on a plot of recovery versus pore pressure for several slim-tube tests. The point of intersection of those trend lines is the estimated MMP for the given oil-solvent system. The data from a slim tube test can also be used as input to fine-tune a fluid equation of state for reservoir simulation.

Bacteria that can live with or without oxygen and produce mats of high-density slime that cover surfaces. Their primary detrimental effects are the protection of sulfate-reducing bacteria and pore plugging.

Bacteria that can live with or without oxygen and produce mats of high-density slime that cover surfaces. Their primary detrimental effects are the protection of sulfate-reducing bacteria and pore plugging.

An inexact term describing a borehole (and associated casing program) significantly smaller than a standard approach, commonly a wellbore less than 6 in. in diameter. The slimhole concept has its roots in the observed correlation between well costs and volume of rock extracted. If one can extract less rock, then well costs should fall. One form of slimhole work involves using more or less conventional equipment and procedures, but simply reducing the hole and casing sizes for each hole interval. A second form involves technology used for exploration boreholes in the hard rock mining industry. In the mining rig operations, the drillstem serves a dual purpose. After the hole is drilled, the drillstem remains in the hole and is cemented in place. Then a new drillstem is used for the new hole section, and also cemented in place. The drillstring for mining rig operations is rotated like that for conventional oilfield rotary rig operations, but typically at a much higher speed.

The phenomenon in multiphase flow when one phase flows faster than another phase, in other words slips past it. Because of this phenomenon, there is a difference between the holdups and cuts of the phases.

To replace the drilling line wrapped around the crown block and traveling block. As a precaution against drilling line failure due to fatigue, the work done by the drilling line is closely monitored and limited. The work is commonly measured as the cumulative product of the load lifted (in tons) and the distance lifted or lowered (in miles). After a predetermined limit of ton-miles, new line is unspooled from the storage reel and slipped through the crown block and traveling block sheaves and drawworks spool, with the excess on the drawworks spool end cut off and discarded.

A completion component designed to accommodate tubing movement or length changes while maintaining a hydraulic seal between the production conduit and the annulus. The size or length of the slip joint depends on the wellbore conditions and completion characteristics.

A downhole lock device, run on slickline, that incorporates a slip mechanism that engages on the tubing wall to anchor the lock at the desired setting depth. Slip locks are not depth-dependent and do not require special completion equipment. However, the slip lock has limited function and pressure capacity and is generally less desirable than nipple or collar locks.

The difference between the average velocities of two different fluids flowing together in a pipe. In vertical ascending flow, the lighter fluid flows faster than the heavier fluid. The slipvelocity depends mainly on the difference in density between the two fluids, and their holdups.

To replace the drilling line wrapped around the crown block and traveling block. As a precaution against drilling line failure due to fatigue, the work done by the drilling line is closely monitored and limited. The work is commonly measured as the cumulative product of the load lifted (in tons) and the distance lifted or lowered (in miles). After a predetermined limit of ton-miles, new line is unspooled from the storage reel and slipped through the crown block and traveling block sheaves and drawworks spool, with the excess on the drawworks spool end cut off and discarded.

Any self-gripping toothed device functioning substantially as above, but gripping components other than drillstring, such as wireline, metal sinker bars, or drill collars.

A formation in which the velocity of the compressional wave traveling through the borehole fluid is greater than the velocity of the shear wave through the surrounding formation. In such conditions, there is no critical refraction of the shear wave and no shear head wave generated, so that standard techniques based on monopole transducers cannot be used to measure formation shear velocity. Instead, it is necessary to use dipole sources to excite the flexural mode. The velocity of the latter is closely related to that of the shear wave. In very slow formations, such as in high-porosity gas sands, the formation compressional velocity also may be less than the borehole fluid velocity, causing no compressional head wave. In such cases, it is possible to estimate the formation compressional velocity from the low-frequency end of a leaky mode.

A substance added at slow rate to the production fluid stream to prevent corrosion.

A parameter used to characterize neutron interactions in bulk material above the thermal region. The slowing-down length (Ls) is proportional to the root-mean-square distance from the point of emission of a high-energy neutron to the point at which its energy has decreased to the lower edge of the epithermal energy region. The slowing-down length is the physical parameter that best describes the response of an epithermal neutron porosity measurement, and describes a large part of the response of a thermal neutron porosity measurement. Thermal neutrons have about the same energy as the surrounding matter, typically less than about 0.4 eV, while epithermal neutrons have higher energy, between about 0.4 and 10 eV.

With reference to pulsed neutron logging, the characteristic time for the decay of the epithermal neutron population. The slowing-down time of a formation is strongly dependent on the porosity. In openhole pulsed neutron logging, it is also dependent on the standoff between tool and borehole wall. Epithermal neutrons have energies above that of the surrounding matter, between about 0.4 eV and 10 eV.

A technique used for identifying and measuring the slowness and time of arrival of coherentacoustic energy propagating across an array of receivers. The different packets of coherent energy can then be identified in terms of their origin, for example compressional, shear, Stoneley or other arrivals. In formation evaluation slowness-time coherence is used in conjunction with an array-sonic tool in which the full waveforms at each receiver have been recorded. The technique consists in passing a narrow window across the waveforms and measuring the coherence within the window for a wide range of slownesses and times of arrival.

A thick, viscous emulsion containing oil, water, sediment and residue that forms because of the incompatibility of certain native crude oils and strong inorganic acids used in well treatments.Use of certain additives, such as surfactants, or the presence of dissolved iron can promote sludge formation, especially if asphaltenes are present in the crude oil. Therefore, it is important to test a sample of crude with the treating fluid before injecting a treatment into a reservoir.

A small volume of fluid, often of a higher density than the main body of fluid, within the circulating or production-fluid system that influences the flow or production characteristics of the well. A slug may be placed to ensure that fluids are naturally drained from a tubing string as it is pulled from the wellbore. The term may also be applied to a small volume of liquid produced from a gas well. Similarly, it is used to describe the flow characteristics that occur when a mixture of liquid and gas result in a sporadic production regime as the liquids are unloaded erratically.

A type of flow in which surface equipment may be damaged by the sudden impact of a liquid slug in a phenomenon called water hammer.

Accumulation of a water, oil or condensate in a gas pipeline. These fluids need to be removed using a pig.

A chemical used to break emulsions to determine the total amount of sediment and water in the samples.

(noun) The plural of slurry. Fluid mixtures containing suspended solid particles, such as cement slurries (a blend of cement powder and water used for zonal isolation), fracturing slurries (fluid carrying proppant), or drilling fluid slurries containing weighting material, each formulated to specific densities and rheological properties for their intended application.

A mixture of suspended solids and liquids. Muds in general are slurries, but are seldom called that. Cement is a slurry and is often referred to as such.

The weight per unit volume of a cementslurry, usually given in units of kg/m3 or lbm/gal. Typical oil- or gas-well slurries have densities of 1380 kg/m3 to 2280 kg/m3 [11.5 lbm/gal to 19.0 lbm/gal], although special techniques, such as foamed cementing and particle-size distribution cementing, extend this range to 840 kg/m3 to 2760 kg/m3 [7 lbm/gal to 23 lbm/gal].

The ability of a cementslurry to maintain homogeneity. Two tests are used as a measure of slurry stability: the free-fluid test and the sedimentation test.

The volume of slurry obtained when one sack of cement is mixed with the desired amount of water and other additives, usually given in units of m3/kg or ft3/sk (sack).

Water in microporosity or other small pores. The term usually refers to the nuclear magnetic resonancesignal of such water, which occurs at very short times and overlaps the signal from clay-bound water.

[(1/2Ca,Na)0.7(Al,Mg,Fe)4(Si,Al)8O20(OH)47nH2O)]A group of clay minerals that includes montmorillonite. This type of mineral tends to swell when exposed to water. Bentonite includes minerals of the smectite group.

A category of clay minerals that have a three-layer crystalline structure (one alumina and two silica layers) and that exhibit a common characteristic of hydrational swelling when exposed to with water. Montmorillonite is a well-known smectite clay mineral to those working in drilling and drilling fluids. Its sodium form, bentonite, is a widely-used water mud additive. It is also used as an oil-mud additive when made oil-dispersible by surface treatment. Smectite clays that occur naturally in shales cause wellbore and mud-control problems due to their hydrational swelling and colloidaldispersion characteristics.

A concave-upward, semicircular event in seismic data that has the appearance of a smile and can be caused by poor data migration or migration of noise.

The action of forcing a pipe or tubular into a well against wellbore pressure. Well-intervention techniques in live wells, such as coiled tubing and snubbing, use equipment designed to apply the necessary forces while supporting the tubing and safely containing wellbore pressure and fluids.

What Is Snubbing? Snubbing is a well intervention technique that forces tubular pipe into a live, pressurized wellbore against wellbore pressure acting on the pipe cross-section, using a specialized hydraulic jack unit and dual slip assembly mounted on a closed blowout preventer stack to maintain full pressure containment while advancing, rotating, or retrieving the pipe string. Key Takeaways Snubbing is required when upward wellbore hydraulic force on the pipe cross-section exceeds the string weight, making the string "pipe light" and preventing conventional gravity-assisted running of pipe into the hole. A hydraulic snubbing unit applies a downward mechanical force through a traveling jack assembly, typically capable of delivering up to 500 tonnes (1,100,000 lbs) of push force, to overcome wellbore pressure and advance the string to target depth. Snubbing operations allow drill pipe, completion strings, or coiled tubing to be run into or pulled from a live well without killing the well first, preserving formation productivity and avoiding kill fluid invasion damage. The International Association of Drilling Contractors (IADC) certifies snubbing crews through a dedicated competency program, and most jurisdictions require evidence of IADC snubbing certification or equivalent competency for all supervisory snubbing personnel. Snubbing is the method of last resort for getting drill string to bottom during a well control event, enabling bullheading kill operations when the well cannot be shut in at surface without the drillstring in place. How Snubbing Works To understand why snubbing requires a specialized unit rather than standard hoisting equipment, it is necessary to understand the "pipe light" condition. When a well is live and contains pressurized fluid, the wellbore pressure acts upward on every cross-sectional area of tubular within the wellbore. For a section of 5-inch (127 mm) outside diameter drill pipe with a cross-sectional area of approximately 19.6 square inches (126 cm²), wellbore pressure of 5,000 PSI (345 bar) exerts an upward hydraulic force of roughly 98,000 lbs (44,500 kg) per tubular joint. If the weight of the drill string in that wellbore is less than the total upward hydraulic force, the string will be ejected from the wellbore unless it is mechanically restrained and forced downward. The threshold between pipe-heavy (conventional running) and pipe-light (snubbing required) operation is called the neutral point or pipe light threshold, calculated as: upward hydraulic force = wellbore pressure (PSI) x pipe OD cross-sectional area (in²). When the drill string weight below the neutral point is less than this force, snubbing equipment must provide the differential push force to advance the string. The hydraulic snubbing unit consists of two primary mechanical assemblies: the stationary slip assembly, which clamps rigidly to the BOP stack or wellhead and grips the pipe when the traveling jack is repositioning, and the traveling slip assembly, which is attached to the hydraulic jack and moves up and down to push or pull the pipe. The two slip sets alternate their engagement in a leapfrog action: the traveling slips grip the pipe and push it downward (or pull it upward) through one stroke of the hydraulic jack, the stationary slips then lock onto the pipe to hold it in place while the traveling slips release and the jack resets for the next stroke. A stripper element or hydraulic packing element sits below the slip assemblies and seals around the moving pipe, preventing wellbore pressure from escaping to atmosphere around the pipe body during each stroke cycle. The entire unit sits atop the BOP stack, which remains closed and provides the primary pressure containment barrier throughout the operation. The critical distinction between snubbing and the related operation of stripping lies in the balance of forces. Stripping describes running or pulling pipe through a stripper element while the string remains pipe-heavy; gravity or the rig hoisting system moves the string and the stripper provides a dynamic seal. Snubbing is the condition where the string is pipe-light and must be pushed downward against wellbore pressure. In practice, a single operation may begin as pipe-heavy stripping at shallow depth, pass through the neutral point at intermediate depth as more pipe enters the wellbore and the weight increases relative to the upward hydraulic force, and become pipe-heavy again below the neutral point. The snubbing unit is designed to handle both phases continuously, with the hydraulic jack switching between push mode (snubbing) and pull mode (stripping or pulling) as dictated by the real-time force balance calculation performed by the snubbing supervisor. Snubbing Unit Components and Hydraulic Capacity A modern hydraulic snubbing unit is a self-contained well intervention package assembled on a work platform that bolts directly to the wellhead or BOP flange, typically at a height of 4 to 8 metres (13 to 26 ft) above the wellhead to accommodate the full stroke length of the jack assembly. The major components include: Hydraulic jack assembly: The power unit consists of two to four hydraulic cylinders arranged symmetrically around the central pipe bore. Cylinder stroke lengths range from 1.2 m to 1.8 m (4 ft to 6 ft) on standard units, with each stroke advancing or retracting the traveling slip set by that distance. Hydraulic pressure from the power pack drives the cylinders; maximum push force for a standard single-post snubbing unit ranges from 100 tonnes (220,000 lbs) for light pipe work to 500 tonnes (1,100,000 lbs) on heavy-duty units designed for large-diameter pipe in HPHT wells. Maximum pull force is similarly rated, as the jack must also be capable of pulling stuck pipe against wellbore differential sticking forces. The hydraulic power pack operates at system pressures up to 350 bar (5,075 PSI) to deliver these forces through the cylinder geometry. Traveling and stationary slips: Slip die inserts are matched to the pipe OD and may be quick-changed for different pipe sizes or connection types. Bowl-and-slip geometry generates self-energizing grip: higher axial load increases radial clamping force proportionally, preventing the slip from releasing under load. Slip inserts for weld-on tool joints or heavy-wall pipe require specialized die profiles to distribute contact stress and avoid gouging the pipe surface, which could introduce stress concentration points for fatigue failure during subsequent operations. Maximum tubular OD accommodated by standard snubbing units is typically 7 inches (178 mm), though custom units are built for 9 5/8-inch (245 mm) and larger casing work. Stripper element (rotating head): The stripper packer seals dynamically around the pipe as it moves. Two basic configurations exist: a static rubber packing element with a solid non-rotating seal (adequate for straight pipe body but unable to accommodate tool joints without opening and closing around them) and a rotating control device (RCD) that uses a bearing assembly to allow the pipe to rotate while maintaining a pressure seal up to 345 bar (5,000 PSI) for some ratings. For snubbing operations with jointed pipe, the stripper must either accommodate the larger-diameter tool joint by momentarily supporting the pipe on the stationary slips while the joint passes through an open stripper element, or use a two-stripper system with staggered element activations that maintain continuous pressure containment as the joint passes. This joint-passing sequence is one of the highest-risk moments in a snubbing operation and requires careful coordination between the snubbing supervisor and the hydraulic control panel operator. Kill manifold and pressure monitoring: A kill manifold with manual and hydraulic-actuated valves provides the ability to pump fluid into the annulus or the pipe bore at any time during the operation. Dual pressure gauges monitor annular pressure and pipe internal pressure simultaneously. A check valve in the lower pipe string prevents backflow through the drill pipe when the traveling slips release and the string is momentarily unsupported. The snubbing unit also connects to the rig's well control kill and choke manifold lines so that the well can be shut in at multiple points. Fast Facts: Snubbing Maximum hydraulic push force (heavy-duty unit): 500 tonnes (1,100,000 lbs / approximately 4.9 MN) Jack stroke length (standard unit): 1.2 m to 1.8 m (4 ft to 6 ft) per stroke cycle Stripper element working pressure: up to 345 bar (5,000 PSI) for standard units; 690 bar (10,000 PSI) for HPHT-rated units Maximum tubular OD (standard unit): 7 inches (178 mm); custom units to 9 5/8 inches (245 mm) Pipe light threshold example: 5,000 PSI (345 bar) on 5-inch (127 mm) pipe = upward force of approximately 98,000 lbs (44,500 kg) Typical snubbing trip speed: 200 to 400 m/hr (650 to 1,300 ft/hr) depending on pipe size, wellbore pressure, and joint-passing frequency IADC snubbing certification levels: Helper, Operator, Crew Chief (each requiring documented hours plus written and practical examination) North Sea HP/HT definition: wellbore pressure above 690 bar (10,000 PSI) or temperature above 150°C (302°F)

The work area at the top of a snubbing unit that houses the unit controls and a means of handling the tubulars and tool string to be run or retrieved.

The force required to insert a tool or tubing string into a live wellbore. Two main components act to determine the snubbing force: the force resulting from the wellheadpressure acting on the cross-sectional area of the tubing, or the outside diameter of the tool and the force required to overcome the friction resulting from the stripper or similar sealing device containing the wellbore pressure and fluids.

The components of a snubbing unit that provide the vertical stroke or movement required to run or retrieve the work string. Snubbing jacks are hydraulically operated and can apply extremely high forces to the tubing string and the wellhead to which they are attached.

In cyclic steam injection, the second phase between the steam-injection phase and the production phase. During the soak phase, the well is shut in for several days to allow uniform heat distribution to thin the oil.

A collective term for organic salts made by reacting an aliphatic carboxylic acid with a base. The base can be an alkali-metal hydroxide (NaOH or KOH), alkaline-earth hydroxide (Ca(OH)2 or Mg(OH)2) or oxide (CaO or MgO). Fatty acids are the carboxylic acids often used to make soaps for oilfield applications, such as emulsifiers for oil muds. Aluminum soaps are used as defoamers in drilling fluids. Sodium and potassium soaps are detergents to emulsify oil into water.

A chemical with the formula NaHCO3. It is called bicarb at the drilling rig and is used to treat cement contamination in water mud. When cement hydrates, substantial amounts of lime, Ca(OH)2, are produced. As the cement sets, less free lime is available. When partially set cement is drilled with a water mud, Ca+2 and OH- ions are leached into the mud, often causing problems associated with clayflocculation and polymer precipitation. Bicarb can be added, either as a pretreatment or over a period of time, to remove the Ca+2 in the form of insoluble CaCO3 while simultaneously neutralizing OH- ions with the H+ ion in the bicarb molecule.

A chemical with the formula Na2CO3. It is called soda ash at the drilling rig and is used to treat most types of calcium ion contamination in freshwater and seawater muds. For cement contamination, sodium bicarbonate is used. Calcium ions from drilling gypsum or anhydrite, CaSO4, cause clayflocculation and polymerprecipitation and lower pH. A soda-ash treatment is appropriate for gypsum contamination because caustic soda, NaOH, is not needed to raise pH. This is also generally the case with hard water influxes into water muds.

Oilfield slang term for rope not made of steel, such as nylon, cotton, or especially standard manila hemp rope.

A general term for sedimentary rocks, although it can imply a distinction between rocks of interest to the petroleum industry and rocks of interest to the mining industry.

Water that does not contain divalent cations, such as Ca+2, Mg+2 or Fe+2 and is therefore suitable for prehydrating bentonite or polymers.

Oilfield slang term for rope not made of steel, such as nylon, cotton, or especially standard manila hemp rope.

(noun) A granular or bead-form hygroscopic material, such as silica gel, activated alumina, or molecular sieves, used in gas processing to adsorb water vapour from a natural gas stream in a dehydration unit, reducing the moisture content to pipeline or cryogenic processing specifications.

The maximum amount of a substance that will dissolve in a given amount of solvent at a given temperature and pressure, or the degree to which a substance will dissolve in a particular solvent. The solubility of a substance is its concentration in a saturated solution. Two fluids that are soluble in one another in all proportions are also referred to as miscible.

Dissolved gas in wellbore or reservoir fluids. The gas will remain in solution until the pressure or temperature conditions change, at which time it may break out of solution to become free gas.

A type of reservoir-drive system in which the energy for the transport and production of reservoir fluids is derived from the gas dissolved in the fluid. As reservoir fluids enter the wellbore, changing pressure conditions cause the gas to break from solution to create a commingled flow of gas and liquid that aids production.

A type of reservoir-drive mechanism in which the energy for the transport and production of reservoir fluids is provided by the gas dissolved in the liquid. As reservoir fluids enter the wellbore, changing pressure conditions cause the gas to break from solution to create a commingled flow of gas and liquid that aids production.

The section of a logging tool that contains the measurement sensors, as distinct from the cartridge, which contains the electronics and power supplies.

The measurement of an induction tool in a nonconducting medium before correction. Electronic offsets and coupling within the tool cause a signal in the receivers even in a nonconducting medium such as air. This signal is cancelled either electronically or in software. Sonde errors change with temperature and pressure downhole. This can be allowed for by characterizing the sonde's response to temperature and pressure on the surface.Sonde error is measured by placing the tool far from the ground in air. Ideally measurements are made at two distances, since the ground signal can then be determined from the difference and eliminated. Originally, sonde error referred only to the R-signal, since this was the only signal being used. The term now refers to both R- and X-signals.

Some authors use the term to describe P-waves in fluids, or as a synonym for seismic or elastic.

A type of acoustic log that displays traveltime of P-waves versus depth. Sonic logs are typically recorded by pulling a tool on a wireline up the wellbore. The tool emits a soundwave that travels from the source to the formation and back to a receiver.

The technique for recording a boreholesonic log, in the sense of measurement of any of the acoustic properties in and around the borehole. The standard sonic measurement, based on first motion detection, normally can be used only to determine formation compressional slowness. For all other sonic measurements, such as shear, flexural and Stoneley slownesses and amplitudes, it is necessary to record the full waveform using an array-sonic tool and process with a technique such as slowness-time coherence.

An acoustic device that measures the time required for an explosive sound to echo from the annular liquid level in nonflowing wells. The time is proportional to the distance from the surface to the liquid. It is used to determine backpressure in the formation or a static fluid level in the annulus. It is also known as an echo meter.

The range of sedimentary grain sizes that occurs in sediment or sedimentary rock. The term also refers to the process by which sediments of similar size are naturally segregated during transport and deposition according to the velocity and transporting medium. Well-sorted sediments are of similar size (such as desert sand), while poorly-sorted sediments have a wide range of grain sizes (as in a glacial till). A well-sorted sandstone tends to have greater porosity than a poorly sorted sandstone because of the lack of grains small enough to fill its pores. Conglomerates tend to be poorly sorted rocks, with particles ranging from boulder size to clay size.

Contaminated with sulfur or sulfur compounds, especially hydrogen sulfide. Crude oil and gas that are sour typically have an odor of rotten eggs if the concentration of sulfur is low. At high concentrations, sulfur is odorless and deadly.

The corrosion caused by contact with hydrogen sulfide [H2S] dissolved in water.Sour corrosion takes the form of sulfidestresscracking or hydrogen embrittlement.

A crude oil containing hydrogen sulfide, carbon dioxide or mercaptans.

A gas containing hydrogen sulfide, carbon dioxide or mercaptans, all of which are extremely harmful.

A device that provides energy for acquisition of seismic data, such as an air gun, explosive charge or vibrator.

A rock rich in organic matter which, if heated sufficiently, will generate oil or gas. Typical source rocks, usually shales or limestones, contain about 1% organic matter and at least 0.5% total organic carbon (TOC), although a rich source rock might have as much as 10% organic matter. Rocks of marine origin tend to be oil-prone, whereas terrestrial source rocks (such as coal) tend to be gas-prone. Preservation of organic matter without degradation is critical to creating a good source rock, and necessary for a complete petroleum system. Under the right conditions, source rocks may also be reservoir rocks, as in the case of shale gas reservoirs.

To assemble components to ensure that all critical length dimensions are met, as is required to ensure that the production tubing can be landed in the wellhead and production packer with the desired weight distribution. The term also may apply to surface pressure-control equipment offshore, where well intervention equipment may be required at certain deck levels.

A display, also known as the f-k domain, of seismic data by wavenumber versus frequency rather than the intuitive display of location versus time for convenience during seismic processing. Working in the space-frequency domain provides the seismic processor with an alternative measure of the content of seismic data in which operations such as filtering of certain unwanted events can be accomplished more effectively.

A viscous fluid used to aid removal of drilling fluids before a primary cementing operation. The spacer is prepared with specific fluid characteristics, such as viscosity and density, that are engineered to displace the drilling fluid while enabling placement of a complete cement sheath.

Any liquid used to physically separate one special-purpose liquid from another. Special-purpose liquids are typically prone to contamination, so a spacer fluid compatible with each is used between the two. The most common spacer is simply water. However, chemicals are usually added to enhance its performance for the particular operation. Spacers are used primarily when changing mud types and to separate mud from cement during cementing operations. In the former, an oil-base fluid must be kept separate from a water-base fluid. In this case, the spacer may be base oil. In the latter operation, a chemically treated water spacer usually separates drilling mud from cement slurry. For proper performance and to prevent unanticipated problems, the spacer should be tested with each fluid in small-scale pilot tests. Some spacer fluids are designed to induce a particular flow regime. Ideally, a cement slurry should have turbulent flow to efficiently displace drilling fluids, but there might be pumping restrictions on fluid velocity. Therefore, a spacer that can achieve turbulent or pseudolaminar flow might be selected.

The distance between successive shotpoints.

An area allotted to a well by regulations or field rules issued by a governmental authority having jurisdiction for the drilling and production of a well.

The dimensionless ratio of the weight of a material to that of the same volume of water. Most common minerals have specific gravities between 2 and 7.

The permeability of a porous medium to a specific fluid, when that fluid is the only fluid present. Permeability is defined as a property of the porous medium. However, the permeability measured on samples often depends on the fluid used. For example, liquids can affect the permeability through fines movement and clay alteration; gas permeability depends on slippage and inertial resistance, unless fully corrected for these effects. It is therefore more correct to talk of specific permeability to a particular fluid, although, in practice, the shorter term, permeability, is common.

Pertaining to a spectrum. The spectral content of a wavetrain or wavelet usually refers to its amplitude and phase as a function of frequency.

A technique for utilizing fractal geometry to produce reservoir descriptions.

The distribution of gamma ray energies, or the number of gamma rays as a function of gamma ray energy.

The apparent loss of intensity of a gravitational or magnetic field with distance. Spherical divergence decreases energy with the square of the distance.

A flow regime that occurs when the predominant flow pattern in the reservoir is toward a point. Spherical flow occurs for partial penetration and limited-entry completions. This flow regime is recognized as a -1/2 slope in the pressure derivative on the log-log diagnostic plot. Its presence enables determination of the spherical permeability. When spherical flow is followed by radial flow, both horizontal and vertical permeability can be quantified.

A technique for focusing an electrode device based on maintaining a spherical equipotential surface centered at the main current electrode. Unlike the laterolog, which tries to maintain equipotential lines parallel to the sonde, spherical focusing tries to maintain the spherical equipotential lines that would exist in a homogeneous formation with no borehole. This is achieved with a particular arrangement of current-emitting electrode, current-return electrodes and monitor electrodes. This arrangement creates two spherical equipotential spheres with a constant voltage drop between them. The resistivity is determined from the current flowing between the spheres and the voltage drop. The depth of investigation is determined by the radii of the two spheres. Spherical focusing is used to produce shallow-reading resistivity logs and the pad-based microspherical log.

The solution to the Laplace equation expressed as spherical coordinates. The normal modes of the Earth, or the reverberations that follow earthquakes, have the form of spherical harmonics. Love waves and Rayleigh waves can also be expressed as spherical harmonics.

A ball-shaped vessel used for fluid separation. A spherical separator can be used for two-phase or three-phase separation purposes.Spherical separators are less efficient than either horizontal or vertical cylindrical separators and are seldom used. Nevertheless, their compact size and ease of transportation have made them suitable for crowded processing areas.

A wave generated from a point source, such as that generated by an underground explosion. Typical seismic sources such as vibrators and air-gun arrays emit elastic waves that are assumed to be spherical waves.

The structurally lowest point in a hydrocarbon trap that can retain hydrocarbons. Once a trap has been filled to its spill point, further storage or retention of hydrocarbons will not occur for lack of reservoir space within that trap. The hydrocarbons spill or leak out, and they continue to migrate until they are trapped elsewhere.

A productionlogging method that uses a small propeller turned by fluid movement. The number of turns of the propeller can be related to the amount of fluid passing through the instrument.These devices are used to determine which of several zones contributes the most to the total production or, in the case of an injection well, which zone is receiving the most injected fluids.

For a two-detector density tool, the plot of long-spacing versus short-spacing count rates for different formation densities, mudcake densities and mudcake thicknesses. The plot takes its name from the spine, which is the locus of points with no mudcake, and the ribs, which show the effect of mudcake at certain fixed formation densities. The plot illustrates graphically that for a given formation density there is only one rib for all normal mudcake densities and thicknesses. Thus, although there are three unknowns, it is possible to make a correction using two measurements.

What Is a Spinner Flowmeter? A spinner flowmeter is a downhole production logging tool that measures in-situ fluid velocity inside a wellbore by counting the rotational speed of an impeller or vane assembly. As wellbore fluid flows past the spinner, it imparts a rotational force proportional to velocity, generating electrical pulses that surface acquisition systems convert into flow rate profiles across producing or injecting intervals. Key Takeaways Spinner flowmeters measure fluid velocity by converting impeller rotation rate (revolutions per second) into flow rate, using a calibration function that accounts for tool speed, fluid density, and wellbore geometry to derive in-situ volumetric flow. Four primary spinner configurations serve different wellbore conditions: the continuous (through-tubing) spinner, the fullbore centralized spinner, the packer (diverter) flowmeter, and the basket flowmeter, each with different minimum detectable velocity thresholds and bypass correction requirements. Multipass spinner interpretation requires logging at multiple tool velocities (typically three to five passes in each direction) and plotting spinner revolutions per second against tool velocity to isolate formation flow rate as the zero-tool-speed intercept of the response line. A complete production logging tool (PLT) string combines the spinner with pressure, temperature, gamma ray, fluid density (gradiomanometer), and capacitance or holdup probes to enable full multiphase flow characterization across each producing zone. Spinner surveys in horizontal wells face significant interpretation challenges due to gravity-driven phase segregation, requiring either multiple probes positioned around the wellbore circumference or supplemental tracer and pulsed-neutron measurements to resolve individual oil, water, and gas flow rates by zone. How a Spinner Flowmeter Works The operating principle of a spinner flowmeter is straightforward: when fluid moves past an impeller mounted in the wellbore fluid stream, the fluid exerts a drag force on the impeller blades that causes them to rotate. The rotational speed of the impeller (measured in revolutions per second, RPS) increases with fluid velocity and decreases as fluid velocity drops toward zero. An electrical pickup coil or Hall-effect sensor mounted adjacent to the impeller shaft generates a pulse for each complete revolution; surface acquisition systems count these pulses over a fixed time gate to compute instantaneous RPS as the tool traverses the well. The relationship between RPS and the fluid velocity relative to the tool (the apparent velocity) is linear across most of the tool's operating range, allowing the calibration equation RPS = a x V_rel + b to be applied, where V_rel is the relative velocity between the fluid and the tool, and a and b are calibration constants determined on a surface flow loop prior to logging. Because the tool itself moves through the wellbore at a controlled logging speed set by the surface winch, the measured RPS reflects the sum of the formation fluid velocity and the tool velocity. To extract the true formation flow velocity, the engineer must correct for tool motion. When the tool moves upward (against production flow in a producing well), the relative velocity between fluid and tool is the fluid velocity plus the tool speed; when the tool moves downward, the relative velocity is the fluid velocity minus the tool speed. By running the tool at multiple speeds in both directions, the engineer can construct a plot of apparent RPS versus tool velocity at any depth and identify the zero-crossing, which corresponds to the fluid velocity at that depth. The volumetric flow rate at each depth is then calculated from the derived velocity using the wellbore cross-sectional area, corrected for any slippage between phases and for spinner bypass (the fraction of wellbore flow that passes around the tool without spinning the impeller). Differential flow rate between depth stations directly identifies the contribution of each producing or injecting interval. The minimum detectable velocity, or threshold velocity, is the lowest fluid velocity that can overcome the mechanical friction of the impeller bearings and cause measurable rotation. For a typical small-vane through-tubing spinner, the threshold is approximately 0.05 to 0.15 m/s (0.16 to 0.49 ft/s). Fullbore spinners have lower thresholds because the larger impeller area generates more torque per unit velocity. Below threshold, the spinner reads zero even though flow may be present, creating a blind zone for low-rate intervals. In low-rate or injection wells where velocities approach the threshold, engineers may use the packer or basket flowmeter to divert all wellbore flow through a smaller cross-section past the impeller, dramatically increasing the fluid velocity relative to the spinner and extending the measurable range to much lower in-situ flow rates. Spinner Flowmeter Types Continuous (Through-Tubing) Spinner The continuous spinner is the most commonly deployed configuration. It consists of a small-diameter (typically 1.25 to 1.75 in. / 31.8 to 44.5 mm OD) body that runs inside the production tubing on wireline or coiled tubing, carrying a 1.25 to 1.5 in. (31.8 to 38.1 mm) diameter impeller centrally positioned in the fluid stream. Because the tool OD is small relative to the tubing ID, a significant fraction of the total flow passes in the annulus between the tool body and the tubing wall without interacting with the spinner. The bypass correction factor, typically 0.5 to 0.8 depending on tool OD and tubing ID, must be applied to convert measured flow at the spinner to total wellbore flow. The continuous spinner is most effective in single-phase or predominantly single-phase wells at moderate to high flow rates. Its small size allows deployment through a lubricator without killing the well, making it the preferred tool for routine production surveillance. Fullbore Spinner The fullbore spinner uses a large-diameter impeller mounted on centralizer arms that position it at the center of the tubing or casing bore, with the impeller diameter close to the bore ID. By minimizing the bypass annulus, the fullbore spinner captures nearly all of the wellbore flow and requires only a small bypass correction. Fullbore spinners are significantly more sensitive at low flow rates than continuous spinners and are the preferred tool for wells with low flow rates, gas wells, or wells where accurate zone allocation at low rates is critical. The larger tool diameter means it cannot pass through tubing restrictions, so fullbore spinners are most commonly used on open-hole or cased-hole logging strings where the full wellbore is accessible, or in tubing-pulled configurations. Centralizer arms collapse mechanically for running through tight spots and open against the wellbore wall at logging depth. Packer (Diverter) Flowmeter The packer flowmeter, sometimes called the diverter flowmeter, incorporates an inflatable or mechanical packer element that seals against the tubing or casing wall above the spinner, forcing all wellbore fluid to flow through the spinner body rather than around it. Because 100% of the flow passes through the spinner, there is no bypass correction. The packer flowmeter has the lowest threshold velocity of all spinner types and can resolve flow rates below 5 m3/d (approximately 31 bbl/d) that a continuous spinner would not detect. Its limitation is that the packer must be inflated at each measurement station and then deflated and moved, making the logging process slow and expensive relative to a continuous spinner run. Packer flowmeters are primarily used for detailed zone-by-zone allocation studies on complex multi-layer wells, for injection profiling in waterflood or steamflood projects, and in very-low-rate wells where standard spinner sensitivity is insufficient. Basket Flowmeter The basket flowmeter uses a funnel-shaped deflector basket that is opened mechanically in the wellbore to intercept a portion of the flow stream and direct it past the spinner. Unlike the packer flowmeter, the basket does not seal completely against the wellbore wall, so some bypass still occurs, but the deflector increases the fraction of total flow passing the spinner relative to a continuous spinner. Basket flowmeters are positioned at stationary stations in the same manner as packer flowmeters and are well-suited for moderate-to-low rate wells where packer inflation and sealing may be mechanically challenging (e.g., in corroded or scaled-up tubulars). The basket deflector also helps in multiphase wells where gas segregation can cause a centralized spinner to read predominantly gas velocity rather than the average mixture velocity. Fast Facts: Spinner Flowmeter Performance Typical fullbore spinner threshold: 0.03 to 0.05 m/s (0.10 to 0.16 ft/s) in single-phase water, corresponding to approximately 15 to 30 m3/d (95 to 190 bbl/d) in 3-1/2 in. (88.9 mm) tubing. Through-tubing spinner threshold: 0.05 to 0.15 m/s (0.16 to 0.49 ft/s), equivalent to approximately 30 to 100 m3/d (190 to 630 bbl/d) in 3-1/2 in. tubing due to bypass effects. Logging speed: Continuous spinner surveys are typically run at 15 to 30 m/min (50 to 100 ft/min) for stationary-pass multipass programs; faster speeds reduce data quality but accelerate surveys in long horizontal wells. Multipass requirement: Minimum of three passes at different tool velocities in each direction, giving at least six data points per depth station, for a reliable multipass interpretation. Ghawar field PLT program: Saudi Aramco's horizontal well surveillance program on the Ghawar Arab-D reservoir, one of the world's largest oil fields, uses spinner-based PLT surveys to allocate production across lateral sections exceeding 1,500 m (4,921 ft), directly informing perforation plugging, water shutoff, and artificial lift optimization decisions for the world's largest single oil-producing structure. Production Logging Tool String Configuration The spinner flowmeter is rarely run alone. A complete production logging string combines the spinner with a suite of sensors that characterize both the quantity and composition of fluids flowing at each depth. The standard combined PLT string for a vertical oil well includes a gamma ray tool (for depth correlation with the open-hole log), a casing collar locator (CCL), a pressure gauge (quartz crystal or strain gauge), a thermometer, a gradiomanometer or fluid density tool, a capacitance or optical water holdup probe, and the spinner. In some configurations, especially in gas-lifted or gassy wells, a caliper tool is added to measure actual tubing or casing ID for accurate velocity-to-flow-rate conversion. The pressure and temperature sensors enable construction of a flowing gradient survey across all producing intervals, which independently confirms the spinner-derived flow profile through hydrostatic pressure calculations. If the flowing gradient shows a change in fluid gradient (e.g., a transition from oil to water in the hydrostatic column) at the same depth as a spinner anomaly, the two measurements reinforce the zone identification. The fluid density sensor measures the bulk density of the mixed fluid stream and, when combined with individual fluid densities for oil, water, and gas determined at surface conditions, allows calculation of in-situ holdup fractions (the fraction of the wellbore cross-section occupied by each phase) at each depth. The holdup measurement is essential for converting mixture velocity from the spinner to individual phase velocities, which in turn allow the total flow rate to be decomposed into separate oil, water, and gas contributions from each zone. Interpretation of a combined PLT string in a multiphase flowing well requires knowledge of the slip model: the relationship between the velocities of the different phases relative to each other and to the mixture. In vertical wells, gas rises faster than liquid (positive slip), water falls faster than oil (negative slip relative to oil), and the mixture velocity measured by the spinner reflects a weighted combination. The Gradiomanometer-Spinner method uses the measured fluid density gradient from the density tool and the spinner velocity to solve simultaneously for oil, water, and gas holdups and flow rates, using established multiphase flow correlations. In practice, this system of equations is underdetermined without additional sensors, which is why the full PLT string with multiple independent measurements provides substantially better accuracy than a spinner alone.

The change in direction of rotation that occurs when a spinner flowmeter tool is moving in the same direction, but faster, than the fluid. When the tool is stationary, moving against the fluid flow, or moving in the same direction but slower than the flow, it will rotate in one direction, perhaps clockwise. However, if it moves in the same direction, but faster than the fluid, it will rotate counterclockwise. This may happen at the bottom of a producing well, and, unless identified, can lead to a false interpretation.

A length of ordinary steel link chain used by the drilling crew to cause pipe being screwed together to turn rapidly. This is accomplished by first carefully wrapping the chain around the lower half of the tool joint that is hanging off in the slips, stabbing another joint into that one, and then throwing the chain in such a manner that it wraps itself on the new upper joint. At the proper time, the driller must pull tension on the chain while a member of the floor crew holds some tension on the free end of the chain. This causes the new drillpipe joint to act like a spool, and as the driller pulls the chain on one end using the drawworks, the spool (or new pipe joint) turns and screws into the joint hung off in the slips. If the floor crew members are not extremely careful, loose clothing or worse, fingers, may become trapped in the unspooling chain and be severely damaged or cut off. Most rig contractors have discontinued the use of spinning chains because of high accident rates. The chains are still available on the rigs, but are not routinely used, having been replaced with other mechanical spinning devices.

A standard laboratory instrument to measure interfacial tension. The method is particularly applicable to values of interfacial tension below 1 mN/m and especially below 10-2 mN/m, as may occur when employing surfactants for enhanced oil recovery. The method utilizes a tube containing a drop of the less-dense phase within the more-dense phase. When the tube is spun along its long axis at high speed, the resulting forces center the drop on the tube axis and deform it. The interfacial tension is a function of the shape of the deformed drop, the liquid densities and the rotation speed. Advanced versions of the instrument can periodically vary the rotation rate. The phase lag between the change of rotation rate and the drop deformation can be used to determine both interfacial elasticity and interfacial viscosity.

A mathematical procedure for connecting data points with a smooth line. The line does not necessarily go through the data points, but its direction and curvature are affected by all the data points. The "stiffness" of the line is controlled by a variable (lambda) in the algorithm.

What Is Spontaneous Potential? The spontaneous potential (SP) log measures the natural electrochemical voltage, in millivolts, generated between a moving borehole electrode and a fixed surface reference electrode as the tool traverses permeable formations. Petrophysicists worldwide use the SP response to identify permeable beds, estimate formation water salinity, calculate clay volume, and correlate stratigraphic intervals between wells. Key Takeaways The SP log records naturally occurring electrical potential differences between the borehole and surface, requiring no external current source and no conductive drilling fluid to function properly. Two electrochemical components drive the SP signal: the membrane potential arising at clay-rich boundaries and the liquid junction potential at the invaded zone interface, together making up the electrochemical potential. A negative SP deflection from the shale baseline indicates a permeable, clean sand where drilling mud filtrate is fresher than formation water, while a positive deflection signals either a salty mud system or certain carbonate intervals. The static spontaneous potential (SSP) in a perfectly clean, water-bearing sand serves as the theoretical maximum deflection and is the key parameter for calculating formation water resistivity (Rw) using the mud filtrate resistivity (Rmf). The SP log cannot be recorded in air-filled boreholes, oil-base mud (OBM) systems, or highly resistive formations, making the gamma ray log the preferred clay indicator in those environments. How Spontaneous Potential Works The SP measurement relies on electrochemical activity at the boundary between the mud filtrate that has invaded a permeable formation and the undisturbed formation water beyond the invasion zone. When the salinity of the formation water differs from the salinity of the mud filtrate, ions migrate across the permeable bed face and across clay membranes, generating a measurable voltage. The tool simply records this voltage continuously as the wireline sonde travels up the borehole at a standard logging speed, typically 300 to 600 metres per hour (about 1,000 to 2,000 feet per hour). The total SP deflection has two main contributors. The electrochemical potential, by far the larger component in most oil-field environments, consists of the membrane potential and the liquid junction potential. The membrane potential develops across shale laminae and clay-rich zones, which act as selective ion barriers: sodium ions pass through preferentially while chloride ions do not, creating a charge imbalance. The liquid junction potential develops at the contact between the mud filtrate in the invaded zone and the formation water in the uninvaded zone, where ions of differing mobilities cross the boundary at different rates. A third, usually minor contribution called the electrokinetic potential arises from fluid pressure differences that drive mud filtrate through the mudcake and formation pore throats, but in most permeable sands this term is small enough to neglect. Geologists and petrophysicists read the SP curve against a baseline called the shale line, which is the SP value recorded opposite thick, impermeable shale intervals where no permeable bed is present and no electrochemical gradient develops. Any deflection away from the shale line toward more negative millivolt values indicates a permeable zone. The maximum deflection measured in a thick, clean, water-bearing sand under a given set of mud and formation-water salinity conditions is called the static spontaneous potential, or SSP. In shaly sands, where clay dispersed in the pore space or laminated within the sand reduces the electrochemical efficiency of the membrane, the deflection reaches only the pseudostatic SP value, abbreviated PSP. The ratio PSP/SSP is directly related to clay volume, making SP one of the earliest tools used to quantify Vcl, the clay volume fraction, before gamma ray logs became the standard. Spontaneous Potential Across International Jurisdictions Canada: Alberta and the Montney/Duvernay Plays The Alberta Energy Regulator (AER) requires that wells drilled for oil and gas in Alberta submit wireline log data, including SP logs where recorded, through the Petrinex and KERMIT systems. Directive 065 governs the content and format of well logs submitted to the regulator. In conventional Cretaceous sandstone plays such as the Cardium and Viking formations of the Western Canada Sedimentary Basin, the SP log has decades of calibrated use for identifying permeable pay zones and correlating stratigraphy between closely spaced vertical wells. In the unconventional Montney siltstone play of northeastern British Columbia and northwestern Alberta, SP responses are more subdued because the tight, fine-grained Montney matrix limits permeability and the salinity contrast between low-salinity modern mud systems and the formation brine varies considerably across the play area. Petrophysicists working the Montney typically use the SP as a qualitative lithology indicator alongside gamma ray and resistivity logs rather than attempting a quantitative Rw calculation. In the Duvernay formation, a liquids-rich shale play in central Alberta, the SP is similarly limited in quantitative value but still useful for picking formation tops and correlating between horizontal wells in a pad-drilling programme. United States: Permian Basin Tight Sand Evaluation The SP log has a long history in Permian Basin operations in West Texas and southeastern New Mexico. In the prolific Spraberry, Wolfcamp, and Bone Spring intervals of the Midland and Delaware sub-basins, operators historically used SP deflections to identify water-saturated sands for Rw determination, which then fed into Archie water-saturation calculations. The U.S. Bureau of Land Management (BLM) and the Railroad Commission of Texas (RRC) both accept SP data as part of the required well-completion records. In the modern tight-oil Permian, where horizontal LWD suites have largely replaced wireline logging in the lateral section, the SP is often run only in the vertical portion of the well, providing petrophysical calibration data for the formation evaluation team. The Society of Petrophysicists and Well Log Analysts (SPWLA) has published standardised SP presentation guidelines that call for a track-one scale of -160 millivolts to +40 millivolts, with the shale baseline near the centre of the track. Australia: Cooper Basin Well Logging The Cooper Basin of South Australia and Queensland, Australia's primary onshore conventional gas province, uses SP logs extensively in Permian Patchawarra and Tirrawarra sandstone evaluation. The National Offshore Petroleum Titles Administrator (NOPTA) and the relevant state mining departments require log submissions for all wells, and SP data is archived in the national PEPS (Petroleum Exploration and Production System) database managed by Geoscience Australia. Cooper Basin formation waters tend to be moderately saline, typically in the range of 10,000 to 50,000 parts per million NaCl equivalent, which provides a reasonable salinity contrast with water-based muds and gives measurable SP deflections useful for zone identification and Rw estimation. Santos and Beach Energy, the dominant operators in the Cooper Basin, have built extensive petrophysical databases correlating SP responses to core-derived porosity and permeability data across thousands of wells, enabling reliable formation evaluation without coring every interval. Middle East: Ghawar Carbonate Evaluation Saudi Arabia's Ghawar field, the world's largest conventional oil field, produces primarily from the Arab-D carbonate reservoir. Carbonate formations generally show weaker SP responses than clastics because carbonates lack the clay mineral content needed for strong membrane potential development. However, Saudi Aramco petrophysicists use the SP log in Ghawar wells to distinguish between porous, water-wet carbonate zones and tighter, oil-bearing intervals where the invasion pattern and formation water salinity contrast still generate a measurable signal. The Saudi Ministry of Energy requires full log suites for all wells drilled on the Arabian Peninsula, and well data is managed through Saudi Aramco's proprietary formation evaluation database. In the Khuff gas formation, which underlies the Arab-D across much of the Eastern Province, SP logs help identify porous zones in dolomitised intervals and provide baseline salinity data for reservoir simulation models. Norway and the North Sea: Ekofisk Chalk Evaluation The Ekofisk field in the Norwegian sector of the North Sea, operated by ConocoPhillips, produces from a highly porous chalk reservoir in the Upper Cretaceous and Danian. Like other carbonate reservoirs, chalk yields subdued SP responses compared to clastic formations of equivalent permeability, because the very low clay content limits membrane potential development. The Norwegian Offshore Directorate (now the Norwegian Offshore Directorate, NOD, formerly Oljedirektoratet) requires wireline log data submission for all wells on the Norwegian Continental Shelf, archived in the DISKOS national database. In chalk evaluation, the SP log serves primarily as a lithology boundary marker and a formation water salinity indicator rather than a permeability discriminator. The chalk's high porosity (15 to 48 percent in Ekofisk) and low clay content mean the SP deflection is modest, but the log remains part of the standard triple-combo suite run alongside resistivity and neutron porosity tools on all exploration and appraisal wells. Fast Facts: SP Log Discovery and Scale Conrad Schlumberger and his team first documented the spontaneous potential effect in Russian oil fields in 1931, observing that the borehole electrode deflected measurably opposite permeable sand beds without any applied current. A typical SP deflection in a clean, water-bearing Cretaceous sandstone with a salinity contrast of 10,000 ppm formation water versus freshwater mud plots at approximately -80 millivolts to -120 millivolts on a standard presentation scale of -160 mV to +40 mV, and those deflections remain the primary depth reference for lithology correlation on millions of wells drilled worldwide over the past nine decades.

A device used to handle and temporarily store a coiled tubing string. Spoolers generally are configured with a removable drum that allows transport spools to be inserted, allowing a new string to be spooled onto a reel. The term is also occasionally used to describe the levelwind assembly on a tubing reel.

To accurately place a fluid, or fluid interface, at a given position within the wellbore. Treatment fluids such as cementslurries and stimulation fluids for localized treatment often require accurate placement. Correctly calculating and pumping the appropriate volume of displacement fluid while taking account of well production, wellbore returns and fluid-density variations are key factors in achieving accurate placement of fluids.

A sample of liquid or sediments obtained at a specific depth inside a tank using a thief or a bottle. Spot samples are analyzed to determine the gravity of the oil and BS&W content of the fluid in the tank.

A small volume or pill of fluid placed in a wellbore annulus to free differentially stuck pipe. Oil-base mud is the traditional stuck-pipe spotting fluid. Speed in mixing and placing the spot is of primary importance to successfully freeing pipe. Because of concern about mud disposal, spots used offshore are either synthetic-based emulsions or benign water-base formulations. Each type is supplied as prepackaged concentrate designed for rapid access and mixing at the rig. A spot frees pipe by covering the stuck region. It presumably breaks up the filter cake, allowing the spot to migrate into cracks in the cake and between the pipe and the cake, reducing the stuck area and allowing pipe to be pulled free.

The geometrical pattern of groups of geophones relative to the seismicsource. The output from a single shot is recorded simultaneously by the spread during seismic acquisition. Common spread geometries include in-line offset, L-spread, split-spread and T-spread.

The additional loss in amplitude of an electromagnetic wave emitted by an electromagnetic propagation or dielectric propagation measurement compared to that of a plane wave. The spreading loss depends on the geometry of the transmitter-receiverarray and also on the dielectric properties of the formation. The same effect also causes a small correction to the propagation time.

What Is a Spud? A spud marks the moment drilling begins on a new well, the first rotation of the drill bit breaking ground at the surface or seafloor. Operators report the spud date to regulators including the AER in Alberta, the NDIC in North Dakota, Sodir in Norway, and NOPSEMA in Australia, and the spud date initiates the statutory clock for many lease and licence obligations across international petroleum jurisdictions. Key Takeaways Spud is the industry term for the start of drilling, triggered when the bit begins rotating below surface or seafloor, and is tracked by every major oil and gas regulator as an official well-lifecycle milestone. Spud dates tie into lease obligations such as commitment wells, drill-or-drop provisions, and continuous drilling requirements under the terms of a CAPL 91 freehold lease, a BLM federal lease, or a state Crown lease. Operators, service companies, regulators, and investors all track spud activity because the aggregate weekly spud count is the primary leading indicator of future oil and gas supply. Regulatory reporting of spud dates follows AER daily spud reports in Alberta, the NDIC daily activity report in North Dakota, NOPSEMA well-activity notifications in Australian Commonwealth waters, and Sodir drilling permit records on the Norwegian Continental Shelf. Global spud activity in 2026 runs at approximately 550 active rigs in the United States and Canada combined, 180 rigs across the Middle East, 40 rigs on the Norwegian Continental Shelf, and 15 rigs offshore Australia. How a Spud Works A well is spudded after the surface location is constructed, the drilling rig is rigged up, and the conductor or surface hole is drilled or driven. On a typical North American land rig, the spud begins when the rotary table or top drive engages the kelly or drive shaft and the bit first contacts and begins breaking through the surface soil or caprock. The driller records the spud time to the nearest minute in the tour sheet, and the well-site supervisor reports the spud to the operator's drilling office, which in turn notifies the applicable regulator. Offshore, the spud moment is cleaner: the subsea BOP is landed on the temporary guidebase, the drill bit is lowered through the BOP and the conductor, and rotation begins below the seafloor. On a jackup rig in shallow water, the cantilever is extended over the wellhead location and the rig floor equipment engages the bit, mirroring the onshore process with an offshore platform. After the spud, the drilling program proceeds through discrete hole sections. The first section is typically 20-inch or 26-inch diameter for onshore wells, advancing to roughly 50 m (164 ft) or as deep as 800 m (2,625 ft) depending on jurisdiction and surface geology. Surface casing is then run and cemented, after which the BOP is installed and the well is ready for the deeper sections. The spud date commonly refers to the spud of the top hole, though some operators track a separate rig-release or reached-TD date as the end of the drilling phase. Spud Reporting Across International Jurisdictions Every major producing country captures spud data as part of statutory well reporting, and regulator feeds from these filings power the commercial intelligence used by Baker Hughes, Enverus, Rystad Energy, Wood Mackenzie, and the International Energy Agency. In Canada, the AER publishes daily spud reports for Alberta wells via the Production Audit and Reporting System, and the BCER and Saskatchewan's Ministry of Energy and Resources publish equivalent data for their jurisdictions. Spud dates reconcile against well-licence commitments, including continuous drilling provisions on Crown leases and drill-or-drop obligations under private freehold leases using the CAPL 91 standard form. In the United States, the NDIC Oil and Gas Division publishes a daily drilling rig list for North Dakota Bakken activity, showing each rig's spud date, operator, lease, and county. The Texas Railroad Commission's W-1 drilling permit system captures spud dates for Permian, Eagle Ford, and East Texas activity. Colorado, New Mexico, Oklahoma, Pennsylvania, and West Virginia maintain parallel reporting. Offshore, BSEE publishes monthly activity reports for the Gulf of Mexico and Pacific OCS, and the Bureau of Ocean Energy Management tracks lease commitments that depend on spud dates. Norway's Sodir publishes drilling permits and well-activity logs through its FactPages portal, with each well given a unique NPD identifier at the permit stage. Sodir data covers every operator on the Norwegian Continental Shelf, including Equinor, Aker BP, Var Energi, and TotalEnergies. Australia's NOPSEMA receives well-operation management plans and spud-activity notifications for Commonwealth offshore wells in the Carnarvon, Browse, and Bass Strait basins, while state regulators in Queensland, South Australia, and the Northern Territory cover the Cooper Basin, Beetaloo, and other onshore activity. The Middle East NOCs (ADNOC, Saudi Aramco, Kuwait Oil Company, Qatar Energy) maintain internal spud registers and report aggregate activity through national oil company disclosures and OPEC Monthly Oil Market Reports. Fast Facts North Dakota's Williston Basin sustained a weekly spud count of 25 to 35 new wells through most of 2025, with the NDIC's March 2026 rig list showing 34 active drilling rigs and a monthly spud rate near 110 wells. The Permian Basin in West Texas and southeast New Mexico accounts for roughly 241 of the 525 total active US rigs in 2026, making it the densest drilling activity anywhere on earth measured by rigs per square kilometer. Spud Dates, Lease Obligations, and Commercial Signals The spud date is more than a technical milestone. It triggers obligations and payments across multiple stakeholder groups. For the mineral owner, the spud date typically converts the lease from a primary-term paid-up or delay-rental structure to a secondary-term held-by-production structure, provided the well eventually produces in paying quantities. Under the CAPL 91 freehold lease form that dominates Western Canadian mineral negotiations, spud within the primary term preserves the lease through the continuous drilling provision. For the operator, the spud date starts AFE (Authorization for Expenditure) tracking against the approved drilling budget. Drilling cost overruns are measured against the days-from-spud curve, and service contractors invoice spread rates (day rates for the rig, mud engineer, directional drilling contractor, etc.) from the spud moment. Regulatory filings tied to spud include federal and state permit validity, BSEE Form BSEE-0123 for offshore wells, and AER Directive 056 applications that must be current on the spud date. For investors and market analysts, aggregate weekly spud counts published by Baker Hughes (the weekly North American Rig Count) and Rystad Energy provide a six-to-twelve-month leading indicator of future production. A week-over-week rig count decline in the Permian in early 2026, for example, telegraphs slower production growth in late 2026 and 2027, which in turn affects commodity price forecasts at Goldman Sachs, Morgan Stanley, and RBC Capital Markets. OPEC+ production policy decisions reference US spud activity as a counterweight to managed Middle East output cuts. Tip: Field crews sometimes distinguish between "spud with surface rig" and "spud with main rig" on wells where a top-hole rig drills the first 500 m (1,640 ft) and then a larger drilling rig moves on for the deeper sections. In AER Directive 036 and NDIC reporting, only the spud with the main drilling rig typically counts as the official spud date. Mineral-rights negotiators should confirm which event satisfies the drilling commitment under the relevant lease before assuming a lease is preserved. Spud Synonyms and Related Terminology Spud date: the calendar date on which drilling began, reported to regulators and lease stakeholders. Spud in: verbal form used in daily operations: "we spudded in at 05:30 this morning." Spud mud: the low-cost fresh-water bentonite mud used for the surface hole. Initial spud: the start of the very first hole section; used when a well is spudded with a top-hole rig and later deepened by a main rig. Kickoff: distinct from spud; refers to the depth at which a directional well begins to build angle from vertical. Rig release: the opposite milestone; the moment the drilling rig is released from the well after reaching total depth. Related terms: Casing, Cement, Blowout Preventer, Horizontal Drilling, Directional Drilling, Lease, Landman, Well Control. Frequently Asked Questions What does it mean to spud a well? To spud a well means to begin drilling. The spud moment is the first rotation of the drill bit breaking ground at the surface or seafloor, and it is the official start of a well's active drilling phase. Regulators, mineral owners, and operators all track the spud date as the trigger point for lease obligations, permit timelines, and commercial commitments. Where does the term spud come from? The term originated from old shallow-drilling practices where a wooden or metal spud (a tool resembling a chisel or spade) was used to break ground before setting the first casing. The term carried forward into modern rotary drilling despite the tool itself no longer being used. How is the spud date reported? Spud dates are reported to the relevant regulator within 24 to 48 hours of drilling commencement. In Alberta, the AER receives spud notifications via the PAR system. In North Dakota, the NDIC receives spud reports through the daily rig list. Norway's Sodir captures spud data via FactPages, and NOPSEMA receives Australian offshore spud notifications under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. Why is the spud date important to landowners? The spud date often determines whether a lease is preserved beyond its primary term. Under the CAPL 91 freehold lease standard common in Alberta and Saskatchewan, spudding a well during the primary term can preserve the entire lease under the continuous drilling clause, provided the operator follows through to completion and production. Missing the spud deadline can result in lease expiry and loss of access to the minerals. How many wells are spudded globally each year? Global well spuds in 2026 run approximately 60,000 to 70,000 per year, with the majority concentrated in the United States (roughly 11,000 to 14,000 onshore spuds per year), the Middle East (roughly 6,000 to 8,000), China (roughly 15,000 to 20,000 including CBM and tight gas), and Canada (roughly 4,500 to 6,000). Offshore spuds worldwide total approximately 1,200 to 1,500 per year, concentrated in the Gulf of Mexico, the North Sea, the Norwegian Continental Shelf, Brazil's pre-salt, West Africa, and the Persian Gulf. Why Spud Dates Matter in Oil and Gas The spud date is the industry's universal start-of-work signal, the moment when an operator's investment decision converts into dirt and steel on a rig pad. Every lease payment schedule, every AFE cash-out, every regulator's compliance clock, and every analyst's supply forecast traces back to the spud. For the rig crew turning to the right on a frozen Alberta pad, the landman protecting a lease's continuous drilling obligation, the NDIC geologist compiling the daily rig list, and the commodity trader reading the weekly Baker Hughes rig count, the spud moment is where paper becomes production.

Mud used to drill a well from surface to a shallow depth. Guar gum or saltgel are commonly used offshore as spud mud. Onshore spud mud is usually a water-base mud containing bentoniteclay that is flocculated with lime. In a large-diameter surface hole, a flocculated clay-based mud can remove large gravel cuttings encountered at shallow depths and is simple and inexpensive.

The instantaneous volume (spurt) of liquid that passes through a filter medium prior to deposition of a competent and controlling filter cake. In static filtration, the spurt volume can be a disproportionately large percentage of the total 30-minute filtrate in an API-type test. This indicates that filter cake is slow in being deposited compared to a similar mud with lower spurt loss. To avoid uncertainties of spurt-loss volume, relative filtrate volume is used in static tests.

A log in which the changes in reading with depth only occur abruptly, with no transition. A square log is often an approximation of a real log, in which the continuously varying input log has been approximated by constant values and abrupt changes. A square log contains less data than a real log but can be useful for further processing.

What Is Squeeze Cementing? Squeeze cementing forces cement slurry under pressure through perforations, channels, or voids in an existing wellbore to restore or establish zonal isolation between formations. Operators deploy this remedial technique when primary cementing fails to achieve complete coverage, when a casing string develops leaks, or when regulatory requirements demand verified isolation before abandonment. Key Takeaways Squeeze cementing is a pressure-driven remedial operation that places cement slurry into specific locations in an existing wellbore to seal channels, perforations, microannuli, or casing defects that compromise zonal isolation. The hesitation squeeze technique, which alternates pumping and shut-in cycles, is the most reliable method for permeable zones because the pauses allow cement to dehydrate and build filtercake before additional slurry is pumped. Final squeeze pressure (FSP) must remain below the formation fracture gradient for competent casing repair squeezes, but may intentionally exceed it when placing cement into the formation matrix during abandonment squeezes. Low-water-loss cement slurry with a fluid loss of less than 50 cc per 30 minutes is the industry standard for squeeze operations, preventing premature dehydration in the pump lines while ensuring rapid dehydration at the squeeze target. Post-squeeze evaluation using cement bond logs (CBL), variable density logs (VDL), and ultrasonic imaging tools is mandatory under most regulatory frameworks including AER Directive 020, BSEE 30 CFR Part 250, and NOPSEMA well operations standards. How Squeeze Cementing Works Squeeze cementing begins with a thorough diagnostic phase to identify the location and character of the isolation failure. A cement bond log (CBL) and variable density log (VDL) run before the squeeze maps acoustic impedance contrast between the casing wall and the surrounding annulus, identifying channeled cement, free pipe sections, and areas of partial bonding. Once the squeeze target interval is identified, the wellbore is conditioned by circulating kill fluid to control bottom-hole pressure, and the target perforations or casing defects are washed with a perforation wash tool to remove scale, filter cake, and debris that would block cement entry. Residue from formation damage or prior stimulation treatments must be flushed from the perforations before cement can enter; even a thin layer of residual filter cake can prevent slurry from entering a perforation and cause the squeeze to fail. A retrievable packer is set above the squeeze interval to isolate the zone from the wellbore above. The packer directs all pump pressure into the isolated interval, preventing slurry from traveling up the casing to unintended locations. A cement stinger, a smaller-diameter pipe string run inside the production tubing or on coiled tubing, delivers the cement slurry directly to the perforations or defect, minimizing cement contamination by wellbore fluids. In simpler Bradenhead squeeze operations, no downhole packer is used; pressure is applied at the surface through the tubing head, relying on the column of fluid in the wellbore to direct cement toward the target. Bradenhead squeezes are less controllable and are reserved for low-pressure wells or situations where running a packer is impractical. After the cement slurry is mixed and pumped, the operator monitors surface treating pressure throughout the job. As cement enters the target zone and begins to dehydrate against the formation face or the channeled annulus, the hydraulic resistance increases and surface pressure rises. The operator manages pump rate and pressure to stay below the formation fracture gradient while ensuring adequate cement placement. Once the job is complete, the packer and stinger are retrieved and the wellbore is shut in during the wait-on-cement (WOC) period, which ranges from 8 to 24 hours depending on the cement formulation and bottom-hole temperature. After WOC, a drill-out run or wireline perforating gun removes excess cement from the casing bore and the well is re-evaluated with post-squeeze logging. Squeeze Cementing Across International Jurisdictions Canada (Alberta): AER Directive 020, "Well Abandonment," and AER Directive 009, "Well Licencing," set out the technical and procedural requirements for squeeze cementing in Alberta. Directive 020 mandates that all perforation intervals in abandoned wells be sealed with a minimum 20 m (66 ft) cement plug verified by either a cement bond log or a pressure test demonstrating that the plug holds pressure at 1,000 kPa (145 psi) above hydrostatic for 30 minutes without bleed-off. Squeeze cementing is the prescribed method when the original primary cement does not provide this coverage. The AER also requires the operator to submit a post-abandonment report documenting the squeeze design, actual treating pressure, cement volume pumped, and CBL evaluation results. In the Montney and Duvernay plays, where well densities in some townships exceed 400 wells per section, ensuring squeeze integrity during abandonment is critical to preventing cross-zone contamination of groundwater formations and future drilling hazards. United States (Offshore and Onshore): BSEE regulates offshore squeeze cementing under 30 CFR Part 250, Subpart B, which requires operators to submit an Application for Permit to Modify (APM) before any remedial cementing operation. The APM must include the squeeze design basis, target interval, cement slurry formulation, anticipated treating pressures, and planned post-job evaluation method. Onshore squeeze cementing on federally managed lands is regulated by the Bureau of Land Management (BLM) under Onshore Oil and Gas Order No. 2, which requires that the wellbore be in a safe condition and that all remedial operations be documented and submitted in the Well Completion or Recompletion Report. In Texas and other state-regulated jurisdictions, the Railroad Commission of Texas (RRC) governs remedial cementing through its Statewide Rules, particularly Rule 13 for casing requirements, and requires that squeeze jobs achieve an external casing pressure (ECP) seal verified by a step-rate test or bond log. Norway and the North Sea: NORSOK Standard D-010 classifies remedial cementing including squeeze cementing as a well barrier operation requiring a pre-job well barrier schematic showing how zonal isolation will be maintained throughout the squeeze operation. The PSA Norway requires that the operator demonstrate competent authority approval for squeeze operations on HPHT wells where the proposed treating pressure exceeds 80% of the formation fracture pressure. Post-squeeze CBL and VDL evaluation is required for all abandonment squeezes, and the results must be incorporated into the well's permanent abandonment record in accordance with the Norwegian Petroleum Directorate's DISKOS well database requirements. The North Sea's long-established well stock, with thousands of wells drilled in the 1970s and 1980s using cement formulations and techniques that fall below modern standards, makes squeeze cementing a routine part of late-life asset management programs for all major North Sea operators. Australia: NOPSEMA requires that any squeeze cementing operation be described in the operator's Well Operations Management Plan (WOMP) and that the plan demonstrate compliance with the Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations 2009. The WOMP must address pre-job risk assessment, job design rationale, treating pressure limits relative to the formation fracture gradient, contingency plans for job failure, and post-job evaluation criteria. For wells in the Browse Basin and on the North West Shelf, where carbonate reservoirs have highly variable permeability and natural fracture networks, the squeeze design must account for the possibility of unintentional fracture initiation during pumping, which could route cement away from the intended isolation target. NOPSEMA inspectors conduct periodic audits of WOMP compliance and may require additional well integrity testing if squeeze quality is in doubt. Middle East: Saudi Aramco Engineering Standard SAES-S-070, "Cementing Requirements," and the associated Saudi Aramco Materials System Specification (SAMSS-039) govern squeeze cementing design and execution for onshore and offshore wells in the Kingdom. Saudi Aramco requires a pre-squeeze well integrity review signed off by the Well Integrity Unit before any squeeze operation on a producing well. Post-squeeze evaluation on Ghawar and Abqaiq field wells frequently uses downhole ultrasonic imaging tools, such as the Isolation Scanner (SLB) or Flexus (Baker Hughes), rather than conventional CBL, because the high-density formation lithology and casing sizes used in Saudi Aramco wells can attenuate the conventional CBL signal, making image-based evaluation more reliable. Abu Dhabi National Oil Company (ADNOC) follows a similar framework under its Well Engineering Standard WES-022, with the additional requirement that all squeeze jobs on wells producing from the Khuff gas reservoirs be reviewed by the Reservoir Management Division to assess the risk of cement entering the producing formation and causing permanent permeability damage. Fast Facts Typical cement volume per zone: 10 to 50 barrels (1.6 to 8 m3) of slurry per squeeze interval, depending on void volume and permeability. Fluid loss requirement: Low-water-loss slurry with fluid loss below 50 cc per 30 minutes (APIRP 10B test method) is standard for squeeze operations. Final squeeze pressure: Typically set at 500 to 1,000 psi (3.4 to 6.9 MPa) below the formation fracture pressure for casing repair; may exceed fracture pressure intentionally for formation squeezes. Wait-on-cement time: 8 to 24 hours at bottom-hole temperature before drill-out or pressure testing; longer WOC for low-temperature wells below 40 degrees Celsius (104 degrees Fahrenheit). Micro-fine cement particle size: D90 below 15 microns for squeezing microannuli and natural fractures below 50 microns in aperture. CBL evaluation threshold: A post-squeeze CBL amplitude reduction of 80% relative to free-pipe amplitude indicates adequate cement coverage in most carbonate and sandstone formations. Packer setting depth: Typically 3 to 10 m (10 to 33 ft) above the top perforation to ensure the packer element is set on clean, uncorroded casing.

A manifold connected within the surface treating lines that is configured to enable control and routing of fluids during a squeeze operation. Most squeeze manifolds have treating line connections with the tubing string, annulus, pit line and pump unit. Isolation valves enable the appropriate flowpath to be selected, and pressure sensors included in tubing and annulus lines monitor the key treatment pressures. In some squeeze treatments, such as squeeze cementing, it may be desirable to reverse-circulate excess cement from the tubing string. The squeeze manifold enables a change in fluid routing to be quickly and easily achieved from one station.

A type of retrievable packer used in squeeze-cementing operations. Key features include a bypass system and hold-down slips. The bypass system prevents surge and swab effects when running and retrieving the packer and enables circulation of the cementslurry to the proximity of the packer before closing the bypass for injection into the treatment zone. The hold-down slip assembly enables application of high squeeze pressure without the risk of the packer unsetting or moving up the wellbore.

The final or maximum pressure that can be applied during a squeeze operation. When conducting a squeeze-cement job, it is generally desirable to achieve a high final squeeze pressure that indicates the target holes and voids are filled with cement filter cake.

To place the male threads of a piece of the drillstring, such as a joint of drillpipe, into the mating female threads, prior to making up tight.

To guide and engage components that are designed to couple, such as a seal assembly in a sealborepacker.

A valve that is connected to the work string in the event that the well starts to flow when running or retrieving the string. A stabbing valve generally is kept on the rig floor as a contingency against unexpected well flow. On snubbing operations, a stabbing valve, or safety valve, is kept in the workbasket to protect against tubing plug or backpressure valve failure.

A state that a producing well reaches when the flow rate and well pressure are apparently constant for a reasonable period of time, such as a few hours or a day or more. The actual time period is rather arbitrary and depends on the location and the people involved. For shut-in wells, stabilization refers to a reasonably constant pressure. Stabilized pressures are commonly used as starting points for well tests.In reality, the time to stabilization at truly constant pressure and rate is infinite. The target stabilization for rigorous testing in gas wells is pseudosteady-state flow, and this may be recognized as the pressure change versus time predicted from formation properties and drainage area size. The onset of radial flow may produce an apparent stabilization that is acceptable for analysis when multirate flow periods are of equal duration.

A term describing a flowing well when its rate of production through a given choke size remains constant, or in the case of a pumping well, when the fluid column within the well remains constant in height.

A gas well producing at a constant rate in which wellheadpressure changes no more than a small amount as a function of time. The actual amount of change permitted in a given time period to allow a well to be designated as stabilized may be fixed by law. Alternatively, the target stabilization for rigorous flow-after-flow testing in gas wells is pseudosteady-state flow, and this may be recognized as the pressure change versus time predicted from formation properties and drainage area size.

The geometric profile around a correctly placed perforation. With the removal of perforating debris and the crushed zone by flushing or stimulation treatment, the exposed formation forms an arch that is capable of withstanding the differential pressure and the forces created by fluid flow during production. An unstable formation interface, such as shattered formation surrounding the perforation tunnel, may result in plugging or collapse of the perforation tunnel.

To sum traces to improve the signal-to-noise ratio, reduce noise and improve seismic data quality. Traces from different shot records with a common reflection point, such as common midpoint (CMP) data, are stacked to form a single trace during seismic processing. Stacking reduces the amount of data by a factor called the fold.

The distance-time relationship determined from analysis of normal moveout (NMO) measurements from common depth point gathers of seismic data. The stacking velocity is used to correct the arrival times of events in the traces for their varying offsets prior to summing, or stacking, the traces to improve the signal-to-noise ratio of the data.

An operation in which the well stream is passed through two or more separators that are arranged in series. The first separator is called first-stage separator, the second separator is called second-stage separator and additional separators are named according to their position in the series. The operating pressures are sequentially reduced, so the highest pressure is found at the first separator and the lowest pressure at the final separator.The objective of stage separation is to maximize the hydrocarbon liquid recovery and to provide maximum stabilization to the resultant phases (liquid and gas) leaving the final separator. Stabilization means that considerable amounts of gas or liquid will not evolve from the final liquid and gas phases, respectively, in places such as stock tanks or gas pipelines. Additionally, stage separation reduces the horsepower required by a compressor, since the gas is fed at higher pressures.

An operation in which numerous reservoir intervals are hydraulically stimulated in succession. Staged hydraulic fracturing operations are commonly performed from horizontal wellbores placed in shale gas reservoirs. Using geomechanical data, engineers are able to optimize the placement of perforations and fracturing stages to maximize gas production.

Two or three single joints of drillpipe or drill collars that remain screwed together during tripping operations. Most modern medium- to deep-capacity drilling rigs handle three-joint stands, called "trebles" or "triples." Some smaller rigs have the capacity for only two-joint stands, called "doubles." In each case, the drillpipe or drill collars are stood back upright in the derrick and placed into fingerboards to keep them orderly. This is a relatively efficient way to remove the drillstring from the well when changing the bit or making adjustments to the bottomhole assembly, rather than unscrewing every threaded connection and laying the pipe down to a horizontal position.

A rigid metal conduit that provides the high-pressure pathway for drilling mud to travel approximately one-third of the way up the derrick, where it connects to a flexible high-pressure hose (kelly hose). Many large rigs are fitted with dual standpipes so that downtime is kept to a minimum if one standpipe requires repair.

A type of batch-treating technique used in corrosion control. The batch of corrosion inhibitor is displaced through the annulus to the bottom of the well. Once the inhibitor is at the bottom, it is circulated up the tubing and returned back into the annulus, leaving a considerable amount of inhibitor in the annulus for further circulation. A standard batch treatment is used mainly in pumping wells and could last from a day to several months depending on the specific corrosion inhibitor used.

In a subsurface sucker-rod pump, a valve that permits flow up the tubing to fill the pump-barrel chamber while preventing downward flow.

A piece of material designed to hold a logging tool a certain distance away from the borehole wall. It is usually made of hard rubber and consists of four to six fins of the desired length.

A rigid metal conduit that provides the high-pressure pathway for drilling mud to travel approximately one-third of the way up the derrick, where it connects to a flexible high-pressure hose (kelly hose). Many large rigs are fitted with dual standpipes so that downtime is kept to a minimum if one standpipe requires repair.

A drilling-mud additive used to control fluid loss in water muds ranging from freshwater to saturated-salt to high-pH lime muds. Starches have thermal stability to about 250°F [121°C]. They are subject to bacterial attack unless protected by high salinity or bactericide. Drilling-grade natural starch has API/ISO specifications for quality. Starches are carbohydrates of a general formula (C6H10O5)n and are derived from corn, wheat, oats, rice, potatoes, yucca and similar plants and vegetables. They consist of about 27% linear polymer (amylose) and about 73% branched polymer (amylopectin). The two polymers are intertwined within starch granules. Granules are insoluble in cold water, but soaking in hot water or under steampressure ruptures their covering and the polymers hydrate into a colloidal suspension. This product is a pregelatinized starch and has been used in muds for many years. Amylose and amylopectin are nonionic polymers that do not interact with electrolytes. Derivatized starches, such as hydroxypropyl and carboxymethyl starches, are used in drill-in fluids, completion fluids and various brine systems as well as in drilling-mud systems. The use of starch typically causes a minimal increase in viscosity while effectively controlling fluid loss.

A mud test in which the mud sample is not agitated. This test is usually performed at a selected high temperature. Typically, the mud sample is sealed in a mud-aging cell and placed in an oven for a given period of time (often 16 hours, overnight). The cooled mud is tested before it is stirred. Commonly, the sample is retested after it has been stirred. Static-aged mud, before it is stirred, simulates a mud that is static in a well while pipe is out of the hole during a bit trip or loggingrun. The stirred mud simulates the same mud after arriving at the surface and after being agitated by mud guns and through centrifugal pumps. The amount and kind of mud treatment are determined from these tests.

Often called statics, a bulk shift of a seismic trace in time during seismic processing. A common static correction is the weathering correction, which compensates for a layer of low seismic velocity material near the surface of the Earth. Other corrections compensate for differences in topography and differences in the elevations of sources and receivers.

A filtration process in which the slurry being filtered remains static. Filter cake continues to grow thicker as filtration continues. Under static conditions, no cake erosion occurs. In theory, the filtrate volume increases as the square root of elapsed time, ignoring spurt loss.

The level to which fluid rises in a well when the well is shut in. The hydrostatic head of this fluid is equal to the well bottomhole pressure.

The pressure measured in a well after the well has been closed in for a period of time, often after 24 or 72 hours. When a reservoir is first discovered, the static pressure equals the initial pressure. After production begins, the static pressure approaches the average reservoir pressure.

The ideal spontaneous potential (SP) that would be observed opposite a permeablebed if the SP currents were prevented from flowing and any shaliness in the bed were ignored. The static spontaneous potential (SSP) is equal to the electrochemical potential. When current is flowing, the SP measures only that fraction of the potential drop that occurs in the borehole. In normal conditions, this potential drop is much higher than the drop in the formation because the cross-sectional area of the borehole is much smaller, and hence its resistance much higher. It is for this reason that in the middle of a thick, clean bed whose resistivity is not too high, the SP reads close to the SSP. However, in other conditions the SP is significantly less than the SSP.As well as ignoring shaliness in the sand, the SSP ignores other sources of potential and assumes a surrounding shale that is a perfect cationic membrane.

A mud test in which the mud sample is not agitated. This test is usually performed at a selected high temperature. Typically, the mud sample is sealed in a mud-aging cell and placed in an oven for a given period of time (often 16 hours, overnight). The cooled mud is tested before it is stirred. Commonly, the sample is retested after it has been stirred. Static-aged mud, before it is stirred, simulates a mud that is static in a well while pipe is out of the hole during a bit trip or loggingrun. The stirred mud simulates the same mud after arriving at the surface and after being agitated by mud guns and through centrifugal pumps. The amount and kind of mud treatment are determined from these tests.

A form of homogeneity in a single characteristic. Local stationarity occurs when two or more adjacent, locally homogeneous samples yield similar values of the property of interest.

The slip set on a snubbing unit located at the base of the jack. Two sets of stationary slips are available, one set for pipe-heavy conditions and another for pipe-light conditions.

The stationary slip set on a snubbing unit used when operating under light-pipe conditions. Under these conditions, the wellheadpressure is sufficient to eject the tubing string from the wellbore. Therefore, the slips are oriented in a hold-down position to grip with the force acting upward on the string.

A branch of mathematics that attempts to bring some understanding in the analysis of quantitative measurements. This science deals with the collection, analysis and interpretation of numerical data, often using probability theory. Statistics can also involve the generation of synthetic data between or within a group of measured data.

A system that has reached equilibrium for the measurement or phenomenon concerned. In the case of permeability measurements on core samples, a steady state is reached when the flow rate, the upstream and the downstream pressures no longer change with time. At this point the permeability can be calculated from the flow rate and pressures and applying Darcy's equation. If gas is used, the inertial resistance and gas slippage (Klinkenberg effect) should be corrected for.

Simultaneously constant pressure (wellhead or bottomhole) and flow rate. This behavior can result when there is pressure support, either naturally through an aquifer or gas-cap drive, or artificially through water or gas injection.

A two-phase mixture of liquid water and steam produced from a generator. The latent heat of vaporization for steam is very high, and when the steam condenses in the reservoir a significant amount of heat is transferred from the steam to the formationrock and fluids. Since steam is lighter and more mobile than oil, gravity differences and channeling of the steam through the most permeable parts of the reservoir can create sweep efficiency problems during steam-injection processes.To increase sweep efficiency, there are two categories of improvements. The first is operational changes such as selective completion of injector wells, fracturing operations and constructing horizontal wells, and the second is the use of additives in the steam. For example, water-soluble surfactants modify interfacial properties of the oil-water system, and foams reduce steam mobility.

The volume of reservoir in which mobile steam exists for an extended period of time. Within the steam chamber, rock temperature rises to the point where steam vapor can be sustained at reservoir pressure conditions. The steam chamber is normally found in the upper portion of a reservoir sand between a steam injector and a producer, where steam has broken through to the producer. With time, the steam chamber can expand to cover an entire area of a five-spot pattern steamflood. For a steam assisted gravity drainage (SAGD) system, the steam chamber in a mature field project can extend from a broad area across the top of the sand to a narrow finger down to the producing horizontal well near the bottom of the sand.Also referred to as a steam chest.

The overall heat and fuel management for a steam injection process. It includes economically efficient use of fuel consumed to generate steam, minimization of heat losses in surface steam-distribution lines, proper splitting of steam flow and quality and intersections in steam-distribution lines, and effective management of steam and heat distribution in the reservoir.

Crude oils with high viscosity (typically above 10 cP), and gravity lower than 22.3° API are classified as heavy oils. These crudes generally require special producing techniques to overcome their high viscosity. This special section in the Oilfield Glossary reflects the growing importance of heavy oil to the E&P Industry, and provides an evergreen, comprehensive listing for major heavy-oil terms. Definitions ranging from API gravity to steamflood to wormhole have been reviewed by technical experts in the domain, with some terms supplemented by high-quality illustrations for clarification.

A barrier or resistance to the flow of injected steam formed by a volume around a producing well in a steamflood that contains high oil and liquid water saturation. This is typically maintained by choking the production well to keep the surrounding formation just below saturated steam temperature and pressure conditions. It is used in the steam-assisted gravity-drainage process.

A thermal production method for heavy oil that pairs a high-angle injection well with a nearby production well drilled along a parallel trajectory. The pair of high-angle wells is drilled with a vertical separation of about 5 m [16 ft]. Steam is injected into the reservoir through the upper well. As the steam rises and expands, it heats up the heavy oil, reducing its viscosity. Gravity forces the oil to drain into the lower well where it is produced.

Parameter used to monitor the efficiency of oil production processes based on steam injection. Commonly abbreviated as SOR, it measures the volume of steam required to produce one unit volume of oil. Typical values of SOR for cyclic steam stimulation are in the range of three to eight, while typical SOR values for steam assisted gravitydrainage are in the range of two to five. The lower the SOR, the more efficiently the steam is utilized and the lower the associated fuel costs.

A method of thermal recovery in which steam generated at surface is injected into the reservoir through specially distributed injection wells.When steam enters the reservoir, it heats up the crude oil and reduces its viscosity. The heat also distills light components of the crude oil, which condense in the oil bank ahead of the steam front, further reducing the oil viscosity. The hot water that condenses from the steam and the steam itself generate an artificial drive that sweeps oil toward producing wells.Another contributing factor that enhances oil production during steam injection is related to near-wellbore cleanup. In this case, steam reduces the interfacial tension that ties paraffins and asphaltenes to the rock surfaces while steam distillation of crude oil light ends creates a small solvent bank that can miscibly remove trapped oil. Steamflooding is also called continuous steam injection or steam drive.

A mud motor incorporating a bent housing that may be stabilized like a rotary bottomhole assembly. A steerable motor can be used to steer the wellbore without drillstring rotation in directional drilling operations, or to drill ahead in a rotary drilling mode.

The weight bar used in slickline operations to overcome the effects of wellheadpressure and friction at the surface seal where the wire enters the wellbore. In addition to a solid steel stem, a special high-density stem is available with internal cavities filled with lead, tungsten or mercury alloys.

With reference to invasion, an abrupt change from the flushed zone to the undisturbed zone, with no transition zone or annulus. This simple model is used most commonly in connection with older resistivity logs since it allows the invasion to be represented by three parameters: flushed-zone resistivity, undisturbed-zone resistivity and diameter of invasion. The model assumes equal invasion at all azimuths. Newer array logs allow more complex invasion models to be interpreted.

A test performed in preparation for a hydraulic fracturing treatment in which an injection fluid is injected for a defined period in a series of increasing pump rates. The resulting data are used to identify key treatment parameters of the fracturing operation, such as the pressure and flow rates required to successfully complete the treatment.

The irregular movement of a logging tool up a well due to it being stuck at some point and then being released. In normal operation, the cable is pulled smoothly out of the well and the logging tool follows. However, the tool can become stuck by differential pressure or an irregular hole. The cable stretches, and its tension increases, until the tool is freed. At this point it moves, or slips, quickly up the hole until the normal movement is resumed.Since the depth measurement is driven by the cable, the log readings opposite a zone of stick and slip are displayed at incorrect depths. Furthermore, since each measurement has a different measure point, the zone of stick and slip shows up at a different depth on each measurement.

A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracturepressure of the reservoirformation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.

A compound formed by a secondary reaction of stimulation fluids with fluids or solids present in the reservoirmatrix. The most damaging stimulation byproducts are the insoluble precipitates that can form when the pH of the treatment fluid increases during the reaction process. Precipitates of iron compounds can be particularly problematic if conditions allow the formation of gelatinous, insoluble ferric compounds in the near-wellbore area.

A treatment fluid prepared for stimulation purposes, although the term most commonly is applied to matrix stimulation fluids. Most matrix stimulation fluids are acid or solvent-based, with hydrochloric acid being the most common base due to its reaction characteristics and its relative ease of control.

An analysis related to a process involving a randomly determined sequence of observations, each of which is considered as a sample of one element from a probabilitydistribution.

(noun) Statistical and probabilistic techniques used in reservoir modelling and geostatistics to generate multiple equally probable realisations of reservoir properties (such as porosity, permeability, and facies distribution) that honour available data while capturing geological uncertainty.

The production of a model of a reservoir or field by using stochastic methods to interpolate between data measurements (usually wells).

A storage tank for oil production after the oil has been treated.

A measure of the volume of treated oil stored in stock tanks. A stock tank barrel is commonly abbreviated as STB.

A downhole valve that operates by fluid velocity and closes when the fluid flow from the well exceeds preset limits. The forerunner to modern subsurface controlled safety valves, storm chokes were used in offshore applications as a contingency device in the event of a catastrophic failure of surface facilities during a storm or hurricane.

A heavy-duty retrievable packer assembly that can be run in to isolate the wellbore of a new well in the event of suspended activities, for example, during a severe storm. An on-off disconnect feature enables the storm packer to be set at a safe depth while using the weight of the string below the packer to maintain the set and hang off the drillstring to avoid pulling all the way out of the hole.

The permanent deformation evident in rocks and other solid bodies that have experienced a sufficiently high applied stress. A change in shape, such as folding, faulting, fracturing, or change, generally a reduction, in volume are common examples of strain seen in rocks. Strain can be described in terms of normal and shear components, and is the ratio of the change in length or volume to the initial length or volume.For more on strain: Means WD: Stress and Strain. New York, New York, Springer-Verlag, 1976.

A device used to catch and hold the debris flowing in pipelines. Such foreign materials can cause severe damage to meters or other surface equipment.

To measure the dimensions of an oil tank, such as external diameter and height, using a steel tape. Once the measurements are recorded, they may be used to prepare tank tables, which describe tank capacity.

(noun) The process of calibrating the volume of a storage tank by measuring its internal dimensions at regular intervals and constructing a strapping table that relates the liquid level (gauge height) to the contained volume. Strapping is a fundamental custody transfer measurement procedure governed by API standards.

A graduated tape use to measure, or strap, producing tanks. The measurements are used to generate a tank table, which describes tank capacity.

A multiphase-flow regime in horizontal or near-horizontal wells in which the fluids are separated into different layers, with lighter fluids flowing above heavier fluids. Stratified flow is more likely to occur at low flow rates and in flat or downhill sections of horizontal wells. In uphill sections, and as the flow rate increases, the interface between the fluids becomes mixed and irregular, hence the term wavy stratified flow is often used.

(noun) The study of the origin, composition, distribution, and succession of rock strata to interpret depositional environments, correlate formations between wells, and identify stratigraphic traps that may contain hydrocarbon accumulations. Stratigraphic analysis integrates well logs, core data, seismic data, and outcrop observations.

A variety of sealed geologic container capable of retaining hydrocarbons, formed by changes in rock type or pinch-outs, unconformities, or sedimentary features such as reefs. Structural traps, in contrast, consist of geologic structures in deformed strata such as faults and folds whose geometries permit retention of hydrocarbons.

The study of the history, composition, relative ages and distribution of strata, and the interpretation of strata to elucidate Earth history. The comparison, or correlation, of separated strata can include study of their lithology, fossil content, and relative or absolute age, or lithostratigraphy, biostratigraphy, and chronostratigraphy.

Layers of sedimentary rock that form beds.

A surface marine cable, usually a buoyant assembly of electrical wires that connects hydrophones and relays seismic data to the recording seismic vessel. Multistreamer vessels tow more than one streamer cable to increase the amount of data acquired in one pass.

In marineseismic acquisition, the lateral deviation of a streamer away from the towing direction because of a water current.

A decline of cement strength at elevated temperatures. This decline is pronounced at temperatures above 230°F [110°C], but it may be controlled by the addition of silica to the cement.

The force applied to a body that can result in deformation, or strain, usually described in terms of magnitude per unit of area, or intensity.

A form of corrosion in which susceptible types of metals will break by a combination of stress within the metal and the specific type of corrosion. Sulfide corrosion of ferrous alloys and chloride corrosion of stainless steels are two common type of SCC. When high-strength steel remains in contact with hydrogen sulfide (or sulfide ion) in a water-mud environment, sulfide SCC may occur. Tool joints, hardened parts of blowout preventers and valve trim are particularly susceptible to brittle failure caused by sulfide SCC. For this reason, along with toxicity risks of hydrogen sulfide gas, it is essential that water muds be kept entirely free of soluble sulfides and especially hydrogen sulfide at low pH.

A form of corrosion in which susceptible types of metals will break by a combination of stress within the metal and the specific type of corrosion. Sulfide corrosion of ferrous alloys and chloride corrosion of stainless steels are two common type of SCC. When high-strength steel remains in contact with hydrogen sulfide (or sulfide ion) in a water-mud environment, sulfide SCC may occur. Tool joints, hardened parts of blowout preventers and valve trim are particularly susceptible to brittle failure caused by sulfide SCC. For this reason, along with toxicity risks of hydrogen sulfide gas, it is essential that water muds be kept entirely free of soluble sulfides and especially hydrogen sulfide at low pH.

A situation in which the formationshear-wavevelocity varies azimuthally around the borehole, because unequal horizontal stresses in the formation have caused azimuthal variations in the stress concentrations around the borehole. These stress concentrations change the shear-wave speeds in the region surrounding the well from those in the far field, such that a characteristic response is observed in the dispersion of the dipole flexural mode.

The azimuth of the intersection of a plane, such as a dipping bed, with a horizontal surface.

A fault whose primary movement is in the strike direction (usually horizontal). This type of fault is usually caused by continents or tectonic plates moving laterally with respect to each other, as is happening in California today. The San Andreas fault is a strike-slip fault along which the western side is moving north relative to the eastern side.

A type of fault whose surface is typically vertical or nearly so. The motion along a strike-slip fault is parallel to the strike of the fault surface, and the fault blocks move sideways past each other. A strike-slip fault in which the block across the fault moves to the right is described as a dextral strike-slip fault. If it moves left, the relative motion is described as sinistral. Local deformation near bends in strike-slip faults can produce pull-apart basins and grabens. Flower structures are another by-product of strike-slip faults. A wrench fault is a type of strike-slip fault in which the fault surface is nearly vertical.

The sealing element used in coiled tubing or snubbing stripper systems. The stripper element is a consumable product and generally should be replaced for each operation. Coiled tubing elements can be replaced with the tubing in place, enabling a worn or leaking element to be replaced during an operation. Snubbing stripper rubbers are of single-piece construction and cannot be changed with the work string in place.

The running or retrieving of a tubing string in a well under pressure, using a stripper or similar sealing device to contain well pressure and fluids. Coiled tubing, snubbing and some specialized workoverrig operations can be conducted on live wells using special sealing equipment to safely and reliably contain wellbore pressure and fluids. Well-intervention systems designed to operate on live wells incorporate a secondary or contingency means of isolating wellbore pressure.

A ram-type blowout preventer used to provide primary pressure control in high-pressure snubbing operations. Stripping rams are used when the wellhead pressure is higher than the limitations of a stripper bowl.

In a sucker-rod pump, one complete round of the polished rod (surface stroke). On each stroke, a fixed volume of liquid is lifted. This volume is related to the cross-sectional area of the pump and the length of the stroke.The stroke length at the subsurface sucker-rod pump usually differs from the surface stroke because of the stretching in the upstroke and the rebounding in the downstroke.

The number of strokes the polished rod completes in one minute. This determines the rate at which liquid is pumped. If the number of strokes per minute is increased, the pump rate is also increased. This term is also referred to as stroke speed.

An examination of a geological scenario to understand the geometry and spatial arrangement of rocks. The structure or deformation can include many mechanisms, such as folding, faulting and fracturing. Structure can usually be interpreted in terms of the deformation of the crust of the Earth as continents and tectonic plates move and collide.

A particular type of shale distribution in which the shale exists as grains within a rock framework, in contrast to dispersed shale and laminar shale. The term also refers to a formationmodel or saturation equation based on this distribution.

A variety of sealed geologicstructure capable of retaining hydrocarbons, such as a fault or a fold. Stratigraphic traps form where changes in rock type can retain hydrocarbons.

A geological feature produced by deformation of the Earth's crust, such as a fold or a fault; a feature within a rock, such as a fracture or bedding surface; or, more generally, the spatial arrangement of rocks.

A type of subsurface map whose contours represent the elevation of a particular formation, reservoir or geologic marker in space, such that folds, faults and other geologic structures are clearly displayed. Its appearance is similar to that of a topographic map, but a topographic map displays elevations of the Earth's surface and a structure map displays the elevation of a particular rocklayer, generally beneath the surface.

Referring to the varying degrees of inability to move or remove the drillstring from the wellbore. At one extreme, it might be possible to rotate the pipe or lower it back into the wellbore, or it might refer to an inability to move the drillstring vertically in the well, though rotation might be possible. At the other extreme, it reflects the inability to move the drillstring in any manner. Usually, even if the stuck condition starts with the possibility of limited pipe rotation or vertical movement, it will degrade to the inability to move the pipe at all.

The portion of the drillstring that cannot be rotated or moved vertically.

Wave-like or tooth-like, serrated, interlocking surfaces most commonly seen in carbonate and quartz-rich rocks that contain concentrated insoluble residue such as clay minerals and iron oxides. Stylolites are thought to form by pressure solution, a dissolution process that reduces pore space under pressure during diagenesis.

The compound C6H5-HC=CH2, also known as styrolene, cinnamene and phenethylene. The phenyl radical, C6H5-, replaces one of the hydrogen atoms on ethylene. Styrene polymers are analogous to vinyl polymers in structure except that phenyl radicals replace the corresponding H atom. (Due to larger size of the phenyl radical as compared to the H atom, not all corresponding polymers are possible.) A phenyl radical has the benzene ring structure-missing one H-with alternating double bonds between adjacent carbons. It is an aromatic group that is nonionic.

Slang for substructure, which is the part of the rig that supports the derrick, rig floor and associated equipment.

A plate tectonic process in which one lithospheric plate descends beneath another into the asthenosphere during a collision at a convergent plate margin. Because of the relatively higher density of oceanic lithosphere, it will typically descend beneath the lighter continental lithosphere during a collision. In a collision of plates of continental lithosphere, the density of the two plates is so similar that neither tends to be subducted and mountains form. As a subducted plate descends into the asthenosphere, Earthquakes can occur, especially in the Wadati-Benioff zone, but, if the plate descends deeply into the mantle, it will eventually be heated to the point of melting. Volcanoes can form above a descending plate.

A particular type of floating vessel, usually used as a mobile offshore drilling unit (MODU), that is supported primarily on large pontoon-like structures submerged below the seasurface. The operating decks are elevated 100 or more feet [30 m] above the pontoons on large steel columns. Once on the desired location, this type of structure is slowly flooded until it rests on the seafloor. After the well is completed, the water is pumped out of the buoyancy tanks, the vessel refloated and towed to the next location. Submersibles, as they are known informally, operate in relatively shallow water, since they must actually rest on the seafloor.

An exploration and production play type in which prospects exist below salt layers. Until relatively recently, many explorationists did not seek prospects below salt because seismic data had been of poor quality below salt (i.e., it was not possible to map traps accurately) or because they believed that reservoir-quality rock or hydrocarbons did not exist below salt layers. Advances in seismic processing and compelling drilling results from exploration wells encouraged companies to generate and drill prospects below salt layers, salt sheets and other previously disregarded potential traps. The offshore Gulf of Mexico contains numerous subsalt-producing fields, and similar areas are being explored internationally.

A well in which the wellhead, Christmas tree and production-control equipment is located on the seabed.

The relative sinking of the Earth's surface. Plate tectonic activity (particularly extension of the crust, which promotes thinning and sinking), sediment loading and removal of fluid from reservoirs are processes by which the crust can be depressed. Subsidence can produce areas in which sediments accumulate and, ultimately, form sedimentary basins.

Any pressure measured in a well below the surface.

A safety device installed in the upper wellbore to provide emergency closure of the producing conduits in the event of an emergency. Two types of subsurface safety valve are available: surface-controlled and subsurface controlled. In each case, the safety-valve system is designed to be fail-safe, so that the wellbore is isolated in the event of any system failure or damage to the surface production-control facilities.

A downhole safety valve designed to close automatically in an emergency situation. There are two basic operating mechanisms: valves operated by an increase in fluid flow and valves operated by a decrease in ambient pressure. Given the difficulties in testing or confirming the efficiency of these valves, surface-controlled safety valves are much more common.

A steel rod that is used to make up the mechanical assembly between the surface and downhole components of a rod pumping system. Sucker rods are 25 to 30 ft [7 to 9 m] long and threaded at each end to enable the downhole components to be run and retrieved easily.

(noun) A positive displacement downhole pump, driven by a surface beam pumping unit through a string of sucker rods, consisting of a standing valve at the bottom, a travelling valve on the plunger, and a close-fitting barrel. The reciprocating motion of the plunger alternately fills and displaces fluid from the pump chamber to lift oil to the surface.

A mudtank, usually made of steel, connected to the intake of the main rig pumping system. The connection is commonly formed with a centrifugal pump charging the main rig pumps to increase efficiency. Since it is the last tank in the surface mud system, the suction pit should contain the cleanest and best-conditioned mud on location. It is also the most representative of mud characteristics in the hole, except for temperature.

A common anaerobic bacterium, commonly abbreviated SRB, that can convert sulfate ions, SO4-2, into S-2 and HS-, with the concomitant oxidation of a carbon source. The lignite, lignin, tannins, cellulose, starches and fatty acids found in many mud systems are carbon food sources for SRB. Where mud is stored, precautions should always be taken when handling or reconditioning water muds containing lignosulfonates, gypsum (sulfate sources) and starches, cellulose, xanthan gum and lignite (food sources). These muds can harbor SRB and can have high sulfide accumulations. Mud filtrate should be tested with the Garrett Gas Train to determine sulfide concentration in a stored mud, followed by treatments with caustic soda to raise pH and zinc-based scavengers to remove sulfides as ZnS. Before storage of mud, treatment with a bactericide can inhibit SRB growth. Also, circulating mud from time to time, with air entrainment, can retard development of anaerobic conditions.Anaerobic bacteria can convert the sulfate or sulfite present in water handling facilities to hydrogen sulfide [H2S]. This by-product, combined with iron, can form iron sulfide, a scale that is very difficult to remove. SRB occur naturally in surface waters, including seawater. Bacteria accumulation can lead to pitting of steel, and the buildup of H2S increases the corrosiveness of the water, thus increasing the possibility of hydrogen blistering or sulfide stresscracking.

The ability of set cement to resist deterioration in the presence of sulfate ions.

A cement in which the amount of tricalcium aluminate is controlled as specified by API Specification 10A.

A common anaerobic bacterium, commonly abbreviated SRB, that can convert sulfate ions, SO4-2, into S-2 and HS-, with the concomitant oxidation of a carbon source. The lignite, lignin, tannins, cellulose, starches and fatty acids found in many mud systems are carbon food sources for SRB. Where mud is stored, precautions should always be taken when handling or reconditioning water muds containing lignosulfonates, gypsum (sulfate sources) and starches, cellulose, xanthan gum and lignite (food sources). These muds can harbor SRB and can have high sulfide accumulations. Mud filtrate should be tested with the Garrett Gas Train to determine sulfide concentration in a stored mud, followed by treatments with caustic soda to raise pH and zinc-based scavengers to remove sulfides as ZnS. Before storage of mud, treatment with a bactericide can inhibit SRB growth. Also, circulating mud from time to time, with air entrainment, can retard development of anaerobic conditions.Anaerobic bacteria can convert the sulfate or sulfite present in water handling facilities to hydrogen sulfide [H2S]. This by-product, combined with iron, can form iron sulfide, a scale that is very difficult to remove. SRB occur naturally in surface waters, including seawater. Bacteria accumulation can lead to pitting of steel, and the buildup of H2S increases the corrosiveness of the water, thus increasing the possibility of hydrogen blistering or sulfide stress cracking.

A cement in which the amount of tricalcium aluminate is controlled as specified by API Specification 10A.

A compound of sulfur that contains the S-2 ion. H2S is the gaseous and highly toxic molecular form often found in the subsurface. Sulfide, S-2, and bisulfide, HS-, are the corresponding ionic forms. Sulfides can be generated from soluble iron sulfide minerals or from sulfate-reducing bacteria. The term "active sulfide" is used to denote compounds that revert to H2S gas when acidified with 2-molar citric acid solution, as opposed to inert sulfides, which are stable. Active sulfides include calcium sulfide and bisulfide formed when H2S reacts with lime in an oil mud. Their accumulation constitutes a safety concern at the rig because of the risk of reverting to H2S gas should an acidic influx occur. They may be converted to inert sulfides by adding zinc oxide.Reference:Garrett RL, Carlton LA and Denekas MO: "Methods for Field Monitoring of Oil-Based Drilling Fluids for Hydrogen Sulfide and Water Intrusions," SPE Drilling Engineering 3, no.3 (September 1988): 296-302.

A chemical that removes all three soluble sulfide species, H2S, S-2 and HS-, and forms a product that is nonhazardous and noncorrosive. Zinc compounds are commonly used to precipitate ZnS and decrease the concentration of all three sulfides that are in equilibrium in a solution to a very low concentration. For water mud, zinc basic carbonate, and, for oil mud, zinc oxide, are recognized to be effective sulfide scavengers. Oxidation of sulfides to form other types of sulfur compounds will remove sulfides from a mud, but slowly and with less certainty.

An asphaltic mud additive that has been reacted with sulfite to add anionic sulfonate groups to the complex molecular structure. Sulfonate groups make an additive water dispersible, depending on the extent of sulfonation. Such an additive is used to stabilize wellbores and as a filter-cake additive for water- and oil-base muds.

A copolymer of polystyrene (containing sulfonate groups on the ring) and anhydrous maleic acid (a di-hydroxy acid). The sulfonated ring-structure polymer component is anionic and usually low to moderate in chain length and molecular weight. As such, with negative groups on the structure (amount of negativity depending on degree of sulfonation), it is used as a claydeflocculant for bentonite-based water mud. It is especially stable to temperature up to around 400°F [204°C], and often used in high-density muds to stabilize rheology. Lignosulfonate is used for this purpose up to about 300°F [149°C] and then SSMA polymeric deflocculant is often phased into the mud system for drilling deeper and hotter zones.

Light crude oil containing sulfur compounds such as hydrogen sulfide.

A technique for measuring the effective porosity of a core sample by summing the volumes of the fluids recovered from it. The volumes of the gas, oil and water in the sample usually are determined by the retort method, which also determines the bulk volume. The porosity is then the ratio of the total fluid volume to the bulk volume.

The velocity of fluid moving through a pipe, defined as the volumetric flow rate of that fluid divided by the cross-sectional area. In monophasic flow, it is equal to the mean velocity of the fluid. In multiphase flow, it is not a physically real velocity but is a convenient parameter for analysis.

A mathematical technique based on the property that solutions to linear partial equations can be added to provide yet another solution. This permits constructions of mathematical solutions to situations with complex boundary conditions, especially drawdown and buildup tests, and in settings where flow rates change with time.

A mathematical computation that accounts for production from multiple wells. Image wells are used to model the effect of impermeable barriers.

A mathematical computation that accounts for the flow-rate history in analytical models generated to match with pressure-transient test data. The pressure-derivative response can be distorted in late-time data by the effects of superposition in time, except in data acquired from an initial drawdown. Analysts must be aware of this limitation in diagnosing reservoir features from the pressure-derivative response.

In offshore operations, any barge, boat or ship that brings materials and personnel to and from the rigsite.

In seismic acquisition and processing, the attenuation of amplitudes to reduce the effects of noise or to prevent overload from the high energy of first breaks.

A large-diameter, relatively low-pressure pipe string set in shallow yet competent formations for several reasons. First, the surface casing protects fresh-water aquifers onshore. Second, the surface casing provides minimal pressure integrity, and thus enables a diverter or perhaps even a blowout preventer (BOP) to be attached to the top of the surface casing string after it is successfully cemented in place. Third, the surface casing provides structural strength so that the remaining casing strings may be suspended at the top and inside of the surface casing.

Ownership of the right or interest to exploit the surface of the land. Some landowners only have rights to the surface of their tract, while the government or other entity owns rights to any production obtained beneath that tract.

The pressure measured at or near the surface in a well. This measurement of pressure is usually performed by inserting a gauge into the production string just below the shut-in valve, and is also referred to as tubing-head pressure.

A well shut in at the surface, rather than downhole. Most transient well tests are conducted in this manner for convenience.

Surface free energy that exists between a liquid and air. Surface tension can be observed as a curved meniscus in a small tube of the liquid. This energy barrier prevents a liquid (such as water) from spontaneously mixing with air to form a foam. To make a foam, as used for a drilling fluid, the liquid's surface tension must be lowered by adding a third component (a foamer) that accumulates at the interface. Foam preparation usually requires mechanical energy to break up the bulk liquid into thin films around each gas bubble.

A wave that propagates at the interface between two media as opposed to through a medium. A surface wave can travel at the interface between the Earth and air, or the Earth and water. Love waves and Rayleigh waves are surface waves.

A downhole safety valve that is operated from surface facilities through a control line strapped to the external surface of the production tubing. Two basic types of SCSSV are common: wireline retrievable, whereby the principal safety-valve components can be run and retrieved on slickline, and tubing retrievable, in which the entire safety-valve assembly is installed with the tubing string. The control system operates in a fail-safe mode, with hydraulic control pressure used to hold open a ball or flapper assembly that will close if the control pressure is lost.

A chemical that preferentially adsorbs at an interface, lowering the surface tension or interfacial tension between fluids or between a fluid and a solid. This term encompasses a multitude of materials that function as emulsifiers, dispersants, oil-wetters, water-wetters, foamers and defoamers. The type of surfactant behavior depends on the structural groups on the molecule (or mixture of molecules). Hydrophile-lipophile balance (HLB) number helps define the function that a molecular group will perform.

An enhanced oil recovery process in which a small amount of surfactant is added to an aqueous fluid injected to sweep the reservoir. The presence of surfactant reduces the interfacial tension between the oil and water phases and also alters the wettability of the reservoir rock to improve oil recovery.

An enhanced oil recovery process in which alternating slugs of a surfactant solution and gas are injected into a reservoir. The injected surfactant and gas mix and generate foam that reduces the gas mobility, especially in previously swept or high-permeability regions of the reservoir. This improves sweep efficiency by mitigating gravity override and viscous fingering during gas injection. The presence of the surfactant in the injectant can also improve recovery by reducing interfacial tension between reservoir oil and the injection phases.

A vessel placed in a flowline through which liquids or gases are flowed to neutralize sudden pressure surges.

A formationlayer above or below the layer being measured by a logging tool. The term is used in particular to describe the adjacent layers above or below a horizontal well. In a vertical well, the term shoulder bed is more common. The term adjacent bed is used in both cases.

To record a measurement versus depth or time, or both, of one or more physical quantities in or around a well. In early years, the term was used more often than log.

Dispersed particles in a slurry that can be separated by filtration and are not dissolved. In the water, oil and solids test (retort test), the retort solids are divided into two types, dissolved and suspended solids. Suspended solids are the particulates. In calculating solids content of water- or oil-base muds, suspended solids are divided into high-gravity and low-gravity solids (HGS and LGS). LGS are sometimes further subdivided into active (clay) and inactive solids.

To unload liquids from the production tubing to initiate flow from the reservoir. A swabbing tool string incorporates a weighted bar and swab cup assembly that are run in the wellbore on heavy wireline. When the assembly is retrieved, the specially shaped swab cups expand to seal against the tubing wall and carry the liquids from the wellbore.

The topmost valve on a Christmas tree that provides vertical access to the wellbore.

A threaded adapter used to connect a circulating line to a casing or tubing string. A casing or tubing swage generally is required as a contingency option to enable any obstruction or fill to be circulated clear during the running process.

A downhole tool, generally run on slickline, that is used to open collapsed or damaged tubing. Configured with a tapered profile, the swaging tool acts as a circular wedge to force the tubing wall out as it is driven through a collapsed or restricted area. A jar is included in the tool string to provide the impact force necessary to push the swaging tool through the tubing restriction.

A wetland depositional environment in which water is present either permanently or intermittently and in which trees and large woody plants can grow but peat does not form. Swamps can contain considerable quantities of organic matter.

A measure of the effectiveness of an enhanced oil recovery process that depends on the volume of the reservoir contacted by the injected fluid. The volumetric sweep efficiency is an overall result that depends on the injection pattern selected, off-pattern wells, fractures in the reservoir, position of gas-oil and oil/water contacts, reservoir thickness, permeability and areal and vertical heterogeneity, mobility ratio, density difference between the displacing and the displaced fluid, and flow rate.

A relatively small volume of viscous fluid, typically a carrier gel, that is circulated to sweep, or remove, debris or residual fluids from the circulation system.

Pertaining to crude oil or natural gas lacking appreciable amounts of sulfur or sulfur compounds.

The corrosion caused by contact with carbon dioxide [CO2] dissolved in water.In gas condensate wells, sweet corrosion takes the form of deep pitting inside the tubing walls. The pitting is produced only at depths where the acidic gas contacts condensed water droplets.

Crude oil containing low levels of sulfur compounds, especially hydrogen sulfide [H2S]. The facilities and equipment to handle sweet crude are significantly simpler than those required for other potentially corrosive types of crude oil.

Oil containing small amounts of hydrogen sulfide and carbon dioxide.

Natural gas that contains small amounts of hydrogen sulfide and carbon dioxide.

Colloquial expression for a target location or area within a play or a reservoir that represents the best production or potential production. Geoscientists and engineers attempt to mapsweet spots enable wellbores to be placed in the most productive areas of the reservoir. Sweet spots in shale reservoirs may be defined by source-rock richness or thickness, by natural fractures, or by other factors, using geological data such as core analysis, well log data, or seismic data.

A process used to remove hydrogen sulfide [H2S] and carbon dioxide [CO2] from a gas stream. These components are removed because they can form acidic solutions when they contact water, which will cause corrosion problems in gas pipelines.In a sweetening process, different types of ethanolamine can be used, including monoethanolamine (MEA), diethanolamine (DEA), diglycolamine (DGA) and methyldiethanolamine (MDEA). Hydrogen sulfide and carbon dioxide are absorbed by the ethanolamine and sweet gas leaves at the top of the absorber.The ethanolamine is heated and acid gas (hydrogen sulfide and carbon dioxide gases) and water vapor are obtained. The water is removed while the acid gas can be flared or further treated in a sulfur recovery unit to separate out elemental sulfur. Finally, the lean ethanolamine is returned to the absorber.

An isolation device that relies on elastomers to expand and form an annular seal when immersed in certain wellbore fluids. The elastomers used in these packers are either oil- or water-sensitive. Their expansion rates and pressure ratings are affected by a variety of factors. Oil-activated elastomers, which work on the principle of absorption and dissolution, are affected by fluid temperature as well as the concentration and specific gravity of hydrocarbons in a fluid. Water-activated elastomers are typically affected by water temperature and salinity. This type of elastomer works on the principle of osmosis, which allows movement of water particles across a semi-permeable membrane based on salinity differences in the water on either side of the membrane.

A mechanical device that suspends the weight of the drillstring. It is designed to allow rotation of the drillstring beneath it conveying high volumes of high-pressuredrilling mud between the rig's circulation system and the drillstring.

The slang abbreviation for synthetic. The term can be confusing to the uninitiated, so its use is avoided.

Basin- or trough-shaped fold in rock in which rock layers are downwardly convex. The youngest rock layers form the core of the fold and outward from the core progressively older rocks occur. Synclines typically do not trap hydrocarbons because fluids tend to leak up the limbs of the fold. An anticline is the opposite type of fold, having upwardly-convex layers with old rocks in the core.

Any of a number of fluids (liquids) manufactured from starting products of known composition and purity. Popular fluid types include several olefin oligomers of ethylene. Esters made from vegetable fatty acid and alcohol were among the first such fluids. Ethers and polyethers, made from alcohols and polyalcohols, have been used, along with paraffinic hydrocarbons and linear alkyl benzenes. Mixtures of these fluids are also used to make synthetic-base muds.

Nonaqueous, water-internal (invert) emulsion muds in which the external phase is a synthetic fluid rather than an oil. This and other more minor changes in formulations have made synthetic fluids in muds more environmentally acceptable for offshore use. Synthetic muds are popular in most offshore drilling areas, despite high initial mud costs, because of their environmental acceptance and approval to dispose of cuttings into the water. "Oil mud" should not be used to describe synthetic-base muds.

A type of minor fault whose sense of displacement is similar to its associated major fault. Antithetic-synthetic fault sets are typical in areas of normal faulting.

A gas obtained by heating coal or refining heavy hydrocarbons. Synthetic natural gas is abbreviated SNG.

The result of one of many forms of forward modeling to predict the seismic response of the Earth. A more narrow definition used by seismic interpreters is that a synthetic seismogram, commonly called a synthetic, is a direct one-dimensional model of acoustic energy traveling through the layers of the Earth. The synthetic seismogram is generated by convolving the reflectivity derived from digitized acoustic and density logs with the wavelet derived from seismic data. By comparing marker beds or other correlation points picked on well logs with major reflections on the seismic section, interpretations of the data can be improved. The quality of the match between a synthetic seismogram depends on well log quality, seismic data processing quality, and the ability to extract a representative wavelet from seismic data, among other factors. The acoustic log is generally calibrated with check-shot or vertical seismic profile (VSP) first-arrival information before combining with the density log to produce acoustic impedance.

The seismic traces at a wellbore generated from wireline log data. Synthetic seismograms are generated by calculating reflection coefficients from the sonic and density logs and then applying an ideal or real wavelet to the reflections to obtain the seismic "wiggle" traces. Synthetic seismograms are usually generated to compare with the actual seismic data and identify reflectors with layers and formations already known in the wellbore.

Any of a number of fluids (liquids) manufactured from starting products of known composition and purity. Popular fluid types include several olefin oligomers of ethylene. Esters made from vegetable fatty acid and alcohol were among the first such fluids. Ethers and polyethers, made from alcohols and polyalcohols, have been used, along with paraffinic hydrocarbons and linear alkyl benzenes. Mixtures of these fluids are also used to make synthetic-base muds.

Nonaqueous, water-internal (invert) emulsion muds in which the external phase is a synthetic fluid rather than an oil. This and other more minor changes in formulations have made synthetic fluids in muds more environmentally acceptable for offshore use. Synthetic muds are popular in most offshore drilling areas, despite high initial mud costs, because of their environmental acceptance and approval to dispose of cuttings into the water. "Oil mud" should not be used to describe synthetic-base muds.

Ratio of the volume percent synthetic fluid to the volume percent brine in a synthetic mud, where each is expressed as a percent of the total liquid in the mud. The SBR is calculated in an analogous way to the oil/brine ratio using data from the retort test.

Ratio of the volume percent synthetic fluid to the volume percent water in a synthetic-base mud, where each is a percent of the total liquid in the mud. The SWR is calculated in an analogous way to the oil/brine ratio using data from the retort test.

A reproducible inaccuracy of measurement introduced by either faulty design, failing equipment, inadequate calibration, inferior procedure or a change in the measurement environment.

Subdivisions of sequences that consist of discrete depositional units that differ in geometry from other systems tracts and have distinct boundaries on seismic data. Different systems tracts are considered to represent different phases of eustatic changes. A lowstand systems tract develops during times of relatively low sea level; a highstand systems tract at times of high sea level; and a transgressive systems tract at times of changing sea level.