Oil and Gas Terms Beginning with “D”

An individual trained in the science and art of intentionally drilling a well along a predetermined path in three-dimensional space, usually involving deviating the well from vertical and directing it in a specific compass direction or heading. The directional driller considers such parameters as rotary speed, weight on bit, control drilling and when to stop drilling and take surveys of the wellpath, and works closely with the toolpusher.

A treating system used to remove hydrogen sulfide [H2S], carbon dioxide [CO2] and carbonyl sulfide from a gas stream. The acid gases are absorbed by the diethanolamine (DEA), and sweet gas leaves at the top of the absorber.

The difference in the arrival times or traveltimes of a reflected wave, measured by receivers at two different offset locations, that is produced when reflectors dip. Seismicprocessing compensates for DMO.

A seismicprofile recorded specifically to study the lower crust, the Mohorovicic discontinuity and the mantle of the Earth, typically using refraction methods. Most standard seismic reflection profiles record only a small fraction (typically, on the order of 10 km [6 miles]) of the Earth's crust, which is 5 to 75 km [3 to 45 miles] thick.

Well tests conducted with the drillstring still in the hole. Often referred to as DST, these tests are usually conducted with a downhole shut-in tool that allows the well to be opened and closed at the bottom of the hole with a surface-actuated valve. One or more pressure gauges are customarily mounted into the DST tool and are read and interpreted after the test is completed. The tool includes a surface-actuated packer that can isolate the formation from the annulus between the drillstring and the casing, thereby forcing any produced fluids to enter only the drillstring. By closing in the well at the bottom, afterflow is minimized and analysis is simplified, especially for formations with low flow rates. The drillstring is sometimes filled with an inert gas, usually nitrogen, for these tests. With low-permeability formations, or where the production is mostly water and the formation pressure is too low to lift water to the surface, surface production may never be observed. In these cases, the volume of fluids produced into the drillstring is calculated and an analysis can be made without obtaining surface production. Occasionally, operators may wish to avoid surface production entirely for safety or environmental reasons, and produce only that amount that can be contained in the drillstring. This is accomplished by closing the surface valve when the bottomhole valve is opened. These tests are called closed-chamber tests.Drillstem tests are typically performed on exploration wells, and are often the key to determining whether a well has found a commercial hydrocarbonreservoir. The formation often is not cased prior to these tests, and the contents of the reservoir are frequently unknown at this point, so obtaining fluid samples is usually a major consideration. Also, pressure is at its highest point, and the reservoir fluids may contain hydrogen sulfide, so these tests can carry considerable risk for rig personnel.The most common test sequence consists of a short flow period, perhaps five or ten minutes, followed by a buildup period of about an hour that is used to determine initial reservoir pressure. This is followed by a flow period of 4 to 24 hours to establish stable flow to the surface, if possible, and followed by the final shut-in or buildup test that is used to determine permeability thickness and flow potential

The characteristic plot of pressure versus time obtained from the mechanical recording of pressure gauges in a DST tool. Pressure rises as the tool is lowered into the hole and the hydrostatic head above the tool increases. The pressure stabilizes when the tool reaches bottom and then moves when the packer is set. Pressure drops immediately upon opening of the downhole valve to match the pressure in the drillstring, and then rises as fluid flows into the string. When the downhole valve is closed, the pressure buildup period begins immediately and continues until the valve is closed again.

Units of atm, cm3/s, cp and D, as originally used by Darcy in flow experiments.

The drilling line from the crown block sheave to the anchor, so called because it does not move.

A method for the measurement of fluid saturations in a core sample by distillation extraction. The water in the sample is vaporized by boiling solvent, then condensed and collected in a calibrated trap. This gives the volume of water in the sample. The solvent is also condensed, then flows back over the sample and extracts the oil. Extraction continues for a minimum of two days until the extracted solvent is clean or the sample shows no more fluorescence. The weight of the sample is measured before and after extraction. Then the volume of oil is calculated from the loss in weight of the sample minus the weight of the water removed from it. Saturations are calculated from the volumes.

Removable, hard-steel, serrated pieces that fit into the jaws of the tongs and firmly grip the body of the drill pipe, drill collars, or casing.

The power supplied to a drilling rig by diesel engines driving electric generators.

Tools utilized in achieving directional drills, including whip stocks, BHA configurations, three-dimensional measuring devices, mud motors, and specialized drill bits.

An equation used to calculate the interval velocity within a series of flat, parallel layers, named for American geophysicist C. Hewitt Dix (1905 to 1984). Sheriff (1991) cautions that the equation is misused in situations that do not match Dix's assumptions. The equation is as follows:

A type of gas detector tube that quantitatively measures a gas that is passed through the tube by the length of the stain it generates chemically in the tube. Drdger tubes are used in Garrett Gas Train tests for sulfides and carbonates.

Heavy, thick-walled tubes used between the drill pipe and the bit in the drill string, used to stiffen the drilling assembly and put weight on the bit.

What Is Drill Pipe? Drill pipe is a hollow seamless steel tubular that forms the primary structural and hydraulic connection between the surface rotary system and the downhole drill bit assembly, transmitting rotary torque and drill string weight to the bit while simultaneously circulating drilling fluid downward through its bore and returning cuttings-laden fluid up the annulus to surface. A typical onshore well string contains hundreds of individual drill pipe joints, each threaded together by hardened steel tool joints at their ends. Key Takeaways Drill pipe is manufactured and tested to API Specification 5DP (ISO 11961), which defines outside diameter, wall thickness, steel grade, length range, and inspection requirements for all drill pipe products used in petroleum well operations worldwide. The four principal steel grades are E-75, X-95, G-105, and S-135, designated by their minimum yield strength in thousands of pounds per square inch (ksi); S-135 drill pipe is standard in extended-reach drilling (ERD) and deep high-pressure/high-temperature (HPHT) wells where torsional and tensile demands are most severe. Tool joints, the larger-diameter threaded connectors at each end of a drill pipe joint, are manufactured from heat-treated alloy steel and are the primary load-bearing component in the drill string, carrying torsion, tension, bending, and internal pressure simultaneously. Drill pipe must always be maintained in tension above the neutral point in the drill string to prevent sinusoidal and helical buckling, which causes accelerated fatigue damage, wear on the borehole wall, and potential twist-off failures. Extended-reach drilling wells in the Montney Formation in Alberta and British Columbia routinely deploy 5-1/2-inch (139.7 mm) S-135 drill pipe strings of 5,000 to 7,000 metres (16,404 to 22,966 feet) measured depth, with surface torques exceeding 40,000 to 60,000 foot-pounds (54,200 to 81,300 Newton-metres). How Drill Pipe Is Manufactured and Assembled Drill pipe is produced from seamless steel tube manufactured by the rotary piercing (Mannesmann) or extrusion process, ensuring the absence of a longitudinal weld seam that could serve as a fatigue crack initiation site under the cyclic bending loads encountered during directional drilling. The tube body is hot-formed, heat-treated by quench and temper to achieve the specified yield strength grade, and then inspected by ultrasonic testing (UT) for wall thickness, laminations, and longitudinal defects. The pipe body undergoes an upsetting operation at both ends to increase the wall thickness locally, forming either an internal upset (IU), external upset (EU), or internal-external upset (IEU) configuration. Upsetting displaces metal to reinforce the area beneath the tool joint, creating a transition zone that mitigates the stress concentration at the thread root of the tool joint box connection. Tool joints are friction-welded to the upset ends of the pipe body using an inertia or continuous-drive friction welding process that produces a solid-state, metallurgically clean weld with a flash that is subsequently machined and inspected. The pin (male thread) and box (female thread) of the tool joint are machined with a tapered National Standard thread form, designated by API thread type. Common API thread designations include NC (Numbered Connection), Regular (REG), and Full Hole (FH). For example, an NC50 connection on a 4-1/2-inch (114.3 mm) drill pipe features a 50/8-inch (6.25-inch) pitch diameter at the gauge point. Premium proprietary connections such as Grant Prideco's HT series and Vallourec's VAM system offer improved cross-hole flow area, higher make-up torque capacity, and enhanced fatigue resistance for demanding applications. Tool joint outer diameters are substantially larger than the pipe body to provide adequate torsional strength and connection face bearing area; the inner diameter of the box governs the hydraulic flow area through the tool joint, a critical parameter in measurement-while-drilling (MWD) and logging-while-drilling (LWD) strings where bore restriction affects mud motor and pulser performance. Individual drill pipe joints are manufactured in three API length ranges: Range 1 (18 to 22 feet or 5.5 to 6.7 metres), Range 2 (27 to 30 feet or 8.2 to 9.1 metres, colloquially "singles"), and Range 3 (38 to 45 feet or 11.6 to 13.7 metres, commonly called "doubles" or "thribbles" when the rig assembles them into stands). The vast majority of onshore drilling uses Range 2 drill pipe, while offshore deepwater and ultra-deepwater operations routinely use Range 3 to reduce the number of connections and the associated connection make-up and break-out time at greater measured depths. Drill Pipe Grades and Strength Properties API Specification 5DP establishes four principal strength grades for drill pipe. Grade E-75 has a minimum yield strength of 75,000 psi (517 MPa) and a minimum tensile strength of 100,000 psi (690 MPa). E-75 is adequate for shallow, vertical wells in benign conditions and remains in widespread use for surface hole sections where tensile loads are modest. Grade X-95 (95,000 psi minimum yield, 660 MPa) offers a moderate strength increase at slightly higher cost and is often selected for medium-depth wells. Grade G-105 (105,000 psi minimum yield, 724 MPa) is a common choice for horizontal Permian Basin and Eagle Ford shale wells, providing adequate torque and tension capacity for 3,000-metre (9,843-foot) laterals with 5-inch (127 mm) pipe. Grade S-135 (135,000 psi minimum yield, 931 MPa) is the premium high-strength grade used in ERD wells, HPHT wells, and ultra-deepwater strings where the combined demands of high torque, high hookload, and high internal pressure approach the limits of lower-grade pipe. For extremely demanding applications such as deep geothermal wells or offshore wells with sour gas exposure, non-API Grade V-150 (150,000 psi minimum yield, 1,034 MPa) and corrosion-resistant alloy (CRA) overlay pipe products are available, though V-150 must be evaluated carefully for sulfide stress cracking (SSC) susceptibility in H2S environments under NACE MR0175 (ISO 15156). The torsional yield strength of drill pipe is a primary design constraint in high-angle and horizontal wells, where rotating the string against borehole wall friction generates torque that accumulates from the bit face to surface. For 5-1/2-inch S-135 drill pipe with a wall thickness of 0.415 inches (10.5 mm), the API torsional yield torque is approximately 65,000 foot-pounds (88,100 Newton-metres). In an ERD Montney well with a 7,000-metre (22,966-foot) measured depth and a 90° inclination through the lateral, surface torque readings of 35,000 to 55,000 foot-pounds (47,500 to 74,600 Newton-metres) are not uncommon, leaving relatively limited torque margin. Torque management techniques including rotary steerable system (RSS) use, lubricant-treated drilling fluid, casing reamer shoes, and optimized tool joint hardbanding directly affect torque margins and the selection of pipe grade. Tensile design for drill pipe in deep wells must account for the buoyed weight of the drill string below the hook, the additional tensile load from overpull required to free a stuck pipe, and dynamic loads from hoisting acceleration. For a 6,000-metre (19,685-foot) deep well using 5-inch G-105 drill pipe with a nominal weight of 19.50 lb/ft (29.0 kg/m), the air weight of the drill pipe string alone approaches 117,000 pounds (530 kN). Adding drill collars, HWDP, and a BHA increases the total hookload significantly and requires verification against the API-rated tensile yield strength of the pipe and tool joints, with a safety factor of at least 1.3 applied to the design working load.

A heavy duty wire rope hoisting line, reeved back and forth through the sheaves of the crown block and travelling block.

The unit of measurement to compare the relative intensity of acoustic or electrical signal, equal to one-tenth of a bel, named for American inventor Alexander Graham Bell (1847 to 1922). The logarithm of the ratio of the sound or signal to a standard provides the decibel measurement. The symbol for the unit is dB. Humans typically hear sounds in the range of 20 to 50 dB in conversation, and upwards of 90 dB when exposed to heavy machinery or aircraft.

Natural or induced production impairments that can develop in the reservoir, the near-wellbore area, the perforations, the gravel-pack completion or the production pipelines, such as the tubing. Natural damage occurs as produced reservoir fluids move through the reservoir, while induced damage is the result of external operations and fluids in the well, such as drilling, well completion, workover operations or stimulation treatments. Some induced damage triggers natural damage mechanisms.Natural damage includes phenomena such as finesmigration, clay swelling, scale formation, organic deposition, including paraffins or asphaltenes, and mixed organic and inorganic deposition. Induced damage includes plugging caused by foreign particles in the injected fluid, wettability changes, emulsions, precipitates or sludges caused by acid reactions, bacterial activity and water blocks.Wellbore cleanup or matrix stimulation treatments are two different operations that can remove natural or induced damage. Selecting the proper operation depends on the location and nature of the damage.

The area surrounding the wellbore that has been harmed by the drilling process, generally as a result of mud or cement-filtrateinvasion. Near-wellbore damage can significantly affect productivity and is typically easier to prevent than it is to cure. Although almost always present, a lightly damaged zone around the wellbore can be bypassed by perforation tunnels to create connecting conduits from the wellbore to the undamaged reservoirformation. More severe cases of damage may require a matrix-acidizing treatment to restore the natural permeability, or a hydraulic fracturing treatment to create a new high-conductivity flow path to the reservoir.

The opposition, slowing or prevention of oscillation, or decreasing vibration amplitude, as kinetic energy dissipates. Frictional damping can be important in the use of geophones for seismic surveys, since a vibrating instrument is difficult to read. Eddy currents can produce electromagnetic damping. The classic example of damping from physics is the slowing of a swinging pendulum unless it has a steady supply of energy.

A standard unit of measure of permeability. One darcy describes the permeability of a porous medium through which the passage of one cubic centimeter of fluid having one centipoise of viscosity flowing in one second under a pressure differential of one atmosphere where the porous medium has a cross-sectional area of one square centimeter and a length of one centimeter. A millidarcy (mD) is one thousandth of a darcy and is a commonly used unit for reservoir rocks.

A device dropped or pumped through a tubing or coiled tubing string to activate downhole equipment and tools.

The rate at which measurements are transmitted between logging tool and surface. In measurement-while-drilling (MWD), if the data rate is low in comparison with the drilling or tripping speed, the sampling interval or the amount of data transmitted must be reduced or else information will be lost. In wireline logging, the data rate can limit the logging speed or the number of tools in the tool string.

A depth reference point, typically established at the time the well is completed, against which subsequent depth measurements should be corrected or correlated.

A value added to reflection times of seismic data to compensate for the location of the geophone and source relative to the seismic datum.

The depth to which pressures are corrected to adjust for differences in elevations at which pressure measurements are made in different wells or at different times.

The daily cost to the operator of renting the drilling rig and the associated costs of personnel and routine supplies. This cost may or may not include fuel, and usually does not include capital goods, such as casing and wellheads, or special services, such as logging or cementing. In most of the world, the day rate represents roughly half of the cost of the well. Similarly, the total daily cost to drill a well (spread rate) is roughly double what the rig day-rate amount is.

Oil at sufficiently low pressure that it contains no dissolved gas or a relatively thick oil or residue that has lost its volatile components.

The unit of measurement to compare the relative intensity of acoustic or electrical signal, equal to one-tenth of a bel, named for American inventor Alexander Graham Bell (1847 to 1922). The logarithm of the ratio of the sound or signal to a standard provides the decibel measurement. The symbol for the unit is dB. Humans typically hear sounds in the range of 20 to 50 dB in conversation, and upwards of 90 dB when exposed to heavy machinery or aircraft.

A fault surface parallel to a mechanically weak horizon or layer, or parallel to bedding, that detaches or separates deformed rocks above from undeformed or differently deformed rocks below. Decollements, or decollement surfaces, are typical of regions of thrust faulting such as the Alps.

A mathematical operation that uses downhole flow-rate measurements to transform bottomhole pressure measurements distorted by variable rates to an interpretable transient. Deconvolution also can use surface rates to transform wellhead pressures to an interpretable form. Deconvolution has the advantage over convolution that it does not assume a particular model for the pressure-transient response. However, the simplest form of deconvolution often gives a noisy result, and more complex approaches may be computing intensive.

A particular type of induction log that was designed to read deep into the formation while maintaining reasonable vertical resolution. The deep induction log (ID) is based on the measurement of a 6FF40array and was combined with a medium induction array to form the dual induction tool. Versions built after 1968 had a small extra transmitter coil to reduce the borehole effect on the medium induction while changing the deep response very little. The midpoint of the ID integrated radial geometrical factor is at 62 in. [157 cm] radius for high resistivities, reducing to 45 in. [114 cm] at 1 ohm-m. ID receives very little signal from within 20 in. [50 cm] of the tool. The vertical resolution is about 8 ft [2.4 m] but varies with local conditions.

A seismic profile recorded specifically to study the lower crust, the Mohorovicic discontinuity and the mantle of the Earth, typically using refraction methods. Most standard seismic reflection profiles record only a small fraction (typically, on the order of 10 km [6 miles]) of the Earth's crust, which is 5 to 75 km [3 to 45 miles] thick.

A method of marineseismic acquisition in which a boat tows a receiver well below the surface of the water to get closer to features of interest or to reduce noise due to conditions of the sea. Deep tow devices are used for some side-scan sonar, gravity and magnetic surveys.

A perforating charge designed to provide a long perforation tunnel, such as may be required to bypass any near-wellbore damage. Specially designed deep-penetrating charges achieve this additional length while retaining a medium-sized entrance hole, an important consideration in high-shot density applications.

Exploration activity located in offshore areas where water depths exceed approximately 600 feet [200 m], the approximate water depth at the edge of the continental shelf. While deep-water reservoir targets are geologically similar to reservoirs drilled both in shallower present-day water depths as well as onshore, the logistics of producing hydrocarbons from reservoirs located below such water depths presents a considerable technical challenge.

(noun) A production logging tool that uses a deflector plate or vane positioned in the flow stream within a wellbore to measure the velocity and direction of fluid flow. The force exerted on the deflector by the flowing fluid is proportional to the flow rate, enabling downhole flow profiling across producing intervals.

A thinning agent used to reduce viscosity or prevent flocculation; incorrectly called a "dispersant." Most deflocculants are low-molecular weight anionic polymers that neutralize positive charges on clay edges. Examples include polyphosphates, lignosulfonates, quebracho and various water-soluble synthetic polymers.

A clay-based, water mud that has had its viscosity reduced with a chemical treatment; incorrectly, called a "dispersed" mud. The chemical used is a deflocculant, not a dispersant. A well-known and effective clay deflocculant is lignosulfonate. The mud, after being deflocculated, usually shows much improved filter-cake qualities with lower yield point and gel strengths. Filter-cake quality is improved because when clays are deflocculated, the platelets become detached from each other and can lie flat to form a thin, low-permeability filter cake. Lowering yield point and gel strength may not always be desired and can be adjusted by the amount of deflocculant added in each treatment. If yield point and gels are lowered too far, suspension and cutting capacity of the mud are impaired.

The act of reducing the viscosity of a suspension by adding a thinning agent, also known as a deflocculant.

A mud additive used to lower interfacial tension so that trapped gas will readily escape from mud. Mechanical degassing equipment is commonly used along with defoamer. Octyl alcohol, aluminum stearate, various glycols, silicones and sulfonated hydrocarbons are used as defoamers.

In a separator, a series of inclined parallel plates or tubes to promote coalescence, or merging, of the foam bubbles liberated from the liquid.

A device that removes air or gases (methane, H2S, CO2 and others) from drilling liquids. There are two generic types that work by both expanding the size of the gas bubbles entrained in the mud (by pulling a vacuum on the mud) and by increasing the surface area available to the mud so that bubbles escape (through the use of various cascading baffle plates). If the gas content in the mud is high, a mud gas separator or "poor boy degasser" is used, because it has a higher capacity than standard degassers and routes the evolved gases away from the rig to a flaring area complete with an ignition source.

A unit of measurement established by the American Petroleum Institute (API) that indicates the density of a liquid. Fresh water has an API density of 10.

To remove water from a substance. The substance may be crude oil, natural gas or natural gas liquids (NGL).Fluid dehydration is needed to prevent corrosion and free-water accumulation in the low points of a pipeline. In the case of gas, it is especially important to avoid hydrate formation and also to meet pipeline requirements. Typical maximum allowable water vapor content is 7 pounds of water per million standard cubic feet. In colder climates, this threshold value could be 3 to 5 pounds per million standard cubic feet. Water vapor can also affect the sweetening and refining processes of a natural gas.Dehydration of crude oil is normally achieved using emulsion breakers, while gas dehydration is accomplished using various liquid desiccants such as glycols (ethylene, diethylene, triethylene and tetraethylene) or solid desiccants such as silicagel or calcium chloride [CaCl2].

The loss of water from cementslurry or drilling fluid by the process of filtration. Dehydration results in the deposition of a filter cake and loss of the slurrys internal fluid into a porousmatrix. The cement is not completely dehydrated because sufficient water remains to allow setting of the cement.

A device used to remove water and water vapors from gas. Gas dehydration can be accomplished through a glycol dehydrator or a dry-bed dehydrator, which use a liquid desiccant and a solid desiccant, respectively.Gas dehydrators are designed to handle only water and gas vapors. If liquid water or oil enters the dehydrator, the device cannot work properly.

Consideration paid to the lessor by a lessee to extend the terms of an oil and gas lease in the absence of operations and/or production that is contractually required to hold the lease. This consideration is usually required to be paid on or before the anniversary date of the oil and gas lease during its primary term, and typically extends the lease for an additional year. Nonpayment of the delay rental in the absence of production or commencement of operations will result in abandonment of the lease after its primary term has expired.

Tests in an oil or gas well to determine its flow capacity at specific conditions of reservoir and flowing pressures. The absolute open flow potential (AOFP) can be obtained from these tests, and then the inflow performance relationship (IPR) can be generated. A deliverability test also is called a productivity test.

An area of deposition or the deposit formed by a flowing sediment-laden current as it enters an open or standing body of water, such as a river spilling into a gulf. As a river enters a body of water, its velocity drops and its ability to carry sediment diminishes, leading to deposition. The term has origins in Greek because the shape of deltas in map view can be similar to the Greek letter delta. The shapes of deltas are subsequently modified by rivers, tides and waves. There is a characteristic coarsening upward of sediments in a delta. The three main classes of deltas are river-dominated (Mississippi River), wave-dominated (Nile River), and tide-dominated (Ganges River). Ancient deltas contain some of the largest and most productive petroleum systems.

A log that shows the magnitude of the correction applied to the long-spacingdetector of a density measurement. When delta rho is above a certain value, typically +/- 0.15 g/cm3, the correction may no longer be accurate, and needs to be examined in more detail. Delta rho is also used as a qualitative indicator of boreholerugosity.

A feature on a sonic log caused by low signalamplitude that results in erroneously long traveltimes. Sonic logs that do not record waveforms measure the acoustic traveltime between transmitter and receiver by detecting the first signal at the receiver above a certain threshold (first motion detection). The threshold is small so that the signal is detected just after it crosses the zero signal baseline. However, if the threshold is set too high, or the signal is too small, the system will not trigger at the sharp zero crossing but at some later point on the waveform. This increases the apparent transmitter-receiver time. Delta-t stretch is more likely at the far receiver, where signals are weaker, so that the apparent traveltime calculated between receivers is too large. In the extreme case, the system triggers on the next cycle of the waveform, known as cycle skipping.

A chemical used to break emulsions (that is, to separate the two phases). The type of demulsifier selected depends on the type of emulsion, either oil-in-water or water-in-oil. Demulsifiers are used in the chemical analysis of oil and synthetic muds and to treat produced hydrocarbons.

An instrument that measures the specific gravity of a mixture of gas, liquid and solids. This device is also known as a densitometer.

A device installed on a mixing or pumping system manifold to measure the density of fluids. The density of fluids pumped into a well is frequently a key operating parameter, requiring constant monitoring and control. This is especially true when mixing slurries and transport fluids for solids, such as fracturing or gravel-pack fluids.

Mass per unit of volume. Density is typically reported in g/cm3 (for example, rocks) or pounds per barrel (drilling mud) in the oil field.

The variation in the mass per unit volume of rocks, which affects the local gravitational field of the Earth. A density contrast also contributes to an acousticimpedance contrast, which affects the reflection coefficient.

A measurement of the bulk density of the formation based on borehole-gravity measurements. As the gravitational attraction between two bodies is dependent upon their masses and their separation, it follows that its measurement also can be used to make a direct determination of density. The density thus measured is highly accurate but averaged over a large volume.

A series of gravity measurements made along a line or over an area of a locally high topographic feature to remove or compensate for the effect of topography on deeper density readings.

A graph that shows the effects of environmental factors on the ideal response of a measurement. The name comes from the departure of the actual response from the ideal. The term is used most commonly in relation to the effect of hole size, mudresistivity, bed thickness, invasion and other factors on electrical logs.

In a nuclear magnetic resonance (NMR) measurement, the loss of synchronization of hydrogen atoms precessing at different speeds about the static magnetic field. When the signals from individual atoms are not synchronized, they are out of phase and the total signal is reduced. The dephasing occurs either because of inhomogeneities in the static magnetic field or through molecular processes. Dephasing due to inhomogeneities is known as the free-induction decay and is corrected by the CPMG sequence. Molecular dephasing is known as transverse relaxation.

An isolated section of reservoir in which the pressure has dropped below that of adjacent zones or the main body of the reservoir formation.

The drop in reservoirpressure or hydrocarbon reserves resulting from production of reservoir fluids. At times, a strong waterdrive will maintain reservoir pressure to a substantial degree so that reserves diminish without a corresponding pressure decline.

An assembly of pressure-control equipment that enables the running and retrieval of long tool strings on a coiled tubing string in a live wellbore. The deployment system is configured to provide two barriers against well pressure as the tool string is assembled and run into the wellbore. Once fully assembled, the coiled tubing equipment is connected and the tool string is run into the wellbore. The process is reversed for tool retrieval.

The area of thickest deposition in a basin.

The action of moving sediments and laying them down.

The relative kinetic energy of the environment. A high-energy environment might consist of a rapidly flowing stream that is capable of carrying coarse-grained sediments, such as gravel and sand. Sedimentation in a low-energy environment, such as an abyssal plain, usually involves very fine-grained clay or mud. Depositional energy is not simply velocity. For example, although glaciers do not move quickly, they are capable of carrying large boulders.

The area in which and physical conditions under which sediments are deposited, including sediment source; depositional processes such as deposition by wind, water or ice; and location and climate, such as desert, swamp or river.

The three-dimensional array of sediments or lithofacies that fills a basin. Depositional systems vary according to the types of sediments available for deposition as well as the depositional processes and environments in which they are deposited. The dominant depositional systems are alluvial, fluvial, deltaic, marine, lacustrine and eolian systems.

The practice of ensuring that all measurements taken in a borehole are matched to the "base depth," normally the depth determined with the resistivity log.

A device used in acquisition of marineseismic data that keeps streamers at a certain depth in the water.

The process of transforming seismic data from a scale of time (the domain in which they are acquired) to a scale of depth to provide a picture of the structure of the subsurface independent of velocity. Depth conversion, ideally, is an iterative process that begins with proper seismic processing, seismic velocity analysis and study of well data to refine the conversion. Acoustic logs, check-shot surveys and vertical seismic profiles can aid depth conversion efforts and improve correlation of well logs and drilling data with surface seismic data.

The process of comparing and fixing measured depths with known features on baseline logs of the wellbore tubulars and the surrounding formation.

(noun) A fixed reference elevation from which all depth measurements in a well are calculated, typically the kelly bushing, rotary table, drill floor, or mean sea level. Establishing a consistent depth datum is essential for correlating geological and engineering data between wells in a field.

A two-dimensional representation of subsurface structure with contours in depth that have been converted from seismic traveltimes.

A magnetic mark placed on a loggingcable as a reference for depth measurements. The marks are placed on the cable at regular intervals, usually 100 ft [30 m] or 50 m [164 ft], under a certain tension in a workshop. The intervals may change slightly as a function of tension downhole, but this change can be corrected for. During logging operations, the marks are detected by a magnetic mark detector, and then used to check and correct the depth read by the depth wheel.

Pertaining to two or more logging curves that have been aligned in depth. Logs recorded on different runs will not be exactly aligned at all depths because of the difficulty of perfect depth control. If the two logs are offset by the same amount throughout the log, then only a simple depth shift is required. If the offset varies, then the logs need to be depth matched.Depth matching is simplest if both runs contain the same type of log, such as a gamma ray. The two gamma rays can then be aligned, either manually or with software, and the other logs shifted by the same amount. Otherwise the alignment is based on two logs that respond in a similar fashion, such as a neutron porosity and a shallow laterolog.Depth matching also may be needed for logs recorded on the same run. Although there is a fixed distance between the measure points and the depth reference, the apparent distance will vary if the tool moves unevenly up the hole, due to stick and slip or yo-yo effects. Depth matching is then necessary.

The practice of shifting depths of various data sets to a measurement that is known to be on depth. The general standard that is usually used is the first resistivity logs run, because those logs usually underwent the most rigorous depth control.Depth matching is usually applied to all wireline data, cores, boreholeseismic data, and any other data taken in a well. Depth matching is a vital process in any well evaluation or any reservoir characterization exercise, so much so that, in its absence, accuracy and validity of the exercise must be questioned.

A step in seismic processing in which reflections in seismic data are moved to their correct locations in space, including position relative to shotpoints, in areas where there are significant and rapid lateral or vertical changes in velocity that distort the time image. This requires an accurate knowledge of vertical and horizontal seismic velocity variations.

The distance from the borehole wall that the mudfiltrate has penetrated into the formation. The depth of invasion affects whether a log measures the invaded zone, the undisturbed zone or part of each zone. The term is closely related to the diameter of invasion, the latter being twice the depth of invasion plus the borehole diameter. Depth of invasion is a more appropriate parameter for describing the response of pad and azimuthally focused measurements such as density and microresistivity logs.The term is well-defined in the case of a step profile of invasion. In the case of an annulus or a transition zone, two depths must be defined, corresponding to the inner and outer limits of the annulus or transition zone. When the invasion model is not specified, the term usually refers to the outer limit of invasion.

A distance that characterizes how far a logging tool measures into the formation from the face of the tool or the borehole wall. The depth of investigation summarizes the radial response of the measurement in one or more directions. For nuclear and resistivity measurements, the depth of investigation should be associated with the percentage of signal received from within that depth, typically either 50% or 90%. Most quoted depths of investigation assume a homogeneous formation with certain properties, such as a given resistivity or fluid content. The depths of investigation can vary considerably in inhomogeneous conditions, and at different values of the properties concerned. They should be considered only a qualitative guide to tool response.For other measurements, the depth of investigation is either well-defined by the tool physics (in the case of nuclear magnetic resonance), or else can be given only approximately, an accurate value being too dependent on formation properties (in the case of acoustic and electromagnetic propagation).The term is used for all measurements but is most appropriate for azimuthally focused devices such as nuclear logs. For azimuthally symmetric devices such as resistivity logs, the term radius of investigation is more appropriate.

A point on the surface for which the depth to a horizon has been calculated in a refractionseismic survey. The term is commonly misused as a synonym for common depth point.

The point in a well from which depth is measured. Alternatively, the depth reference is the point at which the depth is defined as being zero. It is typically the top of the kelly bushing or the level of the rig floor on the rig used to drill the well. The depth measured from that point is the measured depth (MD) for the well. Even when the drilling rig has been removed, all subsequent measurements and operations in the well are still tied in to the same depth reference. However, for multiwell studies, the depths are normally shifted to the permanent datum. The depth reference and its elevation above the permanent datum are recorded on the log heading. In some contexts, the term may refer to any point from which depth is measured.

A point within the wellbore from which accurate depth measurements can be made, such as the end of the tubing string, or a nipple or similar completion component.

A display of seismic data with a scale of units of depth rather than time along the vertical axis. Careful migration and depth conversion are essential for creating depth sections.

A calibrated wheel used to drive the depth recording system in wirelinelogging. The wheel is pressed against the logging cable as the cable is spooled onto the drum and therefore turns as the cable is run in and out of the borehole. After zeroing the depth on surface, the depth wheel provides the depth input to the recording system. Small errors in calibration and slippage can cause the wheel to introduce systematic errors in the depth recorded. For this reason, the depth is checked and corrected using depth marks. The depth wheel is also referred to as a depth encoder. Modern encoders have two wheels so that slippage can be detected by differences between the two measurements.

Referring to a borehole-compensation scheme for sonic logs that combines measurements taken when the logging tool is at two different depths in the borehole. In normal borehole-compensation schemes, the effects of caves and sonde tilt are minimized by combining measurements from a second transmitter (T2) above a pair of receivers with those from the first transmitter (T1) below the receivers. This arrangement makes the logging tool unacceptably long for the long-spacing sonic log. In the depth-derived system, T2 is located below T1, at a distance equal to the receiver spacing. T1 is fired and the transit time between the receivers at depth z (TT1z) is recorded as usual. Then when T1 and T2 are at depth z, both are fired sequentially and the difference in time for their signals to reach one of the receivers is recorded (TT2z). The average of TT1z and TT2z is borehole-compensated since the acoustic signals traveled in opposite directions for the two measurements.

Logs that have been calculated from other logs to find the rate at which a log is changing with depth. For example, the derivative caliper (rugosity) calculates the rate at which the caliper is changing from one depth to another. Bad hole conditions that cause the density log to produce incorrect measurements are usually more closely related to the rugosity of the hole than the hole size, so the rugosity curve is the more useful in this regard.

The structure used to support the crown blocks and the drillstring of a drilling rig. Derricks are usually pyramidal in shape, and offer a good strength-to-weight ratio. If the derrick design does not allow it to be moved easily in one piece, special ironworkers must assemble them piece by piece, and in some cases disassemble them if they are to be moved.

The member of the drilling crew in charge of the mud-processing area during periods of circulation. The derrickman also measures mud density and conducts the Marsh funnel viscosity test on a regular basis when the mud is circulating in the hole. The derrickman reports to the toolpusher, but is instructed in detail by the mud engineer on what to add to the mud, how fast and how much. His other job is to handle pipe in the derrick while pulling out or running into the hole.

A hydrocyclone device that removes large drill solids from the whole mud system. The desander should be located downstream of the shale shakers and degassers, but before the desilters or mud cleaners. A volume of mud is pumped into the wide upper section of the hydrocylone at an angle roughly tangent to its circumference. As the mud flows around and gradually down the inside of the cone shape, solids are separated from the liquid by centrifugal forces. The solids continue around and down until they exit the bottom of the hydrocyclone (along with small amounts of liquid) and are discarded. The cleaner and lighter density liquid mud travels up through a vortex in the center of the hydrocyclone, exits through piping at the top of the hydrocyclone and is then routed to the mud tanks and the next mud-cleaning device, usually a desilter. Various size desander and desilter cones are functionally identical, with the size of the cone determining the size of particles the device removes from the mud system.

A substance used in a gas-dehydration unit to remove water and moisture. The desiccant can be liquid, such as methanol, glycol (ethylene, diethylene, triethylene, and tetraethylene). Dessicants also can be solid, such as silica gel or calcium chloride [CaCl2].The most common gas-dehydration system (glycol dehydrator) uses liquid desiccants such as diethylene, triethylene and tetraethylene, which are substances that can be regenerated. Regeneration means that the water absorbed by these substances can be separated from them. Some liquid desiccants such as methanol or ethylene cannot be regenerated.Solid desiccants are also used for gas dehydration. They are placed as beds through which wet gas is passed. The main limitation of the use of solid dessicants is that they absorb only limited quantities of water. When the desiccant saturation point is reached, the solid dessicant must be replaced. Another limitation is that sometimes water cannot be removed from it.

A hydrocyclone much like a desander except that its design incorporates a greater number of smaller cones. As with the desander, its purpose is to remove unwanted solids from the mud system. The smaller cones allow the desilter to efficiently remove smaller diameter drill solids than a desander does. For that reason, the desilter is located downstream from the desander in the surface mud system.

To remove sulfur or sulfur compounds from an oil or gas stream.

A log with a depth scale chosen to show sufficient detail of the formation. The most common scales are 1/200 or 5 in./100 ft.

The minimum thickness necessary for a layer of rock to be visible or distinct in reflectionseismic data. Generally, the detectable limit is at least 1/30 of the wavelength. Acquisition of higher frequency seismic data generally results in better detection or vertical resolution of thinner layers.

A sensor or receiver, such as a geophone or hydrophone, gravimeter or magnetometer.

The ability of a chemical agent to remove a contaminant from a solid surface. For example, in enhanced oil recovery, a surfactant can be used to remove an oil phase from a mineral surface. At least two mechanisms can occur: a) The surfactant adsorbs on the contaminated surface and presents its hydrophilic group to the contacting liquid. Thus, the surface behaves hydrophilically and repels macroscopic oil drops. b) The surfactant adsorbs to the contaminant. It is energetically more favorable for the combination of surfactant and contaminant to be in solution than to be attached to the surface so the contaminant is solubilized, exposing the mineral surface.

The use of deterministic methods to solve problems or find solutions to data sets.

A type of inverse filtering, or deconvolution, in which the effects of the filter are known by observation or assumed, as opposed to statistical deconvolution.

Techniques that use equations or algorithms that have been previously developed for similar situations. These methods do not involve stochastic or statistical approaches. Deterministic methods are generally easier and faster to apply and readily lend themselves to computer applications. However, they may not provide the most detailed or the most accurate reservoir models.

A cord containing high-explosive material sheathed in a flexible outer case, which is used to connect the detonator to the main high explosive. This provides an extremely rapid initiation sequence that can be used to fire several charges simultaneously.

A device containing primary high-explosive material that is used to initiate an explosive sequence. The two common types of detonators are electrical detonators (also known as blasting caps) and percussion detonators. Electrical detonators have a fuse material that burns when high voltage is applied to initiate the primary high explosive. Percussion detonators contain abrasive grit and primary high explosive in a sealed container that is activated by a firing pin. The impact force of the firing pin is sufficient to initiate the ballistic sequence that is then transmitted to the detonating cord. Several safety systems are used in conjunction with detonators to avoid accidental firing during rig-up or rig-down. Safety systems also are used to disarm the gun or ballistic assembly if downhole conditions are unsafe for firing.

Pertaining to particles of rock derived from the mechanical breakdown of preexisting rocks by weathering and erosion. Detrital fragments can be transported to recombine and, through the process of lithification, become sedimentary rocks. Detrital is usually used synonymously with clastic, although a few authors differentiate between weathering of particles, which forms detrital sediments, and mechanical breakage, which produces clastic sediments.

The phase of petroleum operations that occurs after exploration has proven successful, and before full-scale production. The newly discovered oil or gas field is assessed during an appraisal phase, a plan to fully and efficiently exploit it is created, and additional wells are usually drilled.

A wellbore that is not vertical. The term usually indicates a wellbore intentionally drilled away from vertical.

The angle at which a wellbore diverges from vertical. Wells can deviate from vertical because of the dips in the beds being drilled through. Wells can also be deliberately deviated by the use of a whipstock or other steering mechanism. Wells are often deviated or turned to a horizontal direction to increase exposure to producing zones, intersect a larger number of fractures, or to follow a complex structure.

The process of removing water from water-base drilling mud. Dewatering can involve chemical treatment for the flocculation and aggregation of solids followed by mechanical separation, such as centrifugation, or mechanical treatments alone.

The pressure at which the first condensate liquid comes out of solution in a gas condensate. Many gas condensate reservoirs are saturated at initial conditions, meaning that the dewpoint is equal to the initial reservoir pressure. Condensate dissolution is called retrograde condensation because this is counter to the behavior of pure substances, which vaporize when the pressure drops below the saturation pressure under isothermal (constant temperature) conditions.

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

The initial stage of alteration of sediments and maturation of kerogen that occurs at temperatures less than 50°C [122°F]. The type of hydrocarbon generated depends on the type of organic matter in the kerogen, the amount of time that passes, and the ambient temperature and pressure. During early diagenesis, microbial activity is a key contributor to the breakdown of organic matter and generally results in production of biogenic gas. Longer exposure to higher temperatures during diagenesis, catagenesis, and metagenesis generally results in transformation of the kerogen into liquid hydrocarbons and hydrocarbon gases.

A type of secondary porosity created during diagenesis, commonly through dissolution or dolomitization or both. Diagenesis usually destroys porosity, so diagenetic porosity is rare.

The distance from the borehole wall into the formation that the mudfiltrate has penetrated. The term assumes equal invasion on all sides of the borehole. It is the diameter of the circle thus formed, with the center being the center of the borehole. The diameter of invasion affects whether a log measures the invaded zone, the undisturbed zone, or part of each zone. The term is closely related to the depth of invasion, being twice the depth of invasion plus the borehole diameter. Diameter of invasion is a more appropriate parameter for describing the response of azimuthally symmetric measurements such as induction, laterolog and propagation resistivity.The term is well-defined in the case of a step profile of invasion. In the case of an annulus or a transition zone, two diameters must be defined, corresponding to the inner and outer limits of the annulus or transition zone. When the invasion model is not specified, the term usually refers to the outer limit of invasion.

A distance that characterizes how far a logging tool measures into the formation from the axis of the tool or borehole. The term is similar to depth of investigation but is appropriate only for azimuthally symmetric measurements such as resistivity.

A tool for drilling rock that works by scraping industrial grade diamonds against the bottom of the hole. The diamonds are embedded into the metal structure (usually a sintered or powdered carbide base matrix) during the manufacture of the bit. The bit designer has virtually unlimited combinations of bit shape, the placement of hydraulic jetting ports, the amount of diamonds and the size of the diamonds used (usually expressed as diamonds per carat). In general, a diamond bit that drills faster has a shorter lifetime. Similarly, a bit designed for extremely long life will typically drill at a slower rate. If a bit has a relatively high number of diamonds compared with other bits, it is said to be "heavy-set" and has higher durability. A "light-set" bit, on the other hand, drills more aggressively, but wears out faster because fewer diamonds do the work.

A relatively mobile mass that intrudes into preexisting rocks. Diapirs commonly intrude vertically through more dense rocks because of buoyancy forces associated with relatively low-density rock types, such as salt, shale and hot magma, which form diapirs. The process is known as diapirism. By pushing upward and piercing overlying rock layers, diapirs can form anticlines, salt domes and other structures capable of trapping hydrocarbons. Igneous intrusions are typically too hot to allow the preservation of preexisting hydrocarbons.

A microscopic, single-celled, freshwater or saltwater algae that has a silica-rich cell wall called a frustule. Diatoms are so abundant that they can form thick layers of sediment composed of the frustules of the organisms that died and sank to the bottom. Frustules have been an important component of deep-sea deposits since Cretaceous time. Diatomite is the sedimentary rock that forms from diatom frustules.

A soft, silica-rich sedimentaryrock comprising diatom remains that forms most commonly in lakes and deep marine areas. Diatomite can form an excellent reservoir rock. The Belridge diatomite in the San Joaquin basin, California, USA, is a prolific oil-producing formation.

A type of salt in which chromium atoms are in the plus-7 valence state, such as potassium dichromate, K2Cr2O7.

A material used in a capacitor to store a charge from an applied electrical field. A pure dielectric does not conduct electricity.

The degree to which a medium resists the flow of electric charge, defined as the ratio of the electric displacement to the electric field strength. It is more common to use the relative dielectric permittivity.

A log of the high-frequency (on the order of 25 MHz) dielectric properties of the formation. The log usually includes two curves the relative dielectric permittivity, symbolized by epsilon which is unitless, and the resistivity in ohm-m. At the frequency used, water molecules have a strong effect on the dielectric properties, so that both relative dielectric permittivity and conductivity increase with the volume of water present. Relative dielectric permittivity can be used to distinguish hydrocarbons from water of any salinity. However, the effect of salinity is more important than the salinity effect with the high-frequency electromagnetic propagation log, and the interpretation is more complex. The advantage of the dielectric propagation log is that the lower frequency permits a larger depth of investigation and therefore an analysis of the undisturbed zone.

The resistivity of the formation derived by combining the attenuation and phase shift of a propagation resistivity measurement. Common practice is to transform attenuation and phase shift independently to resistivity, assuming a certain transform between permittivity and resistivity. These relations lose accuracy at high resistivity. However, by combining the two measurements, both the dielectric permittivity and resistivity can be determined without need for a transform. The dielectric resistivity extends the range of measurement, typically up to 3000 ohm-m.

An oil-base mud with diesel oil as its external phase. Diesel-oil mud is the traditional oil mud and has a history of excellent performance for drilling difficult wells. It has been used because the base oil is low-cost and widely available motor fuel. In-gauge holes can be drilled through all types of shales, salt, gypsum and other difficult strata using diesel-oil mud systems. It is often the mud of choice for drilling high-pressure, high-temperature zones. Diesel-oil muds usually contain from 5 to 40 vol.% emulsified brine water (except those that are specially designed to have none). The water phase usually contains 20 to 40 wt.% dissolved calcium chloride for shale control. Diesel-oil muds have been replaced in land drilling by mineral-oil muds and offshore by synthetic-fluid muds. These newer muds have fewer health, safety and environmental concerns compared to diesel oil.

An oil-base mud with diesel oil as its external phase. Diesel-oil mud is the traditional oil mud and has a history of excellent performance for drilling difficult wells. It has been used because the base oil is low-cost and widely available motor fuel. In-gauge holes can be drilled through all types of shales, salt, gypsum and other difficult strata using diesel-oil mud systems. It is often the mud of choice for drilling high-pressure, high-temperature zones. Diesel-oil muds usually contain from 5 to 40 vol.% emulsified brine water (except those that are specially designed to have none). The water phase usually contains 20 to 40 wt.% dissolved calcium chloride for shale control. Diesel-oil muds have been replaced in land drilling by mineral-oil muds and offshore by synthetic-fluid muds. These newer muds have fewer health, safety and environmental concerns compared to diesel oil.

A map that represents the change from one map to another, such as a reservoir map of an area made from two different seismic surveys separated in production history (one possible product of 4D seismic data), or an isochron map that displays the variation in time between two seismic events or reflections.

The spontaneous potential (SP) measured between two electrodes placed close together in the borehole, as opposed to the normal SP, which is measured with one electrode in the borehole and one at surface.

A phenomenon that occurs after the deposition of some sediments such that different parts of the sedimentary accumulation develop different degrees of porosity or settle unevenly during burial beneath successive layers of sediment. This can result from location on an uneven surface, such as near and over a reefstructure, or near a growth fault, or from different susceptibility to compaction. The porosity in a formation that has experienced differential compaction can vary considerably from one area to another.

The difference between two pressure measurements. For production wells, the differential pressure is the difference between average reservoir pressure and bottomhole pressure, and for injection wells, it is the difference between injection pressure and average reservoir pressure.

A technique in nuclear magnetic resonance (NMR) logging that is based on the difference between the T2 distributions, or spectra, acquired at different polarization times. The technique often is used to detect gas or light oil. These fluids have long T1 that exceed 1 s. A measurement made with a long polarization time will polarize much of these fluids and give significant signal at the appropriate T2. A measurement made with a short polarization time will polarize little of these fluids and will give a much smaller signal. Other fluids, with shorter T1, will be polarized in both cases, so that a difference in signal at the appropriate T2 identifies gas or light oil.

What Is Differential Sticking? Differential sticking occurs when a stationary drill pipe, drill collar, or bottomhole assembly (BHA) becomes embedded in the filter cake deposited on a permeable formation wall, held in place by the compressive force generated by the pressure difference between the overbalanced drilling fluid column and the lower pore pressure of the formation. The pipe cannot rotate or reciprocate until the sticking force is overcome or the wellbore differential pressure is reduced. Key Takeaways Differential sticking requires three simultaneous conditions: a permeable formation, an overbalanced mud column depositing filter cake, and a stationary pipe in contact with that cake for an extended period. Sticking force equals differential pressure multiplied by the pipe-to-cake contact area; a 1,500 psi (103 bar) differential over 10 ft² (0.93 m²) generates approximately 216,000 lb (961 kN) of holding force. Prevention centers on lowering differential pressure through managed pressure drilling or reduced mud weight, minimizing filter cake thickness with low fluid-loss additives, and keeping pipe moving during connections and surveys. The primary freeing technique is spotting a diesel- or mineral oil-based spotting fluid (40-80 bbl / 6.4-12.7 m³) at the stuck point to soak and degrade the filter cake, followed by pulling and jar impact. The average differential sticking event costs USD $500,000 to $3 million in non-productive time (NPT) and is one of the most expensive single drilling hazards encountered in depleted reservoir intervals worldwide. How Differential Sticking Works When a wellbore is drilled overbalanced, the hydrostatic pressure of the drilling fluid column exceeds the pore pressure of the formation. Across permeable zones such as sandstone reservoirs or vuggy carbonates, this pressure differential drives fluid filtrate into the formation and deposits a layer of solids on the borehole wall known as filter cake. The thickness and compressibility of the filter cake depend on the fluid-loss properties of the mud: high-spurt, high-API fluid-loss muds build thick, firm cakes, while properly treated water-based muds using starch, carboxymethyl cellulose (CMC), or hydroxyethyl cellulose (HEC) polymers build thinner, more slippery cakes. Oil-based muds (OBM) characteristically produce the thinnest, most ductile filter cakes and carry significantly lower differential sticking risk than equivalent water-based muds (WBM). The sticking event itself is initiated by static pipe time. During logging-while-drilling (LWD) surveys, pipe connections, gas circulation, or any operation requiring the string to remain stationary, the pipe sinks under gravity into the soft filter cake. Once embedded, the contact area between the pipe's outer surface and the cake grows rapidly. The force required to free the pipe follows the relationship: F = DP × A × 144 Where F is sticking force in pounds-force, DP is the differential pressure in psi (wellbore pressure minus formation pore pressure), A is the pipe-to-cake contact area in square feet, and 144 converts square feet to square inches. In practical terms, differential pressures of 1,000 to 3,000 psi (69-207 bar) combined with contact areas of 5 to 20 ft² (0.46-1.86 m²) produce sticking forces ranging from 50,000 lb (222 kN) to more than 1,000,000 lb (4,448 kN). These forces vastly exceed the tensile rating of standard drill pipe and the mechanical capability of surface jars, making prevention far preferable to remediation. The zones most susceptible to differential sticking are depleted producing formations, where reservoir pressure has fallen well below the original hydrostatic gradient after years of production. In the Permian Basin, operators drilling new horizontal wells through stacked carbonate and Wolfcamp benches regularly encounter depleted intervals where pore pressures may be only 2,000 to 3,000 psi (138-207 bar) while the wellbore hydrostatic exceeds 5,000 psi (345 bar), creating differentials that can instantly trap pipe. Similar conditions exist in the North Sea chalk plays at Ekofisk and Valhall, the Arab-D carbonate at Ghawar in Saudi Arabia, and the Doig and Montney tight silt intervals in the Alberta Deep Basin. Differential Sticking Across International Jurisdictions Canada (Alberta and British Columbia) In Alberta, the Alberta Energy Regulator (AER) Directive 036: Drilling Blowout Prevention Requirements and Procedures governs incident reporting for stuck pipe events. Montney horizontal wells drilled from the Peace River Arch south to the Dawson Creek area are highly susceptible to differential sticking across the Upper Triassic Doig Formation, which is frequently depleted due to historical gas production. Operators are required to report unplanned stuck-pipe NPT exceeding 24 hours to the AER operations field office. The AER's Well Event Reporting System (WERS) tracks differential sticking incidents as a component of drilling performance benchmarking. British Columbia's Energy Regulator (BCER) applies equivalent requirements under the Drilling and Production Regulation (BC Reg 282/2010). United States (Offshore and Onshore) The Bureau of Safety and Environmental Enforcement (BSEE) regulates offshore drilling incidents under 30 CFR Part 250, Subpart D. Operators in the Gulf of Mexico (GoM) deepwater must report differential sticking events that result in stuck-pipe time exceeding threshold hours or that require sidetrack. The deepwater GoM Miocene turbidite sands, particularly in the Mississippi Canyon and Green Canyon areas, present some of the highest differential sticking risk in the world: reservoir pressures in these sands are frequently sub-hydrostatic due to production from adjacent fields, while required riser mud weights often exceed 12 to 14 ppg (1,438-1,678 kg/m³). Onshore, the Oklahoma Corporation Commission and the Texas Railroad Commission require reporting of significant stuck-pipe incidents that result in a well control event or well abandonment. Australia The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) requires operators to notify NOPSEMA of any drilling incident that results in loss of well control or significant NPT under the Offshore Petroleum and Greenhouse Gas Storage (OPGGS) Act 2006 and associated regulations. In the Cooper Basin (South Australia and Queensland), onshore operators encounter differential sticking in the depleted Permian Patchawarra and Tirrawarra sandstone formations, where reservoir pressures in many wells have declined to less than 1,000 psi (69 bar) over decades of production. The relevant state regulatory body, the Department of Energy and Mining (South Australia) or the Department of Resources (Queensland), administers reporting under the Petroleum and Geothermal Energy Act 2000. Middle East (Saudi Arabia and UAE) Saudi Aramco's Well Engineering Manual (WEM) dedicates a dedicated chapter to differential sticking in Arab-D carbonate drilling at Ghawar, the world's largest conventional oil field. The Arab-D Member of the Jurassic Arab Formation has been under production since the 1950s, and pressure depletion in the gas cap zones and peripheral areas creates differential pressures of 2,000 to 4,000 psi (138-276 bar) against standard drilling fluid hydrostatics. Saudi Aramco mandates the use of low-fluid-loss oil-based muds in all Arab-D horizontal wells and requires a pre-approved spotting fluid program before spudding these intervals. Abu Dhabi National Oil Company (ADNOC) applies equivalent requirements under ADNOC General Specifications for Drilling Operations for the Khuff Formation in Abu Dhabi offshore fields, where high-pressure, high-temperature (HPHT) conditions add additional complexity to freeing operations. Norway and the North Sea In Norway, the Petroleum Safety Authority Norway (Ptil, formerly Petroleumstilsynet) investigates differential sticking incidents under the Framework Regulations and Activities Regulations as part of its oversight of drilling and well operations on the Norwegian Continental Shelf (NCS). Sodir (formerly NPD) compiles drilling performance data including stuck-pipe statistics in its annual "Norwegian Petroleum Directorate's Resource Report." The Ekofisk chalk field in the Central Graben and the Brent sandstone group in the Northern North Sea are historically the highest-risk zones for differential sticking in Norwegian and UK waters. At Ekofisk, compaction-driven subsidence has created pore pressure depletion of up to 4,000 psi (276 bar) in the producing chalk, while deepwater Brent Group wells drilled from the Hutton, Cormorant, and Statfjord platforms encountered differential sticking regularly until the adoption of low-toxicity mineral oil-based muds in the 1990s. In the UK sector, the North Sea Transition Authority (NSTA, formerly OGA) requires well incident reporting under the Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations 1995 and the associated guidance in the Step Change in Safety Stuck Pipe Guidelines. Fast Facts Typical differential pressure range: 1,000 to 3,000 psi (69-207 bar) for most stuck-pipe events; up to 5,000 psi (345 bar) in severely depleted GoM Miocene sands. Typical contact area: 5 to 20 ft² (0.46-1.86 m²), depending on drill collar OD and length of permeable zone. Spotting fluid volume: 40 to 80 bbl (6.4-12.7 m³) per treatment, pumped to stuck point depth via displacement calculation. Success rate: Approximately 70% of differential sticking events are freed within 12 hours of spotting; success drops sharply after 24 hours. Average NPT cost: USD $500,000 to $3 million per incident; deepwater GoM incidents frequently exceed $5 million when sidetrack is required. Most vulnerable string components: Large-OD drill collars and heavyweight drill pipe (HWDP) due to greater contact area against the borehole wall. Static time threshold: Most differential sticking events occur after 3 to 15 minutes of pipe immobility; risk increases exponentially with time.

A type of static correction that compensates for delays in seismicreflection or refraction times from one point to another, such as among geophone groups in a survey. These delays can be induced by low-velocity layers such as the weathered layer near the Earth's surface.

A record of the difference in temperature between two vertical points in a well. Most differential-temperature logs are obtained by differentiating a normal temperature log with respect to depth. Some are obtained by recording the difference in temperature between two vertically displaced sensors. Note that the differential-temperature log and the radial differential-temperature log are not the same.

Pertaining to a cement that is not easily dispersed by a material known as a dispersant. This term is commonly abbreviated as DTD.

Pertaining to cement that is not easily dispersed by a material known as a dispersant when the slurry is mixed with water containing a high concentration of salt. The term is commonly abbreviated DTDS.

A type of event produced by the radial scattering of a wave into new wavefronts after the wave meets a discontinuity such as a fault surface, an unconformity or an abrupt change in rock type. Diffractions appear as hyperbolic or umbrella-shaped events on a seismicprofile. Proper migration of seismic data makes use of diffracted energy to properly position reflections.

The process by which particles move over time within a material due to their kinetic motion. The term is most commonly used in pulsed neutron capturelogging and in nuclear magnetic resonance (NMR) logging. In a pulsed neutron capture log, the term refers to the spread of neutrons away from the neutron generator. In NMR logging, diffusion refers to the movement of gas, oil or water molecules within the pore space.

A fundamental differential equation obtained by combining the continuity equation, flow law and equation of state. Most of the mathematics of well testing were derived from solutions of this equation, which was originally developed for the study of heat transfer. Fluid flow through porous media is directly analogous to flow of heat through solids. Solutions used in well testing usually assume radial flow and homogenous, isotropic formations.

In a nuclear magnetic resonance (NMR) measurement, the loss of coherent energy by hydrogen atoms as they move within the pore space. Hydrogen atoms that move significantly within the pores during a NMR measurement will encounter different magnetic fields and hence will precess at different rates, or dephase. Dephasing contributes only to T2 and is most significant in gas or light oils. The magnitude depends on the field gradient, the echo spacing and the diffusion coefficient of the fluid. Diffusion relaxation can be induced in water by using long echo spacings. This is the basis of the enhanced diffusion technique.

An intrusive rock that invades preexisting rocks, commonly in a tabular shape that cuts vertically or nearly vertically across preexisting layers. Dikes form from igneous and sedimentary rocks.

The increase in the volume of rocks as a result of deformation, such as when fractures develop.

A possible explanation for volume changes in rocks due to strain, such as microfracturing or cracking, and the accompanying change in the ratio of P- to S-wavevelocity. Support for dilatancy theory comes in the form of porosity increases from 20 to 40% that have been measured in laboratory experiments using rock samples.

A rarefaction, or decrease in pressure and density of a medium as molecules are displaced by a P-wave. As P-waves pass through the Earth, the Earth undergoes compression and expansion. These changes in volume contribute to the positive and negative amplitudes of a seismictrace.

A hydrocarbon fluid that is used to dilute heavy oil and reduce its viscosity for easier transportation. Generally a distillation tower cut such as naphtha is used as for heavy oil dilution and transportation. The added diluent may be recovered at the destination using distillation and the diluent may be subsequently pumped back for blending.

The process of adding fresh mud (or liquid phase) in order to reduce the solids content and maintain the properties of the drilling fluid in the active system.

A type of local seismicevent that, in contrast to a bright spot, shows weak rather than strong amplitude. The weak amplitude might correlate with hydrocarbons that reduce the contrast in acousticimpedance between the reservoir and the overlying rock, or might be related to a stratigraphic change that reduces acoustic impedance.

The angle between a planar feature, such as a sedimentarybed or a fault, and a horizontal plane. True dip is the angle a plane makes with a horizontal plane, the angle being measured in a direction perpendicular to the strike of the plane.Apparent dip is the angle measured in any direction other than perpendicular to the strike of the plane. Given the apparent dip and the strike, or two apparent dips, the true dip can be computed.

An algorithm for correcting the effects of dip or boreholedeviation on the response of a logging measurement. These effects are significant for deep-reading logs such as induction and electrode devices. The standard processing used to produce these logs assumes a vertical well with horizontal formation layers. In the presence of a relative dip between the borehole and formation layers, the logs may read incorrectly. For older logs such as the dual induction, a set of inversefilters can be designed to correct for dip effect up to about 60. For modern array logs, iterative forward modeling with a one-dimensional layered earth model can correct up to about 85.

A fault whose primary movement is in the dip direction. Dip faults are also referred to as dip-slip faults.

The procedure in seismic processing that compensates for the effects of a dipping reflector. DMO processing was developed in the early 1980s.

A small antenna used in electromagnetic surveying that can be represented mathematically as a dipole.

A layer of rock or sediment that is not horizontal.

The application of nuclear magnetic resonance (NMR) logging to the determination of hydrocarbon type (gas, light oil, medium oil, heavy oil), using only NMR data. Three techniques are most commonly used: differential spectrum, shifted spectrum and enhanced diffusion.

The instrument used to measure viscosity and gel strength of drilling mud. The direct-indicating viscometer is a rotational cylinder and bob instrument, also known as a V-G meter. Two speeds of rotation, 300 and 600 rpm, are available in all instruments, but some are 6- or variable-speed. It is called "direct-indicating" because at a given speed, the dial reading is a true centipoise viscosity. For example, at 300 rpm, the dial reading (511 sec-1) is a true viscosity. Bingham plasticrheological parameters are easily calculated from direct-indicating viscometer readings: PV (in units of cp) = 600 dial - 300 dial and YP (in units of lb/100 ft2) = 300 dial - PV. Gel strength is also directly read as dial readings in oilfield units of lb/100 ft2.

The instrument used to measure viscosity and gel strength of drilling mud. The direct-indicating viscometer is a rotational cylinder and bob instrument, also known as a V-G meter. Two speeds of rotation, 300 and 600 rpm, are available in all instruments, but some are 6- or variable-speed. It is called "direct-indicating" because at a given speed, the dial reading is a true centipoise viscosity. For example, at 300 rpm, the dial reading (511 sec-1) is a true viscosity. Bingham plasticrheological parameters are easily calculated from direct-indicating viscometer readings: PV (in units of cp) = 600 dial - 300 dial and YP (in units of lb/100 ft2) = 300 dial - PV. Gel strength is also directly read as dial readings in oilfield units of lb/100 ft2.

An individual trained in the science and art of intentionally drilling a well along a predetermined path in three-dimensional space, usually involving deviating the well from vertical and directing it in a specific compass direction or heading. The directional driller considers such parameters as rotary speed, weight on bit, control drilling and when to stop drilling and take surveys of the wellpath, and works closely with the toolpusher.

What Is Directional Drilling? Directional drilling steers a wellbore along a planned non-vertical path using a combination of mud motors, rotary steerable systems, and measurement-while-drilling tools. Operators apply directional drilling to develop horizontal shale wells in the Permian and Montney, multilateral wells in the Middle East, extended-reach wells at BP's Wytch Farm and ExxonMobil's Sakhalin-1, and offshore wells from clustered subsea templates in the Norwegian Continental Shelf and Australian Carnarvon Basin. Key Takeaways Directional drilling deliberately deviates a wellbore from vertical to reach a specific subsurface target, the foundational technology enabling horizontal shale development, extended-reach drilling, and multilateral wells. Rotary steerable systems (RSS), mud motors with bent housings, MWD tools, and LWD tools form the directional drilling toolkit, with modern RSS tools holding wellbore placement within 0.5 m (1.6 ft) over 3,000 to 5,000 m (9,843 to 16,404 ft) laterals. Operators, drilling contractors, and investors track directional drilling performance through rate-of-penetration, dogleg severity, and directional-control accuracy, all of which drive cycle time and cost per foot drilled. Regulatory frameworks for directional surveying include AER Directive 059 in Alberta, Texas Railroad Commission survey requirements for Permian horizontals, Sodir directional reporting on the Norwegian Continental Shelf, and NOPSEMA survey-accuracy requirements for Australian Commonwealth offshore wells. ExxonMobil's Sakhalin-1 Chayvo Z-42, drilled in 2013 to 12,700 m (41,667 ft) measured depth with 11,739 m (38,514 ft) horizontal departure, stands as the benchmark extended-reach well record. How Directional Drilling Works A directionally drilled well begins as a vertical hole from surface. At the kickoff point (KOP), the driller deploys a directional assembly that creates a controlled deviation from vertical. Two primary technologies generate the steering force: the positive displacement motor (PDM) with a bent housing, and the rotary steerable system (RSS). Both sit in the bottomhole assembly just above the bit, instrumented with MWD tools that transmit real-time inclination, azimuth, and tool-face data to the surface via mud-pulse or electromagnetic telemetry. A PDM is a downhole motor powered by circulating drilling fluid. The bent housing creates an angular offset of roughly 1 to 3 degrees between the motor axis and the drill-string axis, so when the drill pipe is held stationary and the motor rotates the bit, the hole advances at that angle. Alternating between sliding (motor-only rotation) and rotating (full drill-string rotation) allows the directional driller to build angle, drop angle, or drill straight ahead. PDMs dominate onshore directional drilling for shale plays because they are cost-effective and reliable. A rotary steerable system applies side force at the bit through servo-controlled pads (push-the-bit) or an offset internal shaft (point-the-bit), while the entire drill string rotates continuously. RSS eliminates sliding time, improves rate-of-penetration, and reduces tortuosity in the completed wellbore. Schlumberger's PowerDrive, Halliburton's Geo-Pilot, Baker Hughes's AutoTrak, and NOV's Vector family are the dominant RSS platforms. Modern high-build-rate RSS tools, introduced from 2018 onward, execute build rates above 15 degrees per 30 m (100 ft) while maintaining full rotation, enabling shorter build sections and longer reservoir contact. Directional Drilling Across International Jurisdictions Every major producing country regulates directional surveying to verify that wells stay within leased mineral rights, maintain offset distances from adjacent wells, and respect regulatory boundaries. In Canada, AER Directive 059 Well Drilling and Completion Data Filing Requirements prescribes directional survey reporting for every Alberta well, including gyroscopic or MWD survey data at prescribed intervals. The BCER and Saskatchewan's Ministry of Energy and Resources apply equivalent requirements for Montney, Horn River, Bakken, Viking, and Lloydminster wells. In the United States, the Texas Railroad Commission's Rule 11 requires directional surveys on all horizontal wells in Texas, with specific accuracy thresholds tied to offset-well distance and lease boundaries. The NDIC, the Colorado Energy and Carbon Management Commission, the Pennsylvania DEP, and BSEE 30 CFR 250 all specify survey intervals, tool accuracy, and reporting formats. Federal BLM wells on public lands follow BLM Instruction Memoranda that track API Bulletin K2 accuracy standards. Norway's Sodir enforces strict survey accuracy on the Norwegian Continental Shelf, particularly for wells drilled from fixed platforms where multiple wells share common wellheads. NORSOK D-010 references the Industry Steering Committee on Wellbore Survey Accuracy (ISCWSA) error models as the baseline. Operators at Troll, Johan Sverdrup, Snøhvit, and Ekofisk submit directional surveys to Sodir as part of standard well filings. Australia's NOPSEMA requires directional survey data in Well Operations Management Plans submitted by Woodside, Santos, INPEX, Chevron Australia, and other operators in Commonwealth waters covering Browse, Carnarvon, and Bass Strait basins. Middle East operators apply API and ISCWSA survey standards supplemented by company-specific requirements. Saudi Aramco's Maximum Reservoir Contact (MRC) wells in Ghawar and the deep gas Jafurah project use multilateral configurations with multiple branches from a single parent wellbore, demanding particularly precise directional work. ADNOC's extended-reach wells in the UAE offshore, Kuwait Oil Company's multilateral Burgan developments, and QatarEnergy's North Field wells all rely on RSS and high-accuracy MWD to meet their subsurface targets. Fast Facts BP's Wytch Farm onshore field in Dorset, England, set the extended-reach drilling benchmark of the 1990s. The M16 well, drilled in 1999, reached a measured depth of 11,275 m (36,992 ft), a horizontal departure of 10,275 m (33,712 ft), and a true vertical depth of only 1,628 m (5,340 ft), accessing reservoirs beneath Poole Harbour from surface locations far inland. The M-15 Wytch Farm well was drilled as a multilateral with two branches of 8,900 m (29,199 ft) and 6,700 m (21,982 ft), an early demonstration of multilateral extended-reach technology that subsequently informed Sakhalin-1, Saudi Aramco MRC wells, and Gulf of Mexico deepwater subsea programs. MWD, LWD, and Geosteering Measurement-While-Drilling (MWD) tools sit in the bottomhole assembly and transmit directional and drilling dynamics data to surface in real time. Core MWD measurements include inclination, azimuth, tool face, rotary speed, downhole vibration, and pressure-while-drilling (PWD). The driller uses inclination and azimuth to verify the well is advancing on the planned trajectory, while tool face indicates the direction of the bent housing for sliding operations with a mud motor. Logging-While-Drilling (LWD) tools extend MWD with formation evaluation sensors: gamma ray, resistivity, density, neutron porosity, sonic, imaging, and magnetic resonance. LWD allows the directional driller to steer based on formation properties rather than only on geometric target coordinates, a practice called geosteering. Geosteering is standard in horizontal shale wells and thin-reservoir offshore wells where keeping the lateral inside a 3 to 10 m (10 to 33 ft) pay zone materially affects EUR. Modern MWD/LWD systems from Schlumberger, Halliburton, Baker Hughes, and Weatherford combine high-speed telemetry (mud-pulse at 6 to 40 bits per second, electromagnetic at up to 100 bits per second, or wired pipe at up to 57,600 bits per second) with real-time data transmission to onshore remote operations centers in Calgary, Houston, Aberdeen, Stavanger, and Dubai. Decision-making on directional adjustments frequently happens within seconds of a downhole measurement reaching surface. Tip: Investors and portfolio managers can track directional drilling efficiency by comparing days-per-foot and cost-per-foot across operators in the same basin. A leading Permian operator using high-build-rate RSS plus wired-pipe telemetry might complete a 4,500 m (14,764 ft) lateral in 6 to 8 drilling days, while a lagging operator with traditional RSS and mud-pulse telemetry takes 10 to 12 days. That gap compounds into USD 2 to 3 million per well and materially changes program-level free cash flow on large acreage positions. Directional Drilling Synonyms and Related Terminology Deviated drilling: older term for non-vertical drilling, still common in engineering specifications. Horizontal drilling: the subset of directional drilling at 80 to 95 degrees inclination. Extended-reach drilling (ERD): directional wells with horizontal displacement more than twice true vertical depth. Slant well: a low-angle deviated well, typical of SAGD thermal oil sands development in Alberta. Multilateral well: a well with multiple lateral branches from a single parent wellbore. Sidetrack: a new wellbore kicked off from an existing well, frequently used to bypass a stuck bottom hole assembly or reach a new target. Geosteering: real-time directional adjustment based on LWD formation data to stay inside a target reservoir. Related terms: Horizontal Drilling, MWD, LWD, Lateral, Casing, Hydraulic Fracturing, Spud, Drilling Fluid. Frequently Asked Questions What is directional drilling in oil and gas? Directional drilling is the practice of deliberately steering a wellbore along a planned non-vertical path. It uses mud motors, rotary steerable systems, and measurement-while-drilling tools to reach subsurface targets that cannot be accessed by a vertical well. Directional drilling enables horizontal shale development, extended-reach wells from onshore pads to offshore reservoirs, multilateral wells with multiple branches, and subsea developments with clustered wellheads. How does directional drilling work? Directional drilling uses either a mud motor with a bent housing or a rotary steerable system to deflect the wellbore from its current trajectory. MWD tools transmit inclination, azimuth, and tool face data to surface, allowing the directional driller to verify position and adjust steering. LWD tools provide formation data that enables geosteering, keeping the lateral inside the target reservoir rock. What is the difference between a mud motor and a rotary steerable system? A mud motor (positive displacement motor with bent housing) generates its steering force by offsetting the bit axis from the drill-string axis. The driller alternates between sliding (motor-only rotation, building or dropping angle) and rotating (full drill-string rotation, drilling straight) to steer. A rotary steerable system applies side force at the bit while the entire drill string rotates continuously, eliminating sliding and delivering faster, smoother wellbores. RSS costs more per day but typically finishes laterals faster. Why Directional Drilling Matters in Oil and Gas Directional drilling is the enabling technology behind nearly every form of modern oil and gas development. Shale plays across the Permian, Bakken, Marcellus, Montney, Duvernay, and Vaca Muerta depend on it. Extended-reach wells at Sakhalin-1, Wytch Farm, and Saudi Aramco's Manifa depend on it. Deepwater subsea tiebacks from the North Sea to the Gulf of Mexico to offshore Brazil depend on it. For the directional driller on a Midland Basin horizontal, the RSS engineer troubleshooting a PowerDrive in Abu Dhabi, the geosteering operator watching a Duvernay lateral in Calgary, and the portfolio manager tracking days-per-foot efficiency for an upstream valuation, directional drilling sits at the center of how the industry turns subsurface targets into surface production.

Permeability that varies with direction of flow through the porous medium. Lateral permeability contrast can be particularly important in fractured formations, where effective permeability in the direction of the fractures may be many times greater than the matrix permeability. If the permeability in one direction is significantly more than in the other, the flow pattern may more closely approximate linear flow than radial flow. This can be detected from well-test data.Likewise, laminations in most clastic formations cause the permeability normal to the bedding plane to be less than the lateral permeability parallel to bedding. This is called vertical to horizontal permeability anisotropy.

Variograms and semivariograms that have a directional component in addition to the normal distance component. Directional variograms and semivariograms are commonly used where geological features are heterogeneous. For example, fluvial environments dominated by valleys, channels and point bars are likely to have directional components that are detectable and that will influence the behavior of fluids in these formations. Geostatistical models that use directional variograms can be expected to be more reliable in these circumstances.

A wellbore that requires the use of special tools or techniques to ensure that the wellbore path hits a particular subsurface target, typically located away from (as opposed to directly under) the surface location of the well.

The property of some seismic sources whereby the amplitude, frequency, velocity or other property of the resulting seismic waves varies with direction. A directional charge, such as a length of primer cord or a linear array of charges, can be used when directivity is desirable. Directivity is also a property of geophone arrays, air guns, explosives or vibrators, which can be positioned to reduce horizontal traveling noise such as ground roll. Receivers in the form of groups in which the individual geophones or hydrophones are separated from each other in linear (1D) or areal (2D) arrays are directional, and are designed to suppress signal arriving nearly horizontally and to pass nearly vertical arrivals with minimum attenuation or distortion. Directivity is often present, but the difficulty in accounting for it during seismic processing makes it undesirable in most cases.

Describing sedimentaryrock that contains clay minerals. Even small amounts of clay minerals in pores can drastically reduce porosity and permeability. Dirty and clean are qualitative, descriptive terms to describe the relative amount of clay minerals in a rock.

A common coating problem in which the protective coating detaches from the pipeline.

A geologic surface that separates younger strata from older strata and represents a time of nondeposition, possibly combined with erosion. Some disconformities are highly irregular whereas others have no relief and can be difficult to distinguish within a series of parallel strata.

A subsurface boundary or interface at which a physical quantity, such as the velocity of transmission of seismic waves, changes abruptly. The velocity of P-waves increases dramatically (from about 6.5 to 8.0 km/s) at the Mohorovicic discontinuity between the Earth's crust and mantle.

Pertaining to structures in which the shapes of adjacent layers differ or do not conform to one another. Folds of rock layers that have different mechanical properties or competence tend to be disharmonic, with a change in fold shape, symmetry or wavelength from one layer to the next.

A chemical that aids in breaking up solids or liquids as fine particles or droplets into another medium. This term is often applied incorrectly to clay deflocculants. Clay dispersants are various sodium phosphates and sodium carbonates aided by heat, mechanical shearing and time. Powdered polymers are dispersed by precoating the particles with a type of glycol to prevent formation of "fish-eye" globules. For dispersing (emulsification) of oil into water (or water into oils), surfactants selected on the basis of hydrophile-lipophile balance (HLB) number can be used. For foam drilling fluids, synthetic detergents and soaps are used, along with polymers, to disperse foam bubbles into the air or gas.

(noun) A multiphase flow regime in a pipe or wellbore characterised by small gas bubbles distributed uniformly throughout a continuous liquid phase at relatively high liquid velocities, where the buoyancy forces are insufficient to cause significant gas-phase segregation or coalescence.

Clay that is scattered throughout the pore space. There are three general types: pore lining, pore filling and pore bridging. The terms dispersed clay and dispersed shale tend to be used synonymously.

Spatial separation of components within a fluid. This separation is often driven by diffusion, mixing or differential flow. In an oil field components might be separated because of heterogeneity of permeability, or simply because of different paths taken by the fluid through the pore structure. Hydrodynamic dispersion includes both of these mechanical effects and molecular diffusion. The components of an enhanced oil recovery formulation can also be dispersed within a porousrock via differential adsorption properties (chromatographic effects).

The act of forcing a cementslurry that has been pumped into a casing string or drillstring to exit the bottom of the casing or drillstring by pumping another fluid behind it. Cement displacement is similar to definition 5 above, with the noted exception that the cement slurry would not normally be pumped out the top of the annulus, but would instead be placed in a particular location in the annulus. This location might be the entire annulus on a short casing string, or filling only a bottom portion of the casing on longer casing strings.

The fraction of oil that has been recovered from a zone swept by a waterflood or other displacement process. Displacement efficiency equation:

The fluid, usually drilling mud, used to force a cementslurry out of the casing string and into the annulus.

The interface between an injectant and the fluid it is displacing.

A well, often a depleted oil or gas well, into which waste fluids can be injected for safe disposal. Disposal wells typically are subject to regulatory requirements to avoid the contamination of freshwater aquifers.

In water analysis, the soluble components in a sample or the residue left after evaporation of a sample. Dissolved solids are reported as ppm or mg/L. Dissolved solids are included in retort solids and can be calculated from chemical analysis results by assuming that all dissolved solids are either NaCl or CaCl2, or a mixture of the two.

A technique for cleaning core samples in which the water fraction is removed by distillation and the oil fraction is extracted using solvents. Cleaning is done with either the Soxhlet or, when fluid saturation measurements are required, the Dean-Stark apparatus. Different solvents are used depending on the type of fluids and rock, the most common ones being toluene, methanol, xylene and chloroform. Several solvents may be used in sequence.

A change in a waveform that is generally undesirable, such as in seismic waves.

A record of the change in temperature along a well, normally recorded by a fiber-optic cable. The distributed temperature is measured by sending a pulse of laser light down the optical fiber. Molecular vibration, which is directly related to temperature, creates weak reflected signals. These signals are detected at the surface and converted to a log of temperature along the well, sampled approximately every 1 m [3.28 ft] with a resolution of 0.1oC. The fiber-optic cable is normally installed at the time of well completion, so that the distributed-temperature log can be recorded at any later time without well intervention.Introduced in the mid-1990s, the technique can also be used to measure flow rates by creating a temperature transient and observing its movement along the well.

The variation in the values of a one-dimensional data set. There are a number of readily recognized, possible distributions known to statistics, each with mathematical definitions. Statisticians may endeavor to find whether a data set is a good fit to any of the recognized distributions. Some examples include:bimodalBoltzmannchi-squaredgeneral normalGaussian or standard normal (bell-shaped curve)normalPoissonstudent's t.

The daily variation in properties of the Earth, such as the temperature or the local geomagnetic field, or the daily change in sunlight. Such variations depend in part on latitude, proximity to the ocean, the effects of solar radiation and tides and other factors.

In Cartesian coordinates, divergence is the sum of the partial derivatives of each component of the vector field with respect to the corresponding spatial coordinate:

A technique used in injection treatments, such as matrixstimulation, to ensure a uniform distribution of treatment fluid across the treatment interval. Injected fluids tend to follow the path of least resistance, possibly resulting in the least permeable areas receiving inadequate treatment. By using some means of diversion, the treatment can be focused on the areas requiring the most treatment. To be effective, the diversion effect should be temporary to enable the full productivity of the well to be restored when the treatment is complete. There are two main categories of diversion: chemical diversion and mechanical diversion.

A device for measuring in-situ the velocity of fluid flow in a production or injection well in which the total fluid flow is diverted to pass over an impeller, or spinner. Various techniques have been used to achieve this, one of the earliest being the packer flowmeter. In a typical modern device, the diverter consists of a fabric in a metal cage that is collapsed to pass through the tubing and other restrictions. Below the tubing, the cage is opened until an inflatable ring seals against the casing wall. At this point, the up-going production fluids are forced through the diverter and over an impeller. This ensures that the total casing flow is measured, but may also create an extra pressure drop and hence a change in multiphaseflow structure.The diverter flowmeter is particularly suitable for low flow rates in vertical or moderately deviated wells. Readings are made with the tool stationary.

An agreement between the operator and net revenue interest (NRI) owner in which the parties specify the fractional type of interest attributed to the NRI owner by the operator after an examination of title.

A safety device used when running and retrieving tools or drill collars with a flush external surface that may easily pass through the rotary table slips. The dog collar is temporarily attached to the assembly between the tool joint and the slips. If the slips fail to hold the tool assembly, the dog collar will prevent the entire assembly from dropping through and being lost in the wellbore.

The steel-sided room adjacent to the rig floor, usually having an access door close to the driller's controls. This general-purpose shelter is a combination tool shed, office, communications center, coffee room, lunchroom and general meeting place for the driller and his crew. It is at the same elevation as the rig floor, usually cantilevered out from the main substructure supporting the rig.

An abrupt turn, bend or change of direction in a survey line, a wellbore, or a piece of equipment. Dog-legs can be described in terms of their length and severity and quantified in degrees or degrees per unit of distance.

The steel-sided room adjacent to the rig floor, usually having an access door close to the driller's controls. This general-purpose shelter is a combination tool shed, office, communications center, coffee room, lunchroom and general meeting place for the driller and his crew. It is at the same elevation as the rig floor, usually cantilevered out from the main substructure supporting the rig.

An abrupt turn, bend or change of direction in a survey line, a wellbore, or a piece of equipment. Dog-legs can be described in terms of their length and severity and quantified in degrees or degrees per unit of distance.

The name given to dolomitized limestone.

The geochemical process in supratidal sabkha areas where magnesium [Mg] ions from the evaporation of seawater replace calcium [Ca] ions in calcite, forming the mineraldolomite. The volume of dolomite is less than that of calcite, so the replacement of calcite by dolomite in a rock increases the pore space in the rock by 13% and forms an important reservoir rock. Dolomitization can occur during deep burial diagenesis.

A rock composed chiefly (> 90%) of dolomite. The rock is sometimes called dolomite, but dolostone is preferable to avoid ambiguity between the mineral and rock names. Replacement dolomite that forms soon after deposition is typically fine-grained and preserves original sedimentary structures. Recrystallization late in diagenesis produces coarser grained dolomite, destroys sedimentary structures and results in higher porosity.

The set of values assigned to the independent variables of a function.

A structure made up of a number of superposed domains, usually of different size or wavelength. These are used in geostatistical work to describe statistical behaviors on small scales (such as porosity in thin sections) to large scales (such as porosity distributions in reservoirs).

(noun) A geological feature in which a rock mass is divided into distinct structural domains, each with its own characteristic deformation style, fabric orientation, or strain pattern. In structural geology, domainal analysis is used to evaluate heterogeneous deformation in folded and faulted terrains.

A type of anticline that is circular or elliptical rather than elongate. The upward migration of salt diapirs can form domes, called salt domes.

Slang term to describe a seismologist performing seismic field work.

To place lubricant on drillpipe, also known as "doping" the pipe.

A low-volume fluid pump with controllable discharge rate used to inject chemical additives to the mixing or pumping system. Dosing pumps frequently are used to inject fluids that may be difficult to mix efficiently in batch-tank systems because of their low volume.

Located down the slope of a dipping plane or surface. In a dipping (not flat-lying) hydrocarbonreservoir that contains gas, oil and water, the gas is updip, the gas-oil contact is downdip from the gas, and the oil-water contact is still farther downdip.

A pressure gauge, typically run on slickline, used to measure and record downhole pressure. Downhole gauges are commonly used in assessing the downhole pressure under various flowing conditions, the basis of pressure transient analysis.

A receiver located in a wellbore, as opposed to a location on the Earth's surface.

A downhole device that isolates wellbore pressure and fluids in the event of an emergency or catastrophic failure of surface equipment. The control systems associated with safety valves are generally set in a fail-safe mode, such that any interruption or malfunction of the system will result in the safety valve closing to render the well safe. Downhole safety valves are fitted in almost all wells and are typically subject to rigorous local or regional legislative requirements.

Mechanical or electronic devices for measuring various properties in the well such as pressure, fluid flow rate from each branch of a multilateral well, temperature, vibration, composition, fluid flow regime, and fluid holdup. These devices can be permanent; in this case, they are left in place for months or even years.

A seismic source located in a wellbore rather than at the Earth's surface.

The termination of more steeply dipping overlying strata against a surface or underlying strata that have lower apparent dips; a term used to describe a particular geometry of reflections in seismic data in sequencestratigraphy.

Pertaining to equipment, facilities or systems that are located in the production train after the surface choke, typically attached or close to the Christmas tree.

A pipeline that receives natural gas or oil from another pipeline at some specific connection point

The portion of movement of a downhole pump at which the rods are going down and the downhole pump is being filled with fluid.

A technique used to estimate the value of a potential field or seismic data at a surface beneath a measured surface. The method is risky because it assumes continuity of the field, so anomalies affect predictions, especially if they occur beneath the measured surface. Noise can be exaggerated and affect calculations adversely.

Pertaining to a technique in which a packerflowmeter is partially inflated and dragged up the hole to give a continuous flow log. This obsolete technique was introduced in the 1960s because the packer flowmeter could make only stationary measurements.

The process of forcing a nonwetting phase into a porousrock. Oil migrates into most reservoirs as the non-wetting phase, so initial charging of the reservoir is a drainage process.

The reservoir area or volume drained by the well. The terms drainage area, reservoir area and drainage volume are often incorrectly used interchangeably. When several wells drain the same reservoir, each drains its own drainage area, a subset of the reservoir area.

The portion of the volume of a reservoir drained by a well. In a reservoir drained by multiple wells, the volume ultimately drained by any given well is proportional to that well's production rate:Vi = Vt x qi/qt,where Vi is the drainage volume of Well i, Vt is the entire drainage volume of the reservoir, qi is the production rate from Well i, and qt is the total production rate from the reservoir.

A hole or short conduit through which fluids can flow. In equipment applications, a drainhole is generally made to avoid the buildup of pressure within a nonpressure area, such as may occur in the event of a leak in a pressure housing within a tool assembly.

A configuration of layers of rock that has the appearance of a fold, but might form simply through sagging or differential compaction of layers around a preexisting structure (such as a reef) or on an uneven surface.

The difference in height between the static level and the dynamic level in a pumping well, expressed as hydrostatic fluid pressure.

The measurement and analysis of pressure data taken after a well is put on production, either initially or following an extended shut-in period. Drawdown data are usually noisy, meaning that the pressure moves up and down as fluid flows past the gauges and minute variations in flow rate take place. This is especially true for new wells, in which well cleanup commonly occurs for days after production has begun. Such data are difficult to interpret, and the noise often obscures regions of interest to the analyst. Transient downhole flow rates measured while flowing can be used to correct pressure variations through convolution or deconvolution calculations that enable diagnosis and interpretation, analogous to that done for the pressure change and derivative.

What Are Drawworks? The drawworks hoists and lowers the drill string, casing strings, and completion equipment through a crown block and traveling block system by spooling and unspooling heavy steel wire rope on a large-diameter drum, converting prime mover torque into the vertical lifting force that controls weight on bit and manages the entire casing and BHA during every tripping operation. It is the central power-transmission unit of every rotary drilling rig worldwide. Key Takeaways The drawworks drum spools drilling line that runs through a crown block at the top of the derrick and a traveling block below it, creating a mechanical advantage block-and-tackle system that multiplies the prime mover force into hook load capacity. Modern AC-electric drawworks are rated from 500 hp (373 kW) on workover rigs to 3,000 hp (2,237 kW) on ultra-deepwater drillships; hook load capacity ranges from 250 tonnes (551,000 lb / 551 kips) to over 1,350 tonnes (2,976,000 lb / 2,976 kips). Drawworks specifications are evaluated by drilling contractors bidding on rig contracts, drilling engineers designing well programs, and investors assessing rig capability against planned well depths and casing weights. Regulatory bodies overseeing drawworks inspection and load certification include the AER in Alberta, BSEE in the US Gulf of Mexico, and NORSOK D-001 plus the Norwegian Petroleum Safety Authority (PSA) in Norway. The drawworks brake system is a safety-critical component: brake failure with a fully loaded drill string can result in a freefall event, potentially driving the bit through the bottom of the hole and causing catastrophic wellbore damage or a well control incident. How Drawworks Work The drawworks drum is a large-diameter steel cylinder, typically 800 mm to 1,400 mm (31.5 to 55 in) in diameter, around which multiple layers of wire rope are spooled. The wire rope, called drilling line, runs from the drum up through a set of sheaves in the crown block at the derrick top, back down through the traveling block hanging below, and the free end is anchored to a deadline anchor bolted to the rig substructure. On a 12-line system, the rope makes six passes between crown and traveling block, providing a 12:1 mechanical advantage before accounting for friction losses. A 3,000 hp (2,237 kW) drawworks on a 12-line reeving can generate over 1,350 tonnes (2,976,000 lb) of hook load. API Specification 7K governs the design and rated capacity of drawworks, setting out drum dimensions, gear ratios, brake torque requirements, and documentation standards. The prime mover, originally diesel engines through mechanical transmissions and now typically AC electric motors fed by diesel-generator sets or grid power, drives the drum through a transmission that provides multiple speed ranges. High gear gives fast line speed for tripping operations, typically 150-300 m/min (490-980 ft/min) at low hook load. Low gear gives high torque for lifting heavy casing strings at slow speeds. AC VFD systems eliminate mechanical gear changes entirely, providing continuously variable speed and torque across the operating range. This gives the driller precise control over weight on bit by adjusting hook load in increments as fine as 0.5 tonne (1,100 lb), which is critical for optimizing ROP in heterogeneous formations. The auxiliary or sand-reel drum, a smaller secondary drum on the same drawworks frame, handles the geophysical logging line, coring equipment, and completion tools. Some rigs include a third drum for handling the drilling line during slip-and-cut procedures required by API RP 9B to retire worn sections of wire rope before they fail in service. The slip-and-cut interval is calculated based on accumulated tonne-km (or ton-mile) of service, a measure of the mechanical work done by the wire rope that accounts for both load and distance traveled. Drawworks Across International Jurisdictions In Alberta's Montney and Deep Basin plays, drilling contractors such as Precision Drilling and Ensign Energy Services operate high-spec land rigs with AC drawworks rated at 1,500-2,000 hp (1,119-1,491 kW). AER Directive 059 requires that hoisting equipment ratings appear in the well license application and that no drilling operation exceed the equipment's rated hook load. Precision Drilling's Tier 1 pad rigs use regenerative AC drawworks that feed braking energy back into the rig power bus, reducing diesel fuel consumption by up to 15 percent on deep Montney wells where frequent tripping dissipates significant energy. In the Permian Basin, Nabors Industries, Patterson-UTI, and Pioneer Natural Resources' contracted rig fleets use 2,000-3,000 hp (1,491-2,237 kW) drawworks on super-spec rigs designed for 3,000-4,600 m (9,843-15,092 ft) vertical depths plus 3,000 m (9,843 ft) horizontal laterals. BSEE's 30 CFR Part 250 requires that offshore drawworks pass annual third-party inspection by a qualified certifying authority such as ABS or DNV-GL. Gulf of Mexico deepwater rigs use tandem drawworks systems where two independent units share the load for hook loads exceeding 1,000 tonnes (2,205,000 lb). On Norway's Continental Shelf, Equinor, Aker BP, and Vår Energi drill under NORSOK D-001 requirements, which mandate drawworks load testing, brake certification, and documented maintenance intervals. The Petroleum Safety Authority Norway (PSA) audits rig maintenance records including drawworks brake inspections as part of its consent-to-drill process. Transocean's high-specification semisubmersibles operating at Johan Sverdrup carry 7,500 kW (10,055 hp) combined AC drawworks capable of handling 3 million lb (1,361 tonne) hook loads. Saudi Aramco's drilling program, the largest single-operator drilling program in the world, standardizes drawworks specifications in its rig contract requirements. Onshore rigs at Ghawar use 2,000-3,000 hp (1,491-2,237 kW) drawworks. ADNOC's offshore operations in Abu Dhabi use jackup rigs with drawworks rated to 1,000 tonnes (2,205,000 lb) for conductor and surface casing programs on the shallow-water fields of the Arabian Gulf. Fast Facts The Noble Globetrotter II drillship, operating in the Gulf of Mexico in waters up to 3,658 m (12,000 ft) deep, carries a drawworks system rated at 15,000 kW (20,110 hp) combined power to handle drill string weights exceeding 1,000 tonnes (2,205,000 lb) in ultra-deepwater operations where the drill string itself weighs more than the surface equipment on most land rigs. Drawworks Brake Systems and Safety Design The brake system is the most safety-critical element of the drawworks. Three independent braking mechanisms work together: the primary mechanical band brake, the auxiliary brake (electromagnetic or hydraulic), and the emergency deadman brake. The primary band brake uses heat-resistant friction material pressed against brake drums on the drawworks drum shaft. A skilled driller can control hook descent to within millimeters per second through hand pressure on the brake lever, a skill that takes months to develop and years to master. Modern automated brake control systems use load cells on the deadline anchor to measure hook load continuously and adjust brake torque automatically to maintain a setpoint descent rate. Electromagnetic auxiliary brakes use eddy current principles: a rotating conductor disc passes between electromagnet poles, and the induced eddy currents create a braking force proportional to rotational speed and magnetic field strength. This "regenerative" braking converts kinetic energy to heat in the magnet housing rather than in friction material, dramatically extending brake wear life. At full hook load of 1,000 tonnes (2,205,000 lb) descending at 60 m/min (197 ft/min), the electromagnetic brake absorbs approximately 9,800 kW (13,140 hp) of power, equivalent to a large diesel locomotive at full throttle. AC regenerative drawworks redirect this energy into the rig power bus. Hydraulic retarder brakes use viscous fluid shear to absorb energy, offering smooth continuous braking torque independent of drum speed. They are common on medium-duty rigs where electromagnetic brakes are cost-prohibitive. The emergency deadman brake engages automatically if the driller releases the brake lever without the drawworks being in a locked or powered state, preventing accidental freefall. API Spec 7K requires that the deadman system be tested at the rated hook load before every well spud, and BSEE regulations require documentation of this test in the well file. Wire rope management follows API RP 9B guidelines. Drilling line is inspected visually every tour (typically 12 hours) and measured for diameter reduction and core protrusion. Slip-and-cut procedures retire the most heavily worn portion of the line at calculated tonne-km intervals. A typical deepwater well accumulates 50,000-100,000 tonne-km of wire rope service. The deadline anchor load cell monitors deadline tension continuously, and the ratio of fast-line tension to deadline tension indicates sheave bearing condition and system friction losses. Tip: A field engineer can calculate the number of lines strung through the block by counting the rope segments visible between crown block and traveling block. Increasing lines from 10 to 12 reduces fast-line tension by 17 percent, extending wire rope life significantly on a deep well program. Investors evaluating drilling contractors should check whether rigs carry AC regenerative drawworks, which reduce fuel cost by 12-20 percent and indicate a modern, capital-efficient rig fleet. Drawworks Synonyms and Related Terminology Hoist: The generic engineering term used in international rig documentation, particularly in Middle Eastern and European contracts, referring to the complete hoisting system including drawworks, blocks, and wire rope. Drum: Field shorthand for the drawworks, used by drillers in North America: "put it on the drum" means engage the drawworks to hoist the string. Block and tackle: The crown block and traveling block system that multiplies the drawworks force; sometimes used loosely to refer to the entire hoisting system. Fast line: The wire rope segment running directly from the drawworks drum to the first crown block sheave, carrying the highest tension in the system. Related terms: rotary table, casing, BHA, drilling contractor Frequently Asked Questions What does a drawworks do on a drilling rig? The drawworks is the rig's primary hoisting machine. It raises and lowers the drill string, casing, and completion tools through a crown block and traveling block system using heavy wire rope. By controlling drum rotation speed and the brake system, the driller manages the weight on bit during drilling and the tripping speed during pipe handling operations. The drawworks is also used to set slips, run casing, and position the traveling block for every connection and stand change. How is drawworks power rated? Drawworks are rated in horsepower (hp) or kilowatts (kW) of input power and in hook load capacity expressed in kips (thousands of pounds) or tonnes. A 3,000 hp (2,237 kW) drawworks on a 12-line block system might deliver a maximum hook load of 1,200-1,350 tonnes (2,646,000-2,976,000 lb) depending on mechanical efficiency. The input horsepower determines the maximum hoisting speed at a given load; hook load capacity is set by wire rope rating, block sheave pin loads, and derrick structure rating. What is the difference between AC and DC drawworks? DC drawworks use direct current electric motors with mechanical commutators, providing variable speed through armature voltage control. AC drawworks use alternating current motors with variable frequency drives (VFDs) for speed control. AC systems have fewer moving parts, lower maintenance cost, better dynamic braking performance, and can regenerate braking energy back into the rig power bus. Nearly all new land rigs and offshore rigs built since 2005 use AC systems. DC rigs remain in service but are being retired from high-spec programs. Why Drawworks Matters in Oil and Gas The drawworks is the mechanical heart of every drilling rig, translating prime mover power into the precise vertical control that determines whether a well is drilled safely, on time, and on budget. Its capacity limits determine the maximum well depth and casing weights a rig can handle, directly influencing which prospects a drilling contractor can pursue. Brake reliability is a primary safety determinant: drawworks failures have contributed to some of the industry's most costly well incidents. For investors and operators evaluating rig capabilities, understanding drawworks ratings, drive technology, and maintenance standards provides a clear window into rig performance and operational risk across every major producing basin from the Alberta foothills to the deepwater fields of the Middle East.

An accurately machined device that is pulled through the casing, tubulars and completion components to ensure minimum-diameter specifications are within tolerance, as described in definition 2. While this tool is usually of a short length, the well planner may specify a special drift that either has a longer length or a nonstandard outside diameter. The large-diameter casing drifts are frequently known as "rabbits."

What Is a Drill Collar? A drill collar provides the weight on bit (WOB) and compressive stiffness needed to keep the bottom hole assembly on trajectory by placing the heavy, thick-walled pipe section directly above the bit in compression, preventing the lighter drill pipe above from buckling, and supplying the axial force that drives the cutting structure into the formation, manufactured to API Specification 7-2 with outside diameters from 79 mm (3-1/8 in) to 279 mm (11 in). Key Takeaways Drill collars function in compression rather than tension like drill pipe, using their weight to apply force to the bit while the drill pipe above remains in tension to prevent buckling and string failures. Standard drill collar unit weights range from 29 kg/m (19.5 lb/ft) for a 79 mm (3-1/8 in) OD collar to 296 kg/m (199 lb/ft) for a 279 mm (11 in) OD collar; typical WOB applied through drill collars runs 44-222 kN (10,000-50,000 lb). Drilling engineers, directional drillers, and BHA designers specify drill collar dimensions; drilling contractors supply the collars; company representatives and regulators verify BHA design compliance with approved well programs. API Specification 7-2 governs drill collar manufacturing in North America and internationally; NORSOK D-001 in Norway and AER Directive 059 in Canada incorporate API 7-2 requirements by reference for drilling program review. Nonmagnetic (monel) drill collars placed around MWD and LWD tools prevent the magnetic steel collar body from corrupting the magnetometer readings used for directional surveying. How Drill Collars Work The drill collar's fundamental mechanical function exploits a basic structural principle: a column of pipe running in tension does not buckle, while a column running in compression beyond its critical load will buckle, contact the wellbore wall, and cause deviation from the intended trajectory. Drill pipe is relatively thin-walled and will buckle sinusoidally, then helically, at compressive loads well below what is needed to drive a bit into rock. Drill collars, with their thick walls and heavy cross-sectional areas, have a much higher critical buckling load and can safely carry the WOB in compression. The neutral point, where the string transitions from compression below to tension above, should always fall within the drill collar section, never in the drill pipe, to protect the lighter pipe from cyclic bending fatigue. Wall thickness is the defining characteristic of a drill collar compared to drill pipe. A 6-5/8 in (168 mm) OD drill collar has a typical ID (inner diameter) of 2-13/16 in (71 mm), giving a wall thickness of approximately 48 mm (1.9 in). A 6-5/8 in OD drill pipe joint has a wall thickness of only 9-11 mm (0.35-0.43 in). This massive wall thickness gives the drill collar its weight per foot, its stiffness, and its resistance to the compressive fatigue forces generated by WOB cycles, vibration, and tool rotation. API Specification 7-2 sets out the dimensional tolerances, minimum wall thickness requirements, and straightness standards for drill collars, requiring a maximum bow of 0.5 mm/m (0.006 in/ft) over the entire collar length for standard service. Drill collars are manufactured in standard lengths of 9.14 m (30 ft) for slick (non-spiral) collars and 9.5 m (31.2 ft) for spiral collars. Spiral grooves machined into the collar OD reduce the contact area between collar and wellbore wall, lowering differential sticking risk in permeable formations. The spiral reduces OD contact by approximately 35 percent compared to a slick collar of the same OD, significantly reducing the force required to free a differentially stuck string. API 7-2 specifies allowable spiral profiles, groove depth, and width to ensure the structural integrity of the collar body is not compromised by the grooving. Drill Collar Across International Jurisdictions In Canada's Deep Basin and Montney plays of Alberta, BHA designs for 4,500-6,000 m (14,764-19,685 ft) wells typically use five to eight 8 in (203 mm) OD drill collars providing 90,000-140,000 lb (400-623 kN) of available WOB, plus two nonmagnetic monel collars surrounding the MWD/LWD tools. Precision Drilling and Ensign Energy Services maintain drill collar inventories at their major Canadian rig yards. AER Directive 059 requires that the BHA string description including collar dimensions appear in the approved well program before spud, and that any changes to the BHA during drilling be documented in the morning report and the AER-format daily drilling log. In the US Permian Basin, WOB requirements for drilling through hard Permian carbonates and cemented sandstones run toward the high end of the typical range: 30,000-50,000 lb (133-222 kN) for PDC bits in the Bone Spring and Wolfcamp formations. Pioneer Natural Resources (now ExxonMobil), Devon Energy, and ConocoPhillips design BHAs with 8-12 drill collars per run. BSEE requires that offshore BHA descriptions including collar sizes and weights appear in the well permit application and that deviations from the permitted BHA be reported within 24 hours. On Norway's Continental Shelf, Equinor and Aker BP operate under NORSOK D-001, which requires that BHA design documents be prepared by a certified drilling engineer and approved before each well phase. Drill collar procurement for North Sea operations follows both API 7-2 and NORSOK M-120 material standards for high-strength drill string components. The Johan Sverdrup platform wells use BHAs with 7 in (178 mm) OD drill collars in the 8-1/2 in (216 mm) hole section and 4-3/4 in (121 mm) OD collars in the 6 in (152 mm) reservoir section, all nonmagnetic to protect MWD accuracy in the deviated wellbore trajectories required by the platform slot pattern. Saudi Aramco's high-volume drilling program for Ghawar and Shaybah fields uses standardized BHA designs approved through the company's Drilling Engineering department. Monel drill collars for MWD tools are provided by Saudi Aramco's in-house drill string inventory, the largest single operator inventory in the world. ADNOC Drilling in Abu Dhabi specifies collar sizes in its contractor rig packages, with 6-3/4 in (171 mm) collars standard for 8-1/2 in (216 mm) hole sections in the Arab Formation carbonates of the Zakum and Asab fields. Fast Facts A single 9.14 m (30 ft) long, 8 in (203 mm) OD drill collar weighs approximately 1,600 kg (3,527 lb) in air and is machined from a single billet of 4145H modified chromium-molybdenum alloy steel heat-treated to yield strength of 120,000 PSI (827 MPa), making it one of the most metallurgically demanding and precisely toleranced components in the entire drill string. Drill Collar Types, Grades, and Nonmagnetic Specifications Slick drill collars are the standard type: a plain cylindrical body with no external features except the threaded connection boxes at each end. They are used in the majority of BHA configurations below the MWD/LWD tool section. Spiral drill collars, as described above, add machined grooves to reduce differential sticking risk. Monel (nonmagnetic) drill collars are manufactured from Monel K-500, a nickel-copper alloy with very low magnetic permeability (typically less than 1.01 relative permeability versus 100+ for carbon steel). MWD directional sensors are placed inside monel collars to prevent the magnetic field of the steel collar body from biasing the magnetometer readings used to compute azimuth. The minimum nonmagnetic spacing required around an MWD magnetometer depends on the local magnetic inclination and the accuracy requirement for the survey. In high-latitude regions of Canada and Norway where the magnetic dip angle is steep, longer nonmagnetic spacing is required: typically 24 m (79 ft) or more of monel collars surrounding the sensor. At lower latitudes in the Middle East, 12 m (39 ft) of nonmagnetic spacing may be sufficient. Directional drilling service companies including SLB, Halliburton, and Baker Hughes provide nonmagnetic spacing calculations for each well based on the local magnetic field parameters, well profile, and required survey accuracy. OD and ID tolerances for API 7-2 drill collars are tightly controlled. OD tolerance is +0.79 mm / -0.79 mm (+1/32 in / -1/32 in) of nominal. ID tolerance is +1.59 mm / -0 mm (+1/16 in / -0) of nominal. These tolerances ensure compatibility with drill pipe connections and BOP ram sizing. The bore ID must be sufficient to pass the expected mud flow rates without excessive annular velocity losses; typical IDs of 2-13/16 in (71 mm) allow flow rates of 600-2,500 L/min (160-660 gpm) for 6-3/4 in (171 mm) to 9-1/2 in (241 mm) hole sizes. Connections are API NC38, NC46, NC50, 6-5/8 FH, or other standard API thread profiles matching the drill pipe connections used in the well program. Drill collar condition monitoring follows API RP 7G guidelines. Visual inspection checks for corrosion pitting, fishing neck damage, and thread wear. Dimensional inspection measures OD wear (allowing up to 5 percent OD reduction) and ID enlargement. Magnetic particle inspection or dye penetrant testing checks for fatigue cracks at the stress concentration points: the pin base, box shoulder, and any spiral groove termination. Collars with cracks or OD wear exceeding 5 percent are downgraded or retired. A typical drill collar has a service life of 3,000-8,000 rotating hours depending on application severity. Tip: When selecting drill collar OD for a new well program, size the collar to 75-85 percent of the bit OD to ensure adequate annular clearance for cuttings transport while maximizing available weight per foot. An 8-1/2 in (216 mm) hole section works optimally with 6-3/4 in (171 mm) collars (79 percent of bit OD), which provide 79 kg/m (53 lb/ft) unit weight. Investors reviewing drilling programs should note that operators using undersized collars in hard formations often struggle with low ROP and bit damage, directly inflating cost per foot metrics. Drill Collar Synonyms and Related Terminology DC: Drill collar, the standard field abbreviation used in BHA diagrams, morning reports, and well cost tracking spreadsheets. Monel collar: A nonmagnetic drill collar manufactured from Monel K-500 nickel-copper alloy; sometimes called a "non-mag collar" or simply "non-mag" in the field. Slick collar: A plain-OD drill collar without spiral grooves; distinguishes it from spiral drill collars in BHA specification documents. Heavy-wall drill pipe (HWDP): A drill pipe product with wall thickness intermediate between standard drill pipe and drill collars; used as a transition element between the drill collar section and standard drill pipe, particularly in directional wells where reducing WOB oscillations is important. Related terms: BHA, MWD, LWD, rotary table, kelly, directional drilling, well control Frequently Asked Questions What is a drill collar and what does it do? A drill collar is a thick-walled, heavy steel pipe placed in the bottom hole assembly directly above the drill bit. Its primary purpose is to provide weight on bit (WOB), the compressive downward force needed to push the bit into the formation at the desired penetration rate. Its secondary purpose is to keep the BHA in compression so the lighter drill pipe above stays in tension and does not buckle. Without drill collars, drilling through hard rock formations would be impractical because standard drill pipe would buckle long before generating sufficient WOB. How much weight do drill collars provide? Drill collar weight per unit length depends on the OD, ID, and steel density (approximately 7,850 kg/m3 or 490 lb/ft3). A 6-3/4 in (171 mm) OD collar weighs approximately 79 kg/m (53 lb/ft) in air and about 68 kg/m (46 lb/ft) in 1.5 SG (12.5 ppg) drilling fluid due to buoyancy. A typical BHA string of eight such collars in a 9.14 m (30 ft) length provides approximately 4,960 kg (10,936 lb) of available WOB at the bit, well within the 10,000-50,000 lb (44-222 kN) range typical for most PDC and roller-cone bit programs. Why are nonmagnetic drill collars used near MWD tools? MWD directional tools contain magnetometers that measure the Earth's magnetic field to calculate the drill string's azimuth (compass direction). If standard steel drill collars surround the magnetometers, the strong magnetic field of the steel corrupts the readings. Nonmagnetic collars made from Monel K-500 or other low-permeability alloys have negligible magnetic properties, allowing the magnetometer to measure only the Earth's true field. The required length of nonmagnetic spacing depends on the survey accuracy needed and the local magnetic field inclination angle.

A special fluid designed exclusively for drilling through the reservoir section of a wellbore. The reasons for using a specially designed mud are: (1) to drill the reservoir zone successfully, often a long, horizontal drainhole. (2) to minimize damage and maximize production of exposed zones. (3) to facilitate the well completion needed, which can include complicated procedures. A drill-in fluid should resemble a completion fluid. It may be a brine containing only selected solids of appropriate particle size ranges (salt crystals or calcium carbonate) and polymers. Only additives essential for filtration control and cuttings carrying are present in a drill-in fluid.

Formation solids contained in a mud system, generally considered to be detrimental to the drilling operation because they produce high plasticviscosity, yield point and gel strengths and build poor-quality filter cakes. They also occupy space that is needed for barite in high-density muds. Drill solids cause excessive wear in the mud pumps and other rig equipment. Solids control is aimed at economically and efficiently removing drill solids. This implies removal as soon as possible after they enter the mud system, while the particles are at their largest size.

A special fluid designed exclusively for drilling through the reservoir section of a wellbore. The reasons for using a specially designed mud are: (1) to drill the reservoir zone successfully, often a long, horizontal drainhole. (2) to minimize damage and maximize production of exposed zones. (3) to facilitate the well completion needed, which can include complicated procedures. A drill-in fluid should resemble a completion fluid. It may be a brine containing only selected solids of appropriate particle size ranges (salt crystals or calcium carbonate) and polymers. Only additives essential for filtration control and cuttings carrying are present in a drill-in fluid.

A technique using the noise of the drill bit as a source and receivers laid out along the ground to acquire a vertical seismicprofile (VSP). Acquisition and processing of a drill-noise VSP, also called a seismic-while-drilling VSP, are typically a tougher task than for more conventional VSPs. Drill-noise VSPs yield reliable time-depth information and sometimes reflection information, and can be performed while a well is being drilled, so data from a drill-noise VSP can be considered in decisions during drilling operations.

A packer assembly that can be removed from the wellbore only by drilling or milling. Drillable packers, and similar tools such as bridge plugs, are typically made from cast iron, aluminum, plastic or similar brittle materials.

The supervisor of the rig crew. The driller is responsible for the efficient operation of the rigsite as well as the safety of the crew and typically has many years of rigsite experience. Most drillers have worked their way up from other rigsite jobs. While the driller must know how to perform each of the jobs on the rig, his or her role is to supervise the work and control the major rig systems. The driller operates the pumps, drawworks, and rotary table via the drillers console-a control room of gauges, control levers, rheostats, and other pneumatic, hydraulic and electronic instrumentation. The driller also operates the drawworks brake using a long-handled lever. Hence, the driller is sometimes referred to as the person who is "on the brake."

The depth of a well or features within the wellbore as measured while drilling. The measured length of each joint of drillpipe or tubing is added to provide a total depth or measurement to the point of interest. Drillers depth is the first depth measurement of a wellbore and is taken from the rotary table level on the rig floor. In most cases, subsequent depth measurements, such as those made during the well completion phase, are corrected to the wellheaddatum that is based on drillers depth.

A sudden increase in the rate of penetration during drilling. When this increase is significant (two or more times the normal speed, depending on local conditions), it may indicate a formation change, a change in the porepressure of the formation fluids, or both. It is commonly interpreted as an indication of the bit drilling sand (high-speed drilling) rather than shale (low-speed drilling). The fast-drilling formation may or may not contain high-pressure fluids. Therefore, the driller commonly stops drilling and performs a flow check to determine if the formation is flowing. If the well is flowing, or if the results are uncertain, the driller may close the blowout preventers or circulatebottoms-up. Depending on the bit being used and the formations being drilled, a formation, even if sand, may sometimes drill slower rather than faster. This slowing of drilling progress, while technically also a drilling break, is usually referred to as a "reverse drilling break", or simply "reverse break."

The company that owns and operates a drilling rig. The drilling contractor usually charges a fixed daily rate for its hardware (the rig) and software (the people), plus certain extraordinary expenses. Under this arrangement, the cost of the well is largely a function of the time it takes to drill and complete the well. The other primary contracting methods are footage rates (where the contractor receives an agreed upon amount per foot of hole drilled), or turnkey operations, where the contractor may assume substantial risk of the operations and receives a lump sum payment upon supplying a well of a given specification to the operator.

Personnel who operate the drilling rig. The crew typically consists of roustabouts, roughnecks, floor hands, lead tong operators, motormen, derrickmen, assistant drillers, and the driller. Since drilling rigs operate around the clock, there are at least two crews (twelve hour work shifts called tours, more common when operating offshore), or three crews (eight hour tours, more common onshore). In addition, drilling contractors must be able to supply relief crews from time to time when crew members are unavailable. Though less common now than in years past, the drilling contractor may opt to hire only a driller, and the driller in turn is responsible for hiring everyone reporting to him.

A surfactant-type mud additive intended to prevent formation shales and clays from sticking to the drilling assembly and also to prevent gumboshale from agglomerating and plugging the annulus and flowlines. Some DDs are claimed to be mud lubricants that lessen the torque and drag of the drillstring as it is rotated and moved up and down in the hole.

What Is Drilling Fluid? Drilling fluid (commonly called drilling mud) is the engineered circulating fluid that a rig crew pumps down the drill string, through the bit, and back up the annulus during drilling operations, simultaneously controlling wellbore pressure, transporting cuttings to surface, stabilizing the borehole wall, lubricating the bottom-hole assembly, and enabling formation evaluation while the well is being drilled. Key Takeaways Drilling fluid serves at least five simultaneous functions: pressure control, cuttings transport, borehole stabilization, bit lubrication, and formation evaluation support. Three primary fluid systems exist: water-based mud (WBM), oil-based mud (OBM), and synthetic-based mud (SBM), each with distinct performance and environmental profiles. Fluid density (expressed in ppg, pcf, or kg/L) is the primary pressure-control mechanism; it must be maintained within a window bounded by pore pressure at the low end and fracture gradient at the high end. API RP 13B-1 (water-based) and API RP 13B-2 (non-aqueous) govern field testing procedures for density, viscosity, fluid loss, and other properties worldwide. Cuttings disposal regulations vary sharply by jurisdiction: onshore Canada and the US permit land application of WBM cuttings under permit, while Norway mandates zero discharge of OBM cuttings under OSPAR Convention rules. How Drilling Fluid Works The fluid system operates as a closed loop. Mud pumps pressurize the fluid and force it down the inside of the drill string at rates typically ranging from 200 to 1,200 gallons per minute (gpm) (roughly 750 to 4,500 L/min). The fluid exits through jets in the drill bit, picking up formation cuttings, and then travels back to surface through the annular space between the drill string and the borehole wall. At surface the fluid passes over the shale shaker screens, where cuttings are separated and discarded or collected for disposal. The cleaned fluid then flows through desanders, desilters, and a mud cleaner before returning to the active pit and recirculation. Pressure control is achieved through the hydrostatic head of the fluid column. The mud weight (density) multiplied by the true vertical depth and a conversion constant of 0.052 (for ppg and feet) gives the hydrostatic pressure in psi at any point in the wellbore. This pressure must exceed formation pore pressure to prevent an influx of formation fluid (kick) while remaining below the fracture gradient to avoid lost circulation. The working pressure window between these two limits is called the "mud weight window" or "drilling window." In high-pressure/high-temperature (HPHT) wells and narrow-window deepwater wells, this window can be as small as 0.2 ppg (24 kg/m3), requiring precise density management and real-time equivalent circulating density (ECD) monitoring. Cuttings transport depends on the relationship between fluid velocity in the annulus and the settling velocity of cuttings. In vertical wells, annular velocities of 100 to 150 ft/min (30 to 46 m/min) are typically sufficient. In deviated and horizontal wells, cuttings tend to settle on the low side of the hole and form a cuttings bed that increases torque, drag, and the risk of packoff. Higher viscosity, higher annular velocity, and optimized rheological properties (particularly low-end-rate viscosity from the yield point and gel strength) are required to keep cuttings in suspension and transport them efficiently. API RP 13D provides detailed guidance on cuttings transport modeling. Drilling Fluid Across International Jurisdictions Canada's wellbore fluid management is governed primarily by the Alberta Energy Regulator (AER) Directive 050, which sets out requirements for drilling waste management including cuttings disposal by land application, annular injection, and road spreading of WBM cuttings, subject to agronomic rate limits. British Columbia and Saskatchewan have analogous provincial directives. The Canadian Association of Petroleum Producers (CAPP) publishes industry-standard fluid formulation guidelines widely adopted across western Canada. For offshore Canada, the Canada-Newfoundland and Labrador Offshore Petroleum Board (CNLOPB) and Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) apply federal regulations under the Oil and Gas Spill and Debris Liability regulations, which restrict synthetic-based mud discharges. In the United States, onshore drilling fluid regulations are administered by individual states (Texas Railroad Commission, Oklahoma Corporation Commission, Colorado ECMC, etc.) and by the Bureau of Land Management (BLM) on federal lands. Offshore operations on the Outer Continental Shelf (OCS) fall under Bureau of Safety and Environmental Enforcement (BSEE) regulations at 30 CFR Part 250, which prohibit discharge of diesel-based OBM cuttings and restrict SBM cuttings discharge to those passing a biodegradability test (CROSERF protocol, 96-hour LC50 greater than 30,000 ppm). WBM cuttings with oil content below 6.9% by dry weight may be discharged offshore under National Pollutant Discharge Elimination System (NPDES) General Permit. Norway operates under the strictest offshore discharge framework in the world. The Oslo/Paris (OSPAR) Convention, which governs discharges to the North-East Atlantic, effectively prohibits the operational discharge of OBM and SBM cuttings from Norwegian Continental Shelf (NCS) operations. Equinor, Aker BP, and other NCS operators must collect and transport all non-aqueous fluid cuttings to shore for thermal treatment or re-injection. The Norwegian Environment Agency enforces annual discharge limits, and operators that cannot collect all cuttings must apply for a specific discharge permit with robust environmental impact justification. Middle Eastern operations, centered on Saudi Arabia (Saudi Aramco), the UAE (ADNOC), Kuwait (KPC), Iraq (Basra Oil Company), and Oman (PDO), typically employ WBM and OBM systems sized for high downhole temperatures (often exceeding 150 degrees Celsius / 302 degrees Fahrenheit) and high-salinity aquifers. Saudi Aramco Engineering Standards (SAES) provide detailed fluid specifications. Offshore Qatar (North Field, QatarEnergy) and Abu Dhabi (ADNOC Offshore) apply International Association of Oil and Gas Producers (IOGP) and OSPAR-aligned discharge policies for their offshore blocks. Fast Facts A single deepwater well may consume 3,000 to 8,000 barrels (480,000 to 1,270,000 L) of drilling fluid during construction. Premium synthetic-based fluids cost USD 300 to 600 per barrel, meaning total fluid costs for a deepwater well can reach USD 2 to 4 million. API Spec 13A sets a minimum barite purity of 95% BaSO4 and a maximum residue on a 75-micron (200-mesh) sieve of 3.0%. A typical WBM for a 12.25-inch (311 mm) surface hole in Alberta might be formulated to 9.5 ppg (1,138 kg/m3) using bentonite, soda ash, and polymer. The deepest wells ever drilled, including the Sakhalin-I Z-44 Chayvo well (12,376 m / 40,604 ft measured depth), required specialized high-performance OBM systems with densities up to 18 ppg (2,159 kg/m3). Types of Drilling Fluid Systems Water-Based Mud (WBM) uses fresh water or salt water as the continuous phase. WBM systems range from simple bentonite-polymer muds for shallow surface holes to highly engineered inhibitive systems for reactive shales. Key WBM types include: fresh-water gel muds (bentonite + polymer, used for conductor and surface hole), lime muds (high pH, calcium-treated, for polyvalent-cation formations), potassium chloride (KCl) polymer muds for shale inhibition, saturated salt muds for salt formations and halite sequences, and silicate muds that precipitate a protective silica layer in reactive shale sections. WBM is favored for environmental compliance and lower cost but provides less inhibition against shale hydration than non-aqueous systems. Oil-Based Mud (OBM) uses refined mineral oil or diesel as the continuous phase, with water emulsified as the dispersed phase. OBM formulations are characterized by their oil:water ratio (typically 80:20 to 90:10 by volume). OBM provides excellent shale inhibition (water activity is suppressed), superior lubricity for high-angle wells, and stability in high-temperature formations. Its disadvantages include high cost (USD 300 to 500/bbl for mineral oil base), restricted offshore discharge, and the requirement for specialized waste treatment of OBM-contaminated cuttings. Diesel-based OBM is essentially banned offshore in Norway, the UK sector, and the US Gulf of Mexico OCS. Low-toxicity mineral oil OBM remains in use onshore in Canada, the US, and the Middle East. Synthetic-Based Mud (SBM) replaces the mineral oil or diesel base with a synthetically manufactured fluid: linear alpha-olefins (LAO), internal olefins (IO), esters, or polyalphaolefins (PAO). SBM delivers OBM-like performance at lower environmental risk because the synthetic bases biodegrade more readily than mineral hydrocarbons. Under BSEE regulations, SBM cuttings may be discharged offshore if the base fluid passes the CROSERF biodegradation test and if the cuttings contain less than 9.4% retained fluid on a dry weight basis. SBM typically costs USD 400 to 700/bbl, making it the most expensive drilling fluid type but often cost-justified in deepwater wells where borehole stability and well economics demand non-aqueous performance. Related: synthetic-base mud. Air and Foam Drilling Fluids use compressed air, mist, foam, or aerated fluid as the circulating medium. These are used in naturally fractured or low-pressure formations where conventional fluid would cause severe lost circulation, in hard-rock formations where penetration rates with WBM are very slow, and in coal-bed methane or geothermal drilling. Air drilling eliminates hydrostatic pressure concerns but introduces serious wellbore stability and fire/explosion risks in the presence of formation hydrocarbons. Foam provides more cuttings-carrying capacity than air alone and can be weighted with foaming agents to provide modest hydrostatic control. Related: air drilling.

The engineering plan for constructing the wellbore. The plan includes well geometries, casing programs, mud considerations, well control concerns, initial bit selections, offset well information, porepressure estimations, economics and special procedures that may be needed during the course of the well. Although drilling procedures are carefully developed, they are subject to change if drilling conditions dictate.

The speed at which the drill bit can break the rock under it and thus deepen the wellbore. This speed is usually reported in units of feet per hour or meters per hour.

A large-diameter pipe that connects the subsea BOP stack to a floating surface rig to take mudreturns to the surface. Without the riser, the mud would simply spill out of the top of the stack onto the seafloor. The riser might be loosely considered a temporary extension of the wellbore to the surface.

Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.

Pertaining to the use of drillpipe to move wirelinelogging tools up and down a borehole. In difficult conditions--high well deviation, rough hole--wireline logging tools cannot reach the bottom of the hole under their own weight. In drillpipe-conveyed logging operations, the tools are moved mechanically by the drillpipe, while a wireline maintains the electrical connection.

What Is a Drillship? A drillship is a ship-shaped mobile offshore drilling unit (MODU) equipped with a drilling derrick and a central through-hull opening called a moonpool, through which the drill string, marine riser, and subsea blowout preventer stack are deployed to the seafloor. Drillships rely on dynamic positioning systems to maintain station over the wellbore without anchors, making them the preferred choice for ultra-deepwater exploration in water depths from 1,500 metres to more than 3,600 metres (4,921 to 11,811 feet). Key Takeaways A drillship uses a ship hull rather than the pontoon-and-column configuration of a semisubmersible, making it more mobile and self-propelled but more susceptible to heave in harsh sea states. The moonpool is a central opening through the hull, typically 12 to 15 metres by 12 to 15 metres (39 to 49 feet square), through which all subsea well equipment including the BOP stack and riser are deployed. Class DP-3 dynamic positioning, the standard on modern ultra-deepwater drillships, requires three independent and physically separated control and thruster systems capable of holding station in a 100-year storm simulation without loss of position. Modern seventh-generation drillships are rated to 3,600 metres (11,811 feet) of water depth and can drill to measured depths of 12,000 metres (39,370 feet), covering pre-salt, Lower Tertiary, and ultra-deepwater frontier plays worldwide. Drillships are the dominant unit type for ultra-deepwater exploration in the Atlantic margin basins of Brazil and West Africa, where calm equatorial sea states suit the ship hull form better than the harsher North Sea or Gulf of Mexico environments preferred by semisubmersibles. How a Drillship Works A drillship combines the hull, propulsion, and navigation systems of a conventional ocean-going vessel with a full offshore drilling package integrated around a central moonpool. The moonpool penetrates the full height of the hull from the drilling deck to the keel, providing a protected opening through which the marine drilling riser, subsea BOP stack, and well equipment are lowered to the seafloor. The derrick is positioned directly above the moonpool, and the rotary table or top drive drives the drill string through the riser to the wellbore. The moonpool structure must be designed to withstand the cyclic loads from the riser tensioner system, which typically applies 2,000 to 4,000 kN (450,000 to 900,000 lbf) of upward tension to prevent the riser from going into compression as the vessel heaves. The drilling package on a modern drillship is essentially identical to that on a semisubmersible of comparable generation. A top drive rated at 1,500 to 2,000 metric tons (1,653 to 2,205 short tons) hook load rotates and suspends the drill string; a bottom hole assembly incorporating LWD and MWD tools provides real-time formation evaluation and directional data. Drilling fluid circulates down the drill string and returns up the annulus, carrying cuttings and balancing formation pressure through careful control of mud weight. Bulk fluid storage on drillships is large: modern ultra-deepwater drillships carry 3,000 to 8,000 barrels (477 to 1,272 cubic metres) of mud in pressurised storage tanks, reflecting the long well construction times and high mud consumption at ultra-deepwater depths. Casing strings are run through the moonpool and set in the wellbore, with cementing operations performed through the string using displacement plugs and top-drive cement heads. Well control on a drillship follows the same subsea BOP architecture as a semisubmersible. The BOP stack sits on the seafloor wellhead, connected to the drillship by the marine riser. The lower marine riser package (LMRP) can be disconnected hydraulically in an emergency, leaving the BOP latched to the wellhead. The accumulator system on the subsea control pods stores sufficient hydraulic energy to close all preventers and disconnect the LMRP without power from the surface. If a kick is detected through an increase in pit volume, a change in return flow rate, or a background gas increase, the driller closes the annular preventer and initiates a well kill procedure in accordance with the driller's method or wait-and-weight method, as specified in the well control plan approved by the coastal state regulator. Drillship Dynamic Positioning Across International Jurisdictions Dynamic positioning (DP) is the defining characteristic of modern drillships. Unlike spread-moored semisubmersibles, drillships deploy no anchors; instead, the DP computer continuously resolves the vessel's position error against a setpoint and commands individual thrusters to produce the forces and moments required to maintain station. Position references include acoustic systems (HIPAP/USBL), differential GPS (DGPS), and taut-wire sensors; at least three independent reference systems are active at all times on a DP-3 vessel. The DP controller models environmental forces from wind, waves, and current in real time, using feedforward algorithms to anticipate load changes before they cause position excursion. United States Gulf of Mexico: BSEE regulates drillship operations under 30 CFR Part 250 in the same manner as semisubmersibles. Following the Macondo disaster, the 2016 Well Control Rule requires all MODUs, including drillships, to maintain two independent, tested well barriers throughout the well life cycle. DP reliability requirements derive from IMO MSC/Circ.645, and BSEE inspectors verify BOP documentation, riser inspection records, and DP annual trials before granting drilling permits. Transocean and Seadrill drillships have operated extensively in the Keathley Canyon, Walker Ridge, and Green Canyon deepwater areas of the Gulf of Mexico, targeting Lower Tertiary Wilcox plays in 2,500 to 3,000 metres (8,202 to 9,843 feet) of water. Brazil: Petrobras operates the world's largest concentration of ultra-deepwater drillships, targeting pre-salt reservoirs beneath thick carbonate and evaporite sequences in the Santos Basin (including Lula, Buzios, and Sapinhoa fields) and the Campos Basin. The Agencia Nacional do Petroleo, Gas Natural e Biocombustiveis (ANP) governs drilling operations under Brazil's Petroleum Law (Law 9.478/1997) and requires operators to file a Well Program (Programa de Perfuracao) demonstrating well barrier compliance, BOP certification, and environmental response plans. Pre-salt wells in the Santos Basin target reservoirs at 5,000 to 7,000 metres (16,404 to 22,966 feet) measured depth in water depths of 2,000 to 2,500 metres (6,562 to 8,202 feet), requiring drillships with 12,000-metre (39,370-foot) MD capability and high-pressure riser systems. West Africa: Nigeria, Angola, and the Republic of Congo are major ultra-deepwater drillship markets. In Nigeria, the Department of Petroleum Resources (DPR, now reorganised as the Nigerian Upstream Petroleum Regulatory Commission, NUPRC under the Petroleum Industry Act 2021) regulates offshore drilling. In Angola, the national oil company Sonangol and the regulator ANPG (Agencia Nacional de Petroleo, Gas e Biocombustiveis) oversee deepwater operations. Fields including Egina (Total, 1,750 metres / 5,741 feet water depth), Zinia (TotalEnergies), and Sangos required multiple drillship campaigns. Drillships are well-suited to West African operations because the equatorial Atlantic experiences relatively benign sea states compared to the North Atlantic or Gulf of Mexico hurricane belt. Norway: The Norwegian Continental Shelf operates in harsh North Sea and Barents Sea conditions that historically favoured semisubmersibles over drillships. However, some drillships are used in milder areas of the southern NCS and in benign Barents Sea summer operations. The Petroleum Safety Authority Norway (Ptil) enforces NORSOK D-010 well integrity requirements for all MODUs on the NCS, regardless of type. DP-3 is mandatory for floating units drilling in Norwegian waters, and annual DP trials and third-party verification of the DP capability plot (FMEA-based) are required. Australia: NOPSEMA regulates drillship operations in Australian Commonwealth waters under the OPGGSA and the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. Operators must submit a Well Operations Management Plan (WOMP) demonstrating two independent well barriers. Drillships have operated in the Carnarvon Basin (Browse and Exmouth sub-basins) and the Bight Basin targeting ultra-deepwater frontier plays. NOPSEMA also requires a Diving Safety Management System (DSMS) if saturation diving is conducted in association with the drillship operation. Fast Facts First drillship for science: Glomar Challenger, 1968 (Deep Sea Drilling Project) Typical moonpool dimensions: 12 x 12 m (39 x 39 ft) to 15 x 15 m (49 x 49 ft) Ultra-deepwater rated depth: up to 4,000 m (13,123 ft) on some units Maximum drilling depth (MD): typically 12,000 m (39,370 ft) DP thruster count: typically 8-10, each rated at 3.5-5.5 MW Mud storage capacity: 3,000-8,000 bbl (477-1,272 m³) Position reference systems (DP-3): minimum 3 independent systems (HIPAP, DGPS, Artemis) Key drillship contractors: Transocean, Seadrill, Valaris, Noble Corporation, Diamond Offshore, Saipem Drillship Design, Generations, and Notable Units Drillship design evolved through a series of informal generations roughly paralleling the semisubmersible fleet, driven by increases in target water depth, hook-load requirements, and regulatory complexity: First Generation (1960s-1970s): Pioneered by scientific programs; the Glomar Challenger (1968) completed the Deep Sea Drilling Project (DSDP), drilling in water depths to 6,247 metres (20,495 feet) and recovering core from across the global ocean basins. Early commercial drillships of this era had primitive station-keeping (early DP or manual thruster control) and were limited to moderate water depths and benign environments. Second and Third Generations (1970s-1990s): Integrated DP Class 1 and Class 2 systems; derrick ratings increased to 750 metric tons (827 short tons); vessels designed for specific regional markets such as the Gulf of Mexico or West Africa. The Saipem FDS (First Drillship) and similar units represented the early commercial third-generation fleet. Fourth and Fifth Generations (1990s-2000s): DP Class 2 standard; water depth ratings of 2,000 to 3,000 metres (6,562 to 9,843 feet); hook-load ratings of 907 to 1,360 metric tons (1,000 to 1,500 short tons). The Transocean Discoverer Enterprise (1999) and Discoverer Spirit (2000) are representative fifth-generation units rated to 3,048 metres (10,000 feet). Sixth Generation (2005-2012): Full DP Class 3; water depth ratings of 3,000 to 3,658 metres (9,843 to 12,001 feet); dual-activity drilling capability (ability to run casing and drill concurrently using two independent drilling systems on the same moonpool); hook-load ratings of 1,360 to 2,000 metric tons (1,500 to 2,205 short tons). Samsung Heavy Industries (SHI) and Hyundai Heavy Industries (HHI) in South Korea delivered the majority of sixth-generation drillships. The Seadrill West Saturn (2014) and Transocean Dhirubhai Deepwater KG2 are examples. Seventh Generation (2012-present): Rated to 3,658 metres (12,001 feet) or deeper; hook-load of 2,000 metric tons (2,205 short tons) and above; high-pressure/high-temperature (HPHT) rated equipment; integrated BOP test systems; managed pressure drilling (MPD) capability integrated into the riser system. The Seadrill West Gemini and the Transocean Deepwater Conqueror are illustrative seventh-generation drillships. Some units in this generation are fitted with dual derricks and dual moonpools, reducing well construction time by enabling parallel operations.

What Is a Drillstem Test? A drillstem test (DST) is a temporary well evaluation procedure performed with the casing string or open hole still in place, using a specialized downhole tool assembly to isolate a target formation, flow reservoir fluids to surface, and measure pressure responses that reveal permeability, skin damage, and original reservoir pressure before permanent completion decisions are made. Key Takeaways A DST delivers the definitive flow rate, reservoir pressure, and permeability data that determine whether a discovery is commercially viable before operators commit to full completion expenditure. The standard test sequence alternates between timed flow periods and shut-in periods; the pressure buildup during shut-in is analyzed on a Horner plot to calculate permeability-thickness (kh) and skin factor. Downhole shut-in valves allow the well to be closed at the formation face rather than at surface, producing cleaner pressure transient data and dramatically reducing surface H2S and hydrocarbon release hazards. Closed-chamber DST (no flow to surface) is used in tight formations, environmentally sensitive areas, and offshore wells where flaring is restricted, capturing fluids in the drillstring itself for volumetric analysis. Regulatory bodies in every major hydrocarbon jurisdiction, including the Alberta Energy Regulator (AER), BSEE, NOPSEMA, and Sodir, require formal reporting of DST results as part of the well licensing and disclosure framework. How a Drillstem Test Works Before a DST begins, the operator assembles the test string from bottom to top: a perforated anchor pipe or tail pipe, a formation tester valve or reverse-circulation valve, one or more packers to isolate the zone, pressure and temperature gauges (typically crystal quartz gauges accurate to 0.01 PSI), a drill collar weight section, and the surface string of drill pipe. The packer or packer-pair is run to the desired depth and set mechanically or hydraulically against the borehole wall, sealing the annular space and forcing any formation fluids to flow exclusively through the drill pipe bore. With the zone isolated, the surface operator opens the downhole test valve and begins the initial flow period (IFP), typically lasting 5 to 30 minutes. This short burst clears drilling fluid filtrate from the near-wellbore region and establishes a stabilized producing pressure. The valve is then closed for the initial shut-in period (ISIP), which runs for approximately one hour. During shut-in, reservoir pressure rebuilds and the pressure transient travels outward through the formation; the rate of pressure recovery encodes permeability information that engineers later extract through pressure transient analysis. The main flow period (FP) follows and typically runs 4 to 24 hours at a controlled choke setting that keeps the producing bottomhole flowing pressure above the bubble point to avoid multiphase flow complications in tight formations. A final shut-in period (FSIP) of 4 to 12 hours closes the test and allows the pressure to rebuild fully toward static reservoir pressure. The entire sequence is recorded continuously by the downhole gauges, and the memory data is retrieved when the string is pulled. Surface measurements during the flow periods capture the flowing tubing pressure (FTP), gas-oil ratio (GOR), oil gravity, water cut, and gross flow rate in barrels of oil equivalent per day (BOE/d). Downhole gauge data captures bottomhole shut-in pressure (BHSIP), flowing bottomhole pressure (FBHP), and temperature at formation depth. Together these parameters feed Horner plot analysis, which linearizes the pressure buildup data and extracts extrapolated static reservoir pressure, permeability, and skin factor. A positive skin value indicates near-wellbore damage (from mud invasion or poor perforation efficiency) that would be remedied by stimulation; a negative skin value suggests natural or induced fractures that enhance productivity beyond the matrix alone. DST Tool String Components in Detail The downhole assembly for a conventional open-hole DST starts at the base with a perforated anchor pipe or junk basket that allows formation fluids to enter while preventing cuttings from plugging the string. Immediately above sits the downhole shut-in tool (DHSI), a surface-actuated sleeve valve operated by pipe rotation or annular pressure pulses that allows the wellbore to be closed precisely at formation depth. This is the single most important safety advancement in modern DST practice: closing at the formation rather than at the wellbore shut-in prevents the trapped wellbore volume from masking the true pressure transient signal and eliminates the need to hold back a column of gas-laden fluid at surface. Above the DHSI sits a safety joint or hydraulic disconnect, which allows emergency retrieval of the lower assembly should the packer become stuck. A hydraulic packer, or in dual-zone tests a straddle packer pair, isolates the test interval. Straddle packers use two inflatable or mechanical elements set above and below the target zone, allowing a single zone within a longer open-hole section to be tested without perforating. Pressure and temperature memory gauges are typically mounted below the packer at formation depth, with a second set placed above the packer or in the drill collars for reference. Above the packer and gauges, a string of BHA components including drill collars provides mechanical weight to set the packer and prevents the string from becoming "pipe light" due to internal wellbore pressure acting upward on the tool cross-section. The upper drill string transmits fluid from the formation to the surface test separator, where gas is metered, oil is stored in test tanks, and produced water is handled per environmental permit conditions. Crystal quartz pressure gauges have replaced strain gauge instruments as the industry standard because they deliver resolution better than 0.01 PSI (0.0007 bar) and temperature stability to 175 degrees Celsius (347 degrees Fahrenheit), accurate enough to detect the weak pressure transient signals from micro-darcy formations. Gauges are downloaded post-test through a gauge reading tool at surface, and the data is processed in pressure transient analysis software such as Kappa Saphir or IHS Harmony. Fast Facts: Drillstem Test Typical test string depth: 500 m to 7,000 m (1,640 ft to 22,965 ft) TVD Pressure gauge resolution: 0.01 PSI (0.0007 bar); temperature range to 175°C (347°F) Standard flow period duration: 4 to 24 hours for conventional reservoirs; up to 72+ hours for tight gas appraisal Typical DST flow rates: 10 BOE/d (tight) to 50,000+ BOE/d (high-permeability carbonate) BHSIP extrapolation accuracy: within 1 to 3 PSI (0.07 to 0.21 bar) of true reservoir pressure with adequate buildup time Packer element ratings: differential pressure ratings up to 700 bar (10,153 PSI) for HPHT applications Wireline MDT sampling volume per station: 1 to 10 litres; DST recovers hundreds of barrels for more representative analysis AER Well Test Report filing deadline: within 60 days of completion of the test, under Directive 051 Closed-Chamber DST and Specialized Configurations A closed-chamber drillstem test differs from a conventional surface-flow DST in that no fluids are produced to surface. Instead, the drill string above the formation tester valve is filled with a compressible gas (usually nitrogen or air) at a known initial pressure. When the formation tester opens, reservoir fluids flow into the sealed drill-string chamber and compress the gas cushion. By monitoring the pressure increase in the chamber over a defined flow period, engineers calculate the flow rate and reservoir pressure without routing any hydrocarbons to surface equipment. Closed-chamber testing is the preferred approach in several scenarios: very tight formations (permeability below 0.1 millidarcy) where flow rates would be too low to measure accurately at surface; offshore wells operating under strict flaring and venting restrictions imposed by BSEE, NOPSEMA, or Sodir; exploration wells in wilderness or environmentally sensitive areas where surface disposal of formation fluids is not permitted; and wells expected to contain high concentrations of hydrogen sulfide (H2S), where eliminating a surface flow stream reduces crew exposure risk. The wireline formation tester (WFT), marketed under trade names such as Schlumberger MDT (Modular Formation Dynamics Tester) and Halliburton RFT (Repeat Formation Tester), is often used as a pre-DST reconnaissance tool. The MDT/RFT runs on wireline and takes pressure measurements and small fluid samples (1 to 10 litres per station) at multiple depths in a single wireline run, building a pressure-versus-depth profile that identifies fluid contacts and reservoir pressure gradients. However, the WFT's small sample volume and short flow duration mean it cannot establish dynamic flow rates, measure deliverability, or capture the extended transient needed to estimate permeability at reservoir scale. The DST remains the definitive measurement for these parameters. A combined workflow runs the MDT first to identify the most prospective intervals and target intervals, then deploys the DST on the highest-potential zone for deliverability confirmation. In cased-hole DSTs, the well is first cased and cemented, then perforated across the target interval using a perforation gun assembly. The DST packer is then set above the perforations in the casing, and the test proceeds identically to an open-hole configuration. Cased-hole testing provides better wellbore integrity for high-pressure zones and allows re-testing of the same interval after stimulation; however, perforation efficiency and phasing introduce additional skin effects that must be accounted for in the pressure transient analysis. Perforating with underbalanced or near-balance conditions minimizes crush damage and reduces the skin contribution from perforation tunnel compaction.

The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.

The water and heavy hydrocarbons that condense from the gas stream and accumulate in the lower points of the flowlines.

A device used to collect water and heavy hydrocarbons that drop out of a gas stream in a pipeline.

A ball that is dropped or pumped through the wellbore tubulars to activate a downhole tool or device. When the ball is located on a landing seat, hydraulic pressure generally is applied to operate the tool mechanism.

A heavy steel bar that is dropped through the tubing or running string to fire the percussion detonator on a tubing-conveyed perforating (TCP) gun assembly. The drop bar must be capable of falling through the string with sufficient speed to impart the necessary force for detonation. Therefore, this method of firing is best suited to vertical or slightly deviated wellbores where there will be minimal drag or friction effect.

A device, shaped like a short length of pipe, which is used to drop TCP guns in the rathole or sump. It is commonly used to drop guns that are connected to the completion into the sump, thus providing access to the reservoir for subsequent intervention work. It may also be used to break the tool string into fishable sections.

A perforating gun assembly designed to be detached from the tubing or running string after firing. The detached assembly can then drop, or be pushed, to the bottom of the well depending on deviation and production requirements. Drop-off gun assemblies often are used in underbalanced perforating applications, eliminating the need to kill the well to recover the spent gun assembly. In such cases, the wellbore will be designed to accommodate the spent gun assembly without compromising productivity, while recovery of the gun assembly may be planned during subsequent workover operations. The drop-off mechanism may be automatic and actuated at time of firing, or be actuated after firing.

The failure of a channel or geophone to record a shot or shots in a seismicsurvey, which results in a loss of data.

A hygroscopic solid such as silica gel, calcium chloride [CaCl2] or other materials used in dry-bed dehydrators to absorb water and water vapor from a gas stream.

An in situ combustion technique in which only air or oxygen-enriched air mixtures are injected into a formation. A drawback related to dry combustion is the highly corrosive and noxious combustion products that are produced.

A type of in situ combustion in which the burning front moves in the same direction as the injected air. As air is continuously supplied at the injection well, the fire ignited at this location moves toward the production wells.During forward combustion, the temperature behind the burning front is high, indicating a great amount of heat stored in the formationmatrix. The injected gas heats on contact with the matrix and recovers only a small amount of the heat, with considerable losses to the surrounding formations. Another drawback of dry forward combustion is the presence of a highly viscous oil zone surrounding the production well. The fluid in this zone remains at the original reservoir temperature and its forward displacement by the heated oil is normally difficult.

Gas produced from a well that produces little or no condensate or reservoir liquids. The production of liquids from gas wells complicates the design and operation of surface process facilities required to handle and export the produced gas.

A wellbore that has not encountered hydrocarbons in economically producible quantities. Most wells contain salt water in some zones. In addition, the wellbore usually encounters small amounts of crude oil and natural gas. Whether the well is a "duster" depends on many factors of the economic equation, including proximity to transport and processing infrastructures, local market conditions, expected completion costs, tax and investment recovery conditions of the jurisdiction and projected oil and gas prices during the productive life of the well.

A treated oil that contains small amounts of basic sediments and water (BS&W). Dry oil is also called clean oil.

A subsurface rock that lacks contact with aquifers or meteoric water within the Earth.

A device that removes water and water vapor from a gas stream using two or more beds of solid desiccants, such as silica gel or calcium chloride [CaCl2]. Wet gas is passed through the solid material, which absorbs the water, and then dry gas is collected at the top of the device.The main limitation of this device is that the solid desiccant absorbs only limited quantities of water. When the desiccant saturation point is reached, it must be replaced and sometimes water cannot be removed from it.

A wellbore with simultaneous production of hydrocarbons, water or both from more than one producing zone. Although the term refers to cases in which only two separate zones are present, in actuality there may be multiple zones involved. This completion technique avoids backflow from one reservoir zone to another in the wellbore.

The combination of a deep-induction and a medium-induction array on the same sonde. In a typical implementation, the two arrays share the same transmitters but have different receivers. If the dual-induction log is combined with a shallow laterolog or microresistivity log, it is possible to correct for the effect on invasion on the deep log, assuming a step profile.

A model of shaly formations that considers there to be two waters in the pore space: far water, which is the normalformation water; and near water (or clay-bound water) in the electrical double layer near the clay surface. The clay-bound water consists of clay counter-ions and the associated water of hydration. The volume of this layer is determined by its thickness, which is constant at high salinities, and its area, which is proportional to the counter-ion concentration per unit pore volume (Qv). The volume of clay-bound water per unit pore volume, Swb, can therefore be written as: Swb = alpha * vq * Qvwhere vq = 0.28 cm3/meq at 25oC is the factor relating volume to counter-ion concentration at high salinity and is a function only of temperature, and alpha = 1 above a certain salinity, below which it increases with temperature and with decreasing salinity. The fractional volume of the far water is then (1 ? alpha?* vq * Qv).The dual-water concept was developed for the interpretation of resistivity in shaly sands, but is also useful in the interpretation of nuclear and nuclear magnetic resonance logs. In these cases, the parameter most used is the total volume of clay-bound water in the rock, equal to Swb multiplied by the total porosity.

A dual-porosityreservoir in which flow to the well occurs in both primary and secondary porosity systems.

A rock characterized by primary porosity from original deposition and secondary porosity from some other mechanism, and in which all flow to the well effectively occurs in one porosity system, and most of the fluid is stored in the other. Naturally fractured reservoirs and vugular carbonates are classified as dual-porosity reservoirs, as are layered reservoirs with extreme contrasts between high-permeability and low-permeability layers.

A blank gas-lift valve placed in a gas-lift mandrel to isolate the tubing string from the annulus. Gas-lift valves frequently are replaced with dummy valves during intervention work on wells with gas-lift completions.

A wireline or slickline tool used to place small volumes of cementslurry, or similar material, in a wellbore. Typically, the slurry is placed on a plug or similar device that provides a stable platform for the low-volume cement plug.

A type of fluid pump, commonly used on workover rigs, that has two plungers or pistons. As a positive-reciprocating pump, the fluid flow rate is typically calculated from the number of strokes per minute that the pump makes and the displacement volume per stroke. Such a level of accuracy usually is sufficient for general workover purposes.

(noun) An informal industry term for a dry hole — a well that fails to encounter commercially producible quantities of oil or gas and is subsequently plugged and abandoned. The term reflects the disappointment of drilling an unsuccessful exploration or development well.

A time-variant operation performed on seismic data. Normal moveout (NMO) is a dynamic correction.

Equipment used to measure filtration under dynamic conditions. Two commercial dynamic-filtration testers are available, one of which uses a thick-walled cylinder with rock-like characteristics as the filter medium to simulate radial flow into a wellbore. The other tester uses flat porous disks, such as paper or fused ceramic plates, as filter media. In a dynamic test, filter cake is continually eroded and deposited. Data from this test include a steady-state filtration rate measured during the test, and cake thickness, cake quality and return permeability of the filter medium measured at the conclusion of a test. There is no API standardized test equipment or procedure.

A filtration process in which the slurry being filtered is being circulated over the filter cake, so that the cake is simultaneously eroded and deposited. The erosion rate depends on the shear rate of the fluid at the face of the cake. If the shear rate remains constant, cake thickness and filtration rate reach steady state, usually in a matter of hours. When the conditions change, a new steady state will be established.

The level to which the static fluid level drops in the tubing or casing when the well produced under pumping conditions. The dynamic fluid level is also called the pumping fluid level.

The stationing of a vessel, especially a drillship or semisubmersible drilling rig, at a specific location in the sea by the use of computer-controlled propulsion units called thrusters. Though drilling vessels have varying sea and weather state design conditions, most remain relatively stable even under high wind, wave and current loading conditions. Inability to maintain stationkeeping, whether due to excessive natural forces or failure of one or more electromechanical systems, leads to a "drive off" condition that requires emergency procedures to disconnect the riser from the subsea BOP stack, or worse, drop the riser from the vessel altogether.

The ratio of or difference between the highest and the lowest reading, or strongest and weakest signal, that can be recorded or reproduced by an instrument without distortion.

A type of explosive used as a source for seismic energy during data acquisition. Originally, dynamite referred specifically to a nitroglycerin-based explosive formulated in 1866 by Alfred Bernhard Nobel (1833 to 1896), the Swedish inventor who endowed the Nobel prizes. The term is incorrectly used to mean any explosive rather than the original formulation.

An instrument used in sucker-rod pumping to record the variation between the polished rod load and the polished rod displacement.

The record made by the dynamometer. An analysis of this survey may reveal a defective pump, leaky tubing, inadequate balance of the pumping unit, a partially plugged mud anchor, gas locking of the pump or an undersized pumping unit. The dynamometer card is also called a dynagraph.