SLB Oilfield Glossary_Drilling

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logging-while-drilling

1. adj. [Drilling, Shale Gas] The measurement of formation properties during the excavation of the hole, or shortly thereafter, through the use of tools integrated into the bottomhole assembly. LWD, while sometimes risky and expensive, has the advantage of measuring properties of a formation before drilling fluids invade deeply. Further, many wellbores prove to be difficult or even impossible to measure with conventional wireline tools, especially highly deviated wells. In these situations, the LWD measurement ensures that some measurement of the subsurface is captured in the event that wireline operations are not possible. Timely LWD data can also be used to guide well placement so that the wellbore remains within the zone of interest or in the most productive portion of a reservoir, such as in highly variable shale reservoirs. Alternate Form: logging-while-drilling, LWD See: bottomhole assembly, deviated hole, formation evaluation while drilling, measurements-while-drilling, wireline log

turnkey

1. adj. [Drilling] A type of financing arrangement for the drilling of a wellbore that places considerable risk and potential reward on the drilling contractor. Under such an arrangement, the drilling contractor assumes full responsibility for the well to some predetermined milestone such as the successful running of logs at the end of the well, the successful cementing of casing in the well or even the completion of the well. Until this milestone is reached, the operator owes nothing to the contractor. The contractor bears all risk of trouble in the well, and in extreme cases, may have to abandon the well entirely and start over. In return for assuming such risk, the price of the well is usually a little higher than the well would cost if relatively trouble free. Therefore, if the contractor succeeds in drilling a trouble-free well, the fee added as contingency becomes profit. Some operators, however, have been required by regulatory agencies to remedy problem wells, such as blowouts, if the turnkey contractor does not. See: blowout, casing, cementing, completion, contract depth, drilling contractor

concentric

1. adj. [Drilling] Having the same center, such as when the casing and the wellbore have a common center point and, therefore, a uniform annular dimension. See: annulus, eccentricity

eccentric

1. adj. [Drilling] Off-center, as when a pipe is off-center within another pipe or the openhole. Eccentricity is usually expressed as a percentage. A pipe would be considered to be fully (100%) eccentric if it were lying against the inside diameter of the enclosing pipe or hole. A pipe would be said to be concentric (0% eccentric) if it were perfectly centered in the outer pipe or hole. Eccentricity becomes important to the well designer in estimating casing wear, wear and tear on the drillstring, and the removal of cuttings from the low side of an inclined hole. In the latter case, if the drillpipe lies on the low side of the hole (100% eccentric), the eccentricity results in low-velocity fluid flow on the low side. Gravity pulls cuttings to the low side of the hole, building a bed of small rock chips on the low side of the hole known as a cuttings bed. This cuttings bed becomes difficult to clean out of the annulus and can lead to significant problems for the drilling operation if the pipe becomes stuck in the cuttings bed. Antonyms: concentric See: centralizer, fluid flow

multilateral

1. adj. [Drilling] Pertaining to a well that has more than one branch radiating from the main borehole. The term is also used to refer to the multilateral well itself. See: sidetrack

HPHT

1. adj. [Drilling] Pertaining to wells that are hotter or higher pressure than most. The term came into use upon the release of the Cullen report on the Piper Alpha platform disaster in the UK sector of the North Sea, along with the contemporaneous loss of the Ocean Odyssey semisubmersible drilling vessel in Scottish jurisdictional waters. In the UK, HPHT is formally defined as a well having an undisturbed bottomhole temperature of greater than 300oF [149oC] and a pore pressure of at least 0.8 psi/ft (~15.3 lbm/gal) or requiring a BOP with a rating in excess of 10,000 psi [68.95 MPa]. Although the term was coined relatively recently, wells meeting the definition have been safely drilled and completed around the world for decades. Alternate Form: high-pressure, high-temperature

high-pressure, high-temperature

underbalanced

1. adj. [Drilling] Referring to a situation when the pressure (or force per unit area) exerted on a formation exposed in a wellbore is less than the internal fluid pressure of that formation. If sufficient porosity and permeability exist, formation fluids enter the wellbore. The drilling rate typically increases as an underbalanced condition is approached. Antonyms: overbalance See: coiled tubing drilling, hydrostatic pressure, kill

barefoot

1. adj. [Drilling] Referring to openhole or without casing, as in barefoot completion or barefoot drillstem test. See: cased hole, completion, openhole completion

kelly down

1. adj. [Drilling] Referring to the condition that occurs when the kelly is all the way down, so drilling progress cannot continue. A connection must be made, which has the effect of raising the kelly up by the length of the new joint of drillpipe added, so drilling can resume. See: joint

stuck

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

1. n. [Drilling Fluids] A surfactant-type mud additive intended to prevent formation shales and clays from sticking to the drilling assembly and also to prevent gumbo shale 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. Alternate Form: drilling detergent

hydrogen sulfide

1. n. [Drilling, Drilling Fluids, Production Facilities, Well Testing, Well Workover and Intervention, Well Completions] [H2S] An extraordinarily poisonous gas with a molecular formula of H2S. At low concentrations, H2S has the odor of rotten eggs, but at higher, lethal concentrations, it is odorless. H2S is hazardous to workers and a few seconds of exposure at relatively low concentrations can be lethal, but exposure to lower concentrations can also be harmful. The effect of H2S depends on duration, frequency and intensity of exposure as well as the susceptibility of the individual. Hydrogen sulfide is a serious and potentially lethal hazard, so awareness, detection and monitoring of H2S is essential. Since hydrogen sulfide gas is present in some subsurface formations, drilling and other operational crews must be prepared to use detection equipment, personal protective equipment, proper training and contingency procedures in H2S-prone areas. Hydrogen sulfide is produced during the decomposition of organic matter and occurs with hydrocarbons in some areas. It enters drilling mud from subsurface formations and can also be generated by sulfate-reducing bacteria in stored muds. H2S can cause sulfide-stress-corrosion cracking of metals. Because it is corrosive, H2S production may require costly special production equipment such as stainless steel tubing. Sulfides can be precipitated harmlessly from water muds or oil muds by treatments with the proper sulfide scavenger. H2S is a weak acid, donating two hydrogen ions in neutralization reactions, forming HS- and S-2 ions. In water or water-base muds, the three sulfide species, H2S and HS- and S-2 ions, are in dynamic equilibrium with water and H+ and OH- ions. The percent distribution among the three sulfide species depends on pH. H2S is dominant at low pH, the HS- ion is dominant at mid-range pH and S2 ions dominate at high pH. In this equilibrium situation, sulfide ions revert to H2S if pH falls. Sulfides in water mud and oil mud can be quantitatively measured with the Garrett Gas Train according to procedures set by API. Alternate Form: H2S See: corrosion coupon, Garrett Gas Train, hydrocarbon, natural gas, sour, sweet

air-cut mud

1. n. [Drilling, Drilling Fluids] A drilling fluid (or mud) that has gas (air or natural gas) bubbles in it, resulting in a lower bulk, unpressurized density compared with a mud not cut by gas. The density of gas-cut mud can be measured accurately using a pressurized mud balance. Defoamer chemicals added to the mud or a mechanical vacuum pump degasser can liberate the trapped gas. The derrickman periodically measures mud density and communicates the results to the driller via an intercom, typically reporting something like "9.6 heavy," "10.4," or "13.2 light," indicating more than 9.6 pounds per gallon, 10.4 pounds per gallon, or less than 13.2 pounds per gallon, respectively. Each tenth of a pound per gallon is referred to as a "point" of mud weight. Note that for this low-accuracy measurement, no direct mention of gas cut is made. A gas cut is inferred only if the mud returning to the surface is significantly less dense than it should be. In the case of the mud logger's measurement, "units" of gas (having virtually no absolute meaning) are reported. For the mud logger's measurement, a direct indication of combustible gases is made, with no direct correlation to mud weight. Synonyms: gas-cut mud See: derrickman, drilling fluid

gas-cut mud

1. n. [Drilling, Drilling Fluids] A drilling fluid (or mud) that has gas (air or natural gas) bubbles in it, resulting in a lower bulk, unpressurized density compared with a mud not cut by gas. The density of gas-cut mud can be measured accurately using a pressurized mud balance. Defoamer chemicals added to the mud or a mechanical vacuum pump degasser can liberate the trapped gas. The derrickman periodically measures mud density and communicates the results to the drilling crew via an intercom, typically reporting something like "9.6 heavy," "10.4," or "13.2 light," indicating more than 9.6 pounds per gallon, 10.4 pounds per gallon, or less than 13.2 pounds per gallon, respectively. Each tenth of a pound per gallon is referred to as a "point" of mud weight. Note that for this low-accuracy measurement, no direct mention of gas cut is made. A gas cut is inferred only if the mud returning to the surface is significantly less dense than it should be. In the case of the mud logger's measurement, "units" of gas (having virtually no absolute meaning) are reported. For the mud logger's measurement, a direct indication of combustible gases is made, with no direct correlation to mud weight. Synonyms: air-cut mud See: derrickman, drilling fluid

fluid caliper

1. n. [Drilling, Drilling Fluids] A survey in which the annular volume of the wellbore is mathematically calculated with a flowmeter and a marker. The drilling fluid in the hole is used as an analog to determine the amount of cement needed to circulate back to surface. It is run by pumping the marker down the drillstring, circulating it back up the annulus, and catching it where it exits the flow line. Using the circulation time, pump volume, hole size, fluid viscosity, and several other factors, the annular volume of cement is calculated. It can be run on any string to any depth. It can be run with partial circulation loss, but not with totally lost returns.

LCM

1. n. [Drilling, Drilling Fluids] Solid material intentionally introduced into a mud system to reduce and eventually prevent the flow of drilling fluid into a weak, fractured or vugular formation. This material is generally fibrous or plate-like in nature, as suppliers attempt to design slurries that will efficiently bridge over and seal loss zones. In addition, popular lost circulation materials are low-cost waste products from the food processing or chemical manufacturing industries. Examples of lost circulation material include ground peanut shells, mica, cellophane, walnut shells, calcium carbonate, plant fibers, cottonseed hulls, ground rubber, and polymeric materials. Alternate Form: lost-circulation material, lost-circulation material

hammer union

1. n. [Drilling, Production Testing, Well Completions, Well Testing, Well Workover and Intervention] A connection common in the oil industry consisting of two joints coupled by a threaded nut. Protrusions on the nut are hit with a sledgehammer to tighten the connection and energize the seals. Hammer unions are commonly used on treating iron because of their ability to be quickly made up or broken down. See: make a connection

swivel flange

1. n. [Drilling, Production, Production Testing, Well Completions, Well Testing, Well Workover and Intervention] A flange consisting of two parts—a hub and a ring. The hub contains the gasket profile, and the ring features the bolt-hole pattern. The ring can rotate around the hub for easier makeup. Once the bolts are tightened, the ring is compressed against the hub via a shoulder and secured in place.

multiwell pad

1. n. [Drilling, Production] A pad with multiple wells.

pad

1. n. [Drilling, Production] A temporary drilling site, usually constructed of local materials such as gravel, shell or even wood. For some long-drilling-duration, deep wells, such as the ultradeep wells of western Oklahoma, or some regulatory jurisdictions such as The Netherlands, pads may be paved with asphalt or concrete. After the drilling operation is over, most of the pad is usually removed or plowed back into the ground. See: multiwell pad

nipple

1. n. [Drilling, Production] Any short piece of pipe, especially if threaded at both ends with male threads.

rotary steerable system

1. n. [Drilling, Shale Gas] A tool designed to drill directionally with continuous rotation from the surface, eliminating the need to slide a steerable motor. Rotary steerable systems typically are deployed when drilling directional, horizontal, or extended-reach wells. State-of-the-art rotary steerable systems have minimal interaction with the borehole, thereby preserving borehole quality. The most advanced systems exert consistent side force similar to traditional stabilizers that rotate with the drillstring or orient the bit in the desired direction while continuously rotating at the same number of rotations per minute as the drillstring. See: directional drilling

LWD

1. n. [Drilling, Shale Gas] Abbreviation for logging while drilling. The measurement of formation properties during the excavation of the hole, or shortly thereafter, through the use of tools integrated into the bottomhole assembly. LWD, while sometimes risky and expensive, has the advantage of measuring properties of a formation before drilling fluids invade deeply. Further, many wellbores prove to be difficult or even impossible to measure with conventional wireline tools, especially highly deviated wells. In these situations, the LWD measurement ensures that some measurement of the subsurface is captured in the event that wireline operations are not possible. Timely LWD data can also be used to guide well placement so that the wellbore remains within the zone of interest or in the most productive portion of a reservoir, such as in highly variable shale reservoirs. Alternate Form: logging-while-drilling See: deviated hole, measurements-while-drilling, wireline log

formation evaluation while drilling

1. n. [Drilling, Shale Gas] Also known as logging while drilling or LWD, the measurement of formation properties during the excavation of the hole, or shortly thereafter, through the use of tools integrated into the bottomhole assembly. LWD, while sometimes risky and expensive, has the advantage of measuring properties of a formation before drilling fluids invade deeply. Further, many wellbores prove to be difficult or even impossible to measure with conventional wireline tools, especially highly deviated wells. In these situations, the LWD measurement ensures that some measurement of the subsurface is captured in the event that wireline operations are not possible. Timely LWD data can also be used to guide well placement so that the wellbore remains within the zone of interest or in the most productive portion of a reservoir, such as in highly variable shale reservoirs. See: bottomhole assembly, deviated hole, measurements-while-drilling, wireline log

directional drilling

1. n. [Drilling, Shale Gas] The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken downhole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a downhole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes. Directional drilling is common in shale reservoirs because it allows drillers to place the borehole in contact with the most productive reservoir rock. For more details, see The Defining Series: Elements of Hydraulic Fracturing. See: bottomhole assembly, crooked hole, deviated drilling, directional driller, directional well, dogleg, drill bit, driller, geosteering, horizontal drilling, mud motor, rotary drilling, rotary steerable system, slide, steerable motor

swellable packer

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

bottomhole static temperature

1. n. [Drilling, Well Completions] The temperature of the undisturbed formation at the final depth in a well. The formation cools during drilling, and most of the cooling dissipates after about 24 hours of static conditions, although it is theoretically impossible for the temperature to return to undisturbed conditions. This temperature is measured under static conditions after sufficient time has elapsed to negate any effects from circulating fluids. Tables, charts, and computer routines are used to predict BHST as functions of depth, geographic area, and various time functions. The BHST is generally higher than the bottomhole circulating temperature and can be an important factor when using temperature-sensitive tools or treatments. Alternate Form: BHST See: total depth

positive displacement pump

1. n. [Drilling, Well Workover and Intervention, Well Completions] A type of fluid pump in which the displacement volume of the pump is fixed for each rotation of the pump. Generally associated with high-pressure applications, positive-displacement pumps are commonly used in drilling operations to circulate the drilling fluid and in a range of oil and gas well treatments, such as cementing, matrix treatments and hydraulic fracturing.

connection gas

1. n. [Drilling] A brief influx of gas that is introduced into the drilling fluid when a pipe connection is made. Before making a connection, the driller stops the mud pumps, thereby allowing gas to enter the wellbore at depth. Gas may also be drawn into the wellbore by minor swabbing effects resulting from short movements of the drillstring that occur during the connection. Connection gas usually occurs after one lag interval following the connection. On a mud log, it will appear as a short peak above background levels. This peak often appears at 30-foot intervals, depending on the lengths of drillpipe being connected as the well is drilled. See: equivalent circulating density, trip gas

liner

1. n. [Drilling] A casing string that does not extend to the top of the wellbore, but instead is anchored or suspended from inside the bottom of the previous casing string. There is no difference between the casing joints themselves. The advantage to the well designer of a liner is a substantial savings in steel, and therefore capital costs. To save casing, however, additional tools and risk are involved. The well designer must trade off the additional tools, complexities and risks against the potential capital savings when deciding whether to design for a liner or a casing string that goes all the way to the top of the well (a "long string"). The liner can be fitted with special components so that it can be connected to the surface at a later time if need be. See: casing joint, casing string, reciprocate, underream

thread protector

1. n. [Drilling] A cheap, expendable, perhaps even disposable threaded shape to mate with threads on drillstring and casing components. Thread protectors prevent harmful impacts and other contact to the metal thread surfaces. Some protectors are strong enough and are fitted with lifting eyes so that they may be screwed into a joint of drillpipe, a drill collar or another component and a chain tied to the eye for lifting the joint. Except for this type, most of the other available styles of thread protectors are relatively inexpensive, being made from thermoplastics and various epoxy resins. See: drill collar

flapper valve

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

cathead

1. n. [Drilling] A clutched spool connected to the drawworks power system used to tension chains, cables, and softline rope.

makeup cathead

1. n. [Drilling] A clutched, rotating spool that enables the driller to use the drawworks motor to apply tension to a chain connected to the makeup tongs. This tensioned chain, acting at right angles to the tong handle, imparts torque to the connection being tightened. See: drawworks, tongs

breakout cathead

1. n. [Drilling] A clutching mechanism that permits the driller to apply high torque to a connection using the power of the drawworks motor.

gamma ray log

1. n. [Drilling] A common and inexpensive measurement of the natural emission of gamma rays by a formation. Gamma ray logs are particularly helpful because shales and sandstones typically have different gamma ray signatures that can be correlated readily between wells. See: signature

directional survey

1. n. [Drilling] A completed measurement of the inclination and azimuth of a location in a well (typically the total depth at the time of measurement). In both directional and straight holes, the position of the well must be known with reasonable accuracy to ensure the correct wellbore path and to know its position in the event a relief well must be drilled. The measurements themselves include inclination from vertical, and the azimuth (or compass heading) of the wellbore if the direction of the path is critical. These measurements are made at discrete points in the well, and the approximate path of the wellbore computed from the discrete points. Measurement devices range from simple pendulum-like devices to complex electronic accelerometers and gyroscopes used more often as MWD becomes more popular. In simple pendulum measurements, the position of a freely hanging pendulum relative to a measurement grid (attached to the housing of the tool and assumed to represent the path of the wellbore) is captured on photographic film. The film is developed and examined when the tool is removed from the wellbore, either on wireline or the next time pipe is tripped out of the hole. Synonyms: deviation survey See: survey

deviation survey

drill collar

1. n. [Drilling] A component of a drillstring that provides weight on bit for drilling. Drill collars are thick-walled tubular pieces machined from solid bars of steel, usually plain carbon steel but sometimes of nonmagnetic nickel-copper alloy or other nonmagnetic premium alloys. The bars of steel are drilled from end to end to provide a passage to pumping drilling fluids through the collars. The outside diameter of the steel bars may be machined slightly to ensure roundness, and in some cases may be machined with helical grooves ("spiral collars"). Last, threaded connections, male on one end and female on the other, are cut so multiple collars can be screwed together along with other downhole tools to make a bottomhole assembly (BHA). Gravity acts on the large mass of the collars to provide the downward force needed for the bits to efficiently break rock. To accurately control the amount of force applied to the bit, the driller carefully monitors the surface weight measured while the bit is just off the bottom of the wellbore. Next, the drillstring (and the drill bit), is slowly and carefully lowered until it touches bottom. After that point, as the driller continues to lower the top of the drillstring, more and more weight is applied to the bit, and correspondingly less weight is measured as hanging at the surface. If the surface measurement shows 20,000 lbm [9,080 kg] less weight than with the bit off bottom, then there should be 20,000 pounds force on the bit (in a vertical hole). Downhole MWD sensors measure weight-on-bit more accurately and transmit the data to the surface. See: bottomhole assembly, circulation system, collar, drilling fluid, keyseat, measurements-while-drilling, outside diameter, saver sub, sub, weight indicator

differential sticking

1. n. [Drilling] A condition whereby the drillstring cannot be moved (rotated or reciprocated) along the axis of the wellbore. Differential sticking typically occurs when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking is, for most drilling organizations, the greatest drilling problem worldwide in terms of time and financial cost. It is important to note that the sticking force is a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking the pipe as can a high differential pressure applied over a small area. Synonyms: differential pressure sticking, wall sticking See: low-colloid oil mud, mechanical sticking, overbalance, pill, reservoir pressure, stuck pipe

differential pressure sticking

1. n. [Drilling] A condition whereby the drillstring cannot be moved (rotated or reciprocated) along the axis of the wellbore. Differential sticking typically occurs when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking is, for most drilling organizations, the greatest drilling problem worldwide in terms of time and financial cost. It is important to note that the sticking force is a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking the pipe as can a high differential pressure applied over a small area. Synonyms: differential sticking, wall sticking See: low-colloid oil mud, mechanical sticking, overbalance, reservoir pressure, saltwater flow, stuck pipe

bit box

1. n. [Drilling] A container, usually made of steel and fitted with a sturdy lock, to store drill bits, especially higher-cost PDC and diamond bits. These bits are extremely costly but often small in size, so they are prone to theft. See: bit, diamond bit, polycrystalline diamond compact bit

cement head

1. n. [Drilling] A device fitted to the top joint of a casing string to hold a cement plug before it is pumped down the casing during the cementing operation. In most operations, a bottom plug is launched before the spacer or cement slurry. The top plug is released from the cement head after the spacer fluid. Most cement heads can hold both the top and bottom plugs. A manifold incorporated into the cement head assembly allows connection of a fluid circulation line. See: cement head

scratcher

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

packer

1. n. [Drilling] A device that can be run into a wellbore with a smaller initial outside diameter that then expands externally to seal the wellbore. Packers employ flexible, elastomeric elements that expand. The two most common forms are the production or test packer and the inflatable packer. The expansion of the former may be accomplished by squeezing the elastomeric elements (somewhat doughnut shaped) between two plates, forcing the sides to bulge outward. The expansion of the latter is accomplished by pumping a fluid into a bladder, in much the same fashion as a balloon, but having more robust construction. Production or test packers may be set in cased holes and inflatable packers are used in open or cased holes. They may be run on wireline, pipe or coiled tubing. Some packers are designed to be removable, while others are permanent. Permanent packers are constructed of materials that are easy to drill or mill out. See: cased hole, coiled tubing, completion, differential pressure, drillstem test, milling, openhole, production packer

ram blowout preventer

1. n. [Drilling] A device that can be used to quickly seal the top of the well in the event of a well control event (kick). A ram blowout preventer (BOP) consists of two halves of a cover for the well that are split down the middle. Large-diameter hydraulic cylinders, normally retracted, force the two halves of the cover together in the middle to seal the wellbore. These covers are constructed of steel for strength and fitted with elastomer components on the sealing surfaces. The halves of the covers, formally called ram blocks, are available in a variety of configurations. In some designs, they are flat at the mating surfaces to enable them to seal over an open wellbore. Other designs have a circular cutout in the middle that corresponds to the diameter of the pipe in the hole to seal the well when pipe is in the hole. These pipe rams effectively seal a limited range of pipe diameters. Variable-bore rams are designed to seal a wider range of pipe diameters, albeit at a sacrifice of other design criteria, notably element life and hang-off weight. Still other ram blocks are fitted with a tool steel-cutting surface to enable the ram BOPs to completely shear through drillpipe, hang the drillstring off on the ram blocks themselves and seal the wellbore. Obviously, such an action limits future options and is employed only as a last resort to regain pressure control of the wellbore. The various ram blocks can be changed in the ram preventers, enabling the well team to optimize BOP configuration for the particular hole section or operation in progress. See: annular BOP, blind ram, BOP stack, kick, snubbing, stripping

degasser

1. n. [Drilling] 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. See: desander, gas separator

top drive

1. n. [Drilling] A device that turns the drillstring. It consists of one or more motors (electric or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drillstring itself. The topdrive is suspended from the hook, so the rotary mechanism is free to travel up and down the derrick. This is radically different from the more conventional rotary table and kelly method of turning the drillstring because it enables drilling to be done with three joint stands instead of single joints of pipe. It also enables the driller to quickly engage the pumps or the rotary while tripping pipe, which cannot be done easily with the kelly system. While not a panacea, modern topdrives are a major improvement to drilling rig technology and are a large contributor to the ability to drill more difficult extended-reach wellbores. In addition, the topdrive enables drillers to minimize both frequency and cost per incident of stuck pipe. See: hook, kelly, make a connection, rotary table, stuck pipe

slips

1. n. [Drilling] A device used to grip the drillstring in a relatively nondamaging manner and suspend it in the rotary table. This device consists of three or more steel wedges that are hinged together, forming a near circle around the drillpipe. On the drillpipe side (inside surface), the slips are fitted with replaceable, hardened tool steel teeth that embed slightly into the side of the pipe. The outsides of the slips are tapered to match the taper of the rotary table. After the rig crew places the slips around the drillpipe and in the rotary, the driller slowly lowers the drillstring. As the teeth on the inside of the slips grip the pipe, the slips are pulled down. This downward force pulls the outer wedges down, providing a compressive force inward on the drillpipe and effectively locking everything together. Then the rig crew can unscrew the upper portion of the drillstring (kelly, saver sub, a joint or stand of pipe) while the lower part is suspended. After some other component is screwed onto the lower part of the drillstring, the driller raises the drillstring to unlock the gripping action of the slips, and the rig crew removes the slips from the rotary. See: kelly, make a connection, rotary table, saver sub, spinning chain, stand

positive displacement motor

1. n. [Drilling] A downhole motor used in the oil field to drive the drill bit or other downhole tools during directional drilling or performance drilling applications. As drilling fluid is pumped through the positive displacement motor, it converts the hydraulic power of the fluid into mechanical power to cause the bit to rotate. During directional drilling, this capability is used while drilling in sliding mode, when the drillstring is not rotated from the surface. Positive displacement motors can also be used for performance drilling, straight hole drilling, coring, underreaming, and milling operations. In straight hole drilling, the motor functions as a drilling performance tool to increase the rate of penetration and reduce casing wear by minimizing drillstring rotation. Alternate Form: PDM

antiwhirl bit

1. n. [Drilling] A drill bit, usually polycrystalline diamond compact bit (PDC) type, designed such that the individual cutting elements on the bit create a net imbalance force. This imbalance force pushes the bit against the side of the borehole, which in turn creates a stable rotating condition that resists backwards whirling, wobbling and downhole vibration. Antiwhirl bits allow faster rates of penetration, yet achieve longer bit life than more conventional bits, which are not dynamically biased to run smoothly, are inherently unstable, are vibration-prone and thus have shorter lives. No bit is whirl-proof, however. See: bit, bottomhole assembly, drilling rate, polycrystalline diamond compact bit, roller cone bit

settling pit

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

air drilling

1. n. [Drilling] A drilling technique whereby gases (typically compressed air or nitrogen) are used to cool the drill bit and lift cuttings out of the wellbore, instead of the more conventional use of liquids. The advantages of air drilling are that it is usually much faster than drilling with liquids and it may eliminate lost circulation problems. The disadvantages are the inability to control the influx of formation fluid into the wellbore and the destabilization of the borehole wall in the absence of the wellbore pressure typically provided by liquids. See: lost circulation, mist drilling

fixed-cutter bit

1. n. [Drilling] A drilling tool that uses polycrystalline diamond compact (PDC) cutters to shear rock with a continuous scraping motion. These cutters are synthetic diamond disks about 1/8-in thick and about 1/2 to 1 in in diameter. PDC bits are effective at drilling shale formations, especially when used in combination with oil-base muds. Synonyms: polycrystalline diamond compact bit, polycrystalline diamond compact bit See: antiwhirl bit, bit

drag bit

1. n. [Drilling] A drilling tool that uses polycrystalline diamond compact (PDC) cutters to shear rock with a continuous scraping motion. These cutters are synthetic diamond disks about 1/8-in thick and between 1/2- and 1-in diameter. PDC bits are effective at drilling shale formations, especially when used in combination with oil-base muds. Synonyms: drag bit, polycrystalline diamond compact bit See: antiwhirl bit, bit

polycrystalline diamond compact (PDC) bit

1. n. [Drilling] A drilling tool that uses polycrystalline diamond compact (PDC) cutters to shear rock with a continuous scraping motion. These cutters are synthetic diamond disks about 1/8-in. thick and about 1/2 to 1 in. in diameter. PDC bits are effective at drilling shale formations, especially when used in combination with oil-base muds. Synonyms: fixed-cutter bit, polycrystalline diamond compact bit See: bit

cellar

1. n. [Drilling] A dug-out area, possibly lined with wood, cement or very large diameter (6 ft [1.8 m]) thin-wall pipe, located below the rig. The cellar serves as a cavity in which the casing spool and casinghead reside. The depth of the cellar is such that the master valve of the Christmas tree are easy to reach from ground level. On smaller rigs, the cellar also serves as the place where the lower part of the BOP stack resides, which reduces the rig height necessary to clear the BOP stack on the top. Prior to setting surface casing, the cellar also takes mud returns from the well, which are pumped back to the surface mud equipment.

box

1. n. [Drilling] A female threadform (internally threaded) for tubular goods and drillstring components. See: back off, break out, casing, casing string, mousehole, pin

packoff

1. n. [Drilling] A flexible, usually elastomeric sealing element and housing used to seal an irregular surface such as a wireline. Alternate Form: pack off

roughneck

1. n. [Drilling] A floor hand, or member of the drilling crew who works under the direction of the driller to make or break connections as drillpipe is tripped in or out of the hole. On most drilling rigs, roughnecks are also responsible for maintaining and repairing much of the equipment found on the drill floor and derrick. The roughneck typically ranks above a roustabout and beneath a derrickman, and reports to the driller. See: drilling crew

kick

1. n. [Drilling] A flow of formation fluids into the wellbore during drilling operations. The kick is physically caused by the pressure in the wellbore being less than that of the formation fluids, thus causing flow. This condition of lower wellbore pressure than the formation is caused in two ways. First, if the mud weight is too low, then the hydrostatic pressure exerted on the formation by the fluid column may be insufficient to hold the formation fluid in the formation. This can happen if the mud density is suddenly lightened or is not to specification to begin with, or if a drilled formation has a higher pressure than anticipated. This type of kick might be called an underbalanced kick. The second way a kick can occur is if dynamic and transient fluid pressure effects, usually due to motion of the drillstring or casing, effectively lower the pressure in the wellbore below that of the formation. This second kick type could be called an induced kick. See: choke line, differential pressure, hydrostatic pressure, kill, mud density, mud weight, pressure hunt, ram blowout preventer, snubbing, swab, wildcat

annular gas flow

1. n. [Drilling] A flow of formation gas in the annulus between a casing string and the borehole wall. Annular gas flows occur when there is insufficient hydrostatic pressure to restrain the gas. They can occur in uncemented intervals and even in cemented sections if the cement bond is poor. After cementing, as the cement begins to harden, a gel-like structure forms that effectively supports the solid material in the cement slurry. However, during this initial gelling period, the cement has no appreciable strength. Hence, with the solid (weighting) material now supported by the gel structure, the effective density of the slurry that the reservoir experiences falls rather suddenly to the density of the mix water of the cement, which is usually freshwater, whose density is 8.34 lbm/galUS, or a gradient of 0.434 psi/ft of vertical column height. Various chemical additives have been developed to reduce annular gas flow. See: cement

thief zone

1. n. [Drilling] A formation encountered during drilling into which circulating fluids can be lost. See: lost circulation, pill

float joint

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

fishing tool

1. n. [Drilling] A general term for special mechanical devices used to aid the recovery of equipment lost downhole. These devices generally fall into four classes: diagnostic, inside grappling, outside grappling, and force intensifiers or jars. Diagnostic devices may range from a simple impression block made in a soft metal, usually lead, that is dropped rapidly onto the top of the fish so that upon inspection at the surface, the fisherman may be able to custom design a tool to facilitate attachment to and removal of the fish. Other diagnostic tools may include electronic instruments and even downhole sonic or visual-bandwidth cameras. Inside grappling devices, usually called spears, generally have a tapered and threaded profile, enabling the fisherman to first guide the tool into the top of the fish, and then thread the fishing tool into the top of the fish so that recovery may be attempted. Outside grappling devices, usually called overshots, are fitted with threads or another shape that "swallows" the fish and does not release it as it is pulled out of the hole. Overshots are also fitted with a crude drilling surface at the bottom, so that the overshot may be lightly drilled over the fish, sometimes to remove rock or metallic junk that may be part of the sticking mechanism. Jars are mechanical downhole hammers, which enable the fisherman to deliver high-impact loads to the fish, far in excess of what could be applied in a quasi-static pull from the surface. See: cut-and-thread fishing technique, intensifier, jar, mechanical sticking, overshot, safety joint, washover pipe

mobile offshore drilling unit

1. n. [Drilling] A generic term for several classes of self-contained floatable or floating drilling machines such as jackups, semisubmersibles, and submersibles. Alternate Form: MODU See: jackup rig, semisubmersible, submersible drilling rig

MODU

gumbo

1. n. [Drilling] A generic term for soft, sticky, swelling clay formations that are frequently encountered in surface holes offshore or in sedimentary basins onshore near seas. This clay fouls drilling tools and plugs piping, both severe problems for drilling crews. See: native clay

tubulars

1. n. [Drilling] A generic term pertaining to any type of oilfield pipe, such as drill pipe, drill collars, pup joints, casing, production tubing and pipeline.

choke line

1. n. [Drilling] A high-pressure pipe leading from an outlet on the BOP stack to the backpressure choke and associated manifold. During well-control operations, the fluid under pressure in the wellbore flows out of the well through the choke line to the choke, reducing the fluid pressure to atmospheric pressure. In floating offshore operations, the choke and kill lines exit the subsea BOP stack and then run along the outside of the drilling riser to the surface. The volumetric and frictional effects of these long choke and kill lines must be considered to properly control the well. See: adjustable choke, choke manifold, kick, kill line, well control

kill line

1. n. [Drilling] A high-pressure pipe leading from an outlet on the BOP stack to the high-pressure rig pumps. During normal well control operations, kill fluid is pumped through the drillstring and annular fluid is taken out of the well through the choke line to the choke, which drops the fluid pressure to atmospheric pressure. If the drillpipe is inaccessible, it may be necessary to pump heavy drilling fluid in the top of the well, wait for the fluid to fall under the force of gravity, and then remove fluid from the annulus. In such an operation, while one high pressure line would suffice, it is more convenient to have two. In addition, this provides a measure of redundancy for the operation. In floating offshore operations, the choke and kill lines exit the subsea BOP stack and run along the outside of the riser to the surface. The volumetric and frictional effects of these long choke and kill lines must be taken into account to properly control the well. See: blowout preventer, BOP stack, choke line, well control

elevator

1. n. [Drilling] A hinged mechanism that may be closed around drillpipe or other drillstring components to facilitate lowering them into the wellbore or lifting them out of the wellbore. In the closed position, the elevator arms are latched together to form a load-bearing ring around the component. A shoulder or taper on the component to be lifted is larger in size than the inside diameter of the closed elevator. In the open position, the device splits roughly into two halves and may be swung away from the drillstring component. See: hook, racking back pipe, zip collars

bit record

1. n. [Drilling] A historical record of how a bit performed in a particular wellbore. The bit record includes such data as the depth the bit was put into the well, the distance the bit drilled, the hours the bit was being used "on bottom" or "rotating", the mud type and weight, the nozzle sizes, the weight placed on the bit, the rotating speed, and hydraulic flow information. The data are usually updated daily. When the bit is pulled at the end of its use, the condition of the bit and the reason it was pulled out of the hole are also recorded. Bit records are often shared among operators and bit companies and are one of many valuable sources of data from offset wells for well design engineers. See: offset well

desander

1. n. [Drilling] 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. See: degasser, desilter, mud cleaner, shale shaker

desilter

1. n. [Drilling] 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. See: drill solids

blowout preventer

1. n. [Drilling] A large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation. BOPs come in a variety of styles, sizes, and pressure ratings. Some can effectively close over an open wellbore. Some are designed to seal around tubular components in the well (drillpipe, casing or tubing). Others are fitted with hardened steel shearing surfaces that can actually cut through drillpipe. Because BOPs are critically important to the safety of the crew, the rig, and the wellbore itself, BOPs are inspected, tested, and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type, and legal requirements. BOP tests vary from daily function testing on critical wells to monthly or less frequent testing on wells thought to have low probability of well control problems. Alternate Form: BOP See: annular BOP, blowout, BOP stack, casing string, drilling break, hook load, inside blowout preventer, kill line, mud density, nipple down, pipe ram, ram blowout preventer, shear ram, surface casing, underground blowout, wildcat

BOP

1. n. [Drilling] A large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation. BOPs come in a variety of styles, sizes, and pressure ratings. Some can effectively close over an open wellbore. Some are designed to seal around tubular components in the well (drillpipe, casing, or tubing). Others are fitted with hardened steel shearing surfaces that can actually cut through drillpipe. Because BOPs are critically important to the safety of the crew, the rig, and the wellbore itself, BOPs are inspected, tested, and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type, and legal requirements. BOP tests vary from daily function testing on critical wells to monthly or less frequent testing on wells thought to have low probability of well control problems. Alternate Form: blowout preventer See: choke line

annular BOP

1. n. [Drilling] A large valve used to control wellbore fluids. In this type of valve, the sealing element resembles a large rubber doughnut that is mechanically squeezed inward to seal on either pipe (drill collar, drillpipe, casing, or tubing) or the openhole. The ability to seal on a variety of pipe sizes is one advantage the annular blowout preventer has over the ram blowout preventer. Most blowout preventer (BOP) stacks contain at least one annular BOP at the top of the BOP stack, and one or more ram-type preventers below. While not considered as reliable in sealing over the openhole as around tubulars, the elastomeric sealing doughnut is required by API specifications to seal adequately over the openhole as part of its certification process. Synonyms: annular BOP See: blowout preventer, snubbing, stripping

rotary hose

1. n. [Drilling] A large-diameter (3- to 5-in. inside diameter), high-pressure flexible line used to connect the standpipe to the swivel. This flexible piping arrangement permits the kelly (and, in turn, the drillstring and bit) to be raised or lowered while drilling fluid is pumped through the drillstring. The simultaneous lowering of the drillstring while pumping fluid is critical to the drilling operation. Synonyms: kelly hose See: gooseneck, kelly, standpipe, swivel

kelly hose

1. n. [Drilling] A large-diameter (3- to 5-in. inside diameter), high-pressure flexible line used to connect the standpipe to the swivel. This flexible piping arrangement permits the kelly (and, in turn, the drillstring and bit) to be raised or lowered while drilling fluid is pumped through the drillstring. The simultaneous lowering of the drillstring while pumping fluid is critical to the drilling operation. Synonyms: rotary hose See: gooseneck, kelly, standpipe, swivel

drilling riser

1. n. [Drilling] A large-diameter pipe that connects the subsea BOP stack to a floating surface rig to take mud returns 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. See: BOP stack, choke line, slip joint

marine drilling riser

surface casing

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

spinning chain

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

intermediate casing string

1. n. [Drilling] A length of pipe used below the surface casing string, but before the production casing is run, to isolate one or more zones of the openhole to enable deepening of the well. There may be several intermediate casing strings. Depending on well conditions, these strings may have higher pressure integrity than the prior casing strings, especially when abnormally pressured formations are expected during the drilling of the next openhole section. See: casing string, production casing

kelly

1. n. [Drilling] A long square or hexagonal steel bar with a hole drilled through the middle for a fluid path. The kelly is used to transmit rotary motion from the rotary table or kelly bushing to the drillstring, while allowing the drillstring to be lowered or raised during rotation. The kelly goes through the kelly bushing, which is driven by the rotary table. The kelly bushing has an inside profile matching the kelly's outside profile (either square or hexagonal), but with slightly larger dimensions so that the kelly can freely move up and down inside. See: circulation system, hook, junk basket, kelly bushing, kelly hose, kelly spinner, make a connection, mousehole, rathole, rotary bushing, rotary table, saver sub, slips, top drive

coiled tubing

1. n. [Drilling] A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4-1/2 in.) and the spool size, coiled tubing can range from 2,000 ft to 15,000 ft [610 to 4,570 m] or greater length. For more details, The Defining Series: Introduction to Coiled Tubing. Synonyms: endless tubing, reeled tubing Alternate Form: CT See: coiled tubing drilling, packer

lubricator

1. n. [Drilling] A long, high-pressure pipe fitted to the top of a wellhead or Christmas tree so that tools may be put into a high-pressure well. The top of the lubricator assembly includes a high-pressure grease-injection section and sealing elements. The lubricator is installed on top of the tree and tested, the tools placed in the lubricator and the lubricator pressurized to wellbore pressure. Then the top valves of the tree are opened to enable the tools to fall or be pumped into the wellbore under pressure. To remove the tools, the reverse process is used: the tools are pulled up into the lubricator under wellbore pressure, the tree valves are closed, the lubricator pressure is bled off, and then the lubricator may be opened to remove the tools.

catwalk

1. n. [Drilling] A long, rectangular platform about 3 ft [0.9 m] high, usually made of steel and located perpendicular to the vee-door at the bottom of the slide. This platform is used as a staging area for rig and drillstring tools, components that are about to be picked up and run, or components that have been run and are being laid down. A catwalk is also the functionally similar staging area, especially on offshore drilling rigs, that may not be a separate or raised structure. See: pipe rack

1. n. [Drilling] A male threadform, especially in tubular goods and drillstring components. See: back off, box, break out, casing, casing string

drillship

1. n. [Drilling] A maritime vessel modified to include a drilling rig and special station-keeping equipment. The vessel is typically capable of operating in deep water. A drillship must stay relatively stationary on location in the water for extended periods of time. This positioning may be accomplished with multiple anchors, dynamic propulsion (thrusters) or a combination of these. Drillships typically carry larger payloads than semisubmersible drilling vessels, but their motion characteristics are usually inferior. See: dynamic positioning, moon pool

mechanical specific energy

1. n. [Drilling] A measure of drilling efficiency. Mechanical specific energy (MSE) is the energy required to remove a unit volume of rock. For optimum drilling efficiency, the objective is to minimize the MSE and to maximize the rate of penetration (ROP). To control the MSE, drillers can control the weight on bit (WOB), torque, ROP and drillbit revolutions per minute (rpm). Reference: Teale R: "The Concept of Specific Energy in Rock Drilling," International Journal of Rock Mechanics and Mining Sciences & Geomechanics Abstracts 2, no. 1 (March 1965): 57-73. Alternate Form: MSE

hydraulic horsepower

1. n. [Drilling] A measure of the energy per unit of time that is being expended across the bit nozzles. It is commonly calculated with the equation HHP=P*Q/1714, where P stands for pressure in pounds per square in., Q stands for flow rate in gallons per minute, and 1714 is a conversion factor necessary to yield HHP in terms of horsepower. Bit manufacturers often recommend that fluid hydraulics energy across the bit nozzles be in a particular HHP range, for example 2.0 to 7.0 HHP, to ensure adequate bit tooth and bottom-of-hole cleaning (the minimum HHP) and to avoid premature erosion of the bit itself (the maximum HHP). Alternate Form: HHP See: bit nozzle, mud motor, positive displacement pump

HHP

kelly spinner

1. n. [Drilling] A mechanical device for rotating the kelly. The kelly spinner is typically pneumatic. It is a relatively low torque device, useful only for the initial makeup of threaded tool joints. It is not strong enough for proper torque of the tool joint or for rotating the drillstring itself. The kelly spinner has largely replaced the infamous spinning chains, which were responsible for numerous injuries on the rig floor. See: kelly, spinning chain, tool joint

casing centralizer

1. n. [Drilling] A mechanical device that keeps casing from contacting the wellbore wall. A continuous 360° annular space around casing allows cement to completely seal the casing to the borehole wall. There are two distinct classes of centralizers. The older and more common is a simple, low-cost bow-spring design. Since the bow springs are slightly larger than the wellbore, they can provide complete centralization in vertical or slightly deviated wells. However, they do not support the weight of the casing very well in deviated wellbores. The second type is a rigid blade design. This type is rugged and works well even in deviated wellbores, but since the centralizers are smaller than the wellbore, they will not provide as good centralization as bow-spring type centralizers in vertical wells. Rigid-blade casing centralizers are slightly more expensive and can cause trouble downhole if the wellbore is not in excellent condition. See: annulus, bow-spring centralizer, deviated hole

swivel

1. n. [Drilling] A mechanical device that suspends the weight of the drillstring. It is designed to allow rotation of the drillstring beneath it conveying high volumes of high-pressure drilling mud between the rig's circulation system and the drillstring. See: hook, kelly hose, standpipe, traveling block

jar

1. n. [Drilling] A mechanical device used downhole to deliver an impact load to another downhole component, especially when that component is stuck. There are two primary types, hydraulic and mechanical jars. While their respective designs are quite different, their operation is similar. Energy is stored in the drillstring and suddenly released by the jar when it fires. The principle is similar to that of a carpenter using a hammer. Kinetic energy is stored in the hammer as it is swung, and suddenly released to the nail and board when the hammer strikes the nail. Jars can be designed to strike up, down, or both. In the case of jarring up above a stuck bottomhole assembly, the driller slowly pulls up on the drillstring but the BHA does not move. Since the top of the drillstring is moving up, this means that the drillstring itself is stretching and storing energy. When the jars reach their firing point, they suddenly allow one section of the jar to move axially relative to a second, being pulled up rapidly in much the same way that one end of a stretched spring moves when released. After a few inches of movement, this moving section slams into a steel shoulder, imparting an impact load. In addition to the mechanical and hydraulic versions, jars are classified as drilling jars or fishing jars. The operation of the two types is similar, and both deliver approximately the same impact blow, but the drilling jar is built such that it can better withstand the rotary and vibrational loading associated with drilling. See: bottomhole assembly, fishing tool

bow-spring centralizer

1. n. [Drilling] A metal strip shaped like a hunting bow and attached to a tool or to the outside of casing. Bow-spring centralizers are used to keep casing in the center of a wellbore or casing ("centralized") prior to and during a cement job. See: casing centralizer, cementing, centralizer

cut and thread fishing technique

1. n. [Drilling] A method for recovering wireline stuck in a wellbore. In cut-and-thread operations, the wireline is gripped securely with a special tool and cut at the surface. The cut end is threaded through a stand of drillpipe. While the pipe hangs in the wellbore, the wireline is threaded through another stand of drillpipe, which is screwed onto the stand in the wellbore. The process is repeated until the stuck wireline is recovered. This technique, while dangerous and time-consuming, is known to improve greatly the chances of full recovery of the wireline and the tool at its end in the shortest overall time compared with trying to grab the wireline in the openhole with fishing tools. See: drillpipe, fishing tool, stand

cut-and-thread fishing technique

cable-tool drilling

1. n. [Drilling] A method of drilling whereby an impact tool or bit, suspended in the well from a steel cable, is dropped repeatedly on the bottom of the hole to crush the rock. The tool is usually fitted with some sort of cuttings basket to trap the cuttings along the side of the tool. After a few impacts on the bottom of the hole, the cable is reeled in and the cuttings basket emptied, or a bailer is used to remove cuttings from the well. The tool is reeled back to the bottom of the hole and the process repeated. Due to the increasing time required to retrieve and deploy the bit as the well is deepened, the cable-tool method is limited to shallow depths. Though largely obsolete, cable-tool operations are still used to drill holes for explosive-charge placement (such as for acquisition of surface seismic data) and water wells. Alternate Form: basket sub See: rotary drilling

rotary drilling

1. n. [Drilling] A method of making hole that relies on continuous circular motion of the bit to break rock at the bottom of the hole. This method, made popular after the discovery of the East Texas Field by "Dad" Joiner in 1930, is much more efficient than the alternative, cable tool drilling. Rotary drilling is a nearly continuous process, because cuttings are removed as drilling fluids circulate through the bit and up the wellbore to the surface. Cable tool operations are discontinuous and cuttings removal is inefficient. This difference in efficiency becomes particularly significant as hole depth increases. See: cable-tool drilling, cuttings, directional drilling, settling pit, steerable motor

mud pulse telemetry

1. n. [Drilling] A method of transmitting LWD and MWD data acquired downhole to the surface, using pressure pulses in the mud system. The measurements are usually converted into an amplitude- or frequency-modulated pattern of mud pulses. The same telemetry system is used to transmit commands from the surface. See: logging-while-drilling, measurements-while-drilling, survey, telemetry

jet mixer

1. n. [Drilling] A mixing system used to mix dry powder materials with a base liquid, such as cement slurry or drilling muds. A funnel for the dry powder is mounted above a profiled bowl that incorporates one or more jets through which the liquid is pumped. The venturi effect created by the jets draws the powder into the turbulent stream, providing a rapid and efficient mixing action. Synonyms: jet

steerable motor

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

suction pit

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

worm

1. n. [Drilling] A new, completely inexperienced member of the drilling crew. Such a crewmember is stereotyped as prone to making mistakes and being injured, and typically endures pranks played on him by the drilling crew. While the terms weevil and its close cousin, worm, are used widely, they are labels of inexperience, rather than derogatory terms. Synonyms: weevil

weevil

upset

1. n. [Drilling] A part at the end of tubulars, such as drillpipe, casing or other tubing, which has extra thickness and strength to compensate for the loss of metal in the threaded ends. See: ringworm corrosion

threadform

1. n. [Drilling] A particular style or type of threaded connection, especially as used for rotary shouldered connections. Threadforms come in a variety of sizes, pitches, tapers, threads per in., and individual thread profiles. Fortunately, each of these varieties has a published standard, either considered public and maintained by the American Petroleum Institute (API) or maintained by operating or service companies as proprietary information. See: back off, break out, pin

semisubmersible

1. n. [Drilling] A particular type of floating vessel that is supported primarily on large pontoon-like structures submerged below the sea surface. The operating decks are elevated perhaps 100 or more feet above the pontoons on large steel columns. This design has the advantage of submerging most of the area of components in contact with the sea and minimizing loading from waves and wind. Semisubmersibles can operate in a wide range of water depths, including deep water. They are usually anchored with six to twelve anchors tethered by strong chains and wire cables, which are computer controlled to maintain stationkeeping. Semisubmersibles (called semisubs or simply semis) can be used for drilling, workover operations, and production platforms, depending on the equipment with which they are equipped. When fitted with a drilling package, they may be called semisubmersible drilling rigs. See: drillship, dynamic positioning, mobile offshore drilling unit, workover

submersible drilling rig

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

dogleg

1. n. [Drilling] A particularly crooked place in a wellbore where the trajectory of the wellbore in three-dimensional space changes rapidly. While a dogleg is sometimes created intentionally by directional drillers, the term more commonly refers to a section of the hole that changes direction faster than anticipated or desired, usually with harmful side effects. In surveying wellbore trajectories, a standard calculation of dogleg severity is made, usually expressed in two-dimensional degrees per 100 feet [degrees per 30 m] of wellbore length. There are several difficulties associated with doglegs. First, the wellbore is not located in the planned path. Second is the possibility that a planned casing string may no longer easily fit through the curved section. Third, repeated abrasion by the drillstring in a particular location of the dogleg results in a worn spot called a keyseat, in which the bottomhole assembly components may become stuck as they are pulled through the section. Fourth, casing successfully cemented through the dogleg may wear unusually quickly due to higher contact forces between the drillstring and the inner diameter (ID) of the casing through the dogleg. Fifth, a relatively stiff bottomhole assembly may not easily fit through the dogleg section drilled with a relatively limber BHA. Sixth, excessive doglegs increase the overall friction to the drillstring, increasing the likelihood of getting stuck or not reaching the planned total depth. Usually these problems are manageable. If the dogleg impairs the well, remedial action can be taken, such as reaming or underreaming through the dogleg, or even sidetracking in extreme situations. See: bottomhole assembly, casing string, directional driller, inside diameter, ream, sidetrack, total depth, underream

hostile environment

1. n. [Drilling] A particularly difficult set of well conditions that may detrimentally affect steel, elastomers, mud additives, electronics, or tools and tool components. Such conditions typically include excessive temperatures, the presence of acid gases (H2S, CO2), chlorides, high pressures and, more recently, extreme measured depths. See: hydrogen sulfide, wireline log

mud motor

1. n. [Drilling] A positive displacement drilling motor that uses hydraulic horsepower of the drilling fluid to drive the drill bit. Mud motors are used extensively in directional drilling operations. See: bottomhole assembly, differential pressure, directional drilling, hydraulic horsepower

rotating control device

1. n. [Drilling] A pressure-control device used during drilling for the purpose of making a seal around the drillstring while the drillstring rotates. This device is intended to contain hydrocarbons or other wellbore fluids and prevent their release to the atmosphere. Alternate Form: RCD

drillstem test

1. n. [Drilling] A procedure to determine the productive capacity, pressure, permeability or extent (or a combination of these) of a hydrocarbon reservoir. While several different proprietary hardware sets are available to accomplish this, the common idea is to isolate the zone of interest with temporary packers. Next, one or more valves are opened to produce the reservoir fluids through the drillpipe and allow the well to flow for a time. Finally, the operator kills the well, closes the valves, removes the packers and trips the tools out of the hole. Depending on the requirements and goals for the test, it may be of short (one hour or less) or long (several days or weeks) duration and there might be more than one flow period and pressure buildup period. Alternate Form: DST See: barefoot, flow period, kill, packer, pressure buildup, safety joint, trip out

hardbanding

1. n. [Drilling] A process in which a wear-resistant alloy is applied to the tool joints of drillpipe or drill collars to prolong the life of oilfield tubulars. Hardbanding is applied where rotational and axial friction associated with drilling and tripping create excessive abrasive wear between drillstring and casing, or between drillstring and rock. Hard alloy overlays are applied to the points of greatest contact, typically using advanced welding techniques. Typical alloys used in this process range from ultra-wear resistant tungsten carbide, to less abrasive chromium carbide, titanium carbide and borides. Some hardbanding processes take a different approach to reducing wear in tubulars, using materials that achieve a low coefficient of friction used to protect the drillstring from abrasion. See: tool joint, upset, hardfacing

sheave

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

zip groove

1. n. [Drilling] A reduced-diameter section that has been machined at the box (up) end of a drill collar (usually a straight drill collar) so that the collar may be more easily handled with open-and-close elevators. The elevators close around the reduced-diameter section, latch securely, and a shoulder on the elevators prevents the larger diameter end of the collar from passing through the elevators, so the collars can be lifted. If zip grooves are not used on the collars, special lifting subs must be threaded into each stand of collars for lifting, which is time-consuming and less efficient compared with zip grooves. The primary drawback to zip grooves is that they may reduce the life of the collar by putting an effective limit on how many times the collar threads may be recut. See: zip collars

cat line

1. n. [Drilling] A relatively thin cable used with other equipment to move small rig and drillstring components and to provide tension on the tongs for tightening or loosening threaded connections.

catline

1. n. [Drilling] A relatively thin cable used with other equipment to move small rig and drillstring components and to provide tension on the tongs for tightening or loosening threaded connections. See: cat line

cement bond log

1. n. [Drilling] A representation of the integrity of the cement job, especially whether the cement is adhering solidly to the outside of the casing. The log is typically obtained from one of a variety of sonic-type tools. The newer versions, called cement evaluation logs, along with their processing software, can give detailed, 360° representations of the integrity of the cement job, whereas older versions may display a single line representing the integrated integrity around the casing. Alternate Form: cement evaluation log

cement evaluation log

caliper log

1. n. [Drilling] A representation of the measured diameter of a borehole along its depth. Caliper logs are usually measured mechanically, with only a few using sonic devices. The tools measure diameter at a specific chord across the well. Because wellbores are usually irregular (rugose), it is important to have a tool that simultaneously measures diameter at several different locations. Such a tool is called a multifinger caliper. Drilling engineers or rigsite personnel use caliper measurement as a qualitative indication of both the condition of the wellbore and the degree to which the mud system has maintained hole stability. Caliper data are integrated to determine the volume of the openhole, which is then used in planning cementing operations. See: cementing, openhole

standpipe

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

cementing plug

1. n. [Drilling] A rubber plug used to separate the cement slurry from other fluids, reducing contamination and maintaining predictable slurry performance. Two types of cementing plug are typically used on a cementing operation. The bottom plug is launched ahead of the cement slurry to minimize contamination by fluids inside the casing prior to cementing. A diaphragm in the plug body ruptures to allow the cement slurry to pass through after the plug reaches the landing collar. The top plug has a solid body that provides positive indication of contact with the landing collar and bottom plug through an increase in pump pressure. Synonyms: wiper plug

tight hole

1. n. [Drilling] A section of a wellbore, usually openhole, where larger diameter components of the drillstring, such as drillpipe tool joints, drill collars, stabilizers, and the bit, may experience resistance when the driller attempts to pull them through these sections. See: openhole, tool joint

jackup

1. n. [Drilling] A self-contained combination drilling rig and floating barge, fitted with long support legs that can be raised or lowered independently of each other. The jackup, as it is known informally, is towed onto location with its legs up and the barge section floating on the water. Upon arrival at the drilling location, the legs are jacked down onto the seafloor, preloaded to securely drive them into the seabottom, and then all three legs are jacked further down. Since the legs have been preloaded and will not penetrate the seafloor further, this jacking down of the legs has the effect of raising the jacking mechanism, which is attached to the barge and drilling package. In this manner, the entire barge and drilling structure are slowly raised above the water to a predetermined height above the water, so that wave, tidal and current loading acts only on the relatively small legs and not the bulky barge and drilling package. See: bridge, mobile offshore drilling unit, Texas deck

jackup rig

choke manifold

1. n. [Drilling] A set of high-pressure valves and associated piping that usually includes at least two adjustable chokes, arranged such that one adjustable choke may be isolated and taken out of service for repair and refurbishment while well flow is directed through the other one. See: choke line

block

1. n. [Drilling] A set of pulleys used to gain mechanical advantage in lifting or dragging heavy objects. There are two large blocks on a drilling rig: the crown block and the traveling block. Each has several sheaves that are rigged with steel drilling cable or line such that the traveling block may be raised (or lowered) by reeling in (or out) a spool of drilling line on the drawworks. See: sheave

BOP stack

1. n. [Drilling] A set of two or more BOPs used to ensure pressure control of a well. A typical stack might consist of one to six ram-type preventers and, optionally, one or two annular-type preventers. A typical stack configuration has the ram preventers on the bottom and the annular preventers at the top. The configuration of the stack preventers is optimized to provide maximum pressure integrity, safety and flexibility in the event of a well control incident. For example, in a multiple ram configuration, one set of rams might be fitted to close on 5-in diameter drillpipe, another set configured for 4 1/2-in drillpipe, a third fitted with blind rams to close on the openhole, and a fourth fitted with a shear ram that can cut and hang-off the drillpipe as a last resort. It is common to have an annular preventer or two on the top of the stack since annulars can be closed over a wide range of tubular sizes and the openhole, but are typically not rated for pressures as high as ram preventers. The BOP stack also includes various spools, adapters and piping outlets to permit the circulation of wellbore fluids under pressure in the event of a well control incident. See: annular BOP, blind ram, blowout preventer, casinghead, cellar, drilling riser, dynamic positioning, kill line, nipple up, ram blowout preventer, ram preventer, shut-in bottomhole pressure, shut-in pressure, Texas deck

saver sub

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

casing coupling

1. n. [Drilling] A short length of pipe used to connect two joints of casing. A casing coupling has internal threads (female threadform) machined to match the external threads (male threadform) of the long joints of casing. The two joints of casing are threaded into opposite ends of the casing coupling. See: casing collar, collar

keyseat

1. n. [Drilling] A small-diameter channel worn into the side of a larger diameter wellbore. This can be the result of a sharp change in direction of the wellbore (a dogleg), or if a hard formation ledge is left between softer formations that enlarge over time. In either case, the diameter of the channel is typically similar to the diameter of the drillpipe. When larger diameter drilling tools such as tool joints, drill collars, stabilizers, and bits are pulled into the channel, their larger diameters will not pass and the larger diameter tools may become stuck in the keyseat. Preventive measures include keeping any turns in the wellbore gradual and smooth. The remedy to keyseating involves enlarging the worn channel so that the larger diameter tools will fit through it. See: dogleg, drill collar, mechanical sticking, tool joint

jet

1. n. [Drilling] A small-diameter tungsten carbide nozzle used in drill bits to produce a high-velocity drilling fluid stream exiting the bit. Synonyms: jet mixer See: bit

bit breaker

1. n. [Drilling] A special tool used by the rig crew to prevent the drill bit from turning while the bit sub on top of it is tightened or loosened. Bits have noncylindrical shapes, so the conventional wrenches used by the rig crew to tighten cylindrical shapes like pipes do not properly fit the bits. In addition, some bits, such as PDC bits, have a wide range of unusual and asymmetric shapes or profiles. The bit breaker must match the bit profile or the bit may be ruined before ever being used. See: bit, polycrystalline diamond compact bit, round trip, sub

slant rig

1. n. [Drilling] A specially designed drilling rig capable of drilling directional wells. See: directional well

slant-hole rig

1. n. [Drilling] A specially designed drilling rig capable of drilling directional wells. See: directional well

pipe dope

1. n. [Drilling] A specially formulated blend of lubricating grease and fine metallic particles that prevents thread galling (a particular form of metal-to-metal damage) and seals the roots of threads. The American Petroleum Institute (API) specifies properties of pipe dope, including its coefficient of friction. The rig crew applies copious amounts of pipe dope to the drillpipe tool joints every time a connection is made. See: connection, dope, tool joint

Geronimo line

1. n. [Drilling] A steel cable attached to the rig derrick or mast near the work platform for the derrickman. This cable is anchored at surface level (on a vessel or the Earth) away from the mast in a loose catenary profile, and fitted with a handle and hand brake that is stored at the top. The escape line provides a rapid escape path for the derrickman should well conditions or massive mechanical failure warrant. In such a case the derrickman would disconnect his safety belt from the rig, rehook it over the escape line if time permitted, firmly grip the tee-bar handle and ride the trolley down the cable while holding on to the handle with his hands. The escape line is also known as the "Geronimo line." See: derrick, derrickman, mast

escape line

rathole

1. n. [Drilling] A storage place for the kelly, consisting of an opening in the rig floor fitted with a piece of casing with an internal diameter larger than the outside diameter of the kelly, but less than that of the upper kelly valve so that the kelly may be lowered into the rathole until the upper kelly valve rests on the top of the piece of casing. See: kelly, mousehole

tapered string

1. n. [Drilling] A string of drillpipe or casing that consists of two or more sizes or weights. In most tapered strings, a larger diameter pipe or casing is placed at the top of the wellbore and the smaller size at the bottom. Note that since the pipe is put into the well bottom first, the smaller pipe is run into the hole first, followed by the larger diameter. Other than the different sizes, which are usually chosen to optimize well economics, there is nothing distinctive about the pipe sections. However, pipe-handling tools must be available for each pipe size, not just one size, as is the typical case. Synonyms: combination string

horizontal drilling

1. n. [Drilling] A subset of the more general term "directional drilling," used where the departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting it as deviation from vertical, which would then be 85 degrees. Because a horizontal well typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical well. See: directional drilling, directional well

drilling break

1. n. [Drilling] 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 pore pressure 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 circulate bottoms-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." See: blowout preventer, formation fluid, pore pressure, rate of penetration

show

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

casing grade

1. n. [Drilling] A system of identifying and categorizing the strength of casing materials. Since most oilfield casing is of approximately the same chemistry (typically steel) and differs only in the heat treatment applied, the grading system provides for standardized strengths of casing to be manufactured and used in wellbores. The first part of the nomenclature, a letter, refers to the tensile strength. The second part of the designation, a number, refers to the minimum yield strength of the metal (after heat treatment) at 1,000 psi [6895 KPa]. For example, the casing grade J-55 has minimum yield strength of 55,000 psi [379,211 KPa]. The casing grade P-110 designates a higher strength pipe with minimum yield strength of 110,000 psi [758,422 KPa]. The appropriate casing grade for any application typically is based on pressure and corrosion requirements. Since the well designer is concerned about the pipe yielding under various loading conditions, the casing grade is the number that is used in most calculations. High-strength casing materials are more expensive, so a casing string may incorporate two or more casing grades to optimize costs while maintaining adequate mechanical performance over the length of the string. It is also important to note that, in general, the higher the yield strength, the more susceptible the casing is to sulfide stress cracking (H2S-induced cracking). Therefore, if H2S is anticipated, the well designer may not be able to use tubulars with strength as high as he or she would like. See: casing string, float shoe, hydrogen sulfide

guide shoe

1. n. [Drilling] A tapered, often bullet-nosed piece of equipment often found on the bottom of a casing string. The device guides the casing toward the center of the hole and minimizes problems associated with hitting rock ledges or washouts in the wellbore as the casing is lowered into the well. The outer portions of the guide shoe are made from steel, generally matching the casing in size and threads, if not steel grade. The inside (including the taper) is generally made of cement or thermoplastic, since this material must be drilled out if the well is to be deepened beyond the casing point. It differs from a float shoe in that it lacks a check valve. Synonyms: shoe See: casing point, casing string, check valve, float shoe, washout

slip joint

1. n. [Drilling] A telescoping joint at the surface in floating offshore operations that permits vessel heave (vertical motion) while maintaining a riser pipe to the seafloor. As the vessel heaves, the slip joint telescopes in or out by the same amount so that the riser below the slip joint is relatively unaffected by vessel motion. Synonyms: travel joint See: drilling riser

drift

1. n. [Drilling] A term to describe the inclination from vertical of a wellbore. See: deviation survey, inclination

carbide lag test

1. n. [Drilling] A test performed by the mud logger or wellsite geologist, used to calculate sample lag. The lag period can be measured as a function of time or pump strokes. Acetylene is commonly used as a tracer gas for this purpose. This gas is generated by calcium carbide, a man-made product that reacts with water. Usually, a small paper packet containing calcium carbide is inserted into the drillstring when the kelly is unscrewed from the pipe to make a connection, and the time is noted, along with the pump-stroke count on the mud pump. Once the connection is made and drilling resumes, the packet is pumped downhole with the drilling fluid. Along the way, the drilling fluid breaks down the paper and reacts with the calcium carbide. The resulting acetylene gas circulates with the drilling fluid until it reaches the surface, where it is detected at the gas trap, causing a rapid increase or spike in gas readings. The time and pump-stroke count are again noted, and the cuttings sample lag interval is calculated. See: cycle time, lag gas, lag time

leakoff test

1. n. [Drilling] A test to determine the strength or fracture pressure of the open formation, usually conducted immediately after drilling below a new casing shoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure that the formation experiences. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a space by fracturing the rock. The results of the leakoff test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leakoff test result. Synonyms: PIT, pressure integrity test Alternate Form: LOT See: casing shoe, formation fracture pressure, fracture gradient, leakoff, mud weight

blind ram

1. n. [Drilling] A thick, heavy steel component of a conventional ram blowout preventer. In a normal pipe ram, the two blocks of steel that meet in the center of the wellbore to seal the well have a hole (one-half of the hole on each piece) through which the pipe fits. The blind ram has no space for pipe and is instead blanked off to be able to close over a well that does not contain a drillstring. It may be loosely thought of as the sliding gate on a gate valve. See: blowout, BOP stack, shear ram

roller cone bit

1. n. [Drilling] A tool designed to crush rock efficiently while incurring a minimal amount of wear on the cutting surfaces. Invented by Howard Hughes, the roller-cone bit has conical cutters or cones that have spiked teeth around them. As the drillstring is rotated, the bit cones roll along the bottom of the hole in a circle. As they roll, new teeth come in contact with the bottom of the hole, crushing the rock immediately below and around the bit tooth. As the cone rolls, the tooth then lifts off the bottom of the hole and a high-velocity fluid jet strikes the crushed rock chips to remove them from the bottom of the hole and up the annulus. As this occurs, another tooth makes contact with the bottom of the hole and creates new rock chips. Thus, the process of chipping the rock and removing the small rock chips with the fluid jets is continuous. The teeth intermesh on the cones, which helps clean the cones and enables larger teeth to be used. There are two main types of roller-cone bits, steel milled-tooth bits and carbide insert bits. Alternate Form: roller cone bit

diamond bit

1. n. [Drilling] 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.

basket sub

1. n. [Drilling] A tool run into the wellbore to retrieve junk from the bottom of the hole. See: cable-tool drilling, junk basket, junk sub

junk basket

1. n. [Drilling] A tool run into the wellbore to retrieve junk from the bottom of the hole. Synonyms: junk sub Alternate Form: basket sub See: junk

heavyweight drillpipe

1. n. [Drilling] A type of drillpipe whose walls are thicker and collars are longer than conventional drillpipe. HWDP tends to be stronger and has higher tensile strength than conventional drillpipe, so it is placed near the top of a long drillstring for additional support. Alternate Form: HWDP See: collar, drillstring

HWDP

chain tongs

1. n. [Drilling] A type of pipe wrench used for hand-tightening various threaded connections around the rigsite. It consists of a handle, a set of gripping die teeth, a length of flat chain, and a hooking slot where the chain may be adjusted to fit the pipe. See: tongs

pipe ram

1. n. [Drilling] A type of sealing element in high-pressure split seal blowout preventers that is manufactured with a half-circle hole on the edge (to mate with another horizontally opposed pipe ram) sized to fit around drillpipe. Most pipe rams fit only one size or a small range of drillpipe sizes and do not close properly around drillpipe tool joints or drill collars. A relatively new style is the variable bore ram, which is designed and manufactured to properly seal on a wider range of pipe sizes. See: blind ram, blowout preventer

inside blowout preventer

1. n. [Drilling] A valve in the drillstring that may be used to prevent the well from flowing uncontrollably up the drillstring. See: blowout preventer

adjustable choke

1. n. [Drilling] A valve usually used in well control operations to reduce the pressure of a fluid from high pressure in the closed wellbore to atmospheric pressure. It may be adjusted (opened or closed) to closely control the pressure drop. Adjustable choke valves are constructed to resist wear while high-velocity, solids-laden fluids are flowing by the restricting or sealing elements. See: choke, choke line, choke manifold, well control

mist drilling

1. n. [Drilling] A variation of air drilling in which a small amount of water trickles into the wellbore from exposed formations and is carried out of the wellbore by the compressed air used for air drilling. The onset of mist drilling often signals the impending end of practical air drilling, at which point the water inflow becomes too great for the compressed air to remove from the wellbore, or the produced water (usually salty) becomes a disposal problem. See: air drilling, mist

safety joint

1. n. [Drilling] A weak spot in the drillstring. Such a weak spot sometimes is intentionally put into the drillstring so that if tension in the drillstring exceeds a predetermined amount, the safety joint will part and the rest of the drillstring will be salvageable. A safety joint is commonly included in fishing strings and drillstem testing equipment, where the fish may be successfully caught by the fishing assembly, but tension to free the fish may prove insurmountable. By having the safety joint in the hole, the fishing company representative knows where the fishing string will part and what will be needed to latch onto the top of this additional fish. See: drillstem test, fishing tool

dry hole

1. n. [Drilling] 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. See: crude oil, duster, hydrocarbon, natural gas

gauge hole

1. n. [Drilling] A wellbore that is essentially the same diameter as the bit that was used to drill it. It is common to find well-consolidated sandstones and carbonate rocks that remain gauge after being drilled. For clays, it is common for the hole to slowly enlarge with the passing of time, especially if water-base muds are being used. Bit gauges, rings of defined circumference, are slipped around drill bits to detect and measure wear, which reduces the circumference of the bit during drilling. See: drill bit, erosion, water-base drilling fluid

deviated hole

1. n. [Drilling] A wellbore that is not vertical. The term usually indicates a wellbore intentionally drilled away from vertical. See: casing centralizer, centralizer, crooked hole, hydrostatic head, inclination, jet, logging-while-drilling

directional well

1. n. [Drilling] 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. See: directional drilling, horizontal drilling, slant rig

tour

1. n. [Drilling] A work shift of a drilling crew. Drilling operations usually occur around the clock because of the cost to rent a rig. As a result, there are usually two separate crews working twelve-hour tours to keep the operation going. Some companies prefer three eight-hour tours: the daylight tour starts at daylight or 8 AM; the graveyard tour is the overnight shift or the shift that begins at midnight. (Pronounced "tower" in many areas.) See: daylight tour, drilling crew, evening tour, graveyard tour, morning tour

ERD

1. n. [Drilling] Abbreviation for extended-reach drilling. Mobil Oil Company first used this term in the early 1980s for drilling directional wells in which the drilled horizontal reach (HR) attained at total depth (TD) exceeded the true vertical depth (TVD) by a factor greater than or equal to two. Extended-reach drilling (ERD) is particularly challenging for directional drilling and requires specialized planning to execute well construction. Since the term was coined, the scope of extended-reach drilling has broadened and the definition, which is now more flexible, includes deep wells with horizontal distance-to-depth, or H:V, ratios less than two. The drilling industry's ERD database classifies wells, with increasing degree of well construction complexity, into low-, medium-, extended- and very extended-reach wells. Construction complexity depends on many factors, including water depth (for offshore wells), rig capability, geologic constraints and overall TVD. For example, a vertical well with TVD greater than 7,620 m [25,000 ft] is considered an extended-reach well. Also, depending on the conditions, drilling a well in deep water or through salt may be classified as ERD even if the well's horizontal extent is not more than twice its TVD. Alternate Form: extended-reach drilling See: directional drilling, directional well, horizontal drilling

LOT

1. n. [Drilling] Abbreviation for leakoff test, a test to determine the strength or fracture pressure of the open formation, usually conducted immediately after drilling below a new casing shoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure that the formation experiences. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a space by fracturing the rock. The results of the leakoff test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leakoff test result. Synonyms: pressure integrity test Alternate Form: leakoff test See: casing shoe, formation fracture pressure, fracture gradient, leakoff, mud weight

MPD

1. n. [Drilling] Abbreviation for managed pressure drilling. Alternate Form: managed pressure drilling

MSE

1. n. [Drilling] Abbreviation for mechanical specific energy. Alternate Form: mechanical specific energy

PDM

1. n. [Drilling] Abbreviation for positive displacement motor, a downhole motor used in the oil field to drive the drill bit or other downhole tools during directional drilling or performance drilling applications. As drilling fluid is pumped through the positive displacement motor, it converts the hydraulic power of the fluid into mechanical power to cause the bit to rotate. During directional drilling, this capability is used while drilling in sliding mode, when the drillstring is not rotated from the surface. Positive displacement motors can also be used for performance drilling, straight hole drilling, coring, underreaming, and milling operations. In straight hole drilling, the motor functions as a drilling performance tool to increase the rate of penetration and reduce casing wear by minimizing drillstring rotation. Alternate Form: positive displacement motor

RCD

1. n. [Drilling] Abbreviation for rotating control device, a pressure-control device used during drilling for the purpose of making a seal around the drillstring while the drillstring rotates. The RCD is intended to contain hydrocarbons or other wellbore fluids and prevent their release to the atmosphere.

shaker

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

1. n. [Drilling] Abbreviation for total depth. The depth of the bottom of the well. Usually, it is the depth where drilling has stopped. Alternate Form: total depth

wall sticking

1. n. [Drilling] Also known as differential sticking, a condition whereby the drillstring cannot be moved (rotated or reciprocated) along the axis of the wellbore. Differential sticking typically occurs when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking is, for most drilling organizations, the greatest drilling problem worldwide in terms of time and financial cost. It is important to note that the sticking force is a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area can be just as effective in sticking the pipe as can a high differential pressure applied over a small area. Synonyms: differential sticking See: low-colloid oil mud, mechanical sticking, overbalance, pill, reservoir pressure, saltwater flow, stuck pipe

mud return line

1. n. [Drilling] Also known as flowline, the large-diameter metal pipe that connects the bell nipple under the rotary table to the possum belly at the mud tanks. The flowline is simply an inclined, gravity-flow conduit to direct mud coming out the top of the wellbore to the mud surface-treating equipment. When drilling certain highly reactive clays, called "gumbo," the flowline may become plugged and require considerable effort by the rig crew to keep it open and flowing. In addition, the flowline is usually fitted with a crude paddle-type flow-measuring device commonly called a "flow show" that may give the driller the first indication that the well is flowing. Alternate Form: flowline See: bell nipple, circulation system, gumbo, rotary table

pressure integrity test

1. n. [Drilling] Also known as leakoff test, a test to determine the strength or fracture pressure of the open formation, usually conducted immediately after drilling below a new casing shoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure that the formation experiences. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a space by fracturing the rock. The results of the leakoff test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leakoff test result. Synonyms: leakoff test Alternate Form: PIT See: casing shoe, formation fracture pressure, fracture gradient, leakoff, mud weight

PIT

1. n. [Drilling] Also known as pressure integrity test or leakoff test, a test to determine the strength or fracture pressure of the open formation, usually conducted immediately after drilling below a new casing shoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure that the formation experiences. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a space by fracturing the rock. The results of the leakoff test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leakoff test result. Synonyms: leakoff test, pressure integrity test Alternate Form: LOT See: casing shoe, formation fracture pressure, fracture gradient, leakoff, mud weight

travel joint

1. n. [Drilling] Also known as slip joint, a telescoping joint at the surface in floating offshore operations that permits vessel heave (vertical motion) while maintaining a riser pipe to the seafloor. As the vessel heaves, the slip joint telescopes in or out by the same amount so that the riser below the slip joint is relatively unaffected by vessel motion. Synonyms: slip joint

formation damage

1. n. [Drilling] Alteration of the far-field or virgin characteristics of a producing formation, usually by exposure to drilling fluids. The water or solid particles in the drilling fluids, or both, tend to decrease the pore volume and effective permeability of the producible formation in the near-wellbore region. At least two mechanisms are at work. First, solid particles from the drilling fluid physically plug or bridge across flowpaths in the porous formation. Second, when water contacts certain clay minerals in the formation, the clay typically swells, increasing in volume and decreasing the pore volume. Third, chemical reactions between the drilling fluid and the formation rock and fluids can precipitate solids or semisolids that plug pore spaces. One approach to minimize formation damage is to use drill-in or completion fluids that are specially formulated to avoid damage to the formation when drilling pay zones, rather than ordinary drilling fluids. See: bridge, completion fluid, drill-in fluid, drilling fluid

wiper trip

1. n. [Drilling] An abbreviated recovery and replacement of the drillstring in the wellbore that usually includes the bit and bottomhole assembly passing by all of the openhole, or at least all of the openhole that is thought to be potentially troublesome. This trip varies from the short trip or the round trip only in its function and length. Wiper trips are commonly used when a particular zone is troublesome or if hole-cleaning efficiency is questionable.

short trip

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

1. n. [Drilling] An adapter that serves to connect the rotary table to the kelly. The kelly bushing has an inside diameter profile that matches that of the kelly, usually square or hexagonal. It is connected to the rotary table by four large steel pins that fit into mating holes in the rotary table. The rotary motion from the rotary table is transmitted to the bushing through the pins, and then to the kelly itself through the square or hexagonal flat surfaces between the kelly and the kelly bushing. The kelly then turns the entire drillstring because it is screwed into the top of the drillstring itself. Depth measurements are commonly referenced to the KB, such as 8327 ft KB, meaning 8327 feet below the kelly bushing. Synonyms: kelly bushing, rotary bushing

kelly bushing

managed pressure drilling

1. n. [Drilling] An adaptive drilling method used to precisely control the annular pressure throughout a wellbore. After determining the downhole pressure environment, drillers manage wellbore pressure constrained by the limits of formation properties. The annular pressure is kept slightly above the pore pressure to prevent the influx of formation fluids into the wellbore, but it is maintained well below the fracture initiation pressure. Rapid corrective actions can often be implemented in order to deal with observed pressure variations. The MPD process may utilize a variety of techniques including control of back pressure, adjusting mud density, modifying fluid rheology, adjusting the annular fluid level, controlling circulating friction and incorporating hole geometry in the well construction. The use of MPD to control the risks and costs of drilling wells that have narrow downhole pressure limits by actively managing the wellbore pressure profile has become a common practice. The dynamic control of annular pressures enables drilling wells that might not otherwise be practical. See: underbalanced, overbalance

casing string

1. n. [Drilling] An assembled length of steel pipe configured to suit a specific wellbore. The sections of pipe are connected and lowered into a wellbore, then cemented in place. The pipe joints are typically approximately 40 ft [12 m] in length, male threaded on each end and connected with short lengths of double-female threaded pipe called couplings. Long casing strings may require higher strength materials on the upper portion of the string to withstand the string load. Lower portions of the string may be assembled with casing of a greater wall thickness to withstand the extreme pressures likely at depth. Casing is run to protect or isolate formations adjacent to the wellbore. The following are the most common reasons for running casing in a well: protect fresh-water aquifers (surface casing) provide strength for installation of wellhead equipment, including BOPs provide pressure integrity so that wellhead equipment, including BOPs, may be closed seal off leaky or fractured formations into which drilling fluids are lost seal off low-strength formations so that higher strength (and generally higher pressure) formations may be penetrated safely seal off high-pressure zones so that lower pressure formations may be drilled with lower drilling fluid densities seal off troublesome formations, such as flowing salt comply with regulatory requirements (usually related to one of the factors listed above). See: bell nipple, blowout preventer, BOP, box, casing, casing shoe, conductor pipe, coupling, displacement, dogleg, float joint, intermediate casing string, joint, liner, mill, pin, reciprocate, surface casing

BGG

1. n. [Drilling] An average or baseline measure of gas entrained in circulating mud. This baseline trend pertains to gas that is liberated downhole while drilling through a uniform lithologic interval at a constant rate of penetration. The gas is typically obtained from a suction line above the gas trap located immediately upstream of the shale shaker screens, where the gas evolves out of the mud. Oil-based mud systems tend to produce higher background gas values than do water-based muds. Deviations from the background gas trend likely indicate changes in porosity or permeability, or changes in drilling conditions; any of which merits further investigation. A drift or gradual shift of the background gas trend toward higher values may indicate a slow gas influx into the mud column, which can eventually lead to a kick or blowout. When annotated on mud logs, background gas is usually abbreviated as BGG. Alternate Form: background gas

background gas

1. n. [Drilling] An average or baseline measure of gas entrained in circulating mud. This baseline trend pertains to gas that is liberated downhole while drilling through a uniform lithologic interval at a constant rate of penetration. The gas is typically obtained from a suction line above the gas trap located immediately upstream of the shale shaker screens, where the gas evolves out of the mud. Oil-based mud systems tend to produce higher background gas values than do water-based muds. Deviations from the background gas trend likely indicate changes in porosity, permeability, or drilling conditions, any of which merits further investigation. A drift or gradual shift of the background gas trend toward higher values may indicate a slow gas influx into the mud column, which can eventually lead to a kick or blowout. When annotated on mud logs, background gas is usually abbreviated as BGG. Alternate Form: BGG See: contamination gas, entrained gas, gas show

electrodynamic brake

1. n. [Drilling] An electric motor that acts as a brake. Braking is accomplished by reversing the electric fields on the motor, effectively turning it into a generator. The usage of the generated power, either in useful applications or dissipation as heat, restrains the motor-turned-generator and provides a braking action.

cable head

1. n. [Drilling] An electromechanical device used to connect an electrical toolstring to a logging cable, electrical wireline, or coiled tubing string equipped with an electrical conductor. It provides attachments to both the mechanical armor wires (which give logging cable its tensile strength) and the outer mechanical housing of a logging tool, usually by means of threads. This connection to the logging tool results in a good electrical path from the electrical conductors of the logging cable to the electrical contacts of the logging too, and shields this electrical path from contact with conductive fluids, such as certain drilling muds. The basic requirements of most cable heads include providing reliable electrical and mechanical connectivity between the running string and tool string. Another attribute of cable heads is that they serve as a "weak link," so that if a logging tool becomes irretrievably stuck in a well, the operator may intentionally pull in excess of the breaking strength of the logging cable head, causing the cable to pull out of the cable head in a controlled fashion.

bell nipple

1. n. [Drilling] An enlarged pipe at the top of a casing string that serves as a funnel to guide drilling tools into the top of a well. The bell nipple is usually fitted with a side outlet to permit drilling fluids to flow back to the surface mud treating equipment through another inclined pipe called a flowline. See: circulation system

washout

1. n. [Drilling] An enlarged region of a wellbore. A washout in an openhole section is larger than the original hole size or size of the drill bit. Washout enlargement can be caused by excessive bit jet velocity, soft or unconsolidated formations, in-situ rock stresses, mechanical damage by BHA components, chemical attack and swelling or weakening of shale as it contacts fresh water. Generally speaking, washouts become more severe with time. Appropriate mud types, mud additives and increased mud density can minimize washouts. See: drill bit, float shoe, guide shoe, jet velocity

offset well

1. n. [Drilling] An existing wellbore close to a proposed well that provides information for planning the proposed well. In planning development wells, there are usually numerous offsets, so a great deal is known about the subsurface geology and pressure regimes. In contrast, rank wildcats have no close offsets, and planning is based on interpretations of seismic data, distant offsets and prior experience. High-quality offset data are coveted by competent well planners to optimize well designs. When lacking offset data, the well planner must be more conservative in designing wells and include more contingencies. Synonyms: offset See: bit record, drilling procedure, wildcat

wildcat

1. n. [Drilling] An exploration well. The significance of this type of well to the drilling crew and well planners is that by definition, little if anything about the subsurface geology is known with certainty, especially the pressure regime. This higher degree of uncertainty necessitates that the drilling crews be appropriately skilled, experienced and aware of what various well parameters are telling them about the formations they drill. The crews must operate top-quality equipment, especially the blowout preventers, since a kick could occur at virtually any time. If a wildcat is especially far from another wellbore, it may be described as a "rank wildcat." See: blowout preventer, offset well, tight hole

directional driller

1. n. [Drilling] 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. Alternate Form: DD See: deviation, directional drilling, toolpusher

slimhole well

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

bicenter bit

1. n. [Drilling] An integral bit and eccentric reamer used to simultaneously drill and underream the hole. See: ream, underream

goose neck

1. n. [Drilling] An inverted "U" shaped section of rigid piping normally used as a conduit for high-pressure drilling fluid. In particular, the term is applied to a structure that connects the top of a vertical standpipe running up the side of a derrick or mast to a flexible kelly hose that in turn is connected to another gooseneck between the flexible line and the swivel. Alternate Form: gooseneck

gooseneck

mousehole

1. n. [Drilling] An opening in the rig floor near the rotary table, but between the rotary table and the vee-door, that enables rapid connections while drilling. The mousehole is usually fitted underneath with a length of casing, usually with a bottom. A joint of drillpipe that will be used next in the drilling operation is placed in the mousehole, box end up, by the rig crew at a convenient time (immediately after the previous connection is made). When the bit drills down and the kelly is near the rotary table, another piece of drillpipe must be added for drilling to continue. This next piece of pipe is standing in the mousehole when the kelly is screwed onto it. Then the kelly and the joint of pipe in the mousehole are raised to remove the pipe from the mousehole, the mousehole pipe screwed onto the rest of the drillstring, and the drillstring lowered, rotated, and pumped through to continue drilling. Another piece of pipe is put in the mousehole to await the next connection. See: box, kelly, make a connection, rathole, rotary table, vee-door

blow out

1. n. [Drilling] An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of salt water, oil, gas, or a mixture of these. Blowouts occur in all types of exploration and production operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant openhole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) downhole and intervention efforts will be averted. Alternate Form: blowout

combination string

1. n. [Drilling] Another term for a tapered string: a string of drillpipe or casing that consists of two or more sizes or weights. In most tapered strings, a larger diameter pipe or casing is placed at the top of the wellbore and the smaller size at the bottom. Note that since the pipe is put into the well bottom first, the smaller pipe is run into the hole first, followed by the larger diameter. Other than the different sizes, which are usually chosen to optimize well economics, there is nothing distinctive about the pipe sections. However, pipe-handling tools must be available for each pipe size, not just one size, as is the typical case. Synonyms: tapered string

wiper plug

1. n. [Drilling] Another term for cementing plug, a rubber plug used to separate the cement slurry from other fluids, reducing contamination and maintaining predictable slurry performance. Two types of cementing plug are typically used on a cementing operation. The bottom plug is launched ahead of the cement slurry to minimize contamination by fluids inside the casing prior to cementing. A diaphragm in the plug body ruptures to allow the cement slurry to pass through after the plug reaches the landing collar. The top plug has a solid body that provides positive indication of contact with the landing collar and bottom plug through an increase in pump pressure. Synonyms: cementing plug

reeled tubing

1. n. [Drilling] Another term for coiled tubing, a long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft to 15,000 ft [610 to 4,570 m] or greater length. Synonyms: coiled tubing, CT See: coiled tubing drilling, endless tubing, packer

endless tubing

1. n. [Drilling] Another term for coiled tubing, a long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft to 15,000 ft [610 to 4,570 m] or greater length. Synonyms: coiled tubing, CT, reeled tubing See: coiled tubing drilling, packer

1. n. [Drilling] Another term for coiled tubing, a long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft to 15,000 ft [610 to 4,570 m] or greater length. Synonyms: coiled tubing, endless tubing, reeled tubing See: coiled tubing drilling, packer

shoe joint

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

shoe track

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

rotary bushing

1. n. [Drilling] Another term for kelly bushing, an adapter that serves to connect the rotary table to the kelly. The kelly bushing has an inside diameter profile that matches that of the kelly, usually square or hexagonal. It is connected to the rotary table by four large steel pins that fit into mating holes in the rotary table. The rotary motion from the rotary table is transmitted to the bushing through the pins, and then to the kelly itself through the square or hexagonal flat surfaces between the kelly and the kelly bushing. The kelly then turns the entire drillstring because it is screwed into the top of the drillstring itself. Depth measurements are commonly referenced to the KB, such as 8327 ft KB, meaning 8327 feet below the kelly bushing. Synonyms: KB, kelly bushing See: kelly, rotary table

reversing out

1. n. [Drilling] Another term for reverse circulation, the intentional pumping of wellbore fluids down the annulus and back up through the drillpipe. This is the opposite of the normal direction of fluid circulation in a wellbore. Since the inside volume of the drillpipe is considerably less than the volume of the annulus outside of the drillpipe, reverse circulation can bring bottomhole fluids to the surface faster than normal circulation for a given flow rate. Two potential hazards of reverse circulation include lifting cuttings and other junk into the drillstring and the rapid flow of reservoir fluids to the surface in a kick situation. Synonyms: back wash, reverse circulation See: cuttings, displacement, junk

backwash

1. n. [Drilling] Another term for reverse circulation, the intentional pumping of wellbore fluids down the annulus and back up through the drillpipe. This is the opposite of the normal direction of fluid circulation in a wellbore. Since the inside volume of the drillpipe is considerably less than the volume of the annulus outside of the drillpipe, reverse circulation can bring bottomhole fluids to the surface faster than normal circulation for a given flow rate. Two potential hazards of reverse circulation include lifting cuttings and other junk into the drillstring and the rapid flow of reservoir fluids to the surface in a kick situation. Synonyms: reverse circulation, reversing out See: cuttings, displacement, junk

settling tank

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

surface pipe

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

crooked hole

1. n. [Drilling] Antiquated term for a deviated wellbore, usually used to describe a well deviated accidentally during the drilling process. See: deviated hole, directional drilling

lag gas

1. n. [Drilling] Any gas deliberately introduced into the mud system to help a mudlogger or wellsite geologist track the amount of time or the number of mud pump strokes it takes to circulate mud from the kelly downhole through the drillstring to the bit, and back uphole to the gas trap at the shale shaker. This interval is used to calculate the lag period. See: carbide lag test, lag time

spacer fluid

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

pill

1. n. [Drilling] Any relatively small quantity (less than 200 bbl) of a special blend of drilling fluid to accomplish a specific task that the regular drilling fluid cannot perform. Examples include high-viscosity pills to help lift cuttings out of a vertical wellbore, freshwater pills to dissolve encroaching salt formations, pipe-freeing pills to destroy filter cake and relieve differential sticking forces and lost circulation material pills to plug a thief zone. See: cuttings, differential sticking, drilling fluid, lost-circulation material, thief zone

sub

1. n. [Drilling] Any small component of the drillstring, such as a short drill collar or a thread crossover. See: bit breaker, drill collar, junk basket

connection

1. n. [Drilling] Any threaded or nonthreaded union or joint that connects two tubular components. See: back off, break circulation, break out, dope, joint, pipe dope

roustabout

1. n. [Drilling] Any unskilled manual laborer on the rigsite. A roustabout may be part of the drilling contractor's employee workforce, or may be on location temporarily for special operations. Roustabouts are commonly hired to ensure that the skilled personnel that run an expensive drilling rig are not distracted by peripheral tasks, ranging from cleaning up location to cleaning threads to digging trenches to scraping and painting rig components. Although roustabouts typically work long hard days, this type of work can lead to more steady employment on a rig crew. See: drilling contractor, drilling crew

junk

1. n. [Drilling] Anything in the wellbore that is not supposed to be there. The term is usually reserved for small pieces of steel such as hand tools, small parts, bit nozzles, pieces of bits or other downhole tools, and remnants of milling operations. See: bridge, fish, junk basket, junk basket, mechanical sticking, mill, rathole, reverse circulation, sidetrack

fish

1. n. [Drilling] Anything left in a wellbore. It does not matter whether the fish consists of junk metal, a hand tool, a length of drillpipe or drill collars, or an expensive MWD and directional drilling package. Once the component is lost, it is properly referred to as simply "the fish." Typically, anything put into the hole is accurately measured and sketched, so that appropriate fishing tools can be selected if the item must be fished out of the hole. See: back off, drill collar, fishing tool, sidetrack, washover pipe

borehole orientation

1. n. [Drilling] Borehole direction. Borehole orientation may be described in terms of inclination and azimuth. Inclination refers to the vertical angle measured from the down direction—the down, horizontal, and up directions have inclinations of 0°, 90°, and 180°, respectively. Azimuth refers to the horizontal angle measured clockwise from true north—the north, east, south, and west directions have azimuths of 0°, 90°, 180° and 270°, respectively. Synonyms: wellbore orientation

neat cement

1. n. [Drilling] Cement that has no additives to modify its setting time or rheological properties. See: cement

zip collars

1. n. [Drilling] Drill collars (usually straight drill collars) that have been machined with a reduced diameter at the box (up) end so that they may be more easily handled with open-and-close elevators. The elevators close around the reduced-diameter section, latch securely, and a shoulder on the elevators prevents the larger diameter end of the collar from passing through the elevators, so the collars can be lifted. If zip grooves are not used on the collars, special lifting subs must be threaded into each stand of collars for lifting, which is time-consuming and less efficient than zip grooves. The primary drawback to zip grooves is that they may reduce the life of the collar by putting an effective limit on how many times the collar threads may be recut. See: drill collar, elevator, lifting sub

trip gas

1. n. [Drilling] Gas entrained in the drilling fluid during a pipe trip, which typically results in a significant increase in gas that is circulated to surface. This increase arises from a combination of two factors: lack of circulation when the mud pumps are turned off, and swabbing effects caused by pulling the drillstring to surface. These effects may be seen following a short trip into casing or a full trip to surface. Alternate Form: TG See: connection gas, short trip, tripping pipe

contamination gas

1. n. [Drilling] Gas that is introduced into the drilling mud from a source other than the formation. Contamination gas normally evolves as a by-product of oil-base mud systems and those using volatile additives such as diesel fuel or other lubricants. See: oil-base mud

gas show

1. n. [Drilling] Gas that rises to the surface, usually detected because it reduces the density of the drilling mud. Gas detectors, which the mud logger monitors, measure combustible gases (methane, ethane, butane and others). The mud logger reports total gas, individual gas components, or both, on the mud log. In extreme cases, gas visibly bubbles out of the mud as it returns to the surface. Because the mud does not circulate to the surface for a considerable time, sometimes lagging several hours after a formation is drilled, a gas show may be representative of what happened in the wellbore hours (or many feet) prior to the current total depth of the well. See: drilling fluid, total depth

washover pipe

1. n. [Drilling] In fishing operations, a large-diameter pipe fitted with an internal grappling device and tungsten carbide cutting surfaces on the bottom. The washover pipe can be lowered over a fish in the wellbore and to latch onto and retrieve the fish. Since the washover pipe is relatively thin-walled and large in diameter, and may be prone to sticking itself, the washover operation is usually reserved as a measure of last resort before abandoning the fish altogether. See: fish, fishing tool

hopper

1. n. [Drilling] In general, a funnel-shaped device used to transfer products. The hopper is often at the bottom of any container for holding or using bulk products, especially drilling fluid additives and cementing material.

differential pressure

1. n. [Drilling] In general, a measurement of fluid force per unit area (measured in units such as pounds per square in.) subtracted from a higher measurement of fluid force per unit area. This comparison could be made between pressures outside and inside a pipe, a pressure vessel, before and after an obstruction in a flow path, or simply between two points along any fluid path, such as two points along the inside of a pipe or across a packer. See: packer

supply vessel

1. n. [Drilling] In offshore operations, any barge, boat or ship that brings materials and personnel to and from the rigsite.

reserve pit

1. n. [Drilling] In onshore operations, an earthen-bermed storage area for discarded drilling fluid. These small reservoirs are used for several reasons. First, when properly arranged, most of the solids in the mud settle out and a suction hose may be placed in the reserve pit to have additional fluid available to pump into the wellbore in an emergency. In addition, in arid areas, a considerable amount of evaporation occurs, thus minimizing mud disposal volumes. At the end of drilling operations, and perhaps at intermediate times during drilling, the fluids and solids in the reserve pit must be carefully discarded, usually by transfer to a properly certified landfill. If the mud is benign, the solids (mostly clay), and liquids (water), may be plowed and tilled back into the local soil. This technique of disposal and reclamation is known as land farming.

inside diameter

1. n. [Drilling] Inside or inner diameter. Casing, tubing and drillpipe are commonly described in terms of inside diameter and outside diameter (OD). Antonyms: outside diameter Alternate Form: ID See: borehole, dogleg

breakout tongs

1. n. [Drilling] Large-capacity self-locking wrenches used to grip drillstring components and apply torque. The breakout tongs are the active tongs during breakout operations. A similar set of tongs is tied off to a deadline anchor during breakout operations to provide backup to the connection, not unlike the way a plumber uses two pipe wrenches in an opposing manner to tighten or loosen water pipes, except that breakout tongs are much larger. See: break out, tongs

makeup tongs

1. n. [Drilling] Large-capacity, self-locking wrenches used to grip drillstring components and apply torque. As with opposing pipe wrenches for a plumber, the tongs must be used in opposing pairs. As a matter of efficiency, one set of tongs is essentially tied off with a cable or chain to the derrick, and the other is actively pulled with mechanical catheads. The breakout tongs are the active tongs during breakout (or loosening) operations. The makeup tongs are active during makeup (or tightening) operations. See: breakout tongs, cat line, cathead, chain tongs, derrick, makeup cathead, tool joint

tongs

casing

1. n. [Drilling] Large-diameter pipe lowered into an openhole and cemented in place. The well designer must design casing to withstand a variety of forces, such as collapse, burst, and tensile failure, as well as chemically aggressive brines. Most casing joints are fabricated with male threads on each end, and short-length casing couplings with female threads are used to join the individual joints of casing together, or joints of casing may be fabricated with male threads on one end and female threads on the other. Casing is run to protect freshwater formations, isolate a zone of lost returns, or isolate formations with significantly different pressure gradients. The operation during which the casing is put into the wellbore is commonly called "running pipe." Casing is usually manufactured from plain carbon steel that is heat-treated to varying strengths but may be specially fabricated of stainless steel, aluminum, titanium, fiberglass, and other materials. See: box, brine, cased hole, casing grade, cement bond log, concentric, day rate, displacement, float joint, float shoe, joint, pin, scratcher, turnkey

extended-reach drilling

1. n. [Drilling] Mobil Oil Company first used this term in the early 1980s for drilling directional wells in which the drilled horizontal reach (HR) attained at total depth (TD) exceeded the true vertical depth (TVD) by a factor greater than or equal to two. Extended-reach drilling (ERD) is particularly challenging for directional drilling and requires specialized planning to execute well construction. Since the term was coined, the scope of extended-reach drilling has broadened and the definition, which is now more flexible, includes deep wells with horizontal distance-to-depth, or H:V, ratios less than two. The drilling industry's ERD database classifies wells, with increasing degree of well construction complexity, into low-, medium-, extended- and very extended-reach wells. Construction complexity depends on many factors, including water depth (for offshore wells), rig capability, geologic constraints and overall TVD. For example, a vertical well with TVD greater than 7,620 m [25,000 ft] is considered an extended-reach well. Also, depending on the conditions, drilling a well in deep water or through salt may be classified as ERD even if the well's horizontal extent is not more than twice its TVD. Alternate Form: ERD, extended reach drilling See: directional drilling, directional well, horizontal drilling

extended reach drilling

1. n. [Drilling] Mobil Oil Company first used this term in the early 1980s for drilling directional wells in which the drilled horizontal reach (HR) attained at total depth (TD) exceeded the true vertical depth (TVD) by a factor greater than or equal to two. Extended-reach drilling (ERD) is particularly challenging for directional drilling and requires specialized planning to execute well construction. Since the term was coined, the scope of extended-reach drilling has broadened and the definition, which is now more flexible, includes deep wells with horizontal distance-to-depth, or H:V, ratios less than two. The drilling industry's ERD database classifies wells, with increasing degree of well construction complexity, into low-, medium-, extended- and very extended-reach wells. Construction complexity depends on many factors, including water depth (for offshore wells), rig capability, geologic constraints and overall TVD. For example, a vertical well with TVD greater than 7,620 m [25,000 ft] is considered an extended-reach well. Also, depending on the conditions, drilling a well in deep water or through salt may be classified as ERD even if the well's horizontal extent is not more than twice its TVD. Alternate Form: ERD, extended-reach drilling See: directional drilling, directional well, horizontal drilling

circulation

1. n. [Drilling] Noun form of circulate. See: circulate

softline

1. n. [Drilling] Oilfield slang term for rope not made of steel, such as nylon, cotton, or especially standard manila hemp rope. See: cathead

Texas deck

1. n. [Drilling] On an offshore jackup drilling rig, the deck below the rotary table and rig floor where workers can access the BOP stack. This platform surrounds the base of the BOP stack and is suspended from the cantilever (where the rig floor is located) by adjustable cables. It is accessed from the main deck of the jackup barge by a semipermanent stairwell. The Texas deck is used primarily for installing the wellhead and nippling the BOP stack up and down. See: BOP stack, jackup rig, rig floor, rotary table, wellhead

weight indicator

1. n. [Drilling] One of the instruments that the driller uses to monitor and improve the operating efficiencies of the drilling operation. The actual measurement of weight is made with a hydraulic gauge attached to the dead line of the drilling line. As tension increases in the drilling line, more hydraulic fluid is forced through the instrument, turning the hands of the indicator. The weight that is measured includes everything exerting tension on the wire rope, including the traveling blocks and cable itself. Hence, to have an accurate weight measurement of the drillstring, the driller must first make a zero offset adjustment to account for the traveling blocks and items other than the drillstring. Then the indicated weight will represent the drillstring (drillpipe and bottomhole assembly). However, the driller is only nominally interested in this weight for most operations. The weight of interest is the weight applied to the bit on the bottom of the hole. The driller could simply take the rotating and hanging off bottom weight, say 300,000 pounds [136,200 kg], and subtract from that the amount of rotating on bottom weight, say 250,000 pounds [113,500 kg], to get a bit weight of 50,000 pounds [22,700 kg]. However, most rigs are equipped with a weight indicator that has a second indicator dial that can be set to read zero ("zeroed") with the drillstring hanging free, and works backwards from the main indicator dial. After proper zeroing, any weight set on bottom (that takes weight away from the main dial), has the effect of adding weight to this secondary dial, so that the driller can read weight on bit directly from the dial. See: drill collar, traveling block

derrickman

1. n. [Drilling] One of the rig crew members who gets his name from the fact that he works on a platform attached to the derrick or mast, typically 85 ft [26 m] above the rig floor, during trips. On small land drilling crews, the derrickman is second in rank to the driller. Larger offshore crews may have an assistant driller between the derrickman and the driller. In a typical trip out of the hole (TOH), the derrickman wears a special safety harness that enables him to lean out from the work platform (called the monkeyboard) to reach the drillpipe in the center of the derrick or mast, throw a line around the pipe and pull it back into its storage location (the fingerboards) until it is time to run the pipe back into the well. In terms of skill, physical exertion and perceived danger, a derrickman has one of the most demanding jobs on the rig crew. Some modern drilling rigs have automated pipe-handling equipment such that the derrickman controls the machinery rather than physically handling the pipe. In an emergency, the derrickman can quickly reach the ground by an escape line often called the Geronimo line. See: derrick, driller, drilling crew, escape line, fingerboard, gas-cut mud, monkeyboard, racking back pipe, round trip

pipe rack

1. n. [Drilling] Onshore, two elevated truss-like structures having triangular cross sections. The pipe rack supports drillpipe, drill collars or casing above the ground. These structures are used in pairs located about 20 ft [6 m] apart and keep the pipe above ground level and closer to the level of the catwalk. Pipe stored horizontally on the pipe racks can have its threads cleaned and inspected and the rig crew may roll the pipe from one end of the pipe racks to the other with relative ease. The pipe racks are usually topped with a wooden board so as to not damage pipe, especially casing, as it is rolled back and forth along the racks. When large amounts of pipe are stored, wooden sills are placed between the layers of pipe to prevent damage. See: catwalk, measured depth

outside diameter

1. n. [Drilling] Outside or outer diameter. Casing and tubing are commonly described in terms of inside diameter (ID) and outside diameter. Antonyms: inside diameter Alternate Form: OD See: drill collar

1. n. [Drilling] Outside or outer diameter. Casing and tubing are commonly described in terms of inside diameter (ID) and outside diameter. Antonyms: inside diameter Alternate Form: outside diameter

twist-off

1. n. [Drilling] Parting or breaking of the drillstring downhole due to fatigue or excessive torque. Alternate Form: twist off

drilling crew

1. n. [Drilling] 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. See: derrickman, driller, motorman, roughneck, roustabout, toolpusher, tour

dope

1. n. [Drilling] Pipe dope, a specially formulated blend of lubricating grease and fine metallic particles that prevents thread galling (a particular form of metal-to-metal damage) and seals the roots or void spaces of threads. The American Petroleum Institute (API) specifies properties of pipe dope, including its coefficient of friction. The rig crew applies copious amounts of pipe dope to the drillpipe tool joints every time a connection is made. Alternate Form: pipe dope See: drilling crew, tool joint

annuli

1. n. [Drilling] Plural form of annulus.

recycled gas

1. n. [Drilling] Residual gas that remains entrained in the drilling fluid despite being circulated to surface. At the surface, it remains in the mudstream, which is suctioned from the mud pit and recirculated into the wellbore. See: degasser, entrained gas, gas-cut mud

p rate

1. n. [Drilling] Slang for penetration rate, or the speed that the bit is drilling into the formation. Alternate Form: p-rate

p-rate

1. n. [Drilling] Slang for penetration rate, or the speed that the bit is drilling into the formation. See: antiwhirl bit, drill bit

duster

1. n. [Drilling] Slang term for dry hole. Alternate Form: dry hole

cuttings

1. n. [Drilling] Small pieces of rock that break away due to the action of the bit teeth. Cuttings are screened out of the liquid mud system at the shale shakers and are monitored for composition, size, shape, color, texture, hydrocarbon content and other properties by the mud engineer, the mud logger and other on-site personnel. The mud logger usually captures samples of cuttings for subsequent analysis and archiving. See: bridge, cable-tool drilling, circulate out, eccentricity, mechanical sticking, mud engineer, overbalance, pack off, pill, reciprocate, reverse circulation, rotary drilling, settling pit, shale shaker

structural steering

1. n. [Drilling] Structural steering is a method of directing the wellbore trajectory of horizontal wells using 3D visualization. It is the process of combining structural analysis and modeling capabilities with borehole images to optimize well placement, often in real-time. Structural steering integrates deep-reading LWD resistivity tools and high-resolution imaging devices to create structural models of often complex geologic conditions encountered by the drill bit. This technique helps operators understand the formations already drilled and allows them proactively to correct wellbore trajectories for anticipated changes. See: deviated drilling, directional drilling, directional well, geosteering, horizontal drilling, logging-while-drilling, LWD

tripping pipe

1. n. [Drilling] The act of pulling the drillstring out of the hole or replacing it in the hole. A pipe trip is usually done because the bit has dulled or has otherwise ceased to drill efficiently and must be replaced. Synonyms: pipe trip See: coiled tubing drilling, measurements-while-drilling, monkeyboard, round trip, stand, survey

pipe trip

1. n. [Drilling] The act of pulling the drillstring out of the hole or replacing it in the hole. A pipe trip is usually done because the bit has dulled or has otherwise ceased to drill efficiently and must be replaced. Synonyms: tripping pipe See: monkeyboard, round trip, short trip

trip

1. n. [Drilling] The act of pulling the drillstring out of the hole or replacing it in the hole. A pipe trip is usually done because the bit has dulled or has otherwise ceased to drill efficiently and must be replaced. Synonyms: tripping pipe See: monkeyboard, round trip, short trip

snubbing

1. n. [Drilling] The act of putting drillpipe into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well. Snubbing is necessary when a kick is taken, since well kill operations should always be conducted with the drillstring on bottom, and not somewhere up the wellbore. If only the annular BOP has been closed, the drillpipe may be slowly and carefully lowered into the wellbore, and the BOP itself will open slightly to permit the larger diameter tool joints to pass through. If the well has been closed with the use of ram BOPs, the tool joints will not pass by the closed ram element. Hence, while keeping the well closed with either another ram BOP or the annular BOP, the ram must be opened manually, then the pipe lowered until the tool joint is just below the ram, and then closing the ram again. This procedure is repeated whenever a tool joint must pass by a ram BOP. In snubbing operations, the pressure in the wellbore acting on the cross-sectional area of the tubular can exert sufficient force to overcome the weight of the drillstring, so the string must be pushed (or "snubbed") back into the wellbore. In ordinary stripping operations, the pipe falls into the wellbore under its own weight, and no additional downward force or pushing is required. See: annular BOP, blowout preventer, kick, kill, ram blowout preventer, stripping, tool joint

stripping

1. n. [Drilling] The act of putting drillpipe into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well. This is necessary when a kick is taken, since well kill operations should always be conducted with the drillstring on bottom, and not somewhere up the wellbore. If only the annular BOP has been closed, the drillpipe may be slowly and carefully lowered into the wellbore, and the BOP itself will open slightly to permit the larger diameter tool joints to pass through. If the well has been closed with the use of ram BOPs, the tool joints will not pass by the closed ram element. Hence, while keeping the well closed with either another ram or the annular BOP, the ram must be opened manually, then the pipe lowered until the tool joint is just below the ram, and then the ram closed again. This procedure is repeated whenever a tool joint must pass by a ram BOP. Rig crews are usually required to practice ram-to-ram and ram-to-annular stripping operations as part of their well control certifications. In stripping operations, the combination of the pressure in the well and the weight of the drillstring is such that the pipe falls in the hole under its own weight, whereas in snubbing operations the pipe must be pushed into the hole. See: annular BOP, ram blowout preventer, snubbing, tool joint

casinghead

1. n. [Drilling] The adapter between the first casing string and either the BOP stack (during drilling) or the wellhead (after completion). This adapter may be threaded or welded onto the casing and may have a flanged or clamped connection to match the BOP stack or wellhead. See: casing spool, cellar, flange, surface casing

casing head

1. n. [Drilling] The adapter between the first casing string and either the BOP stack (during drilling) or the wellhead (after completion). This adapter may be threaded or welded onto the casing, and may have a flanged or clamped connection to match the BOP stack or wellhead. Synonyms: casinghead See: casing spool, cellar, flange, surface casing

underbalance

1. n. [Drilling] The amount of pressure (or force per unit area) exerted on a formation exposed in a wellbore below the internal fluid pressure of that formation. If sufficient porosity and permeability exist, formation fluids enter the wellbore. The drilling rate typically increases as an underbalanced condition is approached. Antonyms: overbalance See: coiled tubing drilling, hydrostatic pressure, kill

overbalance

1. n. [Drilling] The amount of pressure (or force per unit area) in the wellbore that exceeds the pressure of fluids in the formation. This excess pressure is needed to prevent reservoir fluids (oil, gas, water) from entering the wellbore. However, excessive overbalance can dramatically slow the drilling process by effectively strengthening the near-wellbore rock and limiting removal of drilled cuttings under the bit. In addition, high overbalance pressures coupled with poor mud properties can cause differential sticking problems. Because reservoir pressures vary from one formation to another, while the mud is relatively constant density, overbalance varies from one zone to another. Antonyms: underbalance See: cuttings, differential sticking

toolface

1. n. [Drilling] The angle measured in a plane perpendicular to the drillstring axis that is between a reference direction on the drillstring and a fixed reference. For near-vertical wells, north is the fixed reference and the angle is the magnetic toolface. For more-deviated wells, the top of the borehole is the fixed reference and the angle is the gravity toolface, or high side toolface. See: borehole orientation, gravity toolface, high-side toolface, magnetic toolface, wellbore orientation

shoe

1. n. [Drilling] The bottom of the casing string, including the cement around it, or the equipment run at the bottom of the casing string. Synonyms: casing shoe See: bullhead, float shoe, plug and abandon

casing shoe

1. n. [Drilling] The bottom of the casing string, including the cement around it, or the equipment run at the bottom of the casing string. Synonyms: shoe See: bullhead, float shoe, plug and abandon

conductor pipe

1. n. [Drilling] The casing string that is usually put into the well first, particularly on land wells, to prevent the sides of the hole from caving into the wellbore. This casing, sometimes called drive pipe, is generally a short length and is sometimes driven into the ground. Conductor pipe is run because the shallow section of most wells onshore is drilled in unconsolidated sediment or soil rather than consolidated strata typically encountered deeper. Offshore, the drive pipe or structural casing may be installed prior to the conductor for similar reasons.

cementing engineer

1. n. [Drilling] The colloquial term for the crew member in charge of a specialized cementing crew and trucks. Synonyms: cementer

cementer

1. n. [Drilling] The colloquial term for the crew member in charge of a specialized cementing crew and trucks. Synonyms: cementing engineer

drillstring

1. n. [Drilling] 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. See: bottomhole assembly, drill bit, drillpipe, heavyweight drillpipe

drillstem

1. n. [Drilling] 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. Synonyms: drillstring See: bit, bottomhole assembly, drillpipe, heavyweight drillpipe

drilling contractor

1. n. [Drilling] 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. See: contract depth, day rate, roustabout

operator

1. n. [Drilling] The company that serves as the overall manager and decision-maker of a drilling project. Generally, but not always, the operator will have the largest financial stake in the project. At the successful completion of logging the target zones, the decision to complete or plug and abandon generally has partner input and potential override clauses. As far as the drilling contractor and service companies are concerned, the designated operator is paying for the entire operation, and the operator is responsible for recouping some of that expense from the partners. See: drilling contractor, plug and abandon

round trip

1. n. [Drilling] The complete operation of removing the drillstring from the wellbore and running it back in the hole. This operation is typically undertaken when the bit becomes dull or broken, and no longer drills the rock efficiently. After some preliminary preparations for the trip, the rig crew removes the drillstring 90 ft [27 m] at a time, by unscrewing every third drillpipe or drill collar connection. When the three joints are unscrewed from the rest of the drillstring, they are carefully stored upright in the derrick by the fingerboards at the top and careful placement on wooden planks on the rig floor. After the drillstring has been removed from the wellbore, the dull bit is unscrewed with the use of a bit breaker and quickly examined to determine why the bit dulled or failed. Depending on the failure mechanism, the crew might choose a different type of bit for the next section. If the bearings on the prior bit failed, but the cutting structures are still sharp and intact, the crew may opt for a faster drilling (less durable) cutting structure. Conversely, if the bit teeth are worn out but the bearings are still sealed and functioning, the crew should choose a bit with more durable (and less aggressive) cutting structures. Once the bit is chosen, it is screwed onto the bottom of the drill collars with the help of the bit breaker, the drill collars are run into the hole (RIH), and the drillpipe is run in the hole. Once on bottom, drilling commences again. The duration of this operation depends on the total depth of the well and the skill of the rig crew. A general estimate for a competent crew is that the round trip requires one hour per thousand feet of hole, plus an hour or two for handling collars and bits. At that rate, a round trip in a ten thousand-foot well might take twelve hours. A round trip for a 30,000-ft [9230 m] well might take 32 or more hours, especially if intermediate hole-cleaning operations must be undertaken. Alternate Form: trip See: bit breaker, break circulation, derrick, derrickman, fingerboard, run in hole, tripping pipe, wiper trip

circulation system

1. n. [Drilling] The complete, circuitous path that the drilling fluid travels. Starting at the main rig pumps, major components include surface piping, the standpipe, the kelly hose (rotary), the kelly, the drillpipe, drill collars, bit nozzles, the various annular geometries of the openhole and casing strings, the bell nipple, the flowline, the mud-cleaning equipment, the mud tanks, the centrifugal precharge pumps, and, finally, the positive displacement main rig pumps. See: bit nozzle, casing string, centrifugal pump, drill collar, kelly, positive displacement pump, surface pipe

day rate

1. n. [Drilling] 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. See: casing, cementing, contract depth, drilling contractor, wellhead

contract depth

1. n. [Drilling] The depth in a drilling well at which the drilling contractor receives a lump-sum payment for reaching a particular milestone. The contract depth is specified in a legal agreement between the operator, who pays for the well, and the drilling contractor, who owns and operates the drilling rig. Contract depth may be the final or total depth (TD) of the well, an intermediate point in the well or another milestone, such as running well-logging tools to the bottom of the hole. In the case of an intermediate contract depth, the work to deepen the well would likely be done on a day rate basis, or a "time and materials" contract. See: drilling contractor, turnkey

total depth (TD)

1. n. [Drilling] The depth of the bottom of the well. Usually, it is the depth where drilling has stopped. Alternate Form: TD

inclination

1. n. [Drilling] The deviation from vertical, irrespective of compass direction, expressed in degrees. Inclination is measured initially with a pendulum mechanism, and confirmed with MWD accelerometers or gyroscopes. For most vertical wellbores, inclination is the only measurement of the path of the wellbore. For intentionally deviated wellbores, or wells close to legal boundaries, directional information is usually also measured. See: accelerometer, azimuth, deviated hole, survey

wellbore

1. n. [Drilling] The drilled hole or borehole, including the openhole or uncased portion of the well. Borehole may refer to the inside diameter of the wellbore wall, the rock face that bounds the drilled hole. Synonyms: borehole See: inside diameter, openhole

drilling procedure

1. n. [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, pore pressure 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. See: offset well, pore pressure, well control

drilling program

tool joint

1. n. [Drilling] The enlarged and threaded ends of joints of drillpipe. These components are fabricated separately from the pipe body and welded onto the pipe at a manufacturing facility. The tool joints provide high-strength, high-pressure threaded connections that are sufficiently robust to survive the rigors of drilling and numerous cycles of tightening and loosening at threads. Tool joints are usually made of steel that has been heat treated to a higher strength than the steel of the tube body. The large-diameter section of the tool joints provides a low stress area where pipe tongs are used to grip the pipe. Hence, relatively small cuts caused by the pipe tongs do not significantly impair the strength or life of the joint of drillpipe. See: back off, break out, dope, drillpipe, kelly spinner, keyseat, pipe dope, snubbing, spinning chain, stripping, tight hole, tongs

measurements-while-drilling

1. n. [Drilling] The evaluation of physical properties, usually including pressure, temperature and wellbore trajectory in three-dimensional space, while extending a wellbore. MWD is now standard practice in offshore directional wells, where the tool cost is offset by rig time and wellbore stability considerations if other tools are used. The measurements are made downhole, stored in solid-state memory for some time and later transmitted to the surface. Data transmission methods vary from company to company, but usually involve digitally encoding data and transmitting to the surface as pressure pulses in the mud system. These pressures may be positive, negative or continuous sine waves. Some MWD tools have the ability to store the measurements for later retrieval with wireline or when the tool is tripped out of the hole if the data transmission link fails. MWD tools that measure formation parameters (resistivity, porosity, sonic velocity, gamma ray) are referred to as logging-while-drilling (LWD) tools. LWD tools use similar data storage and transmission systems, with some having more solid-state memory to provide higher resolution logs after the tool is tripped out than is possible with the relatively low bandwidth, mud-pulse data transmission system. Synonyms: mud pulse telemetry Alternate Form: MWD See: differential pressure, drill collar, logging-while-drilling, survey, tripping pipe

MWD

pressure hunt

1. n. [Drilling] The evaluation of various well parameters in an attempt to identify when the pore pressure in a drilling well is changing. A team consisting of geologists, engineers and most of the rigsite personnel usually conducts the hunt. The purpose of a pressure hunt is to detect the pore pressure transition (usually from lower to higher pressure) and safely set casing in the transition zone to maximize wellbore strength. A casing string set too shallow, while eliminating some problems associated with drilling fluid contacting the wellbore wall, may not add strength or aid in drilling deeper, perhaps abnormally pressured formations. On the other hand, if drilling is continued too deep into a transition zone, a kick may be taken that cannot be contained in the open wellbore, causing an underground blowout. The hunt team, therefore, seeks to get into the transition zone far enough to gain wellbore strength without taking a kick. See: blowout, casing, casing point, casing string, kick, pore pressure

jet velocity

1. n. [Drilling] The exit velocity of the drilling fluid after it accelerates through bit nozzles. See: bit nozzle, exit velocity

crown block

1. n. [Drilling] The fixed set of pulleys (called sheaves) located at the top of the derrick or mast, over which the drilling line is threaded. The companion blocks to these pulleys are the traveling blocks. By using two sets of blocks in this fashion, great mechanical advantage is gained, enabling the use of relatively small drilling line (3/4 to 1 1/2 in. diameter steel cable) to hoist loads many times heavier than the cable could support as a single strand. See: block, drawworks, mast, sheave, slip and cut, traveling block

crossflow

1. n. [Drilling] The flow of fluid across the bottom of the bit after it exits the bit nozzles, strikes the bottom or sides of the hole and turns upwards to the annulus. Modern, well-designed bits maximize crossflow using an asymmetric nozzle arrangement. See: bit nozzle

displacement fluid

1. n. [Drilling] The fluid, usually drilling mud, used to force a cement slurry out of the casing string and into the annulus. See: casing string, displacement, drilling mud

shut-in bottomhole pressure

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

SIBHP

SIBP

bridge

1. n. [Drilling] The gangplank or stairway connecting a jackup rig to a fixed platform.

completion

1. n. [Drilling] The hardware used to optimize the production of hydrocarbons from the well. This may range from nothing but a packer on tubing above an openhole completion ("barefoot" completion), to a system of mechanical filtering elements outside of perforated pipe, to a fully automated measurement and control system that optimizes reservoir economics without human intervention (an "intelligent" completion). See: brine, completion fluid, hydrocarbon, rathole, turnkey

hook

1. n. [Drilling] The high-capacity J-shaped equipment used to hang various other equipment, particularly the swivel and kelly, the elevator bails or topdrive units. The hook is attached to the bottom of the traveling block and provides a way to pick up heavy loads with the traveling block. The hook is either locked (the normal condition) or free to rotate, so that it may be mated or decoupled with items positioned around the rig floor, not limited to a single direction. See: elevator, kelly, swivel, top drive, traveling block

geosteering

1. n. [Drilling] The intentional directional control of a well based on the results of downhole geological logging measurements rather than three-dimensional targets in space, usually to keep a directional wellbore within a pay zone. In mature areas, geosteering may be used to keep a wellbore in a particular section of a reservoir to minimize gas or water breakthrough and maximize economic production from the well. See: directional drilling, geosteer

reverse circulation

1. n. [Drilling] The intentional pumping of wellbore fluids down the annulus and back up through the drillpipe. This is the opposite of the normal direction of fluid circulation in a wellbore. Since the inside volume of the drillpipe is considerably less than the volume of the annulus outside of the drillpipe, reverse circulation can bring bottomhole fluids to the surface faster than normal circulation for a given flow rate. Two potential hazards of reverse circulation include lifting cuttings and other junk into the drillstring and the rapid flow of reservoir fluids to the surface in a kick situation. Synonyms: back wash, reversing out See: cuttings, displacement, junk

flowline

1. n. [Drilling] The large-diameter metal pipe that connects the bell nipple under the rotary table to the possum belly at the mud tanks. The flowline is simply an inclined, gravity-flow conduit to direct mud coming out the top of the wellbore to the mud surface-treating equipment. When drilling certain highly reactive clays, called "gumbo," the flowline may become plugged and require considerable effort by the rig crew to keep it open and flowing. In addition, the flowline is usually fitted with a crude paddle-type flow-measuring device commonly called a "flow show" that may give the driller the first indication that the well is flowing. Alternate Form: mud return line See: bell nipple, circulation system, gumbo, rotary table

flow line

measured depth

1. n. [Drilling] The length of the wellbore, as if determined by a measuring stick. This measurement differs from the true vertical depth of the well in all but vertical wells. Since the wellbore cannot be physically measured from end to end, the lengths of individual joints of drillpipe, drill collars and other drillstring elements are measured with a steel tape measure and added together. Importantly, the pipe is measured while in the derrick or laying on a pipe rack, in an untensioned, unstressed state. When the pipe is screwed together and put into the wellbore, it stretches under its own weight and that of the bottomhole assembly. Although this fact is well established, it is not taken into account when reporting the well depth. Hence, in virtually all cases, the actual wellbore is slightly deeper than the reported depth. Alternate Form: MD See: bottomhole assembly, hydrostatic head, pipe rack, true vertical depth (TVD)

mechanical sticking

1. n. [Drilling] The limiting or prevention of motion of the drillstring by anything other than differential pressure sticking. Mechanical sticking can be caused by junk in the hole, wellbore geometry anomalies, cement, keyseats or a buildup of cuttings in the annulus. See: cuttings, differential sticking, junk, keyseat

toolpusher

1. n. [Drilling] The location supervisor for the drilling contractor. The toolpusher is usually a senior, experienced individual who has worked his way up through the ranks of the drilling crew positions. His job is largely administrative, including ensuring that the rig has sufficient materials, spare parts and skilled personnel to continue efficient operations. The toolpusher also serves as a trusted advisor to many personnel on the rigsite, including the operator's representative, the company man. Synonyms: drilling foreman, pusher See: company man, driller

pusher

drilling foreman

1. n. [Drilling] The location supervisor for the drilling contractor. The toolpusher is usually a senior, experienced individual who has worked his way up through the ranks of the drilling crew positions. The toolpusher's job is largely administrative, including ensuring that the rig has sufficient materials, spare parts, and skilled personnel to continue efficient operations. The toolpusher also serves as a trusted advisor to many personnel on the rigsite, including the operator's representative. Synonyms: toolpusher See: company man, driller

casing point

1. n. [Drilling] The location, or depth, at which drilling an interval of a particular diameter hole ceases, so that casing of a given size can be run and cemented. Establishing correct casing points is important in the design of the drilling fluid program. The casing point may be a predetermined depth, or it may be selected onsite by a pressure hunt team, selected onsite according to geological observations, or dictated by problems in the openhole section. In many cases, weak or underpressure zones must be protected by casing to enable mud weight adjustments that control unstable formations or overpressure zones deeper in the wellbore. See: cementing

circulation loss

1. n. [Drilling] The loss of drilling fluid to a formation, usually caused when the hydrostatic head pressure of the column of drilling fluid exceeds the formation pressure. This loss of fluid may be loosely classified as seepage losses, partial losses, or catastrophic losses, each of which is handled differently depending on the risk to the rig and personnel and the economics of the drilling fluid and each possible solution. Alternate Form: lost circulation See: hydrostatic pressure

bottomhole assembly

1. n. [Drilling] The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices ("jars"), and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment, and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices. Alternate Form: BHA See: antiwhirl bit, crossover, directional drilling, dogleg, jar, logging-while-drilling, measured depth, stand, sub, threadform

BHA

1. n. [Drilling] The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices ("jars"), and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment, and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools, and other specialized devices. Alternate Form: bottomhole assembly

drawworks

1. n. [Drilling] The machine on the rig consisting of a large-diameter steel spool, brakes, a power source and assorted auxiliary devices. The primary function of the drawworks is to reel out and reel in the drilling line, a large diameter wire rope, in a controlled fashion. The drilling line is reeled over the crown block and traveling block to gain mechanical advantage in a "block and tackle" or "pulley" fashion. This reeling out and in of the drilling line causes the traveling block, and whatever may be hanging underneath it, to be lowered into or raised out of the wellbore. The reeling out of the drilling line is powered by gravity and reeling in by an electric motor or diesel engine. See: brake, breakout cathead, cathead, crown block, driller, makeup cathead, prime mover, slip and cut, spinning chain, traveling block

rig

1. n. [Drilling] The machine used to drill a wellbore. In onshore operations, the rig includes virtually everything except living quarters. Major components of the rig include the mud tanks, the mud pumps, the derrick or mast, the drawworks, the rotary table or topdrive, the drillstring, the power generation equipment and auxiliary equipment. Offshore, the rig includes the same components as onshore, but not those of the vessel or drilling platform itself. The rig is sometimes referred to as the drilling package, particularly offshore. Synonyms: drilling rig See: rig up

drilling rig

leakoff

1. n. [Drilling] The magnitude of pressure exerted on a formation that causes fluid to be forced into the formation. The fluid may be flowing into the pore spaces of the rock or into cracks opened and propagated into the formation by the fluid pressure. This term is normally associated with a test to determine the strength of the rock, commonly called a pressure integrity test (PIT) or a leakoff test (LOT). During the test, a real-time plot of injected fluid versus fluid pressure is plotted. The initial stable portion of this plot for most wellbores is a straight line, within the limits of the measurements. The leakoff is the point of permanent deflection from that straight portion. The well designer must then either adjust plans for the well to this leakoff pressure, or if the design is sufficiently conservative, proceed as planned. Alternate Form: leak off See: leakoff test, LOT, PIT

brake

1. n. [Drilling] The mechanism on the drawworks that permits the driller to control the speed and motion of the drilling line and the drillstring, or the brake handle that the driller operates to control the brake mechanism.

motorman

1. n. [Drilling] The member of the rig crew responsible for maintenance of the engines. While all members of the rig crew help with major repairs, the motorman does routine preventive maintenance and minor repairs. See: drilling crew

moon pool

1. n. [Drilling] The opening in the hull of a drillship or other offshore drilling vessel through which drilling equipment passes. See: drillship

graveyard tour

1. n. [Drilling] The overnight work shift of a drilling crew. Drilling operations usually occur around the clock because of the cost to rent a rig. As a result, there are usually two separate crews working twelve-hour tours to keep the operation going. Some companies prefer three eight-hour tours. The graveyard tour is the shift that begins at midnight. (Pronounced "tower" in many areas.) See: daylight tour, drilling crew, evening tour, morning tour, tour

jet nozzle

1. n. [Drilling] The part of the bit that includes a hole or opening for drilling fluid to exit. The hole is usually small (around 0.25 in. in diameter) and the pressure of the fluid inside the bit is usually high, leading to a high exit velocity through the nozzles that creates a high-velocity jet below the nozzles. This high-velocity jet of fluid cleans both the bit teeth and the bottom of the hole. The sizes of the nozzles are usually measured in 1/32-in. increments (although some are recorded in millimeters), are always reported in "thirty-seconds" of size (i.e., fractional denominators are not reduced), and usually range from 6/32 to 32/32. See: circulation system, crossflow, differential pressure, exit velocity, hydraulic horsepower, jet, jet velocity

bit nozzle

1. n. [Drilling] The part of the bit that includes a hole or opening for drilling fluid to exit. The hole is usually small (around 0.25-in diameter) and the pressure of the fluid inside the bit is usually high, leading to a high exit velocity through the nozzles that creates a high-velocity jet below the nozzles. This high-velocity jet of fluid cleans both the bit teeth and the bottom of the hole. The sizes of the nozzles are usually measured in 1/32-in increments (although some are recorded in millimeters), are always reported in "thirty-seconds" of size (i.e., fractional denominators are not reduced), and usually range from 6/32 to 32/32. Alternate Form: jet nozzle See: circulation system, crossflow, differential pressure, exit velocity, hydraulic horsepower, jet, jet velocity

stuck pipe

1. n. [Drilling] The portion of the drillstring that cannot be rotated or moved vertically. See: differential sticking, pack off, stuck, top drive

cased hole

1. n. [Drilling] The portion of the wellbore that has had metal casing placed and cemented to protect the openhole from fluids, pressures, wellbore stability problems, or a combination of these. Antonyms: openhole See: barefoot, cement, packer

bottomhole pressure

1. n. [Drilling] The pressure, usually measured in pounds per square inch (psi), at the bottom of the hole. This pressure may be calculated in a static, fluid-filled wellbore with the equation: BHP = MW * Depth * 0.052 where BHP is the bottomhole pressure in pounds per square inch MW is the mud weight in pounds per gallon depth is the true vertical depth in feet 0.052 is a conversion factor if these units of measure are used. For circulating wellbores, the BHP increases by the amount of fluid friction in the annulus. The BHP gradient should exceed the formation pressure gradient to avoid an influx of formation fluid into the wellbore. On the other hand, if BHP (including the added fluid friction pressure of a flowing fluid) is too high, a weak formation may fracture and cause a loss of wellbore fluids. The loss of fluid to one formation may be followed by the influx of fluid from another formation. Alternate Form: BHP See: formation pressure

BHP

shale shaker

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

bit trip

1. n. [Drilling] The process of pulling the drillstring out of the wellbore for the purpose of changing a worn or underperforming drill bit. Upon reaching the surface, the bit is usually inspected and graded on the basis of how worn the teeth are, whether it is still in gauge and whether its components are still intact. On drilling reports, this trip may be abbreviated as TFNB (trip for new bit). See: bit record, tripping pipe

breakout

1. n. [Drilling] The process of unscrewing drillstring components, which are coupled by various threadforms known as connections, including tool joints and other threaded connections. Synonyms: break out See: drillstring

embrittlement

1. n. [Drilling] The process whereby steel components become less resistant to breakage and generally much weaker in tensile strength. While embrittlement has many causes, in the oil field it is usually the result of exposure to gaseous or liquid hydrogen sulfide [H2S]. On a molecular level, hydrogen ions work their way between the grain boundaries of the steel, where hydrogen ions recombine into molecular hydrogen [H2], taking up more space and weakening the bonds between the grains. The formation of molecular hydrogen can cause sudden metal failure due to cracking when the metal is subjected to tensile stress. This type of hydrogen-induced failure is produced when hydrogen atoms enter high strength steels. The failures due to hydrogen embrittlement normally have a period where no damage is observed, which is called incubation, followed by a sudden catastrophic failure. Hydrogen embrittlement is also called acid brittleness. See: corrosion control, hydrogen embrittlement, hydrogen induced failures, tensile strength

volumetric efficiency

1. n. [Drilling] The ratio of the actual output volume of a positive displacement pump divided by the theoretical geometric maximum volume of liquid that the pump could output under perfect conditions. Inefficiencies are caused by gaseous components (air and methane) being trapped in the liquid mud, leaking and noninstantaneously sealing valves in the pumps, fluid bypass of pump swab seals, and mechanical clearances and "play" in various bearings and connecting rods in the pumps. This efficiency is usually expressed as a percentage, and ranges from about 92% to 99% for most modern rig pumps and cement pumps. For critical calculations, this efficiency can be determined by a rigsite version of the "bucket and stopwatch" technique, whereby the rig crew will count the number of pump strokes required to pump a known volume of fluid. In cementing operations, displacement is often measured by alternating between two 10-bbl displacement tanks. See: swab

lost circulation

1. n. [Drilling] The reduced or total absence of fluid flow up the annulus when fluid is pumped through the drillstring. Though the definitions of different operators vary, this reduction of flow may generally be classified as seepage (less than 20 bbl/hr [3 m3/hr]), partial lost returns (greater than 20 bbl/hr [3 m3/hr] but still some returns), and total lost returns (where no fluid comes out of the annulus). In this severe latter case, the hole may not remain full of fluid even if the pumps are turned off. If the hole does not remain full of fluid, the vertical height of the fluid column is reduced and the pressure exerted on the open formations is reduced. This in turn can result in another zone flowing into the wellbore, while the loss zone is taking mud, or even a catastrophic loss of well control. Even in the two less severe forms, the loss of fluid to the formation represents a financial loss that must be dealt with, and the impact of which is directly tied to the per barrel cost of the drilling fluid and the loss rate over time. See: air drilling, bullhead, cementing, thief zone, well control

lost returns

rig floor

1. n. [Drilling] The relatively small work area in which the rig crew conducts operations, usually adding or removing drillpipe to or from the drillstring. The rig floor is the most dangerous location on the rig because heavy iron is moved around there. Drillstring connections are made or broken on the drillfloor, and the driller's console for controlling the major components of the rig are located there. Attached to the rig floor is a small metal room, the doghouse, where the rig crew can meet, take breaks and take refuge from the elements during idle times. Synonyms: derrick floor See: doghouse, slide, sub, Texas deck

derrick floor

workover

1. n. [Drilling] The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons. See: hydrocarbon

company representative

1. n. [Drilling] The representative of the oil company or operator on a drilling location. For land operations, the company man is responsible for operational issues on the location, including the safety and efficiency of the project. Even administrative managers are expected to respond to the direction of the company man when they are on the rigsite. Offshore, depending on the regulatory requirements, there may be an offshore installation manager, who supervises the company man on safety and vessel integrity issues, but not on operational issues. Synonyms: company man See: drilling foreman, toolpusher

company man

rotary table

1. n. [Drilling] The revolving or spinning section of the drillfloor that provides power to turn the drillstring in a clockwise direction (as viewed from above). The rotary motion and power are transmitted through the kelly bushing and the kelly to the drillstring. When the drillstring is rotating, the drilling crew commonly describes the operation as simply, "rotating to the right," "turning to the right," or, "rotating on bottom." Almost all rigs today have a rotary table, either as primary or backup system for rotating the drillstring. Topdrive technology, which allows continuous rotation of the drillstring, has replaced the rotary table in certain operations. A few rigs are being built today with topdrive systems only, and lack the traditional kelly system. See: driller, flowline, kelly, kelly bushing, mousehole, prime mover, racking back pipe, rig, slips, Texas deck, top drive

crushed zone

1. n. [Drilling] The rubblized rock just below the tooth of a rock bit. Rock in the crushed zone fails due to the high compressive stress placed on it by the bit tooth (in the case of a roller-cone bit). The effective creation of and removal of crushed zone rock is important to the efficiency of the drill bit. If the rock is not broken and removed efficiently, the result is akin to effectively drilling the hole twice. See: roller cone bit

bottoms-up

1. n. [Drilling] The sample obtained at the bottoms-up time or a volume of fluid to pump, as in "pump bottoms-up before drilling ahead."

traveling block

1. n. [Drilling] The set of sheaves that move up and down in the derrick. The wire rope threaded through them is threaded (or "reeved") back to the stationary crown blocks located on the top of the derrick. This pulley system gives great mechanical advantage to the action of the wire rope drilling line, enabling heavy loads (drillstring, casing and liners) to be lifted out of or lowered into the wellbore. See: block, crown block, drawworks, drillstring, hook, liner, sheave, slip and cut

Christmas tree

1. n. [Drilling] The set of valves, spools, and fittings connected to the top of a well to direct and control the flow of formation fluids from the well. See: cellar, formation fluid, shut-in bottomhole pressure, shut-in pressure

monkeyboard

1. n. [Drilling] The small platform that the derrickman stands on when tripping pipe. See: derrickman, fingerboard, tripping pipe

prime mover

1. n. [Drilling] The source of power for the rig location. On modern rigs, the prime mover consists of one to four or more diesel engines. These engines commonly produce several thousand horsepower. Typically, the diesel engines are connected to electric generators. The electrical power is then distributed by a silicon-controlled-rectifier (SCR) system around the rigsite. Rigs that convert diesel power to electricity are known as diesel electric rigs. Older designs transmit power from the diesel engines to certain rig components (drawworks, pumps and rotary table) through a system of mechanical belts, chains and clutches. On these rigs, a smaller electric generator powers lighting and small electrical requirements. These older rigs are referred to as mechanical rigs or more commonly, simply power rigs. See: drawworks, rotary table

annulus

1. n. [Drilling] The space between two concentric objects, such as between the wellbore and casing or between casing and tubing, where fluid can flow. Pipe may consist of drill collars, drillpipe, casing, or tubing. Alternate Form: annuli See: annular velocity, bridge, casing centralizer, cement, cementing, crossflow, displacement, drill collar, eccentricity, flapper valve, pack off

annular velocity

1. n. [Drilling] The speed at which drilling fluid or cement moves in the annulus. It is important to monitor annular velocity to ensure that the hole is being properly cleaned of cuttings, cavings and other debris while avoiding erosion of the borehole wall. The annular velocity is commonly expressed in units of feet per minute or, less commonly, meters per minute. The term is distinct from volumetric flow. Alternate Form: AV

rate of penetration (ROP)

1. n. [Drilling] 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. Alternate Form: rate of penetration See: antiwhirl bit, drill bit

drilling rate

1. n. [Drilling] 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. See: antiwhirl bit, drill bit

penetration rate

exit velocity

1. n. [Drilling] The speed the drilling fluid attains when accelerated through bit nozzles. The exit velocity is typically in the low-hundreds of feet per second. It has been reported that in certain shaly formations, an impingement velocity on the order of 250 feet per second is required to effectively remove newly created rock chips from the bottom of the hole. This impingement velocity is not, however, the same as the exit velocity, since the high-energy fluid jet loses velocity through viscous losses and conversions from kinetic energy to forms of potential energy occur once the fluid leaves the bit. For this reason, the well designer generally seeks to maximize the fluid velocity (or other measure of jet energy) to achieve maximum cleaning at the bottom of the hole. See: bit nozzle, drilling fluid, jet velocity

dynamic positioning

1. n. [Drilling] 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. See: BOP stack, drilling riser, drillship, semisubmersible

doghouse

1. n. [Drilling] 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. See: driller, rig floor

mast

1. n. [Drilling] The structure used to support the crown block and the drillstring. Masts are usually rectangular or trapezoidal in shape and offer a very good stiffness, important to land rigs whose mast is laid down when the rig is moved. They suffer from being heavier than conventional derricks and consequently are not usually found in offshore environments, where weight is more of a concern than in land operations. See: crown block, derrick, escape line, gooseneck, vee-door

derrick

1. n. [Drilling] 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. See: crown block, derrickman, escape line, fingerboard, gooseneck, mast, round trip, sheave, slide, standpipe, sub, tongs, traveling block

driller

1. n. [Drilling] 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." See: derrickman, directional drilling, doghouse, drilling crew, rotary table

shut-in pressure

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

SIP

wellhead

1. n. [Drilling] The system of spools, valves and assorted adapters that provide pressure control of a production well. See: casing string, casinghead, day rate, Texas deck

well control

1. n. [Drilling] The technology focused on maintaining pressure on open formations (that is, exposed to the wellbore) to prevent or direct the flow of formation fluids into the wellbore. This technology encompasses the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to offset those pressures in a predictable fashion. Also included are operational procedures to safely stop a well from flowing should an influx of formation fluid occur. To conduct well-control procedures, large valves are installed at the top of the well to enable wellsite personnel to close the well if necessary. See: abnormal pressure, adjustable choke, aquifer, blowout preventer, BOP stack, check valve, crossflow, flapper valve, formation fluid, kill line, lost circulation, mud weight, openhole, ram blowout preventer, swab

BHCT

1. n. [Drilling] The temperature of the circulating fluid (air, mud, cement or water) at the bottom of the wellbore after several hours of circulation. This temperature is lower than the bottomhole static temperature. Therefore, in extremely harsh environments, a component or fluid that would not ordinarily be suitable under bottomhole static conditions may be used with great care in circulating conditions. Similarly, a high-temperature well may be cooled down in an attempt to allow logging tools to function. The BHCT is also important in the design of operations to cement casing because the setting time for cement is temperature-dependent. The BHCT and bottomhole static temperature (BHST) are important parameters when placing large volumes of temperature-sensitive treatment fluids. Alternate Form: bottomhole circulating temperature

bottomhole circulating temperature

1. n. [Drilling] The temperature of the circulating fluid (air, mud, cement, or water) at the bottom of the wellbore after several hours of circulation. This temperature is lower than the bottomhole static temperature. Therefore, in extremely harsh environments, a component or fluid that would not ordinarily be suitable under bottomhole static conditions can be used with great care in circulating conditions. Similarly, a high-temperature well can be cooled down in an attempt to allow logging tools to function. The BHCT is also important in the design of operations to cement casing because the setting time for cement is temperature-dependent. The BHCT and bottomhole static temperature (BHST) are important parameters when placing large volumes of temperature-sensitive treatment fluids. Alternate Form: BHCT See: cementing, circulate, logging tool, treatment fluid

BHST

1. n. [Drilling] The temperature of the undisturbed formation at the final depth in a well. The formation cools during drilling and most of the cooling dissipates after about 24 hours of static conditions, although it is theoretically impossible for the temperature to return to undisturbed conditions. This temperature is measured under static conditions after sufficient time has elapsed to negate any effects from circulating fluids. Tables, charts, and computer routines are used to predict BHST as functions of depth, geographic area, and various time functions. The BHST is generally higher than the bottomhole circulating temperature and can be an important factor when using temperature-sensitive tools or treatments. See: bottomhole static temperature

eccentricity

1. n. [Drilling] The term used to describe how off-center a pipe is within another pipe or the openhole. It is usually expressed as a percentage. A pipe would be considered to be fully (100%) eccentric if it were lying against the inside diameter of the enclosing pipe or hole. A pipe would be said to be concentric (0% eccentric) if it were perfectly centered in the outer pipe or hole. Eccentricity becomes important to the well designer in estimating casing wear, wear and tear on the drillstring, and the removal of cuttings from the low side of an inclined hole. In the latter case, if the drillpipe lies on the low side of the hole (100% eccentric), the eccentricity results in low-velocity fluid flow on the low side. Gravity pulls cuttings to the low side of the hole, building a bed of small rock chips on the low side of the hole known as a cuttings bed. This cuttings bed becomes difficult to clean out of the annulus and can lead to significant problems for the drilling operation if the pipe becomes stuck in the cuttings bed. Antonyms: concentric See: centralizer, fluid flow

casing collar

1. n. [Drilling] The threaded collar used to connect two joints of casing. The resulting connection must provide adequate mechanical strength to enable the casing string to be run and cemented in place. The casing collar must also provide sufficient hydraulic isolation under the design conditions determined by internal and external pressure conditions and fluid characteristics. See: casing coupling, casing string

bit

1. n. [Drilling] The tool used to crush or cut rock. Everything on a drilling rig directly or indirectly assists the bit in crushing or cutting the rock. The bit is on the bottom of the drillstring and must be changed when it becomes excessively dull or stops making progress. Most bits work by scraping or crushing the rock, or both, usually as part of a rotational motion. Some bits, known as hammer bits, pound the rock vertically in much the same fashion as a construction site air hammer. See: antiwhirl bit, bit breaker, bottomhole assembly, drill collar, jet, make hole, polycrystalline diamond compact bit, roller cone bit

drill bit

1. n. [Drilling] The tool used to crush or cut rock. Everything on a drilling rig directly or indirectly assists the bit in crushing or cutting the rock. The bit is on the bottom of the drillstring and must be changed when it becomes excessively dull or stops making progress. Most bits work by scraping or crushing the rock, or both, usually as part of a rotational motion. Some bits, known as hammer bits, pound the rock vertically in much the same fashion as a construction site air hammer. Synonyms: bit See: bottomhole assembly, drillstring, gauge hole, jet, make hole, polycrystalline diamond compact bit, roller cone bit, spud

hook load

1. n. [Drilling] The total force pulling down on the hook. This total force includes the weight of the drillstring in air, the drill collars and any ancillary equipment, reduced by any force that tends to reduce that weight. Some forces that might reduce the weight include friction along the wellbore wall (especially in deviated wells) and, importantly, buoyant forces on the drillstring caused by its immersion in drilling fluid. If the BOPs are closed, any pressure in the wellbore acting on the cross-sectional area of the drillstring in the BOPs will also exert an upward force. See: blowout preventer, deviated hole, drilling fluid

open hole

1. n. [Drilling] The uncased portion of a well. All wells, at least when first drilled, have openhole sections that the well planner must contend with. Prior to running casing, the well planner must consider how the drilled rock will react to drilling fluids, pressures and mechanical actions over time. The strength of the formation must also be considered. A weak formation is likely to fracture, causing a loss of drilling mud to the formation and, in extreme cases, a loss of hydrostatic head and potential well control problems. An extremely high-pressure formation, even if not flowing, may have wellbore stability problems. Once problems become difficult to manage, casing must be set and cemented in place to isolate the formation from the rest of the wellbore. While most completions are cased, some are open, especially in horizontal or extended-reach wells where it may not be possible to cement casing efficiently. See: barefoot, blowout, borehole, caliper log, casing point, cementing, completion, packer, tight hole, well control

openhole

underground blowout

1. n. [Drilling] The uncontrolled flow of reservoir fluids from one reservoir into the wellbore, along the wellbore, and into another reservoir. This crossflow from one zone to another can occur when a high-pressure zone is encountered, the well flows, and the drilling crew reacts properly and closes the blowout preventers (BOPs). Pressure in the annulus then builds up to the point at which a weak zone fractures. Depending on the pressure at which the fracturing occurs, the flowing formation can continue to flow and losses continue to occur in the fractured zone. Underground blowouts are historically the most expensive problem in the drilling arena, eclipsing the costs of even surface blowouts. It may prove necessary to drill a second kill well in order to remedy an underground blowout. See: blowout, blowout preventer, kill

vee-door

1. n. [Drilling] The upside down V-shaped opening in one side of the derrick that enables long pipes and tools to be lifted into the interior of the derrick. This opening is aligned with the slide and catwalk of the rig. See: catwalk, mousehole, racking back pipe, slide, slide

coiled tubing drilling

1. n. [Drilling] The use of coiled tubing with downhole mud motors to turn the bit to deepen a wellbore. Coiled tubing drilling operations proceed quickly compared to using a jointed pipe drilling rig because connection time is eliminated during tripping. Coiled tubing drilling is economical in several applications, such as drilling slimmer wells, areas where a small rig footprint is essential, reentering wells and drilling underbalanced. See: coiled tubing, mud motor, trip, tripping pipe

true vertical depth

1. n. [Drilling] The vertical distance from a point in the well (usually the current or final depth) to a point at the surface, usually the elevation of the rotary kelly bushing (RKB). This is one of two primary depth measurements used by the drillers, the other being measured depth. TVD is important in determining bottomhole pressures, which are caused in part by the hydrostatic head of fluid in the wellbore. For this calculation, measured depth is irrelevant and TVD must be used. For most other operations, the driller is interested in the length of the hole or how much pipe will fit into the hole. For those measurements, measured depth, not TVD, is used. While the drilling crew should be careful to designate which measurement they are referring to, if no designation is used, they are usually referring to measured depth. Note that measured depth, due to intentional or unintentional curves in the wellbore, is always longer than true vertical depth. Alternate Form: true vertical depth (TVD) See: bottomhole pressure, hydrostatic head, hydrostatic pressure, kelly bushing, measured depth

yield

1. n. [Drilling] The volume occupied by one sack of dry cement after mixing with water and additives to form a slurry of a desired density. Yield is commonly expressed in US units as cubic feet per sack (ft3/sk).

borehole

1. n. [Drilling] The wellbore itself, including the openhole or uncased portion of the well. Borehole may refer to the inside diameter of the wellbore wall, the rock face that bounds the drilled hole. Synonyms: wellbore See: inside diameter, openhole

daylight tour

1. n. [Drilling] The work shift of a drilling crew that commences at about the sunrise hour. Drilling operations usually take place around the clock because of the cost to rent a rig. As a result, there are usually two separate crews working twelve-hour tours to keep the operation going. Some companies prefer three eight-hour tours: the daylight tour starts at daylight or 8 AM; the graveyard tour is the overnight shift or the shift that begins at midnight. (Pronounced "tower" in many areas.) Synonyms: morning tour, tour See: drilling crew

evening tour

1. n. [Drilling] The work shift of a drilling crew that starts in the evening or late afternoon. Drilling operations usually occur around the clock because of the cost to rent a rig. As a result, there are usually two separate crews working twelve-hour tours to keep the operation going. Some companies prefer three eight-hour tours: the evening tour starts at 4 PM; the graveyard tour is the overnight shift or the shift that begins at midnight. (Pronounced "tower" in many areas.) Antonyms: morning tour See: tour

morning tour

1. n. [Drilling] The work shift of a drilling crew that starts in the morning. Drilling operations usually occur around the clock because of the cost to rent a rig. As a result, there are usually two separate crews working twelve-hour tours to keep the operation going. Some companies prefer three eight-hour tours: the daylight tour starts at daylight or 8 AM; the graveyard tour is the overnight shift or the shift that begins at midnight. (Pronounced "tower" in many areas.) See: drilling crew, evening tour, graveyard tour, tour

fingerboard

1. n. [Drilling] The working platform approximately halfway up the derrick or mast in which the derrickman stores drillpipe and drill collars in an orderly fashion during trips out of the hole. The entire platform consists of a small section from which the derrickman works (called the monkeyboard), and several steel fingers with slots between them that keep the tops of the drillpipe in place. See: drill collar, monkeyboard, racking back pipe, round trip, stand, trip out

gravity toolface

1. n. [Drilling] Toolface angle used for deviated wells. Gravity toolface is the angle of the borehole survey instrument within the wellbore measured clockwise relative to up and in the plane perpendicular to the wellbore axis; the high side (maximum build), maximum right, low side (maximum drop) and maximum left directions have gravity toolface angles of 0°, 90°, 180° and 270°, respectively. Synonyms: high-side toolface See: magnetic toolface, toolface

high-side toolface

1. n. [Drilling] Toolface angle used for deviated wells. High-side toolface is the angle of the borehole survey instrument within the wellbore measured clockwise relative to up and in the plane perpendicular to the wellbore axis; the high side (maximum build), maximum right, low side (maximum drop) and maximum left directions have high-side toolface angles of 0°, 90°, 180° and 270°, respectively. Synonyms: gravity toolface Alternate Form: high-side toolface, high-side toolface See: magnetic toolface, toolface

magnetic toolface

1. n. [Drilling] Toolface angle used for near-vertical wells. Magnetic toolface is the angle, or azimuth, of the borehole survey instrument within the wellbore measured clockwise relative to magnetic north and in the plane perpendicular to the wellbore axis; the north, east, south and west directions have magnetic toolface angles of 0°, 90°, 180° and 270°, respectively. Magnetic toolface may be corrected to reference either grid north or true north. See: gravity toolface, toolface

drillpipe

1. n. [Drilling] 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. See: bottomhole assembly, circulation system, drilling fluid, drillstem, drillstring, joint, tool joint

stand

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

blowout

1. n. [Drilling] Uncontrolled flow of formation fluids from a well. An uncontrolled flow of formation fluids from the wellbore or into lower pressured subsurface zones (underground blowout). Uncontrolled flows cannot be contained using previously installed barriers and require specialized services intervention. A blowout may consist of water, oil, gas or a mixture of these. Blowouts may occur during all types of well activities and are not limited to drilling operations. In some circumstances, it is possible that the well will bridge over, or seal itself with rock fragments from collapsing formations downhole. See: abnormal pressure, blowout preventer, openhole, pressure hunt, turnkey

wellbore orientation

1. n. [Drilling] Wellbore direction. Wellbore orientation may be described in terms of inclination and azimuth. Inclination refers to the vertical angle measured from the down direction—the down, horizontal and up directions have inclinations of 0°, 90° and 180°, respectively. Azimuth refers to the horizontal angle measured clockwise from true north—the north, east, south and west directions have azimuths of 0°, 90°, 180° and 270°, respectively. Synonyms: borehole orientation

H2S

1. n. [Drilling] [H2S] An extraordinarily poisonous gas with a molecular formula of H2S. At low concentrations, H2S has the odor of rotten eggs, but at higher, lethal concentrations, it is odorless. H2S is hazardous to workers and a few seconds of exposure at relatively low concentrations can be lethal, but exposure to lower concentrations can also be harmful. The effect of H2S depends on duration, frequency and intensity of exposure as well as the susceptibility of the individual. Hydrogen sulfide is a serious and potentially lethal hazard, so awareness, detection and monitoring of H2S is essential. Since hydrogen sulfide gas is present in some subsurface formations, drilling and other operational crews must be prepared to use detection equipment, personal protective equipment, proper training and contingency procedures in H2S-prone areas. Hydrogen sulfide is produced during the decomposition of organic matter and occurs with hydrocarbons in some areas. It enters drilling mud from subsurface formations and can also be generated by sulfate-reducing bacteria in stored muds. H2S can cause sulfide-stress-corrosion cracking of metals. Because it is corrosive, H2S production may require costly special production equipment such as stainless steel tubing. Sulfides can be precipitated harmlessly from water muds or oil muds by treatments with the proper sulfide scavenger. H2S is a weak acid, donating two hydrogen ions in neutralization reactions, forming HS- and S-2 ions. In water or water-base muds, the three sulfide species, H2S and HS- and S-2 ions, are in dynamic equilibrium with water and H+ and OH- ions. The percent distribution among the three sulfide species depends on pH. H2S is dominant at low pH, the HS- ion is dominant at mid-range pH and S2 ions dominate at high pH. In this equilibrium situation, sulfide ions revert to H2S if pH falls. Sulfides in water mud and oil mud can be quantitatively measured with the Garrett Gas Train according to procedures set by API. Alternate Form: hydrogen sulfide

tortuosity

1. n. [Formation Evaluation] A measure of the geometric complexity of a porous medium. Tortuosity is a ratio that characterizes the convoluted pathways of fluid diffusion and electrical conduction through porous media. In the fluid mechanics of porous media, tortuosity is the ratio of the length of a streamline—a flow line or path—between two points to the straight-line distance between those points. Tortuosity is thus related to the ratio of a fluid's diffusion coefficient when it is not confined by a porous medium to its effective diffusion coefficient when confined in a porous medium. Tortuosity is also related to the formation factor, which is the ratio of electrical resistivity of a conductive fluid in a porous medium to the electrical resistivity of the fluid itself. In some literature, tortuosity denotes the square of the ratio defined above, whereas in other literature, the term tortuosity factor is used for the square of the ratio. See: a, formation factor

TOC

1. n. [Geology, Shale Gas] The concentration of organic material in source rocks as represented by the weight percent of organic carbon. A value of approximately 0.5% total organic carbon by weight percent is considered the minimum for an effective source rock, although values of 2% are considered the minimum for shale gas reservoirs; values exceeding 10% exist, although some geoscientists assert that high total organic carbon values indicate the possibility of kerogen filling pore space rather than other forms of hydrocarbons. Total organic carbon is measured from 1-g samples of pulverized rock that are combusted and converted to CO or CO2. If a sample appears to contain sufficient total organic carbon to generate hydrocarbons, it may be subjected to pyrolysis. Alternate Form: total organic carbon

aquifer

1. n. [Geology] A body of rock whose fluid saturation, porosity and permeability permit production of groundwater.

abnormal pressure

1. n. [Geology] A subsurface condition in which the pore pressure of a geologic formation exceeds or is less than the expected, or normal, formation pressure. When impermeable rocks such as shales are compacted rapidly, their pore fluids cannot always escape and must then support the total overlying rock column, leading to abnormally high formation pressures. Excess pressure, called overpressure or geopressure, can cause a well to blow out or become uncontrollable during drilling. Severe underpressure can cause the drillpipe to stick to the underpressured formation. See: compaction, geopressure gradient, geostatic pressure, hydrostatic pressure, normal pressure, pressure gradient

joint

1. n. [Geology] A surface of breakage, cracking or separation within a rock along which there has been no movement parallel to the defining plane. The usage by some authors can be more specific: When walls of a fracture have moved only normal to each other, the fracture is called a joint. See: fault, fracture

azimuth

1. n. [Geology] The angle between the vertical projection of a line of interest onto a horizontal surface and true north or magnetic north measured in a horizontal plane, typically measured clockwise from north. See: attitude, dip, strike, trend

cement

1. n. [Geology] The binding material in sedimentary rocks that precipitates between grains from pore fluids. Calcite and quartz are common cement-forming minerals. See: authigenic, cased hole, cementation, chlorite, diagenesis, hardground, lithification, sandstone

hydrostatic head

1. n. [Geology] The height of a column of freshwater that exerts pressure at a given depth. Some authors use the term synonymously with hydrostatic pressure. See: fresh water, hydraulic head, hydrostatic pressure, sag

hydrostatic pressure

1. n. [Geology] The normal, predicted pressure for a given depth, or the pressure exerted per unit area by a column of freshwater from sea level to a given depth. Abnormally low pressure might occur in areas where fluids have been drained, such as a depleted hydrocarbon reservoir. Abnormally high pressure might occur in areas where burial of water-filled sediments by an impermeable sediment such as clay was so rapid that fluids could not escape and the pore pressure increased with deeper burial. See: abnormal pressure, absolute pressure, formation pressure, fresh water, geopressure, geopressure gradient, hydraulic head, hydrostatic head, normal pressure, overpressure, pore pressure, reservoir pressure, underpressure

displacement

1. n. [Geology] The offset of segments or points that were once continuous or adjacent. Layers of rock that have been moved by the action of faults show displacement on either side of the fault surface. See: fault, transform fault

formation pressure

1. n. [Geology] The pressure of fluids within the pores of a reservoir, usually hydrostatic pressure, or the pressure exerted by a column of water from the formation's depth to sea level. When impermeable rocks such as shales form as sediments are compacted, their pore fluids cannot always escape and must then support the total overlying rock column, leading to anomalously high formation pressures. Because reservoir pressure changes as fluids are produced from a reservoir, the pressure should be described as measured at a specific time, such as initial reservoir pressure. Alternate Form: pore pressure, reservoir pressure See: abnormal pressure, absolute pressure, formation, geopressure, geostatic pressure, hydrostatic pressure, lithostatic pressure, normal pressure, overpressure, pressure gradient, shale, virgin pressure

pore pressure

1. n. [Geology] The pressure of fluids within the pores of a reservoir, usually hydrostatic pressure, or the pressure exerted by a column of water from the formation's depth to sea level. When impermeable rocks such as shales form as sediments are compacted, their pore fluids cannot always escape and must then support the total overlying rock column, leading to anomalously high formation pressures. Because reservoir pressure changes as fluids are produced from a reservoir, the pressure should be described as measured at a specific time, such as initial reservoir pressure. See: abnormal pressure, compaction, geopressure, hydrostatic pressure, impermeable, overpressure, permeability, pressure gradient, shale, underpressure, virgin pressure

reservoir pressure

1. n. [Geology] The pressure of fluids within the pores of a reservoir, usually hydrostatic pressure, or the pressure exerted by a column of water from the formation's depth to sea level. When impermeable rocks such as shales form as sediments are compacted, their pore fluids cannot always escape and must then support the total overlying rock column, leading to anomalously high formation pressures. Because reservoir pressure changes as fluids are produced from a reservoir, the pressure should be described as measured at a specific time, such as initial reservoir pressure. Synonyms: hydrostatic pressure See: hydrostatic pressure, lithostatic pressure, retrograde condensation, virgin pressure

erosion

1. n. [Geology] The process of denudation of rocks, including physical, chemical and biological breakdown and transportation. See: conformable, conformable, detrital, disconformity, filter-cake thickness, micrite, nonconformity, sequence boundary, unconformity, weathering

brine

1. n. [Geology] Water containing more dissolved inorganic salt than typical seawater. See: connate water, formation water, fresh water, interstitial water

clear brine

1. n. [Geology] Water containing more dissolved inorganic salt than typical seawater. Synonyms: brine See: cesium formate, formation water, fresh water

free water

1. n. [Geology] Water that is mobile, available to flow, and not bound to surfaces of grains or minerals in rock.

skid

1. n. [Geophysics] A conveyance, such as a sled with runners or pontoons, used to transport geophysical gear to a location. Skids are commonly deployed in acquisition of seismic data in marshes or other areas of soft, soggy terrain. See: acquisition, marsh

survey

1. n. [Geophysics] A dataset measured and recorded with reference to a particular area of the Earth's surface, such as a seismic survey. See: accelerometer, base station, baseline, baseline, benchmark, benchmark, cultural noise, depth point, drift, electromagnetic method, free-air correction, gravity, gravity survey, magnetics, monument, perpendicular offset, salt proximity survey, seismic, side-scan sonar, telluric-current method

wireline log

1. n. [Reservoir Characterization, Formation Evaluation, Drilling] A continuous measurement of formation properties with electrically powered instruments to infer properties and make decisions about drilling and production operations. The record of the measurements, typically a long strip of paper, is also called a log. Measurements include electrical properties (resistivity and conductivity at various frequencies), sonic properties, active and passive nuclear measurements, dimensional measurements of the wellbore, formation fluid sampling, formation pressure measurement, wireline-conveyed sidewall coring tools, and others. For wireline measurements, the logging tool (or sonde) is lowered into the open wellbore on a multiple conductor, contra-helically armored wireline cable. Once the tool string (link to ID 2964) has reached the bottom of the interval of interest, measurements are taken on the way out of the wellbore. This is done in an attempt to maintain tension on the cable (which stretches) as constant as possible for depth correlation purposes. (The exception to this practice is in certain hostile environments in which the tool electronics might not survive the downhole temperatures for long enough to allow the tool to be lowered to the bottom of the hole and measurements to be recorded while pulling the tool up the hole. In this case, "down log" measurements might be conducted on the way into the well, and repeated on the way out if possible.) Most wireline measurements are recorded continuously while the sonde is moving. Certain fluid sampling and pressure-measuring tools require that the sonde be stopped, increasing the chance that the sonde or the cable might become stuck. Logging while drilling (LWD) tools take measurements in much the same way as wireline-logging tools, except that the measurements are taken by a self-contained tool near the bottom of the bottomhole assembly and are recorded downward (as the well is deepened) rather than upward from the bottom of the hole. See: hostile environment, log

deviated drilling

1. n. [Shale Gas, Drilling] The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken downhole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a downhole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes. Directional drilling is common in shale reservoirs because it allows drillers to place the borehole in contact with the most productive reservoir rock. Synonyms: directional drilling See: directional driller, directional well, geosteering, horizontal drilling, mud motor, slide, steerable motor

shear ram

1. n. [Well Workover and Intervention, Drilling] A blowout preventer (BOP) closing element fitted with hardened tool steel blades designed to cut the drillpipe or tubing when the BOP is closed, and then fully close to provide isolation or sealing of the wellbore. A shear ram is normally used as a last resort to regain pressure control of a well that is flowing. Once the pipe is cut (or sheared) by the shear rams, it is usually left hanging in the BOP stack, and kill operations become more difficult. The joint of drillpipe or tubing is destroyed in the process, but the rest of the string is unharmed by the operation of shear rams. Synonyms: blind shear ram See: blind ram, blowout, blowout preventer, BOP stack, drillstring, kill, shear-seal BOP

blind shear ram

1. n. [Well Workover and Intervention, Drilling] A blowout preventer (BOP) closing element fitted with hardened tool steel blades designed to cut the drillpipe or tubing when the BOP is closed, and then fully close to provide isolation or sealing of the wellbore. A shear ram is normally used as a last resort to regain pressure control of a well that is flowing. Once the pipe is cut (or sheared) by the shear rams, it is usually left hanging in the BOP stack, and kill operations become more difficult. The joint of drillpipe or tubing is destroyed in the process, but the rest of the string is unharmed by the operation of shear rams. Synonyms: shear ram See: blind ram, blowout preventer, BOP stack, kill, shear-seal BOP

mill

1. n. [Well Workover and Intervention, Drilling] A tool that grinds metal downhole. A mill is usually used to remove junk in the hole or to grind away all or part of a casing string. In the case of junk, the metal must be broken into smaller pieces to facilitate removal from the wellbore so that drilling can continue. When milling casing, the intent is to cut a window through the side of the casing or to remove a continuous section of the casing so that the wellbore may be deviated from the original well through the window or section removed. Depending on the type of grinding or metal removal required, the shape of the cutting structures of mills varies. Virtually all mills, however, utilize tungsten carbine cutting surfaces. See: casing string, junk, mill out, packer

milling

1. n. [Well Workover and Intervention, Drilling] The use of a mill or similar downhole tool to cut and remove material from equipment or tools located in the wellbore. Successful milling operations require appropriate selection of milling tools, fluids and techniques. The mills, or similar cutting tools, must be compatible with the fish materials and wellbore conditions. The circulated fluids should be capable of removing the milled material from the wellbore. Finally, the techniques employed should be appropriate to the anticipated conditions and the likely time required to reach the operation objectives. See: casing string, junk, mill out, packer

mill out

1. vb. [Drilling, Well Workover and Intervention] To use a mill or similar downhole tool to cut and remove metal downhole. A mill is usually used to remove junk in the hole or to grind away all or part of a casing string. When milling out casing, the intent is to cut a window through the side of the casing or to remove a continuous section of the casing so that the wellbore may be deviated from the original well through the window or section removed. Successful milling operations require appropriate selection of milling tools, fluids and techniques. The mills, or similar cutting tools, must be compatible with the fish or casing materials and wellbore conditions. The circulated fluids should be capable of removing the milled material from the wellbore. Finally, the techniques employed should be appropriate to the anticipated conditions and the likely time required to reach the operation objectives. See: casing string, junk, milling, packer

POOH

1. vb. [Drilling] Abbreviation for pull out of the hole. To remove the drillstring from the wellbore. Synonyms: come out of the hole, trip out Alternate Form: pull out of the hole See: bit trip, round trip, TFNB, trip

TFNB

1. vb. [Drilling] An abbreviation on drilling reports or mud logs signifying trip for new bit. See: bit trip, tripping pipe

kick off

1. vb. [Drilling] Intentionally deviate a vertical well.

leak off

1. vb. [Drilling] The magnitude of pressure exerted on a formation that causes fluid to be forced into the formation. The fluid may be flowing into the pore spaces of the rock or into cracks opened and propagated into the formation by the fluid pressure. This term is normally associated with a test to determine the strength of the rock, commonly called a pressure integrity test (PIT) or a leakoff test (LOT). During the test, a real-time plot of injected fluid versus fluid pressure is plotted. The initial stable portion of this plot for most wellbores is a straight line, within the limits of the measurements. The leakoff is the point of permanent deflection from that straight portion. The well designer must then either adjust plans for the well to this leakoff pressure, or if the design is sufficiently conservative, proceed as planned. Alternate Form: leakoff

make a connection

1. vb. [Drilling] To add a length of drillpipe to the drillstring to continue drilling. In what is called jointed pipe drilling, joints of drillpipe, each about 30 ft [9 m] long, are screwed together as the well is drilled. When the bit on the bottom of the drillstring has drilled down to where the kelly or topdrive at the top of the drillstring nears the drillfloor, the drillstring between the two must be lengthened by adding a joint or a stand (usually three joints) to the drillstring. Once the rig crew is ready, the driller stops the rotary, picks up off bottom to expose a threaded connection below the kelly and turns the pumps off. The crew sets the slips to grip the drillstring temporarily, unscrews that threaded connection and screws the kelly (or topdrive) into the additional joint (or stand) of pipe. The driller picks that joint or stand up to allow the crew to screw the bottom of that pipe into the top of the temporarily hanging drillstring. The driller then picks up the entire drillstring to remove the slips, carefully lowers the drillstring while starting the pumps and rotary, and resumes drilling when the bit touches bottom. A skilled rig crew can physically accomplish all of those steps in a minute or two. See: joint, kelly, mousehole, slips, stand, top drive

reciprocate

1. vb. [Drilling] To alternately raise and lower the drillstring, casing string or liner in the wellbore. Reciprocation is usually limited to 30 to 60 ft [9 to 18 m] of vertical travel in the derrick. The purpose of reciprocating the drillstring is usually to clean cuttings and other debris from the wellbore. Reciprocating the strings can improve the chances of a good cement job in casing or liners. See: cementing, cuttings, liner

RIH

1. vb. [Drilling] To connect pipe together and lower the connected length into the borehole in a controlled fashion. The pipe lengths are usually screwed together either with rotary-shouldered connections for the drillstring, or threaded and coupled connections for casing, liners and most tubing. Antonyms: come out of the hole Alternate Form: run in hole

run in hole

geosteer

1. vb. [Drilling] To control the direction of a well based on the results of downhole geological logging measurements rather than three-dimensional targets in space, usually to keep a directional wellbore within a pay zone. In mature areas, geosteering may be used to keep a wellbore in a particular section of a reservoir to minimize gas or water breakthrough and maximize economic production from the well. See: directional drilling, geosteering

make hole

1. vb. [Drilling] To deepen a wellbore with the drill bit. To drill ahead. See: bit

core

1. vb. [Drilling] To deepen the wellbore by way of collecting a cylindrical sample of rock. A core bit is used to accomplish this, in conjunction with a core barrel and core catcher. The bit is usually a drag bit fitted with either PDC or natural diamond cutting structures, but the core bit is unusual in that it has a hole in its center. This allows the bit to drill around a central cylinder of rock, which is taken in through the bit and into the core barrel. The core barrel itself may be thought of as a special storage chamber for holding the rock core. The core catcher serves to grip the bottom of the core and, as tension is applied to the drillstring, the rock under the core breaks away from the undrilled formation below it. The core catcher also retains the core so that it does not fall out the bottom of the drillstring, which is open in the middle at that point. See: diamond bit, drag bit, polycrystalline diamond compact bit

sidetrack

1. vb. [Drilling] To drill a secondary wellbore away from an original wellbore. A sidetracking operation may be done intentionally or may occur accidentally. Intentional sidetracks might bypass an unusable section of the original wellbore or explore a geologic feature nearby. In the bypass case, the secondary wellbore is usually drilled substantially parallel to the original well, which may be inaccessible due to an irretrievable fish, junk in the hole, or a collapsed wellbore. See: fish, junk

air drill

1. vb. [Drilling] To drill using gases (typically compressed air or nitrogen) to cool the drill bit and lift cuttings out of the wellbore, instead of the more conventional use of liquids. The advantages of air drilling are that it is usually much faster than drilling with liquids and it may eliminate lost circulation problems. The disadvantages are the inability to control the influx of formation fluid into the wellbore and the destabilization of the borehole wall in the absence of the wellbore pressure typically provided by liquids. See: lost circulation, mist drilling

slide

1. vb. [Drilling] To drill with a mud motor rotating the bit downhole without rotating the drillstring from the surface. This operation is conducted when the bottomhole assembly has been fitted with a bent sub or a bent housing mud motor, or both, for directional drilling. Sliding is the predominant method to build and control or correct hole angle in modern directional drilling operations. Directional drilling is conceptually simple: Point the bit in the desired direction. This pointing is accomplished through the bent sub, which has a small angle offset from the axis of the drillstring, and a measurement device to determine the direction of offset. Without turning the drillstring, the bit is rotated with a mud motor, and drills in the direction it points. With steerable motors, when the desired wellbore direction is attained, the entire drillstring is rotated and drills straight rather than at an angle. By controlling the amount of hole drilled in the sliding versus the rotating mode, the wellbore trajectory can be controlled precisely. See: catwalk, directional drilling, mud motor, vee-door

underream

1. vb. [Drilling] To enlarge a wellbore past its original drilled size. Underreaming is sometimes done for safety or efficiency reasons. Some well planners believe it is safer to drill unknown shallow formations with a small-diameter bit, and if no gas is encountered, to then enlarge the pilot hole. An underreaming operation may also be done if a small additional amount of annular space is desired, as might be the case in running a liner if surge pressures were problematic. See: bicenter bit, liner, ream

ream

1. vb. [Drilling] To enlarge a wellbore. Reaming may be necessary for several reasons. Perhaps the most common reason for reaming a section of a hole is that the hole was not drilled as large as it should have been at the outset. This can occur when a bit has been worn down from its original size, but might not be discovered until the bit is tripped out of the hole, and some undergauge hole has been drilled. Last, some plastic formations may slowly flow into the wellbore over time, requiring the reaming operation to maintain the original hole size. See: underream

break circulation

1. vb. [Drilling] To establish circulation of drilling fluids after a period of static conditions. Circulation may resume after a short break, such as taking a survey or making a mousehole connection, or after a prolonged interruption, such as after a round trip. The operation is of more concern to drillers and well planners with longer static intervals, since immobile drilling fluid tends to become less fluid and more gelatinous or semisolid with time. See: circulate, connection, mousehole

bullhead

1. vb. [Drilling] To forcibly pump fluids into a formation, usually formation fluids that have entered the wellbore during a well control event. Though bullheading is intrinsically risky, it is performed if the formation fluids are suspected to contain hydrogen sulfide gas to prevent the toxic gas from reaching the surface. Bullheading is also performed if normal circulation cannot occur, such as after a borehole collapse. The primary risk in bullheading is that the drilling crew has no control over where the fluid goes and the fluid being pumped downhole usually enters the weakest formation. In addition, if only shallow casing is cemented in the well, the bullheading operation can cause wellbore fluids to broach around the casing shoe and reach the surface. This broaching to the surface has the effect of fluidizing and destabilizing the soil (or the subsea floor), and can lead to the formation of a crater and loss of equipment and life. See: casing shoe, formation fluid, lost circulation

rig up

1. vb. [Drilling] To make ready for use. Equipment must typically be moved onto the rig floor, assembled and connected to power sources or pressurized piping systems. Antonyms: rig down

twist off

1. vb. [Drilling] To part or break the drillstring downhole due to either fatigue or excessive torque. Alternate Form: twist-off

racking back pipe

1. vb. [Drilling] To place a stand of drillpipe in the derrick when coming out of the hole on a trip. The rig crew racks back pipe after the stand is unscrewed from the rest of the drillstring. The floor crew then pushes the lower part of the stand away from the rotary table to a position on one side of the vee-door. While the floor crew is pushing the pipe, the derrickman gets ready to pull the top of the stand over into the fingerboards. Once the rig crew has the pipe in the correct location, the driller slacks off on the drawworks, allowing the stand to rest on the drillfloor. This takes weight off of the elevators previously supporting the pipe at the top, so the derrickman can then unlatch the elevators and pull the top of the pipe into the fingerboards for storage. Modern rig designs have automated pipe-handling equipment that moves the pipe. When tripping the pipe out of the hole, racking back pipe may occur every two to five minutes for hours at a time. See: come out of the hole, derrickman, elevator, fingerboard, rotary table, stand, vee-door

stab

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

pack off

1. vb. [Drilling] To plug the wellbore around a drillstring. This can happen for a variety of reasons, the most common being that either the drilling fluid is not properly transporting cuttings and cavings out of the annulus or portions of the wellbore wall collapse around the drillstring. When the well packs off, there is a sudden reduction or loss of the ability to circulate, and high pump pressures follow. If prompt remedial action is not successful, an expensive episode of stuck pipe can result. The term is also used in gravel packing to describe the act of placing all the sand or gravel in the annulus. See: annulus, circulate, cuttings, stuck pipe

plug and abandon

1. vb. [Drilling] To prepare a well to be closed permanently, usually after either logs determine there is insufficient hydrocarbon potential to complete the well, or after production operations have drained the reservoir. Different regulatory bodies have their own requirements for plugging operations. Most require that cement plugs be placed and tested across any open hydrocarbon-bearing formations, across all casing shoes, across freshwater aquifers, and perhaps several other areas near the surface, including the top 20 to 50 ft [6 to 15 m] of the wellbore. The well designer may choose to set bridge plugs in conjunction with cement slurries to ensure that higher density cement does not fall in the wellbore. In that case, the bridge plug would be set and cement pumped on top of the plug through drillpipe, and then the drillpipe withdrawn before the slurry thickened. Alternate Form: P&A See: bridge plug, casing shoe, cement, cementing, operator

P&A

cementing

1. vb. [Drilling] To prepare and pump cement into place in a wellbore. Cementing operations may be undertaken to seal the annulus after a casing string has been run, to seal a lost circulation zone, to set a plug in an existing well from which to push off with directional tools or to plug a well so that it may be abandoned. Before cementing operations commence, engineers determine the volume of cement (commonly with the help of a caliper log) to be placed in the wellbore and the physical properties of both the slurry and the set cement needed, including density and viscosity. A cementing crew uses special mixers and pumps to displace drilling fluids and place cement in the wellbore. For more details, see The Defining Series: Well Cementing Fundamentals. See: bottomhole circulating temperature, bow-spring centralizer, casing point, cement head, centralizer, check valve, day rate, drilling fluid, float joint, free water, openhole, plug and abandon, reciprocate, scratcher, surface casing, turnkey, wait on cement

circulate

1. vb. [Drilling] To pump fluid through the whole active fluid system, including the borehole and all the surface tanks that constitute the primary system. See: bottomhole circulating temperature, break circulation, circulation, pack off

circulate out

1. vb. [Drilling] To pump the drilling fluid until a sample from the bottom of the hole reaches the surface. This is commonly performed when drilling has ceased so that the wellsite geologist can collect a cuttings sample from the formation being drilled or when the driller suspects that a small amount of gas has entered the wellbore. Thus, by circulating out, the gas bubble is eased out of the wellbore safely. See: drilling fluid

snub

1. vb. [Drilling] To put drillpipe into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well. Snubbing is necessary when a kick is taken, since well kill operations should always be conducted with the drillstring on bottom, and not somewhere up the wellbore. If only the annular BOP has been closed, the drillpipe may be slowly and carefully lowered into the wellbore, and the BOP itself will open slightly to permit the larger diameter tool joints to pass through. If the well has been closed with the use of ram BOPs, the tool joints will not pass by the closed ram element. Hence, while keeping the well closed with either another ram BOP or the annular BOP, the ram must be opened manually, then the pipe lowered until the tool joint is just below the ram, and then closing the ram again. This procedure is repeated whenever a tool joint must pass by a ram BOP. In snubbing operations, the pressure in the wellbore acting on the cross-sectional area of the tubular can exert sufficient force to overcome the weight of the drillstring, so the string must be pushed (or "snubbed") back into the wellbore. In ordinary stripping operations, the pipe falls into the wellbore under its own weight, and no additional downward force or pushing is required. See: annular BOP, blowout preventer, kick, kill, ram blowout preventer, stripping, tool joint

nipple up

1. vb. [Drilling] To put together, connect parts and plumbing, or otherwise make ready for use. This term is usually reserved for the installation of a blowout preventer stack. See: BOP stack

swab

1. vb. [Drilling] To reduce pressure in a wellbore by moving pipe, wireline tools or rubber-cupped seals up the wellbore. If the pressure is reduced sufficiently, reservoir fluids may flow into the wellbore and towards the surface. Swabbing is generally considered harmful in drilling operations, because it can lead to kicks and wellbore stability problems. In production operations, however, the term is used to describe how the flow of reservoir hydrocarbons is initiated in some completed wells. See: kick, volumetric efficiency, well control

come out of the hole

1. vb. [Drilling] To remove the drillstring from the wellbore. Antonyms: run in hole Alternate Form: pull out of the hole, trip out See: racking back pipe

trip out

1. vb. [Drilling] To remove the drillstring from the wellbore. Synonyms: come out of the hole, pull out of the hole See: bit trip, TFNB, trip

pull out of the hole

1. vb. [Drilling] To remove the drillstring from the wellbore. Synonyms: come out of the hole, trip out Alternate Form: POOH See: bit trip, round trip, TFNB, trip

slip and cut

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

spud

1. vb. [Drilling] To start the well drilling process by removing rock, dirt and other sedimentary material with the drill bit. See: bit

kill

1. vb. [Drilling] To stop a well from flowing or having the ability to flow into the wellbore. Kill procedures typically involve circulating reservoir fluids out of the wellbore or pumping higher density mud into the wellbore, or both. In the case of an induced kick, where the mud density is sufficient to kill the well but the reservoir has flowed as a result of pipe movement, the driller must circulate the influx out of the wellbore. In the case of an underbalanced kick, the driller must circulate the influx out and increase the density of the drilling fluid. In the case of a producing well, a kill fluid with sufficient density to overcome production of formation fluid is pumped into the well to stop the flow of reservoir fluids. Synonyms: density See: drillstem test, kick, mud, mud density, shear ram, snubbing, underbalanced, underground blowout

wait on cement (WOC)

1. vb. [Drilling] To suspend drilling operations while allowing cement slurries to solidify, harden and develop compressive strength. The drilling crew usually uses this time to catch up on maintenance items, to rig down one BOP and rig up another one for the new casing, to get tools and materials ready for the next hole section, and other non-drilling tasks. The WOC time ranges from a few hours to several days, depending on the difficulty and criticality of the cement job in question. WOC time allows cement to develop strength, and avert development of small cracks and other fluid pathways in the cement that might impair zonal isolation. Alternate Form: wait on cement See: cement, cementing, rig down, rig up

rig down

1. vb. [Drilling] To take apart equipment for storage and portability. Equipment typically must be disconnected from power sources, decoupled from pressurized systems, disassembled and moved off the rig floor or even off location. Antonyms: rig up

nipple down

1. vb. [Drilling] To take apart, disassemble and otherwise prepare to move the rig or blowout preventers. See: blowout preventer, rig

make up

1. vb. [Drilling] To tighten threaded connections.

backoff

1. vb. [Drilling] To unscrew drillstring components downhole. The drillstring, including drillpipe and the bottomhole assembly, are coupled by various threadforms known as connections, or tool joints. Often when a drillstring becomes stuck it is necessary to "back off" the string as deep as possible to recover as much of the string as possible. To facilitate the fishing or recovery operation, the backoff is usually accomplished by applying reverse torque and detonating an explosive charge inside a selected threaded connection. The force of the explosion enlarges the female (outer) thread enough that the threaded connection unscrews instantly. A torqueless backoff may be performed as well. In that case, tension is applied, and the threads slide by each other without turning when the explosive detonates. Backing off can also occur unintentionally. Synonyms: break out Alternate Form: back off

back off

1. vb. [Drilling] To unscrew drillstring components downhole. The drillstring, including drillpipe and the bottomhole assembly, are coupled by various threadforms known as connections, or tool joints. Often, when a drillstring becomes stuck, it is necessary to "back off" the string as deep as possible to recover as much of the string as possible. To facilitate the fishing or recovery operation, the backoff is usually accomplished by applying reverse torque and detonating an explosive charge inside a selected threaded connection. The force of the explosion enlarges the female (outer) thread enough that the threaded connection unscrews instantly. A torqueless backoff may be performed as well. In that case, tension is applied, and the threads slide by each other without turning when the explosive detonates. Backing off can also occur unintentionally. Synonyms: break out Alternate Form: backoff See: box, connection, fish, pin, threadform, tool joint

break out

1. vb. [Drilling] To unscrew drillstring components, which are coupled by various threadforms known as connections, including tool joints and other threaded connections. See: back off, box, connection, pin, threadform, tool joint

erode

1. vb. [Geology] To cause or undergo erosion, the process of denudation of rocks, including physical, chemical and biological breakdown and transportation. The material from the rocks can be transported by wind, water, ice, or abrasive solid particles, or by mass-wasting, as in rock falls and landslides. See: detrital, nonconformity, sequence boundary, unconformity, weathering

log

1. vb. [Reservoir Characterization, Formation Evaluation, Drilling] To continuously measure formation properties with electrically powered instruments to infer properties and make decisions about drilling and production operations. The record of the measurements, typically a long strip of paper, is also called a log. Measurements include electrical properties (resistivity and conductivity at various frequencies), sonic properties, active and passive nuclear measurements, dimensional measurements of the wellbore, formation fluid sampling, formation pressure measurement, wireline-conveyed sidewall coring tools, and others. For wireline measurements, the logging tool (or sonde) is lowered into the open wellbore on a multiple conductor, contra-helically armored wireline cable. Once the tool string (link to ID 2964) has reached the bottom of the interval of interest, measurements are taken on the way out of the wellbore. This is done in an attempt to maintain tension on the cable (which stretches) as constant as possible for depth correlation purposes. (The exception to this practice is in certain hostile environments in which the tool electronics might not survive the downhole temperatures for long enough to allow the tool to be lowered to the bottom of the hole and measurements to be recorded while pulling the tool up the hole. In this case, "down log" measurements might be conducted on the way into the well, and repeated on the way out if possible.) Most wireline measurements are recorded continuously while the sonde is moving. Certain fluid sampling and pressure-measuring tools require that the sonde be stopped, increasing the chance that the sonde or the cable might become stuck. Logging while drilling (LWD) tools take measurements in much the same way as wireline-logging tools, except that the measurements are taken by a self-contained tool near the bottom of the bottomhole assembly and are recorded downward (as the well is deepened) rather than upward from the bottom of the hole. See: hostile environment, wireline log

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