Oil and Gas Terms Beginning with “M”

A test to determine the amount of clay-like materials in a water-base drilling fluid based on the amount of methylene blue dye absorbed by the sample. Results are reported as "MBT" and also as "lbm/bbl, bentonite equivalent" when performed to API specifications.

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.

A compound containing hydroxide anions in association with two or more metal cations. MMH particles are extremely small and carry multiple positive charges. They can associate with bentonite to form a strong complex that exhibits highly shear-thinning properties, with high and fragile gel strengths, high yield point (YP), and low plastic viscosity (PV). MMH is described as a mixed-metal layered hydroxide (MMLH). In the crystal layers, Al+3 , Mg+2 and OH- ions reside, but due to symmetry considerations, there is not enough room for sufficient OH- ions to electrically offset the charges of the two cations. Therefore, a net positive charge exists on the crystal surfaces. Exchangeable anions sit on the positive surface (much the same as cations sit on negative clay surfaces). MMH muds are used as nondamaging drilling fluids, metal-reaming fluids (to carry out metal cuttings) and for wellbore shale control. Being cationic, MMH mud is sensitive to anionic deflocculants and small anionic polymers, such as polyphosphates, lignosulfonate or lignite.Reference:Burba JL III and Crabb CR: "Laboratory and Field Evaluation of Novel Inorganic Drilling Fluid Additive," paper IADC/SPE 17198, presented at the IADC/SPE Drilling Conference, Dallas, Texas, USA, February 28-March 2, 1988.Fraser L and Enriquez F: "Mixed-Metal Hydroxides Fluid Research Widens Applications," Petroleum Engineer International 64, no. 6 (June 1992): 43-46.

A product similar to mixed-metal hydroxide, but based on silicate chemistry

Abbreviation for million standard cubic feet, a common measure for volume of gas. Standard conditions are normally set at 60oF and 14.7 psia.

A generic term for several classes of self-contained floatable or floating drilling machines such as jackups, semisubmersibles, and submersibles.

(noun) Abbreviation for Magnetic Reversal Sequence. A chronostratigraphic tool based on the record of periodic reversals in the Earth's magnetic field preserved in sedimentary and volcanic rocks, used in biostratigraphy and basin analysis to date and correlate formations across wells and outcrop sections.

A specific document that shows important physical and chemical characteristics of a chemical or product to alert a user, transporter or other interested party to potential safety hazards that may be associated with the material. The MSDS also contains treatments for exposure or ingestion as well as the type of equipment needed for safe handling. An MSDS is a legal requirement in most countries for all aspects of commerce involving chemicals.

An electromagnetic method used to map the spatial variation of the Earth's resistivity by measuring naturally occurring electric and magnetic fields at the Earth's surface. These natural EM fields are generated (at all frequencies) in the Earth's atmosphere mainly by lightning strokes and by interactions between the solar wind and the ionosphere. In the most general MT method, the horizontal components of the electric field and all three components of the magnetic field are measured at the surface. The measurements are used to determine specific ratios of electric to magnetic field components called tensor impedances. The technique was introduced the French geophysicist Louis Cagniard in the 1950s and has been popular for mineralexploration and regional geophysical mapping. It is used in oil exploration for low-cost reconnaissance of sedimentary basins and for exploration in areas where seismic surveys are difficult because of severe topography or the presence high-impedancevolcanic rocks near the surface. The resolution of MT surveys is limited by the diffusive nature of EM propagation in the earth; it is usually on the order of hundreds of meters to kilometers. But the MT method can probe the Earth to depths of several tens of kilometers.

What Is Measurement While Drilling (MWD)? Measurement while drilling (MWD) describes the downhole instrumentation and surface telemetry system that transmits real-time wellbore survey data, including inclination, azimuth, and toolface orientation, along with drilling mechanics parameters such as weight on bit, torque, and rotary speed, to the surface while drilling operations continue uninterrupted, enabling the directional driller and company man to steer the well and optimise drilling performance without pulling the string. MWD tools are integrated into the bottom hole assembly and communicate with surface through mud-pulse, electromagnetic, or wired-pipe telemetry channels, feeding real-time data to directional drilling software and enabling LWD formation evaluation data to be transmitted simultaneously. Key Takeaways MWD delivers continuous wellbore survey stations every 10 to 30 m (33 to 98 ft) of drilled depth, allowing directional drillers to maintain trajectory within a tolerance of plus or minus 0.1 degrees inclination and plus or minus 0.5 degrees azimuth under ISCWSA Revision 4 error models. Mud-pulse telemetry systems transmit data at 1 to 12 bits per second (bps), while wired drill pipe systems achieve 57,600 bps, more than 4,000 times the speed of mud pulse, enabling transmission of full LWD image logs in real time. Operators, directional drilling service companies (SLB, Halliburton, Baker Hughes, NOV), and well-site geologists all rely on MWD data for real-time decision making during every directional well worldwide. Survey accuracy standards are governed by the ISCWSA (Industry Steering Committee on Wellbore Survey Accuracy) error model framework, which feeds into collision avoidance calculations required by the AER, BSEE, Sodir, and NOPSEMA. MWD reduces drilling cost per metre by eliminating the need for survey wireline runs, cuts non-productive time by enabling rapid directional corrections, and underpins geosteering decisions that maximise hydrocarbon contact. How Measurement While Drilling Works An MWD system consists of three integrated subsystems: the downhole sensor package, the telemetry transmitter, and the surface signal processing and decoding unit. The downhole sensor package contains a triaxial accelerometer set that measures gravitational components along three orthogonal axes to determine wellbore inclination, and a triaxial magnetometer set that measures the Earth's magnetic field vector to calculate azimuth. Together, these six sensors produce a three-dimensional survey station at each measurement point, allowing the driller to calculate the wellbore's three-dimensional position relative to the wellhead using minimum curvature, radius of curvature, or balanced tangential calculation methods as defined in API Recommended Practice 11V9 and SPE paper 84246. Mud-pulse telemetry, used in approximately 85 percent of all MWD operations globally, encodes digital survey and drilling mechanics data as pressure pulses superimposed on the circulating drilling fluid column. Positive pulse systems briefly obstruct the mud flow path with a valve to create a pressure spike; negative pulse systems vent a small volume of mud to the annulus to create a pressure drop; continuous wave systems use a rotating valve to generate a sinusoidal carrier wave that is frequency-modulated with the data signal. Surface transducers, typically mounted on the standpipe manifold, detect these pressure variations at 0.007 to 0.070 MPa (1 to 10 psi) amplitude and feed them to surface processing units that decode the signal using proprietary algorithms. Noise from the rig pumps, drill string vibration, and reflections from pipe connections all degrade the signal, requiring sophisticated filtering and error-correction coding in the surface decoders. Electromagnetic (EM) telemetry transmits data as extremely low-frequency electromagnetic signals through the earth and formation from a downhole antenna to surface receivers. EM telemetry operates independently of drilling fluid circulation, making it the preferred choice for air drilling, foam drilling, or underbalanced drilling operations where mud pulse cannot function. EM range is limited by formation resistivity: conductive salt formations or high-salinity brines attenuate the signal rapidly, restricting EM telemetry to depths of typically 3,000 m (9,843 ft) in most geological settings, though recent antenna and amplifier improvements have extended this to 5,000 m (16,400 ft) in resistive carbonates. Wired drill pipe (WDP) technology, commercialised by NOV's IntelliServ network and now offered by multiple vendors, transmits data at broadband speeds through inductive couplers embedded in every pipe connection, delivering 57,600 bps bandwidth that enables real-time transmission of full LWD waveforms, borehole images, and acoustic logs. MWD Across International Jurisdictions Canada: The Alberta Energy Regulator Directive 059 requires that all directional wells submit a final wellbore survey report validated against an independent survey quality check before the well is released. Most Alberta operators use MWD-based minimum curvature surveys as the primary survey, supplemented by a gyroscopic survey run in the production casing to provide a magnetically independent verification of the final trajectory, particularly in multi-well pad environments where magnetic interference between adjacent wells is a significant concern. The Montney and Duvernay plays in northwest Alberta and northeast BC produce MWD datasets of exceptional density: a typical 4,000 m (13,123 ft) lateral will contain 150 to 200 survey stations, each validated against the ISCWSA Revision 4 error ellipse model. United States: BSEE regulations under 30 CFR Part 250.423 require directional survey programs to be submitted with the Application for Permit to Drill and that all deviation surveys include the wellbore depth, inclination, and azimuth at each survey station. In the Permian Basin's Delaware and Midland sub-basins, MWD data is used not only for wellbore placement but for real-time formation top correlation against offset wells, enabling drillers to adjust the landing point mid-well if seismic or geological prognosis differs from actual penetrated tops. The Eagle Ford and Haynesville plays in the Gulf Coast similarly rely on azimuthal gamma ray MWD to identify the precise stratigraphic position of the lateral within the target zone. Norway and the North Sea: Sodir (formerly NPD) requires that all wells on the Norwegian Continental Shelf submit a final wellbore survey accuracy report citing the ISCWSA error model used and the resultant positional uncertainty ellipse at each survey station. The North Sea's high magnetic inclination, roughly 73 degrees in the central North Sea, severely reduces the sensitivity of magnetic azimuth measurements, making it the most challenging global region for MWD survey accuracy. Operators including Equinor, Aker BP, and TotalEnergies North Sea routinely deploy gyroscopic MWD tools as the primary survey instrument in the vertical and upper build sections of wells where magnetic interference from adjacent infrastructure, dense well clusters on platforms, and the high magnetic inclination make magnetic MWD azimuth uncertainty unacceptably large for collision avoidance. Middle East: Saudi Aramco's Drilling Engineering Standards require MWD survey programs to meet the ISCWSA Revision 4 error model with a positional uncertainty of less than 0.2 percent of measured depth at all points in the wellbore. In dense well clusters on the Ghawar, Safaniyah, and Abqaiq fields, Aramco additionally requires an anti-collision rule of a separation factor (SF) greater than 1.5 times the combined positional uncertainty of the subject and offset wells, which drives the selection of high-accuracy gyroscopic survey tools at specific intervals in every well. ADNOC applies similar standards across the Abu Dhabi onshore fields and the offshore Zakum and Umm Shaif fields. Fast Facts The first commercial mud-pulse MWD system was deployed in 1978 by Teledyne Exploration Company. By 2024, the global MWD/LWD services market exceeded USD 7.4 billion annually, with mud-pulse telemetry remaining the dominant transmission technology at over 85 percent market share. Wired drill pipe systems now achieve data rates of 57,600 bps, compared to the 1 to 4 bps of early commercial mud pulse systems in the 1980s, a 14,000-fold improvement in bandwidth over 40 years. MWD Tool Types and Telemetry Specifications Commercial MWD systems span three telemetry architectures, each optimised for different wellbore environments and data bandwidth requirements. Positive Pulse MWD: The most widely deployed MWD telemetry type globally. A spring-loaded valve inside the MWD pulser collar intermittently restricts flow through the bore, generating positive pressure spikes of 0.034 to 0.207 MPa (5 to 30 psi) at the surface standpipe. SLB's PowerPulse MWD, introduced in 1995 and now in its fourth commercial generation, and Halliburton's CIMMCO MWD (later rebranded as the iStar platform) are the two dominant positive-pulse platforms globally. Data rates range from 1 to 12 bps depending on flow rate, mud weight, mud rheology, standpipe length, and the signal-to-noise ratio at surface. Higher flow rates improve pulse propagation but require the pulser valve to work against greater differential pressure, shortening valve seal life. Negative Pulse MWD: A solenoid-operated valve vents a small volume of drilling fluid from the drill string bore to the annulus, generating a momentary pressure drop at the surface standpipe. Negative pulse systems are mechanically simpler than positive pulse but generate weaker signals, typically 0.014 to 0.070 MPa (2 to 10 psi), and are more susceptible to noise from pump pulsations. Baker Hughes' OnTrak MWD platform uses negative pulse as its primary telemetry in its legacy tool lineup. Negative pulse is less common in HPHT environments where differential pressure across the vent valve can exceed the valve's rated capability. Continuous Wave (CW) MWD: A turbine-driven rotating disc valve generates a continuous sinusoidal carrier wave in the mud column, modulated with data using frequency-shift keying (FSK) or phase-shift keying (PSK) encoding. CW systems offer superior data rates, up to 20 to 40 bps, and better noise rejection than positive or negative pulse, because the surface decoding system can use frequency-domain filtering to isolate the carrier signal from pump noise. Schlumberger's PowerDrive Orbit RSS integrates CW telemetry as a native feature of the steering system, enabling simultaneous data-while-drilling from the RSS position sensors and the MWD survey sensors at combined rates up to 12 bps. Survey Accuracy and Error Models: MWD survey accuracy is quantified using the ISCWSA (Industry Steering Committee on Wellbore Survey Accuracy) error model, which assigns uncertainty coefficients to each error source: accelerometer bias and scale factor, magnetometer bias and scale factor, magnetic declination uncertainty, drill string magnetic interference, wellbore misalignment, and depth measurement error. The RSS error model (Revision 4, 2015) is the current industry standard and is required by most national regulators. Surveys are classified by quality indicator (QI) values, with QI less than 1.0 indicating the survey passed all internal consistency checks. High-accuracy tools, including gyroscopic survey tools and continuous gyroscopic MWD tools such as APS Technology's SureShot or Baker Hughes' GyroTrak, reduce positional uncertainty by 60 to 80 percent compared to standard magnetic MWD tools, enabling tighter anti-collision windows in dense well fields. Tip: When evaluating a drilling contractor's MWD program, ask specifically whether they plan to run a gyroscopic survey in the casing or open hole at the kick-off point. A magnetic-only survey in a dense multi-well pad can carry positional uncertainty of 8 to 15 m (26 to 49 ft) at 3,000 m (9,843 ft) depth, which may be insufficient for the anti-collision separation factor required by the regulatory body. Adding a single gyroscopic survey run reduces that uncertainty to 1 to 3 m (3 to 10 ft) and can be the difference between a permitted and a rejected well plan.

Abbreviation for millions of years before present. The preferred abbreviation is Ma.

Mega annum. The abbreviation for million years that is most commonly used in the geologic literature.

What Is a Marsh Funnel? A Marsh funnel is a standardized conical field viscometer that drilling crews use worldwide to measure the apparent viscosity of drilling fluid by recording the time, in seconds, for one quart (946 mL) of mud to drain through a calibrated orifice under gravity. The test takes less than two minutes, requires no power source, and gives mud engineers an immediate, comparable viscosity reading that guides real-time fluid management at the wellsite. Key Takeaways The Marsh funnel measures funnel viscosity as the time in seconds for one quart (946 mL) of mud to flow through a 3/16-inch (4.76 mm) orifice; fresh water exits in approximately 26 seconds at 70°F (21°C). API Recommended Practice 13B-1 governs the test procedure for water-base muds; API RP 13B-2 covers oil-base and synthetic-base drilling fluids. Funnel viscosity reflects apparent viscosity at a single, relatively high shear rate and cannot separately quantify plastic viscosity or yield point, which require a Fann rotational viscometer. Drillers compare mud-in and mud-out funnel viscosity readings throughout each tour to detect gas influx, formation cuttings loading, barite sag, and chemical treatment effects before those problems escalate. Hallan N. Marsh introduced the instrument in a 1931 American Institute of Mining Engineers paper; it remains the most widely used single mud-quality check in global drilling operations nearly a century later. How the Marsh Funnel Works The instrument itself is a seamless cone 12 inches (305 mm) tall with a 6-inch (152 mm) diameter opening at the top. A stainless-steel screen with 1/16-inch (1.59 mm) openings sits across the inlet to stop large cuttings or lost-circulation material from plugging the orifice tube. The tube at the base has an inside diameter of 3/16 inch (4.76 mm) and a length of 2 inches (50.8 mm). The funnel holds approximately 1.5 quarts (1.42 L) in total, but the test measures only the first quart (946 mL) collected in a graduated mud cup held at the outlet. To run the test, the mud engineer covers the orifice with a finger, fills the funnel through the screen to the 1.5-quart mark, and then releases the finger while simultaneously starting a stopwatch. The reading is taken when the mud level in the graduated cup reaches the one-quart (946 mL) mark. Results are reported in seconds per quart and are temperature-sensitive: fresh water measures approximately 26 seconds at 70°F (21°C) and roughly 24 seconds at 120°F (49°C). Because elevated temperature reduces fluid viscosity, API RP 13B-1 recommends recording ambient temperature alongside every funnel viscosity result so readings from different wellsites or depths can be compared meaningfully. Typical ranges vary with fluid type and mud weight. Unweighted water-base muds used for surface hole sections commonly read 28 to 45 seconds. Weighted muds carrying barite to 14 lb/gal (1.68 kg/L) or higher often read 55 to 80 seconds, sometimes exceeding 100 seconds in high-density brines. Oil-base and synthetic-base muds used in extended-reach wells and high-pressure, high-temperature environments typically target 40 to 70 seconds depending on operator program requirements. Any step change of more than 5 to 10 seconds between successive readings — particularly an increase in mud-out versus mud-in — signals a change in the fluid system that warrants investigation before the next connection. Marsh Funnel Across International Jurisdictions Although the instrument and the API testing protocol are globally recognized, regulatory bodies in different regions embed Marsh funnel requirements into their own well-control and drilling program frameworks with varying levels of specificity. Canada (Alberta and British Columbia): The Alberta Energy Regulator (AER) Directive 036 and the BC Energy Regulator (BCER) well-control requirements mandate that operators maintain a drilling program specifying fluid properties, including viscosity ranges, for each hole section. In the Montney tight-gas play, where operators drill with water-base muds at densities of 8.6 to 10.5 lb/gal (1.03 to 1.26 kg/L), wellsite geologists and mud engineers record funnel viscosity alongside pit volume, mud weight, and temperature every 30 minutes during drilling ahead and at every connection. AER inspectors review mud logs and trip sheets for documented funnel viscosity trends as part of post-well compliance checks. United States: The Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Land Management (BLM) do not prescribe a specific funnel viscosity interval in federal regulations, but operator drilling programs submitted to BSEE under 30 CFR Part 250 for offshore wells must include fluid specifications. In practice, service company mud programs for Permian Basin, Eagle Ford, and Marcellus shale wells specify funnel viscosity tests every 30 minutes while drilling and at each bit run as the primary field QC gate. Mud engineers working for major operators such as ExxonMobil, Chevron, and ConocoPhillips treat the Marsh funnel reading as the first-pass quality indicator before committing to Fann viscometer analysis. Australia: The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates offshore drilling under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. NOPSEMA accepts drilling safety cases that incorporate API RP 13B-1 and RP 13B-2 as the controlling standards for mud testing frequency and documentation. Onshore regulators in Western Australia (Department of Energy, Mines, Industry Regulation and Safety, DEMIRS) and the Northern Territory similarly reference API standards for unconventional gas programs in the Beetaloo and Perth Basins. Norway and the North Sea: Equinor's well engineering standards and Sodir (formerly NPD) well data submission requirements specify that mud properties, including funnel viscosity, be recorded and reported for each wellbore section. The NORSOK D-010 standard for well integrity management references API RP 13B-1 for fluid testing. Offshore drilling contractors operating on the Norwegian Continental Shelf typically run the Marsh funnel test every 30 minutes during normal drilling and report daily mud checks to the operator's drilling supervisor and to Sodir's Diskos well-data database at well completion. Saudi Arabia and the Middle East: Saudi Aramco Drilling Engineering Standard DES-10 and its associated drilling-fluid specifications require Marsh funnel viscosity to be measured at surface and at the sand trap (mud return) no less than once per hour during drilling operations. Operators drilling in Abu Dhabi under ADNOC directives and in Kuwait under the Kuwait Oil Company (KOC) well engineering framework follow similar hourly testing intervals. The consistently high formation temperatures encountered in the Arabian Peninsula, often exceeding 300°F (149°C) at total depth, make temperature correction particularly critical when comparing field Marsh funnel readings against laboratory baseline values. Fast Facts A Marsh funnel costs roughly USD $40 to $60 and weighs less than 1 lb (0.45 kg), yet it guides fluid decisions on wells that may cost $10 million to $50 million or more to drill. Across the global drilling industry, hundreds of thousands of Marsh funnel readings are recorded every day, making it the single most frequently executed quantitative test in oilfield mud engineering. Marsh Funnel Viscosity versus Full Rheology: Knowing the Difference The Marsh funnel produces what the industry calls funnel viscosity, expressed simply as "seconds per quart." This value corresponds to an apparent viscosity at a single, moderately high shear rate determined by the fixed geometry of the orifice. At 26 seconds for water, the effective shear rate through the orifice is approximately 800 to 1,000 reciprocal seconds, placing funnel viscosity in the upper range of the shear rates experienced in the annulus of a typical rotary-drilled well. Because the Marsh funnel collapses all rheological complexity into one number, it cannot distinguish between the two independent variables that dominate mud rheology under the Bingham Plastic model: plastic viscosity (PV) and yield point (YP). Plastic viscosity, measured in centipoise (cP) or milliPascal-seconds (mPa-s), governs viscosity at high shear rates and is primarily controlled by solids content, solids type, and base fluid viscosity. Yield point, measured in lb/100 ft2 or Pascals, governs the gel-like resistance to flow at low and zero shear rates and is primarily controlled by electrochemical interactions between clay particles and fluid additives. A mud with high PV and low YP can produce the same funnel viscosity as a mud with low PV and high YP, yet the two fluids behave very differently in the annulus with respect to cuttings transport, equivalent circulating density, and surge and swab pressures. Proper rheological characterization requires a Fann VG meter (rotational viscometer), typically a Model 35 or equivalent, operated at six standard speeds: 600, 300, 200, 100, 6, and 3 RPM. From these readings, mud engineers calculate PV, YP, low-shear yield point (LSYP), and 10-second and 10-minute gel strengths. The API filtration test (HPHT and low-pressure) measures fluid-loss control and filter-cake quality. Chloride content, pH, alkalinity, and methylene blue test (MBT) for bentonite equivalent complete the standard API mud check. The Marsh funnel is not a substitute for this suite; rather, it is the rapid field sentinel that tells the mud engineer whether a full rheology run is urgently needed. One practical rule of thumb widely used in North American shale plays: if the mud-out funnel viscosity increases by more than 8 seconds compared to mud-in without a corresponding deliberate chemical treatment, the mud engineer runs a full Fann analysis and checks pit volumes for possible formation fluid influx or solids loading from reactive shales. Conversely, a drop of more than 5 seconds may indicate dilution by formation water or an incompatible brine, which could signal an early kick warning condition requiring the driller and company man to evaluate well control status. Marsh Funnel in Drilling Fluid Program Design Drilling engineers specify target funnel viscosity ranges in the well's drilling program for each hole section. These ranges are not arbitrary: they balance competing hole-cleaning and well-control requirements. A funnel viscosity that is too low (below 28 to 30 seconds for a water-base mud) suggests insufficient gel structure to suspend barite and cuttings when circulation is stopped for a connection or a survey, increasing the risk of barite sag that can cause differential sticking or an unplanned kick due to the localized density reduction. A funnel viscosity that is too high (above 90 to 100 seconds for most non-deviated wells) increases equivalent circulating density (ECD), raises the risk of lost circulation in depleted or fractured formations, and adds hydraulic horsepower requirements at the surface pumps. Directional and extended-reach wells introduce additional complexity. High-angle wellbores, including those characteristic of Montney horizontal wells in British Columbia or Permian horizontal wells in West Texas, require higher annular velocities and rheological properties to keep cuttings beds from forming on the low side of the wellbore. In these applications, mud engineers may target funnel viscosities at the higher end of the acceptable range and supplement with periodic high-viscosity pills (funnel viscosity 120 to 180 seconds) pumped at high flow rates to mechanically sweep accumulated cuttings beds. The Marsh funnel provides a fast check that the high-viscosity pill has been mixed to specification before it is committed downhole past the drill floor. Field Tip: Always hold the graduated mud cup firmly against the funnel orifice before releasing your finger from the tube. Any gap between the orifice and the cup allows mud to splash outside the cup and causes a falsely short reading. On cold mornings in northern Alberta or North Dakota, warm the funnel and the sample to approximately 70°F (21°C) in the mud lab before testing, or record the actual sample temperature so the reading can be temperature-corrected using the published API correction tables. A reading at 50°F (10°C) can be 3 to 5 seconds longer than the same mud tested at standard temperature.

A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that rotating motion can be transmitted to the kelly.

A specific document that shows important physical and chemical characteristics of a chemical or product to alert a user, transporter or other interested party to potential safety hazards that may be associated with the material. The MSDS also contains treatments for exposure or ingestion as well as the type of equipment needed for safe handling. An MSDS is a legal requirement in most countries for all aspects of commerce involving chemicals.

A group of four partial differential equations that describe all classical phenomena, involving electric and magnetic fields. James Clerk Maxwell (1831 to 1879), a British physicist, first wrote out this complete set of equations:Equation (1) is equivalent to Coulomb's law, the inverse square attraction of static electric charges. Equation (2) is Ampere's law relating magnetic fields and currents, which was extended by Maxwell to include induction of a magnetic field by a time-varying electric displacement. Equation (3) is Coulomb's law for magnetic flux, expressing the absence of isolated magnetic charges. Equation (4) is Faraday's law of induction, relating an electric field to a time-varying magnetic flux. Maxwell's equations are the starting point for all calculations involving surface or borehole EM methods.

A drilling rig in which the source of power is diesel engines and the power is distributed through mechanical devices including chains, sprockets, clutches, and shafts.

The variation of the Earth's exposure to the sun's rays, or insolation, that results from variations in the orbit of the Earth and the tilt of its axis, and that might affect climate, sea level and sedimentation. Such variations are thought to occur in distinct time periods on the order of thousands of years. Ice ages might be a consequence of Milankovitch cycles. Milutin Milankovitch (1879 to 1958) was a Yugoslavian mathematician and physicist who specialized in studies of solar radiation and the orbit of the Earth.

A branch of the US Lands and Mineral Management Department that supervises national resources. MMS has oversight of oil and gas leasing, royalty collection and other operations in US-owned areas. It closely monitors operations in Federal waters, oversees leasing of acreage, issues drilling permits and monitors operators for permit violations.

The boundary between the crust and the mantle of the Earth, which varies from approximately 5 km [3 miles] under the midoceanic ridges to 75 km [46 miles] deep under the continents. This boundary, commonly called "the Moho," was recognized in 1909 by Croatian seismologist Andrija Mohorovicic on the basis of its abruptly higher compressional wave (P-wave) velocity.

The boundary between the crust and the mantle of the Earth, which varies from approximately 5 km [3 miles] under the midoceanic ridges to 75 km [46 miles] deep under the continents. This boundary, commonly called "the Moho," was recognized in 1909 by Croatian seismologist Andrija Mohorovicic on the basis of its abruptly higher compressional wave (P-wave) velocity.

An approach to performing risk analysis on any project with uncertain input data. Generally, numbers are selected from representative input data and then used in iterative, CPU-intensive calculations to find the most likely outcome and the range of probable outcomes. The uncertainty in the output also provides a measure of the validity of the model. The technique is applied to financial investment portfolio and investment risk analysis as well as scientific applications.Monte Carlo analysis methods are used in the oil field to estimate the risks involved in new exploration projects, evaluation of development schemes and evaluation of validity of reservoir models.

The sampling of uncertain data for use in Monte Carlo risk analysis or simulation.

The use of Monte Carlo risk analysis techniques to estimate the most probable outcomes from a model with uncertain input data and to estimate the validity of the simulated model.

Abbreviation for a thousand standard cubic feet per day, a common measure for volume of gas. Standard conditions are normally set at 60oF and 14.7 psia.

A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig. A typical mud pump is a two- or three-cylinder piston pump.

Open steel tanks used for holding drilling fluids. Some tanks are used for suction to mud pumps, settling of sediments, and storage of reserve mud.

A device that removes gas from the mud coming out of a well when a kick is being circulated out.

A marineseismic data acquisition method in which a conventional narrow-azimuth towed-streamer configuration is used to acquire data over a survey area in more than one direction. The number of directions is typically three or more. The azimuthal range for a multiazimuth survey is not continuous in azimuth, but is well sampled along the shooting directions.

Abbreviation for million years. The preferred abbreviation is Ma.

Pertaining to minerals or igneous rocks composed of minerals that are rich in iron and magnesium, dense, and typically dark in color. The term comes from the words magnesium and ferric. Common mafic minerals are olivine and pyroxene. Basalt is a mafic igneous rock. (Compare with felsic.)

The molten rock in the Earth that can either rise to the surface as lava and form extrusive igneous rock or cool within the Earth to form plutonic igneous rock.

A procedure for determining magnesium ion (Mg+2) concentration in a water-base drilling fluid based upon analyses for both calcium and total hardness. The standard test has been proscribed by API. Magnesium ion (Mg+2) concentration is calculated by subtracting calcium (Ca+2) analysis results from total hardness analysis results.

A drilling mud with a significant magnetic susceptibility. The magnetic susceptibility may affect the response of some logging measurements, mainly the induction X signal and nuclear magnetic resonance logs. The most common magnetic muds contain iron filings or magnetite. Other paramagnetic minerals such as hematite and ilmenite may contribute, although their magnetic susceptibility is considerably less.

A phenomenon by which a nucleus absorbs electromagnetic radiation of a specific frequency in the presence of a strong magnetic field. Isidor Isaac Rabi (1898 to 1988), an American physicist born in Austria, first detected magnetic resonance in 1938. Since then, magnetic resonance has been applied to the detection of light atoms (such as hydrogen in hydrocarbons) and as a nondestructive way to study the human body.

(noun) A non-destructive inspection technique used to detect corrosion, pitting, and metal loss in ferromagnetic tubulars and pipelines. The method works by magnetising the pipe wall and measuring distortions in the magnetic field caused by variations in wall thickness, enabling identification of internal and external defects without removing the pipe from service.

The study of the Earth's magnetic field, a branch of geophysics that began with the observation by British scientist William Gilbert (1544 to 1603) that the Earth is a magnet. Variations in the magnetic field can be used to determine the extent of sedimentary basins and the depth to basement rocks, as well as to differentiate between igneous rocks and certain sedimentary rocks such as salt. High-resolution magnetic surveys can also be used to determine the locations of oil pipelines and production equipment.

An instrument used to measure the strength or direction of the Earth's magnetic field.

An electromagnetic method used to map the spatial variation of the Earth's resistivity by measuring naturally occurring electric and magnetic fields at the Earth's surface. These natural EM fields are generated (at all frequencies) in the Earth's atmosphere mainly by lightning strokes and by interactions between the solar wind and the ionosphere. In the most general MT method, the horizontal components of the electric field and all three components of the magnetic field are measured at the surface. The measurements are used to determine specific ratios of electric to magnetic field components called tensor impedances. The technique was introduced the French geophysicist Louis Cagniard in the 1950s and has been popular for mineralexploration and regional geophysical mapping. It is used in oil exploration for low-cost reconnaissance of sedimentary basins and for exploration in areas where seismic surveys are difficult because of severe topography or the presence high-impedancevolcanic rocks near the surface. The resolution of MT surveys is limited by the diffusive nature of EM propagation in the earth; it is usually on the order of hundreds of meters to kilometers. But the MT method can probe the Earth to depths of several tens of kilometers.

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.

To deepen a wellbore with the drill bit. To drill ahead.

To connect tools or tubulars by assembling the threaded connections incorporated at either end of every tool and tubular. The threaded tool joints must be correctly identified and then torqued to the correct value to ensure a secure tool string without damaging the tool or tubular body.

Water added to a maintain or dilute a water-mud system. The added water may be fresh water, seawater or salt water, as appropriate for the mud. Make-up water volume is an important parameter in a material balance check on solids content and solids removal efficiency for a mud system. The amount of dilution strongly influences mud economics. If soft make-up water is needed, treatments to remove hardness ions should be done prior to adding the water to the mud to avoid clayflocculation and polymerprecipitation.

Water added to a maintain or dilute a water-mud system. The added water may be fresh water, seawater or salt water, as appropriate for the mud. Make-up water volume is an important parameter in a material balance check on solids content and solids removal efficiency for a mud system. The amount of dilution strongly influences mud economics. If soft make-up water is needed, treatments to remove hardness ions should be done prior to adding the water to the mud to avoid clayflocculation and polymerprecipitation.

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.

Gas injected into a gas-condensatereservoir to maintain the pressure level, thus preventing further condensate dropout.

(noun) Large hydraulic or manual wrenches used on a drilling rig to apply torque to threaded connections when assembling (making up) joints of drillpipe, casing, or tubing. Makeup tongs grip the pipe body or coupling and apply controlled rotational force to achieve the specified connection torque.

A bar, shaft or spindle around which other components are arranged or assembled. The term has been extended in oil and gas well terminology to include specialized tubular components that are key parts of an assembly or system, such as gas-lift mandrel or packer mandrel.

An arrangement of piping or valves designed to control, distribute and often monitor fluid flow. Manifolds are often configured for specific functions, such as a choke manifold used in well-control operations and a squeeze manifold used in squeeze-cementing work. In each case, the functional requirements of the operation have been addressed in the configuration of the manifold and the degree of control and instrumentation required.

The intermediate layer of the Earth beneath the crust that is about 2900 km thick [1820 miles] and overlies the core of the Earth. The mantle consists of dense igneous rocks like pyroxenite and dunite, composed of the minerals pyroxene and olivine. The crust, mantle and core of the Earth are distinguished from the lithosphere and asthenosphere on the basis of their composition and not their mechanical behavior. The Mohorovicic discontinuity abruptly separates the crust from the mantle, where the velocity of compressional waves is significantly higher.

A representation, on a plane surface and at an established scale, of the physical features of a part or whole of the Earth's surface or of any desired surface or subsurface data, by means of signs and symbols, and with the means of orientation indicated. Reservoirs are often represented by a series of maps for each of the layers distinguished within the reservoir. This series of maps may include maps of structure, gross thickness, net thickness, porosity, water saturation and other required petrophysical characteristics. A complete set of petrophysical characteristic maps may constitute a reservoir description, reservoir characterization or reservoir model.

A well that, for reasons of depletion or natural low productivity, is nearing the limits of viable production and profitability.

Pertaining to sediments or environments in seas or ocean waters, between the depth of low tide and the ocean bottom.

(noun) A stratigraphic surface that records a significant increase in water depth across a sedimentary basin, marking a transgressive event in which marine conditions advance landward over previously non-marine or shallower-water deposits. Marine flooding surfaces are key sequence stratigraphic boundaries used in correlating subsurface formations.

A widespread distinctive rock unit that can be correlated readily over a large area. The most useful marker beds tend to form rapidly, such as during volcanic or geologically instantaneous depositional events, and have unusual seismic, magnetic, electrical or other physical properties that aid geological or geophysical interpretation. Coal beds and volcanic ash falls are examples of marker beds.

A joint of tubing used in a workover or completion tubing string that serves as a position or depth indicator. In most cases, a marker joint is significantly shorter than other joints in the string so that it is easily noticeable on correlation logs or when retrieving a work string, such as on a snubbing or hydraulic workover unit.

An agreement by which a party sells production on behalf of a producing company and then remits the proceeds, minus agreed-upon costs and expenses, to the producing company.

An environment from which water rarely drains that supports primarily grassy vegetation and does not form peat.

A block of rock that forms a structural or topographic feature, such as a block of igneous of metamorphic rock within an area of mountain building, or orogeny. A massif can be as large as a mountain and is typically more rigid than the rocks that surround it.

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.

A well-servicing unit for slickline, wireline or coiled tubing operations that is equipped with a mast rather than a crane or gin pole. The mast provides a means of lifting and stabilizing tools, and running pressure-control and other equipment.

A valve located on the Christmas tree that controls all flow from the wellbore. A correctly functioning master valve is so important that two master valves are fitted to most Christmas trees. The upper master valve is used on a routine basis, with the lower master valve providing backup or contingency function in the event that the normal service valve is leaking and needs replacement.

An expression for conservation of mass governed by the observation that the amount of mass leaving a control volume is equal to the amount of mass entering the volume minus the amount of mass accumulated in the volume. Through material balance, reservoir pressures measured over time can be used to estimate the volume of hydrocarbons in place.

Mathematical relationship between the densities and the corresponding volumes of mixtures of liquid-solid slurries and clear fluid blends, such as drilling muds and completion fluids. Assumptions are: (1) masses and volumes of components are additive and (2) material is neither generated nor lost from the system. As a simple example, below are the two material-balance equations for a three-component mixture of oil (o), water (w) and solids (s), where V = volume percent, D = specific density and MW = mixture weight. (This could represent a simple, weighted oil-base mud formulation.)MW = DsVs + DoVo + DwVw100% = Vs + Vo + Vw.By solving these equations simultaneously, an unknown parameter can be found if other parameters are known or can be estimated accurately. Material-balance equations are used to derive formulations of muds, to calculate the amount of barite needed to weight-up a mud, to determine the amount of water needed to dilute a mud, and to find the volume of two or more muds to mix together to achieve a new mud weight and volume. Material balance is also the basis for calculating solids content of muds based on mud testing data.

Mathematical relationship between the densities and the corresponding volumes of mixtures of liquid-solid slurries and clear fluid blends, such as drilling muds and completion fluids. Assumptions are: (1) masses and volumes of components are additive and (2) material is neither generated nor lost from the system. As a simple example, below are the two material-balance equations for a three-component mixture of oil (o), water (w) and solids (s), where V = volume percent, D = specific density and MW = mixture weight. (This could represent a simple, weighted oil-base mud formulation.)MW = DsVs + DoVo + DwVw100% = Vs + Vo + Vw.By solving these equations simultaneously, an unknown parameter can be found if other parameters are known or can be estimated accurately. Material-balance equations are used to derive formulations of muds, to calculate the amount of barite needed to weight-up a mud, to determine the amount of water needed to dilute a mud, and to find the volume of two or more muds to mix together to achieve a new mud weight and volume. Material balance is also the basis for calculating solids content of muds based on mud testing data.

The finer grained, interstitial particles that lie between larger particles or in which larger particles are embedded in sedimentary rocks such as sandstones and conglomerates.

The treatment of a reservoirformation with a stimulation fluid containing a reactive acid. In sandstone formations, the acid reacts with the soluble substances in the formation matrix to enlarge the pore spaces. In carbonate formations, the acid dissolves the entire formation matrix. In each case, the matrix acidizing treatment improves the formation permeability to enable enhanced production of reservoir fluids. Matrix acidizing operations are ideally performed at high rate, but at treatment pressures below the fracturepressure of the formation. This enables the acid to penetrate the formation and extend the depth of treatment while avoiding damage to the reservoir formation.

What Is Matrix Stimulation? Matrix stimulation is a well intervention technique that injects treating fluids into a reservoir at pressures below the formation parting pressure, dissolving damage, removing pore-plugging material, and restoring or enhancing near-wellbore permeability without creating hydraulic fractures. It is applied in both sandstone and carbonate formations globally to reduce positive skin damage and improve production log inflow profiles. Key Takeaways Matrix stimulation operates strictly below the formation parting pressure, distinguishing it from hydraulic fracturing, which intentionally exceeds that pressure to create new fracture surface area. In sandstone reservoirs, hydrochloric-hydrofluoric (HCl-HF) mud acid dissolves clay minerals, silica fines, and carbonate cement that reduce near-wellbore permeability, restoring the formation to its original or near-original flow capacity. In carbonate reservoirs, hydrochloric acid creates preferential dissolution channels called wormholes that bypass damaged zones and extend deep into the formation at optimal injection rates, increasing effective wellbore radius significantly. Pre-job evaluation using X-ray diffraction for clay typing, core flood tests, and skin factor analysis from pressure transient data is essential to selecting the correct acid formulation, volume, and injection rate for each candidate well. Post-stimulation improvement is quantified by the reduction in skin factor (S) from a positive value indicating damage to a near-zero or mildly negative value, translating directly into production rate uplift and improved project economics. How Matrix Stimulation Works The technical objective of matrix stimulation is to reduce the skin factor, a dimensionless parameter in Darcy's law that quantifies the additional pressure drop across the near-wellbore zone beyond that predicted by radial flow theory. A positive skin indicates damage: clays swollen by incompatible fluids, fines migrated onto grain surfaces, scale deposits, emulsion blockages, or asphaltene precipitation have choked the pore throats within a radius of roughly 0.3 to 3 m (1 to 10 ft) from the wellbore. A skin of +10, for example, means the well is producing as if the wellbore radius were dramatically smaller than its actual diameter, and a successful matrix treatment that drives skin to near zero can double or triple the production rate from the same drawdown pressure, with no additional capital expenditure on new wells or compression. The critical operating constraint is the fracture extension pressure, or formation parting pressure, which equals the minimum principal horizontal stress (sigma-h) plus the tensile strength of the rock, typically in the range of 0.7 to 0.9 psi per foot (15.8 to 20.4 kPa/m) of depth depending on basin tectonic regime. Injection pressure must remain below this threshold throughout treatment. Field engineers monitor instantaneous injection pressure and surface treating pressure in real time during pumping, and job design includes a maximum allowable surface treating pressure (MASP) calculation that accounts for hydrostatic head, tubular friction, and a safety margin of at least 500 PSI (34.5 bar) below the estimated fracture gradient. Exceeding MASP even briefly can initiate an unintended fracture that bypasses the target zone and communicates with water zones or creates out-of-zone injection, triggering regulatory reporting obligations in most jurisdictions. Sandstone Acidizing: HCl-HF Mud Acid Treatment Sandstone matrix stimulation employs a sequential pumping schedule designed to prepare the formation, deliver the reactive acid, and then flush spent acid away from the wellbore before it precipitates secondary precipitates. The standard treatment sequence, refined through decades of laboratory and field work by researchers at Dowell, Halliburton, Schlumberger, and academic groups, consists of three stages. The pre-flush stage typically uses 5 to 15% hydrochloric acid (HCl) by volume: it dissolves carbonates present in the near-wellbore zone, removes iron compounds that could catalyse HF decomposition, and creates a low-pH, low-calcium environment that stabilises the subsequent HF-containing stage. Without a competent pre-flush, calcium fluoride (CaF2) and other fluoride precipitates can form in the main treatment stage and cause permanent permeability damage worse than the original problem. The main stage, known as mud acid, is a blend of hydrofluoric acid and hydrochloric acid. The most common formulation is 12% HCl combined with 3% HF (by weight), referred to as 12:3 mud acid in field practice. For formations with elevated feldspar or clay content, a weaker 13.5% HCl and 1.5% HF (13.5:1.5) blend reduces the risk of alumino-silicate gel precipitation as spent acid contacts formation water. The HF reacts selectively and sequentially with clay minerals (kaolinite, illite, chlorite, montmorillonite), silica cement, and feldspars, consuming HF in that priority order. X-ray diffraction (XRD) analysis of formation core or cutting samples, performed in advance at a recognised petrophysical laboratory, quantifies the relative abundance of each mineral phase and directly informs the acid volume required to achieve adequate HF consumption without over-spending on excess acid that provides no incremental benefit. The overflush stage uses a mutual solvent (typically 5 to 10% isopropanol or ethylene glycol monobutyl ether, EGMBE) or a dilute HCl solution to displace spent acid, aluminium fluoride complexes, and silica gels away from the wellbore into the formation where they are less damaging to flow. The total volume of each stage is designed per foot of net pay using published guidelines: typical main-stage mud acid volumes range from 50 to 150 gallons per foot (0.62 to 1.86 L/cm) of perforated interval, with the exact volume governed by the formation mineralogy and the desired radius of acid penetration. Carbonate Acidizing: Wormhole Formation and Propagation Carbonate matrix stimulation uses hydrochloric acid, typically 15 to 28% HCl by weight, to dissolve calcite (CaCO3) or dolomite (CaMg(CO3)2) in limestone and dolostone reservoirs. Unlike sandstone acidizing, where the goal is uniform dissolution of pore-plugging material, carbonate acidizing exploits the intrinsically unstable nature of acid flow in a dissolving porous medium: at optimal injection rates, acid preferentially etches the highest-permeability flow paths, creating highly conductive dissolution channels called wormholes that propagate several metres into the formation well beyond the damage zone, with minimal consumption of acid in the surrounding matrix. Laboratory core flood experiments on short carbonate plugs at varying acid injection rates, quantified by the dimensionless Damkohler number (ratio of reaction rate to convective transport rate) and the Peclet number (ratio of convective to diffusive transport), reveal five distinct dissolution regimes. At very low injection rates, face dissolution occurs: acid reacts before it can penetrate deep, creating a shallow cavity at the wellbore face with no deep penetration. As injection rate increases, conical wormholes form and eventually transition to the dominant branching (or optimal) wormhole structure, which achieves the deepest penetration per unit of acid consumed and produces the greatest skin reduction per treatment dollar. At high injection rates, uniform dissolution occurs as acid contacts the entire matrix simultaneously with shallow penetration. The optimal injection rate for branching wormholes in field treatments, recommended by Nierode, Williams, Economides, and subsequent researchers, typically falls in the range of 0.1 to 1.0 cm/min (0.04 to 0.4 in/min) of interstitial velocity at the wormhole tip, translating to surface injection rates of 0.5 to 5 bpm (0.08 to 0.8 m3/min) depending on wellbore geometry and formation thickness. Wormhole penetration depth in carbonates can reach 1 to 3 m (3.3 to 9.8 ft) beyond the wellbore for typical treatment volumes of 50 to 200 gallons per foot (0.62 to 2.48 L/cm) of pay, effectively increasing the effective wellbore drainage radius by the wormhole length and dramatically reducing convergence pressure losses. In naturally fractured carbonates, acid preferentially enters existing fractures and dissolves fracture walls, widening the aperture and connecting additional natural fractures to the wellbore. Saudi Aramco's extensive carbonate stimulation programs in the Arab-D reservoir of Ghawar and the Hadriya Formation have refined optimal acid volumes, diversion techniques, and wormhole placement to maximise productivity in carbonate formations with matrix permeabilities often below 5 millidarcies (mD). Fast Facts Matrix acidizing accounts for the majority of stimulation treatments performed worldwide by count, with hundreds of thousands of treatments completed annually across producing regions from the Permian Basin to the North Sea to the Arabian Peninsula. In carbonate formations, a properly designed HCl matrix treatment costing USD 20,000 to 80,000 per well can deliver production rate increases of 50 to 300%, yielding project payout in days to weeks on a typical oil well producing at market prices above USD 60 per barrel. Formation Damage Diagnosis and Treatment Selection Matrix stimulation success depends critically on identifying the specific type and spatial extent of formation damage before selecting a treatment. The primary diagnostic tool is pressure transient analysis (PTA), specifically the skin factor derived from a drawdown or buildup test analysed using Horner semi-log plots or modern type-curve matching. A skin above +5 on a well with good reservoir permeability indicates sufficient damage to warrant stimulation; a skin above +20 represents severe near-wellbore impairment that will respond dramatically to a well-designed treatment. However, a high skin on a low-permeability well may reflect geometric skin from partial penetration or limited entry perforations rather than true formation damage, and acidizing a geometrically damaged well produces no benefit. Formation damage types and their corresponding treatments include the following. Clay damage encompasses kaolinite and illite swelling or fines migration triggered by low-salinity or incompatible injection water; the treatment is HCl-HF mud acid with clay stabiliser additives (quaternary amines, zirconium crosslinkers) pumped post-flush. Scale deposits of calcium carbonate, barium sulphate, strontium sulphate, or iron compounds form when incompatible waters mix or when pressure and temperature drop in the near-wellbore zone; CaCO3 scale responds to HCl, while BaSO4 and SrSO4 require chelating agents such as EDTA (ethylenediaminetetraacetic acid) at concentrations of 15 to 25% by weight in an alkaline solution. Organic damage from asphaltene precipitation (common in high-paraffin crude from the Middle East, the Orinoco Belt, and Alberta oil sands upgrader feed wells) and paraffin wax deposition requires aromatic solvent pre-flushes: xylene, toluene, or purpose-formulated dispersants dissolve and disperse the organic deposits before the acid stage. Emulsion blockages formed when drilling fluid or treatment fluids contact crude oil require mutual solvents and demulsifiers. Bacterial damage from sulphate-reducing bacteria (SRB) that form biofilm plugs in injection wells or producing wells in water-flood projects requires biocide treatments, typically quaternary ammonium compounds or glutaraldehyde solutions, followed by a mechanical or chemical displacement.

The process of a sourcerock becoming capable of generating oil or gas when exposed to appropriate pressures and temperatures. As a source rock begins to mature, it generates hydrocarbons. As an oil-prone source rock matures, the generation of heavy oils is succeeded by medium and light oils and condensates. Above a temperature of approximately 100&degC [212&degF], only dry gas is generated, and incipient metamorphism is imminent. The maturity of a source rock reflects the ambient pressure and temperature as well as the duration of conditions favorable for hydrocarbon generation. Understanding maturation is especially important in shale reservoirs because of the shales dual role as source rock and reservoir rock.

The state of a source rock with respect to its ability to generate oil or gas. As a source rock begins to mature, it generates gas. As an oil-prone source rock matures, the generation of heavy oils is succeeded by medium and light oils. Above a temperature of approximately 100 oC [212 oF], only dry gas is generated, and incipient metamorphism is imminent. The maturity of a source rock reflects the ambient pressure and temperature as well as the duration of conditions favorable for hydrocarbon generation.

A widespread marine flooding surface that separates the underlying transgressivesystems tract from the overlying highstand systems tract. The surface also marks the deepest water facies within a sequence. The maximum flooding surface represents a change from retrogradational to progradational parasequence stacking patterns. It commonly displays evidence of condensation or slow deposition, such as abundant burrowing, hardgrounds, mineralization and fossil accumulations. On wireline logs, the shales that immediately overlie the maximum flooding surface commonly have different characteristics than other shales and can often be recognized on the basis of resistivity, gamma ray, neutron and density logs. These shales can also be recognized by electrofacies analysis when the analysis is designed to do so.

The highest temperature recorded on a loggingrun. It is usually taken to be the bottomhole temperature for use in log interpretation. However, on the first logging run or runs after circulation, the mud may be hottest some distance above the bottom of the hole.

The surface-pump pressure limit below which a treatment should be performed. The maximum treating pressure is determined to avoid fracturing the formation or damaging completion components. The maximum treating pressure is generally calculated to ensure that the pump-pressure limit equates to downhole and reservoir conditions that are within the design limits of the treatment.

(noun) A statistical measure of central tendency, calculated as the arithmetic average of a set of values. In petroleum engineering, the mean is widely used in reservoir characterisation to summarise distributions of porosity, permeability, saturation, and other parameters, though the geometric or harmonic mean may be more appropriate for certain flow calculations.

The point on a logging tool at which it is considered the logging measurement is made. It is the center of the vertical response, or in some cases an alternative, more suitable point. For measurements that must be recorded over a significant time period, there is a difference between the static and dynamic measure point, known as the lag.

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.

Measurements made by measurements-while-drilling (MWD) tools subsequent to the initial bitrun. MWD logs are recorded while drilling the well. However, these tools can also record logs at later times when the drillstring is in the hole. This may be while pulling out after drilling, or on a subsequent bit run or circulating trip. The latter is also known as logging while tripping.

The difference between the true value and that which is reported from a measurement.

The range of values for a quantity for which the error of a measuring instrument is intended to lie within specified limits. Within this range, the measurement has a well-defined accuracy or applicability. Outside the range, it does not. It is distinct from the operating range, within which the instrument will provide a measurement but the error is not well-defined.

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, sonicvelocity, 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.

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, sonicvelocity, 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.

A calibrated tank that automatically measures the liquid volume passing through it. Measuring tanks are also called metering tanks or dump tanks.

The use of mechanical devices, such as ball sealers, packers and straddle-packer assemblies, to divert reservoir treatments to the target zone. Ball sealers and solid-particle diverting agents incorporated into the treatment fluid form a temporary plug in the perforations accepting the most fluid flow, thereby diverting the remaining treatment fluid to the less permeable zones. Packers and straddle-packer assemblies function by performing several short treatments over a longer interval to help ensure an even treatment over the entire zone.

A type of jar that incorporates a mechanical trip or firing mechanism that activates only when the necessary tension or compression has been applied to the running string. In slickline operations, the term is often used to describe any jar that does not contain a hydraulic trip mechanism, such as link and tubular jars that do not incorporate a firing mechanism.

The reduction in permeability in the near-wellbore area resulting from mechanical factors such as the displacement of debris that plugs the perforations or formationmatrix. Such damage in the near-wellbore area can have a significant effect on the productivity of a well.

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.

A mathematical measure of the centrality of a data set. If the data set is arranged in the order of the values, the median is the value of the central data point for an odd number of data, or the mean of the two central data points for an even number of data. The median is often used in place of the mean or average when there are a number of extreme data values or the distribution of data is skewed.

Referring to any particle in the size range 74 to 250 microns.

A particular type of induction log designed to read an intermediate distance into the formation while maintaining good vertical resolution. The medium-induction array of eight coils (IM) is produced by three transmitters and five receivers running at 20 kHz. A small fourth transmitter coil was added in tools built since 1968. The midpoint of the integrated radial geometrical factor is 30 in. [76 cm] in radius. The vertical resolution is about 4 ft [1.2 m] but varies with conditions. The IM is combined with a deep-induction log on the same sonde to produce a dual induction log.

The electromagnetic force generated across an ion-selective membrane when solutions on either side of the membrane have different salinities. Shales and clays are cationic membranes, since they allow the passage of cations, such as Na+, but not anions, such as Cl-. When the drilling mud in the borehole and the formation water have different salinities, a membrane potential is generated at the boundary between a shale and a permeableformation. This potential is one component of the electrochemical potential, from which the spontaneous potential (SP) log is derived. The other, much smaller component is the liquid-junction potential. The membrane potential is reduced if the shale is not a good cationic membrane, or in other words has a low cation-exchange capacity.A membrane potential may also be generated across the mudcake if there is no flushed zone; for example if the mudfiltrate has moved vertically since invasion took place, and by clay within a shalysand, but with the opposite polarity to the normal SP potentials.The membrane potential is also used in core analysis to determine the cation-exchange capacity of a sample. In this case, the clay within the sample is the ion-selective membrane, and the potential generated across it is related to the cation-exchange capacity per unit pore volume, Qv. As a method of measuring Qv, the technique is faster than the multiple salinity method, and more representative of the in-situ value than destructive methods such as conductometric titration. However, care is needed in making the measurement and deriving the appropriate Qv.

A type of electronic pressure gauge that samples and records downhole pressures, with the data being stored, ready for downloading to acquisition equipment when the tool assembly has been retrieved to surface. Memory gauges are generally used to measure bottomhole pressures and temperatures in response to various production rates in tests to assess well productivity and reservoir performance.

The curved interface between two immiscible phases in a tube, such as in a pipette or graduated cylinder. Liquid volumes should be read at the bottom of a curved meniscus by alignment of the bottom of the meniscus. For water and liquids that wet the glass, the meniscus is concave. For nonwetting liquids, such as mercury, the meniscus is convex.

A technique for measuring the bulk volume of a core sample by observing the displacement of mercury in a chamber. The chamber is first filled to a reference level and the volume recorded. The sample is introduced and the new volume recorded. The difference is the bulk volume of the sample. If the sample is weighed, its bulk density can also be calculated. Mercury is used because it is strongly nonwetting and therefore does not enter the pore space.

The last stage of maturation and conversion of organic matter to hydrocarbons. Metagenesis occurs at temperatures of 150&deg to 200&degC [302° to 392&degF]. At the end of metagenesis, methane, or dry gas, is evolved along with nonhydrocarbon gases such as CO2, N2, and H2S, as oil molecules are cracked into smaller gas molecules.

The apparent increase in thickness of a casing or tubing string compared to the assumed value. Metal gain is determined by electromagnetic thickness, acoustic resonance or mechanical methods. The apparent increase is usually due a change of hardware, such as a casing coupling, a heavier joint, a pup joint, a mandrel or a valve. The term is used in contrast to metal loss caused by corrosion.

The loss of material on the inside or outside of a casing or tubing due to corrosion. Monitoring metal loss in situ helps determine when the pipe may be at risk for leaking or failure. Metal loss is determined by comparing casing or tubing thickness measured by electromagnetic, acoustic resonance or mechanical methods with either an earlier measurement or an assumed value.

One of three main classes of rock (igneous, metamorphic and sedimentary). Metamorphic rocks form from the alteration of preexisting rocks by changes in ambient temperature, pressure, volatile content, or all of these. Such changes can occur through the activity of fluids in the Earth and movement of igneous bodies or regional tectonic activity. The texture of metamorphic rocks can vary from almost homogeneous, or nonfoliated, to foliated rocks with a strong planar fabric or foliation produced by alignment of minerals during recrystallization or by reorientation. Common foliated metamorphic rocks include gneiss, schist and slate. Marble, or metamorphosed limestone, can be foliated or non-foliated. Hornfels is a nonfoliated metamorphic rock. Graphite, chlorite, talc, mica, garnet and staurolite are distinctive metamorphic minerals.

The process by which the characteristics of rocks are altered or the rock is recrystallized. Metamorphism of igneous, sedimentary, or preexisting metamorphic rock can produce new metamorphic rock. Such alteration occurs as rocks respond to changes in temperatures, pressures and fluids, commonly along the edges of colliding lithospheric plates. The pressures and temperatures at which metamorphism occurs are higher than those of diagenesis, but no clear boundary between the two has been established.

A device used to measure volumes or rates of fluids (liquid or gas).

The operation to adjust the meter to a specific standard.

The maximum and the minimum rate of flow specified by the manufacturer to maintain accuracy in the readings.

The difference in gas volume registered using two different meters.

A correction number for the meter. It is determined by calibrating the meter using an incompressible fluid (liquid).

The volume of liquid that is not registered by the meter at a specific flow rate.

[CH4]The lightest and most abundant of the hydrocarbon gases and the principal component of natural gas. Methane is a colorless, odorless gas that is stable under a wide range of pressure and temperature conditions in the absence of other compounds.

A pH indicator used in alkalinity titration of mud filtrate and water samples. The indicator is yellow in solutions above pH 4.3, and red below pH 4.3. "M" alkalinity is the titration volume measured using the methyl orange indicator. Methyl orange is often replaced in test kits by bromocresol green.

A measure of the total amount of hydroxyl ions in a solution as determined by titration with standardized acid. This test is a well-known water-analysis procedure to estimate hydroxyl, carbonate ion and bicarbonate ion concentrations. There are two pH endpoints, P and M, in this titration, corresponding to phenolphthalein and methyl orange indicators. The "P" endpoint is at pH 8.3 and the "M" endpoint is at pH 4.3. Each is reported in units of cm3 acid/cm3 sample. For water samples and very simple mud filtrates, P and M data indicate OH-, HCO3- and CO3-2 concentrations, but an alkalinity test is unreliable for analyzing complex mud filtrates. The API has established standards for conducting alkalinity tests

A blue dye with a cationic charge on the molecule used as the reagent for the methylene blue test used to estimate cation-exchange capacity (CEC) of solids in a water-base drilling mud.

A test to determine the amount of clay-like materials in a water-base drilling fluid based on the amount of methylene blue dye absorbed by the sample. Results are reported as "MBT" and also as "lbm/bbl, bentonite equivalent" when performed to API specifications.

A water-base drilling fluid containing a high concentration of methylglucoside. The mud has been used to drill water-sensitive shales with less hole enlargement and fewer drilling problems. Methylglucoside is a polysaccharide containing methyl groups on the ring-like sugar structure. Being a rather large, nonionic molecule (resembling starch but highly water soluble), it ties up water molecules in concentrated solutions and it is thought to act as a low-efficiency osmotic membrane.

[Muscovite mica K2Al4(Si6Al2O20(OH,F)4]A group of sheet silicates characterized by a platy appearance and basal cleavage most common in igneous and metamorphic rocks. Several clay minerals, such as chlorite and glauconite, are closely related to the mica group.

An enhanced oil recovery technique in which a micelle solution is pumped into a reservoir through specially distributed injection wells. The chemical solution reduces the interfacial and capillary forces between oil and water and triggers an increase in oil production.The procedure of a micellar-polymer flooding includes a preflush (low-salinity water), a chemical solution (micellar or alkaline), a mobilitybuffer and, finally, a driving fluid (water), which displaces the chemicals and the resulting oil bank to production wells.

An enhanced oil recovery technique in which a micelle solution is pumped into a reservoir through specially distributed injection wells. The chemical solution reduces the interfacial and capillary forces between oil and water and triggers an increase in oil production.The procedure of a micellar-polymer flooding includes a preflush (low-salinity water), a chemical solution (micellar or alkaline), a mobility buffer and, finally, a driving fluid (water), which displaces the chemicals and the resulting oil bank to production wells.

An ordered aggregate of surfactant molecules formed when the surfactant concentration in a solution reaches a critical point, thus lowering the free energy of the system. Within an aqueous phase, the molecules in a micelle organize such that the hydrophilichead group is the outermost part of the micelle and the hydrophobictail group is inside the micellar surface. Within an oil phase a reverse, or inverse, micelle can form: The surfactant molecules then organize such that the hydrophobic tail group is outermost, and the hydrophilic head group is inside the surface. A micelle can solubilize oil in water; a reverse micelle can solubilize water in oil.

Dense, fine-grained carbonate mud or rocks composed of mud that forms by erosion of larger carbonate grains, organic precipitation (such as from algae), or inorganic precipitation. The grains in micrite are generally less than 4 microns in size.

A small gap that can form between the casing or liner and the surrounding cement sheath, most commonly formed by variations in temperature or pressure during or after the cementing process. Such variations cause small movement of the steel casing, breaking the cement bond and creating a microannulus that is typically partial. However, in severe cases the microannulus may encircle the entire casing circumference. A microannulus can jeopardize the hydraulic efficiency of a primary cementing operation, allowing communication between zones if it is severe and connected.

An enhanced recovery process in which microorganisms are used in a reservoir to improve oil recovery. The microorganism can either be injected into the reservoir, or the population of an existing microorganism in the reservoir can be enhanced by injection of nutrients preferred by that microorganism. The microorganisms improve oil recovery by various means: (1) by releasing gases and increasing the pressure of the reservoir; (2) by breaking the heavier molecules into smaller chain components, resulting in the reduction of viscosity of oil; and 3) by producing natural surfactants that can improve oil flow by altering the interfacial properties of the system comprising the crude oil, brine and rock.

An electrode device with small spacings from which the current flow, and hence the measurement, is focused a short distance into the formation. The microcylindrical log measures the resistivity of the flushed zone with minimum influence from the mudcake or the undisturbed zone. The electrodes are mounted on a pad that is pressed against the borehole wall. The current is focused both parallel and perpendicular to the tool axis. Three measurements are made, each with a different depth of investigation. These measurements are combined to solve for the mudcake and flushed-zone resistivity.

A thermodynamically stable emulsion consisting of a mixture of oil, water and surfactant. In contrast to a simple emulsion formed under shear, a microemulsion is a minimum energy state. It does not require an input of energy into the system to form; instead, it forms spontaneously. Depending on the structure of the surfactant and the presence or absence of cosurfactant, an oil-in-water system (Winsor Type I), a water-in-oil system (Winsor Type II) or a bicontinuous system (Winsor Type III) may form. Various structures of micelles and reverse micelles are possible, ranging from spherical through cylindrical to lamellar. A typical microemulsion will have micelle diameters in the range of 3 to 20 nm.

A small fish eye, typically invisible, but which can nevertheless cause formation damage by polymer plugging of pore throats. Microgels may be formed by adding polymer too quickly when viscosifying a completion brine.

An electrode device with small spacings from which the current flow, and hence the measurement, is focused a short distance into the formation. Introduced in 1953, the microlaterolog measures the resistivity of the flushed zone with minimum influence from the mudcake or the undisturbed zone. The central current emitting electrode (A0) is surrounded by a guard electrode that emits sufficient current to focus the current from A0 a certain distance into the formation. The electrodes are mounted on a pad that is pressed against the borehole wall. In a typical tool design, 90% of the signal comes from within 3 in. [7.6 cm] of the pad, ensuring that the undisturbed zone rarely has an effect.

An unfocused electrode device with small spacings, mounted on a pad and pressed against the borehole wall. The typical microlog has one current-emitting electrode and two measure electrodes in line above it, one at 1 in. [2.5 cm], the other at 2 in. [5 cm]. The potential at the 2-in. electrode gives a 2-in. micronormal log. The difference in potential between the two measure electrodes gives a 1-in. x 1-in. microinverse log. The micronormal reads deeper than the microinverse.Introduced in 1948, the microlog is used to detect permeable zones across which a mudcake has formed. Since the mudcake is usually less resistive than the invaded zone, the microinverse will read less than the micronormal opposite permeable zones. If the resistivity and thickness of the mudcake are known, it is possible to estimate the resistivity of the flushed zone. The log is usually presented on a linear scale, chosen to emphasize the lower readings often seen opposite permeable zones with mudcake.

The study of microfossils too small to be seen without the use of a microscope. Marine microfossils such as foraminifera are important for stratigraphic correlation.

That part of the pore space that has a characteristic dimension less than 1 micron. In general, this includes not only very small pores but also the porosity associated with surface roughness. The water in this pore space is part of the capillary-bound water and the small-pore water. Water in micropores is not expected to flow on production. The term is also defined as porosity that cannot be seen at magnifications less than 50x.

Related to a log of the resistivity of the flushed zone recorded by a wirelineelectrode device. The device is mounted on a pad and pressed against the borehole wall. Several designs exist, for example microlog, microlaterolog, proximity log, microspherical log and microcylindrical log. The microlog, being unfocused, is a more qualitative measurement.The other measurements are focused. They try to minimize the effect of mudcake and rugose hole, while reading as short a distance as possible into the formation, to remain unaffected by the undisturbed zone. They are usually combined with a laterolog or induction log to correct the latter for the effects of invasion and for saturation determination in quick-look ratio methods. The logs are presented on a logarithmic scale from, for example 0.2 to 2000 ohm-m.

An electrode device with small spacings from which the current flow, and hence the measurement, is focused a short distance into the formation. The microspherical log measures the resistivity of the flushed zone with minimum influence from the mudcake or the undisturbed zone. The principle of spherical focusing is used. The electrodes are mounted on a pad that is pressed against the borehole wall. In a typical tool design, 90% of the signal comes from within 3 in. [7.6 cm] of the pad, ensuring that the undisturbed zone rarely has an effect.

A common term for the infinite-acting radial flow regime. This portion of the pressure-transient response is between wellbore-dominated flow regimes in the early-time transient data and boundary-dominated flow regimes in the late-time transient data. This most common flow regime is the most central to pressure-transient analysis because its presence enables determination of permeability and skin.

The mountainous, linear axis of ocean basins along which rifting occurs and new oceanic crust forms as magma wells up and solidifies. The most prominent midoceanic ridges are those of the Atlantic and Indian Oceans. The new crust is made of mafic igneous rock called basalt, commonly referred to as midocean ridge basalt, or MORB, whose composition reflects that of the deeper mantle of the Earth. The presence of the spreading plate boundaries of the midoceanic ridges; their symmetrically spreading, successively older crust outward from the ridge; and the lack of oceanic crust older than approximately 200 Ma support the theory of plate tectonics and the recycling of oceanic crust through the process of subduction.

The halfway point between a seismic source and a receiver at the Earth's surface.

A mathematical method of finding a central value for a group of data. The midrange is defined as the sum of the lowest value in the data set and the highest value if the data set divided by two.

A step in seismic processing in which reflections in seismic data are moved to their correct locations in the x-y-time space of seismic data, including two-way traveltime and position relative to shotpoints. Migration improves seismic interpretation and mapping because the locations of geological structures, especially faults, are more accurate in migrated seismic data. Proper migration collapses diffractions from secondary sources such as reflector terminations against faults and corrects bow ties to form synclines. There are numerous methods of migration, such as dip moveout (DMO), frequency domain, ray-trace and wave-equation migration.

A term used to describe an emulsion in a water-base mud in which the oil phase is internal (as in milk), and water is external.

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.

A downhole tool routinely used in fishing operations to prepare the top and outside surface of a fish, generally to allow an overshot or similar fishing tool to engage cleanly on the fish. In some cases, the outer portion of a fish may be milled out to allow the body and remaining debris to be pushed to the bottom of the wellbore.

On the basis of weight, the equivalent of parts per million, usually applied to small amounts of one solid admixed with another solid, such as 100 mg/kg of siderite in barite, the same as 100 ppm.

On a weight per volume basis, the SI unit of concentration, abbreviated mg/L, usually applied to dissolved material in a solution. This unit is used in water analyses and in mud and mud-filtrate analyses. Increasingly, mg/L and ppm are used interchangeably in mud analyses. Actually, mg/L and ppm can only be interchanged when the sample has the exact density of water, which is only approximated by very dilute solutions.

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.

A common measure for gas volume. Standard conditions are normally set at 60oF and 14.7 psia, abbreviated MMscf.

A unit of measurement for the corrosion rate of a coupon, abbreviated as mpy. A mil is one thousandth of an inch.

A crystalline substance that is naturally occurring, inorganic, and has a unique or limited range of chemical compositions. Minerals are homogeneous, having a definite atomic structure. Rocks are composed of minerals, except for rare exceptions like coal, which is a rock but not a mineral because of its organic origin. Minerals are distinguished from one another by careful observation or measurement of physical properties such as density, crystal form, cleavage (tendency to break along specific surfaces because of atomic structure), fracture (appearance of broken surfaces), hardness, luster and color. Magnetism, taste and smell are useful ways to identify only a few minerals.

Ownership of the right to exploit, mine or produce all minerals lying beneath the surface of a property. In this case, minerals include all hydrocarbons. Mineral interests include: 1. the right to use as much of the surface as is reasonably necessary to access the minerals, 2. the right to execute any conveyances of mineral rights, 3. the right to receive bonus consideration, 4. the right to receive delay rentals and 5. the right to receive royalty. Any or all of the above five rights of mineral ownership may be conveyed by the mineral owner.

A small fracturing treatment performed before the main hydraulic fracturing treatment to acquire critical job design and execution data and confirm the predicted response of the treatment interval. The minifrac procedure provides key design data from the parameters associated with the injection of fluids and the subsequent pressure decline. The final job procedures and treatment parameters are refined according to the results of the minifrac treatment.

At constant temperature and pressure, the minimum quantity of additional components, such as intermediate-chain gases or CO2, that must be added to an injection gas to reach first-contact miscibility with a reservoir fluid at a given temperature and pressure. At minimum miscibility concentration conditions, the interfacial tension is zero and no interface exists between the fluids.

At constant temperature and composition, the lowest pressure at which first- or multiple-contact miscibility (dynamic miscibility) can be achieved. At minimum miscibility pressure, the interfacial tension is zero and no interface exists between the fluids.

The smallest diameter present in a wellbore through which a tool string must pass to enable access to the operating depth or zone of interest. The minimum restriction determines the maximum tool string outside diameter and may influence the configuration of the assembled tools or equipment. The minimum restriction should be considered in both running and retrieving modes if any increase in tool string outside diameter is likely, such as when perforating or when using inflatable packers.

An annotation made on a log print once every minute. By reading the depth interval between each minute mark, it is possible to check the logging speed. Minute marks are typically made by blanking out the vertical grid line on the far left of the print for a short interval every minute.

A situation in interpretation of seismic data in which predicted and actual values differ, or when an interpreted reflection does not close, or tie, when interpreting intersecting lines; or when interpreted seismic data do not match results of drilling a well. Mis-ties commonly occur when data of different phases, rather than uniformly zero-phase data, are interpreted together, or data that have different datum corrections are tied. Mis-ties are described as static if they involve a bulk shift of data (as in the case of tying seismic sections with different datum corrections) or dynamic if the magnitude of the mis-tie varies with time (as in the case of data that have been migrated differently).

Pertaining to a condition in which two or more fluids can mix in all proportions and form a single homogeneous phase.

A general term for injection processes that introduce miscible gases into the reservoir. A miscible displacement process maintains reservoir pressure and improves oil displacement because the interfacial tension between oil and water is reduced. The effect of gas injection is similar to that of a solution gasdrive.Miscible displacement is a major branch of enhanced oil recovery processes. Injected gases include liquefied petroleum gas (LPG), such as propane, methane under high pressure, methane enriched with light hydrocarbons, nitrogen under high pressure, and carbon dioxide [CO2] under suitable reservoir conditions of temperature and pressure. The fluid most commonly used for miscible displacement is carbon dioxide because it reduces the oil viscosity and is less expensive than liquefied petroleum gas.Miscible displacement is also called miscible gasdrive, miscible drive or miscible flood.

Small liquid droplets (moisture or liquid hydrocarbons) in a gas stream. In separators, mist extractors are used to collect mist.

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.

A device used to collect small liquid droplets (moisture or hydrocarbons) from the gas stream before it leaves the separator. The two most common types of mist extractors are wire-mesh pads and vanes. Once the small droplets of liquid are collected, they are removed along with the other liquids from the separator.

A multiphase-flow regime, with gas as the continuous phase, in which oil or water exists as very small, approximately homogeneously distributed droplets. Mist flow occurs at high gas velocities. Unless the velocity is very high, there may be a thin film of liquid on the pipe wall, in which case the term annular flow or annular mist flow is also used.

A blend of organic and inorganic compounds such as scales, silts or clays. Migrating fines that become oil-wet often become targets for organic deposits, thereby creating a mixed deposit.Mixed deposits are considered a type of damage. Treating this type of deposit requires a dual-solvent system composed of an aromatic hydrocarbon and an acid.

mixed-metal hydroxide1. n. [Drilling Fluids] ID: 2102 A compound containing hydroxide anions in association with two or more metal cations. MMH particles are extremely small and carry multiple positive charges. They can associate with bentonite to form a strong complex that exhibits highly shear-thinning properties, with high and fragile gel strengths, high yield point (YP), and low plastic viscosity (PV). MMH is described as a mixed-metal layered hydroxide (MMLH). In the crystal layers, Al+3 , Mg+2 and OH- ions reside, but due to symmetry considerations, there is not enough room for sufficient OH- ions to electrically offset the charges of the two cations. Therefore, a net positive charge exists on the crystal surfaces. Exchangeable anions sit on the positive surface (much the same as cations sit on negative clay surfaces). MMH muds are used as nondamaging drilling fluids, metal-reaming fluids (to carry out metal cuttings) and for wellbore shale control. Being cationic, MMH mud is sensitive to anionic deflocculants and small anionic polymers, such as polyphosphates, lignosulfonate or lignite.Reference:Burba JL III and Crabb CR: "Laboratory and Field Evaluation of Novel Inorganic Drilling Fluid Additive," paper IADC/SPE 17198, presented at the IADC/SPE Drilling Conference, Dallas, Texas, USA, February 28-March 2, 1988.Fraser L and Enriquez F: "Mixed-Metal Hydroxides Fluid Research Widens Applications," Petroleum Engineer International 64, no. 6 (June 1992): 43-46.

A product similar to mixed-metal hydroxide, but based on silicate chemistry.

A product similar to mixed-metal hydroxide, but based on silicate chemistry.

A generic term for several classes of self-contained floatable or floating drilling machines such as jackups, semisubmersibles, and submersibles.

The ratio of effective permeability to phase viscosity. The overall mobility is a sum of the individual phase viscosities. Well productivity is directly proportional to the product of the mobility and the layer thickness product.

In chemical flooding, a fluid stage, normally water thickened with a polymer, pumped between the micellar or alkaline chemical solution and the final water injection.Mobility buffers are prepared with polyacrylamides or polysaccharides and are frequently employed in micellar-polymer flooding operations because they improve sweep efficiency, which increases oil production. The high viscosity of the mobility buffer aids in the displacement of chemicals into the reservoir and also minimizes the channeling of the final water injection into the chemical solution or into the resulting oil bank.

A condition in oil recovery processes whereby the mobility of the injectant is lower than that of the oil or preceding chemical slug, leading to a stable displacement by the injectant. Commonly the injectant is water containing a soluble polymer that increases its viscosity. Micellar-polymer floods incorporate a mobility buffer to maximize the sweep efficiency of the injected chemical and associated oil bank.

The mobility of an injectant divided by that of the fluid it is displacing, such as oil. The mobility of the oil is defined ahead of the displacement front while that of the injectant is defined behind the displacement front, so the respective effective permeability values are evaluated at different saturations.

A conceptual, three-dimensional construction of a reservoir or oil and gas field. The model is constructed from incomplete data and much of the interwell space must be estimated from nearby wells or from low vertical resolution data, such as seismic data. The construction of models can be performed by deterministic methods or geostatistical methods, or a combination of both.

The act of constructing a model.

A type of deliverability test conducted in gas wells to generate a stabilized gas deliverability curve (IPR). This test overcomes the limitation of the isochronal test, which requires long shut-in times to reach the average reservoir pressure.In the modified isochronal test, the shut-in periods are of equal duration, as are the flowing periods. The final shut-in pressure before the beginning of the new flow is used as an approximation of the average reservoir pressure. The same procedure is typically repeated four times. A stabilized point (pseudosteady state) is usually obtained at the end of the test.Modified isochronal tests are commonly used in gas wells, because they require less time and money to produce results comparable to the isochronal test.

A type of secondary porosity created through the dissolution of a preexisting constituent of a rock, such as a shell, rock fragment or grain. The pore space preserves the shape, or mold, of the dissolved material.

The mean or expected value of the product formed by multiplying together a set of one or more variates or variables, each to a specified power.

The small platform that the derrickman stands on when tripping pipe.

The small platform that the derrickman stands on when tripping pipe.

The chemical unit from which a polymer is made.

Describing a type of acoustic transducer that emits or receives energy in all directions. Monopole transducers are used in standard sonic logs, and also in array-sonic logs to record shear and Stoneley waves.

A hydratable, dispersible claymineral of the smectite group. Montmorillonite is a three-layer, expanding clay with a large surface area and high cation-exchange capacity. Na+ and Ca+2 are the typical exchangeable cations. Sodium montmorillonite, also called sodium bentonite, is a premium clay mud additive. Natural deposits are found in Wyoming, North Dakota, South Dakota and Utah, USA. Calcium montmorillonite is a low-yield bentonite that is more widely distributed and used in many commercial applications, including drilling fluid.

A relatively permanent, fixed marker used in surveying, such as a concrete block or steel plate, with an inscription of location and elevation.

The opening in the hull of a drillship or other offshore drilling vessel through which drilling equipment passes.

A tubular placed at the bottom of the subsurface sucker-rod pump and inside the gas anchor to drive the formation fluid with little or no gas into the pump.

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.

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.

The volume of hydrocarbons per unit volume of rock that can be moved on production, measured in volume/volume or porosity units. Typically only primary and secondary production methods are considered when estimating moveable hydrocarbons. Moveable hydrocarbons are not necessarily the same as moved hydrocarbons, which are those hydrocarbons that have been moved by invasion.

The volume of hydrocarbons per unit volume of rock that have been moved by invasion, measured in volume/volume or porosity units. Moved hydrocarbons are not necessarily the same as moveable hydrocarbons, which are those hydrocarbons that can be moved on primary and secondary production.

The procedure in seismic processing that compensates for the effects of the separation between seismic sources and receivers.

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

Abbreviation for mils (thousandths of an inch) per year penetration, a unit of measurement for the corrosion rate of a coupon.

A term that is generally synonymous with drilling fluid and that encompasses most fluids used in hydrocarbon drilling operations, especially fluids that contain significant amounts of suspended solids, emulsified water or oil. Mud includes all types of water-base, oil-base and synthetic-base drilling fluids. Drill-in, completion and workover fluids are sometimes called muds, although a fluid that is essentially free of solids is not strictly considered mud.

A mixture of hydrofluoric acid [HF] and hydrochloric acid [HCl] or organic acid used as the main fluid in a sandstonematrix treatment. Hydrochloric acid or organic acid is mixed with HF to keep the pH low when it spends, thereby preventing detrimental precipitates. The name mud acid was given to these mixtures because they were originally developed to treat damage from siliceous drilling muds. Mud acid is also called hydrofluoric-hydrochloric acid.

A material added to a drilling fluid to perform one or more specific functions, such as a weighting agent, viscosifier or lubricant.

A cylindrical vessel in which a mud sample can be heated under pressure. Cells, often called bombs, are routinely used for static-aging and hot-roll aging of mud samples. Cells are usually made of metal or metal alloy, such as stainless steel or aluminum bronze, and have open tops. Caps should be fitted with a valve so that gas pressure can be applied and then released before opening the cell. Common sizes are 260 and 500 cm3, to accommodate half- and one-barrel equivalent volumes, plus space for thermal expansion. Glass or plastic jars can be used judiciously when pressure is nil and temperature is limited to below about 150°F [66°C].

Large diameter pipe placed outside the gas anchor to reduce the amount of solids carried by the formation liquid entering the subsurface sucker-rod pump.

A device to measure density (weight) of mud, cement or other liquid or slurry. A mud balance consists of a fixed-volume mud cup with a lid on one end of a graduated beam and a counterweight on the other end. A slider-weight can be moved along the beam, and a bubble indicates when the beam is level. Density is read at the point where the slider-weight sits on the beam at level. Accuracy of mud weight should be within +/- 0.1 lbm/gal (+/- 0.01 g/cm3). A mud balance can calibrated with water or other liquid of known density by adjusting the counter weight. Most balances are not pressurized, but a pressurized mud balance operates in the same manner.

A desilter unit in which the underflow is further processed by a fine vibrating screen, mounted directly under the cones. The liquid underflow from the screens is fed back into the mud, thus conserving weighting agent and the liquid phase but at the same time returning many fine solids to the active system. Mud cleaners are used mainly with oil- and synthetic-base muds where the liquid discharge from the cone cannot be discharged, either for environmental or economic reasons. It may also be used with weighted water-base fluids to conserve barite and the liquid phase.

A graduated cup used to take samples and to crudely measure volumes of mud for testing at the rig. A mud cup is used primarily with the Marsh funnel to measure one quart of flow out of the funnel. It is also used as a container for performing simple pilot tests with an electric mixer that clamps onto the top of the cup.

A person responsible for testing the mud at a rig and for prescribing mud treatments to maintain mud weight, properties and chemistry within recommended limits. The mud engineer works closely with the rig supervisor to disseminate information about mud properties and expected treatments and any changes that might be needed. The mud engineer also works closely with the rig's derrickman, who is charged with making scheduled additions to the mud during his work period.

A mud-flow device, also called a jet hopper, in which materials are put into the circulating mud system. The mud hopper is powered by a centrifugal pump that flows the mud at high velocity through a venturi nozzle (jet) below the conical-shaped hopper. Dry materials are added through the mud hopper to provide dispersion, rapid hydration and uniform mixing. Liquids are sometimes fed into the mud by a hose placed in the hopper.

The place where mud additives are kept at the rig, also known as the sack room.

A mud sample taken from the suction pit (the last pit in the flow series) just before the mud goes into the pump and down the wellbore. The in sample is also called the suction-pit sample, or "mud in" on a drilling fluid report. This mud has been treated and properly weighted and is in good condition to encounter downhole pressures, temperatures and contamination. Comparisons are made between properties of this mud-in sample and the "out" or mud-out sample taken at surface prior to solids removal.

What Is a Mud Motor? A mud motor converts the hydraulic energy of circulating drilling fluid into mechanical rotation of the drill bit, enabling the bit to turn independently of the drillstring. Deployed as the lowest section of the bottom-hole assembly (BHA), mud motors are the foundation of modern directional drilling and horizontal drilling programs across every major petroleum basin worldwide. Key Takeaways A mud motor is a positive displacement motor (PDM) that uses the Moineau principle: pressurized drilling fluid forces an eccentrically rotating rotor to spin inside a helical elastomeric stator, transmitting torque to the drill bit without rotating the entire drillstring. The lobe configuration of the rotor-stator pair determines the motor's speed-torque characteristics; a 1:2 lobe ratio produces high RPM with low torque, while a 7:8 ratio produces low RPM with high torque suited to roller-cone bits and hard formations. A bent housing or bent sub machined into the motor body, typically adjustable between 0 and 3 degrees, deflects the bit face off-axis so that sliding the drillstring (without surface rotation) builds inclination or changes azimuth in a controlled curve. Mud motors operate across a wide envelope: flow rates of 200 to 1,200 gallons per minute (757 to 4,542 liters per minute), temperatures up to 350 degrees Fahrenheit (177 degrees Celsius) for high-pressure/high-temperature (HPHT) designs, and pressure drops across the power section of 300 to 1,200 PSI (21 to 83 bar). All major drilling services companies, including Baker Hughes, SLB (Schlumberger), National Oilwell Varco (NOV), and Weatherford, manufacture mud motor product lines differentiated by lobe count, motor diameter, elastomer compound, and bearing package rated working pressure. How a Mud Motor Works The operating principle of a mud motor derives from the Moineau progressing-cavity pump, invented by René Moineau in 1930 and adapted for downhole use in the 1960s. In pump mode, a motor shaft turns to move fluid; in motor mode, the fluid flow drives the shaft. Inside the power section, the stator is a steel housing lined with a molded elastomeric insert carrying N helical lobes. The rotor is a hardened chrome-steel spiral shaft with N minus one lobes. Because the rotor has one fewer lobe than the stator, it cannot spin concentrically; instead it precesses, tracing an eccentric orbit that converts fluid pressure differential into rotary output. Each full precession cycle advances the fluid through one pitch length and turns the rotor shaft by the ratio defined by the lobe geometry. The transmitted torque and rotational speed depend on the number of lobe stages (each additional rotor-stator stage in series adds torque in proportion) and the flow rate through the motor. At a given flow rate, higher-stage motors (5:6, 7:8) spin more slowly, typically 60 to 250 RPM, but develop more torque per unit of pressure drop, making them preferred for tricone roller-cone bits and aggressive PDC cutters in hard rock. Low-stage motors (1:2, 2:3) spin at 400 to 800 RPM and are favored with PDC bits in softer to medium formations, where high bit RPM maximizes rate of penetration. Output torque can reach 15,000 foot-pounds (20,340 Newton-meters) on large-diameter (9-5/8-inch or 245-millimeter) motors, while miniaturized slim-hole motors as small as 1-11/16 inches (43 millimeters) diameter are used in coiled tubing operations and through-tubing re-entry. Between the power section and the bit box, the driveshaft assembly and bearing package transmit both the rotary torque and axial weight-on-bit loads while sealing wellbore fluid from the internal motor cavity. Sealed radial and thrust bearings, rated to withstand axial loads exceeding 100,000 pounds-force (445 kilonewtons) in large motors, allow the bit to drill while absorbing vibration. The bypass or dump valve at the top of the motor opens a flow path from the drillstring annulus to the bore when circulation is stopped, preventing the motor from hydraulically locking and allowing drillstring tripping. Design requirements for positive displacement motors are governed by API Specification 11D1 (ISO 15136-1), which specifies design verification, acceptance testing, and dimensional standards for downhole progressive cavity pump/motor assemblies. All major service company motors carry certification to API 11D1 or an equivalent national standard. Mud Motor Across International Jurisdictions Canada (Alberta and British Columbia): In the Montney tight gas and Duvernay condensate windows, pad-based horizontal drilling programs rely almost exclusively on mud motors with bent housings in the range of 1.5 to 2.5 degrees. The Alberta Energy Regulator (AER) governs drilling operations through Directive 059 (Well Drilling and Completion Data Filing Requirements) and Directive 036, which set reporting obligations but do not prescribe BHA configuration; motor selection remains an engineering decision documented in the well program submitted prior to spud. British Columbia Energy Regulator (BCER) regulations follow a parallel structure. On average, a Montney horizontal well drills a 2,000-to-3,000-meter (6,562-to-9,843-foot) lateral section in two to four motor runs, relying on rotary steerable system (RSS) or conventional slide-rotate sequences with real-time measurement-while-drilling (MWD) surveys to maintain wellbore trajectory within a 5-meter (16-foot) landing zone. United States (Permian Basin and Gulf of Mexico): In the Permian Basin, ultra-short-radius motor assemblies with bent housings up to 3 degrees build curves at 15 to 25 degrees per 30 meters (100 feet) to place laterals precisely within the Wolfcamp or Spraberry target intervals. The Bureau of Safety and Environmental Enforcement (BSEE) and Bureau of Ocean Energy Management (BOEM) regulate offshore drilling in the Gulf of Mexico under 30 CFR Part 250; well-specific APDs (Applications for Permit to Drill) require BHA descriptions including motor specifications. Extended-reach drilling (ERD) wells from GOM shelf platforms have used motors paired with RSS to achieve measured depths exceeding 10,000 meters (32,808 feet) with 60-degree departure from vertical. Australia (Cooper Basin and Carnarvon Basin): The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) administers well integrity regulations for Australian offshore operations under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. Onshore Cooper Basin operators use mud motors in directional programs targeting the Permian Patchawarra and Murteree shale intervals. NOPSEMA's Well Operations Management Plan (WOMP) framework requires that downhole tool specifications, including motor make, model, and rated working pressure, be documented and retained as part of the well file. Middle East (Saudi Arabia, UAE): Saudi Aramco's Ghawar and Safaniya fields operate some of the world's largest horizontal multilateral programs. Saudi Aramco Standard SAES-D-009 and the associated drilling engineering standards require high-temperature motor assemblies rated to at least 325 degrees Fahrenheit (163 degrees Celsius) for deep Arab-D carbonate targets. PDC-bit-compatible high-speed motors with 1:2 lobe ratios are preferred in the soft to medium carbonate matrix, while low-speed high-torque motors are used for chert stringers. In the UAE, ADNOC Drilling and contractor companies operate motors compliant with API 11D1 in both conventional and underbalanced drilling programs across the Thamama and Wajid reservoirs. Norway and the North Sea: Equinor's Johan Sverdrup field, the largest discovery on the Norwegian Continental Shelf in decades, uses horizontal laterals drilled through the Jurassic Hugin Formation sandstone. The Petroleum Safety Authority Norway (PSA, now Havinds Petroleumstilsyn) enforces regulations under the Framework Regulations and Activities Regulations, which require that downhole equipment meet recognized standards such as API 11D1 or equivalent ISO specifications. High-stage mud motors with enhanced-temperature elastomers are used for the deep North Sea HPHT wells in the Central Graben where bottomhole temperatures can exceed 300 degrees Fahrenheit (149 degrees Celsius). Fast Facts Invention: René Moineau patented the progressing cavity principle in 1932; first downhole application of a PDM in directional drilling was commercialized in the early 1970s. Lobe ratios in use: 1:2, 2:3, 3:4, 4:5, 5:6, 7:8 (rotor lobes : stator lobes) Pressure drop range: 300 to 1,200 PSI (21 to 83 bar) across the power section at rated flow Operating RPM range: 60 to 800 RPM depending on lobe count and flow rate HPHT temperature rating: Standard motors rated to 300 degrees Fahrenheit (149 degrees Celsius); HPHT motors to 350 degrees Fahrenheit (177 degrees Celsius) Governing standard: API Specification 11D1 / ISO 15136-1 (Downhole Progressive Cavity Pump/Motor) Turbodrill alternative: Axial-flow turbine-stage motors common in Russia and former Soviet states; higher RPM, lower torque per stage than PDMs

A mud sample taken after it has passed from the flowline and through the shaleshaker screens to remove large cuttings. The out sample is also called the shale shaker sample. This mud has experienced the downhole pressures, temperatures and contamination that cause degradation. It is evaluated for needed treatments and compared, on a lagged time basis, with the corresponding "in" or mud-in sample.

An oven into which mud-testing cells are placed. Ovens usually have a set of horizontal rollers inside and are also called roller ovens. Mud-aging cells are placed on the rollers. In pilot tests, rolling the cells allows a film of mud to continually contact the hot wall of the cell. Another type of oven tumbles cells end-to-end. Most ovens can also be used for static-aging tests.

A large tank that holds drilling fluid on the rig or at a mud-mixing plant. For land rigs, most mud pits are rectangular steel construction, with partitions that hold about 200 barrels each. They are set in series for the active mud system. On most offshore rigs, pits are constructed into the drilling vessel and are larger, holding up to 1000 barrels. Circular pits are used at mixing plants and on some drilling rigs to improve mixing efficiency and reduce dead spots that allow settling. Earthen mud pits were the earliest type of mud pit, but environmental protection concern has led to less frequent use of open pits in the ground. Today, earthen pits are used only to store used or waste mud and cuttings prior to disposal and remediation of the site of the pit.

A formal plan developed for a specific well with predictions and requirements at various intervals of the wellbore depth. The mud program gives details on mud type, composition, density, rheology, filtration and other property requirements and general and specific maintenance needs. Mud densities are especially important because they must fit with the casing design program and rock mechanics required in openhole to ensure wellbore pressures are properly controlled as the well is drilled deeper.

The report sheets filled out by the mud engineer at the wellsite on a daily basis. The mud report supplies results of tests performed several times per day as well as details about mud product usage, inventory, recommendations and other pertinent information. Multiple-copy forms in a format approved by the API, which are provided by the mud service company, are the traditional type of mud report. Today, mud reports are more likely to be computerized and transmitted electronically.

A type of nonreactive, easily differentiated material placed in a small portion of a circulating mud system at a certain time to be identified when it later returns to the surface from downhole. Mud tracers are used to determine mud cycle time (circulation time). Dyes, paints, beans, oats, chips, glitter or any material that will follow the mud and not be lost or destroyed can be used as a tracer. Care must be taken to use materials that do not dissolve, disperse or plug the bit or downhole motor. Mud tracers are distinct from mud-filtrate tracers.

What Is Mud Weight? Mud weight measures the density of drilling fluid circulating through the wellbore during drilling operations, expressed in pounds per gallon (ppg), kilograms per cubic meter (kg/m³), or specific gravity (SG). Operators adjust mud weight to balance formation pressure, suspend cuttings, stabilize the wellbore, and prevent kicks that would otherwise compromise well control. Key Takeaways Mud weight is the primary well-control parameter, generating the hydrostatic pressure that holds back formation fluids and prevents uncontrolled influx during drilling. Typical mud weights range from 8.6 ppg (1,030 kg/m³) for shallow wells in freshwater mud to 19.2 ppg (2,300 kg/m³) for HPHT wells in the Gulf of Mexico, North Sea, and Middle East. Drillers, mud engineers, and HSE supervisors all monitor mud weight continuously because small variations translate directly into thousands of psi of bottomhole pressure change. Regulatory frameworks tie mud weight to well-control competency under AER Directive 036, IADC WellSharp, IWCF certification, NORSOK D-010, and NOPSEMA guidance. Equivalent Circulating Density (ECD) extends mud weight into the dynamic case, accounting for annular friction losses during pumping and routinely exceeding static mud weight by 0.5 to 1.5 ppg (60 to 180 kg/m³). How Mud Weight Works Mud weight generates the hydrostatic pressure of the column of drilling fluid inside the wellbore, calculated as pressure in PSI equals mud weight in ppg multiplied by true vertical depth in feet multiplied by 0.052. For metric units, hydrostatic pressure in bar equals mud density in SG multiplied by true vertical depth in meters multiplied by 0.0981. At 3,000 m (9,843 ft) true vertical depth, a 1.20 SG (10 ppg) mud generates approximately 353 bar (5,119 PSI) of hydrostatic pressure at bottomhole. Operators target mud weight to sit above the pore pressure of the exposed formation and below the fracture gradient of the weakest exposed zone. This window, called the mud weight window or the drilling margin, closes in HPHT environments and in depleted reservoirs adjacent to original pressure zones. The Gulf of Mexico Wilcox, North Sea HPHT plays such as Elgin-Franklin, and Middle East deep carbonate reservoirs routinely operate with mud weight windows below 0.5 ppg (60 kg/m³), demanding tight control of both static mud weight and dynamic ECD. Field measurement uses the mud balance per API RP 13B-1, a beam balance calibrated with fresh water that reports density in ppg. Automated sensors on modern rigs read mud density continuously via Coriolis flowmeters and pressure-differential tools, feeding rig-floor displays and remote monitoring systems in Houston, Calgary, Stavanger, and Aberdeen. The mud engineer adjusts density by adding barite (specific gravity 4.2), hematite (specific gravity 5.1), or dissolved salts such as calcium chloride, calcium bromide, or formate brines for specialty applications. Mud Weight Across International Jurisdictions Mud weight sits under the broader well-control regulatory framework in every major producing country. In Canada, AER Directive 036 Drilling Blowout Prevention Requirements and Procedures requires Alberta operators to maintain mud density sufficient to control formation pressure and to log density continuously in the driller's daily report. The BCER and Saskatchewan's Ministry of Energy and Resources apply equivalent provisions. AER Directive 008 (surface casing depth) and Directive 050 (drilling waste management) tie into mud weight selection through the requirement to avoid lost circulation to shallow aquifers. In the United States, BSEE 30 CFR 250.426 requires offshore operators to use drilling fluid of sufficient density to overbalance formation pressures and to log density at least every 15 minutes during drilling. The Texas Railroad Commission, the North Dakota Industrial Commission, and the Colorado Energy and Carbon Management Commission apply parallel rules for onshore operations in the Permian, Bakken, and DJ Basin. Well-control competency for supervisors and drillers is certified through IADC WellSharp or IWCF, both of which cover mud weight as a core topic. Norway's Sodir enforces NORSOK D-010 Section 5.1 requirements on drilling fluid density, including a minimum 200 to 500 PSI (13.8 to 34.5 bar) overbalance above formation pressure at the shoe of the last cemented casing, depending on well classification. Australia's NOPSEMA applies the OPGGS Act and safety case regime to all mud weight decisions in Commonwealth offshore waters, with operators such as Woodside (Browse, Pluto), Santos (Cooper Basin), and INPEX (Ichthys) documenting mud weight rationale in well operations management plans. Middle East operators apply API RP 13D for rheology and hydraulics, with ADNOC, Saudi Aramco, Kuwait Oil Company, and Qatar Energy supplementing with internal specifications for deep HPHT and sour carbonate applications in Ghawar, Manifa, North Field, and Rumaila. Fast Facts Chevron and Shell's deepwater Gulf of Mexico HPHT wells in the Anchor, Whale, and Ballymore developments routinely drill with 17 to 19 ppg (2,040 to 2,280 kg/m³) mud at bottomhole true vertical depths of 8,500 to 10,000 m (27,887 to 32,808 ft), generating bottomhole pressures above 20,000 PSI (1,379 bar). Maintaining ECD within a 0.3 ppg (36 kg/m³) window at these depths requires continuous real-time monitoring, adaptive rheology management, and frequent mud-weight trim jobs during non-drilling hours. Equivalent Circulating Density and Dynamic Pressure Static mud weight reflects only the column density when the pumps are off. Equivalent Circulating Density (ECD) captures the dynamic pressure at any depth during circulation, summing the hydrostatic pressure of the mud column and the frictional pressure losses in the annulus above that point. ECD always exceeds static mud weight, typically by 0.2 to 1.5 ppg (24 to 180 kg/m³) depending on pump rate, hole geometry, cuttings loading, and fluid rheology. API RP 13D Rheology and Hydraulics of Oil-well Drilling Fluids defines the ECD calculation. The dynamic contribution scales with pump rate squared, which is why crews reduce pump rate when approaching a lost-circulation zone or when mud window is narrow. Pipe rotation, eccentricity of the drill string in the hole, temperature at depth, and wellbore roughness all modify ECD, and HPHT wells require temperature-corrected ECD models to prevent inadvertent fracturing of the exposed formation. Downhole pressure-while-drilling (PWD) tools, offered by all major service companies, measure actual ECD in real time at the bit. PWD data has displaced pure calculation in HPHT and narrow-margin drilling because the tool provides direct confirmation that ECD stays inside the drilling window. A sudden PWD increase signals a lost-circulation event or a kick, giving the driller minutes rather than hours to respond. Tip: Mud engineers in Fort McMurray oil sands thermal projects and in the Permian shale plays alike target specific gravity, yield point, and plastic viscosity as a coupled system. Adding only barite to a mud without adjusting viscosity and gel strength frequently causes settled barite at the bottom of the annulus, which can later dislodge as a slug and spike ECD. The benchmark practice is to treat density, rheology, and solids control as one combined specification reviewed at every tour change. Mud Weight Synonyms and Related Terminology Mud density: alternate name emphasizing the physical quantity rather than the field-unit convention. MW: standard industry abbreviation used on drilling reports and in operations chat. Mud gradient: mud weight expressed as pressure per unit depth, common in North Sea and HPHT reporting. Specific gravity (SG): dimensionless density relative to fresh water; used in metric drilling reports globally. Equivalent Mud Weight (EMW): the dynamic-equivalent density calculated from downhole pressure sensors. ECD: Equivalent Circulating Density, the dynamic case including pump-induced friction. Related terms: Drilling Fluid, Well Control, Blowout Preventer, Casing, HPHT, Horizontal Drilling, Cement. Frequently Asked Questions What is mud weight in drilling? Mud weight is the density of the drilling fluid pumped down a wellbore, measured in pounds per gallon (ppg), kilograms per cubic meter (kg/m³), or specific gravity (SG). Its primary job is to generate enough hydrostatic pressure to hold back formation fluids and prevent a kick, while remaining light enough not to fracture the exposed formation and cause lost circulation. How is mud weight calculated? Hydrostatic pressure equals mud weight in ppg multiplied by true vertical depth in feet multiplied by 0.052, yielding pressure in PSI. In metric units, pressure in bar equals specific gravity multiplied by true vertical depth in meters multiplied by 0.0981. For dynamic conditions during pumping, engineers add annular friction pressure to yield Equivalent Circulating Density (ECD), calculated per API RP 13D. What is the typical mud weight used in drilling? Onshore conventional wells in the Western Canadian Sedimentary Basin, the Permian, and the Cooper Basin typically use 8.6 to 10.5 ppg (1,030 to 1,260 kg/m³) fresh-water or low-salinity mud. HPHT wells in the Gulf of Mexico Wilcox, the North Sea Central Graben, the Middle East deep carbonates, and the Norwegian deep gas plays routinely use 14 to 19 ppg (1,680 to 2,280 kg/m³) oil-based or synthetic-based mud with barite weighting. How does mud weight affect well control? Mud weight is the primary well-control barrier. If mud weight falls below formation pore pressure, formation fluids flow into the wellbore, creating a kick that must be controlled with the BOP. If mud weight exceeds the fracture gradient of an exposed weak zone, the formation fractures and mud flows into the rock, causing lost circulation and potentially triggering an underground blowout. Balancing mud weight between these limits is the central well-design challenge. What is ECD in drilling? Equivalent Circulating Density (ECD) is the effective mud weight at any depth during active circulation, combining the static hydrostatic pressure and the dynamic frictional pressure losses in the annulus. ECD always exceeds static mud weight, and HPHT or narrow-margin wells are designed around ECD rather than static mud weight to avoid inadvertent formation breakdown. Pressure-while-drilling (PWD) tools measure ECD directly at the bit in real time. Why Mud Weight Matters in Oil and Gas Mud weight is the single lever a drilling crew adjusts most frequently and with the largest consequences. A quarter-pound-per-gallon swing in mud density changes bottomhole pressure by hundreds of PSI, enough to provoke a kick in Alberta, lose circulation in the North Sea, or fracture a thermal reservoir in Alberta oil sands. For the mud engineer running a barite trim on a drilling rig in the Montney, the well-control instructor teaching IWCF Level 4 in Aberdeen, and the portfolio manager tracking HPHT well cost overruns in deepwater Gulf of Mexico, mud weight sits at the intersection of physics, regulation, and capital efficiency across every drilling jurisdiction on the planet.

A cylindrical vessel in which a mud sample can be heated under pressure. Cells, often called bombs, are routinely used for static-aging and hot-roll aging of mud samples. Cells are usually made of metal or metal alloy, such as stainless steel or aluminum bronze, and have open tops. Caps should be fitted with a valve so that gas pressure can be applied and then released before opening the cell. Common sizes are 260 and 500 cm3, to accommodate half- and one-barrel equivalent volumes, plus space for thermal expansion. Glass or plastic jars can be used judiciously when pressure is nil and temperature is limited to below about 150°F [66°C].

A mud sample taken from the suction pit (the last pit in the flow series) just before the mud goes into the pump and down the wellbore. The in sample is also called the suction-pit sample, or "mud in" on a drilling fluid report. This mud has been treated and properly weighted and is in good condition to encounter downhole pressures, temperatures and contamination. Comparisons are made between properties of this mud-in sample and the "out" or mud-out sample taken at surface prior to solids removal.

A mud sample taken after it has passed from the flowline and through the shale shaker screens to remove large cuttings. The out sample is also called the shale shaker sample. This mud has experienced the downhole pressures, temperatures and contamination that cause degradation. It is evaluated for needed treatments and compared, on a lagged time basis, with the corresponding "in" or mud-in sample.

The action of coatingrock grains and plugging off the permeability of a productive reservoir during drilling. The term is seldom used today, but refers to formation damage by mud solids. By proper selection of solids, such as bridging materials and drill-in fluids, mudding off can be minimized.

The act of adding commercial materials to convert water or a water-clayslurry into a mud. Mudding up is usually done after drilling a well to a certain depth with relatively inexpensive spud mud or other native-clay mud, or with water or air. By delaying the use of drilling fluid, operators can save money in the initial stages of drilling a well.

A fine-grained detritalsedimentaryrock formed by consolidation of clay- and silt-sized particles. Mudrocks are highly variable in their clay content and are often rich in carbonate material. As a consequence, they are less fissile, or susceptible to splitting along planes, than shales. Mudrocks may include relatively large amounts of organic material compared with other rock types and thus have potential to become rich hydrocarbonsource rocks. The typical fine grain size and low permeability, a consequence of the alignment of their platy or flaky grains, allow mudrocks to form good cap rocks for hydrocarbon traps. However, mudrocks are also capable of being reservoir rocks, as evidenced by the many wells drilled into them to produce gas.

A device for measuring in situ the velocity of fluid flow in a production or injection well by measuring the transit time of a disturbance between two dielectric sensors a fixed distance apart. The device is a type of crosscorrelation flowmeter that uses several pairs of capacitance, or dielectric, sensors held on an arm to span the borehole.

Seismic data acquired in a land, marine, or borehole environment by using more than one geophone or accelerometer. 3C seismic data, a type of multicomponent seismic data, uses three orthogonally oriented geophones or accelerometers. 4C seismic data, another type of multicomponent seismic data, involves the addition of a hydrophone to three orthogonally oriented geophones or accelerometers. 3C multicomponent seismic data is particularly appropriate when the addition of a hydrophone (the basis for 4C seismic data) adds no value to the measurement, for example, on land. This technique allows determination of both the type of wave and its direction of propagation.

A device for measuring the diameter of the internal wall of a casing or tubing using multiple arms. By using a large number of arms, or fingers, the caliper can detect small changes in the wall of the pipe. The main purpose of the measurement is to detect deformations, the buildup of scale or metal loss due to corrosion. Typical multifinger calipers have between about 20 and 80 fingers, the larger numbers being necessary in larger pipes.

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.

A technique for interpreting the results from a spinner flowmeter using several logging runs of the flowmeter over the zone of interest at different speeds, both up and down. Spinner speed is a nearly linear function of the effective velocity of the fluid. Although this function can be measured on surface, it varies with the fluid and is most reliably determined in situ. After several passes are made, the function can be calibrated and the spinner speed converted into flow rate.The technique is applicable when the flow is single phase, or else multiphase with a sufficiently homogeneous flow regime such as with emulsion or dispersed bubble flow.

Referring to a fluid with several different immiscible fluids (oil, water or gas).

The simultaneous flow of more than one fluid phase through a porous medium. Most oil wells ultimately produce both oil and gas from the formation, and often produce water. Consequently, multiphase flow is common in oil wells. Most pressure-transient analysis techniques assume single-phase flow.

A fluid, generally a liquid, comprising more than one phase, such as water- or oil-based liquids, solid material or gas. Multiphase fluids and their behavior are of concern in two main areas, the flow of multiphase fluids and the separation of the various phases at surface.

The commingled flow of different phase fluids, such as water, oil and gas. Multiphasefluid flow is a complex factor, important in understanding and optimizing production hydraulics in both oil and gas wells. Four multiphase fluid flow regimes are recognized when describing flow in oil and gas wells, bubble flow, slug flow, transition flow and mist flow.

A record of the fractions of different fluids present at different depths in the borehole. In single-phase flow, the holdup is unity and has no meaning, so that any holdup log is, by definition, a multiphase holdup log.

A device that can register individual fluid flow rates of oil and gas when more than one fluid is flowing through a pipeline. A multiphase meter provides accurate readings even when different flow regimes are present in the multiphase flow. When using single-phase meters, the fluid mixture (oil and gas) coming from the wellbore must pass through a fluid-separation stage (separator) prior metering. Otherwise, the readings of the single-phase meters will be inaccurate. Separators are not necessary for multiphase metering, and the meters can support different proportions of gas and oil. Multiphase meters provide the advantage of continuous well monitoring, which is not possible using single-phase meters. Additionally, multiphase meters cost less, weigh less and require less space. Multiphase meters are more common in deepwater operations, where well-intervention operations are often prohibitively expensive.

A pump that can handle the complete production from a well (oil, natural gas, water and sand, for example) without needing to separate or process the production stream near or at the wellhead. This reduces the cost associated with the surface facilities.Using multiphase pumps allows development of remote locations or previously uneconomical fields. Additionally, since the surface equipment, including separators, heater-treaters, dehydrators and pipes, is reduced, the impact on the environment is also reduced.Multiphase pumps can handle high gas volumes as well as the slugging and different flow regimes associated with multiphase production. Multiphase pumps include twin-screw pumps, piston pumps and helicoaxial pumps.

A single wellbore having tubulars and equipment that enable production from two or more reservoir zones. In most cases, at least two tubing strings will be used to provide the necessary level of control and safety for production fluids. However, in some simple dual completions, the second or upper zone is produced up the tubing-casingannulus. The wellhead and surface flow-control facilities required for multiple completions can be complex and costly; hence, multiple completions are relatively uncommon.

Multiply reflected seismic energy, or any event in seismic data that has incurred more than one reflection in its travel path. Depending on their time delay from the primary events with which they are associated, multiples are characterized as short-path or peg-leg, implying that they interfere with the primary reflection, or long-path, where they appear as separate events. Multiples from the water bottom (the interface of the base of water and the rock or sediment beneath it) and the air-water interface are common in marine seismic data, and are suppressed by seismic processing.

Regression techniques that find relationships between two or more variables that have a complex (nonlinear) relationship. Porosity and permeability relationships are often of this form in rocks that have multiple porosity types (primary, intergranular, fracture or vugular porosity, for example) or multiple cement types and other variables that affect permeability.

A technique used for the determination of the electrical properties of a shalycore sample. The sample is flushed with brines of different salinities, and the conductivity determined after each flush. A plot of the conductivity of the sample (C0) versus the conductivity of the brine (Cw) gives the excess conductivity caused by clays and other surface conductors. Then, using a suitable model (Waxman-Smits, dual water, SGS) it is possible to determine the intrinsic formation factor and porosity exponent, and the cation-exchange capacity.

A contract between a host country and an operator that specifies the services and costs of services that the operator must use in the development of a concession.

A dynamic fluid-mixing process in which an injected gas exchanges components with in situ oil until the phases achieve a state of miscibility within the mixing zone of the flood front. In a vaporizing drive, light and intermediate components from the oil phase enter the gas phase. By contrast, in a condensing drive, intermediate components from the gas phase enter the oil phase. The process may be a combination of vaporizing and condensing drives.

A record of the quantity of different radioactive isotopes near the borehole. The technique used is the same as for natural gamma ray spectroscopy, but measures the quantities of various short half-life radioactive tracers in addition to natural gamma rays. The log is run to monitor the results of processes that can be tagged, for example, hydraulic fracturing, gravel-pack placement, squeezecementing, acid treatment and lost-circulation detection. Different radioactive tracers are added at different stages of the process so that by measuring the different tracers, it is possible to track the development, for example, of the fracture. The most common radioactive tracers are 110Ag (silver), 195Au (gold), 135I (iodine), 192Ir (iridium), 124Sb (antimony), and 46Sc (scandium).

The technique used to produce a multiple-isotope log.

Tests conducted at a series of different flow rates for the purpose of determining well deliverability, typically in gas wells where non-Darcy flow near the well results in a rate-dependent skin effect. Multiple-rate tests are sometimes required by regulatory bodies.

A technique for determining the deviation of a wellbore. The multishot tool provides more accuracy than the single-shot tool and is usually used in highly deviated wells.

To remove the contribution of selected seismic traces in a stack to minimize air waves, ground roll and other early-arriving noise. Low-frequency traces and long-offset traces are typical targets for muting.

A chemical additive for stimulation treatments that is soluble in oil, water and acid-based treatment fluids. Mutual solvents are routinely used in a range of applications, such as removing heavy hydrocarbon deposits, controlling the wettability of contact surfaces before, during or after a treatment, and preventing or breaking emulsions. A commonly used mutual solvent is ethyleneglycolmonobutyl ether, generally known as EGMBE.

The common name for the small shrimp species Mysidopsis bahia, which is used as the test organism in a US EPA bioassay test protocol.