Oil and Gas Terms Beginning with “H”

What Is H2S? H2S (hydrogen sulfide) is a colorless, acutely toxic gas that forms naturally during the anaerobic decomposition of organic matter and occurs alongside hydrocarbons in many oil and gas reservoirs worldwide. Any well, pipeline, or processing facility handling fluids that contain H2S above the sour-service threshold requires specialized equipment, well control procedures, and emergency response planning to protect personnel and infrastructure. H2S is closely related to drilling fluid contamination, casing material selection, and blowout preventer design in sour-service wells. Key Takeaways H2S has a molecular weight of 34.08 g/mol and a density of approximately 1.19 g/L at standard conditions, making it roughly 1.19 times heavier than air and prone to accumulating in low-lying areas such as sumps, cellars, and tanks. The gas is detectable by its characteristic rotten-egg odor at concentrations as low as 0.5 parts per million (ppm), but olfactory fatigue occurs above 100 ppm (0.0001%), rendering smell an unreliable warning at dangerous concentrations. Regulatory bodies worldwide define "sour gas" differently, but the most widely cited threshold is an H2S partial pressure exceeding 0.3 kPa (0.05 psi) in the gas phase, as established by NACE MR0175/ISO 15156, which triggers mandatory sour-service metallurgy requirements. H2S causes sulfide stress cracking (SSC) and hydrogen-induced cracking (HIC) in high-strength steels, requiring downgraded yield strength limits and specific heat treatment for downhole tubulars, wellhead equipment, and surface facilities. Emergency response to H2S events centers on mustering upwind at designated assembly points, donning self-contained breathing apparatus (SCBA) with a minimum 30-minute supply, and using fixed and portable gas detection systems to confirm safe re-entry concentrations below 1 ppm. How H2S Forms and Behaves in Oilfield Environments Hydrogen sulfide originates from two primary sources in petroleum systems. Thermogenic H2S forms when sulfate-bearing minerals such as anhydrite (CaSO4) react with hydrocarbons at elevated reservoir temperatures, a process called thermochemical sulfate reduction (TSR), which dominates in deep, high-temperature carbonate reservoirs above approximately 150 degrees Celsius (302 degrees Fahrenheit). Biogenic H2S is generated by sulfate-reducing bacteria (SRB) that metabolize sulfate ions in the presence of organic matter at lower temperatures, a mechanism responsible for H2S generation in shallow reservoirs, produced water disposal wells, and drilling mud tanks containing water-based muds. Both sources can coexist in a single field, complicating scavenger selection and corrosion management strategies. At standard temperature and pressure (15 degrees Celsius / 59 degrees Fahrenheit, 101.325 kPa / 14.696 psi), H2S boils at -60 degrees Celsius (-76 degrees Fahrenheit) and exists as a gas. Its flammable range in air spans from 4.3% to 46% by volume, a wide band that makes ignition a persistent risk when gas accumulates in confined spaces. The gas dissolves readily in water, forming a weak acid (hydrosulfuric acid), which accelerates corrosion of carbon steel and contributes to the formation of iron sulfide (FeS) scale deposits that can plug perforations, wellbore tubulars, and surface equipment. In drilling fluid, H2S influx from a formation enters the mud column, drops the pH, and can form pyrophoric iron sulfide when metal surfaces corrode, creating a secondary fire hazard. The physiological effect of H2S on the human body is rapid and concentration-dependent. At 0.5 to 5 ppm, the characteristic odor is detectable. At 10 ppm (the OSHA permissible ceiling for general industry), eye irritation begins. At 50 ppm (OSHA immediately dangerous), rapid onset incapacitation can occur. The U.S. National Institute for Occupational Safety and Health (NIOSH) sets the immediately dangerous to life and health (IDLH) value at 100 ppm (0.0001%). Concentrations between 300 and 500 ppm (0.0003 to 0.0005%) cause pulmonary edema and can be fatal within 30 to 60 minutes. At 1,000 ppm (0.001%) and above, nearly instantaneous collapse and death from respiratory paralysis occur. These thresholds underpin the detection alarm setpoints and evacuation criteria used across the global industry. H2S Regulations Across International Jurisdictions Canada's Alberta Energy Regulator (AER) governs sour gas operations through AER Directive 071 (Emergency Preparedness and Response Requirements for the Petroleum Industry), which mandates that operators of wells with an H2S release potential above 0.1 m3/s (at the critical well flow rate) develop and submit an Emergency Response Plan (ERP) before spudding. The Canadian Association of Petroleum Producers (CAPP) publishes complementary guidance, including its "H2S Safety in the Oil and Gas Industry" document, which is widely adopted as industry best practice throughout western Canada. British Columbia Oil and Gas Commission (BCOGC) regulations mirror AER thresholds for sour-service classification in the Montney and Horn River formations, where H2S concentrations frequently exceed 1% by volume in produced gas streams. AER Directive 056 covers energy development applications and requires disclosure of H2S content at test conditions for every well in Alberta. In the United States, the Occupational Safety and Health Administration (OSHA) regulates H2S worker exposure under 29 CFR 1910.1000 (general industry) and 29 CFR 1926.55 (construction), setting a permissible exposure limit (PEL) of 20 ppm as a ceiling concentration with a 50 ppm peak for a maximum 10 minutes once per shift when no other exposure occurs in that shift. The Bureau of Safety and Environmental Enforcement (BSEE) applies Notices to Lessees (NTLs) and 30 CFR Part 250 requirements to offshore sour wells in the Gulf of Mexico, mandating H2S contingency plans for any well with a surface H2S concentration that could exceed 20 ppm in the work area. The American Petroleum Institute (API) publishes RP 49 (Recommended Practice for Safe Drilling of Wells Containing Hydrogen Sulfide) and RP 55, both of which are incorporated by reference into many state and federal regulations. In Australia, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates H2S hazard management under the Offshore Petroleum and Greenhouse Gas Storage Act 2006, requiring operators to demonstrate as-low-as-reasonably-practicable (ALARP) risk reduction through formal safety cases. Safe Work Australia's Workplace Exposure Standards for Airborne Contaminants sets an 8-hour time-weighted average (TWA) of 1 ppm and a short-term exposure limit (STEL) of 5 ppm for H2S, significantly more conservative than OSHA limits and reflecting the Australian precautionary approach to toxic gas exposure in the Cooper Basin, Browse Basin, and offshore Carnarvon Basin fields where sour gas is produced. In the Middle East, Abu Dhabi National Oil Company (ADNOC) operates some of the world's largest sour gas fields, including the Khursaniyah and Haradh gas developments in Saudi Arabia (operated by Saudi Aramco) and the Shah Gas Field in Abu Dhabi, which has an H2S concentration of approximately 23% in raw gas. Saudi Aramco's General Instruction GI-0002.102 governs H2S safety across all Aramco operations, specifying detector placement, alarm levels, and evacuation procedures that exceed many international minimums due to the extreme concentrations encountered. The Shah Gas Plant, commissioned by ADNOC in partnership with Occidental Petroleum, processes over 1 billion standard cubic feet per day (Bcfd) of sour gas and represents one of the most technically complex H2S abatement projects in history, producing approximately 2,000 tons per day of elemental sulfur as a byproduct. In Norway and the North Sea, NORSOK Standard S-001 (Technical Safety) and NORSOK Z-013 (Risk and Emergency Preparedness Assessment) form the primary technical framework for H2S hazard management on offshore installations. The Norwegian Petroleum Safety Authority (Ptil) enforces these through the Facilities Regulations and Activities Regulations. ConocoPhillips' Ekofisk field in the Norwegian sector of the North Sea produces gas with H2S concentrations up to 0.4% and has operated sour-service production since the 1970s, serving as a reference case for North Sea sour well completion design. Equinor (formerly Statoil) applies company-specific engineering standards TR2000 and TR3000 for materials selection in sour service, supplementing NACE MR0175/ISO 15156 requirements across its offshore portfolio. Fast Facts The Shah Gas Field in Abu Dhabi, operated by ADNOC Gas Processing, processes raw gas containing approximately 23% H2S (230,000 ppm) and produces roughly 5,000 tonnes of elemental sulfur per day as a byproduct of sweetening operations. The plant uses a proprietary high-pressure amine treating process at operating pressures exceeding 9,600 kPa (1,400 psi) and is one of the few facilities in the world designed to safely handle H2S at these concentrations at commercial scale. H2S Detection, Monitoring, and Gas Detection Systems Reliable H2S detection is the first line of defense in any sour-service operation. Three categories of detection equipment are standard across the global industry. Personal gas monitors (PGMs) are worn by all personnel entering H2S-risk areas. These electrochemical sensor devices continuously sample the atmosphere at breathing zone height and alarm at two setpoints: a low alarm at 5 to 10 ppm (industry standard; AER Directive 071 recommends a low alarm at 10 ppm) and a high alarm at 15 to 20 ppm. Common PGM models include the MSA Altair, Industrial Scientific GasBadge Pro, and Drager Pac series. Sensor cartridges require calibration every 6 months or per manufacturer specification and must be bump-tested before each use in H2S-prone environments. Fixed gas detection systems provide area coverage at strategic points including the wellhead, choke manifold, pit room, shale shaker area, and gas outlet of the degasser. These detectors are typically electrochemical (for low-concentration accuracy) or catalytic bead (for wide-range detection including flammable concentration measurement). Fixed detectors integrate with the facility's safety instrumented system (SIS), triggering audible and visual alarms, initiating HVAC shutdown on occupied modules, and, in fully automated facilities, activating deluge systems or emergency shutdown valves (ESDs) at H2S concentrations above programmable setpoints. The International Electrotechnical Commission (IEC) 60079 series governs the design of explosion-proof (Ex d) and intrinsically safe (Ex ia/ib) detector housings for use in Zone 1 and Zone 2 classified areas. Colorimetric Drager tubes remain a quick, low-cost verification tool for spot measurements. The tubes use a chemical reaction to produce a color change proportional to H2S concentration, with measurement ranges from 0.2 to 5 ppm (precision tubes) up to 200 ppm (high-concentration survey tubes). While not a substitute for continuous monitoring, Drager tubes are used during confined space entry pre-checks, post-maintenance re-entry assessments, and rapid field diagnostics when electronic equipment is unavailable or undergoing calibration. Wind socks and wind direction indicators are mandatory at all sour well sites and gas processing facilities under AER Directive 071 and API RP 49, because H2S is heavier than air and disperses along terrain contours. Muster stations must be positioned upwind of the likely release source in the prevailing wind direction, with secondary muster points designated for wind shifts. Site operators are required to conduct pre-job H2S orientations with all rig crews and visitors, documenting attendance and content. Helicopter landing zones at offshore and remote onshore sour well sites must have H2S monitoring and personnel must be equipped with escape breathing devices (EBDs) with a minimum 10-minute supply for emergency egress from enclosed spaces.

Abbreviation for held by production.

(noun) Chemical formula for hydrochloric acid. A strong mineral acid widely used in well stimulation and matrix acidising to dissolve carbonate formations, remove scale deposits, and improve near-wellbore permeability. HCl is typically pumped downhole at concentrations of 15% to 28% by weight, often combined with corrosion inhibitors and other additives to protect tubulars.

A nonionic starch derivative, analogous to hydroxyethylcellulose in its method of manufacture and most applications for drilling, workover and completion fluids. Rather than using a cellulosic starting material, such as hydroxyethylcellulose (HEC), starch is used instead, and reacted with ethylene oxide in an alkaline environment.

A nonionic cellulose derivative with hydroxyethyl groups attached to the polymerstructure. HEC is used as a viscosifier in brines and saline fracturing fluids, workover fluids, completion fluids and drill-in fluids. It gives pseudoplasticrheology but essentially no gel strength development. HEC offers little fluid-loss control, other than its rheological effects. HEC is seldom used in drilling fluids. Cellulose fibers are reacted with caustic soda and ethylene oxide to form HEC. Hydroxyethyl groups attach to the OH groups of the polysaccharide structure by ether linkages. A high degree of substitution (from 1.5 to 2.5 out of 3 maximum) gives HEC superior solubility in water and various brines. Being nonionic, it is not precipitated by hardness ions and disperses well at high salinity. HEC is not degraded by common bacteria.

(noun) Chemical formula for hydrofluoric acid. A highly reactive acid used in combination with hydrochloric acid (mud acid) to dissolve siliceous minerals, clays, and fine particles in sandstone formations during matrix acidising treatments, restoring or improving permeability in the near-wellbore region.

Dense solids, such as barite or hematite, which are added to a mud to increase its density, also known as weighting material. The concentration of high-gravity solids in a weighted mud is measured by the mud engineer daily using mud weight, retort data, chloride titration data and other information. Solids are reported as lbm/bbl or vol.%. The specific gravity of water is 1.00, barite is 4.20, and hematite 5.505 g/cm3. Drill solids and other low-gravity solids are normally assumed to be 2.60 g/cm3.

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

A number on the scale of one to 40 according to the HLB system, introduced by Griffin (1949 and 1954). The HLB system is a semi-empirical method to predict what type of surfactant properties a molecular structure will provide. The HLB system is based on the concept that some molecules have hydrophilic groups, other molecules have lipophilic groups, and some have both. Weight percentage of each type of group on a molecule or in a mixture predicts what behavior the molecular structure will exhibit. Water-in-oil emulsifiers have a low HLB numbers, typically around 4. Solubilizing agents have high HLB numbers. Oil-in-water emulsifiers have intermediate to high HLB numbers.Reference:Griffin WC: "Classification of Surface-Active Agents by 'HLB,'" Journal of the Society of Cosmetic Chemists 1 (1949): 311.Reference:Griffin WC: "Calculation of HLB Values of Non-Ionic Surfactants," Journal of the Society of Cosmetic Chemists 5 (1954): 259.

Hydroxypropyl starch is a derivative of natural starch, used primarily for fluid-loss control in drilling muds, drill-in, completion and workover fluids. Being nonionic, it is only slightly affected by salinity and hardness in fluids. Linear and branched carbohydrate polymers in natural starch have three reactive OH groups on each glucose unit. During manufacture, these polymers are reacted with propylene oxide, adding hydroxypropyl (CH(OH)CH2CH3) groups at the OH positions by an ether linkage. By adding the hydroxypropyl groups, the HP starch becomes more resistant to thermal degradation and bacterial attack.

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

A test to measure static filtration behavior of water mud or oil mud at elevated temperature, up to about 380°F [193°C] maximum (450°F [227°C] maximum if a special cell is used), usually according to the specifications of API. Although the test can simulate downhole temperature conditions, it does not simulate downhole pressure. Total pressure in a cell should not exceed 700 psi [4900 kPa], and the differential pressure across the filtermedium is specified as 500 psi [3500 kPa]. Because these cells are half the size of the ambient filtration area, HPHTfiltrate volumes after 30 minutes are doubled.

A type of viscometer generally used in laboratories to test drilling fluids at simulated downhole conditions.

Abbreviation for health, safety and environmental. These three issues are of paramount importance to the drilling and drilling fluids community, as they are to the entire petroleum industry. Adherence to HSE guidelines is a requirement for operators worldwide and is also dictated by internal policies of most corporations.

The point or depth at which a tool or drift of a specific size can no longer pass through the wellbore. A higher than expected holdup depth may result from scale, fill, distortion of the wellbore tubulars or formation movement in an openholecompletion.

A type of drillpipe whose walls are thicker and collars are longer than conventional drillpipe. HWDP tends to be stronger and has higher tensile strength than conventional drillpipe, so it is placed near the top of a long drillstring for additional support.

Hardfaced alloys welded onto drill pipe tool joints, collars, and heavy-weight pipe to protect the drill string from wear.

Like drill pipe, but with a heavier walled thickness and stiffer, used for a flexible transition between the drill collars and the drill pipe.

A fluid described by a three-parameterrheologicalmodel. A Herschel-Bulkley fluid can be described mathematically as follows: The Herschel-Bulkley equation is preferred to power law or Bingham relationships because it results in more accurate models of rheological behavior when adequate experimental data are available. The yieldstress is normally taken as the 3 rpm reading, with the n and K values then calculated from the 600 or 300 rpm values or graphically.Reference:Hemphill T, Campos W and Pilehvari A: "Yield-Power Law Model More Accurately Predicts MudRheology," Oil & Gas Journal 91, no. 34 (August 23, 1993): 45-50.

A fluid described by a three-parameterrheologicalmodel. A Herschel-Bulkley fluid can be described mathematically as follows: The Herschel-Bulkley equation is preferred to power law or Bingham relationships because it results in more accurate models of rheological behavior when adequate experimental data are available. The yieldstress is normally taken as the 3 rpm reading, with the n and K values then calculated from the 600 or 300 rpm values or graphically.Reference:Hemphill T, Campos W and Pilehvari A: "Yield-Power Law Model More Accurately Predicts Mud Rheology," Oil & Gas Journal 91, no. 34 (August 23, 1993): 45-50.

The slope of the chosen straight-line section of a Horner plot. It is used to determine permeability thickness, kh, of the producing zone in the vicinity of the wellbore.

A method for detecting patterns of points in binary data sets. Data pairs on a plot are assigned slopes and offsets and then replotted in slope and offset space. The method has been used on wirelinecurve data and on image data, where dips and azimuths are used. The Hough transform can be used to obtain the Buckles number.Reference:Hough PVC: A Method and Means for Recognizing Complex Patterns, U.S. Patent No. 3,069,064, 1962.

A particular relation between the formation factor (F) and porosity (phi) proposed by the Humble Oil Company. The original formula was expressed as F = 0.62 / phi2.15. A nearly equivalent form, with a simpler porosity exponent, is F = 0.81 / phi2. These formulae are considered most suitable for relatively high-porosity, sucrosic, or granular, rocks.See Winsauer WO, Shearin HM, Masson PH and Williams M: Resistivity of Brine-Saturated Sands in Relation to Pore Geometry, AAPG Bulletin 36 (1952): 253-277.

[NaCl]A soft, soluble evaporitemineral commonly known as salt or rock salt. Because salt is less dense than many sedimentary rocks, it is relatively buoyant and can form salt domes, pillars or curtains by flowing and breaking through or piercing overlying sediments, as seen in the Gulf of Mexico and the Zagros fold belt. Halite can be critical in forming hydrocarbon traps and seals because it tends to flow rather than fracture during deformation, thus preventing hydrocarbons from leaking out of a trap even during and after some types of deformation.

An anomaly that occurs as a ring around a feature, such as electrical or geochemical rings around hydrocarbon accumulations.

A term applied to hard rocks, or igneous and metamorphic rocks that are distinguished from sedimentary rocks because they are typically more difficult to disaggregate. Well cemented sedimentary rocks are sometimes described as being hard, but are usually called soft rock. The term can be used to differentiate between rocks of interest to the petroleum industry (soft rocks) and rocks of interest to the mining industry (hard rocks).

Water that contains hardness ions.

A process in which a wear-resistant alloy is applied to the tool joints of drillpipe or drill collars to prolong the life of oilfieldtubulars. Hardbanding is applied where rotational and axial friction associated with drilling and tripping create excessive abrasive wear between drillstring and casing. Hard alloy overlays are applied to the points of greatest contact, typically using advanced welding techniques. The alloys used in this process range from ultra-wear resistant tungsten carbide, to less abrasive chromium carbide, titanium carbide and borides.

A horizon cemented by precipitation of calcite just below the sea floor. Local concretions form first in a hardground and can be surrounded by burrows of organisms until the cement is well developed.

One of three divalent cations that can be present in water, including calcium (Ca+2), magnesium (Mg+2) and ferrous (Fe+2, a form of iron). Hardness ions develop from dissolved minerals, bicarbonate, carbonate, sulfate and chloride. Bicarbonate salts cause temporary hardness, which can be removed by boiling the water and leaving behind a calcium carbonate solid. Mg+2 and Fe+2 ions can be removed by raising the pH (with NaOH or KOH) and then allowing the precipitated Fe(OH)2 and Mg(OH)2 to settle out. Calcium hardness can be removed by adding excess sodium carbonate to precipitate Ca+2 as CaCO3. Hard water can be passed through an ion exchange column where hardness ions are captured on the resin. Removal of hardness is the process called water softening.

A particular frequency at which a data set has a resonance, or the frequency has special significance.

A nonlinear change in waveform in which simple multiples of (1,2, ... n times) the input frequencies, or harmonics, are generated.

An opening in the top of a tank through which samples are taken or inspection is made.

The device that connects the end of the loggingcable or the bridle to the top of the logging tool. It contains the weak point, so that when the weak point is broken and the cable removed, the uppermost assembly left in the hole is the head. The top of the head is specially designed to ease fishing of the logging tool, and is also known as the fishing bell.

A pressurewave in the borehole fluid generated by the passage of either the acousticcompressional wave or the shear wave in the formation. These pressure waves are recorded by logging tools using hydrophones and are the basis for the sonic log. A head wave is generated only when the compressional or the shear speed is faster than the fluid speed. In slow formations, where the shear speed is less than the fluid speed, no shear head wave is created.

In a gathering system, a pipe arrangement that connects flowlines from several wellheads into a single gathering line. A header has production and testing valves to control the flow of each well, thus directing the produced fluids to production or testing vessels.Individual gas/oil ratios and well production rates of oil, gas and water can be assigned by opening and closing selected valves in a header and using individual metering equipment or separators.

A small box mounted on a shaker screen that takes drilling fluid from the return flow line and distributes it across the surface of the screens via adjustable weirs.

The first page or pages on a log print, which include information about the well, the survey, the mud properties and other relevant data.

Equipment that transfers heat to the produced gas stream.Heaters are especially used when producing natural gas or condensate to avoid the formation of ice and gas hydrates. These solids can plug the wellhead, chokes and flowlines.The production of natural gas is usually accompanied by water vapor. As this mixture is produced, it cools down on its way to the surface and also when the mixture passes through a surface production choke. This reduction of fluid temperature can favor the formation of gas hydrates if heaters are not used.Heaters may also be used to heat emulsions before further treating procedures or when producing crude oil in cold weather to prevent freezing of oil or formation of paraffin accumulations.

(noun) A surface production vessel that combines heat exchange and gravity separation to break oil-water emulsions and separate produced fluids. The heater section raises the temperature of the emulsion to reduce oil viscosity and weaken the interfacial film, while the treater section provides residence time for gravitational separation of oil and water.

In general chemistry, the term refers to metals that are more dense than iron, although some texts and chemical dictionaries do not recognize this as a chemical term.

Crude oil with high viscosity (typically above 10 cp), and high specific gravity. The API classifies heavy oil as crudes with a gravity below 22.3° API. In addition to high viscosity and high specific gravity, heavy oils typically have low hydrogen-to-carbon ratios, high asphaltene, sulfur, nitrogen, and heavy-metal content, as well as higher acid numbers.

An operating condition during a snubbing operation in which the force resulting from the weight of the pipe or tubing string is greater than the wellheadpressure and the buoyancy forces acting to eject the string from the wellbore. In the heavy-pipe condition, the string will drop into the wellbore if the gripping force is lost.

A type of drillpipe whose walls are thicker and collars are longer than conventional drillpipe. HWDP tends to be stronger and has higher tensile strength than conventional drillpipe, so it is placed near the top of a long drillstring for additional support.

A claymineral similar in structure to bentonite but with more negative charges on its surface. Organophilic hectorite, made by the wet process, is a premium performance additive for use in oil-base drilling mud.

A provision in an oil, gas and minerallease that perpetuates a companys right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas. Also abbreviated as HBP.

The mineral form of ferric oxide [Fe2O3]. The hematite ore used as a weighting material in drilling muds has a mica-like crystal structure that grinds to particle size suitable for use in drilling fluids. To check for potential wear, an abrasion test is usually run on hematite as a quality control pilot test.

The unit of measurement of frequency, equivalent to one cycle per second and symbolized by Hz. The unit is named after German physicist Heinrich Hertz (1857 to 1894), who discovered electromagnetic waves.

A technique used in squeezecementing whereby a portion of the slurry is pumped, then pumping stops to expose the slurry to differential pressure against the zone of interest in stages over a period from several minutes to several hours. This pressure, higher than necessary for fluid movement, is applied to force the cement slurry into the area requiring repair. This staged procedure is repeated until all the slurry has been pumped or until no further slurry can be placed into the treatment zone. The cement remaining in the zone forms an effective hydraulic seal with a high compressive strength.

The quality of variation in rock properties with location in a reservoir or formation. Shale gas reservoirs are heterogeneous formations whose mineralogy, organic content, natural fractures, and other properties vary from place to place. This heterogeneity makes petroleum system modeling, formation evaluation, and reservoir simulation critical to maximizing production from shale reservoirs.

Formation with rock properties changing with location in the reservoir. Some naturally fractured reservoirs are heterogeneous formations.

A cessation in deposition of sediments during which no strata form or an erosional surface forms on the underlying strata; a gap in the rock record. This period might be marked by development of a lithified sediment (hardground) or burrowed surface characteristic of periods when sea level was relatively low. A disconformity can result from a hiatus.

A method of cluster analysis in which the distance between every pair of data points is determined and the relative distances displayed on a dendogram. This method is completely accurate but is very CPU intensive when the data set has a large number of data points. For large numbers of data points, the k-means method is usually preferred.This method is sometimes used after the data have first been transformed into their principal components. The method is one possible approach to electrofacies calculations.

Chemical explosive material having an extremely high reaction rate that creates very high combustion pressures, unlike low explosives that have a much lower reaction rate and are commonly used as propellants. High explosives are further categorized as primary- and secondary-high explosive. Primary-high explosives are very sensitive, can be detonated easily and are generally used only in percussion and electrical detonators. Secondary-high explosives are less sensitive, require a high-energy shock wave to achieve detonation and are safer to handle. Secondary-high explosives are used in almost all elements of a ballistic chain, other than the detonator, such as in detonating cord and shaped charges.

Equipment or systems used for completion of wells in thermal production of heavy oil.

Dense solids, such as barite or hematite, which are added to a mud to increase its density, also known as weighting material. The concentration of high-gravity solids in a weighted mud is measured by the mud engineer daily using mud weight, retort data, chloride titration data and other information. Solids are reported as lbm/bbl or vol.%. The specific gravity of water is 1.00, barite is 4.20, and hematite 5.505 g/cm3. Drill solids and other low-gravity solids are normally assumed to be 2.60 g/cm3.

An enhanced oil recovery process utilizing compressed air that is injected into a reservoir. Oxygen in the gas reacts exothermically with some of the oil, producing highly mobile flue gas. The flue gas advances ahead of the reaction front and achieves an efficient displacement of the in situ oil. Scientists believe that the high displacement efficiency of high-pressure air injection is due to a combination of processes that include immiscible gas displacement, improved miscibility caused by the presence of CO2 in the flue gas, reduction in interfacial tension, oil swelling and reservoir repressurization. The process is typically used for deep, tight, relatively light-oil reservoirs where water injectivity is low.

A squeeze-cementing technique involving the application of treatment pressure that is higher than the fracture pressure of the formation. This procedure may be necessary to force the slurry into microcracks or annuli that surround the wellbore. The characteristics of a fracture are dependent on the fluid flow rate when the fracture is initiated; consequently, high-pressure squeeze operations must be conducted with a high degree of control to place the slurry in the desired location.

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

A test to measure static filtration behavior of water mud or oil mud at elevated temperature, up to about 380°F [193°C] maximum (450°F [227°C] maximum if a special cell is used), usually according to the specifications of API. Although the test can simulate downhole temperature conditions, it does not simulate downhole pressure. Total pressure in a cell should not exceed 700 psi [4900 kPa], and the differential pressure across the filter medium is specified as 500 psi [3500 kPa]. Because these cells are half the size of the ambient filtration area, HPHT filtrate volumes after 30 minutes are doubled.

A type of viscometer generally used in laboratories to test drilling fluids at simulated downhole conditions.

A perforating gun having more than four shots per foot. In addition to providing a greater number of perforations, a high-shot density gun also improves the phasing, or distribution of perforations, around the wellbore.

A systems tract bounded below by a downlap surface and above by a sequence boundary, commonly abbreviated as HST. This systems tract is characterized by an aggradational to progradational parasequence set.

The act of adjusting a model of a reservoir until it closely reproduces the past behavior of a reservoir. The historical production and pressures are matched as closely as possible. The accuracy of the history matching depends on the quality of the reservoir model and the quality and quantity of pressure and production data. Once a model has been history matched, it can be used to simulate future reservoir behavior with a higher degree of confidence, particularly if the adjustments are constrained by known geological properties in the reservoir.

A crossplot of two components of particle motion over a time window. Hodograms are used in boreholeseismology to determine arrival directions of waves and to detect shear-wave splitting. Data recorded along two geophone axes are displayed as a function of time.

With reference to multiphase flow in pipes, the fraction of a particular fluid present in an interval of pipe. In multiphase flow, each fluid moves at a different speed due to different gravitational forces and other factors, with the heavier phase moving slower, or being more held up, than the lighter phase. The holdup of a particular fluid is not the same as the proportion of the total flow rate due to that fluid, also known as its cut. To determine in-situ flow rates, it is necessary to measure the holdup and velocity of each fluid. Holdup is usually given the symbol y, with the suffixes g, o or w for gas, oil or water.The sum of the holdups of the fluids present is unity. The holdup ratio is the ratio of the holdups of two fluids, and is sometimes used as a parameter to express the phenomenon.

The point or depth at which a tool or drift of a specific size can no longer pass through the wellbore. A higher than expected holdup depth may result from scale, fill, distortion of the wellbore tubulars or formation movement in an openholecompletion.

A two-dimensional display, using colors or different grey scales, of the holdup around the borehole versus depth. The x-axis of the image shows different segments of the borehole, normally inside a casing, displayed from the top of the hole clockwise around through the bottom and back to the top again. Depth is in the z-axis, while the values of holdup are represented by different colors or changes from black to white.The holdup image is constructed from between four and eight local probe measurements using interpolation within constraints. Images, sometimes called maps, are also made for bubble count and bubble velocity.

A record of the fractions of different fluids present at different depths in the borehole. Various techniques are used to measure these fractions. The earliest techniques measured the fluid density, using a gradiomanometer or a nuclear fluid densimeter, or the dielectric properties, as in the capacitance or water-cutmeter.While these techniques were satisfactory in near-vertical wells with two-phase flow, they were often found to be inadequate in highly deviated and horizontal wells, where flow structures are complex. More recent developments are based on the use of multiple local probes to detect bubbles of gas, oil or water, and on a combination of nuclear techniques usually known as three-phase holdup.

(noun) A graphical representation showing the distribution of fluid phases (oil, water, and gas) as fractions of the total flow area or volume at various depths or locations in a wellbore or pipeline, derived from production logging measurements. Holdup maps help identify fluid entry points, crossflow, and phase segregation.

A device for determining the water holdup in a producing well by measuring the capacitance or impedance of the fluid. The holdup meter is used to produce a capacitance log. Since water has a high dielectric constant, and hence capacitance, it can be distinguished from oil or gas. The meter is a coaxial capacitor, with fluid flowing between a central probe and an external cage that act as electrodes. The meter has often been combined with a packerflowmeter or a diverter flowmeter, so that all the fluids in the well pass through the meter.

The quality of uniformity of a material. If irregularities are distributed evenly in a mixture of material, the material is homogeneous. (Compare with isotropy.)

Formation with rock properties that do not change with location in the reservoir. This ideal never actually occurs, but many formations are close enough to this situation that they can be considered homogeneous. Most of the models used for pressure-transient analysis assume the reservoir is homogeneous.

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

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

A type of packer than utilizes an assembly of friction blocks and slips to set and anchor the packer on the casing or liner wall. Hookwall packers generally are run on tubing or drillpipe and typically require some rotation of the packer assembly to activate or set the packer slips. Subsequent application of tension or compression, depending on packer design, will set the packer elements.

The device used to facilitate the addition of drilling fluid additives to the whole mud system. While several types of hoppers exist, they generally have a high velocity stream of mud going through them and a means of mixing either dry or liquid mud additives into the whole mud stream. The resultant mixed mud is then circulated back into the surface mud system. A hopper is generally used to introduce relatively small quantities of additives to the mud system.

An interface that might be represented by a seismic reflection, such as the contact between two bodies of rock having different seismic velocity, density, porosity, fluid content or all of those.

A map view of a particular reflection in a 3D seismic survey, as opposed to a horizontal (depth) slice or at a given time (a time slice). Slices are convenient displays for visual inspection of seismic attributes, especially amplitude.

What Is Horizontal Drilling? Horizontal drilling deflects a wellbore from vertical to a near-horizontal trajectory inside the target formation, exposing thousands of meters of reservoir rock to the production string. Operators use horizontal wells to develop tight oil, shale gas, and thin-pay conventional reservoirs across the Permian Basin, the Montney, the Duvernay, Australia's Cooper Basin, and the Middle East carbonates of Ghawar and Rumaila. Key Takeaways Horizontal drilling is the industry-standard technique for developing unconventional shale, tight oil, and tight gas plays, with laterals routinely exceeding 3,000 m (9,843 ft) in the Permian, Montney, and Duvernay. Steerable rotary systems guide the bit using MWD and LWD tools, holding the wellbore inside a reservoir interval as thin as 3 m (10 ft) over lateral lengths of several kilometers. Operators, completions engineers, and investors track lateral length because longer laterals materially increase estimated ultimate recovery (EUR) and break-even economics in shale plays. Regulatory frameworks span AER Directive 083 for fracturing in Alberta, Texas Railroad Commission Rule 38 for spacing in the Permian, NOPSEMA for offshore horizontals in the Carnarvon Basin, and Sodir for extended-reach wells on the Norwegian Continental Shelf. Canada's longest onshore well, drilled by Veren Inc. in the Duvernay in 2024, reached a total measured depth of 9,017 m (29,583 ft) with a 5,432 m (17,822 ft) lateral. How Horizontal Drilling Works A horizontal well begins as a conventional vertical hole. The drilling crew runs surface casing and intermediate casing to isolate shallow formations, then kicks off the build section at a predetermined depth called the kickoff point (KOP). From the KOP, directional tools steer the bit through a build curve, typically 8 to 12 degrees of inclination per 30 m (100 ft), until the wellbore reaches 85 to 95 degrees from vertical. The driller then lands the well inside the target reservoir and drills the horizontal lateral, also called the production leg, along the target interval. Steering uses a combination of a positive displacement motor (PDM) with a bent housing or a rotary steerable system (RSS). PDMs flex the bottomhole assembly slightly off-axis to generate side force, while RSS tools apply side force at the bit through servo-actuated pads or an offset internal shaft, allowing continuous rotation of the entire drill string. Modern RSS tools from Schlumberger, Halliburton, and Baker Hughes hold the well trajectory within 0.5 m (1.6 ft) of the planned path over laterals of 3,000 to 5,000 m (9,843 to 16,404 ft), reading formation properties in real time through gamma ray, resistivity, and sonic LWD sensors. Once the lateral is drilled, crews run production casing or a liner and cement it in place using cement blends tailored to the thermal and pressure environment. Multi-stage hydraulic fracturing then stimulates the reservoir through 30 to 60 individual fracture stages spaced 50 to 100 m (164 to 328 ft) apart along the lateral, creating a network of conductive fractures that connects the wellbore to the surrounding rock. Horizontal Drilling Across International Jurisdictions Horizontal drilling dominates North American unconventional development. In Canada, AER Directive 083 governs subsurface integrity for hydraulically fractured horizontal wells in Alberta, covering the Montney, Duvernay, Cardium, and oil sands non-thermal plays. Directive 017 covers measurement, and the broader OGCA licensing regime requires horizontal well trajectories to be surveyed and filed with the AER before production commences. BC Energy Regulator enforces matching standards across the BC Montney, which accounts for approximately 40% of Canadian horizontal rig activity in 2026. In the United States, the Texas Railroad Commission regulates horizontal wells across the Permian Basin and Eagle Ford through field-specific spacing rules and Statewide Rule 38, while the North Dakota Industrial Commission governs the Bakken. The EPA regulates methane emissions from horizontal wells under the 2024 Final Rule for Oil and Natural Gas Sector Emissions, now in full implementation across 2026 operations. Offshore, BSEE 30 CFR 250 applies to horizontal wells drilled from deepwater templates in the Gulf of Mexico Wilcox play, where Chevron's Anchor and Shell's Whale projects employ extended-reach horizontal sections. Australia's NOPSEMA regulates horizontal wells drilled offshore in the Carnarvon and Browse basins, while state regulators cover onshore horizontals in the Cooper Basin (South Australia), the Bowen and Surat basins (Queensland), and the Beetaloo (Northern Territory). Norway's Sodir oversees horizontal and extended-reach wells across the Norwegian Continental Shelf, including Troll, Snøhvit, Ekofisk, and the pre-salt Johan Sverdrup complex. The Middle East uses horizontal drilling extensively in the Ghawar (Saudi Aramco), Rumaila (BP/PetroChina), Manifa (Saudi Aramco), and the offshore Upper Zakum and Lower Zakum (ADNOC), with multilateral horizontal configurations common in carbonate reservoirs. Fast Facts ExxonMobil's Sakhalin-1 Chayvo Z-42 well, drilled in 2013 from onshore Russia, reached a total measured depth of 12,700 m (41,667 ft) with a horizontal departure of 11,739 m (38,514 ft), one of the longest extended-reach wells ever drilled. ExxonMobil has since drilled nine of the ten longest step-out ERD wells from Sakhalin Island, demonstrating the commercial viability of horizontal drilling from onshore pads to reach offshore reservoirs without installing seabed infrastructure. Lateral Length and Well Design Operators have lengthened laterals steadily over the last decade in pursuit of better per-well economics. In 2012, the average Permian horizontal lateral ran 1,800 m (5,906 ft). By 2025, the industry average surpassed 3,350 m (10,991 ft), and operators such as Chevron, ExxonMobil, and Pioneer Natural Resources routinely drill 4,500 m (14,764 ft) laterals in the Delaware Basin. The Montney and Duvernay have followed a similar trajectory: Veren Inc.'s 5,432 m (17,822 ft) lateral in the Duvernay, announced in May 2024, became Canada's longest onshore lateral and demonstrated the technical headroom for further extension. Lateral length materially improves project economics by dividing the fixed cost of the vertical section and the surface pad across more producing reservoir rock. A 4,500 m (14,764 ft) lateral in the Permian Midland typically produces 40% to 60% more cumulative oil than a 3,000 m (9,843 ft) lateral at roughly 25% higher drilling cost, driving internal rate of return improvements of 5 to 10 percentage points on comparable acreage. Investors and analysts at Goldman Sachs, RBC Capital Markets, and Wood Mackenzie publish quarterly benchmarks on lateral length as one of the cleanest indicators of operational efficiency by operator and basin. Tip: Longer laterals are not universally better. Proppant and fluid placement becomes less efficient beyond roughly 4,500 m (14,764 ft), and individual fracture stage effectiveness declines as frictional pressure losses and near-wellbore complexity increase. Operators in the Montney and Delaware have begun reporting incremental EUR per foot declining above 15,000 ft (4,572 m), suggesting an economic plateau absent further completion innovation. Horizontal Drilling Synonyms and Related Terminology Directional drilling: the broader category of non-vertical drilling; horizontal drilling is the subset at 80 to 95 degrees inclination. Extended-reach drilling (ERD): horizontal wells with a horizontal-to-vertical ratio exceeding 2:1, used to reach distant reservoirs from a single surface location. Lateral: the horizontal section of the wellbore from the heel (top of the build) to the toe (far end). Multilateral: a configuration where multiple lateral branches extend from a single parent wellbore. Slant well: a lower-angle deviated well common in oil sands thermal (SAGD) operations in Alberta. Geosteering: real-time navigation of the lateral using LWD data to stay inside the reservoir. Related terms: Directional Drilling, Hydraulic Fracturing, Lateral, MWD, LWD, Casing, Shale, Spud. Frequently Asked Questions What is horizontal drilling in oil and gas? Horizontal drilling is the technique of drilling a wellbore that turns from vertical to near-horizontal inside the target reservoir, placing thousands of meters of pipe in direct contact with producing rock. It unlocks reservoirs that would be uneconomic to develop with vertical wells, particularly shale and tight oil plays where the reservoir rock has low permeability and requires large contact area to produce commercially. How does horizontal drilling work? Horizontal drilling starts as a vertical well, then uses a steerable bottomhole assembly to build inclination from vertical to horizontal at a measured rate. MWD and LWD tools continuously survey the wellbore position and read formation properties, allowing the directional driller to land the well inside a specific reservoir interval and steer along it for kilometers. After drilling, the well is cased, cemented, and hydraulically fractured in stages along the lateral. Why is horizontal drilling important for shale production? Shale reservoirs have permeability thousands of times lower than conventional sandstones and carbonates. A vertical well produces almost nothing from shale because the rock barely yields fluid into the wellbore. A horizontal well placed inside the shale, combined with multi-stage hydraulic fracturing, creates enough surface area and fracture connectivity to produce commercial volumes. Horizontal drilling is why US oil production doubled from 2010 to 2020 and why Canada's Montney and Duvernay have become globally significant gas supply sources. What is the longest horizontal well ever drilled? The longest horizontal well is generally considered to be ExxonMobil's Sakhalin-1 Chayvo Z-42, drilled in 2013 with a total measured depth of 12,700 m (41,667 ft) and a horizontal departure of 11,739 m (38,514 ft). On land, Canada's longest is the Veren Inc. Duvernay well at 9,017 m (29,583 ft) total measured depth with a 5,432 m (17,822 ft) lateral, announced in May 2024. BP's Wytch Farm in the UK set multiple records in the late 1990s with the M16 well at 11,275 m (36,992 ft) measured depth. How much does a horizontal well cost? A typical Permian Basin horizontal well in 2026 costs USD 6 to 9 million all-in for drilling, completion, and tie-in, with the completion (fracturing and perforating) representing roughly 55% to 65% of total cost. Montney horizontals run CAD 5 to 8 million depending on lateral length and completion intensity. Middle East multilateral horizontals in Ghawar or Rumaila can cost USD 15 to 25 million due to the complexity of the multilateral junctions and the scale of the reservoir contact. Why Horizontal Drilling Matters in Oil and Gas Horizontal drilling is the technology that rewrote global oil and gas supply economics after 2005, turning previously uneconomic shale and tight rock into the backbone of US and Canadian production. The Permian Basin, the Montney, the Duvernay, the Marcellus, the Bakken, the Eagle Ford, the Vaca Muerta, and the Ghawar extension wells all depend on horizontal drilling paired with completion technology. For the rig crew landing a well inside a 3 m (10 ft) pay zone, the reservoir engineer modeling EUR versus lateral length, and the commodity trader watching US production grow past 13 million barrels per day, horizontal drilling sits at the foundation of how modern hydrocarbons reach market.

The resistivity of a formation measured by flowing current in a horizontal plane. In anisotropic formations the horizontal and vertical resistivities are different. In a vertical well, wirelineinduction logs and measurements-while-drilling propagation logs measure the horizontal resistivity, whereas laterologs measure the horizontal resistivity with some component of the vertical. In deviated and horizontal wells, all these logs measure some mixture of both vertical and horizontal resistivity.

A vessel, with its cylindrical axes parallel to the ground, that is used to separate oil, gas and water from the produced stream. The horizontal separator can be a two-phase or three-phase separator.

A method to convey or reserve oil, gas or mineral rights at specific depths or geologic horizons.

A Christmas tree design for subsea applications, configured with the master valves and flow-control equipment on a horizontal axis to minimize the assembly height.

A relatively high-standing area formed by the movement of normal faults that dip away from each other. Horsts occur between low-standing fault blocks called graben. Horsts can form in areas of rifting or extension, where normal faults are the most abundant variety of fault.

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

A truck- or skid-mounted unit used to heat oil or treatment fluid. Hot oilers are routinely used in the removal of wax deposits from the upper wellbore section of wells in cold climates where low wellhead temperatures increases the susceptibility of heavy crude oil to wax precipitation.

Circulation of heated fluid, typically oil, to dissolve or dislodge paraffin deposits from the production tubing. Such deposits tend to occur where a large variation in temperature exists across the producing system.

The process of drilling a hole through a pressure barrier using special equipment and procedures to ensure that the pressure and fluids are safely contained when access is made. Hot tapping is often used to enable access to the wellbore when wellhead valves jam closed.

A method of thermal recovery in which hot water is injected into a reservoir through specially distributed injection wells. Hot waterflooding reduces the viscosity of the crude oil, allowing it to move more easily toward production wells.Hot waterflooding, also known as hot water injection, is typically less effective than a steam-injection process because water has lower heat content than steam. Nevertheless, it is preferable under certain conditions such as formation sensitivity to fresh water.

The outside steel case of a cartridge or a sonde in a wirelinelogging tool. The housing isolates the electronics, power supplies and sensors from the borehole and bears the pressure burden.

Slang term for a cyclic process in which a well is injected with a recovery enhancement fluid and, after a soak period, the well is put back on production. Examples are cyclic steam injection and cyclic CO2 injection.

Organic carboxylic acids of complex molecular structure (aromatic and phenolic) that comprise 10 to 90% of lignite. Humic acids in lignite react with caustic ingredients (NaOH and KOH) in mud. The water solubility of lignite depends on its humic acid content. Decarboxylation of humic acid groups by hydrolysis in alkaline muds is a major source of carbonate and bicarbonate anions in water muds.

Moisture (water vapor) in a gaseous atmosphere, such as in air. It is quantified as relative humidity.

(noun) An instrument used to measure the moisture content or relative humidity of a gas stream, ambient air, or process environment. In gas processing and pipeline operations, humidity meters monitor water vapour levels to ensure compliance with dew point specifications and prevent hydrate formation or corrosion.

The abnormal behavior in a buildup curve caused by phase redistribution in a wellbore. This behavior is most noticeable in oil wells producing a substantial amount of gas and having a substantial skin effect. Analysis of buildup curves for wells exhibiting this behavior can be difficult or impossible because the "hump" obscures the reservoir response.

An early scale used for the presentation of resistivity logs. The scale has two parts, equally divided about a midpoint. The left part is linear in resistivity, for example 0 on the left edge to 50 ohm-m at the midpoint. The right part is linear in conductivity, from 0 on the right to 1/50 = 20 mS/m at the midpoint. In this way, it was possible to display the complete range of resistivity in one track. It was subsequently replaced by the logarithmic scale.

A chemical combination of water and another substance. Gypsum is a hydrate mineral. Its anhydrous equivalent is anhydrite.

Absorption of water by a hygroscopic material such as a clay or polymer. Hydration is the first stage of clay-water (or polymer-water) interaction. When dry bentonite is stirred into water, hydration is observed as swelling.

A design feature on packers and similar downhole tools that occupy a large proportion of the drift diameter of the wellbore. When running and retrieving such tools, the hydraulic bypass allows the wellbore fluid to flow through part of the tool assembly to reduce the forces applied to the tool and reduce any damaging swab or surge effect on the reservoirformation.

A substance which, when mixed with water, hardens like stone because of a chemical reaction with the water. Hydraulic cement is capable of setting under water.

A type of tool-string centralizer, generally used in through-tubing applications, that employs hydraulic force to energize the centralizer arms or bows. Through-tubing operations sometimes require the tool string to be centralized within the casing or liner below the tubing. The relatively large expansion required for this is not generally within the operating range of conventional centralizer models.

A technique to track the propagation of a hydraulic fracture as it advances through a formation. Microseisms are detected, located, and displayed in time for scientists and engineers to approximate the location and propagation of the hydraulic fracture. Software provides modeling, survey design, microseismic detection and location, uncertainty analysis, data integration, and visualization for interpretation. Computer imagery is used to monitor the activity in 3D space relative to the location of the fracturing treatment. The monitored activities are animated to show progressive fracture growth and the subsurface response to pumping variations. When displayed in real time, the microseismic activity allows one to make changes to the stimulation design to ensure optimal reservoir contact. Also known as microseismic monitoring, this technique delivers information about the effectiveness of the stimulation of a reservoir that can be used to enhance reservoir development in shale gas completions.

What Is Hydraulic Fracturing? Hydraulic fracturing stimulates an oil or gas reservoir by pumping fluid at pressures above the formation parting pressure, creating and propping open a network of conductive fractures in the rock. Operators use hydraulic fracturing to produce shale plays including the Permian, Marcellus, Montney, Duvernay, Vaca Muerta, and Beetaloo, and to enhance recovery from tight sandstone and carbonate reservoirs in the Middle East and North Sea. Key Takeaways Hydraulic fracturing is the industry-standard stimulation technique for developing unconventional shale and tight rock reservoirs, pumping water, sand, and chemical additives at pressures of 6,000 to 15,000 PSI (414 to 1,034 bar) to fracture the formation. A modern multi-stage completion pumps 20 to 50 stages over a single horizontal lateral, using 50,000 to 150,000 bbl (7.9 to 23.8 million liters) of fluid and 4,000 to 20,000 tonnes of sand per well. Operators, service companies, regulators, and landowners all scrutinize fracturing because it sits at the intersection of production economics, water use, induced seismicity, and chemical disclosure. Regulatory frameworks vary sharply: AER Directive 083 governs Alberta, FracFocus mandates chemical disclosure in the US and Canada, Australia maintains state-level moratoriums in Victoria and the Limestone Coast of South Australia, and the UK maintains a de facto moratorium since 2019. Fracturing in 2026 accounts for over 95% of new oil and gas wells drilled in the United States and Canada combined, making it the dominant production technique in North American energy markets. How Hydraulic Fracturing Works A hydraulic fracturing treatment begins after a well has been drilled, cased, cemented, and perforated. Crews run a plug-and-perf completion or a sliding-sleeve system down the lateral, then pump fluid at high pressure through the casing and into the perforated interval. Once surface pressure exceeds the in-situ minimum horizontal stress of the target formation, the rock parts along a plane roughly perpendicular to the minimum stress direction, creating a primary hydraulic fracture. As pumping continues, the fracture propagates away from the wellbore in a roughly planar geometry, extending 100 to 300 m (328 to 984 ft) from the well in typical shale treatments. Proppant (most commonly silica sand, sometimes ceramic or resin-coated sand for HPHT applications) suspended in the fluid lodges inside the fracture, holding it open after pumping stops. The fluid then flows back to surface, leaving a propped fracture that serves as a high-conductivity pathway between the reservoir matrix and the wellbore. Modern completions divide the lateral into discrete stages, each independently stimulated. A typical Permian or Montney lateral of 3,000 to 5,000 m (9,843 to 16,404 ft) is fractured in 30 to 60 stages, each pumping 3,000 to 5,000 bbl (477,000 to 795,000 liters) of fluid and 100 to 300 tonnes of sand over 90 to 120 minutes. Pumping spreads typically deploy 10 to 20 truck-mounted pumps delivering 100 to 150 bbl/min (15.9 to 23.8 m³/min) at pressures of 9,000 to 13,000 PSI (621 to 896 bar). Total treatment volume per well reaches 50,000 to 150,000 bbl (7.9 to 23.8 million liters) of water and 4,000 to 20,000 tonnes of sand. Hydraulic Fracturing Across International Jurisdictions Regulatory treatment of hydraulic fracturing varies more widely than any other drilling technique. In Canada, AER Directive 083 Hydraulic Fracturing Subsurface Integrity, effective since August 2013, requires Alberta operators to assess subsurface risk before fracturing, manage well control at offset wells, and prevent impacts to non-saline aquifers. Fluid additives are disclosed via FracFocus Canada, administered by the BC Oil and Gas Commission, the AER, and Saskatchewan's Ministry of Energy and Resources. The BCER enforces matching requirements in British Columbia's Montney. The Northwest Territories and Yukon maintain fracturing rules under the NEB/CER legacy framework, though commercial activity is limited. In the United States, FracFocus (administered by the Ground Water Protection Council and IOGCC) is the national chemical disclosure registry, with mandatory reporting in most producing states. The EPA regulates underground injection, air emissions (via the 2024 Final Rule for Oil and Natural Gas Sector Emissions), and wastewater handling, while state agencies govern well construction and fracturing operations. The Texas Railroad Commission oversees the Permian and Eagle Ford, the Pennsylvania DEP governs the Marcellus, the North Dakota Industrial Commission regulates the Bakken, and the Colorado Oil and Gas Conservation Commission applies some of the most stringent state rules nationwide. Australia presents a patchwork. The Northern Territory lifted its moratorium in 2018 and has since allowed fracturing in the Beetaloo Sub-basin, with Origin Energy, Tamboran Resources, and Empire Energy holding exploration permits. Victoria maintains a legislated moratorium banning onshore unconventional gas development. South Australia banned fracturing across the Limestone Coast in late 2024 for 10 years. Queensland and the Cooper Basin in South Australia allow conventional and unconventional fracturing under strict state approvals. Western Australia lifted its moratorium in 2018 but limits fracturing to roughly 2% of the state's land area. NOPSEMA regulates offshore fracturing activities in Commonwealth waters, though the volume is small. Norway allows fracturing under Sodir oversight, but offshore shale gas development has not been pursued commercially on the Norwegian Continental Shelf. The UK authorized fracturing in 2015 with NSTA (now NSTA) oversight, but recurring seismic events at Cuadrilla's Preston New Road site led to a de facto moratorium in November 2019, reaffirmed by successive governments. The Middle East uses fracturing selectively in tight carbonates and unconventional plays: Saudi Aramco's Jafurah gas project, ADNOC's tight gas program in the UAE, and Oman's tight oil developments apply high-intensity completions with in-country service company support. Fast Facts Saudi Aramco's Jafurah unconventional gas project, sanctioned in 2020, targets 200 trillion cubic feet of gas in place from the Tuwaiq Mountain and Hanifa shale formations. Aramco plans to produce 2 billion cubic feet per day by 2030 through a network of hydraulically fractured horizontal wells, making Jafurah the largest unconventional development outside North America and signaling the Middle East's adoption of the techniques first proven in the Barnett and Marcellus shales. Frac Fluid, Proppant, and Water Use A fracturing fluid is roughly 90% water, 9% proppant, and 1% chemical additives by mass. The additives include friction reducers (typically polyacrylamide), biocides to prevent bacterial growth, scale inhibitors, surfactants, and occasionally acids for carbonate formations. FracFocus and FracFocus Canada require operators to publish the chemical composition of every stage, with trade-secret exemptions narrowly defined. Proppant selection tracks reservoir depth and closure stress. Northern White sand from Wisconsin and Minnesota dominates shallow shale plays in the Appalachian and Western Canadian sedimentary basins. Regional sand mines in West Texas and the Permian Basin supply in-basin sand at lower cost but reduced crush resistance. Ceramic proppant and resin-coated sand serve HPHT applications where closure stress exceeds 10,000 PSI (690 bar), such as the deep Haynesville and the Middle East tight gas plays. Water use draws sustained public attention. A single 3,500 m (11,483 ft) Permian lateral consumes 80,000 to 120,000 bbl (12.7 to 19.1 million liters) of water, sourced from fresh water, brackish water, or recycled produced water. The industry has steadily shifted toward produced water recycling: Pioneer, Chevron, and ExxonMobil report recycling rates above 70% in current Permian operations. The Montney uses recycled frac flowback and produced water extensively, and the BCER requires operators to report water sourcing and disposal for every multi-well pad. Tip: Investors assess fracturing-driven production by comparing completion intensity (pounds of proppant per lateral foot, or barrels of fluid per foot) across operators. Permian completions averaged 2,000 lb/ft in 2019 and now exceed 3,300 lb/ft in 2026, reflecting the industry's pursuit of higher EUR through denser proppant placement. The marginal EUR per additional pound of proppant, however, is declining, suggesting the industry is approaching diminishing returns from pure intensity increases. Hydraulic Fracturing Synonyms and Related Terminology Fracking: common shorthand used in media and public discourse; industry documents use the full term. Frac: industry shorthand used in operations and engineering documents. Well stimulation: the broader regulatory category that includes both fracturing and matrix acidizing. Multi-stage fracturing: the horizontal well technique using dozens of discrete fracture treatments along a lateral. Propped fracture: a fracture held open by granular proppant after hydraulic pressure is released. Slickwater frac: a low-viscosity water-based treatment common in most US and Canadian shale plays. Crosslinked gel frac: a high-viscosity gel treatment used for carrying higher proppant loads in deeper, higher-stress reservoirs. Related terms: Horizontal Drilling, Shale, Casing, Cement, Porosity, Well Control, Formation, Reservoir. Frequently Asked Questions What is hydraulic fracturing in oil and gas? Hydraulic fracturing is a completion technique that stimulates oil and gas production by pumping fluid into a reservoir at pressures high enough to fracture the rock. Proppant suspended in the fluid holds the fractures open after pumping stops, creating a network of conductive pathways between the reservoir and the wellbore. Without fracturing, shale and tight rock reservoirs produce at uneconomic rates. How does hydraulic fracturing work? Fracturing pumps water, sand, and chemical additives down the well and through perforations in the casing at pressures above the formation parting pressure. The rock splits along planes perpendicular to the minimum horizontal stress, forming fractures that extend 100 to 300 m (328 to 984 ft) from the wellbore. Proppant lodges inside the fractures, and after pressure is released, the proppant-filled fractures serve as high-permeability channels for hydrocarbons to flow to the well. Where is hydraulic fracturing banned? Fracturing is banned or subject to de facto moratoriums in the UK (since November 2019), France, Germany, Ireland, Bulgaria, Victoria (Australia), and the Limestone Coast of South Australia. The Canadian provinces of Quebec, Nova Scotia, New Brunswick, and Newfoundland and Labrador maintain various forms of moratorium or prohibition. New York State banned high-volume fracturing in 2015, and Vermont and Washington have similar prohibitions, although little unconventional resource exists in those states. Why Hydraulic Fracturing Matters in Oil and Gas Hydraulic fracturing is the technique that converted North America from oil and gas importer to the world's largest producer of both commodities. Without fracturing, the Permian, the Marcellus, the Bakken, the Montney, the Duvernay, and the Eagle Ford would remain geological curiosities rather than the backbone of modern energy supply. For the field technician managing a 20-pump spread on a remote pad, the completions engineer modeling proppant intensity against EUR, the regulator reviewing an AER Directive 083 application, and the investor modeling break-evens against forward oil strips, hydraulic fracturing is the technology that defines the economics of twenty-first-century oil and gas development.

The force per unit area exerted by a column of liquid at a height above a depth (and pressure) of interest. Fluids flow down a hydraulic gradient, from points of higher to lower hydraulic head. The term is sometimes used synonymously with hydrostatic head.

The power of a positive displacement pump. HHP is important for mud pumps and cement pumps.

A type of packer used predominantly in production applications. A hydraulic packer typically is set using hydraulic pressure applied through the tubing string rather than mechanical force applied by manipulating the tubing string.

An assembly of components and controls necessary to provide a hydraulic power supply. In modern oilfield activities, many systems are hydraulically powered, including the majority of mobile systems such as slickline units, coiled tubing units and snubbing units. In most cases, a diesel engine is the prime mover, providing an independent power supply that is harnessed to the necessary hydraulic pump and control systems.

An artificial-lift system that operates using a downhole pump. A surface hydraulic pump pressurizes crude oil called power oil, which drives the bottom pump. When a single production string is used, the power oil is pumped down the tubing and a mixture of the formation crude oil and power oil are produced through the casing-tubing annulus. If two production strings are used, the power oil is pumped through one of the pipes, and the mixture of formation crude oil and power oil are produced in the other, parallel pipe.

A downhole tool designed to allow the lower and upper tool-string sections to be parted to enable retrieval of the running string. Hydraulic disconnects rely on the application of a predefined pressure through the running string to activate a release mechanism. In some cases, a ball or dart is plugged to block circulation through the tool string and enable the application of the release pressure.

A setting or operating method that uses hydraulic force applied through the tubing or running string to activate a downhole tool. In many cases a drop ball, which lands in a profiled seat, will be used to shift the setting or activation mechanism at predetermined pressures.

A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane [CH4], but many are highly complex molecules, and can occur as gases, liquids or solids. The molecules can have the shape of chains, branching chains, rings or other structures. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.

A type of seismicamplitudeanomaly, seismic event, or characteristic of seismic data that can occur in a hydrocarbon-bearing reservoir. Although "bright spots," as hydrocarbon indicators are loosely called, can originate in numerous ways, they are not all indicative of the presence of hydrocarbons. Criteria to distinguish true hydrocarbon indicators (sometimes called HCIs) from other types of amplitude anomalies include:amplitude variation with offsetbright or dim spot(s) in amplitude as a result of variations in lithology and pore fluids, sometimes occurring in groups of stacked reservoirschange or reversal in polarity because of velocity changes, also called phasingconformity with local structuresdiffractions that emanate from fluid contactsflat spot that represents a fluid (gas-oil or gas-water) contact, which can also show the downdip limit of the reservoir in some casesgas chimneys above leaking reservoirsshadow zones below the accumulationvelocity push-down because of lower velocities of hydrocarbons than rocksdifference in response between reflected pressure and shear energy.Hydrocarbon indicators are most common in relatively young, unconsolidated siliciclastic sediments with large impedance contrasts across lithologic boundaries, such as those in the Gulf of Mexico and offshore western Africa. An ongoing issue in exploration for hydrocarbon indicators is the difficulty in distinguishing between gas accumulations and water with a low degree of gas saturation ("fizz water").

An area of the subsurface where source rock has reached appropriate conditions of pressure and temperature to generate hydrocarbons; also known as source kitchen, oil kitchen or gas kitchen.

An acid type commonly used in oil- and gas- well stimulation, especially in carbonate formations. The reaction characteristics of hydrochloric acid enable it to be used in a wide range of treatments, often with chemical additives that enhance its performance or allow greater control of the treatment. Treatments are most commonly conducted with 15% or 28% solutions of hydrochloric acid.

An item of solids-control equipment consisting of an inverted cone, the mud being fed tangentially into the upper (larger diameter) part. The resulting spinning effect forces solids to the wall of the device and they exit from the bottom (apex) of the cone, while the cleaned liquid exits at the top. Hydrocyclones are classified by the size of the cone as either desanders (typically 12 inches in diameter) or desilters (4 to 6 inches in diameter) and will separate particles in the medium-, fine- and ultrafine-size ranges. The efficiency of hydrocyclones is poor in viscous weighted muds and many units are being replaced by more efficient, high-speed shakers.

A poisonous liquid acid composed of hydrogen and fluorine. Hydrofluoric acid [HF] is used primarily because it is the only common, inexpensive mineral acid that can dissolve siliceous minerals. HF is typically mixed with hydrochloric acid [HCl] or organic acid to keep the pH low when it spends, thereby preventing detrimental precipitates. These mixtures, also called mud acids, are considered the main fluid in a sandstone acid treatment because they remove formation damage.Hydrofluoric acid should not be used in sandstone formations with high carbonate content because of the high risk of calcium fluoride precipitation [CaF2].

(noun) A blended acid system combining hydrofluoric acid (HF) and hydrochloric acid (HCl), commonly known as mud acid, used in matrix acidising of sandstone formations to dissolve clay minerals, feldspar, and siliceous fines that reduce near-wellbore permeability, thereby restoring or enhancing well productivity.

A type of hydrogen-induced failure produced when hydrogen atoms enter low-strength steels that have macroscopic defects, such as laminations.The defects in the steel (void spaces) provide places for hydrogen atoms to combine, forming gaseous molecular hydrogen [H2] that can build enough pressure to produce blistering.Hydrogen blistering is a problem mainly in sour environments. Frequently, it does not cause a brittle failure, but it can produce rupture or leakages.

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

The number of hydrogen atoms per unit volume divided by the number of hydrogen atoms per unit volume of pure water at surface conditions. The hydrogen index (HI) is thus the density of hydrogen relative to that of water. It is a key factor in the response of a neutron porosity log.

A type of corrosion produced when a metal absorbs hydrogen atoms. This phenomenon can cause undesirable effects such as blistering, cracking, methaneformation above 400oF [204oC] and hydrogen embrittlement.

A corrosion test instrument mainly used in sour systems (for example, hydrogen sulfide or other sulfide rich environments) to determine qualitatively or semiquantitatively the corrosion of a structure.A hydrogen probe is also called a hydrogen patch probe.

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

Any chemical reaction with water (H2O), such as degradation of lignite by decarboxylation of humic acid (a major component of lignite), which is driven by hydrolysis at high pH and begins at modest temperature.

A weighted, hollow glass bulb with a long, graduated tube attached for measuring the density of a liquid. A hydrometer is placed in the liquid and the bulb sinks according to the density of the liquid. Graduations on the tube indicate the density. Hydrometers are used in fluids that have no gel strength, such as brine, but are not reliable in drilling fluids because of gelation.

A number on the scale of one to 40 according to the HLB system, introduced by Griffin (1949 and 1954). The HLB system is a semi-empirical method to predict what type of surfactant properties a molecular structure will provide. The HLB system is based on the concept that some molecules have hydrophilic groups, other molecules have lipophilic groups, and some have both. Weight percentage of each type of group on a molecule or in a mixture predicts what behavior the molecular structure will exhibit. Water-in-oil emulsifiers have a low HLB numbers, typically around 4. Solubilizing agents have high HLB numbers. Oil-in-water emulsifiers have intermediate to high HLB numbers.Reference:Griffin WC: "Classification of Surface-Active Agents by 'HLB,'" Journal of the Society of Cosmetic Chemists 1 (1949): 311.Reference:Griffin WC: "Calculation of HLB Values of Non-Ionic Surfactants," Journal of the Society of Cosmetic Chemists 5 (1954): 259.

Pertaining to an attraction for water by the surface of a material or a molecule. Clays and most other natural minerals used in drilling fluids, such as barite and hematite, are hydrophilic. They are spontaneously wet by water. To render them oleophilic, they can be treated with an oil-wetting chemical.

(adjective) Describing a surface or substance that repels water and resists wetting by aqueous fluids. In petroleum engineering, hydrophobic materials or coatings are used in sand control screens and other downhole equipment, while hydrophobic reservoir rock surfaces preferentially attract oil, influencing wettability and relative permeability.

A device designed for use in detecting seismic energy in the form of pressure changes under water during marineseismic acquisition. Hydrophones are combined to form streamers that are towed by seismic vessels or deployed in a borehole. Geophones, unlike hydrophones, detect motion rather than pressure.

A slickline tool generally used for the removal of sand or similar small particles around the fishing necks of downhole tools or equipment. The hydrostatic bailer incorporates a sealed atmospheric chamber and a shear pin, or similar activation mechanism, to allow communication with the wellbore. When the tool is activated, there is a fluid surge into the atmosphere as the pressure is equalized. A shroud arrangement at the base of the tool contains and directs the fluid surge to dislodge and capture any debris in the area.

The vertical height of a fluid column, regardless of the length or other dimensions of that fluid column. For example, a deviated wellbore has a longer length than vertical depth. The hydrostatic head at any point in that wellbore is not a function of its measured depth (MD) along the wellbore axis, but rather its vertical distance or true vertical depth (TVD) to the surface. The term "head" or "hydrostatic head" is also commonly used as a measure of the output of centrifugal pumps, usually expressed in "feet of head" or psi. Since this type of pump is a centrifugal (or "velocity") device, the capability of the pump as expressed in feet of head is independent of the density of the fluid being pumped. For example, if a pump is rated as producing "sixty feet of head," it will pump a column of fluid up an open-ended vertical pipe until the top of the liquid is 60 ft [18 m] above the discharge of the pump, regardless of the density of the liquid being pumped.

The pressure at any point in a column of fluid caused by the weight of fluid above that point. Controlling the hydrostatic pressure of a mud column is a critical part of mud engineering. Mud weight must be monitored and adjusted to always stay within the limits imposed by the drilling situation. Sufficient hydrostatic pressure (mud weight) is necessary to prevent an influx of fluids from downhole, but excessive pressure must also be avoided to prevent creation of hydraulic fractures in the formation, which would cause lost circulation. Hydrostatic pressure is calculated from mud weight and true vertical depth as follows:Hydrostatic pressure, psi = 0.052 x Mud Weight, lbm/gal x True Vertical Depth, ft. (To convert to SI units, 1.0 psi = 6.9 kPa.)

Pertaining to hot fluids, particularly hot water, or the activity of hot water, or precipitates thereof. Hydrothermal alteration can change the mineralogy of rock, producing different minerals, including quartz, calcite and chlorite. Hydrothermal activity is commonly associated with hot water that accompanies, or is heated by, magma.

A change of preexisting rocks or minerals caused by the activity of hot solutions, such as fluids accompanying or heated by magma. Quartz, serpentine and chlorite are minerals commonly associated with hydrothermal alteration. Ore deposits, such as lead (as the mineral galena), zinc (sphalerite), and copper (malachite), can occur in areas of hydrothermal alteration.

A nonionic starch derivative, analogous to hydroxyethylcellulose in its method of manufacture and most applications for drilling, workover and completion fluids. Rather than using a cellulosic starting material, such as hydroxyethylcellulose (HEC), starch is used instead, and reacted with ethylene oxide in an alkaline environment.

A nonionic cellulose derivative with hydroxyethyl groups attached to the polymerstructure. HEC is used as a viscosifier in brines and saline fracturing fluids, workover fluids, completion fluids and drill-in fluids. It gives pseudoplastic rheology but essentially no gel strength development. HEC offers little fluid-loss control, other than its rheological effects. HEC is seldom used in drilling fluids. Cellulose fibers are reacted with caustic soda and ethylene oxide to form HEC. Hydroxyethyl groups attach to the OH groups of the polysaccharide structure by ether linkages. A high degree of substitution (from 1.5 to 2.5 out of 3 maximum) gives HEC superior solubility in water and various brines. Being nonionic, it is not precipitated by hardness ions and disperses well at high salinity. HEC is not degraded by common bacteria.

Hydroxypropyl starch is a derivative of natural starch, used primarily for fluid-loss control in drilling muds, drill-in, completion and workover fluids. Being nonionic, it is only slightly affected by salinity and hardness in fluids. Linear and branched carbohydrate polymers in natural starch have three reactive OH groups on each glucose unit. During manufacture, these polymers are reacted with propylene oxide, adding hydroxypropyl (CH(OH)CH2CH3) groups at the OH positions by an ether linkage. By adding the hydroxypropyl groups, the HP starch becomes more resistant to thermal degradation and bacterial attack.

A device for measuring the moisture in a gaseous atmosphere, such as the air, usually as percent relative humidity. Mechanical hygrometers detect moisture by elongation and shrinkage of a fiber or sheet or by a device attached to a needle on a dial. Electrohygrometers measure changes in an electrical property of a moisture-sensitive sensing probe and are more reliable. Determination of the aqueous-phase activity of oil muds by the Chenevert Method requires an electrohygrometer and a series of salt solutions for calibration.

Pertaining to a property of a substance that allows the substance to take up water from the surrounding atmosphere. Many materials used in drilling muds are hygroscopic, for example, high-purity grades of calcium chloride. Bentonite clay is also hygroscopic and absorbs water from the atmosphere. Care must be taken in packaging and handling such materials to avoid waste by premature hydration.