Oil and Gas Terms Beginning with “P”

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that case, the bridge plug would be set and cement pumped on top of the plug through drillpipe, and then the drillpipe withdrawn before the slurry thickened.

An elastic body wave or sound wave in which particles oscillate in the direction the wave propagates. P-waves are the waves studied in conventional seismic data. P-waves incident on an interface at other than normal incidence can produce reflected and transmitted S-waves, in that case known as converted waves.

A cellulose derivative similar in structure, properties and usage in drilling fluids to carboxymethylcellulose. PAC is considered to be a premium product because it typically has a higher degree of carboxymethyl substitution and contains less residual NaCl than technical grade carboxymethylcellulose, although some PACs contain considerable NaCl.

A polymer or copolymer of an alkalene oxide, such as polyethylene glycol (PEG), a polymer of ethylene oxide with general formula HO(CH2CH2O)nH, or polypropylene glycol (PPG), which is a polymer of propylene oxide. PAGs are effective shale inhibitors and have effectively replaced the earlier polyglycerols.

One of the synthetic hydrocarbon liquids manufactured from the monomer ethylene, H2C=CH2. Polyalphaolefins have a complex branched structure with an olefin bond in the alpha position of one of the branches. Hydrogenated polyalphaolefins have olefin-carbons saturated with hydrogen, which lends excellent thermal stability to the molecule. Synthetic-base fluids (similar to oil muds) are made with the various types of synthetic liquids because the cuttings can be discharged in offshore waters, whereas discharge of cuttings coated with refined oils would be disallowed.

The Oslo and Paris Commission, formerly known as PARCOM. The commission is a group of experts who advise North Sea countries on environmental policy and legislation. OSPAR has been influential in establishing North Sea legislation on drilling fluids that has served as the model for other operating areas. OSPAR has published lists of environmentally acceptable and unacceptable products, referred to as the "green," "grey" and "black" lists. The Green or A list consists of products posing relatively little harm to the environment (specifically the marine environment). Examples include inert minerals such as bentonite, inorganic salts that are common constituents of seawater such as sodium and potassium chloride, and simple organic products such as starch and carboxymethylcellulose (CMC). The Grey List consists of products 'requiring strong regulatory control' and includes heavy metals such as zinc, lead and chromium. The Black list covers products considered unsuitable for discharge and includes mercury, cadmium and 'persistent oils and hydrocarbons of a petroleum origin.' The inclusion of hydrocarbons in the black list has been the driving force behind the reduction of oil discharges in the North Sea and elsewhere and has serious implications for the use of oil and synthetic fluids.

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

A log of photoelectric absorption properties. The log measures the photoelectric absorption factor, Pe, which is defined as (Z/10) 3.6 where Z is the average atomic number of the formation. Pe is unitless, but since it is proportional to the photoelectric cross section per electron, it is sometimes quoted in barns/electron. Since fluids have very low atomic numbers, they have very little influence, so that Pe is a measure of the rockmatrix properties. Sandstones have low Pe, while dolomites and limestones have high Pe. Clays, heavy minerals and iron-bearing minerals have high Pe. Thus, the log is very useful for determining mineralogy. In interpretation, PEF is normally converted to the simpler volumetric cross section, U in barns/cm3, by taking the product of PEF and density.The log is recorded as part of the density measurement. The depth of investigation is of the order of one inch, which is normally in the flushed zone. PEF can be affected by heavy minerals such as barite in the mudcake or mud filtrate. PEF logs were introduced in the late 1970s.

A class of water muds that use partially-hydrolyzed polyacrylamide (PHPA) as a functional additive, either to control wellbore shales or to extend bentoniteclay in a low-solids mud. As a shale-control mud, PHPA is believed to seal microfractures and coat shale surfaces with a film that retards dispersion and disintegration. KCl is used as a shale inhibitor in most PHPA mud designs. In low-solids muds, PHPA interacts with minimal concentrations of bentonite to link particles together and improve rheology without increased colloidal solids loading.Reference:Clark RK, Scheuerman RF, Raoth H and van Laar H: "Polyacrylamide-Potassium Chloride Mud for Drilling Water Sensitive Shales," Journal of Petroleum Technology 28, no. 6 (June 1976): 719-726.Reference:Fraser LJ: "New Method Accurately Analyzes PHPA's in Muds," Oil & Gas Journal 85, no. 27 (July 6, 1987): 39-42.

A class of water muds that use partially-hydrolyzed polyacrylamide (PHPA) as a functional additive, either to control wellbore shales or to extend bentoniteclay in a low-solids mud. As a shale-control mud, PHPA is believed to seal microfractures and coat shale surfaces with a film that retards dispersion and disintegration. KCl is used as a shale inhibitor in most PHPA mud designs. In low-solids muds, PHPA interacts with minimal concentrations of bentonite to link particles together and improve rheology without increased colloidal solids loading.Reference:Clark RK, Scheuerman RF, Raoth H and van Laar H: "Polyacrylamide-Potassium Chloride Mud for Drilling Water Sensitive Shales," Journal of Petroleum Technology 28, no. 6 (June 1976): 719-726.Reference:Fraser LJ: "New Method Accurately Analyzes PHPA's in Muds," Oil & Gas Journal 85, no. 27 (July 6, 1987): 39-42.

Abbreviation for productivity index.

Abbreviation for ProductionLogging Tool.

A solvent used with water to break the emulsion of an oil-base or synthetic-base drilling fluid to prepare the sample for chemical titrations to determine lime, calcium or chloride content according to API testing procedures. PNP is an abbreviation for propylene glycolnormal propyl ether. It is an environmentally friendlier replacement of a xylene-isopropynol mixture previously used in certain titrations.

A term used to describe the beginning of thickening of a cementslurry during the thickening-time test, often abbreviated as POD. For some slurries, the POD is used as the thickening time.

A specialized apparatus used in the particle-plugging test. The PPA is used to determine the ability of particles in the drilling fluid to effectively bridge the pores in the filtermedium and, therefore, the ability of the mud to reduce formation damage in the reservoir. The apparatus resembles a high-pressure, high-temperature filtration cell that has been modified to operate upside down (to remove the effects of gravity) and to accept filter media of different permeabilities (sintered metal, which is chosen for higher temperature conditions, aloxite, which is a porous ceramic material, or rock). The medium is selected to match the permeability of the reservoir to be drilled. The filter medium is at the top so that sediment will not affect the filter cake. Pressure is applied hydraulically from below.

A laboratory test used to determine if a drilling fluid blocks movement of filtrate through pore spaces of a shale sample. The PPT device monitors the increase in pore pressure in a shale when exposed to a drilling fluid over a period of time. Shale cores from 1 to 3-inches long are fitted into a modified Hassler cell that has sensitive pressure transducers in reservoirs on each end of the cell.Reference:van Oort E, Hale AH, Mody FK and Roy S: "Transport in Shales and the Design of Improved Water-Based Shale Drilling Fluids," in SPE Drilling and Completion 11, no. 3 (September 1996): 137-146

A mnemonic for the pseudostatic spontaneous potential.

A parameter of the Bingham plasticmodel. PV is the slope of the shearstress/shear rate line above the yield point. PV represents the viscosity of a mud when extrapolated to infinite shear rate on the basis of the mathematics of the Bingham model. (Yield point, YP, is the other parameter of that model.) A low PV indicates that the mud is capable of drilling rapidly because of the low viscosity of mud exiting at the bit. High PV is caused by a viscous base fluid and by excess colloidal solids. To lower PV, a reduction in solids content can be achieved by dilution of the mud.

A shorthand term for pressure, volume, temperature dependencies for fluid properties. In oil-base drilling fluids, PVT effects on viscosity and density must be understood to develop density and hydraulics programs. Downhole pressure makes the base oil more viscous and dense, whereas temperature has the opposite effect. Brines for downhole use also require an understanding of PVT behavior.

Protective clothing or equipment designed to protect the wearer from job-related hazards. Minimum required: hardhat, safety glasses, fire retardant coveralls, and steel-toed boots. Also known as PPE.

A chemical property of an aqueous system that implies that there are more hydroxyl ions (OH-) in the system, or a potential to produce more hydroxyl ions, than there are hydrogen ions (H+), or potential to produce hydrogen ions.

A double logarithmic plot of a resistivity measurement on the x-axis versus a porosity measurement on the y-axis. The plot is named after G.R. Pickett. The plot is based on taking the logarithm of the Archie equation. Points of constant water saturation (Sw) will plot on a straight line with negative slope of value m. Water zones define the lowermost line on the plot. Since Sw = 1, the water resistivity can be determined from a point on the line. Once the water line is established, other parallel lines can be drawn for different Sw, assuming a constant n (usually 2). Other data can then be plotted and interpreted in terms of Sw. The same technique can be applied to the flushed zone, using flushed-zone measurements.See Pickett GR: "A Review of Current Techniques for Determination of Water Saturation from Logs," paper SPE 1446, presented at the SPE Rocky Mountain Regional Meeting, Denver, Colorado, USA, May 23-24, 1966; SPE Journal of Petroleum Technology (November 1966): 1425-1435.

A hydraulic or pneumatic wrench used to make up or break out drill pipe, tubing, or casing on which the torque is provided by air or fluid pressure.

A measuring device for determining the gas-flow rate. It is composed of a 1/8-inch tube inserted horizontally along the axis of the gas flowline. The pressure at the end of the tube is compared with the static pressure to determine the final gas flow rate within the flow line.

A chemical property of an aqueous system that implies that there are more hydroxyl ions (OH-) in the system, or a potential to produce more hydroxyl ions, than there are hydrogen ions (H+), or potential to produce hydrogen ions.

A probabilitydistribution in which the mean and the variance are identical. This distribution was first described by S.D. Poisson, a French mathematician and physicist (1781-1840).

An elastic constant that is a measure of the compressibility of material perpendicular to applied stress, or the ratio of latitudinal to longitudinal strain. This elastic constant is named for Simeon Poisson (1781 to 1840), a French mathematician. Poisson's ratio can be expressed in terms of properties that can be measured in the field, including velocities of P-waves and S-waves as shown below.Note that if VS = 0, then Poisson's ratio equals 1/2, indicating either a fluid, because shear waves do not pass through fluids, or a material that maintains constant volume regardless of stress, also known as an ideal incompressible material. VS approaching zero is characteristic of a gas reservoir. Poisson's ratio for carbonate rocks is ~ 0.3, for sandstones ~0.2, and above 0.3 for shale. The Poisson's ratio of coal is ~ 0.4.

An air or inert gas device that minimizes pressure surges in the output line of a mud pump. Also called a surge dampener.

Slang for penetration rate, or the speed that the bit is drilling into the formation.

Slang for penetration rate, or the speed that the bit is drilling into the formation.

Hydrogen ion potential, which is the log10 of the reciprocal of hydrogen ion, H+, concentration. Mathematically, pH = log10 (1/[H+]), where [ ] represents mole/L. pH is derived from the ion-product constant of water, which at room temperature is 1 x 10-14 = [H+] x [OH-]. Pure water (at neutral pH) has equal concentrations of its two ions: [H+] = [OH-] = 10-7 mole/L. Log10 1/[H+] is 7, which is the pH of a neutral solution. The pH scale ranges from 0 to 14, and values below 7 are acidic and above 7 are basic.

A drilling-fluid test to measure pH of muds and mud filtrates, usually performed according to API specifications. The pH test uses a pH meter equipped with a glass-membrane measuring electrode and reference electrode, which read from 0 to 14. The preferred pH meter automatically compensates for temperature. Buffer solutions of pH = 4, 7 and 10 are specified for calibration of the meter. Color-matching pH paper and sticks are not recommended except for simple muds.

To effect hydraulic isolation, either with a sealing device, such as a packer, or with a specialized plastic or fluid, such as a sealing compound.

What Is a Packer? A packer is a downhole sealing device run on tubing or casing that compresses or inflates a rubber element against the wellbore wall to isolate the annular space between the tubing and casing string, enabling separate management of production zones, pressure control during drillstem testing, and safe delivery of hydraulic fracturing treatments. Key Takeaways Packers seal the annular space between tubing and casing to isolate wellbore zones from one another or from the surface. Mechanical set, hydraulic set, and inflatable designs each suit different wellbore geometries and operational requirements. Element materials range from nitrile (NBR) for standard service to Aflas and HNBR for high-temperature, high-pressure, and H2S environments. API 11D1 governs packer qualification testing, specifying pressure ratings up to 20,000 psi (1,379 bar) and temperatures up to 400 degrees F (204 degrees C) for HPHT applications. Retrievable packers allow workover reuse, while permanent packers offer higher pressure differentials but require milling to remove. How a Packer Works The fundamental sealing mechanism relies on forcing a rubber or elastomer element radially outward until it contacts and grips the casing inner diameter. In a compression-set mechanical packer, right-hand rotation of the tubing string or a series of weight-set-down operations drive slips into the casing wall and simultaneously compress the element. Once the slips anchor the tool body, additional downward load extrudes the element outward to form a pressure-tight seal. Shear pins or snap rings hold the compressed element in the set position throughout the service life of the installation. Hydraulic-set packers eliminate the need for pipe rotation or weight manipulation, making them essential in horizontal and high-angle wellbores where torque and drag prevent reliable mechanical setting. Hydraulic pressure applied down the tubing string or through a separate control line acts on a piston that drives the element into the casing. Many hydraulic packers use a J-slot or latch mechanism to lock the set position once pressure bleeds off, so the seal remains intact without continuous hydraulic supply. In highly deviated wells across the Montney and Duvernay plays in Alberta and British Columbia, hydraulic-set retrievable packers allow operators to perforate multiple zones in a single run, set the packer above each zone, fracture-stimulate, and then release and move uphole to the next stage. Inflatable packers operate on a bladder principle. A reinforced elastomeric element expands radially when fluid or gas pressure is injected through an inflation valve. Inflatable designs excel in openhole completions, cased-hole logging operations, and situations where the wellbore diameter varies significantly. Once inflated, a check valve holds inflation pressure without continuous surface pumping. Openhole bridge plugs used in multistage fracturing in Canada and the US Permian Basin frequently employ inflatable or swellable elements that expand on contact with reservoir fluids or water. Packer Types and Designs The industry distinguishes packers first by permanence. A retrievable packer can be released and recovered to surface using upward tubing pull, left-hand rotation, or a shifting tool on wireline or coiled tubing. Retrievable designs use J-slot release mechanisms, drag spring release, or shear-out options depending on the application. Maximum differential pressure ratings for retrievable packers typically range from 5,000 psi (345 bar) to 15,000 psi (1,034 bar), making them the preferred choice for standard production wells and most workover operations. Permanent packers, sometimes called cast-iron bridge plugs or production packers, use milling to remove rather than mechanical release. Permanent designs achieve higher differential pressure ratings, sometimes exceeding 20,000 psi (1,379 bar), because the mandrel can be fully bonded to the casing via slips and a non-releasing lock ring. High-pressure gas wells in the Deep Anadarko Basin of Oklahoma, tight gas sands in the Western Canadian Sedimentary Basin, and ultra-deep wells on the Norwegian Continental Shelf commonly rely on permanent-style packers where long-term seal integrity outweighs the value of retrievability. Swellable packers use an elastomeric element that swells when exposed to water, oil, or a combination of both. The swell process can take hours to weeks depending on fluid type and temperature, but once set the swell packer conforms precisely to irregular wellbore geometry without requiring mechanical manipulation. Swellable packers are common in openhole multi-zone completions in the Bakken and Cardium plays, where operators rely on a combination of swellable elements and ball-drop sleeves to stimulate individual zones without perforating and setting conventional bridge plugs. HPHT packers designed to API 11D1 V3-rated service must withstand continuous exposure to temperatures above 300 degrees F (149 degrees C) and pressures above 10,000 psi (690 bar). Elastomer selection becomes critical at these conditions. Hydrogenated nitrile butadiene rubber (HNBR) offers excellent resistance to sour gas and moderate temperatures. Aflas (tetrafluoroethylene-propylene copolymer) tolerates higher temperatures and stronger acid or amine environments. Perfluoroelastomers (FFKM) represent the top tier of material performance, used in wells with simultaneous exposure to H2S, CO2, and temperatures above 400 degrees F (204 degrees C) such as deep carbonate reservoirs in the Permian Basin and Arabian Peninsula. Fast Facts The global packer market serves an estimated 60,000 to 80,000 well completions annually. HPHT packers rated to API 11D1 V3 standards tolerate 20,000 psi (1,379 bar) differential pressure and 400 degrees F (204 degrees C). A retrievable packer element compressed against 9.625-inch (244 mm) casing exerts a seating force of 30,000 to 80,000 lbf (133 to 356 kN) depending on design. Swellable packer elements can expand 100 to 250 percent of their original diameter when activated. In the Norwegian North Sea, HPHT wells routinely require two or more independent packer seals to comply with the NORSOK D-010 well integrity standard. Canadian operators running multistage fracturing in the Montney can set, stimulate through, and release a retrievable packer in less than two hours per zone using coiled tubing-conveyed packers. Packer Standards and Pressure Ratings API 11D1 "Packers and Bridge Plugs" is the primary qualification standard governing packer testing and performance ratings worldwide. The standard defines five service rating classes. Class V1 covers standard service: temperatures up to 250 degrees F (121 degrees C) and pressures up to 5,000 psi (345 bar). Class V3, the HPHT tier, certifies 400 degrees F (204 degrees C) and 20,000 psi (1,379 bar). ISO 14310 provides an internationally harmonized alternative used extensively on Norway's Continental Shelf and in Middle Eastern projects governed by Saudi Aramco or ADNOC engineering standards. Tubing movement calculations are mandatory before finalizing any permanent packer installation. Four distinct forces act on the tubing string after the packer is set: temperature change (causes tubing elongation or contraction), ballooning (internal pressure forces tubing outward, shortening it axially), piston effect (pressure differential on cross-sectional area changes tubing length), and Helical buckling (compression loads cause a spiral displacement that shortens effective tubing length). Engineers run these calculations in well planning software, then select the correct packer no-go setting depth, tubing length correction, and expansion joint specification to ensure the tubing neither parts under tension nor buckles into the packer bore under compression. Packers Across International Jurisdictions In Canada, Alberta Energy Regulator Directive 008 governs well completion and servicing operations, requiring documented packer test pressures and confirmation of annular seal integrity before a well is placed on production. Operators in the Deep Basin of northwest Alberta and the Montney fairway routinely run retrievable bridge plug-packer combinations in horizontal wells with 30 to 80 perforation clusters. Each cluster requires isolation from adjacent clusters, making packer and frac plug selection a critical part of completion engineering. In the United States, Bureau of Safety and Environmental Enforcement regulations for offshore Gulf of Mexico wells require that all wellbore barriers including packers meet MMS/BSEE pressure integrity requirements. The Texas Railroad Commission and Colorado Oil and Gas Conservation Commission impose wellbore integrity reporting obligations that effectively require packer qualification data to be on file before production commences. Onshore US unconventional operators in the Permian Basin Wolfcamp and Delaware Basin sections routinely use dissolvable frac plugs, which serve as temporary packers during multistage fracturing and then dissolve in wellbore fluids over 30 to 90 days, eliminating the need for a coiled tubing plug-drill run. On the Norwegian Continental Shelf, NORSOK Standard D-010 requires at least two independent pressure barriers in all wells at all times, including during completion operations. This dual-barrier philosophy means a packer alone is insufficient unless a second barrier, such as a closed downhole safety valve or a casing cement bond confirmed by cement bond log, exists in series. Equinor and Aker BP run extensive HPHT packer qualification tests internally in addition to API 11D1, because North Sea reservoir conditions in the Balder and Alvheim fields commonly exceed 15,000 psi (1,034 bar) at temperatures above 300 degrees F (149 degrees C). Across the Middle East, Abu Dhabi National Oil Company (ADNOC) and Saudi Aramco employ permanent production packers with polished bore receptacles (PBR) that allow the production tubing to telescope in and out with thermal changes while maintaining a seal at the packer face. Carbonate reservoir wells in the Arab D and Khuff formations, which can exceed 18,000 psi (1,241 bar) reservoir pressure, require dual redundant permanent packers with metal-to-metal backup seals that supplement the primary elastomeric element. Australian offshore operations in the North West Shelf and Browse Basin similarly require HPHT-rated packers, with NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority) overseeing well integrity compliance. Tip: When selecting an elastomer for a packer in a well with co-mingled H2S and CO2, always request a compatibility soak test at representative downhole temperature and partial pressures before finalizing the specification. An elastomer rated for H2S at surface conditions can fail catastrophically from explosive decompression when CO2 partial pressure is high and the tool is pulled to surface too quickly. HNBR and Aflas perform differently under these conditions and the soak test data from the packer manufacturer or an independent lab like Intertek or Bureau Veritas will indicate safe decompression rates. Packer Synonyms and Related Terminology Production packer: a permanent or retrievable packer set at the base of the production tubing to isolate the producing zone from the annulus above it. Bridge plug: a specific packer variant designed to plug the wellbore below a zone of interest rather than support a tubing string above it. Frac plug: a temporary bridge plug used in multistage hydraulic fracturing to isolate previously stimulated perforations from the current stimulation stage. Packer element: the rubber or elastomeric sealing component of the packer that contacts the casing wall. Polished bore receptacle (PBR): a tubular extension above a permanent packer that accepts a sealbore assembly on the production tubing, allowing thermal expansion movement without breaking the seal. Retrievable production packer: a packer designed for easy retrieval via pipe manipulation or shifting tools, typically used where future workover access is anticipated. Swellable packer: a packer whose element expands through chemical absorption of formation fluids rather than mechanical compression or hydraulic inflation. Related terms: well control, casing, coiled tubing, completion fluid, drillstem test, hydraulic fracturing, H2S, workover, casing string.

A device for measuring in situ the velocity of fluid flow in a production or injection well in which a packer is inflated between the tool housing and the casing wall, causing the total fluid flow to pass inside the tool and over a spinner. The measurement is made with the tool stationary, after borehole fluids have been pumped to inflate the packer. The packer flowmeter was introduced in the mid-1950s. It is a type of diverter flowmeter, but has generally been replaced by petal basket and inflatable diverter flowmeters.

The fluid that remains in the tubing-casingannulus above the packer after the completion has been run and all circulation devices have been isolated. Packer fluids are prepared for the requirements of the given completion. Generally, they should be of sufficient density to control the producing formation, be solids-free and resistant to viscosity changes over long periods of time, and be noncorrosive to the wellbore and completion components.

A device used to seal around a reciprocating or rotating shaft or spindle. A malleable packing compound is forced into place by an adjustable packing nut, or similar arrangement. This enables the seal or packing to be tightened to suit the operating conditions and allows subsequent adjustment to account for wear.

To effect hydraulic isolation, either with a sealing device, such as a packer, or with a specialized plastic or fluid, such as a sealing compound.

That part of a wireline logging tool that is pressed firmly against the borehole wall. The pad holds sensors that are focused in one direction and must be as close as possible to the borehole wall. The density detectors and the microresistivity electrodes are examples of sensors that must be placed on pads. Some pads are a rigid part of the logging tool. Others have articulated joints attaching them to the logging tool, with a backup arm to press the pad against the borehole wall.

A type of fluid-mixing tank used in the preparation of treatment fluids or slurries that provides the agitation to achieve a well-dispersed mixture. Paddle mixers are generally equipped with rotating paddles that provide turbulence for mixing fluids and an action that prevents the settling of solids prior to being pumped.

An oil and gas lease in which delay rentals for the entire primary term are paid in advance with the bonus consideration.

A gamma ray interaction in which the gamma ray, or photon, is converted into an electron and a positron when the gamma ray enters the strong electric field near the nucleus of an atom. The gamma ray energy must equal at least the rest mass of an electron and a positron (1.022 MeV) for the interaction to be possible. Following pair production, the positron will annihilate with an electron, emitting two gamma rays of 0.511 MeV. The highest probability of occurrence is at high gamma ray energy, above 10 MeV, and in a material of high atomic number.

The study of fossilized, or preserved, remnants of plant and animal life. Changes in the Earth through time can be documented by observing changes in the fossils in successive strata and the environments in which they formed or were preserved. Fossils can also be compared with their extant relatives to assess evolutionary changes. Correlations of strata can be aided by studying their fossil content, a discipline called biostratigraphy.

Pertaining to a depositional environment or organisms from a marsh. It also refers to the type of environment in which palustrine sediments can accumulate.

Describing material deposited in or growing in a marsh.

The study of fossilized remnants of microscopic entities having organic walls, such as pollen, spores and cysts from algae. Changes in the Earth through time can be documented by studying the distribution of spores and pollen. Well log and other correlations are enhanced by incorporating palynology. Palynology also has utility in forensics.

A hydrocarbon compound that often precipitates on production components as a result of the changing temperatures and pressures within the production system. Heavy paraffins occur as wax-like substances that may build up on the completion components and may, if severe, restrict production.Paraffin is normally found in the tubing close to surface. Nevertheless, it can form at the perforations, or even inside the formation, especially in depleted reservoirs or reservoirs under gas-cycling conditions.

A set of techniques used to prevent or considerably reduce paraffin deposition. Paraffin control might involve the following options:· use of paraffin inhibitors.· maintaining pipe surfaces in a water-wet condition because paraffin will not adhere to water. However, the presence of natural surfactants in some crude oils converts water-wet surfaces to an oil-wet condition, making this technique effective only temporarily.· coating the pipe with plastic to provide a smooth surface and reduce paraffin adhesion.· reducing heat transfer to maintain the oil temperature above its cloud point. Filling the annulus of a well with a fluid that has poorer heat transfer properties than the oil maintains the temperature of the flowing crude oil above its cloud point.

A chemical injected into the wellbore to prevent or minimize paraffin deposition. The effectiveness of paraffin inhibitors is strongly dependent on crude oil composition.Paraffin inhibitors must be introduced into the oil before the oil cools to its cloud point. In additional, asphaltene composition should be determined before treatment because it can reduce the effectiveness of the paraffin inhibitor. In some cases, the use of a paraffin inhibitor can actually increase the rate of paraffin deposition because the stability of colloidalasphaltenes is disturbed.

(noun) A mechanical tool run on wireline, slickline, or sucker rods inside the production tubing to remove accumulated paraffin wax deposits from the inner wall, restoring the full bore diameter and maintaining production flow rates in wells susceptible to wax deposition.

A downhole tool, generally run on slickline, used to remove paraffin and soft wax deposits from the internal wall of productiontubulars and completion equipment.

A crude oil containing paraffin wax but very few asphaltic materials. This type of oil is suitable for motor lubricating oil and kerosene.

The group of hydrocarbons consisting of linear molecules with the formula CnH2n+2. Methane, CH4, is the simplest member. Higher members, starting at about C18, are wax-like and are called paraffin. Excessive amounts of paraffinic hydrocarbons in an oil mud adversely affect mud flow and oil removal from cuttings at cool temperatures.

A commonly used preservative for starch, xanthan gum, guar gum and other natural polymers that are prone to attack by bacteria. It is as a trimer of formaldehyde and has the formula O-CH2-O-CH2-O-CH2. Paraformaldehyde is a white, water soluble powder. When added to a mud in advance of a bacterial inoculation and maintained, paraformaldehyde can effectively control many strains of bacteria. The amount or paraformaldehyde in a mud can be estimated by oxidizing it with sulfite into formic acid and performing an alkalinitytitration, according to a procedure published by API.

The deformation of rock layers in which the thickness of each layer, measured perpendicular to initial (undeformed) layering, is maintained after the rock layers have been folded.

The resistivity of a formation measured by flowing current parallel to the bedding planes. In anisotropic formations, the parallel and perpendicular resistivities are different.

A variable that is given a constant value for the purposes of certain calculations. For example, during log analysis of a particular layer of a reservoir, the water resistivity (Rw) may be set to a particular value and referred to as a parameter.

Pertaining to a method of seismic inversion to separate wavefields by iteratively developing a model of the data that conforms to the recorded data. Parametric inversion is used in processing vertical seismic profile (VSP) data.

Relatively conformable depositional units bounded by surfaces of marine flooding, surfaces that separate older strata from younger and show an increase in water depth in successively younger strata. Parasequences are usually too thin to discern on seismic data, but when added together, they form sets called parasequence sets that are visible on seismic data.

A marine flooding surface or its correlative surface.

A succession of genetically related parasequences that form a distinctive stacking pattern, and that are typically bounded by major marine flooding surfaces and their correlative surfaces. Parasequence sets are usually classified as progradational, aggradational or retrogradational.

Completion of or flow from less than the entire producing interval. This situation causes a near-well flow constriction that results in a positive skin effect in a well-test analysis.

An incompletely drilled portion of the productive interval.

The proportion of exploration and production costs each party will bear and the proportion of production each party will receive, as set out in an operating agreement.

A specialized apparatus used in the particle-plugging test. The PPA is used to determine the ability of particles in the drilling fluid to effectively bridge the pores in the filtermedium and, therefore, the ability of the mud to reduce formation damage in the reservoir. The apparatus resembles a high-pressure, high-temperature filtration cell that has been modified to operate upside down (to remove the effects of gravity) and to accept filter media of different permeabilities (sintered metal, which is chosen for higher temperature conditions, aloxite, which is a porous ceramic material, or rock). The medium is selected to match the permeability of the reservoir to be drilled. The filter medium is at the top so that sediment will not affect the filter cake. Pressure is applied hydraulically from below.

The weight, or net volume, of solid particles that fall into each of the various size ranges, given as a percentage of the total solids of all sizes in the sample of interest. Particle size can be determined by sieve analysis, light scattering, passage through an electrically charged orifice, settling rate or other methods. Data are typically shown as a histogram chart with percentage-smaller-than on the y-axis and size ranges on the x-axis. Mud engineers use such data to operate solids-control equipment effectively. Particle-size distributions are used to evaluate bridging materials for drill-in and completion fluids. Barite and hematite samples are examined to ensure performance without excessive wear on equipment and as an API/ISO quality specification.

A specialized apparatus used in the particle-plugging test. The PPA is used to determine the ability of particles in the drilling fluid to effectively bridge the pores in the filter medium and, therefore, the ability of the mud to reduce formation damage in the reservoir. The apparatus resembles a high-pressure, high-temperature filtration cell that has been modified to operate upside down (to remove the effects of gravity) and to accept filter media of different permeabilities (sintered metal, which is chosen for higher temperature conditions, aloxite, which is a porous ceramic material, or rock). The medium is selected to match the permeability of the reservoir to be drilled. The filter medium is at the top so that sediment will not affect the filter cake. Pressure is applied hydraulically from below.

A test performed in a specialized filtration-type apparatus (particle-plugging apparatus) to determine the effectiveness of additives to prevent fluid loss into a permeable medium.

The weight, or net volume, of solid particles that fall into each of the various size ranges, given as a percentage of the total solids of all sizes in the sample of interest. Particle size can be determined by sieve analysis, light scattering, passage through an electrically charged orifice, settling rate or other methods. Data are typically shown as a histogram chart with percentage-smaller-than on the y-axis and size ranges on the x-axis. Mud engineers use such data to operate solids-control equipment effectively. Particle-size distributions are used to evaluate bridging materials for drill-in and completion fluids. Barite and hematite samples are examined to ensure performance without excessive wear on equipment and as an API/ISO quality specification.

The degree of solubilization of a solute into each of multiple immiscible phases at equilibrium. For example, a water-soluble surfactant injected as part of an enhanced oil recovery flood will partially solubilize, or partition, in the oil phase. The degree of partitioning will influence the efficiency of the enhanced oil recovery agent.

A crew that acquires a survey or geophysical data.

The ultimate leader of a survey crew.

The actual leader of a survey crew. The party manager reports to the party chief.

(noun) In production logging, a single traverse of a logging tool through the wellbore, either upward or downward, during which measurements are recorded. Multiple passes at different logging speeds and flow conditions are typically made to ensure data quality and repeatability.

The margin of a continent and ocean that does not coincide with the boundary of a lithospheric plate and along which collision is not occurring. Passive margins are characterized by rifted, rotated fault blocks of thick sediment, such as the present-day Gulf of Mexico and Atlantic margins of North America.

A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The term derives from the fact that it is capable of "paying" an income. Pay is also called pay sand or pay zone. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as minimum porosity, permeability and hydrocarbon saturation) are net pay.

The point at which all costs of leasing, exploring, drilling and operating have been recovered from production of a well or wells as defined by contractual agreement.

The maximum positive or upward deflection, also known as the crest, of the seismic wavelet. The trough is the maximum negative amplitude or downward deflection of the wave. Seismic interpreters commonly pick or interpret seismic data on paper sections along the trough of a wavelet rather than the normally solid-filled peak for ease of viewing.

A type of short-path multiple, or multiply-reflected seismic energy, having an asymmetric path. Short-path multiples are added to primary reflections, tend to come from shallow subsurface phenomena and highly cyclical deposition, and can be suppressed by seismic processing. In some cases, the period of the peg-leg multiple is so brief that it interferes with primary reflections, and its interference causes a loss of high frequencies in the wavelet.

A standard laboratory instrument used to measure interfacial tension. The method is particularly applicable to relatively high interfacial tensions, but with care can measure down to approximately 1 mN/m. A drop of the denser liquid is poised at the end of a square-ended syringe needle. The drop is of sufficient size that its shape is deformed by gravity, but not so large that it detaches from the syringe. Its shape is determined by the balance of interfacial tension and gravity. The interfacial tension can be obtained from the drop shape and the densities of the two liquids. The method works equally well for a drop of the less-dense liquid by inverting the syringe. This inverted configuration can be useful if the less-dense liquid is opaque.

To disperse a substance into a colloidal form or to disperse a clay in water to form a colloidal suspension.

A clay that has been treated during manufacturing to enhance its dispersion.Reference:Garrett RL: "Quality Requirements for Industrial Minerals Used in Drilling Fluids," Mining Engineering 39, no. 11 (November 1987): 1011-1016.

A product that enhances dispersion of a substance (such as clay) into colloidal form. Peptizing agents for drilling-mud clays are sodium carbonate, sodium metaphosphates, sodium polyacrylates, sodium hydroxide and other water-soluble sodium compounds, even common table salt, NaCl, if added at low concentration. The divalent cations on a clay are replaced by the sodium cations, aiding clay hydration and dispersion. Greater benefit is attained by an agent that contributes an anion (for example, carbonate, phosphate or polyacrylate) that precipitates divalent cations and removes them from solution. This process is successful only when the water first contacted is free of hardness ions, otherwise the anion in the peptizing salt (or polymer) will be precipitated by the hard water and make the peptizing agent much less effective.

The creation of holes in the casing or liner to achieve efficient communication between the reservoir and the wellbore. This process is integral to the optimal creation of hydraulic fractures. Geomechanical analysis is commonly conducted before perforating shale reservoirs to account for the relationship between formation stresses and productivity.

To create holes in the liner or casing under conditions in which the hydrostatic pressure inside the casing or liner is greater than the reservoir pressure. When the perforation is made, there will be a tendency for the wellbore fluid to flow into the reservoir formation.

To create holes in the liner or casing under conditions in which the hydrostatic pressure inside the casing or liner is less than the reservoir pressure. When the perforation is made, there will be a tendency for the reservoir fluid to flow into the wellbore.

The section of wellbore that has been prepared for production by creating channels between the reservoirformation and the wellbore. In many cases, long reservoir sections will be perforated in several intervals, with short sections of unperforated casing between each interval to enable isolation devices, like packers, to be set for subsequent treatments or remedial operations.

A wellbore tubular in which slots or holes have been made before the string is assembled and run into the wellbore. Perforated liners typically are used in small-diameter wellbores or in sidetracks within the reservoir where there is no need for the liner to be cemented in place, as is required for zonal isolation.

An acid treatment placed in the wellbore over the interval to be perforated. Because of the overbalance conditions at the time of perforating, the perforating acid is forced into the newly formed perforation tunnel to stimulate the crushed zone. Formulation of the perforating acid depends on the characteristics of the formation and the downhole equipment used.

(noun) A shaped explosive device, typically consisting of a metal case, explosive liner, and detonating cord, that is loaded into a perforating gun and detonated downhole to create a high-velocity jet capable of penetrating casing, cement, and formation rock to establish flow communication between the reservoir and the wellbore.

A wireline log run to provide a means of depth correlation by comparing the position of casing collars to the reference log (gamma ray log). A short casing joint generally is run near the area to be perforated to assist in the correlation process.

A specially prepared fluid placed in the wellbore over the interval to be perforated. The ideal fluid is clean and solids-free (filtered), and will not react to cause damaging by-products on contact with the reservoir formation. Perforating in a dirty fluid may result in significant permeabilitydamage that is difficult to treat and remove.

A device used to perforate oil and gas wells in preparation for production. Containing several shaped explosive charges, perforating guns are available in a range of sizes and configurations. The diameter of the gun used is typically determined by the presence of wellbore restrictions or limitations imposed by the surface equipment.

What Is Perforation? Perforation is the engineered communication tunnel through steel casing, cement sheath, and into the reservoir formation that establishes the primary flow path between the producing interval and the wellbore. Created by detonating shaped explosive charges inside a gun assembly deployed on wireline, coiled tubing, or production tubing, perforations determine where, how efficiently, and at what rate a well produces throughout its life. Key Takeaways Jet perforating uses shaped explosive charges to generate a high-velocity metallic jet reaching up to 8,000 metres per second (26,247 feet per second) that penetrates casing, cement, and formation rock to create a tunnel several centimetres in diameter and up to 610 millimetres (24 inches) deep. Key design parameters include shots per foot (SPF), phasing angle, penetration depth, and entrance hole diameter; these parameters are standardized and evaluated under API RP 19B test procedures using linear and sandstone targets. The crushed and compacted zone surrounding each perforation tunnel reduces local effective permeability to 5 to 20% of virgin formation permeability, creating positive skin damage that stimulation treatments must overcome to achieve economic production rates. Underbalance perforating, in which wellbore pressure is held below reservoir pressure at the moment of detonation, draws crushed-zone debris into the wellbore and significantly reduces perforation skin compared to overbalance conditions. Perforation design is a primary lever in completion engineering for hydraulic fracturing: phasing, density, and interval selection determine whether transverse or longitudinal fractures initiate in horizontal wells and whether stimulation achieves the targeted drainage geometry. How Jet Perforating Works Shaped charge jet perforating applies the Munroe effect, first described in ordnance science in the late 19th century, to petroleum well completion. Each charge consists of a case (typically steel or aluminum), a main explosive fill (usually HMX, RDX, or PETN, chosen for detonation velocity, temperature rating, and sensitivity), a metal liner (copper, aluminum, or tungsten) formed into a cone, and a primer/booster assembly connecting to a detonating cord that carries the firing impulse from charge to charge along the gun. When the detonating cord fires, the explosive detonates from the base of the cone toward the apex; the detonation pressure collapses the metal liner inward and forward, forming a coherent jet of metal particles traveling at velocities between 6,000 and 8,000 metres per second (19,685 to 26,247 feet per second) at the tip. This jet penetrates the gun body, the casing wall, the cement sheath behind the casing, and extends into the formation, leaving behind a cylindrical tunnel whose length and diameter depend on charge design, standoff distance from the casing ID, and formation mechanical properties. The resulting perforation geometry is characterized by four measurements: entrance hole diameter (the opening in the casing, typically 6 to 13 millimetres / 0.25 to 0.5 inches), penetration depth (the total tunnel length from casing ID into the formation, typically 200 to 610 millimetres / 8 to 24 inches), phasing angle (the rotational relationship between successive charges around the gun's circumference), and shot density (shots per foot, or SPF, of perforated interval). API RP 19B establishes the standardized laboratory test procedures for measuring these parameters: Section 1 tests penetration in a linear concrete target; Section 4 uses Berea sandstone targets to simulate penetration under realistic compressive stress; Section 6 tests under simulated formation damage conditions. Published charge performance data in manufacturers' product sheets reference API RP 19B test conditions, allowing engineers to compare charges on a consistent basis. Around each perforation tunnel, the detonation pressure creates a crushed and compacted zone of damaged formation rock. This zone, typically 6 to 25 millimetres (0.25 to 1 inch) thick, has effective permeability ranging from 5 to 20% of virgin formation permeability, representing the primary source of perforation skin damage (positive skin factor, S). The Karakas-Tariq model, published in SPE Production Engineering in 1991, remains the industry-standard analytical framework for calculating perforation skin from geometric parameters including penetration depth, SPF, phasing, and perforation tunnel length to diameter ratio. Hydraulic fracturing, acid stimulation, or post-perforation flow-back can partially remove or bypass the crushed zone and reduce skin, but the initial damage constrains productivity in unstimulated completions. Perforation Across International Jurisdictions Canada (Alberta): The Alberta Energy Regulator governs wireline and explosive perforating operations through AER Directive 084, which specifies requirements for licensed explosives handlers, gun loading procedures, transport of perforating charges as classified explosives under Transport Canada regulations, wellsite safety plans, and post-job reporting. Surface casing vent flow testing and downhole pressure monitoring requirements apply to all completions, including perforated intervals, under AER Directive 020. In SAGD and heavy oil thermal wells where steam injection creates HPHT conditions, perforating charges must be rated for bottomhole temperatures that can exceed 260 degrees Celsius (500 degrees Fahrenheit); specialized high-temperature HMX or TATB explosive fills replace standard PETN, which degrades above approximately 150 degrees Celsius (302 degrees Fahrenheit). The AER Integrated Decision Approach (IDA) framework requires operators to document completion designs including perforating programs in their application for well licenses under the Oil and Gas Conservation Act. United States: On the Outer Continental Shelf, BSEE regulates explosive perforating under 30 CFR Part 250, Subpart E (well operations and equipment), and Subpart I (platforms and structures). Operators must submit a Sundry Notice or Well Operations Notice before perforating operations on federal leases and must maintain records of charge specifications, gun inventory, and well pressure data during and after perforating. The Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF) regulates the transport, storage, and use of perforating charges as commercial explosives under 18 U.S.C. Chapter 40 and 27 CFR Parts 555 and 647. Onshore, the Texas Railroad Commission requires operators to report perforated intervals and completion methods on the Oil or Gas Well Completion Report (Form W-2). In unconventional tight-oil plays including the Permian Basin, Midland Basin, Eagle Ford, and Bakken, high-density perforating (HDP) at 12 to 21 SPF has become the dominant completion design, driven by the need to initiate closely spaced transverse hydraulic fractures in horizontal wellbores of 2,000 to 4,000 metres (6,562 to 13,123 feet) measured depth. Middle East: Saudi Aramco operates multi-zone perforating programs across the Ghawar, Shaybah, Khurais, and offshore Manifa fields, where long intervals (150 to 600 metres / 492 to 1,969 feet) of carbonate reservoir require selective phasing and charge optimization to achieve uniform drawdown across the entire producing column. HPHT reservoirs in the deep Khuff carbonate formation, targeting natural gas at depths exceeding 5,000 metres (16,404 feet) with pressures above 700 bar (10,153 psi) and temperatures above 200 degrees Celsius (392 degrees Fahrenheit), require special explosive compositions and stainless-steel gun bodies rated for extreme wellbore environments. Abu Dhabi National Oil Company (ADNOC) applies TCP programs in offshore fields including Umm Shaif and Zakum, where completions in thin carbonate pay stringers require precise depth control and selective perforating using gamma-ray correlation from wireline logs to position guns within centimetres of target intervals. The UAE Federal Petroleum Authority and emirate-level regulators require perforating programs to be submitted as part of well completion plans. Australia: NOPSEMA requires that all perforating operations on Australian offshore installations be described in the Well Operations Management Plan (WOMP), which must identify the explosive type, quantity, gun specifications, underbalance or overbalance design, and emergency procedures. The Carnarvon Basin offshore Western Australia, home to major LNG-linked gas fields including Gorgon, Wheatstone, and Scarborough, features HPHT gas reservoirs where TCP programs are standard. TCP allows large-diameter guns to be deployed on the production tubing string, fired simultaneously across long perforated intervals on tubing pressure, and the well then placed on immediate production flow-back to clean the crushed zone before the tubing is pulled. The Northern Territory's Beetaloo Sub-basin, an emerging shale gas play, is expected to apply HDP designs similar to North American unconventional completions, with 12 to 16 SPF and 60-degree phasing to optimize transverse fracture initiation under supervision of the Northern Territory Resources Regulator. Norway and the North Sea: Equinor, Aker BP, and other Norwegian Continental Shelf operators apply selective interval perforating in complex multilateral and multi-zone wells under production programs approved by Sodir (formerly NPD). The Johan Sverdrup field, developed with submersible pump completions and sophisticated inflow control devices, uses zonal isolation packers and selective perforating to manage drawdown across the Ekofisk, Draupne, and Sleipner formations. UK North Sea operators, regulated by the NSTA, routinely apply TCP in the Clair Ridge, Schiehallion, and Greater Stella Area fields, where deepwater HPHT conditions and the need for single-trip completion efficiency justify the additional complexity of TCP gun systems over conventional wireline perforating. The UK HSE's offshore safety regime requires explosive inventory management and safety case demonstration for any operation involving perforating charges on manned platforms. Fast Facts Shaped charge perforating guns fire at detonation velocities of 6,000 to 8,500 metres per second (19,685 to 27,887 feet per second), completing the perforation event in microseconds. Standard shot densities range from 4 SPF for simple production completions to 21 SPF for high-density perforating programs designed to initiate tightly spaced hydraulic fracture clusters. API RP 19B Section 4 Berea sandstone targets are tested at a confining stress of 3,000 to 6,000 psi (207 to 414 bar) to replicate formation compressive stress on penetration depth and entrance hole diameter. The crushed zone permeability impairment created by perforating typically contributes a skin factor of +5 to +20 in an unstimulated vertical well, representing a significant productivity penalty that hydraulic fracturing or acid stimulation must overcome. Tubing-conveyed perforating allows guns up to 5.5 inches (139.7 mm) in diameter to be run inside 7-inch (177.8 mm) casing, delivering substantially more penetration depth and larger entrance holes than through-tubing wireline guns of 2.5 to 3.5 inch (63.5 to 88.9 mm) diameter. High-temperature perforating charges using TATB (1,3,5-triamino-2,4,6-trinitrobenzene) explosive fill retain performance integrity at temperatures up to 260 degrees Celsius (500 degrees Fahrenheit) for exposures of 100 hours or more.

The number of perforations per linear foot. This term is used to describe the configuration of perforating guns or the placement of perforations, and is often abbreviated to spf (shots per foot). An example would be an 8 spf casing gun.

A measure, or indicator, of the length that a useable perforation tunnel extends beyond the casing or liner into the reservoir formation. In most cases, a high penetration is desirable to enable access to that part of the formation that has not been damaged by the drilling or completion processes.

The radial distribution of successive perforating charges around the gun axis. Perforating gun assemblies are commonly available in 0-, 180-, 120-, 90- and 60-degree phasing. The 0-degree phasing is generally used only in small outside-diameter guns, while 60, 90 and 120 degree phase guns are generally larger but provide more efficient flow characteristics near the wellbore.

A graphical representation of harmonic information in a data set. Often taken from Fourier analysis of the data, this representation is used to determine periodicities in petrophysical data and in geological depositional sequences.

The permanently frozen subsoil that lies below the upper layer (the upper several inches to feet) of soil in arctic regions.

The level to which all subsurface depths in an area are referred, normally the mean sea level. In individual wells, the depth is measured from the depth reference. However, in order to compare data between wells it is important to have a valid, area wide reference for comparison. This is the permanent datum level.

A situation in which the well and the reservoir are continuously monitored. On the basis of this information, the well completion may be adjusted remotely to adapt to changes in downhole conditions. A permanent well monitoring system is composed of the following:· Inflow control valves that enable choking or shutting off different zones according performance such as drawdown, GOR or water cut· Downhole sensors that register pressure, fluid flow rate and temperature· Control lines for power transmission and transferring of monitored downhole data captured by downhole sensors.· A surface control unit to handle the monitored data and for remote operation of the downhole inflow control valves.Wells with permanent monitoring systems are commonly called intelligent or smart wells. Permanent well monitoring is commonly used in multilateral wells, where hydraulically independent valves control the flow of each lateral and in deepwater wells, where well-intervention operations are often prohibitively expensive.Permanent well monitoring helps improve reservoir management by quickly choking or shutting off zones, avoiding expensive well intervention. It also helps maximize production and optimize recovery.

What Is Permeability? Permeability quantifies a rock's capacity to transmit fluids under a pressure gradient, governing how readily oil, gas, or water moves through interconnected pore spaces in a reservoir. Defined mathematically by Henry Darcy in 1856, it remains the single most important parameter controlling well productivity, recovery efficiency, and economic viability in reservoirs worldwide, from conventional sandstones to ultra-tight shale plays. Key Takeaways Permeability is measured in millidarcies (mD) or microdarcies (microD) and describes how easily fluids move through a porous rock under a given pressure difference. Darcy's Law relates volumetric flow rate directly to permeability, cross-sectional area, pressure gradient, fluid viscosity, and flow length, forming the quantitative foundation of reservoir engineering. Absolute permeability is measured with a single fluid; effective permeability accounts for multiple coexisting fluid phases; relative permeability normalizes effective values to absolute for use in reservoir simulation. Conventional reservoirs typically range from 1 to 1,000 mD, tight gas sands from 0.001 to 1 mD, and shale formations from 0.000001 to 0.001 mD (nanodarcies), with this range spanning nine orders of magnitude. Permeability is determined through routine core analysis, special core analysis, well testing, and NMR log interpretation, with each method sampling a different scale and providing complementary information. How Permeability Works The quantitative basis for permeability is Darcy's Law, derived empirically by Henry Philibert Gaspard Darcy from experiments on sand-packed columns in Dijon, France in 1856. The fundamental form states: Q = (k × A × ΔP) / (μ × L), where Q is volumetric flow rate (cm³/s), k is permeability (darcies), A is cross-sectional area perpendicular to flow (cm²), ΔP is the pressure differential driving flow (atm), μ is dynamic fluid viscosity (centipoise, cP), and L is flow path length (cm). One darcy is defined as the permeability that permits 1 cm³/s of a 1 cP fluid to flow through a 1 cm² cross-section under a 1 atm/cm pressure gradient. In practice, most reservoir rocks have permeabilities well below one darcy, so the millidarcy (1 mD = 0.001 D) is the standard working unit. Tight formations are often reported in microdarcies (1 microD = 0.001 mD) or nanodarcies (1 nD = 0.001 microD). In petroleum engineering, Darcy's Law is cast in Darcy units and then converted to field units. The radial-flow form used in well test analysis is: Q = (0.00708 × k × h × ΔP) / (μ × B × [ln(re/rw) - 0.75 + S]), where h is net pay thickness in feet, B is formation volume factor (res bbl/STB), re is drainage radius (ft), rw is wellbore radius (ft), and S is skin (dimensionless). The product kh, called transmissibility or flow capacity, is reported in mD-ft or mD-m and is the reservoir's ability to move fluids per unit pressure drop. Transmissibility is the parameter actually estimated by pressure transient analysis, because k and h are individually uncertain but their product controls deliverability. Permeability is an intrinsic property of the rock fabric, not the fluid, but it is measured and reported in the context of specific fluids. The Klinkenberg effect describes gas slippage at low pore pressures in tight rocks: gas molecules travel through pores with a mean free path comparable to the pore throat diameter, artificially inflating apparent gas permeability above liquid-equivalent permeability. Laboratory measurements on core plugs apply the Klinkenberg correction by plotting measured gas permeability against reciprocal mean pore pressure and extrapolating to infinite pressure to obtain the liquid-equivalent (Klinkenberg-corrected) permeability. This correction is critical for tight gas and shale reservoirs where gas permeabilities measured at low confining stress can overstate deliverability by factors of two to five. Permeability Across International Jurisdictions Canada (AER and BCER): The Montney Formation, straddling northeastern British Columbia and northwestern Alberta, represents one of the largest tight gas and liquids-rich condensate plays in North America. Montney permeabilities typically range from 0.001 to 0.1 mD (1 to 100 microD), requiring multi-stage hydraulic fracturing to achieve economic flow rates. The Alberta Energy Regulator (AER) classifies Montney as an unconventional reservoir under its resource assessment framework, applying SPE-PRMS (Society of Petroleum Engineers Petroleum Resources Management System) criteria, where permeability below 0.1 mD commonly defines the unconventional threshold. The British Columbia Energy Regulator (BCER) applies comparable definitions. In the Athabasca oil sands, in situ SAGD (Steam-Assisted Gravity Drainage) reservoirs in the McMurray Formation exhibit horizontal permeabilities of 1,000 to 10,000 mD (1 to 10 darcies) in clean sand facies, enabling high steam injectivity, while intercalated shale baffles with kv near zero severely restrict vertical communication. The NI 51-101 reserves disclosure standard requires Canadian companies to report permeability data supporting recoverable volumes in qualifying property reports. United States (BSEE, Texas RRC, NDIC): The Permian Basin's Wolfcamp Shale in the Midland and Delaware sub-basins typifies ultra-tight unconventional permeability: matrix permeabilities of 0.0001 to 0.01 mD (100 nD to 10 microD), entirely dependent on induced hydraulic fracture networks for production. The Texas Railroad Commission (RRC) does not mandate disclosure of permeability values in routine well filings, but operators file completion reports with fracture treatment volumes that implicitly reflect reservoir quality. The Bureau of Safety and Environmental Enforcement (BSEE) and Bureau of Ocean Energy Management (BOEM) govern offshore permeability reporting for Gulf of Mexico deepwater developments. The prolific Haynesville Shale in east Texas and northwest Louisiana averages matrix permeability of 0.00001 to 0.0001 mD (10 to 100 nD), among the tightest commercial gas reservoirs in the world, yet its high reservoir pressure (9,000 to 12,000 PSI or 621 to 827 bar) and gas content make it highly productive with optimized completion designs. Australia (NOPSEMA and DPIR): The Cooper Basin's Patchawarra Formation in South Australia represents a conventional tight gas play with permeabilities ranging from 0.1 to 10 mD, produced since the 1960s by Santos and Beach Energy. Cooper Basin tight sands require hydraulic fracturing to achieve commercial rates, but their permeability is orders of magnitude higher than North American shales. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) governs offshore petroleum activities and requires well completion reports that include core analysis data where available. The Carnarvon Basin on the North West Shelf hosts prolific conventional reservoirs: the Mungaroo Formation at Gorgon and Jansz-Io fields has permeabilities ranging from 100 to 500 mD in good-quality sandstones, supporting very high deliverability from relatively short horizontal well intervals. Middle East (Saudi Aramco and ADNOC): The Arab-D Limestone of the Ghawar field in Saudi Arabia represents the highest-permeability carbonate reservoir in the world. Vuggy and intercrystalline porosity in the Jurassic Arab Formation yields permeabilities of 100 to 2,000 mD in core measurements, with highly productive wells capable of flowing tens of thousands of barrels per day with minimal drawdown. Saudi Aramco's reservoir characterization studies document permeability anisotropy between the high-permeability Arab-D reservoir and tight Hadriya and Hanifa carbonates. In Abu Dhabi, ADNOC operates the Bu Hasa field in the Cretaceous Mishrif limestone, with average matrix permeability of 10 to 200 mD supplemented by fracture permeability that enhances well productivity substantially. Norway and the North Sea (Sodir and Equinor): The Johan Sverdrup field on the Norwegian Continental Shelf, operated by Equinor and overseen by the Norwegian Offshore Directorate (Sodir, formerly NPD), produces from Jurassic Hugin and Draupne sandstones with matrix permeabilities of 1 to 10 darcies (1,000 to 10,000 mD) in the best-quality sand facies. These extremely high permeabilities, combined with reservoir pressures around 4,700 PSI (324 bar) and excellent net-to-gross ratios, make Johan Sverdrup one of the lowest-cost deepwater developments globally. The Troll field's Jurassic sands reach 10 darcies (10,000 mD) in some intervals, enabling very large open-hole horizontal wells to produce at exceptionally low drawdown. Fast Facts Unit conversion: 1 darcy = 9.869 × 10-13 m² (SI unit for permeability is m², not used in petroleum practice) Ghawar permeability: Arab-D limestone averages 200 to 2,000 mD, contributing to Ghawar's peak rate of over 5 million barrels per day Shale permeability: Barnett Shale matrix permeability of 0.00001 mD (10 nD) was the first shale measured by GRI (Gas Research Institute) tight rock methods in the early 1990s Klinkenberg correction: Gas permeability in tight rocks can be 2 to 10 times higher than liquid-equivalent permeability without correction Well test scale: Pressure transient analysis samples 100 to 1,000 m (328 to 3,281 ft) of radius, orders of magnitude larger than a core plug at 3 cm (1.2 in) kv/kh ratio: Clean aeolian sandstones approach kv/kh = 1.0; laminated fluvial sands typically show kv/kh of 0.01 to 0.1

The product of formationpermeability, k, and producing formation thickness, h, in a producing well, referred to as kh. This product is the primary finding of buildup and drawdown tests and is a key factor in the flow potential of a well. It is used for a large number of reservoir engineering calculations such as prediction of future performance, secondary and tertiary recovery potential, and potential success of well-stimulation procedures. Obtaining the best possible value of this product is the primary objective of transient well tests. To separate the elements of the product, it is necessary to have some independent measurement of one of them, usually the estimation of producing formation thickness from well logs. Permeability is then calculated, provided that the fluid formation volume factor and viscosity are known. The accuracy of the calculated permeability is entirely dependent on the accuracy of the estimated formation thickness and the fluid properties.

An apparatus for measuring the permeability of a core sample. Measurements are made either by placing the sample in a chamber (also known as a core holder), or by placing a probe on the surface of the sample. Core-holder measurements are made either with gas or liquid, and either in steady state or unsteady-state conditions. Other variables include the confining pressure and the direction of measurement, which can be axial (along the axis of a cylindrical core sample), transverse (perpendicular to the axis), or radial (to the center of a hollow cylinder). In probe measurements, gas is injected into the sample under either steady- or unsteady-state conditions. Probe permeameters are also known as minipermeameters.

Generally, the distance between a receiver and a source in a survey, such as an electromagnetic survey. In seismic surveys, perpendicular or normal offset is the component of the distance between the source and geophones at a right angle to the spread.

The resistivity of a formation measured by flowing current perpendicular to the bedding planes. In anisotropic formations, the parallel and perpendicular resistivities are different.

(noun) A production logging tool consisting of a flexible, flower-shaped metal basket that expands against the casing or tubing wall to divert all fluid flow through a central spinner or sensor, providing a full-bore flow rate measurement in deviated or horizontal wells where conventional spinner flowmeters may underperform.

The examination of rocks in thin section. Rock samples can be glued to a glass slide and the rock ground to 0.03-mm thickness in order to observe mineralogy and texture using a microscope. (A petrographic microscope is a transmitted-light polarizing microscope.) Samples of sedimentary rock can be impregnated with blue epoxy to highlight porosity.

A complex mixture of naturally occurring hydrocarbon compounds found in rock. Petroleum can range from solid to gas, but the term is generally used to refer to liquid crude oil. Impurities such as sulfur, oxygen and nitrogen are common in petroleum. There is considerable variation in color, gravity, odor, sulfur content and viscosity in petroleum from different areas.

Geologic components and processes necessary to generate and store hydrocarbons, including a mature source rock, migration pathway, reservoir rock, trap and seal. Appropriate relative timing of formation of these elements and the processes of generation, migration and accumulation are necessary for hydrocarbons to accumulate and be preserved. The components and critical timing relationships of a petroleum system can be displayed in a chart that shows geologic time along the horizontal axis and the petroleum system elements along the vertical axis. Exploration plays and prospects are typically developed in basins or regions in which a complete petroleum system has some likelihood of existing.

A technique used to represent the history of a sedimentary basin, including the processes and components necessary to form petroleum: a petroleum sourcerock, a reservoir, a trapping mechanism, a seal, and the appropriate relative timing of formation of these. Using geologic, geophysical, and engineering data, scientists create a 3D model of the subsurface that can be used to understand whether petroleum is present and how much might exist in potential traps. Petroleum systems models can be used to help predict porepressure and plan well construction and fielddevelopment. A useful petroleum systems model can be used to identify and explain inconsistencies in the data. The resulting models are valuable during exploration for identifying resource richness, such as sweet spots in unconventional plays such as shale gas, and during field development and production for improving completion efficiency.Petroleum systems modeling is distinct from reservoir simulation in that it covers a larger scale that might include multiple oil and gas fields and considers a geologic time frame of millions of years rather than a production time frame of years or decades.

The study of macroscopic features of rocks, such as their occurrence, origin and history, and structure (usually by examining outcrops in the field) and their texture and composition (by studying smaller samples more closely).

A model of a reservoir or a field in which the petrophysical data were the only or the primary data used to construct the model.

Rock types that have been classified according to their petrophysical properties, especially properties that pertain to fluid behavior within the rock, such as porosity, capillary pressure, permeabilities, irreducible saturations or saturations. Petrophysical rock types are often calibrated from core and dynamic data, but are usually calculated from wireline logs, where possible, because the wireline logs are generally the only measurements that are available for all wells at all depths. Electrofacies approaches are often used to determine rock types from logs.

An interpretation of the presumed continuation of an event. In areas of discontinuous, divergent reflectors or incoherent data, drawing phantoms allows the interpreter to generate a map on a discontinuous event.

A description of the motion of, or means of comparison of, periodic waves such as seismic waves. Waves that have the same shape, symmetry and frequency and that reach maximum and minimum values simultaneously are in phase. Waves that are not in phase are typically described by the angular difference between them, such as, "180 degrees out of phase." Zero-phase wavelets are symmetrical in shape about zero time whereas non-zero-phase wavelets are asymmetrical. Non-zero-phase wavelets are converted to zero-phase wavelets to achieve the best resolution of the seismic data. Known (zero) phase well synthetics and vertical seismic profiles (VSPs) can be compared with local surface seismic data to determine the relative phase of the surface seismic wavelets. Such knowledge allows the surface seismic data to be "corrected" to zero phase. The units of phase are degrees.

A pressure phenomenon caused in a wellbore by rise of gas and fall of liquids trapped in a wellbore after a surface shut-in. This phenomenon can cause a "hump" in the buildup curve, and frequently leads to incorrect analysis of buildup test results because the entire early portion of the transient is adversely affected by this pressure response.

The change in position of the peaks of a sinusoidal electromagnetic wave as it passes through the formation. If the sinusoidal wave picked up by two receivers a certain distance apart in a formation are compared, it is found that the wave has been attenuated and shifted in time. The shift is known as a phase shift. The term is used in particular with reference to the propagation resistivity log and the electromagnetic propagation log.

The ability of the formation to resist electrical conduction, as derived from the change in position of the peaks of an electromagnetic wave generated in a propagation resistivity measurement. At the frequencies used, the phase shift depends mainly on the resistivity of the material with a small dependence on dielectric permittivity, particularly at high resistivity. Common practice is to transform the phase shift to resistivity assuming that the dielectric permittivity is related to resistivity by a simple algorithm. The transform also depends on transmitter/receiver spacings and tool design. For a 2-MHz measurement, a typical measurement range is 0.2 to 200 ohm-m. Above 200 ohm-m, the dielectric effects become too variable and it is preferable to use the dielectric resistivity.

A record of the velocity with which a particular phase (gas, oil or water) moves in a producing well. While most flowmeters measure some average of all the fluids, the phase-velocity log identifies one particular phase. This is particularly important in highly deviated and horizontal wells with multiphase flow, where the flow structure is complicated.Phase-velocity measurements are made with either the crosscorrelation flowmeter, the water-flow log, or with chemical markers designed to mix specifically with one particular phase. Velocity-shot measurements, using radioactive tracers, have also been used. In a typical chemical marker technique, a gadolinium-rich marker is injected into the flow stream, dissolving in either oil or water. Gadolinium has a high capture cross section, or sigma, so that a slug of fluid with high sigma moves with the appropriate phase up the borehole. This slug can be detected by a standard pulsed-neutron capture tool, and the velocity of the phase computed from the time of flight between ejector and detector.

A pH indicator that is clear below pH 8.3 and red above 8.3. It is the indicator used in various alkalinity titrations.

A group of salts formed by neutralization of phosphorous or phosphoric acid with a base, such as NaOH or KOH. Orthophosphates are phosphoric acid (H3PO4) salts, where 1, 2 or 3 of the hydrogen ions are neutralized. Neutralization with NaOH gives three sodium orthophosphates: (a) monosodium phosphate (MSP), (b) disodium phosphate (DSP) or (c) trisodium phosphate (TSP). Their solutions are buffers in the 4.6 to 12 pH range. TSP is an excellent degreaser. All will precipitate hardness ions such as calcium. Polyphosphates are polymers made from various orthophosphates by dehydration with heat. Sodium acid pyrophosphate (SAPP) is a claydeflocculant and treatment for cement contamination. For clay deflocculation, polyphosphates are limited by the temperature at which they hydrolyze back to orthophosphates, although several that performed up to 280°F [138°C] have been documented in the literature (see reference).Reference:Sikorski CF and Weintritt DJ: "Polyphosphate Drilling-Mud Thinners Deserve Second Look," Oil & Gas Journal 81, no. 27 (July 4, 1983): 71-78.

A gamma ray interaction in which the gamma ray is fully absorbed by a bound electron. If the energy transferred exceeds the binding energy to the atom, the electron will be ejected. Normally, the ejected electron will be replaced within the material and a characteristic X-ray will be emitted with an energy that is dependent on the atomic number of the material. The highest probability for this effect occurs at low gamma ray energy and in a material of high atomic number. The photoelectric effect is the principle behind the PEF log, which identifies lithology.

A record of the density in and around a completed well using a radioactive source of gamma rays and a detector. The log is recorded with a nuclear fluid densimeter. Originally, photon logs were run to determine the size of salt caverns. More recently, they have been run to evaluate the quality of gravel packs and sand cavities, and are then synonymous with gravel-pack logs.

To interpret data, such as seismic sections, by selecting and tracking marker beds or other events.

The depth at which the tool string is picked up off the bottom of the well during a wireline logging survey. Pick-up can be observed by an increase in cable tension and by the start of activity in the log curves. When the logging tool is lowered to the bottom of the well, it is common practice to spool in some extra cable. When the cable is pulled back out, the tool remains stationary before it is picked up off the bottom. During this time the log readings are static but the depth, which is recorded by the movement of the cable, is changing.

To use a relatively weak, inhibited acid to remove scale, rust and similar deposits from the internal surfaces of equipment such as treating lines, pumping equipment or the tubing string through which an acid or chemical treatment is to be pumped. The pickling process removes materials that may react with the main treatment fluid to create undesirable secondary reactions or precipitates damaging to the near-wellbore reservoirformation.

To run a scraper, or pig, through a pipeline for cleaning purposes.

The trip of a pig through a pipeline for cleaning purposes.

The act of forcing a device called a pig through a pipeline for the purposes of displacing or separating fluids, and cleaning or inspecting the line.

A relatively small volume of specially prepared fluid placed or circulated in the wellbore. Fluid pills are commonly prepared for a variety of special functions, such as a sweep pill prepared at high viscosity to circulate around the wellbore and pick up debris or wellbore fill. In counteracting lost-circulation problems, a lost-circulation pill prepared with flaked or fibrous material is designed to plug the perforations or formation interval losing the fluid.

A downhole milling tool designed with an extended pilot or central stinger section that is inserted in the bore of the packer, tubular or equipment being milled. This design helps ensure that the mill follows the desired path and does not damage the casing or liner wall as the milling operation progresses.

An experimental test, or series of tests, used to predict mud behavior and guide future actions by the mud engineer. Rather than experimenting on the full mud volume and risking serious and expensive mistakes, pilot tests such as those listed below give valuable guidance:(1) Weight-up tests evaluate how much mud weight can be increased.(2) Dilution tests evaluate how much prior dilution is needed in order to weight up.(3) Product tests evaluate similar additives for performance to select the best material.(4) Heat-aging tests evaluate how a mud will react if exposed to high temperature while circulating or while static in the hole.(5) Contamination tests evaluate how mud will respond to an expected contaminant.(6) Contaminant-treatment tests evaluate how contaminated mud will respond to various amounts and types of treatments.Pilot test samples are formulated using the concept of barrel equivalent.

Relating to the male threadform, as in the "pin end of the pipe."

(verb) To progressively thin and terminate laterally, as when a geological formation, reservoir sand, or coal seam tapers to zero thickness against an unconformity, fault, or facies change. Pinch-out geometries can form stratigraphic traps capable of containing hydrocarbon accumulations.

A reduction in bed thickness resulting from onlapping stratigraphic sequences.

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

Offshore, the storage bins for drillpipe, drill collars and casing. The offshore pipe rack functions similarly to the onshore version. Due to space limitations, offshore pipe racks tend to be narrower and routinely contain many layers of pipe. The onshore pipe rack tends to have few stacked layers and instead extends laterally as needed to hold the tubular goods because space is not at a premium.

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

The increase in length resulting from the combination of forces acting on a string within the wellbore. The principal factors resulting in an increase in string length are the weight of the string itself and the effects of thermal expansion.

A tube or system of tubes used for transporting crude oil and natural gas from the field or gathering system to the refinery.

The quantity (volume) of oil and gas required to maintain a full pipeline. The static capacity of a pipeline is usually expressed as a volume per unit length (for example, bbl/ft). Nevertheless, the fluid volume passing through a pipeline in a specific time period will depend on initial pressure, flow characteristics, ground elevation, density and delivery pressure.

A sufficiently dry gas that will not drop out natural gas liquids (NGL) when entering the gas pipeline; also, gas with enough pressure to enter high-pressure gas pipelines.

Oil whose free water, sediment and emulsion content (BS&W) is sufficiently low to be acceptable for pipeline shipment.

An inspection of a pipeline to check for leaks, washouts or other abnormal conditions. A pipeline patrol is commonly performed using airplanes.

A type of corrosion in which there is loss of metal in localized areas. The corrosion rate in the pits is many times greater than the corrosion rate on the entire surface.The resultant pits can be large and shallow or narrow and deep. Pitting is a more dangerous problem than general corrosion because the pitted areas can be easily penetrated.

A flat drawing board mounted on a tripod used in combination with an alidade to construct topographic or geologic maps in the field. A sheet of paper or mylar covering the plane table is annotated during map construction.

A wave that is far enough from its source that its wavefront has no effective curvature, or is planar, over a short distance. Seismic and electromagnetic waves are treated as plane waves even though that assumption is not strictly correct.

Minute organisms that float or drift passively near the surface of oceans and seas. Plant-like plankton, or phytoplankton, include diatoms. Zooplankton are animals that have a limited ability to move themselves. The changes in plankton over time are useful for estimation of relative ages of rocks that contain the fossilized remains of plankton.

To place seismometers on the ground. The seismometer should be firmly stuck or planted in the ground in the proper location and orientation for optimal seismic acquisition.

Pertaining to a material that can deform permanently without rupturing.

Permanent mechanical or physical alteration that does not include rupture. Plastic deformation of rocks typically occurs at high temperatures and pressures, conditions under which rocks become relatively viscous.

A fluid in which the shear force is not proportional to the shear rate (non-Newtonian) and that requires a finite shear stress to start and maintain flow. Most drilling muds are characterized as either plastic or pseudoplastic fluids.

A parameter of the Bingham plastic model. PV is the slope of the shear stress/shear rate line above the yield point. PV represents the viscosity of a mud when extrapolated to infinite shear rate on the basis of the mathematics of the Bingham model. (Yield point, YP, is the other parameter of that model.) A low PV indicates that the mud is capable of drilling rapidly because of the low viscosity of mud exiting at the bit. High PV is caused by a viscous base fluid and by excess colloidal solids. To lower PV, a reduction in solids content can be achieved by dilution of the mud.

To stay on the surface of the formation or a perforation tunnel. When, for example, bead tracers are injected into a well, they will be carried by the injection fluid. Instead of entering the formation with the fluid, the bead tracers will be held, like plates, on the surface.

The unifying geologic theory developed to explain observations that interactions of the brittle plates of the lithosphere with each other and with the softer underlying asthenosphere result in large-scale changes in the Earth. The theory of plate tectonics initially stemmed from observations of the shapes of the continents, particularly South America and Africa, which fit together like pieces in a jigsaw puzzle and have similar rocks and fossils despite being separated by a modern ocean. As lithospheric plates heat up or cool down depending on their position, or their tectonic environment, relative to each other and to warmer areas deeper within the Earth, they become relatively more or less dense than the asthenosphere and thus tend to rise as molten magma or sink in cold, brittle slabs or slide past each other. Mountain belts can form during plate collisions or an orogeny; diverging plates or rifts can create new midoceanic ridges; plates that slide past one another create transform fault zones (such as the San Andreas fault); and zones of subduction occur where one lithospheric plate moves beneath another. Plate tectonic theory can explain such phenomena as earthquakes, volcanic or other igneous activity, midoceanic ridges and the relative youth of the oceanic crust, and the formation of sedimentary basins on the basis of their relationships to lithospheric plate boundaries. Convection of the mantle is postulated to be the driving mechanism for the movement of lithospheric plates. Measurements of the continents using the Global Positioning System confirm the relative motions of plates. Age determinations of the oceanic crust confirm that such crust is much younger than that of the continents and has been recycled by the process of subduction and regenerated at midoceanic ridges.

A topographic feature consisting of a large flat area at a relatively high elevation with steep sides.

A relatively flat, nearly level area of sedimentary rocks in a continent that overlies or abuts the basement rocks of a craton.

To pursue hydrocarbon accumulations of a given type.

A log that has been generated from digital data some time after the actual acquisition of the data. It is distinct from the acquisition log. Some of the parameters for processing the log may or may not be different from those of the acquisition log.

To prepare a wellbore to be shut in and permanently isolated. There are typically regulatory requirements associated with the P&A process to ensure that strata, particularly freshwater aquifers, are adequately isolated. In most cases, a series of cement plugs is set in the wellbore, with an inflow or integrity test made at each stage to confirm hydraulic isolation.

A multiphase flow regime in pipes in which most of the gas moves as large bubbles dispersed within a continuous liquid. The bubbles may span much of the pipe. There are also small bubbles within the liquid, but many of these have coalesced to form the larger bubbles, or plugs. In near-horizontal wells, the plugs are also known as elongated bubbles. Plug flow is similar to slug flow, but the bubbles are generally smaller and move more slowly.

A solid or gel in a workover or drilling fluid that blocks off permeable zones to prevent loss of fluid into those permeable zones or to protect those zones from damage. The plugging may be temporary or permanent.

The angle between a linear feature and a horizontal line in a vertical plane containing both lines.

What Is Plunger Lift? Plunger lift is a low-cost artificial lift method that uses a free-traveling cylindrical plunger inside the production tubing to create a mechanical interface between the accumulated casing annulus gas and the liquid slug above it, allowing stored wellbore gas pressure to drive both the plunger and the liquid slug to surface with minimal slippage and high lift efficiency. Key Takeaways Plunger lift requires no downhole power source or injection gas supply, making it the lowest-capital artificial lift option for wells with sufficient natural GLR, typically 400 scf/bbl (71 m3/m3) or greater at operating conditions. The plunger cycle consists of three phases: the closed buildup period, the open flow period during which the plunger travels to surface, and the afterflow period when the well produces past the arrival of the plunger. Pad plungers (continuous-flow plungers) allow liquid and gas to bypass the plunger body through channels or bypass valves, enabling use in wells with lower GLR than conventional solid plungers require. An arrival sensor at the wellhead detects plunger arrival and triggers automatic cycle control via a programmable logic controller (PLC) or a dedicated plunger controller. API Recommended Practice 11PL provides guidelines for the selection, design, and operation of plunger lift installations. How Plunger Lift Works The plunger is a precisely machined cylinder, typically 53 mm to 60 mm (2.125 in to 2.375 in) outside diameter for 2.875-inch (73 mm) tubing, that travels freely up and down the tubing on each cycle. Between cycles, the plunger rests on a bottom-hole bumper spring or a standing valve assembly at the base of the tubing string. During the closed buildup period, the production line valve at the wellhead is closed or restricted, allowing reservoir inflow to accumulate liquid in the tubing and build casing annulus pressure. The plunger remains seated on the bumper spring at the bottom of the tubing while pressure builds in the annulus above the standing valve. When the annulus pressure reaches the setpoint established by the controller, the wellhead motor valve opens and the pressure differential between the casing annulus and the tubing drives the plunger upward. The plunger acts as a piston, pushing the liquid slug ahead of it while minimizing slippage of gas past the plunger-to-tubing interface. Conventional plungers rely on a close mechanical fit (typically 0.03 mm to 0.12 mm clearance) to minimize gas bypass. The plunger arrives at the wellhead lubricator assembly, activates the arrival sensor (magnetic, acoustic, or impact-based), and the controller enters the afterflow phase, during which the well continues to produce gas and some residual liquid until the flow rate drops to the point where the plunger would not be able to return to bottom or until the controller timer ends the afterflow period. During afterflow, the casing pressure continues to decline and the production rate decreases. At the end of afterflow, the wellhead valve closes, the plunger falls back to the bumper spring under gravity through the gas column, and the buildup phase restarts. Total cycle time typically ranges from 30 minutes to several hours depending on the well's deliverability, GLR, tubing depth, and liquid loading rate. Cycle times are optimized by the controller using production data, arrival velocity, and annulus pressure trends to maximize daily liquid production while keeping the plunger velocity within the acceptable range of 150 m/min to 500 m/min (500 ft/min to 1,600 ft/min) to avoid damage to the wellhead lubricator assembly. Plunger Lift Across International Jurisdictions In Canada, plunger lift is widely applied in the Montney tight gas and liquids-rich gas formation in northeastern British Columbia and northwestern Alberta, where late-life well performance declines as reservoir pressure drops and liquid loading becomes the primary flow impairment. Operators including ARC Resources, Tourmaline Oil, and Canadian Natural Resources use plunger lift on Montney wells that have accumulated sufficient casing pressure during the shutin period to drive the plunger to surface. The Alberta Energy Regulator (AER) and the British Columbia Oil and Gas Commission (BCOGC) regulate well completion equipment including plunger lift installations, with wellhead equipment subject to safety testing requirements under their respective completion and well integrity directives. Fast Facts In the Appalachian Basin of the northeastern United States, more than 15,000 wells across West Virginia, Pennsylvania, and Ohio are estimated to use plunger lift to manage liquid loading in Marcellus and Utica shale producers. A typical Appalachian plunger lift installation costs between USD 8,000 and USD 25,000 including the controller, motor valve, lubricator, and plunger, compared to USD 100,000 or more for an electric submersible pump completion. This cost differential makes plunger lift the first artificial lift method evaluated when Marcellus wells begin to load up with water after 3 to 5 years of production. In the United States, the Permian Basin, Appalachian Basin (Marcellus and Utica shale), and mid-continent plays (Anadarko Basin in Oklahoma) are the primary regions for plunger lift deployment. The Bureau of Land Management (BLM) and state regulators including the Texas Railroad Commission (RRC) and the West Virginia Department of Environmental Protection (WVDEP) govern completion equipment on wells within their jurisdictions. In the Permian, plunger lift extends the economic life of older vertical wells in the Wolfcamp and Spraberry formations that have transitioned from flowing or rod pump production to a liquid-loading regime. In Australia, the Cooper Basin in South Australia and Queensland hosts plunger lift applications on tight gas producers operated by Beach Energy and Santos. The low-pressure, late-life nature of many Cooper Basin wells makes plunger lift a practical solution for managing liquid loading without capital-intensive equipment. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) governs offshore wells in Australian waters, while onshore wells fall under state petroleum legislation. In the Middle East, plunger lift is less common than gas lift or ESP because the primary producing reservoirs maintain higher reservoir pressures for longer periods, and the high gas-liquid ratios of many Middle Eastern wells mean that natural flow remains viable well into the life of the well. However, operators in mature fields in Oman, operated under Production Sharing Agreements (PSAs) with Petroleum Development Oman (PDO), have applied plunger lift to gas wells experiencing water loading in the late stages of their producing life. Plunger Lift Technical Details: Types, Components, and GLR Requirements Conventional plungers use a solid cylindrical body with a close fit to the tubing wall to minimize gas bypass. The sealing mechanism relies on the turbulence created by the small annular gap between the plunger OD and the tubing ID to create a dynamic gas seal. Pad plungers (also called continuous-flow plungers or bypass plungers) incorporate spring-loaded pads or bypass ports that allow controlled gas or liquid flow past the plunger during the upstroke, enabling the plunger to operate in wells with GLR as low as 200 scf/bbl (36 m3/m3) that would not sustain a conventional plunger. Brush plungers use a series of wire brushes around the plunger body to provide both a flexible seal and a mechanism for removing paraffin wax or scale deposits from the tubing wall during each cycle, serving a dual purpose of lift and wellbore maintenance. The minimum GLR requirement is the fundamental parameter that determines whether plunger lift is feasible in a given well. The Turner-Coleman minimum GLR correlation estimates the minimum gas rate required to lift a liquid droplet to the surface against gravity; for plunger lift, the critical parameter is not the gas flow rate but the accumulated energy (pressure times volume) stored in the casing annulus during the buildup period. A useful field rule of thumb is that plunger lift requires at least 400 standard cubic feet of gas per barrel of liquid (71 m3/m3) at operating wellhead conditions to sustain reliable cycles in a well with approximately 2,440 m (8,000 ft) of tubing depth. Deeper wells require proportionally higher GLRs because the hydrostatic head of the liquid slug increases with depth. The sleeve valve (also called the motor valve or production valve) at the wellhead is typically a pneumatically actuated ball valve or plug valve controlled by the plunger lift controller. The controller receives input from the arrival sensor, the casing pressure transducer, the tubing pressure transducer, and optionally a flow meter, and uses this data to time the open and closed periods of each cycle. Modern controllers from manufacturers including Production Control Services (PCS), Well Master, and Weatherford incorporate adaptive cycle optimization algorithms that adjust the buildup and afterflow periods in real time to maximize production without causing the plunger to fail to return to bottom or to arrive with insufficient velocity to indicate a good seal. Tip: A plunger arriving at the wellhead with a velocity above 750 m/min (2,500 ft/min) is traveling too fast and will impact the lubricator with damaging force; a plunger arriving below 60 m/min (200 ft/min) indicates poor gas seal and excessive slippage. Adjusting the buildup time to allow more casing pressure to accumulate before opening the motor valve is the primary lever for improving low-velocity arrival performance, while shortening afterflow time reduces over-depletion of annulus pressure in fast-arriving cycles. Plunger Lift Synonyms and Related Terminology Free-piston lift: an alternate term for plunger lift used in some international literature, emphasizing the free-traveling nature of the plunger. Plunger pump: not the same as plunger lift; a plunger pump is a reciprocating positive-displacement pump driven by surface power, whereas plunger lift uses stored wellbore gas energy and a free-traveling cylindrical plunger. Pad plunger: a plunger type with spring-loaded bypass pads that allow gas slippage around the body, enabling operation at lower GLR conditions. Bumper spring: the spring-loaded stop installed at the base of the tubing string that the plunger seats on during the closed buildup period. Lubricator: the wellhead assembly above the production valve that receives the arriving plunger and contains it safely after each cycle. Arrival sensor: the magnetic, acoustic, or impact device on the lubricator that detects plunger arrival and signals the controller to end the afterflow phase or begin timing. Liquid loading: the condition in which produced liquids accumulate in the wellbore faster than the gas velocity can carry them to surface, the primary driver for plunger lift installation. Related terms: gas lift, christmas tree, casing, production log, well control, wellbore storage effects, separator, flow regime

(noun) The additional stroke distance beyond the designed plunger travel in a sucker rod pumping system, occurring when the pump plunger descends past its normal bottom position due to rod stretch or fluid pound. Excessive overtravel can cause mechanical damage to the pump barrel and reduce pump efficiency.

An arcuate deposit of sediment, usually sand, that occurs along the convex inner edges of the meanders of channels and builds outward as the stream channel migrates.

A term used to describe the beginning of thickening of a cementslurry during the thickening-time test, often abbreviated as POD. For some slurries, the POD is used as the thickening time.

In chemistry, referring to a compound in which electrons are not shared equally in the chemical bond, resulting in partial electrical charges. The best example is water, H2O, where the oxygen atom "pulls" the electrons more strongly than the hydrogen atoms and has a partial negative charge. The hydrogen atoms thus carry a partial positive charge. Polar compounds may ionize partially when dissolved in water.

A compound whose electrons are not shared equally in chemical bonds. A polar compound is not necessarily ionized. Water is a polar compound. Polymers can have ionizing polar groups on their complex structures.

The nature of the positive and negative portions of the seismic wavelet, the positive and negative aspects of electrical equipment, or the north and south orientations of magnets and the Earth's magnetic field.

The convention adopted by the Society of Exploration Geophysicists (SEG) for the display of zero-phaseseismic data. If the signal arises from a reflection that indicates an increase in acoustic impedance, the polarity is, by convention, positive and is displayed as a peak. If the signal arises from a reflection that indicates a decrease in acoustic impedance, the polarity is negative and is displayed as a trough. There is another standard for minimum-phase data. In order to interpret seismic data acquired at different times within a region, to model data, or to assess bright or dim spots, some knowledge of the polarity of the data is essential to correlate or tie data properly.

The effect on a propagation resistivity or induction log of charge buildup at the boundary between two formation layers with different dielectric properties. In a vertical well with horizontal layers, the current loops generated by the tool in the formation are parallel to the layers and do not cross bed boundaries. However, with an apparent dip between borehole and formation, the loops cross the bed boundaries and generate a charge buildup at the boundaries. The charge buildup acts like a secondary transmitter that increases the measured resistivity. The result is a spike to high resistivity as the tool crosses the bed boundary. In deviated or horizontal wells, polarization horns on measurements-while-drilling propagation logs often are used to detect a bed boundary.The spike increases with apparent dip and resistivity contrast between beds. The magnitude of polarization spikes varies with tool type and spacing, being larger for the propagation tools.

The time allotted for the alignment of hydrogen atoms with the static magnetic field during a nuclear magnetic resonance (NMR) measurement. The alignment of hydrogen atoms follows an exponential rule such that after a polarization time PT the percentage aligned is 100*(1 ? e-PT/T1) where T1 is their longitudinal relaxation time. An infinite polarization time is therefore needed to align every hydrogen atom, but 95% are aligned after a time of 3*T1. Typical polarization times for a standard NMR log are between 1 and 4 s.

A generic term for a completion component that has been polished or prepared to enable an efficient hydraulic seal. The polished joint may have an internal or external polished surface and is typically configured in a length that enables some movement of the completion string or associated components without compromising the hydraulic seal.

The uppermost joint in the string of sucker rods used in a rod pump artificial-lift system. The polished rod enables an efficient hydraulic seal to be made around the reciprocating rod string.

A polymer with a high molecular weight. The basic repeating unit or monomer of polyacrylamide is a combination of carbon, hydrogen, oxygen and nitrogen. Polyacrylamides increase the viscosity of the water slug that precedes the final water injection. Polyacrylamides are frequently used as mobility-control buffers in micellar-polymer flooding operations.

A polymer or copolymer of an alkalene oxide, such as polyethylene glycol (PEG), a polymer of ethylene oxide with general formula HO(CH2CH2O)nH, or polypropylene glycol (PPG), which is a polymer of propylene oxide. PAGs are effective shale inhibitors and have effectively replaced the earlier polyglycerols.

One of the synthetic hydrocarbon liquids manufactured from the monomer ethylene, H2C=CH2. Polyalphaolefins have a complex branched structure with an olefin bond in the alpha position of one of the branches. Hydrogenated polyalphaolefins have olefin-carbons saturated with hydrogen, which lends excellent thermal stability to the molecule. Synthetic-base fluids (similar to oil muds) are made with the various types of synthetic liquids because the cuttings can be discharged in offshore waters, whereas discharge of cuttings coated with refined oils would be disallowed.

A cellulose derivative similar in structure, properties and usage in drilling fluids to carboxymethylcellulose. PAC is considered to be a premium product because it typically has a higher degree of carboxymethyl substitution and contains less residual NaCl than technical grade carboxymethylcellulose, although some PACs contain considerable NaCl.

A fluid-loss control additive used in high-temperature, water-base muds. It shows good salt tolerance and temperature tolerance.

A series of alcohols with glycerol, C3H5(OH)3, (usually referred to as glycerin in the USA) being the simplest member. Polyglycerols have been used as shale inhibitors in water-base drilling fluids.

A large molecule made up of repeating units. Some polymers are naturally occurring, such as xanthan gum, guar gum and starch. Other polymers are modified natural polymers, such as carboxymethylcellulose (CMC) and hydropropyl starch and lignosulfonate. Some are synthetic such as polyacrylates, polyacrylamides and polyalphaolefins. Polymers may be classified by their structure and may be linear, branched or less commonly cyclic. Copolymers contain two or more different monomers that can be arranged randomly or in blocks. In solution, entangled polymer chains can create networks, giving complex viscosity behavior. Polymers that ionize in solution are called polyelectrolytes. Charged groups strongly affect behavior and interactions with colloidal clays, other polymers and solvents. Molecular size (weight) influences how a specific polymer type performs in a given type of mud. A small polymer may be a deflocculant, whereas a large polymer of the same type may be a flocculant. Some are viscosifiers and others are fluid-loss control additives while others are multifunctional.

An enhanced oil recovery technique using water viscosified with soluble polymers. Viscosity is increased until the mobility of the injectant is less than that of the oil phase in place, so the mobility ratio is less than unity. This condition maximizes oil-recovery sweep efficiency, creating a smooth flood front without viscous fingering. Polymer flooding is also applied to heterogeneous reservoirs; the viscous injectant flows along high-permeability layers, decreasing the flow rates within them and enhancing sweep of zones with lower permeabilities. The two polymers that are used most frequently in polymer flooding are partially hydrolyzed polyacrylamide and xanthan.

A volume of polymerslurry placed in a wellbore, which, in time and under the correct temperature conditions, will develop to provide a high-viscosity platform on which a cement plug can be placed. Polymer plugs are typically used when a cement plug must be set accurately within the wellbore, The viscous material prevents the dense cement slurry from fingering through the lighter wellbore fluid during placement, helping to ensure that cement is placed over the desired interval.

A generic name for low molecular weight, water-soluble polymers and oligomers containing a large number of hydroxyl groups. Specific examples include glycols, polyglycols and polyglycerols. Polyols are used in water-base fluids as shale inhibitors and gas hydrate inhibitors.

A carbohydrate composed of many monosaccharides. Polysaccharides increase the viscosity of the water slug that precedes the final water injection. However, they are not frequently used in chemical flooding operations because they generate numerous by-products that can potentially plug filters or well sandfaces, especially when they contact polyvalent cations or bacteria.Polysaccharides are also called biopolymers.

A rod shorter than usual, usually placed below the polished rod and used to make a rod string of a desired length.

The accumulation of smaller tracts of land, the sum total acreage of which are required for a governmental agency to grant a well permit or assign a production quota or allowable to an operator.

A type of check valve often used in the lines or manifolds associated with kill and choke lines or pressure-control equipment.

A discrete void within a rock, which can contain air, water, hydrocarbons or other fluids. In a body of rock, the percentage of pore space is the porosity.

The pressure of fluids within the pores of a reservoir, usually hydrostatic pressure, or the pressure exerted by a column of water from the formation's depth to sea level. When impermeable rocks such as shales form as sediments are compacted, their pore fluids cannot always escape and must then support the total overlying rock column, leading to anomalously high formation pressures.

In an intergranular rock, the small pore space at the point where two grains meet, which connects two larger pore volumes. The number, size and distribution of the pore throats control many of the resistivity, flow and capillary-pressure characteristics of the rock.

The pressure of the subsurface formation fluids, commonly expressed as the density of fluid required in the wellbore to balance that pore pressure. A normal gradient might require 9 lbm/gal [1.08 kg/m3], while an extremely high pressure gradient might be 18 lbm/gal [2.16 kg/m3] or higher.

A laboratory test used to determine if a drilling fluid blocks movement of filtrate through pore spaces of a shale sample. The PPT device monitors the increase in pore pressure in a shale when exposed to a drilling fluid over a period of time. Shale cores from 1 to 3-inches long are fitted into a modified Hassler cell that has sensitive pressure transducers in reservoirs on each end of the cell.Reference:van Oort E, Hale AH, Mody FK and Roy S: "Transport in Shales and the Design of Improved Water-Based Shale Drilling Fluids," in SPE Drilling and Completion 11, no. 3 (September 1996): 137-146.

An instrument for measuring the pore volume, and hence the porosity, of a core sample. The term is also used for some instruments that actually measure grain volume, such as the Boyle?s Law Double-Cell method. Pore volume is then obtained from the difference between bulk volume and grain volume.Pore volume is most commonly measured directly by Boyle's Law Single-Cell method, summation of fluids or liquid saturation. Bulk volume is most commonly measured by buoyancy, mercury displacement or a physical measurement of size (calipering); grain volume by Boyle?s law Double-Cell method or disaggregation of the sample.Except for disaggregation, all techniques determine the effective porosity, in the sense of all but the isolated pores.

What Is Porosity? Porosity measures the fraction of a rock's bulk volume occupied by void spaces, expressed as a decimal or percentage, and directly controls how much fluid a reservoir can store. Petrophysicists and reservoir engineers quantify porosity from core plugs, wireline logs, and nuclear magnetic resonance tools to estimate original oil and gas in place before any well is drilled. Key Takeaways Porosity equals the ratio of pore volume to bulk volume, expressed as a fraction or percentage (e.g., 0.15 or 15%). Total porosity includes all void space; effective porosity excludes isolated pores and clay-bound water that cannot contribute to production. Primary porosity forms during sediment deposition; secondary porosity develops later through dissolution, fracturing, or dolomitization. Wireline tools measure porosity by different physical principles: the neutron tool responds to hydrogen index, the density tool responds to bulk density, and NMR responds to proton relaxation in pore fluids. Typical values range from 2 to 6 percent in tight gas formations such as the Montney, to 30 to 40 percent in North Sea chalk reservoirs such as Ekofisk. How Porosity Works Every sedimentary rock consists of mineral grains, cementing material, and the spaces between them. Porosity is the ratio of that pore volume (Vp) to the total bulk volume (Vb) of the sample: porosity = Vp / Vb. A sandstone with a porosity of 0.20 has 20 cubic centimeters of pore space for every 100 cubic centimeters of total rock. Those pores may be filled with oil, gas, brine, or mixtures of all three, and the fraction occupied by hydrocarbons determines the hydrocarbon pore volume that feeds production. Petrophysicists distinguish between connected and isolated pores. Connected pores communicate with each other and with the wellbore, allowing fluids to flow. Isolated pores trap fluid permanently and cannot be produced. Total porosity (PHIT) captures both populations; effective porosity (PHIE) includes only the connected volume accessible to flowing fluids. In clean sandstones with low clay content the two values are nearly identical, but in shaly sands or vuggy carbonates the difference can exceed five porosity units, making the distinction critical for reserves calculations. Geologists also separate porosity by origin. Primary (intergranular) porosity is the depositional pore space preserved between grains after compaction and cementation. Secondary porosity develops after burial through dissolution of unstable minerals (moldic and vuggy pores in carbonates), tectonic fracturing (natural fractures that add both storage and permeability), and dolomitization (volume reduction during replacement of calcite by dolomite creates intercrystalline pores). Fractured reservoirs in the Middle East and the naturally fractured carbonates of the Permian Basin often owe their producibility to secondary porosity networks overlying a tight matrix. Porosity Across International Jurisdictions In Canada, the Montney tight gas and liquids play of northeastern British Columbia and northwestern Alberta is characterized by total porosities of 3 to 6 percent measured on core plugs using gas expansion methods. The Alberta Energy Regulator (AER) requires operators to report petrophysical parameters in the well completion report (WCR) filed with the AER's OneStop system after each well is drilled. Operators submitting data to the AER must follow the Canadian Association of Petroleum Producers (CAPP) petrophysical data standards, which specify core analysis procedures aligned with API RP 40 (Core Analysis). In the United States, the Permian Basin's Spraberry and Dean intervals display matrix porosities of 8 to 12 percent, while the Delaware Basin Wolfcamp shale shows matrix porosities of 4 to 9 percent. The Bureau of Land Management (BLM) and the Bureau of Safety and Environmental Enforcement (BSEE) require porosity data submissions as part of completion and well records for federal and offshore leases. The Society of Petrophysicists and Well Log Analysts (SPWLA) sets industry standards for log-based porosity interpretation used by analysts throughout the US. In Norway, the Ekofisk field in the Norwegian North Sea is a celebrated example of chalk reservoir with porosities of 25 to 40 percent. The Norwegian Petroleum Directorate (now Sodir, the Norwegian Oil Directorate) publishes annual resource reports that rely on petrophysical porosity data submitted by operators under the Petroleum Activities Act. The Ekofisk chalk is overpressured and was found to compact significantly during production, reducing porosity by several percentage units and driving reservoir subsidence that required platform leg extensions in the 1980s. In the Middle East, the Arab carbonates of Saudi Arabia, Kuwait, and the UAE typically display matrix porosities of 15 to 25 percent with additional fracture and vuggy porosity contributing to exceptional productivity. Saudi Aramco, KOC, and ADNOC operate extensive petrophysical core analysis laboratories to characterize inter-well porosity variation across their giant fields. The Society of Petroleum Engineers (SPE) Petroleum Resources Management System (PRMS) requires that porosity data used in reserves estimates be derived from methods appropriate to the lithology and fluid content. Fast Facts The North Sea Ekofisk chalk field, discovered in 1969, has reservoir porosities of 30 to 40 percent, among the highest measured in any producing limestone formation worldwide, yet its permeability is so low (0.1 to 1 millidarcy) that economic production required massive hydraulic fracturing of the chalk before horizontal wells became standard practice. Porosity Measurement Methods and Calculations Laboratory measurement on core plugs provides the most direct porosity data. The most common method is the gas expansion (Boyle's Law) technique: a cleaned, dried core plug of known bulk volume is exposed to helium at a known pressure, and the pressure drop when helium expands into the pore space allows calculation of grain volume. Subtracting grain volume from bulk volume gives pore volume. API RP 40 describes the full procedure. Liquid resaturation methods also measure effective pore volume by weighing a dry plug and then a brine-saturated plug; the difference equals pore volume times brine density. Wireline log porosity tools estimate porosity over the entire logged interval rather than just at core plug locations. The compensated neutron porosity log measures the slowing of fast neutrons by hydrogen atoms in pore fluids; because hydrogen is also bound in clay minerals and organic material, the tool overestimates porosity in shaly sands. The compensated density log measures formation bulk density (rhob) and converts it to porosity using: porosity = (rhoma - rhob) / (rhoma - rhof), where rhoma is matrix density (2.65 g/cm3 for quartz, 2.71 for calcite) and rhof is fluid density (1.0 g/cm3 for brine, 0.8 for oil, 0.1 for gas). Gas reduces fluid density below water values, causing the density log to overestimate porosity while the neutron log underestimates it; the crossing of the two curves on a neutron-density crossplot is the classic gas indicator. The neutron-density crossplot combines both tools to identify lithology and estimate porosity free of some individual tool biases. On a standard M-N or MID (matrix identification) plot, the paired readings from neutron and density logs plot near characteristic lithology lines for sandstone, limestone, and dolomite, allowing petrophysicists to select the correct matrix density before calculating porosity. The neutron porosity log is calibrated to limestone units (limestone porosity units, or p.u.) and must be corrected for actual matrix before use in non-carbonate formations. Nuclear magnetic resonance (NMR) logging provides a direct measurement of total and effective porosity without requiring knowledge of matrix density or fluid hydrogen index. The NMR tool measures the T2 relaxation time spectrum of protons in pore fluids; total porosity comes from the total signal amplitude, and effective porosity excludes the clay-bound water signal, which relaxes at very short T2 values (less than 3 milliseconds). NMR also delivers pore size distribution and a continuous permeability estimate, making it especially valuable in complex lithologies where conventional density-neutron methods require uncertain matrix corrections. The SPWLA has published recommended practices for NMR interpretation since the late 1990s. Archie's formation factor equation connects porosity to the electrical behavior of the reservoir, forming the backbone of water saturation calculations: F = a / phi^m, where F is the formation factor, phi is porosity, a is the tortuosity constant (typically 1.0 for consolidated sandstones), and m is the cementation exponent (typically 2.0 for consolidated sandstone, 1.7 to 2.2 for carbonates). Higher porosity means lower formation factor, which means lower resistivity at any given water saturation, making accurate porosity the prerequisite for correct water saturation and ultimately for correct reserve estimates. Tip: When neutron and density porosity values diverge significantly (more than four porosity units apart) in a clean formation, always check for gas effect first. Gas in the pore space lowers fluid density below brine, making the density log read high porosity while slowing fewer neutrons and making the neutron log read low porosity. Correcting for gas using a density-neutron overlay can shift apparent porosity by 5 to 10 porosity units, which directly changes your hydrocarbon pore volume estimate. Porosity by Lithology: Typical Values and Ranges Porosity values differ markedly by lithology and burial depth. Shallow, poorly consolidated marine sandstones may display 30 to 40 percent porosity, but compaction and cementation during burial reduce this to 10 to 20 percent at depths of 2,000 to 4,000 meters (6,500 to 13,000 feet) in most basins. Deep Paleozoic sandstones at 5,000 meters (16,500 feet) may retain only 5 to 10 percent porosity due to quartz cementation. Tight gas sandstones defined by the US Energy Information Administration (EIA) have in-situ permeability below 0.1 millidarcy and typically show porosities below 10 percent. Carbonate reservoirs span a wide porosity range. Dense micritic limestones may have less than 2 percent matrix porosity but produce well through fractures. Grainstone and packstone carbonates show 15 to 25 percent intergranular porosity. Chalks display the highest matrix porosities in the carbonate family, 25 to 45 percent, because chalk consists of nanometer-scale coccolithic plates that create abundant micro-porosity. Dolomitized carbonates often show enhanced porosity of 15 to 20 percent because the dolomitization reaction converts CaCO3 to CaMg(CO3)2 with a volume reduction that creates intercrystalline pores. Shale reservoirs producing from the source rock itself (unconventional plays) present the most complex porosity challenge. Organic-rich shales contain pores in both the inorganic clay matrix and within solid organic matter (kerogen-hosted pores). Total porosities in the Barnett, Marcellus, Eagle Ford, and Duvernay shales range from 3 to 9 percent but are heterogeneous at the nanometer scale. NMR and focused ion beam scanning electron microscopy (FIB-SEM) are increasingly used alongside conventional wireline logs to characterize shale porosity in these unconventional reservoirs.

The exponent, m, in the relation of formation factor (F) to porosity (phi). For a single sample, F is related to phi using the Archie equation F = 1 / phim, with m being the only coefficient needed. In this case, m has been related to many physical parameters, but above all to the tortuosity of the pore space. In theory, it can range from 1 for a bundle of tubes to infinity for porosity that is completely unconnected. For a simple packing of equal spheres, m = 1.5. With a more tortuous pore space or more isolated pores, m increases, while with fractures or conductive solids, m decreases. As a general average for typical reservoir rocks, m is often taken as 2.For a group of rock samples, it is common practice to find a relationship between F and phi that uses two coefficients (F = a / phim). In this case m, like a, becomes an empirical constant of best fit between F and phi, and may take a wide range of values. In complex formations, such as shaly sands or carbonates with multiple pore types, a constant m does not give good results. One solution is to vary m, with the variability related to parameters such as porosity, shaliness, or rock texture, or else determined directly from logs in zones where the water saturation is known or can be computed from a nonresistivity measurement such as electromagnetic propagation.In shaly sands, the preferred solution is to use a saturation equation, such as Waxman-Smits, dual water, SGS or CRMM, in which m is defined as the intrinsic m, determined from the intrinsic formation factor at high salinities or after correction for the effect of shale. In carbonates with multiple pore types, such as fractures, vugs, interparticle porosity and microporosity, one solution is to use equations with different porosity exponents for each pore type. The volume of each pore type must then be determined from logs or borehole images.

A unit equal to the percentage of pore space in a unit volume of rock. It is abbreviated to p.u. and lies between 0 and 100.

A rock or soil with interconnected pores that permit flow of fluids through the medium.

A method for desaturating a core sample by placing one end in capillary contact with a porous plate and applying gas or oil under pressure to the remaining surfaces. The liquid in the original fully saturated sample is expelled through the porous plate. At different pressure stages, the sample is weighed to determine the loss of liquid, and the gas or oil pressure increased. Desaturation continues until no more weight loss is observed, at which time the sample is at irreducible watersaturation. Core samples are desaturated to measure, for example, capillary pressure, irreducible water saturation, resistivity index or nuclear magnetic resonance response.

The product obtained by pulverizing clinker consisting essentially of hydraulic calcium silicates. Portland cement is the most common type of cement used for oil- and gas-well cementing.

Hard granular nodules composed essentially of hydraulic calcium silicates, with smaller quantities of calcium aluminates and ferrites. Portland cement clinker is produced by the heat treatment of cement raw materials in a kiln. Clinker is pulverized with gypsum in the manufacture of portland cement.

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

To annotate a map or other display with data at the appropriate location. For example, geologists post formation tops on well logs, isopach maps and seismic profiles. Geophysicists post velocity values and traveltimes on maps before contouring. Engineers contour maps posted with pressure or production data. Posting can become an iterative process as new data become available and interpretations are updated.

Pertaining to a hydrocarbon source rock that has generated as much hydrocarbon as possible and is becoming thermally altered.

An element with an atomic number of 19. The 40K isotope is radioactive, decaying with the emission of a single gamma ray of 1.46 MeV with a half-life of 1.3 * 109 years to give a stable isotope of argon. Potassium is the largest source of natural radioactivity. It occurs in illite, alkali feldspars, micas and some evaporite minerals. It also occurs in some drilling mud systems. The 40K isotope is only a small fraction, about 0.012%, of the total potassium, the main isotope being 39K, which has an abundance of about 1.7% in the Earth's crust. For the purposes of logging, the total potassium is calculated from the measured quantity of 40K and scaled in percent by weight. It is a valuable aid in determining the mineral content of a formation.

The ion of potassium, K+. There are tests used to monitor high (>5000 mg/L) or low (

A class of muds that contain potassium ion (K+) dissolved in the water phase. Potassium muds are the most widely accepted water mud system for drilling water-sensitive shales, especially hard, brittle shales. K+ ions attach to clay surfaces and lend stability to shale exposed to drilling fluids by the bit. The ions also help hold the cuttings together, minimizing dispersion into finer particles. The presence of Na+ ions counteracts the benefits of K+ ions and should be minimized by using fresh water (not sea water) for make-up water. With time, Na+, Ca+2 and other ions accumulate from ion exchange with clays, making the mud less effective, but regular treatment to remove Ca+2 improves polymer function. Potassium chloride, KCl, is the most widely used potassium source. Others are potassium acetate, potassium carbonate, potassium lignite, potassium hydroxide and potassium salt of PHPA. Use of bentonite clay is restricted because of its strong affinity for K+. Instead, various polymers are used. XC polymer and PHPA are used for rheology. For fluid-loss control, mixtures of starch and polyanionic cellulose are often used. CM starch, HP starch, carboxymethylcellulose and sodium polyacrylate (SPA) are also used. PHPA is widely used for shale encapsulation. Potassium, lime and starch-like polymers have also been used as potassium mud systems. Although three API methods exist for determining the K+ ion concentration, the centrifuge method (for K+ >5000 mg/L) is the most accepted field method, and essential for daily monitoring of potassium in a mud. Regular additions of potassium salt maintain shale stability. K+ ion is rapidly consumed while drilling shallow, soft and highly dispersive (gumbo) shales, but maintaining sufficient K+ ion to stabilize gumbo can become expensive when drilling large holes. Researchers, notably Dr. Dennis O'Brien and Dr. Martin Chenevert (while at Exxon Production Research), evaluated different shales, their clay mineralogy and the concentration of K+ needed to stabilize them. Potassium muds above about 1 wt.% K+ ion usually fail the mysid shrimp (US EPA) bioassay test. Therefore, K-muds currently find low acceptance in offshore drilling in USA waters.Reference:O'Brien DE and Chenevert ME: "Stabilizing Sensitive Shales with Inhibited Potassium-Based Drilling Fluids," Journal of Petroleum Technology 25, no. 9 (September 1973): 1089-1100.

A field that satisfies the Laplace equation. The Laplace equation is equivalent in three dimensions to the inverse square law of gravitational or electrical attraction (in source-free regions; in regions with sources, it becomes Poisson's equation). Examples of potential fields include the field of the gravity potential and static electric and magnetic fields.

The temperature at which a fluid ceases to pour. The pour point for oil can be determined under protocols set forth in the ASTM D-97 pour point test, in which the pour point is established as that temperature at which oil ceases to flow when the sample is held at 90 degrees to the upright for five seconds. High pour points usually occur in crude oils that have significant paraffin content. Paraffins (or waxes) will start to precipitate as temperature decreases. At some point the precipitates accumulate to the point where the fluid can no longer flow. This phenomenon can occur with light oils as well as heavy oils.

In hydraulic pumping, the crude oil that is pressurized at surface to energize the bottom pump.

Volume of fluid injected in a well during hydraulic pumping.

A fluid described by the two-parameter rheological model of a pseudoplastic fluid, or a fluid whose viscosity decreases as shear rate increases. Water-base polymer muds, especially those made with XC polymer, fit the power-law mathematical equation better than the Bingham plastic or any other two-parameter model. Power-law fluids can be described mathematically as follows:

A siliceous or siliceous and aluminous material that possesses little or no cementitious value. In a finely divided form and in the presence of moisture, however, pozzolan reacts chemically with calcium hydroxide to form compounds possessing cementitious properties.

Pertaining to material that possesses little or no cementitious value, but that is capable of reacting chemically with calcium hydroxide at ordinary temperatures to form compounds with cementitious properties.

Abbreviation for concentration, parts-per-billion. For example, lead in a water sample is 10 ppb.

Abbreviation for density, pounds-per-gallon, more correctly written lbm/gal. For example, the density of water is 8.33 ppg at 60°F [16°C].

Abbreviation for the expression of concentration, parts-per-million. For solid and liquid concentrations, ppm is stated in weight (mass) units. For example: (1) Calcite in a ground barite sample is 400 ppm. (2) Calcium chloride in a water solution is 250,000 ppm. Note that the relationship of ppm to weight percentage is 10,000 ppm = 1 wt.%. For gases, ppm is in volume (or mole) units. For example, H2S in an air sample is 10 ppm (both by volume or by moles).

A reaction by-product. In sandstoneacidizing, the reaction between hydrofluoric acids [HF] or spent HF acids with formation minerals can precipitate nondamaging products, such as silica, borosilicates or fluoborates. However, other insoluble or difficult to remove by-products can create formation damage.Ferric iron (Fe+3) and ferrous iron (Fe+2) are potential sources for precipitates. Ferric iron present in some formation minerals, including chlorite and glauconite clays, and in tubing rust (iron oxide) can precipitate as ferric hydroxide [Fe(OH)3], which is a gelatinous, highly insoluble mass that can plug pore channels and reduce permeability. The precipitation of ferric hydroxide or ferrous hydroxide [Fe(OH)2] depends on the pH of the spent acid. The former needs a pH higher than 2.2, while the latter requires a pH higher than 7.7. Since the maximum pH for a spent acid is approximately 5.3, the precipitation of ferric hydroxide is more common. Iron-sequestering or iron-reducing agents can be used in acid to maintain the ferric iron in solution.Calcium fluoride [CaF2] precipitates when HF contacts calcite or any other calcium source, and alkali-fluosilicates or iron sulfide form crystal-like by-products that can bridge pore throats. Additionally, some sequestering agents, corrosion inhibitors or friction reducers can also form residues that may plug formation pores.The formation of precipitates can be avoided or reduced by using a preflush, which dissolves calcareous material, iron rust or iron scales, and displaces formation brines (K, Na, Ca ions) away from the wellbore, thereby reducing the formation of CaF2, ferric hydroxide and alkali-fluosilicates.

The formation of an insoluble material in a fluid. Precipitation can occur by a chemical reaction of two or more ions in solution or by changing the temperature of a saturated solution. There are many examples of this important phenomenon in drilling fluids. Precipitation occurs in the reaction between calcium cations and carbonate anions to form insoluble calcium carbonate: Ca+2 + CO3-2 --> CaCO3. When a saturated clear brine first crystallizes, the solid is a precipitate, and is often caused by changing temperature.

The closeness of agreement between the results obtained by applying a measurement procedure several times on identical materials and under prescribed measurement conditions. The smaller the random part of experimental error, the more precise the measurement procedure. (ISO)In logging, the term usually describes the repeatability of a statistical measurement, such as a nuclear log. The precision must then refer to a particular set of conditions, for example, the speed of logging and the formation properties.

The right that a party has reserved or acquired to operate a lease, well, unit and/or concession.

The right that nonselling participating parties have in a lease, well or unit to proportionately acquire the interest that a participating party proposes to sell to a third party.

In chemical flooding, a fluid stage, normally low-salinity water, pumped ahead of the micellar or alkaline chemical solution.One of the purposes of the preflush is to displace reservoirbrine containing potassium, sodium, calcium and magnesium ions from the near-wellbore area, avoiding adverse interactions with the chemical solution. The other purposes are to adjust reservoir salinity to favorable conditions for the surfactant (chemical solution) and to obtain information about reservoir flow patterns. Sometimes a preflush stage is not necessary, especially when brine-tolerant chemical systems are used.

A water-soluble starch that has undergone irreversible changes by heating in water or steam.

To mix with water and allow to react or yield in the water before use. Prehydrating is a common technique for incorporating bentonite in cementslurry or drilling mud. Prehydration may also be done for convenience in cementing operations to allow mixing of water containing the additives with powdered neat cement. Additives also may be prehydrated with mix water to avoid dry-blending the additives with cement.

A concentrated slurry of bentoniteclay mixed in fresh water. The maximum practical concentration of bentonite is about 30 to 40 lbm/bbl because greater concentrations of bentonite are difficult to mix and pump. Water is put into the rig's prehydration tank and the pH raised to 10 or 11 with caustic soda. Soda ash is added as required to remove hardness. Bentonite is slowly added through the mud hopper. Continual energetic mixing and stirring helps the clay particles fully disperse. In some muds, lignosulfonate should be added shortly before mixing the slurry into the active system to protect the colloidal clay particles from flocculation.

The addition of a mud product to fresh water prior to adding it into the mud system. Bentonite clay and XC polymers are two additives whose performance improves by hydration in fresh water before adding them to a highly-treated or salty mud system.

A class of high-performance thread types that are commonly used in modern oilwell and gaswell completions. Premium threads are available in a number of configurations and are typically designed to provide superior hydraulic sealing, improved tensile capacity and ease of make-up. Unlike conventional threads, the sealing areas in premium thread connections are independent of the thread profile and are included as two or three areas within the tool joint, thereby providing some redundancy.

The phase of a petroleum system after hydrocarbons accumulate in a trap and are subject to degradation, remigration, tectonism or other unfavorable or destructive processes.

A core that has been preserved in the same state as when it was brought to the surface. The term implies that the core has been stored for a period before analysis. If this has not been the case, it is known as fresh core. The goal of preservation is to maintain the original fluid content, fluid distribution, rockwettability and mechanical integrity. Preserved cores are typically sealed and protected from mechanical damage. Depending on the core and the objective, they may also be frozen or placed in humidity ovens.Preservation may be wet, in which the core is submerged in a suitably prepared brine, or dry, without any fluid.

The force distributed over a surface, usually measured in pounds force per square inch, or lbf/ in.2, or psi, in US oilfield units.

A rise in well pressure as a function of time observed after a well is shut in or after the production rate is reduced. Buildup pressures are normally measured at or near the bottom of the hole.

An analysis of data obtained from measurements of the bottomhole pressure in a well that is shut-in after a flow period. The profile created on a plot of pressure against time is used with mathematical reservoir models to assess the extent and characteristics of the reservoir and the near-wellbore area.

The maximum pressure an electrical submersible pump can withstand. This pressure is directly related to the differential pressure between the discharge and the suction pressures, and it is always limited by the maximum capacity of the equipment.

The drop in average reservoir pressure from fluid production. All bounded reservoirs have pressure depletion (a drop in average reservoir pressure) associated with fluid production. Water influx counters this effect in reservoirs that are surrounded or underlain by aquifers. Likewise, the presence of a gas cap can slow pressure depletion.

A decline in well pressure with time due to production.

The pressure decline after halting or reducing fluid injection in a well. Pressure falloff tests in injection wells are analogous to pressure buildup tests in production wells.

A device used to measure pressure. Many different types of pressure gauges have been developed for use in well testing over the years. For bottomhole pressure measurements, these include helical bourdon tube gauges, strain gauges, quartz crystal gauges and surface readout gauges. All have their roles, and are still in use. Digital memory gauges are popular at the moment, since the data can be printed out or input directly into a computer for immediate use. Proper use of the data often requires specific knowledge of the possible idiosyncrasies of the particular gauge used in a test.

A change in pressure as a function of distance. This can refer to radial change in pore pressure with distance from the well (which can be calculated from well-test analysis results), to change in pore pressure with depth (which can be measured by formation tests, and implies formation fluid density and/or fluid contacts) or to change in wellbore fluid pressure with depth (which can be measured with production logs, and implies wellbore fluid density).

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

The sensor component in a system used to measure and display the pressure within a vessel or system. The pressure sender may be hydraulically or electrically connected to a remote gauge or display.

A tank designed for storing volatile liquids such as gasoline and liquefied petroleum gases (LPG), which generate high internal pressures. A pressure storage tank is commonly spherical. Other types include spheroidal or hemispherical vessels. Some pressure storage tanks can support several hundred pounds per square inch of internal pressure. A pressure storage tank is also called a pressure-type tank.

A means of assessing reservoir performance by measuring flow rates and pressures under a range of flowing conditions and applying the data to a mathematical model. Fundamental data relating to the interval under test, such as reservoir height and details of the reservoir fluids, are also input. The resulting outputs typically include an assessment of reservoir permeability, the flow capacity of the reservoir and any damage that may be restricting productivity.

A means of assessing reservoir performance by measuring flow rates and pressures under a range of flowing conditions and then applying the data to a mathematical model. In most well tests, a limited amount of fluid is allowed to flow from the formation being tested. The formation is isolated behind cemented casing and perforated at the formation depth or, in openhole, the formation is straddled by a pair of packers that isolate the formation. During the flow period, the pressure at the formation is monitored over time. Then, the formation is closed (or shut in) and the pressure monitored at the formation while the fluid within the formation equilibrates. The analysis of these pressure changes can provide information on the size and shape of the formation as well as its ability to produce fluids.

A graphical representation indicating phase behavior for variation of saturationpressure and injection gas concentration at a given temperature. The diagram indicates conditions for single-phase and two-phase behavior and, within the two-phase region, lines of constant volume fraction, termed quality lines. The diagram is constructed using swelling test saturation pressures and liquid volumes.

The analysis of pressure-transient behavior observed while the well is flowing. Results are generally much less accurate than those from pressure buildup tests because the bottomhole pressure fluctuates rapidly with even slight changes in the surface flow rate. Therefore, pressure buildup tests are much preferred, and analysis of drawdown test data is usually relegated to backup status unless the buildup data are flawed.

A plot of p2 versus time function used to analyze low-pressure gas-well drawdown and buildup tests. The square term arises from substituting a gas-law equation into the differential equations where required to account for fluid compressibility. This allows an approximation for the differential equations that approaches the linear form required to use the classical solutions of the diffusion equation.

The analysis of pressure changes over time, especially those associated with small variations in the volume of fluid. In most well tests, a limited amount of fluid is allowed to flow from the formation being tested and the pressure at the formation monitored over time. Then, the well is closed and the pressure monitored while the fluid within the formation equilibrates. The analysis of these pressure changes can provide information on the size and shape of the formation as well as its ability to produce fluids.

Well tests in which pressure is recorded as a function of time and interpreted using various analysis methods. These include buildup tests and drawdown tests in production wells and falloff tests in injection wells. Pressure-transient well-test analysis procedures are based on classical mathematical relationships between flow rate, pressure and time, which are directly analogous to the theory of heat transfer.

A device to measure density (weight) of a mud, cement or other liquid or slurry under sufficient pressure that the effect of gas bubbles in the liquid is eliminated. The balance consists of a fixed-volume mud cup on one end of a graduated beam and a counterweight on the other end. The beam has a knife-edge as a balance point and a bubble to show when it is level. The mud cup has a screw-on, sealed cap with a valve in the cap to allow connection of a small piston-type hand pump. Operation of the pressurized balance is identical to an ordinary mud balance after pressurization.

The first cementing operation performed to place a cement sheath around a casing or liner. The main objectives of primary cementing include zonal isolation to prevent fluid migration in the annulus, support for the casing or liner, and protection of the casing from corrosive fluids.

The main elements of an oil or gas well, including the production tubing string, that enable a particular type or design of completion to function as designed. The primary completion components depend largely on the completion type, such as the pump and motor assemblies in an electrical submersible pump completion.

The expulsion of newly generated hydrocarbons from a source rock. The further movement of the hydrocarbons into reservoir rock in a hydrocarbon trap or other area of accumulation is secondary migration.

The porosity preserved from deposition through lithification.

(noun) The first stage of hydrocarbon recovery in which oil and gas are produced using the natural energy of the reservoir, including solution gas drive, gas cap expansion, water drive, gravity drainage, and rock and fluid expansion. Primary recovery typically recovers 5% to 30% of the original oil in place, depending on the drive mechanism.

The first stage of hydrocarbonproduction, in which natural reservoir energy, such as gasdrive, waterdrive or gravity drainage, displaces hydrocarbons from the reservoir, into the wellbore and up to surface.Initially, the reservoir pressure is considerably higher than the bottomhole pressure inside the wellbore. This high natural differential pressure drives hydrocarbons toward the well and up to surface. However, as the reservoir pressure declines because of production, so does the differential pressure. To reduce the bottomhole pressure or increase the differential pressure to increase hydrocarbon production, it is necessary to implement an artificial lift system, such as a rod pump, an electrical submersible pump or a gas-lift installation. Production using artificial lift is considered primary recovery.The primary recovery stage reaches its limit either when the reservoir pressure is so low that the production rates are not economical, or when the proportions of gas or water in the production stream are too high. During primary recovery, only a small percentage of the initial hydrocarbons in place are produced, typically around 10% for oil reservoirs.Primary recovery is also called primary production.

The means by which the initial reservoirproduction is achieved, such as natural production from a gas-drive reservoir. In many cases, a secondary recovery method, such as waterflood, is required to maintain a viable reservoir production rate.

Seismic events whose energy has been reflected once. Multiples, in contrast, are events whose energy has been reflected more than once. A goal of seismic data processing is to enhance primary reflections, which are then interpreted as subsurface interfaces.

The period of time during which an oil and gas lease will be in effect, in the absence of production, drilling or other operations specified by the lease. The oil and gas lease can be perpetuated past the primary term by production in paying quantities, drilling, operations and/or the payment of shut-in royalties specified by the lease.

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

(noun) A flexible, rope-like explosive charge consisting of a core of PETN or RDX explosive within a textile or plastic outer sheath, used to transmit a detonation signal between perforating charges, boosters, or other explosive components in a perforating gun assembly.

The axis along which the data in n-dimensional space is primarily distributed. In two dimensions, the first principal axis is the semimajor axis of the ellipse that best fits the data set. Multiple principal axes are always orthogonal. Data are sometimes rearranged to be in principal component space before further analysis (such as cluster analysis) is performed. Analysis on data that have been transformed into principal component space is referred to as principal component analysis, or PCA.

Analysis of data that has been transformed from the original axes to principal axes, often abbreviated PCA. The first principal axis is the direction in which the data are primarily distributed or the "long" axis of the distribution in n-dimensional space. Data are sometimes rearranged to be in principal component space before further analysis (such as cluster analysis) is performed.

A numerical estimate of the chances of an event occurring given a limited number of opportunities for the event to occur.

In electromagnetic methods, to measure the variation of a property versus depth, including electrical, electromagnetic and magnetotelluric properties. Probing differs from profiling in that the goal of probing is to provide a record of vertical changes, whereas profiling documents lateral variations.

Alteration of seismic data to suppress noise, enhance signal and migrate seismic events to the appropriate location in space. Processing steps typically include analysis of velocities and frequencies, static corrections, deconvolution, normal moveout, dip moveout, stacking, and migration, which can be performed before or after stacking. Seismic processing facilitates better interpretation because subsurface structures and reflection geometries are more apparent.

A generic term used in a number of contexts but most commonly to describe any fluid produced from a wellbore that is not a treatment fluid. The characteristics and phase composition of a produced fluid vary and use of the term often implies an inexact or unknown composition.

A term used to describe water produced from a wellbore that is not a treatment fluid. The characteristics of produced water vary and use of the term often implies an inexact or unknown composition. It is generally accepted that water within the pores of shale reservoirs is not produced due to its low relative permeability and its mobility being lower than that of gas.

An underground rockformation from which oil, gas or water is produced. Any porous rock will contain fluids of some sort, and all rocks at considerable distance below the Earth's surface will initially be under pressure, often related to the hydrostatic column of ground waters above the reservoir. To produce, rocks must also have permeability, or the capacity to permit fluids to flow through them.

A well producing fluids (gas, oil or water).

A measure of the efficiency of seismic acquisition. Production can be expressed in terms of the number of lines, shots or lengths (km or miles) of data acquired in a given time.

Payment by a well operator to a host country upon achievement of certain levels of production.

A casing string that is set across the reservoir interval and within which the primary completion components are installed.

What Is a Production Log? A production log records one or more in-situ measurements that describe the nature and behaviour of fluids in or around the wellbore during active production or injection, enabling engineers worldwide to quantify flow contributions by zone, diagnose underperforming intervals, confirm stimulation effectiveness, and allocate production accurately across multilayer or multi-lateral well completions. Key Takeaways Production logs measure dynamic fluid behaviour inside a producing or injecting well, in contrast to open-hole formation evaluation logs that characterise the static reservoir before completion. The standard production logging tool (PLT) suite combines a spinner flowmeter for velocity, a fluid density log for phase identification, a capacitance or water-holdup sensor, a temperature log, and a pressure gauge into a single pass or series of passes at multiple flow rates. Multiphase flow in deviated and horizontal wells introduces severe measurement complexity because gravity causes liquid phases to segregate in the pipe cross-section, requiring specialised tools and interpretation models beyond the simple pipe-flow assumptions used in vertical well analysis. Distributed temperature sensing (DTS) via permanently installed fibre-optic cables now provides continuous, real-time production log data along the entire wellbore without intervention, transforming production surveillance from periodic spot surveys into continuous reservoir monitoring. Production log economics hinge on comparing the intervention cost per run against the expected incremental production gain from a workover, stimulation, or completion modification identified by the log data, and most operators require a minimum payback period of 12 months or less to justify a PLT run. How Production Logging Works A production logging survey involves lowering a tool string into a live, producing or injecting well and making measurements while fluid is flowing. Unlike open-hole wireline logging, which is conducted in a static borehole before the well has been completed and put on production, production logging takes place with the well in its normal operating condition. The tool string is conveyed either on conventional wireline cable from a surface truck, on slickline if only mechanical tools are needed, or on coiled tubing in horizontal wells where gravity prevents wireline tools from reaching the lateral section. The tool is run in hole at a controlled speed and then pulled back at a series of different flow velocities to determine how the instrument response changes as a function of tool velocity, allowing the true fluid velocity to be separated from the tool's own motion through the fluid. The most fundamental production logging measurement is the spinner flowmeter, which consists of a small rotating impeller whose spin rate is proportional to the fluid velocity past the tool. In a vertical well producing a single-phase fluid, the spinner reading directly converts to volumetric flow rate when multiplied by the pipe cross-sectional area. Measurements at multiple tool speeds, both up-passes and down-passes, allow the interpretation software to determine the cable-motion correction and produce a reliable velocity profile. Integrating the velocity profile over depth gives the contribution of each perforated interval to the total flow, expressed either as a flow profile (barrels per day or cubic metres per day per metre of perforated interval) or as a cumulative percentage contribution by zone. Because most wells produce two or three fluid phases simultaneously, oil, water, and gas, a single spinner measurement is insufficient for complete flow characterisation. The fluid density log, recorded by a gamma-ray densitometer or a differential pressure sensor, measures the bulk density of the fluid mixture at the tool depth, which shifts between the density of water (approximately 1.0 grams per cubic centimetre, or 62.4 pounds per cubic foot) and the density of oil (typically 0.75 to 0.85 g/cc) as the water cut changes. The capacitance or water-holdup tool measures the dielectric properties of the fluid mixture, which change sharply between the high-dielectric water phase and the low-dielectric oil and gas phases, providing a direct estimate of the local water fraction, or water holdup, in the pipe cross-section. Temperature logs detect the Joule-Thomson cooling effect as gas expands through perforations or zones of high pressure drawdown, identifying gas entry points that may not be obvious from the spinner alone. Pressure gauges record the flowing bottomhole pressure and the pressure gradient, which confirms fluid density calculations and provides the data needed for inflow performance relationship (IPR) analysis and future well deliverability forecasting. Production Logging Across International Jurisdictions Canada: AER Production Reporting and Log Data Requirements The Alberta Energy Regulator (AER) regulates production logging activities in Alberta under Directive 038, which covers well servicing operations, and Directive 083, which covers commingled production from multiple zones. When an operator produces oil or gas from two or more separate pools through the same wellbore, the AER requires production allocation between pools to be demonstrated, which is typically accomplished through either zonal testing with packers or through production logging surveys that quantify the fractional contribution of each zone. Log data submitted in support of commingled production applications must include interpretation reports demonstrating the basis for the proposed allocation percentages. The AER's Petrinex reporting system tracks monthly production volumes by pool, and production log data provides the technical justification when those allocations are challenged or reviewed. In the Montney and Duvernay unconventional plays, multi-stage hydraulically fractured horizontal wells are almost universally commingled across dozens of perforation clusters. Production logging in these wells, conducted via coiled tubing-conveyed PLT suites, identifies which stages are contributing to production and which are not, informing refracturing decisions and completion design improvements in future wells on the same pad. The British Columbia Oil and Gas Commission (BCOGC) has similar reporting requirements for Montney wells in northeastern British Columbia, where the province's Petroleum and Natural Gas Act governs well servicing and production surveillance activities. United States: BSEE and BOEM Production Monitoring Requirements In U.S. offshore waters, the Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Ocean Energy Management (BOEM) jointly regulate production operations on the Outer Continental Shelf under the authority of the Outer Continental Shelf Lands Act (OCSLA). BSEE's regulations at 30 CFR Part 250 require operators to maintain accurate production records and to conduct periodic well surveys to verify that production is being allocated correctly between zones, leases, and royalty-bearing intervals. Production log surveys are a standard means of demonstrating that zonal commingling is consistent with approved field development plans and that no undisclosed inter-zone communication is occurring through the wellbore or through the reservoir. In onshore U.S. operations, the Railroad Commission of Texas (RRC) requires production reporting by lease and by field, and the formation-specific allocation data that underpins those reports is often derived from production log surveys. In the Gulf of Mexico deepwater environment, where horizontal subsea wells produce from multiple reservoir sands in a single completion, production logging surveys are conducted periodically to verify that the flow allocation model used in the reservoir simulation history match is consistent with actual in-situ measurements. BSEE's inspection and enforcement division reviews production log data as part of its metering verification programme for offshore royalty payment purposes. Australia: NOPSEMA Production Facility Requirements The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates offshore petroleum production facilities in Australian Commonwealth waters under the Offshore Petroleum and Greenhouse Gas Storage Act (OPGGSA). NOPSEMA's Safety Case framework requires operators to demonstrate that production operations are conducted within specified safety parameters, and production logging data contributes to the well integrity evidence base by confirming that produced fluids are flowing through intended perforations and not through annular channels or compromised casing. The West Australian Department of Mines, Industry Regulation and Safety (DMIRS) governs onshore and state-water petroleum activities in Western Australia, where the Carnarvon Basin offshore and the onshore Perth Basin and Cooper Basin extension into South Australia require similar production allocation documentation. Australian operators such as Woodside Energy and Santos conduct regular production logging surveys in their North West Shelf and Timor Sea facilities to manage water breakthrough in high-rate gas condensate wells and to identify gas cap expansion in oil rim reservoirs. The challenging wellbore environments on Australia's North West Shelf, with high bottomhole temperatures exceeding 150 degrees Celsius (302 degrees Fahrenheit) and pressures above 70 megapascals (about 10,000 psi), require high-temperature, high-pressure (HTHP) rated production logging tool strings, which add cost but are essential for reliable data acquisition. Middle East: Saudi Aramco Ghawar Horizontal Well Production Logging Saudi Aramco operates one of the world's most sophisticated production logging programmes in the Ghawar field, where hundreds of horizontal oil producers and water injectors require regular surveillance to manage the advancing water drive and to maintain oil production rates that underpin global energy markets. In Ghawar's Arab-D carbonate reservoir, horizontal wells may extend 2,000 metres (6,560 feet) or more through the reservoir, and the production log confirms whether the entire lateral length is contributing uniformly or whether certain sections have watered out, are experiencing near-wellbore damage, or are producing from below the oil-water contact. Saudi Aramco has developed proprietary interpretation protocols for production log data in carbonate horizontal wells, incorporating advanced multiphase flow modelling that accounts for the irregular fracture and vug network that characterises Arab-D reservoir heterogeneity. The Ministry of Energy of the Kingdom of Saudi Arabia sets national production targets under Saudi Aramco's concession agreement, and accurate production allocation data from production logs is integral to the reservoir management strategy that supports those targets. Saudi Aramco's production logging programme includes permanent downhole gauges in many Ghawar producers that transmit pressure and temperature data continuously to surface, complementing periodic PLT runs to provide a continuous surveillance record over the producing life of each well. Norway: Sodir Production Allocation Requirements The Norwegian Offshore Directorate (Sodir, formerly Oljedirektoratet) requires all operators on the Norwegian Continental Shelf to maintain accurate production allocation documentation in accordance with the Resource Management Regulations issued under the Petroleum Act. Where multiple reservoirs are produced commingled through a single wellbore, operators must demonstrate allocation accuracy to within agreed tolerances, typically five to ten percent, using approved metering systems or alternative techniques such as production logging surveys. Sodir's DISKOS national petroleum data repository holds production data for all Norwegian fields, and production log data submitted in support of allocation documentation is archived in DISKOS for the field's producing life. Equinor, Aker BP, and ConocoPhillips Norway conduct production logging in subsea horizontal wells on fields such as Johan Sverdrup, Snorre, and Ekofisk using either wireline-deployed tractor-conveyed tool strings (which use motorised wheels to pull the tool string through the horizontal section against gravity and friction) or coiled tubing-conveyed PLT suites, depending on the completion configuration and the available intervention vessel. The North Sea's challenging well environment, with high H2S and CO2 concentrations in some fields and bottomhole pressures exceeding 50 megapascals (about 7,250 psi) in Ekofisk chalk, requires tool strings with enhanced materials specifications and downhole electronics rated for sour-service environments.

A device used to isolate the annulus and anchor or secure the bottom of the production tubing string. A range of production packer designs is available to suit the wellbore geometry and production characteristics of the reservoir fluids.

A portion of proceeds from production, specified by contract, and payable to the lessor or farmor, or host country until total payment has reached a predetermined limit specified by contract.

A fine paid to the host country for failure to attain specified production rates over a defined period of time.

The flow period before a buildup. The duration of the production period should be specified in the test design to assure that a stable flow situation is reached, and that the pressure disturbance has reached far enough into the formation to allow determination of a representative value for kh. For reservoir-limits testing, the production period must be long enough for the pressure disturbance to have reached the boundaries of interest.

An agreement between the parties to a well or wells and a host country to utilize specified goods and services from that country.

An agreement between the parties to a well and a host country regarding the percentage of production each party will receive after the participating parties have recovered a specified amount of costs and expenses.

The primary conduit through which reservoir fluids are produced to surface. The production string is typically assembled with tubing and completion components in a configuration that suits the wellbore conditions and the production method. An important function of the production string is to protect the primary wellbore tubulars, including the casing and liner, from corrosion or erosion by the reservoir fluid.

What Is Production Tubing? Production tubing is the steel pipe string installed inside the production casing of a completed well to serve as the primary conduit for conveying reservoir fluids, including oil, gas, condensate, and water, from the perforated or open-hole completion interval upward to the surface wellhead. Selected to match the wellbore geometry, anticipated flow rates, reservoir fluid chemistry, and downhole pressure and temperature conditions, production tubing is assembled with packers, safety valves, and landing nipples into a production string hung from the tubing hanger at the wellhead. Key Takeaways Production tubing is the innermost steel pipe string in a completed well, installed inside the production casing to flow reservoir fluids from the completion interval to the surface, and it is designed independently of the casing string to allow retrieval and replacement without killing or abandoning the well. Tubing size is expressed as outside diameter (OD) and ranges from 2-3/8 inches (60.3 mm) in tight, low-rate gas wells to 4-1/2 inches (114.3 mm) in high-rate oil producers or injectors; the nominal inside diameter governs maximum flow velocity, erosion risk, and the size of downhole tools that can be run on wireline or coiled tubing. Steel grade selection follows API 5CT, with grades ranging from H-40 for shallow low-pressure wells to P-110 and Q-125 for high-pressure deep wells, and sour service grades L-80 and C-95 for wells producing hydrogen sulfide (H2S) or high CO2 concentrations per NACE MR0175/ISO 15156. Premium threaded connections, such as VAM TOP and Tenaris TenarisHydril, provide gas-tight metal-to-metal seals required for gas wells, high-angle wells, and wells where API round-thread connections cannot reliably maintain the pressure integrity of the production envelope over the well's producing life. The production tubing string integrates with downhole completion components including the production packer, subsurface safety valve (SSSV), gas lift mandrels, and landing nipples, forming a complete production system that controls fluid flow, provides emergency shut-in capability, and allows for future workover intervention to replace or modify downhole equipment. How Production Tubing Works After a well has been drilled, cased, and cemented, the production completion phase installs the downhole equipment that transforms the wellbore into a producing asset. The tubing string is made up at surface by threading together individual tubing joints, each typically 9.14 meters (30 feet) in length, along with the downhole components: a tubing hanger at the top, a subsurface safety valve 30 to 100 meters (98 to 328 feet) below surface, one or more landing nipples at specific depths for wireline plug settings, a production packer near the top of the perforated interval, and in some completions, a blast joint opposite the perforations to resist erosion from high-velocity reservoir fluid entry. The assembled string is run into the wellbore on a workover rig or completion rig and set by applying hydraulic pressure or mechanical rotation to activate the packer, which creates a seal between the tubing and the production casing annulus. Once set, the annulus between tubing and casing (the "A-annulus") is isolated from the reservoir by the packer. Reservoir fluids enter the wellbore through the perforations or open-hole completion, flow inside the tubing to surface, and pass through the christmas tree flow control valves and choke to the gathering pipeline. The annulus above the packer serves as a safety monitoring space: a pressure gauge installed on the tubing-casing annulus valve of the christmas tree allows operators to detect casing-to-tubing seal failures or packer leaks by monitoring for any pressure buildup in the annulus. In gas lift completions, the annulus serves the additional function of carrying injection gas from surface down to the gas lift mandrels, where gas is injected into the tubing to reduce the hydrostatic fluid column and lift production. Tubing selection is governed by the maximum anticipated surface pressure (MASP), the maximum anticipated bottomhole temperature, the fluid composition (CO2 partial pressure, H2S partial pressure, chloride concentration, and water cut), the completion type (vertical, deviated, or horizontal), and the expected flow rates over the producing life. For a high-rate gas condensate well in the Gulf of Mexico with a bottomhole pressure of 69 MPa (10,000 psi) and bottomhole temperature of 177 degrees Celsius (350 degrees Fahrenheit), the tubing must resist internal burst pressure, external collapse from annular pressure, tensile loads from its own weight in a deviated wellbore, and corrosion from CO2 and H2S partial pressures that may exceed 0.7 MPa (100 psi). These loading cases are analyzed using API 5C3 or ISO 10400 burst, collapse, and tension formulas, typically supplemented by the operator's proprietary triaxial stress analysis software. Production Tubing Across International Jurisdictions Canada (AER Directive 036 and NACE MR0175): The Alberta Energy Regulator (AER) requires tubing design documentation in the completion program submitted with each well license application under Directive 036. For Montney Formation wells in the Deep Basin and Dawson Creek area, which produce liquids-rich gas with CO2 concentrations up to 3 percent and H2S concentrations up to 1 percent by volume, operators must demonstrate sour service compliance per NACE MR0175 / ISO 15156 Part 2, typically selecting L-80 or C-95 grade tubing with premium connections. Montney HPHT wells, where bottomhole pressures can exceed 75 MPa (10,875 psi) and bottomhole temperatures can exceed 200 degrees Celsius (392 degrees Fahrenheit), increasingly specify P-110 or Q-125 tubing with titanium alloy or CRA metallurgy for particularly aggressive CO2 environments. Saskatchewan's Ministry of Energy and Resources administers similar tubing design requirements under the Oil and Gas Conservation Regulations, with sour service requirements mirroring AER standards for wells completed in the Bakken, Shaunavon, and Torquay formations. United States (BSEE 30 CFR Part 250 and API 5CT): For offshore wells in the Gulf of Mexico, the Bureau of Safety and Environmental Enforcement (BSEE) mandates under 30 CFR Part 250.517 that all completions include a surface-controlled subsurface safety valve (SCSSV) set at least 30 meters (100 feet) below the mudline, capable of automatic closure on loss of surface control pressure. This requirement applies to all tubing strings in all subsea and surface-platform wells on the Outer Continental Shelf. Operators submit a Completion Procedure application, including tubing design calculations, safety valve specifications, and pressure test procedures, for BSEE review before commencing completion operations. The Eagle Ford Shale in South Texas and the Permian Basin in West Texas and New Mexico fall under the Texas Railroad Commission, which enforces tubing requirements through Rule 36 (H2S safety) and Rule 78 (casing and completion requirements), referencing API 5CT and API 11D1 as the applicable technical standards. Australia (NOPSEMA Production Operations Guidance): NOPSEMA's Well Integrity Guidelines require that the production tubing string constitute a verified element of the primary well barrier envelope in all offshore producing wells. Operators on the North West Shelf, including the Woodside-operated North Rankin and Goodwyn platforms, and in Bass Strait, use 3-1/2 inch or 4-1/2 inch P-110 or C-95 tubing with premium connections to handle the high-pressure dry gas produced from Jurassic Triassic reservoirs. The Ichthys LNG project's subsea wells in the Browse Basin use 3-1/2 inch P-110 tubing with CRA overlay connections to resist CO2 corrosion from the Ichthys reservoir gas, which contains approximately 12 percent CO2. NOPSEMA requires all SCSSVs installed in offshore Australian wells to be tested at minimum annually, with all test results documented in the facility's Safety Case and available for regulatory audit. Norway and the North Sea (NORSOK D-010 and Sodir Regulations): The Johan Sverdrup field in the North Sea, operated by Equinor, is one of the largest recent completion programs in Norwegian history. The Jurassic Ness and Etive sandstone reservoirs of Johan Sverdrup contain reservoir fluids with CO2 concentrations up to 5 percent by mole fraction, requiring corrosion-resistant alloy (CRA) tubing in wells where partial CO2 pressure exceeds the ISO 15156 threshold for carbon steel. Equinor and its partners selected 13Cr (13-percent chromium martensitic stainless steel) tubing as the base specification for most Johan Sverdrup production wells, with super 13Cr or duplex stainless steel selected for the highest-CO2 wells. The Petroleum Safety Authority Norway (PSA) enforces NORSOK D-010 requirements mandating that the production tubing and packer assembly be independently pressure-tested to maximum anticipated wellbore pressure before the completion is accepted as a verified primary barrier. Sodir (the Norwegian Offshore Directorate) collects tubing failure and workover data as part of its annual production statistics for the Norwegian Continental Shelf. Middle East (Saudi Aramco SAES and ADNOC Standards): Saudi Aramco's Arab-D limestone reservoirs in the Ghawar field produce under high pressure, with initial reservoir pressures in the Uthmaniyah and Hawiyah areas approaching 25 MPa (3,625 psi) at depths of 2,100 to 2,300 meters (6,890 to 7,546 feet) TVD. Saudi Aramco Engineering Standards (SAES-S-070 and related drilling and completion standards) specify P-110 tubing as standard for these wells, with premium connections required for all deviated and horizontal wells. For the Safaniya offshore field, where water injection pressures and produced water volumes create elevated CO2 corrosion risk, 13Cr or L-80 tubing is specified. ADNOC's onshore fields in Abu Dhabi, particularly the massive Umm Shaif and Zakum developments, use 3-1/2 inch and 4-1/2 inch P-110 tubing in horizontal development wells, with premium connections (VAM TOP or equivalent) required for all wells exceeding 45 degrees inclination. Fast Facts Most common tubing OD for onshore oil wells: 2-7/8 inch (73.0 mm) OD for rod-pumped stripper wells; 3-1/2 inch (88.9 mm) for moderate-rate producers Sour service threshold (NACE MR0175): wells producing H2S with partial pressure exceeding 0.003 MPa (0.5 psi) at total system pressure require sour service metallurgy API 5CT grades for sour service: H-40, J-55, K-55, L-80, and C-90 are acceptable; N-80, C-95, P-110, and Q-125 require special testing or are prohibited in the most severe sour environments without additional qualification Premium connection gas tightness: VAM TOP and TenarisHydril TS are rated for gas-tight service to full tubular body rating; API 8-round EUE connections are typically rated to 69 MPa (10,000 psi) in gas service only with sealing compounds and are not accepted for HPHT or high-angle applications Typical tubing wall thickness for 3-1/2 inch N-80: 9.30 lb/ft (13.84 kg/m), wall thickness 7.01 mm (0.276 inch), burst rating approximately 50 MPa (7,230 psi) Annual global tubing workover market: estimated at over USD 20 billion per year, reflecting the frequency with which production tubing must be pulled and replaced to restore well integrity or modify the completion design

The portion of a Christmas tree or surface production facility through which production fluids flow. The production wing typically includes a wing valve and a choke to control or isolate flow from the wellbore.

A mathematical means of expressing the ability of a reservoir to deliver fluids to the wellbore. The PI is usually stated as the volume delivered per psi of drawdown at the sandface (bbl/d/psi).

(noun) A well test conducted to measure the flow capacity of a producing well by recording the stabilised flow rate at one or more controlled drawdown pressures. Results are used to calculate the productivity index (PI), determine flow efficiency, and evaluate formation damage or stimulation effectiveness.

To measure the lateral variation of a property, such as gravity or magnetic fields. Probing, in contrast, is the term used to describe the measurement of vertical variations of a property in electromagnetic and other nonseismic geophysical methods.

The process of controlling undesirable water production from a well by conducting treatments to prevent coning or cresting. A range of treatment options is available for profile modification applications, most of which are designed to reduce the permeability of the water-bearing zones to encourage preferential flow from the oil-bearing formation. The injection of polymers, or similar chemicals, that form a rigid gel within the formation matrix is a common treatment.

A procedure that involves sampling gas and liquid at different points across the diameter of pipe to evaluate the degree of stratification at a specific location.

The amount of production, after deducting cost oil production allocated to costs and expenses, that will be divided between the participating parties and the host government under the production sharing contract.

The accumulation of sequences by deposition in which beds are deposited successively basinward because sediment supply exceeds accommodation. Thus, the position of the shoreline migrates into the basin during episodes of progradation, a process called regression.

A type of a sucker rod-pumping unit that uses a rotor and a stator. The rotation of the rods by means of an electric motor at surface causes the fluid contained in a cavity to flow upward. It is also called a rotary positive-displacement unit.

The situation in which 10-second and 10-minute gel strengths for a drilling mud have dissimilar values, with the 10-minute number being much higher than the 10-second number. This indicates that the gelation of the mud is rapidly gaining strength with time, which generally is an undesirable feature of a mud. The mud may require excessive pump pressures to break circulation. If gels appear to be too progressive, a 30-minute gel-strength measurement may be warranted as a third check of progress.

A property of a sinusoidal plane wave equal to twice pi divided by the wavelength. Also known as the wavenumber, the propagation constant is fundamental to the mathematical representation of wavefields. It is the spatial equivalent of angular frequency and expresses the increase in the cycle of the wave (measured in radians) per unit of distance. In nondispersive media, the wavespeed is the ratio of the angular frequency to the propagation constant. The propagation vector has magnitude equal to the propagation constant and points in the direction the wave is traveling.

A measurements-while-drilling log of formation resistivity. The log normally contains at least one attenuation and one phase-shift resistivity reading. In many cases there will be multiple curves of both, the difference being the depth of investigation. For the same nominal depth of investigation, the attenuation resistivity reads deeper than the phase-shift resistivity and is less affected by invasion, but more affected by surrounding beds and apparent dip. The attenuation measurement has a poorer vertical resolution and is less affected by anisotropy. Depths of investigation and vertical resolution of both measurements vary with the average formation resistivity.Although depths of investigation are less than with wireline resistivity logs, the invasion at the time of measurement is usually small and it is possible to derive the resistivity of the undisturbed zone.

A measurement of the formation resistivity made on drillpipe at a frequency in the range of 100 kHz to 10 GHz, most commonly 2 MHz. The basic measurement is accomplished using a transmitter and two receivers. At these frequencies, the response is best explained as the propagation of a wave. Thus, the phase shift and attenuation of the wave between the receivers are measured and transformed to give the phase shift and the attenuation resistivity. In practice, multiple transmitters may be used to obtain different depths of investigation and achieve borehole compensation. The wavelength is such that the borehole has a minor effect, but one for which correction may be needed.

Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

A solvent used with water to break the emulsion of an oil-base or synthetic-base drilling fluid to prepare the sample for chemical titrations to determine lime, calcium or chloride content according to API testing procedures. PNP is an abbreviation for propylene glycol normal propyl ether. It is an environmentally friendlier replacement of a xylene-isopropynol mixture previously used in certain titrations.

A well in which the maximum production rate is fixed by law. These laws were developed by producing states primarily to control the market and avoid periodic price collapses.

The amount of acreage, determined by governmental authority that can be efficiently and economically drained by a well at a particular depth or horizon.

An area of exploration in which hydrocarbons have been predicted to exist in economic quantity. A prospect is commonly an anomaly, such as a geologic structure or a seismic amplitude anomaly, that is recommended by explorationists for drilling a well. Justification for drilling a prospect is made by assembling evidence for an active petroleum system, or reasonable probability of encountering reservoir-quality rock, a trap of sufficient size, adequate sealing rock, and appropriate conditions for generation and migration of hydrocarbons to fill the trap. A single drilling location is also called a prospect, but the term is more properly used in the context of exploration. A group of prospects of a similar nature constitutes a play.

An electrode device with small spacings from which the current flow, and hence the measurement, is focused a short distance into the formation. The proximity log 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 5 to 10 in. [13 to 25 cm] of the pad. This is deeper than the microlaterolog, which ensures that the mudcake has less effect but means that the proximity log is more often affected by the undisturbed zone.

The response of a logging measurement as a function of distance from the tool. The pseudogeometrical factor is normally radial, reflecting the response perpendicular to the tool. It can be a differential factor, which is the contribution to the signal at a particular distance, but is more normally integrated, which is the sum of all signals from the tool to a particular distance.The pseudogeometrical factor developed from the concept of the geometrical factor, and is expressed in the same way. For example, for a radial distance x from the tool, the integrated radial pseudogeometrical factor, Jx, can be written as: Jx = (Ux - Ut) / (Uxo - Ut)where Ut is the log reading of the undisturbed zone (or, alternatively, the reading with no invasion), Uxo is the log reading of the flushed zone (or, alternatively, the reading with infinite invasion), and Ux is the log reading with a step profile invasion to depth x. Unlike the geometrical factor, Jx depends on the values of both Uxo and Ut. Pseudogeometrical factors are a useful way to express the radial response (or vertical response) in typical conditions. The physics of each measurement determines how much Jx varies with Uxo and Ut.Pseudogeometrical factors are often used to express the response of nuclear and resistivity logs, but are not appropriate for acoustic and electromagnetic propagation logs (where the response is too dependent on the contrast in properties), or nuclear magnetic resonance logs (where the response is too localized).

A descriptive term for a fluid with shear-thinning characteristics that does not exhibit thixotropy. Most effective drilling fluids are shear thinning, although most also exhibit some gel-building characteristics. Pseudoplastic rheology, low viscosity at high shear rates and high viscosity at low shear rates, benefits several aspects of drilling-higher drilling rate and improved cuttings lifting. Bingham plastic fluids, power-law fluids and Herschel-Bulkley fluids fall in the psuedoplastic category of rheology.

A plot of real gas pseudopressure (pseudopotential) m(p) versus time function used to analyze gas-well drawdown and buildup tests. The use of the real gas pseudopressure linearizes the diffusion equation for gas flow. This form enables rigorous analysis over all pressure ranges. The pressure-squared plot can be used for low pressure (p ~3000 psi).

The ideal spontaneous potential (SP) that would be observed opposite a shaly, permeablebed if the SP currents were prevented from flowing. In the middle of a thick, permeable bed whose resistivity is not too high, the SP reads close to the pseudostatic spontaneous potential (PSP). In other conditions, however, the SP may be significantly less than the PSP. The PSP ignores other potential sources and assumes that a surrounding shale is a perfect cationic membrane. The ratio of the PSP to the static spontaneous potential is known as the SP reduction factor, alpha. Alpha is less than 1 and is a function of the shaliness, or cation-exchange capacity, within the sand. The higher this cation-exchange capacity, the larger the internal membrane potential. The latter has the opposite polarity to the liquid-junction potential and reduces the SP.The PSP, and alpha, are reduced when hydrocarbons are introduced into shaly sands, because the cation-exchange capacity in the sands is forced into a smaller conductive pore volume and therefore has a larger relative effect.

Behavior observed when a well reaches stabilizedproduction from a limited drainage volume. For constant-rate production, under pseudosteady state, the difference between the flowing wellbore pressure and the average reservoir pressure in the drainage volume is constant, and the pressure drawdown is a linear function of time, resulting in a unit slope in the log-log pressure derivative. The late-time buildup pressure will level off to the average reservoir pressure if the buildup duration is sufficient long, resulting in a sudden drop in the log-log pressure derivative. Pressure depletion occurs with continued pseudosteady-state production.

A phenomenon of relative seismic velocities of strata whereby a shallow layer or feature with a high seismic velocity (e.g., a salt layer or salt dome, or a carbonatereef) surrounded by rock with a lower seismic velocity causes what appears to be a structural high beneath it. After such features are correctly converted from time to depth, the apparent structural high is generally reduced in magnitude.

A slickline or coiled tubing tool used to retrieve temporary devices, such as plugs and flow-control equipment, from the wellbore. Pulling tools are available in a range of sizes and profiles and must be compatible with the equipment to be retrieved. A contingency release system in the pulling tool allows the tool to be released and retrieved if the equipment to be retrieved cannot be released.

A technique in which an ultrasonic transducer, in transmit mode, emits a high-frequencyacoustic pulse towards the borehole wall, where it is reflected back to the same transducer operating in receive mode. The measurement consists of the amplitude of the received signal, the time between emission and reception, and sometimes the full waveform received. Tools that use this technique either have multiple transducers, facing in different directions, or rotate the transducer while making measurements, thereby obtaining a full image of the borehole wall. Pulse-echo techniques are used in the borehole televiewer. In cased hole, the waveform is analyzed to give indications of cement-bond quality and casingcorrosion.

A wireline log of the yields of different elements in the formation, measured using induced gamma ray spectroscopy with a pulsed neutron generator. The elemental yields are derived from two intermediate results: the inelastic and the capture spectrum. The inelastic spectrum is the basis for the carbon-oxygen log, and can also give information on other elements. The capture spectrum depends on many elements, mainly hydrogen, silicon, calcium, iron, sulfur and chlorine. Since the elemental yields give information only on the relative concentration of elements, they are normally given as ratios, such as C/O, Cl/H, Si/(Si + Ca), H/(Si + Ca) and Fe/(Si + Ca). These ratios are indicators of oil, salinity, lithology, porosity and clay, respectively. To get absolute concentrations, it is necessary to calibrate to cores or, more often, use a model such as the oxide-closure model.The depth of investigation of the log is several inches into the formation. It can be run in open or cased hole. Pulsed neutron spectroscopy logs were introduced in the mid 1970s after a decade or more of investigation.

A measurement of the spectrum of gamma rays emitted by a formation bombarded by high-energy neutrons. Neutrons are emitted by a high-energy neutron generator (14.1 MeV). The neutrons interact with different nuclei, which may emit characteristic gamma rays through inelastic neutron scattering, fast-neutron reactions and neutron capture. When pulses from a neutron generator are used, it is possible to separate the different interactions in time after each neutron pulse. Inelastic and fast-neutron interactions occur very soon after the neutron burst, while most of the capture events occur later. The two types can therefore be separated to give a so-called inelastic spectrum and a capture spectrum. The spectra are analyzed either by counting gamma rays in windows placed at the main peaks for the elements concerned, or by comparison with spectral standards, or by combining the two (alpha processing).The resultant logs are known as pulsed neutron spectroscopy logs, the most common of which are the carbon-oxygen log and the elemental capture spectroscopy log.

(noun) A nuclear production logging measurement that uses a pulsed-neutron source to determine the fraction of oil, water, and gas present at each depth in a cased wellbore by exploiting the different hydrogen indices and neutron capture cross-sections of each fluid phase.

The cylinder of the downhole pump.

A condition affecting an operating pump whereby the pump space is not fully charged with fluid being pumped. Pump cavitation may result from inadequate or restricted supply or from the introduction of air or gas into the fluid stream. The effect of cavitation depends on the type of pump. However, in most cases, it is an undesirable condition that causes a reduction in pump efficiency and excessive wear or damage to pump components.

The arrangement of lines and valves used to direct and control fluid on a pumping unit. The manifold on the pump suction is generally known as the inlet or low-pressure manifold. The corresponding manifold located on the pump discharge is commonly known as the high-pressure or discharge manifold. In most cases, reference to the pump manifold relates to the high-pressure manifold.

The difference in hydrostatic head between the pump depth and the dynamic fluid level above the pump. The pump submergence is continuously monitored to adjust the pump flow rate and avoid a pump-off condition.

The relationship between actual pump displacement and the pump displacement under ideal conditions. The relationship can be expressed as percentage. A reduction in pump volumetric efficiency is an indication of an operational problem in the well. In sucker-rod pumps, the gas lock and gas interference phenomena can significantly reduce the volumetric efficiency of the pump.

A phenomenon produced when pump submergence into the fluid column is low. A pump-off situation will increase the gas intake, thus reducing the pump efficiency.

The ability of the slurry to be pumped. Pumpability is usually measured by the API thickening-time test.

A mobile high-pressure pumping unit commonly used for cementing or stimulation operations. Most pump units are configured with a high-pressure triplex pump and one or more centrifugal pumps to precharge the triplex pump and handle displacement fluids.

A document prepared to list the sequence, type and volume of fluids to be pumped during a specific treatment.

The total time required for pumping the cementslurry into the well, plus a safety factor. Pumping time can also be the time required to reach a consistency deemed to be unpumpable (generally 70 Bc) during an API thickening-time test.

A well produced by use of some kind of downhole pump. Pumps are required when the formationpressure is not sufficient to allow flowing production of fluids at the desired or necessary rate. The performance of well tests on pumping wells is always complicated by the presence of the pump, which often must be removed to take downhole pressure measurements. Downhole pressure measurements in pumping wells are usually made by measuring the rise in liquid level in the well. This is often accomplished by sonic devices, like well sounders, that measure the response time of sound waves bounced off the downhole liquid surface. Most oil wells are eventually put on pumps as pressure declines during production. The exceptions are in strong waterdrive reservoirs or in settings where pressure maintenance by gas or water injection is sufficient to maintain a high reservoir pressure.

Testing that is accomplished by measuring pressure in the annulus, or by pulling the pump and running a pressure gauge in the hole. The preferred method is usually to measure the pressure in the annulus if no packer is present. This is best done by monitoring the rise in fluid level with an echo-sounding device and calculating the bottomhole pressure by assuming a fluid density. Several excellent devices and associated services are available. Any time a well is shut in gradually, as is the case for pumping wells, some kind of multirate analysis is usually required to obtain acceptable results.

A phenomenon of relative seismic velocities of strata whereby a shallow layer or feature with a low seismic velocity (e.g., a shalediapir or a gas chimney) surrounded by rock with a higher seismic velocity causes what appears to be a structural low beneath it. After such features are converted from time to depth, the apparent structural low is generally reduced in magnitude. Hydrocarbon indicators can display velocity push-downs because the velocity of hydrocarbon is slower than that of rock.

A type of geochemical analysis in which a rock sample is subject to controlled heating in an inert gas to or past the point of generating hydrocarbons in order to assess its quality as a source rock, the abundance of organic material in it, its thermal maturity, and the quality of hydrocarbons it might generate or have generated. Pyrolysis breaks large hydrocarbon molecules into smaller molecules.This process is used to determine the quality of shale as a source rock and is instrumental in evaluating shale gas plays.

A mineral containing ferrous sulfide, FeS, that typically contains inclusions of free sulfur and other minerals. It is commonly present in shales, and may occur as a trace mineral in some barite ores. Pyrrhotite can liberate sulfides in alkaline muds, with adverse consequences for safety and corrosion.Reference:Binder GG, Carlton LA and Garrett RL: "Evaluating Barite as a Source of Soluble Carbonate and Sulfide Contamination in Drilling Fluids," Journal of Petroleum Technology 33, no. 12 (December 1981): 2371-2376.