Oil and Gas Terms Beginning with “T”

In a nuclear magnetic resonance measurement, the characteristic time for longitudinal relaxation. In rocks, longitudinal relaxation is the inverse sum of the surface relaxation and bulk relaxation. T1 is not normally measured in NMRlogging, but is an important parameter in deciding the polarization time and hence the logging speed. T1 is closely related to the transverse relaxation time, T2. The ratio T1/T2 in water-filled rocks is typically between 1.5 and 2.5. In light hydrocarbons and gas, the ratio increases up to 10 and more as the viscosity decreases.

In nuclear magnetic resonance (NMR) logging, the characteristic time for transverse relaxation. In rocks, there are three components of the transverse relaxation?surface, Ts; bulk, Tb; and diffusion relaxation, Td. T2 is the inverse sum of each component for each fluid, as follows: 1/T2 = 1/Ts + 1/Tb + 1/Td.Because of the reciprocal sum, the smallest of the three types of relaxations is the most important in determining the final T2 for each fluid. There is not one single value of T2 for a rock but a wide distribution of values lying anywhere between fractions of a millisecond and several seconds. The distribution of T2 values is the principal output of an NMR log.

A term describing the application of a cloud pointglycol or polyglycol as a shaleinhibitor. The purported mechanism is that the glycol clouds out at the higher downhole temperatures, coating onto the surface of clays and preventing hydration

Abbreviation for Trans-Alaska Pipeline System

Steps in seismicprocessing to compensate for attenuation, spherical divergence and other effects by adjusting the amplitude of the data. The goal of TAR is to get the data to a state where the reflector amplitudes relate directly to the change in rock properties giving rise to them.

The use of tubing, drillpipe or coiled tubing to convey perforating guns to the required depth. Initially, the technique was developed as a means for conveying the gun string on the production tubing, with the guns remaining in the well until they are removed during the first workover. The subsequent popularity of highly deviated and horizontal wells increased the requirement for tubing-conveyed perforating as the only means of gaining access to the perforating depth. The term is often abbreviated as TCP.

The planned end of the well, measured by the length of pipe required to reach the bottom.

A mode of the electromagnetic field that involves only one component of the electric field and the two components of the magnetic field perpendicular to it; e.g., the x-component of the electric field and y- and z-components of the magnetic field. The TE mode is useful in describing 2D models in which the electric field is perpendicular to the 2D plane of the model. For this case, Maxwell's equations can be reduced to a single scalar equation for the electric field component, which simplifies calculations tremendously. There is an analogous mode for the magnetic field called the TM mode. A general EM field in a region without sources can be expressed as a sum of TE and TM modes.

Abbreviaton for technical evaluation agreement.

A variation of the electromagnetic method in which electric and magnetic fields are induced by transient pulses of electric current in coils or antennas instead of by continuous (sinusoidal) current. In the last two decades,TEM surveys have become the most popular surface EM technique used in exploration for minerals and groundwater and for environmental mapping.

(noun) Abbreviation for Thermally Enhanced Oil Recovery. A category of enhanced oil recovery methods that use heat to reduce crude oil viscosity and improve flow characteristics within the reservoir. TEOR techniques include steam flooding, cyclic steam stimulation (huff and puff), steam-assisted gravity drainage (SAGD), and in-situ combustion.

An abbreviation on drilling reports or mud logs signifying trip for new bit.

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

Abbreviation for toe to heel air injection.

A mode of the electromagnetic field that involves only one component of the magnetic field and the two components of the electric field perpendicular to it; e.g., the x-component of the magnetic field and y- and z-components of the electric field. The TM mode is useful in describing 2D models in which the magnetic field is perpendicular to the 2D plane of the model. For this case, Maxwell's equations can be reduced to a single scalar equation for the magnetic field component, which simplifies calculations tremendously.

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

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

The elapsed time for a seismicwave to travel from its source to a given reflector and return to a receiver at the Earth's surface. Minimum two-way traveltime is that of a normal-incidence wave with zero offset

Referring to the description of different regimes for the simultaneous flow of gas and liquid in vertical pipes introduced by Y. Taitel and A. Dukler in 1980. The results are shown in the form a crossplot or map with the superficial gas velocity, vgs, on the x-axis and the superficial liquid velocity, vls, on the y-axis. Different maps are constructed for different pipe sizes and fluid properties. The Taitel-Dukler map defines the transition between different flow regimes more closely than other models. Taitel and Dukler also described flow transitions in horizontal pipes.Reference:Taitel Y, Barnea D and Dukler AE: Modelling Flow Pattern Transitions for Steady Upward Gas-Liquid Flow in Vertical Tubes, AIChE Journal 26, no. 6 (May 1980): 345-354.

In multiphase flow, large bubbles of the lighter phase that form by coalescence of small bubbles under certain conditions of fluid flow. The large bubbles occur during slug flow and plug flow. The term is named after G.I. Taylor.Reference:Davies RM and Taylor G: The Mechanics of Large Bubbles Rising Through Liquids and Through Liquids in Tubes, Proceedings of the Royal Society of London, Series A. 200 (February 22, 1950): 375-390.

A portable mast that can be erected as a unit, with the upper section nested inside the lower section and raised by wireline or hydraulic system.

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

What Is a Top Drive? Top drive systems are electric or hydraulic motor assemblies mounted at the top of a drilling mast that rotate the drillstring directly, replacing the conventional kelly and rotary table. Installed on rigs from the Norwegian North Sea to the Permian Basin, top drives enable continuous circulation, back-reaming, and multi-stand connections that dramatically reduce flat time and drilling risk on wells worldwide. Key Takeaways A top drive replaces the kelly bushing and rotary table for string rotation, transmitting torque directly to the drillstring via a saver sub threaded onto the quill. Modern AC top drives deliver continuous torque ratings from 20 kN·m to over 100 kN·m (15,000 ft·lbf to 74,000 ft·lbf), with hook loads rated from 250 tonnes (550,000 lb) on land rigs to 1,000 tonnes (2.2 million lb) on ultra-deepwater floaters. Top drives are standard equipment on all offshore drilling rigs and are increasingly mandatory on onshore rigs drilling extended-reach, horizontal, and high-pressure high-temperature wells worldwide. API Specification 8C (Drilling and Production Hoisting Equipment) and ISO 13535 govern load ratings and testing; IADC and API RP 7G cover drillstring compatibility and makeup torque procedures. Integration with iron roughnecks and automated pipe-handling systems reduces personnel exposure to the rotary table and increases connection efficiency to under two minutes per stand. How Top Drive Works A top drive system travels with the travelling block along the mast or derrick rails on a torque track, which prevents the body from rotating while transmitting torque to the drillstring. The motor, whether AC variable-frequency drive (VFD), DC motor, or hydraulic motor, connects through a gearbox to a quill shaft. A saver sub threaded onto the quill mates with the drillstring, transmitting torque in kilonewton-metres. AC VFD systems allow precise control of rotational speed (0 to 300 RPM) and torque, with real-time feedback loops preventing over-torque damage. An internal wash pipe and swivel allow continuous mud circulation whether the string is rotating or stationary, a major advantage over the kelly drive. During drilling, the driller lowers the block and rotates the drillstring continuously until a stand of 28 metres (92 feet) is drilled down. At connection, the roughneck breaks out the saver sub and connects the next stand. The motor remains at low torque so circulation continues through the connection, preventing the stuck-pipe incidents common when both rotation and circulation stop simultaneously. Back-reaming, rotating the string while pulling out of hole, clears tight spots that would trap a static kelly-drive string. Top drives also incorporate upper and lower IBOPs (internal blowout preventers), remotely operable from the driller's console, meeting BSEE and AER requirements for a secondary well control barrier above the BOP stack without floor personnel working near the rotating string. Top Drive Across International Jurisdictions In Canada, AER Directive 036 (Drilling Blowout Prevention Requirements and Procedures) references top drive IBOP functionality as the required secondary well control barrier on critical sour wells. Virtually all rigs drilling horizontal multistage-frack wells in the Montney, Duvernay, and Deep Basin now operate with top drives; older kelly-equipped rigs are limited to shallow coalbed methane programs. In the United States, BSEE mandates remotely operable IBOPs on all floating drilling units in the Gulf of Mexico under 30 CFR Part 250 Subpart D. Onshore, major operators including ExxonMobil, Chevron, and ConocoPhillips require top drives by contract specification for all directional and horizontal wells in Permian Basin and DJ Basin programs. Norway's Petroleum Safety Authority (Ptil) requires top drives on all NCS wells under NORSOK D-010, specifying that upper and lower IBOPs must be independently operable from a remote station and tested weekly at maximum working pressure. Equinor has standardised on AC VFD top drives rated to at least 60 kN·m (44,000 ft·lbf) for standard NCS well programs. Australia's NOPSEMA requires top drives on all offshore rigs in the Carnarvon, Browse, and Bonaparte basins as part of prescribed well integrity standards. Saudi Aramco and ADNOC require top drives on all offshore platforms and most directional onshore rigs, with separate H2S service material requirements for sour fields such as Khursaniyah and Haradh. Fast Facts The NOV Canrig 1075AC top drive installed on Transocean's Deepwater Horizon (Macondo well) was rated to 75,000 ft·lbf (102 kN·m) of continuous torque and a 1,000-tonne (2.2 million lb) hook load, capable of handling the 5-1/2-inch drillstring and 9-7/8-inch casing strings run to depths beyond 5,486 metres (18,000 feet) below the mudline in the ultra-deepwater Gulf of Mexico. Top Drive Types and Technical Specifications Top drives fall into four main drive types: AC electric VFD, DC electric, hydraulic, and (historically) pneumatic. AC VFD systems now dominate new-build rigs because they deliver stepless speed control from 0 to 300 RPM, high starting torque without gear-shock, regenerative braking that feeds energy back into the rig's power system, and quieter operation than DC motors. DC motors remain on many older rigs and are still specified for some land rig applications where VFD capital cost is a constraint. Hydraulic top drives are used on workover rigs, coiled-tubing units, and through-tubing rotary drilling (TTRD) applications where a compact, high-torque, low-speed unit is needed and rig electrical power is limited. Load and torque ratings are the primary specification parameters. Land rig top drives typically carry 250-tonne (550,000 lb) to 500-tonne (1.1 million lb) hook-load ratings and torque outputs of 20 kN·m to 40 kN·m (15,000 to 30,000 ft·lbf). Offshore jackup top drives range from 500 tonne (1.1 million lb) to 750 tonne (1.65 million lb) hook load with torque ratings of 40 to 75 kN·m (30,000 to 55,000 ft·lbf). Deepwater semisubmersible and drillship top drives are rated to 750 tonne to 1,000 tonne (1.65 to 2.2 million lb) hook load with torque capacities of 75 to 122 kN·m (55,000 to 90,000 ft·lbf) for handling heavy drill collars, heavyweight drillpipe, and 20-inch casing strings in deepwater programs. Key suppliers include National Oilwell Varco (NOV), whose Canrig and TDS product lines dominate global markets, Tesco Corporation (now Nabors Industries), and Bentec GmbH for European rigs. NOV's TDS-11SA is a widely deployed AC unit rated to 500 tonnes (1.1 million lb) hook load and 55 kN·m (40,700 ft·lbf), suited for land rigs to 6,000 metres (20,000 feet). The Canrig 1075AC is the benchmark for deepwater floater applications. Top drives used in sour-gas service must be manufactured from NACE MR0175 / ISO 15156-compliant materials to prevent hydrogen embrittlement, with wetted components pressure-tested in H2S concentrations to 30,000 ppm. API Specification 8C defines load ratings, proof-load requirements (200 percent of rated capacity), and inspection classes (S1 and S2). Iron roughneck integration completes the automation picture: the torque wrench engages the saver sub directly for makeup and breakout, enabling a full automated connection sequence within 90 to 120 seconds per stand and reducing struck-by and caught-in hazards that historically generated a disproportionate share of drilling industry fatalities. Tip: When reviewing a top drive inspection report, check the quill thread and saver sub condition together. The quill thread is the highest-value wear interface on the unit: a damaged quill requires a major gearbox teardown, while a worn saver sub is a USD 1,500 to USD 5,000 replacement. Running a saver sub past its service life to save cost is a false economy that routinely causes quill thread damage costing USD 50,000 to USD 200,000 in downtime and repair. Implement a saver sub change-out schedule based on connection count rather than visual inspection alone. Top Drive Synonyms and Related Terminology Top drive is also known as: Top drive system (TDS): full assembly designation used in NOV product nomenclature and API documentation Power swivel: older term, now typically reserved for lower-capacity workover units rather than full drilling top drives TD: common field abbreviation used in daily drilling reports and rig contracts Top drive unit (TDU): alternative abbreviation used by some operators in rig specifications and tender documents Related terms: rotary table, kelly, travelling block, iron roughneck, drillstring, blowout preventer Frequently Asked Questions What is a top drive in oil and gas? A top drive is a motorised assembly mounted at the top of the drilling mast that rotates the drillstring directly from above, replacing the traditional kelly and rotary table system. It travels up and down the derrick with the travelling block and enables continuous rotation, circulation, and back-reaming capabilities that reduce stuck-pipe risk and improve drilling efficiency on directional, horizontal, and deepwater wells globally. How does a top drive work? The top drive motor, typically an AC variable-frequency electric motor, drives a quill shaft that connects to the top of the drillstring via a threaded saver sub. A torque track welded to the mast prevents the unit body from spinning while the quill rotates. An integrated swivel routes drilling mud through the system during rotation. Remotely operable IBOPs above and below the motor provide well control barriers without requiring personnel on the drill floor. What are the advantages of a top drive over a kelly drive? Top drives allow continuous mud circulation and string rotation during connections, reducing the stuck-pipe risk inherent in kelly-drive operations where both stop simultaneously. They enable back-reaming (rotating out of hole) to clear pack-offs, permit drilling longer stands of 27 to 42 metres (90 to 138 feet) instead of single 9-metre (30-foot) joints, integrate with iron roughnecks to automate connections, and provide remotely operable well control IBOPs that keep personnel away from the drill floor during well control events. What standards govern top drives? API Specification 8C (Drilling and Production Hoisting Equipment) sets load rating, proof-load test, and material requirements for top drive hook interfaces and elevator links. ISO 13535 is the equivalent international standard. API RP 7K covers drilling equipment inspection and maintenance procedures, including top drives. NACE MR0175 / ISO 15156 specifies material requirements for H2S service. NORSOK D-010 governs IBOP testing intervals and remote-operation requirements on the Norwegian Continental Shelf. How is a top drive used internationally? Top drives are standard on all offshore rigs operating in the North Sea, Gulf of Mexico, Australian offshore, and Middle East offshore environments, where regulators mandate remotely operable IBOPs. Onshore, they are universal on horizontal shale drilling programs in North America, the MENA region, and Argentina's Vaca Muerta. Saudi Aramco and ADNOC require top drives on most directional land programs. Even in frontier basins with older rig fleets, operators specify top drives in tender documents for complex well programs. Why Top Drive Matters in Oil and Gas The top drive fundamentally changed the economics and safety profile of rotary drilling when it became commercially viable in the early 1980s, and it remains the most consequential mechanical upgrade in the modern drilling rig's history. Continuous rotation and circulation through connections and back-reaming capability during tripping reduced stuck-pipe incidents that had historically caused a significant share of well cost overruns and non-productive time. Directional drilling, particularly the high-angle and extended-reach wells that unlock unconventional reservoirs, is virtually impossible to execute reliably without a top drive to maintain rotation and circulation through the tortuous wellbore trajectory. As operators push measured depths past 9,000 metres (30,000 feet) and HPHT reservoirs demand precise torque management, the top drive's integration with real-time torque-and-drag monitoring and automated connection sequencing positions it at the centre of the industry's shift toward fully automated drilling operations.

A legal document recorded each shift that includes employees' time and records different drilling information required by the oil company and regulatory bodies.

An 800-mile [1287-km], 48-in. [122-cm] pipeline that transports more than 1 million barrels of oil from Deadhorse (near Prudhoe Bay) to Valdez, Alaska, USA. The Trans-Alaska Pipeline System was completed in 1977 and it is often abbreviated as TAPS.

What Is a Travelling Block? The travelling block is the movable pulley assembly in a drilling rig's hoisting system that moves vertically inside the derrick or mast, carrying the hook, swivel, and full weight of the drillstring during tripping operations. Paired with the fixed crown block overhead, the travelling block forms a block-and-tackle system that multiplies the drawworks line pull into the hook load required to handle drill pipe, casing, and tubing strings on wells worldwide. Key Takeaways The travelling block is the lower, movable half of the rig's crown-and-travelling-block hoisting system, converting drawworks drum line pull into vertical hook load through a mechanical advantage created by multiple sheaves. Travelling block load ratings range from 250 tonnes (550,000 lb) on medium land rigs to 1,350 tonnes (2.98 million lb) on ultra-deepwater drillships, with proof-load tests at 200 percent of rated capacity per API Specification 8C. Drillers, rig crews, and drilling engineers on every land rig, jackup, semisubmersible, and drillship worldwide use the travelling block as the primary vertical load-bearing component for all hoisting operations. API Specification 8C (Drilling and Production Hoisting Equipment) and ISO 13535 govern load ratings, proof-load tests, design factors, and material requirements for travelling blocks globally. Block-to-block, the condition where the travelling block reaches the crown block, is one of the most dangerous emergency scenarios on a drilling rig, capable of failing the derrick structure, drawworks, and deadline anchor simultaneously. How Travelling Block Works The block-and-tackle hoisting system on a drilling rig consists of the drawworks (the drum-and-brake mechanism that spools the drilling line), the crown block (a fixed sheave assembly at the top of the derrick), and the travelling block. Drilling line, typically 1-1/8-inch to 1-3/4-inch (28.6 mm to 44.5 mm) steel wire rope, is reeved through alternating sheaves on the crown block and travelling block to create multiple lines of support. The string-up configuration, typically 8, 10, 12, or 14 lines on land rigs and jackups and up to 16 lines on heavy drillships, determines the mechanical advantage: each additional line reduces the fast-line tension the drawworks must generate to lift the total hook load. The fast line connects the drawworks drum to the first crown block sheave. The dead line runs from the last crown block sheave to a deadline anchor on the rig substructure, where a tension transducer measures dead-line load continuously. The weight indicator system multiplies dead-line tension by the number of lines strung to display total hook load, which the driller uses to manage weight on bit. A typical 1,000-tonne (2.2 million lb) class block and hook assembly weighs 20 to 30 tonnes (44,000 to 66,000 lb), a tare that must be subtracted from indicated hook load to determine actual bit weight. API Specification 8C requires sheave grooves to match the nominal drilling line diameter to within a tolerance band; a groove worn more than 1.6 mm (1/16 inch) below nominal radius must be re-machined or the sheave replaced, as undersized grooves concentrate wire rope contact stress and accelerate rope fatigue. Travelling Block Across International Jurisdictions In Canada, AER Directive 036 references API 8C compliance for all rig hoisting equipment on critical sour wells. The CAODC Drilling Rig Inspection Program mandates travelling block inspection as a checklist item, covering sheave condition, axle wear, latch function, and deformation. In the United States, BSEE mandates API 8C compliance for all hoisting equipment on federal offshore facilities under 30 CFR Part 250 Subpart D, verifying that blocks are rated to the maximum anticipated hook load and that the block-to-block crown saver is functional. Onshore, state agencies including the Texas Railroad Commission and COGCC enforce equipment standards through rig inspection programs tied to drilling permits. Norway's Petroleum Safety Authority (Ptil) enforces NORSOK D-010 and NORSOK R-003 (Safe Use of Lifting Equipment), requiring annual third-party inspection of all lifting appliances by a notified body. Saudi Aramco General Instruction GI-0002.100 specifies API 8C as the baseline standard with additional periodic load-cell testing requirements. Australia's NOPSEMA accepts API 8C for all offshore facilities; operators must include block inspection records in their facility safety case. ADNOC applies its Code of Practice for Well Operations referencing API RP 8B inspection intervals. ISO 13535, the international equivalent of API 8C, is accepted by regulators across the European Union, South America, and Southeast Asia. Fast Facts The Transocean Deepwater Titan, one of the world's largest ultra-deepwater drillships, operates with a 1,350-tonne (2.98 million lb) rated travelling block system using a 16-line string-up configuration, enabling it to run 20-inch (508 mm) casing strings and 2.5-million-lb hook loads required for ultra-deep wells in water depths beyond 3,650 metres (12,000 feet) in the Gulf of Mexico. Travelling Block Types and Technical Specifications Travelling blocks are classified by rated hook load and sheave count. Configurations range from 4-sheave blocks on light workover rigs rated to 125 tonnes (275,000 lb) to 8-sheave and 10-sheave blocks on ultra-deepwater drillships rated to 1,350 tonnes (2.98 million lb). A 6-sheave travelling block paired with a 7-sheave crown block supports 14 lines strung, yielding a 14:1 mechanical advantage. API Specification 8C defines two load classes: standard service (S1) and premium service (S2), with S2 carrying higher design factors and more rigorous inspection requirements. Proof load testing requires loading to 200 percent of rated capacity without permanent deformation, with sheave pins and axles sustaining the proof load in bending and shear without yielding. Drilling line tonne-mile fatigue is tracked per API RP 9B (Application, Care and Use of Wire Rope for Oil Field Service). When accumulated tonne-miles reach the retirement limit, the line must be slipped and cut to retire the most fatigued section near the deadline anchor. Improper slip-and-cut management is a leading cause of wire rope failures during heavy block loads. Manufacturers include NOV (TDS and PHD block series), Bentec GmbH for European rigs, and Nabors Industries. Block inspection per API RP 8B defines six levels (T-1 through T-6) from daily visual checks to full NDT disassembly with magnetic particle and liquid penetrant testing of all load-bearing components. Tip: Block-to-block prevention requires both an active crown-saver device and an independently set travel limit on the drawworks brake. Many serious derrick failures have occurred when only one protection layer was present and that layer failed. Verify on every rig inspection that the crown saver setpoint is calibrated against the actual physical block clearance, not copied from a previous well, since mast section changes or block swaps can alter the safe upper-travel limit without anyone updating the setpoint. The two-barrier approach should be documented in the rig's HSE management system and verified at each rig move. Travelling Block Synonyms and Related Terminology Travelling block is also known as: Traveling block: American spelling variant used in API standards and US regulatory documents TB: field abbreviation used in daily drilling reports and rig inspection checklists Block and hook assembly: collective term for the travelling block, hook body, and safety latch used in rig weight-in-air calculations Lower block: informal term distinguishing it from the fixed crown block at the top of the derrick Related terms: crown block, drawworks, top drive, drilling line, hook load, derrick Frequently Asked Questions What is a travelling block in oil and gas? A travelling block is the movable pulley assembly in a drilling rig's hoisting system that travels vertically inside the derrick, connected to the crown block via multiple lines of drilling wire rope. It carries the hook, swivel or top drive, and the full weight of the drillstring during tripping operations. Together with the crown block and drawworks, it forms the block-and-tackle system that gives the rig its ability to lift drillstrings and casing strings weighing hundreds to thousands of tonnes. How does a travelling block work? The drawworks drum winds and unwinds the drilling line, pulling or releasing the fast line that is reeved through alternating sheaves on the crown block and the travelling block. Each pair of sheaves creates an additional line of support, multiplying the drawworks line pull by the number of lines strung. The dead-line tension, measured at the deadline anchor, is used with the string-up count to calculate total hook load on the weight indicator. Bearing-mounted sheaves in the travelling block rotate freely as the drilling line moves, minimising friction losses. What are the advantages of a multi-sheave travelling block? Adding sheaves to the travelling block increases the string-up (lines strung) and raises the mechanical advantage of the hoisting system, allowing the drawworks to lift heavier loads with the same drum line tension. A 12-line string on a well requiring 900-tonne (2 million lb) hook load requires only 75 tonnes (165,000 lb) of line tension at the drawworks, well within the capacity of standard rig wire rope. Higher sheave counts distribute wire rope fatigue across more rope segments, extending rope life on high-cycle deepwater tripping operations. What standards govern travelling blocks? API Specification 8C (Drilling and Production Hoisting Equipment) is the primary standard, setting rated load, proof-load test (200 percent of rated capacity), sheave groove tolerances, and design factors. ISO 13535 is the international equivalent. API RP 8B (Inspection, Maintenance, Repair and Remanufacture of Hoisting Equipment) defines six-level inspection intervals for travelling blocks from daily visual checks to full NDT disassembly. API RP 9B governs drilling line slip-and-cut intervals and tonne-mile retirement criteria directly linked to travelling block operation. How is the travelling block used internationally? Travelling blocks certified to API 8C or ISO 13535 are used on drilling rigs in every oil-producing country. Norwegian NCS operators must have blocks third-party inspected annually under NORSOK R-003. BSEE mandates API 8C compliance for all federal offshore US operations. Saudi Aramco, ADNOC, Petrobras, and Shell all specify API 8C as the baseline standard in their rig contractor qualification requirements. In frontier regions, older rig fleets may use blocks to legacy national standards, though API 8C is increasingly required by international operators as a condition of their drilling contracts. Why Travelling Block Matters in Oil and Gas The travelling block is not a component that draws attention when it is functioning correctly, but it is the load-bearing heart of every drilling operation: without a serviceable, properly rated block, no drillstring can be tripped, no casing string run, and no well completed. Its load rating sets the ceiling for the entire well program, determining the maximum casing weights and drillstring configurations the rig can safely handle. Block-to-block accidents, where an inadvertently raised travelling block contacts the crown block at full drawworks speed, have destroyed derricks, snapped drilling lines, killed personnel, and put rigs out of service for months, making the block-to-block prevention system one of the most safety-critical interlocks on any rig. As wells grow deeper and heavier, the travelling block's rated capacity has grown accordingly, from the 250-tonne (550,000 lb) units common on 1970s land rigs to the 1,350-tonne (2.98 million lb) assemblies on today's ultra-deepwater drillships. Proper maintenance, rigorous API RP 8B inspection compliance, and accurate tonne-mile tracking for the drilling line that runs through the block's sheaves remain foundational to safe, efficient drilling operations across every producing basin in the world.

Any kind of pipe used in oilfield operations including tubing, casing, drill pipe, drill collars, and heavy-weight drill pipe.

A winching machine that hoists or pulls when a cable winds around a revolving drum. Also called a winch.

To contact, or tag, a known reference point or obstruction in the wellbore with the tubing string, wireline or other intervention equipment.

The last page or pages on a log print, which may contain data about the well, the recording parameters and the calibration of the measurements.

A floating device used in marineseismic acquisition to identify the end of a streamer. Tail buoys allow the seismic acquisition crew to monitor the location and direction of streamers. They are commonly brightly colored, reflect radar signals, and are fitted with Global Positioning System (GPS) receivers.

The last cement system pumped during primary cementing. The tail cement covers the lower sections of the well, especially planned completion intervals, and is typically more dense than the lead slurry that precedes it.

A cutoff in time, offset or both that has the effect of eliminating some types of noise from seismic data. A tail mute can be used to exclude slow surface waves such as ground roll.

The tubulars and completion components run below a production packer. The tail pipe may be included in a completion design for several reasons. It can provide a facility for plugs and other temporary flow-control devices, improve downhole hydraulic characteristics, and provide a suspension point for downhole gauges and monitoring equipment.

A list containing details of tubulars that have been prepared for running, or that have been retrieved from the wellbore. Each tubing joint is numbered and the corresponding length and other pertinent details noted alongside.

(noun) A graphical method used in directional drilling to plot the wellbore trajectory by assuming a straight-line path between successive survey stations at the inclination and azimuth measured at the lower station. While simple, the tangential method can accumulate positional errors in wells with rapidly changing direction.

A metal or plastic vessel used to store or measure a liquid. The three types of tanks in an oil field are drilling, production and storage tanks.

A group of tanks that are connected to receive crude oilproduction from a well or a producing lease. A tankbattery is also called a battery.In the tank battery, the oil volume is measured and tested before pumping the oil into the pipeline system.

The settlings -- sediment, dirt, oil emulsified with water and free water -- that accumulate in the bottom of storage tanks. The tank bottoms are periodically cleaned up and settlings can be disposed of or treated by chemicals to recover additional hydrocarbons. Tank bottoms are also called tank settlings or tank sludge.

(noun) The process of determining the relationship between liquid level and contained volume in a storage tank through physical measurement (strapping), optical methods, or liquid calibration techniques. Tank calibration tables are essential for accurate custody transfer and inventory management of crude oil and petroleum products.

A structure constructed around an oil tank to contain the oil in case the tank collapses. The volume or space inside the tank dike should be greater than the volume of the tank. A tank dike is also called a fire wall.

A table that shows the tank capacity in barrels as a function of the liquid level inside the tank. A tank table is also called a tank capacity table or gauge table.

The capacity of all the tanks in a field

A ship designed to transport crude oil, liquefied petroleum gas (LPG), liquefied natural gas (LNG), synthetic natural gas (SNG) or refined products. Tankers with 100,000 deadweight tons of capacity or more are called supertankers (very large crude carriers or ultralarge crude carriers). A tanker is also called a tank ship.

The acids found in tannin. Quebracho contains tannic acid.

Chemical extracted from the bark of trees and used as clay deflocculant in water muds. Tannins are moderate molecular weight, anionic polymers with complex structures. Quebracho is a tannin.

A fishing tool used to engage on the internal diameter of a hollow fish, such as drillpipe or drill collar. By rotating the taper tap when it is in contact with the fish, a threaded profile is cut, enabling the taper tap to securely engage the fish before retrieval.

In a nuclear magnetic resonance measurement, the use of a gradual rather than a sharp cutoff to distinguish between bound water and free water. A sharp cutoff at, for example T2 = 33 ms in sandstones, is normally used to distinguish free water (all T2s above 33 ms) from bound water (all T2s below 33ms). In a water-filled rock, in the fast diffusion limit, T2 is directly related to pore size. The distinction between bound and free water is based on the assumption that all free water resides in large pores, and all bound water in small pores. However, in rocks with large pores, a significant volume of bound water exists on the surface of the grains around a large pore. Being part of a large pore, it gives a long T2 and will be incorrectly counted as free water. One solution is the tapered cutoff, in which the bound water is the sum of all the T2 below a minimum, for example 5 ms, and is then a progressively smaller fraction of the volume at T2s up to a maximum, for example 500 ms. All signal above 500 ms represents free water. The form of the taper is usually empirical, but is based on some model of pore shape, such as a bundle of tubes.See Kleinberg RL and Boyd A: 'Tapered Cutoffs for Magnetic Resonance Bound Water Volume' paper SPE 38737, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 5-8, 1997.

A tubing string or work string that is made up from tubulars of different outside diameters (OD). In production applications, this may be used to improve the flow and production characteristics of a well. In drilling applications, a tapered string may be used to enable a small hole section to be drilled without changing the entire string. In coiled tubing operations, tapered strings are configured with a constant OD but with varying wall thickness.

A sand body that contains heavy hydrocarbon residues such as tar or asphalt, or degraded oil that has lost its volatile components. Hydrocarbons can be liberated from tar sands by heating and other processes, but tar sands, such as the Athabasca tar sands of Canada, are not commonly commercial because of high costs of production.Among some workers in the field of heavy oil, this term is falling out of use, in favor of the term "oil sand."

An agreement between a host country and operator to allow the operator to evaluate geological, geophysical, engineering and transportation issues involving a concession. Also known as a TEA.

Location relative to the boundary of a tectonic plate, particularly a boundary along which plate tectonic activity is occurring or has occurred.

(noun) The large-scale deformation of the Earth's crust driven by plate tectonic forces, including folding, faulting, uplift, and subsidence. Tectonism creates the structural traps, migration pathways, and basin geometries that control the distribution and accumulation of hydrocarbons.

A system for converting the measurements recorded by a wireline or measurements-while-drilling (MWD) tool into a suitable form for transmission to the surface. In the case of wireline logging, the measurements are converted into electronic pulses or analog signals that are sent up the cable. In the case of MWD, they are usually converted into an amplitude or frequency-modulated pattern of mud pulses. Some MWD tools use wirelines run inside the drillpipe. Others use wireless telemetry, in which signals are sent as electromagnetic waves through the Earth. Wireless telemetry is also used downhole to send signals from one part of an MWD tool to another.

A device used to indicate the position or function of mechanical components that cannot be easily observed, such as to indicate the launch of a cementing plug or dart.

A low-frequency electrical current that occurs naturally over large areas at or near the surface of the Earth. Telluric currents are induced by changes in Earth's magnetic field which are usually caused by interactions between the solar wind and the ionosphere (part of the upper atmosphere).

An electromagnetic method in which naturally occurring, low-frequency electric currents (telluric currents), are measured at a base station and compared with values measured at other stations. The normalized measurements of telluric current provide information about the direction of current flow and the conductance (conductivity times thickness) of sediments in the surveyed area. Extremely low-frequency telluric currents (with periods of days or months) provide information about conductivity in the deep interior of the Earth.

A record of the temperature gradient in a well. The temperature log is interpreted by looking for anomalies, or departures, from the reference gradient. This reference might be the geothermal gradient, a log recorded before production started or a log recorded with the well shut-in. Most anomalies are related to the entry of fluids into the borehole or fluid exit into the formation. Since the temperature is affected by material outside the casing, a temperature log is sensitive to not only the borehole but also the formation and the casing-formation annulus.Temperature logs have many applications, with the most common being to identify zones producing or taking fluid, to evaluate a cement or hydraulic fracture treatment, and to locate lost circulation zones and casing leaks. Since temperature takes time to dissipate, a temperature log tends to reflect the behavior of a well over a longer time period than other measurements.

The characteristic of a drilling fluid or a mud product pertaining to its response to prolonged heating, usually in a controlled mud composition in a rolling- or static-aging test.

A temperature data set taken at various depths in the wellbore. Temperature surveys are used to determine the top of cement behind the casing, fluid contacts and water influx. It is also useful to check for valve and casing leaks after the well has been temporarily shut down.

The force per unit cross-sectional area required to pull a substance apart.

A type of packer that is set by applying tension to the running string. These packers are less common than compression-set packers due to the potential difficulties associated with retrieval. However, in applications where there is insufficient string weight to set a compression packer, a tension packer is a useful option.

A mathematical entity with components that change in a particular way in a transformation from one coordinate system to another. Tensor methods are used in "upscaling" reservoir parameters for use in reservoir simulation studies.

An oil and gas lease that expires after a specified period of time, regardless of whether oil, gas and/or other minerals are being produced.

A graphical representation of concentrations in a system with three components. Since the sum of the component percentages is unity, any composition can be uniquely mapped to a single point within a triangular space. In many cases, a mixture of fluids with more than three components is divided into three pseudocomponents, such as light, intermediate and heavy components of a hydrocarbon phase. These diagrams are used to illustrate the phase behavior of a fluid.

The positive gravity correction that accounts for the deviation of the topography from the horizontal slab of infinite extent assumed in the Bouguer correction. Local topographic features always decrease the gravity measurement because the attractive force of the topography above the station is away from the Earth, and the effect of topography below the station is negative because of the absence of attractive material.

Pertaining to sediments or depositional environments on land or above the level of high tide.

Traditionally, the third stage of hydrocarbonproduction, comprising recovery methods that follow waterflooding or pressure maintenance. The principal tertiary recovery techniques used are thermal methods, gas injection and chemical flooding. The term is sometimes used as a synonym for enhanced oil recovery (EOR), but because EOR methods today may be applied at any stage of reservoirdevelopment, the term tertiary recovery is less commonly used than in the past.

A vessel used to separate and meter relatively small quantities of oil and gas. Test separators can be two-phase or three-phase, or horizontal, vertical or spherical. They can also be permanent or portable.Test separators sometimes are equipped with different meters to determine oil, water and gas rates, which are important to diagnose well problems, evaluate production performance of individual wells and manage reserves properly.Test separators can also be called well testers or a well checkers.

Pertaining to analysis based on equations or formulae derived from a theoretical basis in science. The majority of equations used in reservoir characterization and reservoir engineering are empirical, but many have been derived from scientific theory.

A parameter used to characterize thermal neutron interactions in bulk material. Thermal diffusion length (Ld) is the characteristic distance between the point at which a neutron becomes thermal and the point of its final capture. It is related to the quantity of thermal absorbers in the formation, and therefore is an important factor in the thermal neutron porosity measurement. Thermal neutrons have about the same energy as the surrounding matter, typically less than 0.4 eV (0.025 eV at room temperature).

The rate of increase in temperature per unit depth in the Earth. Although the thermal gradient varies from place to place, it averages 25 to 30 oC/km [15 oF/1000 ft].

The degree of heating of a source rock in the process of transforming kerogen into hydrocarbon. Thermal maturity is commonly evaluated by measuring vitrinite reflectance or by pyrolysis.

An element, or mineral, that is particularly effective in absorbing thermal neutrons (neutrons with about the same energy as the surrounding matter, typically less than 0.4 eV). The elements gadolinium, boron, chlorine, hydrogen and iron are thermal absorbers (in decreasing order of effectiveness). The effect of chlorine is used in a pulsed neutron capture log to distinguish salty water from hydrocarbons. In a thermal neutron porosity measurement, the effect of hydrogen is important, while boron and iron affect the response in shales.

A measurement of the slowing down and capture of neutrons between a source and one or more thermal neutron detectors. The neutron source emits high-energy neutrons that are slowed mainly by elastic scattering to near thermal levels. Thermal neutrons have about the same energy as the surrounding matter, typically less than 0.4 eV. The slowing-down process is dominated by hydrogen. At thermal levels, the neutrons diffuse through the material until they undergo thermal capture. Capture is dominated by chlorine, hydrogen and other thermal neutron absorbers.Typical thermal neutron measurements use a chemical neutron source and two thermal neutron detectors. An accelerator source (neutron generator) is sometimes used. Some, mainly earlier, devices measure the gamma rays emitted by thermal capture, rather than thermal neutrons.

A general term for injection processes that introduce heat into a reservoir. Thermal recovery is used to produce viscous, thick oils with API gravities less than 20. These oils cannot flow unless they are heated and their viscosity is reduced enough to allow flow toward producing wells.During thermal recovery, crude oil undergoes physical and chemical changes because of the effects of the heat supplied. Physical properties such as viscosity, specific gravity and interfacial tension are altered. The chemical changes involve different reactions such as cracking, which is the destruction of carbon-carbon bonds to generate lower molecular weight compounds, and dehydrogenation, which is the rupture of carbon-hydrogen bonds.Thermal recovery is a major branch of enhanced oil recovery processes and can be subdivided in two types: hot fluid injection such as steam injection (steamflood or cyclic steam injection) and hot waterflooding and in-situ combustion processes.

The finite-difference or finite-element reservoir simulation that includes energy equations and calculations used to describe heat conduction, heat and fluid convection, and latent heat exchanges occurring in the reservoir rock and fluids during a thermal recovery process such as steamflooding, steam assisted gravity drainage, or in-situ combustion. Combustion thermal simulation also requires equations for modeling combustion reaction kinetics.

A term describing the application of a cloud point glycol or polyglycol as a shaleinhibitor. The purported mechanism is that the glycol clouds out at the higher downhole temperatures, coating onto the surface of clays and preventing hydration.

A measurement of the time during which a cementslurry remains in a fluid state and is capable of being pumped. Thickening time is assessed under simulated downhole conditions using a consistometer that plots the consistency of a slurry over time at the anticipated temperature and pressure conditions. The end of the thickening time is considered to be 50 or 70 Bc for most applications.

A device that can be lowered into a tank to obtain samples (liquid or sediments) at different depths. The samples are analyzed to determine the gravity and BS&W content of the fluid into the tank.

An opening in the top of the stock tank. The thiefhatch allows tank access for a thief or other level measuring devices.

A formation encountered during drilling into which circulating fluids can be lost.

Pertaining to the ability of a fluid, such as cement or drilling mud, to develop gel strength over time when not subject to shearing, and then to liquefy when agitated.

The characteristic of a fluid, such as a drilling mud, to form a gelled structure over time when not subject to shearing and then to liquefy when agitated. The viscosity of a thixotropic fluid changes with time under constant shear rate until reaching equilibrium. Most drilling muds exhibit thixotropy, which is necessary for fast drilling, efficient cuttings lifting and to support weighting material when mud flow stops. Gel strength measured at various time intervals indicates the relative thixotropy of a mud.Thixotropy is sometimes desirable to provide resistance to flowing, such as to avoid or reduce losses or flow into a weak formation.

An element with an atomic number of 90. The 232Th isotope is radioactive and decays with a half-life of 1.4 * 1010 years through a series of intermediate isotopes to a stable isotope of lead. The intermediate isotopes emit a wide range of gamma rays, the most prominent being that of thallium, 208Tl. It is assumed that formations are in secular equilibrium; that is, the relative proportions of parent and daughter isotopes remain constant, and the measured spectrum is directly related to the amount of 232Th. The concentration in the Earth's crust is about 12 parts per million, ppm, by weight.Thorium-bearing minerals are rare. Thorium is a trace element associated with clays and heavy minerals. It is very immobile so that quantity measured today probably was present at the time of deposition. A log of thorium is presented in parts per million. It is often a good measure of clay content.

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

A protective sleeve or cap generally made up on the threads of tubular goods during transport and storage. Thread protectors are available in metal, plastic, or a combination of both.

A pocket-size thread gauge used in field operations to correctly identify or confirm the thread type and size of tubular goods.

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

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

A set of numerous closely-spaced seismic lines that provide a high spatially sampled measure of subsurface reflectivity. Typical receiver line spacing can range from 300 m [1000 ft] to over 600 m [2000 ft], and typical distances between shotpoints and receiver groups is 25 m [82 ft] (offshore and internationally) and 110 ft or 220 ft [34 to 67 m] (onshore USA, using values that are even factors of the 5280 feet in a mile). Bin sizes are commonly 25 m, 110 ft or 220 ft. The resultant data set can be "cut" in any direction but still display a well sampled seismic section. The original seismic lines are called in-lines. Lines displayed perpendicular to in-lines are called crosslines. In a properly migrated 3D seismic data set, events are placed in their proper vertical and horizontal positions, providing more accurate subsurface maps than can be constructed on the basis of more widely spaced 2D seismic lines, between which significant interpolation might be necessary. In particular, 3D seismic data provide detailed information about fault distribution and subsurface structures. Computer-based interpretation and display of 3D seismic data allow for more thorough analysis than 2D seismic data.

The acquisition of seismic data as closely spaced receiver and shot lines such that there typically are no significant gaps in the subsurface coverage. A 2D survey commonly contains numerous widely spaced lines acquired orthogonally to the strike of geological structures and a minimum of lines acquired parallel to geological structures to allow line-to-line correlation of the seismic data and interpretation and mapping of structures.

The simultaneous flow of oil, free gas and water into a wellbore. Stratified flow is the rule rather than the exception.

A vessel that separates the well fluids into gas and two types of liquids: oil and water. A three-phaseseparator can be horizontal, vertical or spherical. This type of separator is commonly called a free-water knockout separator because its main use is to remove any free water that can cause problems such as corrosion and formation of hydrates or tight emulsions, which are difficult to break.The liquids (oil, water) leave the vessel at the bottom through different valves, and the gas leaves the vessel at the top, passing through a mist extractor to remove the small liquid droplets in the gas.

In a spinner flowmeter, the theoretical minimum fluid velocity required to initiate spinner rotation, assuming the spinner response is linear. The actual fluid velocity required to start spinner rotation is slightly higher because of additional viscous and mechanical effects. The threshold velocity is determined by extrapolating the spinner response at higher fluid velocities, where it is known to be nearly linear, back to the value that exists when spinner rotation is zero.

Pertaining to treatments performed on subsea wells where the fluids and associated pump-down equipment, such as plugs or darts, are pumped through the flowline normally used for production fluids.

Pertaining to a range of products, services and techniques designed to be run through, or conducted within, the production tubing of an oil or gas well. The term implies an ability to operate within restricted-diameter tubulars and is often associated with live-well intervention since the tubing is in place.

A perforating gun assembly designed to run through the restricted clearance of production tubing, then operate effectively within the larger diameter of the casing or liner below. A range of small-diameter guns has been developed for this purpose, although small-diameter casing guns also may be used when larger production tubing sizes permit.

A type of reverse fault in which the fault plane has a very shallow dip, typically much less than 45o. The hanging wall fault block moves up the fault surface relative to the footwall. In cases of considerable lateral movement, the fault is described as an overthrust fault. Thrust faults can occur in areas of compression of the Earth's crust.

In logging while drilling, a mark associated with each measurement indicating when a sample was taken. It is usually presented as a short bar in the depth track. Widely spaced tick marks indicate a low sampling rate. In wireline logging, a tick mark indicates the cumulative volume of some quantity, such as hole volume or traveltime. The term is sometimes spelled tic mark.

To correlate data in order to formulate or verify an interpretation or to demonstrate the relationship between data sets. Long, regional-scale 2D seismic lines are commonly tied to 3D surveys that cover a limited area, and 3D surveys of different vintages are tied to each other. Well logs are tied into seismic data routinely to determine the relationship between lithologic boundaries in the logs and seismic reflections. Properly tying all available data, including seismic data, well logs, check-shot surveys, synthetic seismograms and vertical seismic profiles, can reduce or, if there are sufficient data, eliminate ambiguity in interpretations.

In a ternary diagram, a graphical representation of two fluids being mixed. The ends of the tie line indicate the compositional concentrations of the two mixed fluids. The composition of the mixture lies on the line, with its position dependent on the concentration ratio of the two end-point fluids.

A section of liner that is run from a liner hanger back to the wellhead after the initial liner and hanger system have been installed and cemented. A tie-back liner may be required to provide the necessary pressure capacity during a flow-test period or for special treatments, and is typically not cemented in place. In some cases, a tie-back liner will be installed as a remedial treatment when the integrity of the intermediate casing string is in doubt.

A specially designed packer assembly used in conjunction with a tie-back liner. The tie-back packer can be integral to the original liner hanger, or if the tie-back is a remedial treatment, it can be a separate component set above the liner hanger.

(noun) A section of casing or liner run from the top of a previously hung liner back up to the wellhead, creating a continuous casing string from surface to the liner setting depth. Tie-back strings are used to provide additional casing integrity, isolate problematic zones, or convert a liner completion to a full casing string.

Secrecy or confidentiality of information. Operators typically try to prevent disclosure of results from exploration wells and will hold any such information "tight". A tight hole is a well whose status and data are not widely disseminated by the operator.

An emulsion with small and closely distributed droplets. A tight emulsion can be difficult to break.

Gas produced from a relatively impermeablereservoirrock. Hydrocarbonproduction from tight reservoirs can be difficult without stimulation operations. Stimulation of tight formations can result in increased production from formations that previously might have been abandoned or been produced uneconomically. The term is generally used for reservoirs other than shales.

A well that the operator requires be kept as secret as possible, especially the geologic information. Exploration wells, especially rank wildcats, are often designated as tight. Unfortunately, this designation is of questionable benefit in keeping the data secret.

The time that has elapsed between the bit first penetrating a formation and a log being recorded opposite it. In logging while drilling, this time is different for each log, since it depends on the drilling rate and the distance between the bit and the particular logging sensor.

The use of a function of time rather than frequency to express an independent variable or measurement. In contrast, in the frequency domain, variables are expressed as a function of frequency instead of time.

A migration technique for processing seismic data in areas where lateral velocity changes are not too severe, but structures are complex. Time migration has the effect of moving dipping events on a surface seismic line from apparent locations to their true locations in time. The resulting image is shown in terms of traveltime rather than depth, and must then be converted to depth with an accurate velocity model to be compared to well logs.

A horizontal display or map view of 3D seismic data having a certain arrival time, as opposed to a horizon slice that shows a particular reflection. A time slice is a quick, convenient way to evaluate changes in amplitude of seismic data.

Pertaining to techniques in which the same quantity is measured at different times in the life of a reservoir. Normally the only change in a time-lapse measurement or survey will be due to changes in water or gas saturation. Thus, a comparison of two logs run at different times, such as a year apart, should simply reflect the change in fluid saturations in the pore space. The most common time-lapse logs are made with pulsed neutron capture, pulsed neutron spectroscopy and boreholegravity measurements.

Seismic data from the surface or a borehole acquired at different times over the same area to assess changes in the subsurface with time, such as fluid movement or effects of secondary recovery. The data are examined for changes in attributes related to expressions of fluid content. Time-lapse seismic data can repeat 2D, 3D (which is known as 4D seismic data), crosswell and VSP data.

A technique for determining the velocity of fluid flow in an injection well based on measuring the time a slug of radioactive tracer takes to move down the well. The analysis is usually performed as part of a tracer-loss measurement. The depth of the slug is measured by running repeated gamma ray logs at well-defined time intervals. From the differences in depth and time, the velocity can be determined.

In chemical analysis, a procedure to determine the amount of a constituent in a sample by adding a measured volume of reagent until the reaction between the constituent of interest and the reagent is completed, as shown by an appropriate endpoint indicator. For mud and mud filtrate analyses, titration is a common procedure for determining alkalinity, chloride, total hardness, methylene blue capacity and formaldehyde.

An in-situ combustion method for producing heavy oil. In this technique, the fireflooding starts from a vertical well, while the oil is produced from a horizontal well having its toe in close proximity to the vertical air-injection well. This production method is a modification of conventional fire flooding techniques in which the flame front from a vertical well pushes the oil to be produced from another vertical well.

A technique to measure and display the three-dimensional distribution of velocity or reflectivity of a volume of the Earth by using numerous sources and receivers. There are several types of tomography used by geophysicists, including transmission tomography (which uses measurements between boreholes, surface-to-surface, or between a borehole and the surface), reflection or seismic tomography (based on standard reflection seismology), and diffraction tomography (using Fermat's principle for computations instead of Snell's law). Variations in velocity can be attributed to changes in density and elastic properties of rocks, which in turn are affected by the increasing temperature with depth in the Earth. Tomographic techniques have been used to construct maps of the Earth's interior, deep in the mantle, as well as for mapping the shallow subsurface by borehole tomography.

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

The enlarged and threaded ends of joints of drillpipe. These components are fabricated separately from the pipe body and welded onto the pipe at a manufacturing facility. The tool joints provide high-strength, high-pressure threaded connections that are sufficiently robust to survive the rigors of drilling and numerous cycles of tightening and loosening at threads. Tool joints are usually made of steel that has been heat treated to a higher strength than the steel of the tube body. The large-diameter section of the tool joints provides a low stress area where pipe tongs are used to grip the pipe. Hence, relatively small cuts caused by the pipe tongs do not significantly impair the strength or life of the joint of drillpipe.

(noun) An assembly of multiple downhole tools connected end-to-end and run into the wellbore on wireline, coiled tubing, or drillpipe to perform a specific operation such as production logging, perforating, or fishing. The configuration and sequence of tools in the string are designed to accomplish the objectives of the intervention.

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

An oil and gas lease wherein the bonus consideration is paid at the signing of the lease. However, this lease becomes effective only after the expiration or termination of an existing lease on the tract of land.

The top of the interval recorded on the log, or the shallowest point at which the log readings are valid. If the top of the log is at the casing shoe, the last valid reading of many logs will be a short distance below. However, it is common to give the depth of the casing shoe as the top log interval.

What Is a Top Drive? A top drive suspends from the traveling block and rotates the drill string from the top of the stand using an electrically or hydraulically powered motor, eliminating the need for a kelly and rotary table as the primary rotation source, enabling continuous rotation while tripping, back-reaming capability, and single-stand connections that reduce drilling time on complex wells by 15-30 percent compared to conventional kelly systems. Key Takeaways The top drive replaces the kelly as the drill string rotation device by driving the string from a motor assembly suspended from the traveling block rather than from a rotary table mechanism at the rig floor. AC electric top drives typically produce 25-100 kNm (18,440-73,760 ft-lbs) of continuous torque; hydraulic top drives on smaller rigs produce 10-40 kNm (7,376-29,504 ft-lbs). Maximum RPM ranges from 300 to 500 RPM on most models. Top drives are standard equipment specified by drilling engineers and operators, maintained by drilling contractors, and their performance metrics are tracked by company representatives, investors, and supply chain analysts evaluating rig capability ratings. Governing standards include API Specification 7K (design and load ratings), NORSOK D-001 (North Sea), and BSEE 30 CFR Part 250 (US Gulf of Mexico); the Norwegian PSA requires documented IBOP testing before each well spud. Top drives reduce connection time, enable back-reaming through problem zones, and improve well control capability by allowing the internal blowout preventer (IBOP) valve to be closed without stopping drill string rotation. How the Top Drive Works The top drive assembly hangs from the traveling block through a load cell that continuously measures the hook load. The drive motor, either an AC squirrel-cage induction motor fed by a variable frequency drive (VFD) or a hydraulic motor fed by a high-pressure pump, connects to the drill string through a quill shaft and torque sub. The VFD on AC top drives provides continuously variable speed from zero to maximum RPM without mechanical shifting, allowing the driller to adjust rotation at the precise rate needed for the formation and BHA being used. Modern AC top drives offer torque output curves that are nearly flat from low RPM to rated speed, providing full torque at the slow speeds used during sliding or when reaming through tight spots. The pipe handler is a critical subassembly of the top drive that grips the tool joint of the uppermost drill pipe stand using powerful tongs, allowing the top drive to spin up (make up) or spin out (break out) connections without the rig tong crew needing to manually apply back-up tongs. This mechanizes the connection process that was previously done by hand with manual and power tongs on kelly rigs, reducing connection time from 5-8 minutes per joint to 2-4 minutes per stand. Because a stand is typically three joints, this means the top drive makes connections at one-third the frequency of a kelly system on the same well. On a 5,000 m (16,404 ft) well, reducing connections from 525 to 175 saves approximately 30-60 minutes of rig time per trip, a significant cost saving at USD 20,000-100,000 per day rig rates. The IBOP (internal blowout preventer) is a full-opening ball valve integrated into the top drive's quill connection or installed as a sub immediately below the quill. The IBOP can be closed remotely from the driller's console without stopping drill string rotation, providing a critical barrier against flowing formation fluids entering the drill string during a well control event. API RP 53 requires that the IBOP be pressure-tested to its rated working pressure, typically 15,000 PSI (1,034 bar) on deepwater rigs, before each well and function-tested weekly during drilling. This requirement applies equally in Canada under AER Directive 059, in the US under BSEE 30 CFR Part 250, and in Norway under NORSOK D-010. Top Drive Across International Jurisdictions In offshore Canada, every drill ship and semisubmersible operating off the east coast under C-NLOPB (Canada-Newfoundland and Labrador Offshore Petroleum Board) jurisdiction carries AC top drives as standard equipment. The Hebron and Terra Nova platform wells offshore Newfoundland use top drives rated at 65-100 kNm (47,944-73,760 ft-lbs) for the extended-reach wells required to drain their respective reservoirs from fixed platform structures. West Texas Intermediate production from deepwater Atlantic Canada depends entirely on top drives enabling the complex well geometries required to reach reservoir targets kilometers away from the platform footprint. In the US deepwater Gulf of Mexico, all major drilling contractors including Transocean, Valaris, and Diamond Offshore equip their drillships with top drives rated for 15,000 PSI (1,034 bar) working pressure. BSEE's drilling regulations require documented top drive load testing and IBOP pressure testing in the well file before the permit to spud is issued. The Perdido Spar operated by Shell in water depths of 2,438 m (7,999 ft) used top drives capable of handling drill string loads exceeding 1,000 tonnes (2,205,000 lb) to drill the extended-reach producers needed to drain the Silvertip and Tobago reservoirs. On Norway's Johan Sverdrup field, the world's third-largest offshore oil field by recoverable resources at approximately 2.7 billion barrels of oil equivalent, Equinor operates an integrated drilling campaign using jackup and semisubmersible rigs all equipped with top drives from SLB (formerly Schlumberger), Canrig Drilling Technology, and NOV (National Oilwell Varco). NORSOK D-001 mandates that top drive torque sensors, load cells, and IBOP actuation systems be function-tested and calibrated before each well spud. The PSA's audit of top drive maintenance records is part of the consent-to-drill process. ADNOC Drilling in Abu Dhabi operates one of the largest drilling fleets in the Middle East, with top drives on all rigs rated above 2,000 hp (1,491 kW). ADNOC's offshore fields in the Arabian Gulf use top drives from NOV and Varco to drill the extended-reach horizontal wells needed to drain shallow carbonate reservoirs with minimal platform footprint. Saudi Aramco's high-spec rigs at the Shaybah and Khurais fields use top drives from multiple manufacturers specified to API 7K standards and tested to Saudi Aramco Drilling Engineering requirements before mobilization. Fast Facts Varco International (now part of NOV) introduced the first commercially successful top drive system in the North Sea in 1982 for Shell's drilling program, and within a decade the technology spread to virtually every offshore rig in the world; today NOV alone has delivered more than 3,000 top drive systems globally, fundamentally transforming how complex directional and extended-reach wells are drilled. Top Drive Technical Design and Performance AC top drives use induction motors with VFD control for speed regulation. A standard offshore top drive might use a 1,000 kW (1,341 hp) motor producing peak torque of 80 kNm (59,008 ft-lbs) at low speed with a maximum speed of 350 RPM. Continuous torque rating (the torque sustainable for hours without overheating) is typically 60-70 percent of peak rating, so a 80 kNm peak unit offers approximately 48-56 kNm (35,405-41,302 ft-lbs) continuous torque. Thermal management is critical: top drives on extended horizontal wells in low-angle modes run at high torque for hours, and adequate cooling determines sustained performance. Hydraulic top drives use high-pressure hydraulic oil from the rig's hydraulic power unit (HPU) to drive piston or vane motors. Maximum torque of 40 kNm (29,504 ft-lbs) is achievable, but hydraulic systems have higher parasitic losses than AC systems and require more maintenance due to hose wear and seal leakage. Hydraulic top drives remain common on smaller workover rigs and coiled tubing units where their compact footprint outweighs their efficiency disadvantage. The torque and drag monitoring system integrated with modern top drives measures rotating torque at the motor, traveling block hook load, and standpipe pressure simultaneously. Automated torque limits protect the drill string from twist-off: if reactive torque at the motor exceeds a set threshold, the VFD reduces motor current to prevent exceeding the minimum yield torque of the weakest joint in the string. This protection is especially important in horizontal wells where the combined weight-on-bit and string friction torques can approach 80-90 percent of tool joint torsional capacity in extended laterals exceeding 3,000 m (9,843 ft). Top drive guide rails are mounted inside the derrick to constrain the top drive assembly's lateral movement as it travels up and down the mast. Without guide rails, the top drive would swing freely under the traveling block, making pipe handling unsafe. Rail alignment is critical: a misaligned rail section causes the top drive to bind as it travels, requiring rig-down inspection of the guide system. Modern top drives use rolling contact rail followers rather than sliding shoes to reduce friction and maintenance frequency. Tip: When evaluating a drilling contractor's rig spec sheet, note whether the top drive is rated for the full hook load capacity of the block system or only a subset. Some older top drives have load path limitations (typically through the link tilt or pipe handler assembly) that restrict casing running operations to 70-80 percent of maximum hook load, which can create constraints on running heavy casing strings in deep wells. Investors comparing drilling contractor fleets should specifically check top drive hook load ratings against the planned casing program requirements for their target wells. Top Drive Synonyms and Related Terminology TDS: Top Drive System, the formal designation used in rig contracts and API documentation, emphasizing that the unit includes motor, pipe handler, IBOP, and control systems as an integrated system. Power swivel: An older, less powerful predecessor to the modern top drive; provides rotation and fluid circulation like a top drive but without the pipe handler and IBOP systems. Still used on workover rigs. Motorized swivel: Another term for a power swivel or early top drive, used in some international and legacy rig specifications. IBOP: Internal blowout preventer, the safety valve integrated into or immediately below the top drive quill; critical well control equipment referenced in every top drive specification. Related terms: kelly, rotary table, BHA, blowout preventer, horizontal drilling, drill collar Frequently Asked Questions What is a top drive in drilling? A top drive is a motor-powered device that suspends from the traveling block and directly rotates the drill string from the top of the stand, eliminating the need for a kelly and rotary table as the primary rotation source. It consists of an AC or hydraulic motor, a pipe handler for mechanical connection make-up and break-out, and an internal blowout preventer (IBOP) valve for well control. Top drives are standard equipment on all modern offshore rigs and high-spec land rigs, enabling continuous rotation while tripping, back-reaming, and faster connections than kelly systems. What are the main advantages of a top drive over a kelly? Top drives offer four primary advantages: first, they enable stand-length (27-28 m / 90 ft) connections instead of single-joint connections, reducing connection frequency by two-thirds and saving significant rig time; second, they allow back-reaming through tight spots or packoff zones while pulling out of hole, which is impossible with a kelly; third, the IBOP valve provides immediate well control closure without stopping rotation; fourth, continuous rotation while running in hole reduces the risk of differential sticking in permeable formations. These advantages are most valuable on complex, long horizontal wells. How does the IBOP on a top drive work? The IBOP (internal blowout preventer) is a ball valve built into the top drive quill connection or installed as a dedicated sub immediately below it. It can be opened or closed remotely from the driller's console using hydraulic actuation. In normal operation it stays open, allowing drilling fluid to circulate through the drill string. If a kick occurs and formation fluids threaten to flow up through the drill string, the driller closes the IBOP to shut in the string bore, containing pressure inside the drill string while the well control team activates the BOP stack rams. API RP 53 requires IBOP pressure testing to working pressure rating before each well.

A contour map that displays the elevation of the Earth's surface. A topographic map is commonly used as the base map for surface geological mapping.

A plot representing the effect of invasion on resistivity measurements that have different depths of investigation. The plot assumes a step-profilemodel of invasion and determines true resistivity, flushed zone resistivity and diameter of invasion from ratios of deep-, medium- and shallow-resistivity measurements. Strictly speaking, when both resistive invasion and conductive invasion are plotted, the chart is called a butterfly chart. When only one is plotted, it is known as a tornado chart.

The connection between the wirelineloggingcable and the bridle. The torpedo consists of an outer mechanical connection enclosing electrical connections between the conductors.

A device for measuring in situ the velocity of fluid flow in a production or injection well based on the torque, or force, produced by the fluid on a stationary impeller. This torque can be related to the effective velocity of flow across the impeller. The torque flowmeter is sometimes used as an alternative to the spinner flowmeter.

The bottom of a particular hole section, where drilling is stopped, logs are run and casing is cemented before starting the next, smaller diameter hole section.

A chemical analysis to measure the hardness ions in water-mud filtrates or in make-up water. Hardness is quantitatively determined by titration using standardized EDTA (versenate) reagent and ammonium hydroxide (weak) buffer, typically according to procedures of API. Results are reported as calcium ion in mg/L. The hardness ion Ca+2 can be analyzed alone by another EDTA titration method described by the API.

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

The total pore volume per unit volume of rock. It is measured in volume/volume, percent or porosity units.The total porosity is the total void space and as such includes isolated pores and the space occupied by clay-bound water. It is the porosity measured by core analysis techniques that involve disaggregating the sample. It is also the porosity measured by many log measurements, including density, neutron porosity and nuclear magnetic resonance logs.

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

The presentation on hard copy of log data from a single measurement versus depth. The term originated with the early optical recorders in which log data were recorded on film using an optical trace. Now the term curve is more common.

A technique in which a tracer is injected into the flow stream of a production or injection well to determine fluid paths and velocities. Radioactive tracers have been used from the 1940s and are still common for determining flow profiles in injection wells. Tracers with high neutron-capture cross section, such as borax or high-salinity water, were introduced in the 1970s to record injection/pulsed neutron logs. In multiphase production wells, special tracers were introduced in the 1990s to move with only one phase, so as to give a phase-velocity log. Radioactive tracers with different energies are used to track the development of fractures, or other processes, in the multiple-isotope log.Tracer measurements are used qualitatively to determine the movement of fluids behind pipe, or quantitatively to determine fluid-flow velocity within the pipe.

(noun) A production logging technique in which a radioactive or chemical tracer is ejected from a tool into the wellbore fluid stream and detected by sensors positioned above or below the ejection point to determine the velocity, direction, and distribution of fluid flow across producing or injecting intervals.

A method of determining injection-flow profiles by monitoring the reduction in tracer material as it moves down the well. A slug of radioactive tracer is added to the injection fluid. As the slug moves down the well, several gamma ray logs are recorded at well-defined time intervals. The position of the slug is seen as a large gamma ray peak whose size is proportional to the flow rate. A reduction in the size of the peak indicates a loss of fluid into the formation. Fluid velocity can be calculated from the time interval and the distance the peak has moved using timed-slug analysis. Tracer-loss measurements produce a type of radioactive-tracer log, used mainly to give a general idea of fluid flow in low flow-rate wells.In very low flow-rate wells, an alternative technique has been used in which the gamma ray detector is held stationary at some depth until the slug has passed. The detector is then moved down to another depth to observe the slug again. With these data, it is possible to make quantitative estimates of fluid flow.

A vertical section of a log presentation over which one particular set of data is displayed. The track divides the presentation into different sections, each with a certain set of log curves or other data, such as depth numbers. The section is vertical in the sense that it is along the depth or time axis of the log. The curves are usually blanked off when they run outside their allotted track. Tracks are typically numbered from left to right across the page (when viewed with depth or time increasing towards the bottom of the page).

A particular type of strike-slip fault that is a boundary of an oceanic tectonic plate. The actual movement of a transform fault is opposite to its apparent displacement because of the interplay of spreading and faulting between tectonic plates.

The migration of shoreline out of a basin and onto land during retrogradation. A transgression can result in sediments characteristic of shallow water being overlain by deeper water sediments.

A marine flooding surface separating the underlying lowstand systems tract from the overlying transgressivesystems tract. Typically, this is the first major flooding surface following the lowstand systems tract.

(noun) The radial distance from a wellbore to which a pressure disturbance has propagated during a well test before reaching a reservoir boundary or achieving pseudo-steady-state conditions. The transient drainage radius increases with time as the pressure pulse moves outward through the formation.

A variation of the electromagnetic method in which electric and magnetic fields are induced by transient pulses of electric current in coils or antennas instead of by continuous (sinusoidal) current. In the last two decades,TEM surveys have become the most popular surface EM technique used in exploration for minerals and groundwater and for environmental mapping.

The change in pressure with time. In well testing, this refers to the pressure measured as a function of time after the test is initiated.

The pressure response resulting from changes in a well's production rate. This includes drawdown, in which the pressure falls in response to the production of fluids; buildups, in which the pressure rises after a well is shut in; and falloffs, in which the pressure falls after an injection well is shut in.

The pressure measurements recorded as a function of time, usually in the wellbore near the productive interval, after the flow rate of the well is changed. These form the basis for transient well-test analysis, and are primarily used for determining reservoir-rock properties and producing-formation limits.

The analysis of transient rate and pressure data taken while a well is flowing at variable rates. The analysis uses either deconvolution or convolution to correct for the flow-rate variations and can make drawdown data interpretable. It has also been applied to correct for afterflow during the buildup.

The duration of time for a P-wave to travel one foot, typically displayed on an acoustic log. The unit of microseconds per foot (or meter) is called the slowness, which is the inverse of velocity.

A multiphase-fluid flow regime characterized by a chaotic mixture of liquid and gas, with neither phase appearing to be continuous. Also known as churn flow, transition flow is an intermediate flow condition between slug flow and mist flow.

With reference to invasion, the volume between the flushed zone and the undisturbed zone in which the mudfiltrate has only partially displaced the moveable formation fluids. One common model of invasion assumes a smooth transition in resistivity and other formation properties from the flushed to the undisturbed zone. Based on this assumption, the inner and outer diameters of invasion can be determined from array resistivity logs. Another common invasion model, which does not assume a smooth transition, is the annulus.

A technique used in crosswell seismic and electromagnetic tomography for recording the direct signal from the source or transmitter in one well to the receiverarray in another well. This technique is used for mapping the distribution of acoustic velocity and attenuation or electromagnetic resistivity between wells.

The simultaneous occurrence of strike-slip faulting and compression, or convergence, of the Earth's crust. In areas of transpression, rocks can be faulted upward to form a positive flower structure. Areas of strike-slip faulting in rifting or diverging crust are experiencing transtension, in which rocks can drop down to form a negative flower structure.

The simultaneous occurrence of strike-slip faulting and extension, rifting, or divergence of the Earth's crust. In areas of transtension, rocks can be faulted downward to form a negative flower structure. Areas of strike-slip faulting in converging crust are experiencing transpression, in which rocks can be faulted upwards to form a positive flower structure.

A mode of the electromagnetic field that involves only one component of the electric field and the two components of the magnetic field perpendicular to it; e.g., the x-component of the electric field and y- and z-components of the magnetic field. The TE mode is useful in describing 2D models in which the electric field is perpendicular to the 2D plane of the model. For this case, Maxwell's equations can be reduced to a single scalar equation for the electric field component, which simplifies calculations tremendously. There is an analogous mode for the magnetic field called the TM mode. A general EM field in a region without sources can be expressed as a sum of TE and TM modes.

A mode of the electromagnetic field that involves only one component of the magnetic field and the two components of the electric field perpendicular to it; e.g., the x-component of the magnetic field and y- and z-components of the electric field. The TM mode is useful in describing 2D models in which the magnetic field is perpendicular to the 2D plane of the model. For this case, Maxwell's equations can be reduced to a single scalar equation for the magnetic field component, which simplifies calculations tremendously.

The loss of coherent energy by protons in a rock while precessing about a static magnetic field during a nuclear magnetic resonance measurement. The loss of coherent energy, or relaxation, due to the free induction decay is corrected by the CPMG pulse sequence. This leaves three mechanisms for relaxation: surface relaxation, bulk relaxation and diffusion relaxation, all of which depend on formation properties. Transverse relaxation is characterized by an exponential decay of time constant T2.

A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate. Traps are described as structural traps (in deformed strata such as folds and faults) or stratigraphic traps (in areas where rock types change, such as unconformities, pinch-outs and reefs). A trap is an essential component of a petroleum system.

Oil in pore spaces that cannot be moved because of capillary forces. Typical trapped or residual oilsaturation is in the range of 10% to 50% of the pore space, and it is higher in tighter formations where the pore spaces are small. The amount of trapped oil is a function of the displacement method and conditions, making this oil a target for enhanced oil recovery (EOR) processes. EOR methods introduce fluids that reduce viscosity, interfacial tension or mobility ratio, and thus improve flow and sweep efficiency to release the residual oil.

(noun) A section of tubing with a polished bore receptacle or seal assembly that permits relative axial movement between the tubing string and a downhole packer, accommodating thermal expansion, contraction, and pressure-induced length changes in the completion string during production or injection operations.

The set of sheaves that move up and down in the derrick. The wire rope threaded through them is threaded (or "reeved") back to the stationary crown blocks located on the top of the derrick. This pulley system gives great mechanical advantage to the action of the wire rope drilling line, enabling heavy loads (drillstring, casing and liners) to be lifted out of or lowered into the wellbore.

In a subsurface sucker-rod pump, the valve that closes the barrel chamber allowing the trapped fluid to be lifted in the upstroke of the pump. This valve is similar in configuration to the standing valve.

The slip set on a snubbing unit that is located at the top of the jack assembly. Two sets of travelling slips are available, one set for heavy-pipe conditions and another for light-pipe conditions.

The travelling slip set on a snubbing unit that is used when operating under light-pipe conditions. Under these conditions, the wellheadpressure is sufficient to eject the tubing string from the wellbore. Therefore, the slips are oriented in a hold-down position to act against the upward force applied to the tubing string.

The duration of the passage of a signal from the source through the Earth and back to the receiver. A time seismic section typically shows the two-way traveltime of the wave.

A vessel used to treat oil-water emulsions so the oil can be accepted by the pipeline or transport. A treater can use several mechanisms. These include heat, gravity segregation, chemical additives and electric current to break emulsions.There are vertical and horizontal treaters. The main difference between them is the residence time, which is shorter in the vertical configuration compared with the horizontal one.A treater can be called a heater treater or an emulsion treater.

The temporary surface piping, valves and manifolds necessary to deliver a fluid treatment to the wellbore from the mixing and pumping equipment.

A fluid designed and prepared to resolve a specific wellbore or reservoir condition. Treatment fluids are typically prepared at the wellsite for a wide range of purposes, such as stimulation, isolation or control of reservoir gas or water. Every treatment fluid is intended for specific conditions and should be prepared and used as directed to ensure reliable and predictable performance.

Used synonymously with the term play to describe an area in which hydrocarbons occur, such as the Wilcox trend of the Gulf Coast.

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

A positive-displacementreciprocating pump that is configured with three plungers. Triplex pumps are the most common configuration of pump used in both drilling and well service operations. Pumps used in well service activities generally are capable of handling a wide range of fluid types, including corrosive fluids, abrasive fluids and slurries containing relatively large particulates.

The act of pulling the drillstring out of the hole or replacing it in the hole. A pipe trip is usually done because the bit has dulled or has otherwise ceased to drill efficiently and must be replaced.

The minimum (negative) deflection of the seismic wavelet. Seismic interpreters commonly pick or track seismic data on paper sections along the trough of a wavelet rather than the solid-colored peak. With the advent of workstations, this is no longer necessary because of automatic picking techniques and the ability to reverse the polarity of the data in real time.

With reference to core analysis, the resistivity of a sample only partially filled with water. Called Rt, it is used in contrast to the resistivity of a sample completely filled with water, Ro. The water may be replaced by any nonconductive fluid, usually air or dead oil.

The thickness of a bed or rock body after correcting for the dip of the bed or body and the deviation of the well that penetrates it. The values of true stratigraphic thickness in an area can be plotted and contours drawn to create an isopach map.

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

The thickness of a bed or rock body measured vertically at a point. The values of true vertical thickness in an area can be plotted and contours drawn to create an isochore map.

Steps in seismic processing to compensate for attenuation, spherical divergence and other effects by adjusting the amplitude of the data. The goal of TAR is to get the data to a state where the reflector amplitudes relate directly to the change in rock properties giving rise to them.

An interface wave that occurs in cased wellbores when a Rayleigh wave encounters a wellbore and perturbs the fluid in the wellbore. The tube wave travels down the wellbore along the interface between the fluid in the wellbore and the wall of the wellbore. A tube wave suffers little energy loss and typically retains a very high amplitude which interferes with reflected arrivals occurring later in time on vertical seismic profile (VSP) data. Because the tube wave is coupled to the formation through which it is traveling, it can perturb the formation across open fractures intersecting the borehole. This squeezing effect can generate secondary tube waves which travel both up and down from the fracture location. Such events can be diagnostic of the presence of open fractures and their amplitude related qualitatively to the length and width, e.g., volume of the fluid-filled fracture space. This effect is generally seen only in shallow formations where the overburdenpressure is lower.

A downhole tool used to repair damaged or collapsed tubing. The tubing broach incorporates a cutter profile that is forced inside the tubing by jarring or hydraulic force to re-form the tubing wall by removing tubing wall material and forcing the tubing wall into place.

A type of batch-treating technique used in corrosion control in which a batch of corrosion inhibitor is displaced through the tubing to the bottom of the well. The well is shut in for 2 to 15 hr and then put back on production.The tubing-displacement technique, also called a kiss squeeze, is used mainly in wells with packers and in gas-lift wells. The treatment could last from a week to several months depending on the specific corrosion inhibitor used.

A downhole tool frequently used in slickline or coiled tubing tool assemblies to confirm or correlate the tool position on depth-sensitive applications. With the end of the production tubing as a known reference point, any error in measurement that may occur in reaching the treatment depth will be significantly less than what may have resulted if measuring from surface.

A system of classifying the material specifications for steel alloys used in the manufacture of tubing.

What Is a Tubing Hanger? A tubing hanger suspends the entire production tubing string from the tubing head spool inside the wellhead, bearing the full mechanical load of the tubing while simultaneously providing a pressure-tight annular seal between the tubing and the surrounding wellhead bore. Precision-machined from alloy steel, the hanger locates in a machined seat within the tubing head and incorporates a central flow bore through which produced fluids travel to surface. Key Takeaways A tubing hanger performs two simultaneous functions: it bears the full tensile load of the production tubing string (which can range from 50,000 lb / 22,680 kg in shallow wells to over 500,000 lb / 226,796 kg in deep, heavy-wall completions) and it provides a gas-tight annular seal that isolates the tubing-casing annulus from the wellhead bore above. Three principal hanger designs are used in the field: the mandrel hanger (smooth machined OD, seats on a machined shoulder in the tubing head), the slip hanger (cone-and-slip segments that grip the tubing OD mechanically without requiring a threaded shoulder), and the polished bore receptacle integral hanger (used in thermal completions such as SAGD where axial expansion must be accommodated). API 6A / ISO 10423 governs tubing hanger design, material, pressure rating, and test requirements; hangers must match the wellhead's rated working pressure, which runs from 5,000 PSI (345 bar) for shallow conventional gas wells to 15,000 PSI (1,034 bar) for HPHT applications. Metal-to-metal (MXM) annular seals are the preferred configuration for sour-service (H2S-containing) wells and all offshore and HPHT applications; elastomeric pack-off seals are acceptable for lower-pressure, non-sour land wells where temperature excursions remain modest. In directional-flow wellheads, tubing hangers incorporate an orientation pin that aligns chemical-injection and hydraulic-control-line penetrations in the hanger body with matching ports in the christmas tree above, enabling stab-in connections during tree installation. How a Tubing Hanger Works The tubing hanger is the last component made up on the bottom of the tubing head adapter (THA) or tubing head spool assembly before the production string is landed. During completion operations, the tubing string is run in the hole as individual joints or stands and is assembled according to the designed completion program. When the production packer has been set at the intended depth and the tubing has been tensioned or slackened off to the design load, the top of the string is made up into the hanger mandrel or slips. The hanger assembly is then lowered on the running tool until it contacts and locks into the machined profile or bowl in the tubing head. Once landed, a pack-off or metal-to-metal seal assembly is energized either mechanically (by rotating or setting down weight) or hydraulically to create the annular seal. This seal isolates the A-annulus (tubing-casing annulus) from the wellbore below and from the wellhead-Christmas-tree connection above. The seal must withstand full wellhead working pressure from below (shut-in tubing pressure) and, in gas-lift completions, injection pressure from above. API 6A requires a minimum of two independent seals on offshore and HPHT hangers, typically designated as primary and secondary, with the secondary acting as a backup if the primary degrades over the well's producing life. Load ratings are calculated using Lame's equation for thick-walled cylinders, accounting for the tubing string weight in fluid (buoyed weight), thermal elongation due to produced-fluid temperature, and packer-induced compression or tension. For a 3.5-inch (88.9 mm) tubing string run to 15,000 ft (4,572 m) in a deep gas well, the combined mechanical and pressure-induced load on the hanger can exceed 300,000 lb (136,078 kg). The hanger body, running threads, and load-bearing shoulder are all designed to a minimum safety factor of 1.25 against yield under the maximum combined loading per API 6A Annex F. Tubing Hanger Across International Jurisdictions While the fundamental mechanics of the tubing hanger are universal, each major oil-producing jurisdiction overlays its own regulatory requirements on materials, testing, documentation, and sour-service certification. Canada (Alberta): Alberta Energy Regulator (AER) Directive 036 (Drilling Blind Zones) and Directive 059 (Well Completion Requirements) specify wellhead component ratings for the Montney, Duvernay, and Deep Basin HPHT plays. Sour wells with partial H2S pressures above 0.34 kPa (0.05 psi) must use tubing hangers in NACE MR0175 / ISO 15156 compliant material grades, typically EE or FF designation per API 6A Annex F. The AER requires a documented wellhead-assembly pressure test before placing a well on production, and tubing hanger records must be retained for the life of the well and submitted as part of the completion report. In the Peace River oil sands, tubing hangers used on cyclic steam stimulation (CSS) wells must be rated for temperatures up to 340 degrees C (644 degrees F) and must accommodate the large axial displacement caused by repeated thermal cycles. United States: Offshore wells on the Outer Continental Shelf are governed by the Bureau of Safety and Environmental Enforcement (BSEE) under 30 CFR Part 250. Subpart E (Oil and Gas Well-Completion Operations) requires that all wellhead components, including tubing hangers, comply with API Specification 6A. For deepwater wells in the Gulf of Mexico, the tubing hanger is typically a subsea component run inside the subsea christmas tree or tubing head spool, and BSEE requires documented traceability for all pressure-containing parts. Onshore wells in Texas, New Mexico, and Wyoming fall under Railroad Commission of Texas (RRC), New Mexico Oil Conservation Division (NMOCD), and Wyoming Oil and Gas Conservation Commission (WOGCC) regulations respectively; all reference API 6A for wellhead equipment. Australia: The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates offshore completions in the Browse, Carnarvon, and Gippsland basins. Well operators are required to submit a Well Operations Management Plan (WOMP) that includes tubing hanger specifications, pressure rating, seal type, and material certification. NOPSEMA guidance notes reference API 6A and ISO 10423 and require that hanger selection be justified in the completion engineering basis. The high-CO2 wells in the Carnarvon Basin (some above 70% CO2) drive selection of exotic corrosion-resistant alloys (CRA) such as 825 or 625 for hanger bodies, with special attention to crevice corrosion at seal interfaces. Norway / North Sea: NORSOK Standard D-010 (Well Integrity in Drilling and Well Operations) defines the tubing hanger as a well barrier element (WBE) in the primary well barrier for producing wells. Norwegian Continental Shelf (NCS) operators must verify that the tubing hanger provides a tested, documented seal before the well barrier schematic (WBS) can be signed off. Equinor, Aker BP, and TotalEnergies Norway typically require dual MXM seals on all NCS completions regardless of pressure class, and annual well barrier verification testing is mandatory under the Petroleum Safety Authority Norway (PSA) facility regulations. Middle East: Saudi Aramco Engineering Standard SAES-D-008 (Wellhead Equipment) mandates that all wellheads on Ghawar, Safaniya, and Khurais fields use tubing hangers with dual metal-to-metal seals regardless of H2S content, citing the high formation pressures and long well-life targets of 30 to 50 years. Abu Dhabi National Oil Company (ADNOC) references API 6A and additionally imposes internal qualification testing at the company's technical standards committee level. Kuwait Oil Company (KOC) Engineering Standards reference API 6A and require third-party inspection and material traceability certificates for all wellhead components including tubing hangers. Fast Facts Typical tubing hanger bore size: 1.995 inches to 4.0 inches (50.7 mm to 101.6 mm) depending on tubing OD (1.900-inch to 3.500-inch OD tubing is most common) Maximum load bearing: Standard API 6A mandrel hangers are rated from 200,000 lb (90,718 kg) to 1,000,000 lb (453,592 kg) in the heaviest-duty designs for deep, large-bore wells Pressure classes: API 6A designates 2,000 / 3,000 / 5,000 / 10,000 / 15,000 / 20,000 PSI working pressure classes (138 / 207 / 345 / 690 / 1,034 / 1,379 bar) Temperature classes: API 6A K (to -60 degrees F / -51 degrees C), L (-50 degrees F / -46 degrees C), P (-20 degrees F / -29 degrees C), R (60 degrees F / 16 degrees C), S (140 degrees F / 60 degrees C), T (180 degrees F / 82 degrees C), U (250 degrees F / 121 degrees C), V (350 degrees F / 177 degrees C) Lead time for specialty hangers: HPHT or CRA-alloy tubing hangers typically carry 12 to 20 week manufacturing lead times from specialty shops such as Cameron (SLB), Baker Hughes, and Dril-Quip

A wellhead component that supports the tubing hanger and provides a means of attaching the Christmas tree to the wellhead.

The process of removing and replacing the production tubing in an oil or gas well. The term is commonly used when conducting a major workover of a well.

A single length of the pipe that is assembled to provide a conduit through which the oil or gas will be produced from a wellbore. Tubing joints are generally around 30 ft [9 m] long with a thread connection on each end. The specification of the tubing material, geometry of the tubing, and design of the connection thread are selected to suit the reservoir fluid and wellbore conditions.

A mathematical tool used in production engineering to assess the performance of the completion string by plotting the surface production rate against the flowing bottomhole pressure. The fluid composition and behavior of the fluid phases in the specific completion design will determine the shape of the curve. The TPC is used with the inflow performance relationship to predict the performance of a specific well.

Pressure on the tubing in a well, as measured at the wellhead.

A special perforating gun, or charge, that is designed for limited penetration to allow an inner tubing or casing string to be perforated without damaging a surrounding outer string. These guns often are used in remedial or workover operations in which downhole communication devices, such as sliding sleeves, cannot be opened to allow circulation of well-kill fluids.

(noun) A seal unit consisting of elastomeric or metal-to-metal packing elements that is landed in a packer bore or polished bore receptacle to create a pressure-tight seal between the tubing string and the packer, isolating different zones or preventing annular communication in a completed well.

A downhole tool used to plug the bottom of a production tubing string when pressure testing the assembled string. Slickline-deployed tools and plugs are most commonly used in vertical or slightly deviated wellbores.

The threaded connection used to assemble the tubing string from individual tubing joints. Various tubing thread types have evolved to suit the wellbore conditions and functions required of the tubing string, both during installation and while the well is in production.

The use of tubing, drillpipe or coiled tubing to convey perforating guns to the required depth. Initially, the technique was developed as a means for conveying the gun string on the production tubing, with the guns remaining in the well until they are removed during the first workover. The subsequent popularity of highly deviated and horizontal wells increased the requirement for tubing-conveyed perforating as the only means of gaining access to the perforating depth. The term is often abbreviated as TCP.

A downhole tool used on slickline or coiled tubing operations to identify the end of the production tubing, or similar well features. This information is used to correlate the position of the tool string for accurate placement of depth-critical treatments, plugs or downhole equipment.

A type of subsurface safety valve that is run and retrieved as part of the production tubing string. The TRSV body is integral part of the completion that enables the internal components to be configured to provide near fullbore access through the valve. An external control line is secured to the running string for connection to a surface-control system.

A completion design in which the reservoir fluids are produced through small-diameter casing. The absence of a separate tubing string significantly limits the operating and contingency options available for the well.

A downhole tool used on slickline operations. The tubular jar is a relatively simple mechanical jar that is extended or collapsed by manipulation of the slickline at surface. The impact force delivered by the jar depends on the weight of the tool string above the jar, the density of the wellbore fluid and the stroke length of the jar.

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

(noun) A type of sedimentary rock formed by the consolidation and lithification of volcanic ash and pyroclastic material ejected during explosive volcanic eruptions. Tuff beds serve as important stratigraphic markers and chronostratigraphic horizons in basin correlation, and their distinct mineralogy makes them identifiable on gamma ray and other well logs.

A phenomenon of constructive or destructive interference of waves from closely spaced events or reflections. At a spacing of less than one-quarter of the wavelength, reflections undergo constructive interference and produce a single event of high amplitude. At spacing greater than that, the event begins to be resolvable as two separate events. The tuning thickness is the bed thickness at which two events become indistinguishable in time, and knowing this thickness is important to seismic interpreters who wish to study thin reservoirs. The tuning thickness can be expressed by the following formula:Z = VI/2.8 fmax,where Z = tuning thickness of a bed, equal to 1/4 of the wavelengthVI = interval velocity of the targetfmax = maximum frequency in the seismic section.The equation assumes that the interfering wavelets are identical in frequency content and are zero-phase and is useful when planning a survey to determine the maximum frequency needed to resolve a given thickness. Spatial and temporal sampling requirements can then be established for the survey.

Sedimentary deposits formed by turbidity currents in deep water at the base of the continental slope and on the abyssal plain. Turbidites commonly show predictable changes in bedding from coarse layers at the bottom to finer laminations at the top, known as Bouma sequences, that result from different settling velocities of the particle sizes present. The high energy associated with turbidite deposition can result in destruction of earlier deposited layers by subsequent turbidity currents.

An influx of rapidly moving, sediment-laden water down a slope into a larger body of water; also called a density current because the suspended sediment results in the current having a higher density than the clearer water into which it flows. Such currents can occur in lakes and oceans, in some cases as by-products of earthquakes or mass movements such as slumps. The sedimentary deposits that form as the current loses energy are called turbidites and can be preserved as Bouma sequences. Turbidity currents are characteristic of trench slopes of convergent plate margins and continental slopes of passive margins.

A type of fluid flow characterized by swirling or chaotic motion as the fluid moves along the flow path. This is a preferred flow regime for mud removal during primary cementing because it is perceived to result in better removal of mud, especially of mud at the formation wall.

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

To part or break the drillstring downhole due to either fatigue or excessive torque.

Parting or breaking of the drillstring downhole due to fatigue or excessive torque.

A group of 2D seismic lines acquired individually, as opposed to the multiple closely spaced lines acquired together that constitute 3D seismic data.

Seismic data or a group of seismic lines acquired individually such that there typically are significant gaps (commonly 1 km or more) between adjacent lines. A 2D survey typically contains numerous lines acquired orthogonally to the strike of geological structures (such as faults and folds) with a minimum of lines acquired parallel to geological structures to allow line-to-line tying of the seismic data and interpretation and mapping of structures.

A technique for interpreting the results from a spinner flowmeter using two logging runs over the zone of interest, one up and one down. If the two passes are run at the same cable speed, they will overlay below the perforations, where there is no flow. If they were not run at the same speed, the curves are shifted to overlay. Elsewhere, the separation between the curves gives the relative contribution of each zone. Viscosity changes should have a small effect, since they will have the same influence on both passes.The technique is applicable when the flow is single-phase, or else multiphase with a sufficiently homogeneous-flow regime, such as with emulsion or dispersed bubble flow.

The simultaneous flow of both oil and free gas into a wellbore. This is thought to occur through common pore spaces, where the fluids flow simultaneously. In actuality, the situation is much more complicated, and much two-phase flow occurs in a stratified manner, with lighter fluids flowing primarily through the top of a producing zone and heavier ones flowing through the bottom layers.

A vessel that separates the well fluids into gas and total liquid. A two-phaseseparator can be horizontal, vertical or spherical. The liquid (oil, emulsion) leaves the vessel at the bottom through a level-control or dump valve. The gas leaves the vessel at the top, passing through a mist extractor to remove the small liquid droplets in the gas.

The elapsed time for a seismicwave to travel from its source to a given reflector and return to a receiver at the Earth's surface. Minimum two-way traveltime is that of a normal-incidence wave with zero offset.

What Are Type Curves? Type curves are families of dimensionless pressure-change and pressure-derivative solutions computed from analytical reservoir models, plotted on log-log scales so interpreters can overlay field transient test data, match the characteristic shapes of flow regimes, and extract reservoir properties including permeability-thickness product and mechanical skin. They underpin modern well test interpretation across every producing basin from the Permian to the Norwegian Continental Shelf. Key Takeaways Type curves express wellbore pressure response as dimensionless variables (PD, tD/CD) so that a single family of curves can represent any reservoir, fluid, or depth, enabling direct comparison between field data from a Montney tight gas well and a Saudi Arabia HPHT carbonate using the same diagnostic plot. The Bourdet pressure derivative (dP/d(ln t) = t × dP/dt), introduced in 1983, is the single most important advance in well test analysis: it stabilizes noisy data, amplifies subtle flow-regime transitions, and allows interpreters to identify radial flow (flat derivative), linear flow (half-unit slope), bilinear flow (quarter-unit slope), and boundary effects (upturn) on the same log-log plot. Matching field data to the Gringarten-Bourdet CDe2S type curve families simultaneously yields wellbore storage coefficient (C), skin (S), and the permeability-thickness product (kh), reducing ambiguity that plagued earlier semilog Horner analysis. In unconventional reservoirs, normalized-rate type curves derived from Palacio-Blasingame flowing material balance analysis and the Blasingame decline type curve family extend the concept to production data, enabling reserve estimation and completion benchmarking without a formal pressure buildup test. Regulatory bodies including Alberta's AER, the US offshore BSEE, Australia's NOPSEMA, and Norway's Sodir require pressure transient data submission for well deliverability assessments, resource certification, and reservoir management plans, making type curve analysis a legal reporting tool as well as an engineering discipline. How Type Curve Analysis Works A pressure transient test records bottomhole pressure and flow rate as functions of time, either during a drawdown (producing well) or a buildup (shut-in after production). The raw pressure data are processed into two diagnostic curves: the pressure change (delta-P, units of PSI or kPa) and the Bourdet derivative (dP/d(ln Δt), same units), both plotted against elapsed time on a log-log scale. This simultaneous display of delta-P and its derivative is called the diagnostic plot or log-log plot, and it is the first thing every well test interpreter examines. The pressure change alone often hides subtle flow regime transitions, but the derivative magnifies them: a flat derivative over at least one log cycle confirms radial flow and allows direct calculation of kh from the Ramey or Gringarten equations; a half-unit slope on the derivative indicates linear flow into a hydraulic fracture or along a narrow channel; a quarter-unit slope indicates bilinear flow in a fracture with finite conductivity; a unit slope on both curves simultaneously confirms wellbore storage, where production is entirely sustained by fluid expansion in the wellbore rather than reservoir influx. Once the diagnostic plot is constructed, the interpreter selects a type curve family matching the expected well geometry. For a vertical well in a homogeneous reservoir, the Gringarten-Bourdet CDe2S families (also called the standard Bourdet type curves) provide a set of dimensionless pressure-derivative pairs parameterized by the product CDe2S, where CD is the dimensionless wellbore storage coefficient and S is the skin factor. The interpreter overlays the field log-log plot on the type curve sheet, sliding the data horizontally and vertically until the shape of the field curve matches a specific type curve member. The horizontal and vertical shifts between the data and the dimensionless axes provide the match-point coordinates that, combined with fluid properties (viscosity, formation volume factor) and wellbore geometry, yield the permeability-thickness product (kh, in millidarcy-feet or millidarcy-meters) and the skin factor (S, dimensionless). In modern software including Kappa Engineering's Saphir, IHS Harmony (now Enverus Harmony), Ecrin, and IQHP, the matching is performed by automated non-linear least-squares minimization, though experienced interpreters always review the automated solution visually. Specialized type curves exist for every common well geometry and reservoir model. The Warren-Root dual-porosity type curves capture the characteristic trough-and-recovery signature of naturally fractured carbonates, where fluid first drains out of the fracture network (early radial flow) before matrix blocks begin feeding the fractures (transition period) and a second radial flow develops. Layered reservoir type curves (commingled multilayer) handle stratified sandstone sequences. Horizontal well type curves reveal the early vertical radial flow, linear flow phase, and late pseudo-radial flow transition unique to long horizontal laterals. Hydraulically fractured well type curves, developed by Gringarten, Ramey, and Raghavan in 1974 for infinitely conductive fractures and extended by Cinco-Ley and Samaniego in 1978 for finite-conductivity fractures, are essential for hydraulic fracturing diagnostics in the Montney, Duvernay, Haynesville, and Permian. Type Curves Across International Jurisdictions In Canada, the Alberta Energy Regulator (AER) governs well testing under Directive 040 (Pressure and Deliverability Testing of Oil and Gas Wells). Operators must submit test data, well histories, and interpretation reports for all test types, including pressure buildup (PBU), drawdown, and isochronal tests. The AER uses submitted type curve analyses as primary evidence in reserve determinations under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Montney and Duvernay tight gas wells in northeastern British Columbia operate under the BC Energy Regulator (BCER), which mandates analogous reporting under the B.C. Oil and Gas Commission's Operations Regulations. The extreme heterogeneity of the Montney siltstones, with permeabilities typically between 0.0001 and 0.01 millidarcy (0.0001 to 0.01 mD), means that flowing material balance and normalized-rate decline type curves from Enverus Harmony are used more frequently than conventional pressure buildup analysis, since shut-in times of weeks or months are required for pressure stabilization in rocks that tight. In the United States, the Bureau of Safety and Environmental Enforcement (BSEE) requires pressure buildup tests and deliverability tests on all offshore wells in the Gulf of Mexico under 30 CFR Part 250, Subpart J. Onshore, the Railroad Commission of Texas (RRC) requires well tests for tight oil and gas wells seeking enhanced recovery permits, and the North Dakota Industrial Commission (NDIC) uses type curve benchmarks to certify proved developed reserves in Bakken Shale applications. The Permian Basin presents particular type curve challenges because prolific wellbore storage in deep, high-temperature wells (bottomhole temperatures of 200 to 280 degrees Fahrenheit, 93 to 138 degrees Celsius) can mask radial flow for several days, requiring deconvolution algorithms or multi-rate analysis to extract kh from production data. ExxonMobil, Pioneer, and ConocoPhillips publish Permian type curve benchmarks in investor presentations, but these production-based EUR type curves use normalized rate per foot of lateral and differ conceptually from classical pressure-transient type curves. In Australia, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates well testing in Commonwealth waters under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 and the NOPSEMA Well Integrity Guidelines. Operators submit pressure transient data for all exploration and appraisal wells. The Cooper Basin in South Australia and Queensland, Australia's dominant onshore gas province, uses conventional pressure buildup analysis under state regulatory frameworks administered by the South Australian Department for Energy and Mining and the Queensland Resources Council. Cooper Basin tight gas reservoirs, particularly the Permian Patchawarra Formation, require wellbore storage correction and dual-porosity type curves in some naturally fractured intervals. In Norway, the Norwegian Offshore Directorate (Sodir, formerly NPD) requires well test reporting for all exploration and production wells on the Norwegian Continental Shelf (NCS). Operators upload pressure transient data and interpretation reports to the Sodir FactPages database within 90 days of well completion. The NCS's prolific chalk reservoirs in the Ekofisk and Valhall fields require dual-porosity type curves, as the chalk matrix has very low permeability but naturally fractured networks of high conductivity. The Johan Sverdrup field in the North Sea, operated by Equinor, uses advanced type curve analysis for reservoir characterization of its Jurassic sandstones, where heterogeneous permeability ranging from 0.1 to 10 Darcy requires composite and layered type curve families to match buildup transients accurately. In Saudi Arabia, Saudi Aramco operates some of the world's most challenging high-pressure, high-temperature (HPHT) reservoirs, including the Arab-D carbonate at Ghawar where reservoir temperatures exceed 120 degrees Celsius (248 degrees Fahrenheit) and pressures exceed 300 bar (4,351 PSI). Aramco employs custom HPHT pressure gauges capable of operating continuously at temperatures above 150 degrees Celsius (302 degrees Fahrenheit), which is near or above the rated maximum for conventional quartz crystal gauges. Type curve matching in these conditions requires temperature-corrected fluid property tables and HPHT-calibrated wellbore storage models, since fluid compressibility and viscosity change significantly with temperature in carbonate brines. Aramco's Jafurah unconventional gas development, targeting the Lower Jurassic tight carbonates and siltstones at depths of 3,000 to 5,000 m (9,843 to 16,404 ft), adapts North American unconventional type curve methods to HPHT conditions. Fast Facts The concept of type curves in well test analysis was formally introduced by Henry J. Ramey Jr. at Stanford University in his landmark 1970 SPE paper "Short-Time Well Test Data Interpretation in the Presence of Skin Effect and Wellbore Storage." Ramey recognized that plotting dimensionless pressure against dimensionless time on log-log scales made all wells dimensionless, collapsing thousands of possible reservoir and fluid combinations onto a finite number of curve families. Within a decade, the McKinley curves (1974), the Gringarten-Ramey-Raghavan fracture curves (1974), and the Bourdet derivative (1983) had transformed well test interpretation from an art requiring experienced intuition into a systematic engineering discipline with quantitative uncertainty bounds.

A method for quantifying well and reservoir parameters such as permeability, skin, fracture half-length, dual-porosity parameters, and others, by comparing the pressure change and its derivative of the acquired data to reservoir model curve families, called type curves. When a match is found between data and a type curve, the parameters that characterize the behavior of the model providing a match are thereby determined.Originally, type-curve analysis was done manually using only the pressure change. With the introduction of the pressure derivative, the analysis requires matching both pressure change and its derivative. Computer-assisted matching permits rigorous accounting for superposition in time due to flow-rate variations before and even during (in the case of drawdown analysis) the transient data acquisition, as well as providing a continuum of solutions instead of a type-curve family derived from discrete values for the governing parameters.