Oil and Gas Terms Beginning with “L”

A synthetic hydrocarbon liquid made by the polymerization of ethylene, H2C=CH2. LAOs and other synthetic fluids are used in synthetic-base drilling fluids and other applications in which refined oils might otherwise be used if not for HSE concerns. LAOs have a linear structure with a double bond (olefin) at the end of the chain, making them more biodegradable than other olefins. LAOs can be catalytically reacted to move the double bond toward the center of the chain length to convert them to isomerized olefins, IOs.

The lethal concentration of a substance, reported in ppm, that kills 50% of a population of test organisms, such as mysid shrimp, in a standard, controlled laboratory bioassay test. In offshore drilling operations, the LC50 number is used to determine whether waste mud or cuttings can be discharged into the water. The larger the LC50 ppm number from the test, the less toxic the sample is to the organism. For example, if LC50 number is 1,000,000 ppm, the sample is presumably nontoxic according to the test protocol.

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

A type of drilling-fluid solid having a lower density than the barite or hematite that is used to weight up a drilling fluid, including drill solids plus the added bentoniteclay. The mud engineer calculates the concentration of these and other types of solids on the basis of mud weight, retort analysis, chloride titrations and other information. Solids are reported as lbm/bbl or vol.%. Water is 1.0, barite 4.20, and hematite 5.505 g/cm3. Low-gravity solids are normally assumed to have a density of 2.60 g/cm3.

Abbreviation for liquefied natural gas.

Abbreviation for liquefied natural gas carrier, which is a sea vessel used to transport liquefied petroleum gas (LPG).

A test to determine the strength or fracturepressure of the open formation, usually conducted immediately after drilling below a new casingshoe. During the test, the well is shut in and fluid is pumped into the wellbore to gradually increase the pressure that the formation experiences. At some pressure, fluid will enter the formation, or leak off, either moving through permeable paths in the rock or by creating a space by fracturing the rock. The results of the leakoff test dictate the maximum pressure or mud weight that may be applied to the well during drilling operations. To maintain a small safety factor to permit safe well control operations, the maximum operating pressure is usually slightly below the leakoff test result.

(noun) Abbreviation for Liquefied Petroleum Gas. A mixture of light hydrocarbon gases, primarily propane (C₃H₈) and butane (C₄H₁₀), that are compressed and stored as liquids at moderate pressure for use as fuel, petrochemical feedstock, and oilfield applications including well stimulation and enhanced oil recovery.

A highly anionicpolymer used to deflocculateclay-based muds. Lignosulfonate is a byproduct of the sulfite method for manufacturing paper from wood pulp. Sometimes it is called sulfonated lignin. Lignosulfonate is a complex mixture of small- to moderate-sized polymeric compounds with sulfonate groups attached to the molecule. LS became a popular deflocculant in the late 1950s as a replacement for quebracho. Chromium and iron compounds were admixed to get stability benefits at higher temperature. These were called chrome lignosulfonates (CLS) and ferro-chrome lignosulfonates (FCLS). There is less chrome is in most CLS than in the past (now about 2.5 to 3 %), and chrome-free products are available.

What Is Logging While Drilling (LWD)? Logging while drilling (LWD) describes the suite of formation evaluation sensors integrated into the bottom hole assembly that measures petrophysical rock and fluid properties, including natural gamma ray, resistivity, bulk density, neutron porosity, and acoustic compressional slowness, in real time as the drill bit advances through the formation, delivering the same quality of subsurface data as post-drill wireline logs but without interrupting drilling operations or risking an unstable open hole. LWD sensors transmit selected measurements to surface via MWD telemetry for real-time geosteering and store the complete high-resolution dataset in downhole memory for retrieval after the run. Key Takeaways LWD tools measure formation properties within seconds to minutes of the bit penetrating a new rock interval, providing virgin formation data before mud filtrate invasion significantly alters near-wellbore fluid saturation, particularly important in tight carbonates and low-permeability shales where invasion is minimal. Azimuthal LWD tools rotate with the BHA and sample formation properties at multiple directions around the borehole, creating 360-degree borehole images at a depth resolution of 25 mm (1 in) per sample, used for structural dip analysis, fracture characterisation, and precise geosteering in formations as thin as 1 m (3.3 ft). Operators, reservoir engineers, petrophysicists, and geologists use LWD data to make real-time landing and geosteering decisions; service companies including Baker Hughes, SLB, and Halliburton provide LWD tools under day-rate rental agreements with dedicated field engineers on site. Regulatory authorities including the AER (Canada), BSEE (US), Sodir (Norway), and NOPSEMA (Australia) accept LWD logs as primary formation evaluation records for well licensing, resource certification, and environmental assessment submissions. LWD eliminates or reduces the number of wireline logging runs required per well, shortening rig time by 12 to 36 hours per well and reducing open-hole exposure risk in wellbores prone to collapse, swelling shales, or lost circulation, directly lowering total well cost by USD 200,000 to USD 1,000,000 per well in complex environments. How Logging While Drilling Works LWD sensors are housed in dedicated sub-assemblies that replace drill collar joints in the BHA, positioned above the MWD pulser and directional sensors so that they measure the formation as close to the bit as practicable, typically within 3 m to 15 m (10 to 49 ft) of the bit depending on BHA configuration. Each sensor sub contains one or more transmitters and receivers configured according to the physics of the measurement: resistivity tools use coil antenna arrays to propagate electromagnetic waves through the formation; density tools use a Cs-137 gamma ray source and two detector crystals to measure bulk density from Compton scattering; neutron porosity tools use an Am-Be or Cf-252 source and near/far detector pairs to measure hydrogen index from neutron moderation. All sensors are housed in pressure-rated titanium or stainless steel collars rated to at least 207 MPa (30,000 psi) and 175 degrees C (347 degrees F) for standard tools, with HPHT variants rated to 241 MPa (35,000 psi) and 200 degrees C (392 degrees F) for deepwater and HPHT applications. Data is collected in two simultaneous modes: memory mode and real-time mode. In memory mode, all sensor measurements are recorded at full vertical resolution, typically 2.5 mm (0.1 in) to 76 mm (3 in) sampling depending on tool type and rotation speed, and stored in non-volatile flash memory within the downhole tool. This high-resolution dataset is downloaded after the drill string is pulled from the wellbore. In real-time mode, selected measurements are compressed and transmitted to surface via MWD mud-pulse telemetry at 1 to 12 bps, providing a reduced-resolution dataset sufficient for real-time geosteering and drilling decisions. The gap between real-time and memory resolution is the fundamental trade-off of LWD: the petrophysicist and geosteering geologist must make immediate decisions based on lower-resolution real-time data, then validate and refine their interpretations using the high-resolution memory data after the run. Tool standoff from the borehole wall affects measurement quality in directional and horizontal wells because gravity pulls the BHA toward the low side of the hole, causing density and neutron tools to see a variable amount of drilling fluid between the source and the formation. Standoff correction algorithms, validated against laboratory calibration data and applied in real time by the surface software package, compensate for this effect. Azimuthal tools address standoff by sampling formation properties in multiple sectors around the borehole and using only the near-wall sectors for petrophysical calculations, discarding sectors that show high standoff. Baker Hughes' adnVISION tool and SLB's arcVISION platform both incorporate azimuthal density measurements that provide separate readings from the high, low, left, and right sectors of the borehole, enabling real-time detection of formation density contrasts as small as 0.05 g/cc (0.05 g/cm3) that indicate the proximity of the wellbore to a bed boundary. LWD Across International Jurisdictions Canada (Duvernay, Montney, SAGD): The Duvernay Formation in the Deep Basin of western Alberta is one of the most technically demanding LWD environments in the world. Bottomhole temperatures exceed 165 degrees C (329 degrees F) and pressures exceed 72 MPa (10,440 psi) in the deep wet gas window, requiring HPHT-rated LWD tools for every well. Azimuthal gamma ray LWD is used to confirm landing in the organic-rich Lower Duvernay facies by detecting the characteristic gamma ray increase associated with elevated total organic carbon content, with target zones less than 10 m (33 ft) thick. In the SAGD oil sands of the Athabasca and Cold Lake regions, LWD neutron-density cross-plots discriminate oil-saturated sand from lean sand or shale in the producer well pair, enabling the geosteering geologist to maintain the producer within 2 m (6.6 ft) of the base of the oil pay continuously along the lateral. The AER accepts LWD memory data as primary log records for all well licensing submissions under Directive 059. United States (Permian, Eagle Ford, Haynesville): The Permian Basin's stacked pay zones in the Wolfcamp, Bone Spring, and Spraberry formations are typically 15 to 60 m (49 to 197 ft) thick, providing sufficient vertical window to geosteer using a combination of azimuthal gamma ray and resistivity LWD. Operators including Pioneer Natural Resources, Coterra, and Devon Energy mandate real-time LWD geosteering on all horizontal wells, using the azimuthal gamma ray image to ensure the lateral stays in the highest-quality reservoir rock as defined by the type log. BSEE regulations for offshore Gulf of Mexico require LWD logs to be submitted with the Sundry Notice for Well Completion and require that LWD data match wireline data within specified tolerances where both are run. Norway and the North Sea: The Norwegian Continental Shelf's chalk and sandstone reservoirs, including Eldfisk, Edvard Grieg, and Johan Sverdrup, rely heavily on LWD resistivity and density-neutron measurements for reservoir characterisation in horizontal wells. Sodir requires that all LWD data be submitted to the Norwegian Petroleum Directorate's DISKOS national data repository within 30 days of well completion, making Norway one of the world's largest publicly accessible LWD databases. Equinor's partnership with SLB on the Johan Sverdrup development pioneered integrated LWD-geosteering workflows that combined real-time resistivity LWD with seismic-constrained Earth models to navigate the Draupne Formation's heterogeneous sandstone reservoir, achieving average reservoir quality index (RQI) values 15 percent above plan by steering to higher-porosity sandstone facies identified in real time. Middle East and ADNOC: ADNOC's Abu Dhabi onshore and offshore fields, including Bab, Bu Hasa, and the Zakum offshore field, use LWD extensively for horizontal well geosteering in the Arab and Kharaib carbonate formations. The Arab-D reservoir at Ghawar and its equivalent in Abu Dhabi is a thinly laminated carbonate with oil-bearing and tight layers alternating at scales of 0.3 to 3 m (1 to 10 ft), requiring azimuthal LWD with resistivity imaging resolution of 25 mm (1 in) or better to discriminate productive from non-productive layers. ADNOC Operations mandates LWD resistivity image logs as the primary structural geology tool for all horizontal wells, replacing post-drill microresistivity wireline imaging in most cases because LWD image data is available for real-time structural dip modelling without a dedicated wireline run. Fast Facts The first commercial LWD density tool was introduced by Schlumberger in 1985. Today, a single integrated LWD string running gamma ray, resistivity, density, neutron, and sonic sensors can replace five separate wireline logging runs and deliver the complete petrophysical dataset needed for resource certification in a single drilling run. In the Norwegian North Sea, mandatory LWD data submission to the DISKOS repository has created a publicly accessible dataset of more than 18,000 wells covering 50 years of offshore exploration, the largest public subsurface database of its kind in the world.

One of two elastic constants named for French mathematician Gabriel Lame (1795 to 1870). The first, the shear modulus, can be expressed as:The other Lame constant is the bulk modulus less two-thirds of the shear modulus:

A partial differential equation that governs potential fields (in regions where there are no sources) and is equivalent, in three dimensions, to the inverse square law of gravitational or electrical attraction. In Cartesian coordinates, the Laplace equation equates the sum of the second partial (spatial) derivatives of the field to zero. (When a source is present, this sum is equal to the strength of the source and the resulting equation is called Poisson's equation). The differential equation is named for French mathematician Pierre-Simon de Laplace (1749 to 1827), and applies to electrical, gravity and magnetic fields.

To attach elevators to the upper section of drillpipe to pull it out of or run into the hole.

To pull drill pipe from the hole and lay it down on the catwalk.

A type of surface wave in which particles oscillate horizontally and perpendicularly to the direction of wave propagation.

A ball valve installed at one end of the kelly that can be used to stop mud draining from the kelly during a connection.

Pertaining to an environment of deposition in lakes, or an area having lakes. Because deposition of sediment in lakes can occur slowly and in relatively calm conditions, organic-rich source rocks can form in lacustrine environments.

The distance between the static measure point and the dynamic measure point of a logging measurement. For nuclear logs and any others that must be recorded over a significant time period, there is a difference between the measure point with the tool stationary and moving. If the tool is moving during this period, the effective center of measurement will be a certain distance from the point at which the measurement started. This distance is the lag. The lag depends on the logging speed and the sampling interval.

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

The time taken for cuttings to reach the surface. The term is also used in place of cycle time.

A type of streamlined flow for single-phase fluids in which the fluid moves in parallel layers, or laminae. The layers flow smoothly over each other with instabilities being dampened by the viscosity. Laminar flow occurs in straight pipes when the Reynolds number is below a critical value, corresponding to a low production rate. Above this value, the flow is turbulent. For laminar flow in straight pipes, the velocity profile across the pipe is parabolic, increasing from zero at the wall of the pipe to a maximum at the center equal to twice the mean velocity.

A particular model, or equation, for deriving the water saturation from resistivity and other logs. The model assumes a laminar shale distribution and considers the total resistivity to be the sum in parallel of the sand and shale laminae.

A fine layer (~ 1 mm thick) in strata, also called a lamina, common in fine-grained sedimentary rocks such as shale, siltstone and fine sandstone. A sedimentary bed comprises multiple laminations, or laminae.

A component installed near the bottom of the casing string on which the cement plugs land during the primary cementing operation. The internal components of the landing collar are generally fabricated from plastics, cement and other drillable materials.

(noun) A short section of internally machined tubing with a precisely profiled bore, installed at specific locations in a completion string to provide a seating and locking surface for flow-control devices such as plugs, chokes, and gauges that are set and retrieved by wireline or slickline.

What Is a Landman? A landman negotiates the acquisition of mineral rights and surface access agreements between energy companies and landowners across oil and gas producing regions worldwide. Operating at the intersection of law, geology, and commerce, landmen conduct title research, manage lease portfolios, and ensure regulatory compliance for upstream operators from the Permian Basin to the Western Canadian Sedimentary Basin and beyond. Key Takeaways Landmen secure mineral rights and surface access for drilling operations across North America, Australia, and the Middle East. Title research involves tracing ownership records through courthouse documents, Crown land registries, and government databases to establish clear mineral title. Professional certification levels include RL (Registered Landman), RPL (Registered Professional Landman), and CPL (Certified Professional Landman) through the AAPL in the United States, and equivalent designations through CAPL in Canada. Compensation ranges from USD $75,000 to $200,000 in the US Permian Basin, CAD $80,000 to $150,000 in Alberta, and AUD $120,000 to $180,000 for equivalent roles in Australia. The Paramount+ series "Landman" (2024) brought mainstream attention to the profession, though the daily reality centres on legal research and negotiation rather than dramatic confrontation. How a Landman Works The landman's primary function begins well before a drilling rig arrives on location. When a geologist or exploration team identifies a prospective drilling target, the landman conducts a thorough title examination to determine who owns the mineral rights beneath the surface. In the United States, mineral rights can be severed from surface rights, creating complex ownership chains that require meticulous courthouse research stretching back decades or even centuries. In Canada, the process differs significantly. Approximately 81% of mineral rights in Alberta are owned by the Crown (provincial government), administered through the Alberta Department of Energy's mineral rights auction system. The landman in this context manages Crown lease acquisitions through competitive bidding, negotiates freehold mineral leases where private ownership exists, and ensures compliance with Alberta Energy Regulator (AER) Directive 056 for well licence applications. In British Columbia, the BC Energy Regulator (BCER) oversees a similar Crown tenure system, while Saskatchewan's Ministry of Energy and Resources manages its own disposition process. Once mineral rights ownership is confirmed, the landman negotiates lease terms with the mineral owner. Standard oil and gas leases specify a primary term (typically three to five years), a royalty rate (commonly one-eighth or 12.5% in the US, though rates as high as 25% are negotiated in competitive plays), and a bonus payment per net mineral acre. In Canada, Crown royalties are set by provincial regulation rather than negotiation, with Alberta's modernized royalty framework calculating rates based on well productivity and commodity prices. Landman Across International Jurisdictions The landman profession varies significantly across global energy-producing regions, reflecting differences in mineral ownership frameworks and regulatory structures. Canada: Crown Land, Freehold Rights, and Provincial RoyaltiesCanada presents a unique dual-system that shapes a landman's daily work. Approximately 81% of mineral rights in Western Canada are owned by the Crown (provincial governments), while roughly 19% are freehold (privately owned). This split fundamentally changes the negotiation process depending on whether a landman is acquiring Crown or freehold mineral leases.For Crown minerals in Alberta, the provincial government sets lease terms and royalty rates through the Alberta Modernized Royalty Framework (MRF). Under the MRF, royalty rates range from 5% to 40% for crude oil and condensate, and 5% to 36% for natural gas. New wells pay a flat 5% royalty during early production until total revenue reaches the cost allowance threshold (C*), after which higher post-payout rates apply based on commodity prices. Wells spud before January 1, 2017 transition to the MRF at the end of 2026.Alberta's Bitumen Royalty-In-Kind (BRIK) programme, administered by the Alberta Petroleum Marketing Commission (APMC), allows the province to collect its royalty share as physical barrels rather than cash payments. Producers deliver Crown royalty crude to the APMC at over 5,000 delivery points across 170 pipelines and terminals. Shell Trading Canada serves as the APMC's marketing agent. In January 2026, the Alberta government authorized APMC to borrow up to CAD 00 million for market investments under this programme.For freehold minerals, landmen negotiate directly with private mineral owners using the CAPL (Canadian Association of Petroleum Landmen) lease form. The CAPL 91 form is used in approximately 95% of freehold lease negotiations in Western Canada. Newer versions, including CAPL 99 and CAPL 2014, provide stronger protections for freehold owners, with tighter controls on payment obligations and offset well requirements. The Freehold Owners Association (FHOA) advocates for mineral owners' rights in these negotiations.In British Columbia, the province collects royalties on oil and natural gas produced from Crown leases. BC is currently transitioning to a new royalty framework, with the transition period extended to December 31, 2026 for existing wells. The new framework takes full effect January 1, 2027. The BC Energy Regulator (BCER) oversees drilling permits and environmental compliance.Saskatchewan's Crown royalty structure includes a Crown beneficial interest of one-quarter (25%) of production, with qualifying incentive volumes subject to a maximum royalty rate of 2.5% for Crown production. The province also imposes a freehold production tax on privately owned minerals. Saskatchewan's incentive programmes for new drilling make it an active jurisdiction for landmen, particularly in the Bakken and Viking formations. United States: Fee Simple, State and Federal LandsIn the United States, the majority of mineral rights are privately owned under fee simple ownership, making direct negotiation between landmen and individual mineral owners the primary mechanism for lease acquisition. Typical lease terms include a one-eighth (12.5%) to one-quarter (25%) royalty, a primary term of three to five years, and a cash bonus payment per net mineral acre. The American Association of Professional Landmen (AAPL) sets professional standards and certification requirements.Federal lands are managed by the Bureau of Land Management (BLM), which conducts competitive lease sales. State-owned minerals are managed by individual state land offices. Offshore leasing on the Outer Continental Shelf falls under the Bureau of Ocean Energy Management (BOEM). Australia: Offshore Titles and Native TitleAustralia's petroleum tenure system is governed by the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act), regulated by NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority). The equivalent of the landman role in Australia is typically called a "land access officer" or "tenure specialist." Key responsibilities include negotiating Native Title agreements with Indigenous traditional owners under the Native Title Act 1993, a process with no direct equivalent in North American land practices.The Petroleum Resource Rent Tax (PRRT) applies to offshore petroleum projects at a rate of 40% of taxable profits, replacing traditional royalty structures for most offshore production. Onshore, state-based royalty regimes apply, typically ranging from 10% to 12.5% of wellhead value. Middle East and NorwayIn the Middle East, mineral rights are exclusively state-owned. The landman function falls under "concession management" within national oil companies such as ADNOC (Abu Dhabi), Saudi Aramco, Kuwait Oil Company, and QatarEnergy. Concession agreements are negotiated at the government-to-company level, typically as production sharing agreements (PSAs) or service contracts.Norway's petroleum resources are managed by the Ministry of Petroleum and Energy, with the Norwegian Petroleum Directorate (Sodir) administering production licences. All petroleum resources on the Norwegian Continental Shelf are owned by the state. Companies apply for exploration and production licences through competitive licensing rounds, with fiscal terms set by government policy rather than individual negotiation. Landman Responsibilities and Career Path The landman's daily work encompasses several distinct functions that require legal acumen, negotiation skill, and geological awareness. Title Examination: Researching ownership records at county courthouses (US), Land Titles offices (Canada), or government registries to establish a clear chain of title. This involves reading deeds, wills, probate records, mortgage releases, and prior oil and gas leases to identify the current mineral owner and any title defects that must be cured before spudding a well. Lease Negotiation: Drafting and negotiating oil and gas leases, surface use agreements, pipeline easements, and pooling or unitization agreements. In Canadian freehold situations, the CAPL model form lease provides a standard starting point, similar to the AAPL Form 610 in the United States. Due Diligence: Supporting acquisitions and divestitures (A&D transactions) by auditing title, verifying production allocations, and confirming regulatory compliance. During the 2024-2025 M&A wave in the Montney play, landmen were central to transactions totalling billions of dollars. Regulatory Compliance: Filing well licence applications, ensuring compliance with spacing regulations, managing expiring lease terms, and coordinating with the AER (Alberta), Railroad Commission of Texas, North Dakota Industrial Commission (NDIC), or relevant provincial and state regulators. Career progression typically moves from field landman (independent contractor conducting title research) to in-house landman (managing a company's lease portfolio) to land manager or VP of Land (strategic land acquisition and A&D leadership). Many landmen hold degrees in petroleum land management from programs at the University of Texas at Austin, University of Oklahoma, Texas Tech University, or the University of Calgary. Tip: For investors evaluating an operator's acreage position, the quality of the land department's title work directly affects the company's proved reserves. Title defects discovered after a well is drilled can force operators to shut in production and renegotiate leases, impacting both production forecasts and per-barrel operating costs. Landman Synonyms and Related Terminology The landman role is known by several names across international jurisdictions: Land Agent: used in some US and Canadian contexts, particularly for pipeline right-of-way acquisition Land Access Officer: the standard Australian title for professionals negotiating surface access with pastoral and native title holders Tenure Specialist: used in Australian state petroleum agencies and some Canadian regulatory bodies Concession Manager: the equivalent function in Middle Eastern national oil companies managing PSC and service contract portfolios Petroleum Landman: formal title used in AAPL certification programs to distinguish from real estate land professionals CPL: Certified Professional Landman, the highest AAPL designation CAPL: Canadian Association of Petroleum Landmen, which administers Canadian land practices Right-of-Way Agent: specialization within the profession focused on pipeline and utility corridor acquisition Related terms: mineral rights, lease, spud, production, pipeline, drilling rig, well control

A technique for analyzing the grain-size distribution of a core sample. A cleaned, disaggregated sample is dispersed in a carrier fluid. The grains cause diffraction of a laser beam directed through the fluid. The angle of scattering is inversely proportional to the particle size, while the intensity of scattering is proportional to the number of particles. Laser diffraction also may be referred to as laser sieve analysis.

The depth of the last reliable reading of a log. For the normal bottom-to-top survey, the last reliable reading often occurs just before the logging tool enters the casing. With several logging tools in a tool string, the last readings will be at different depths, depending on the measure point of each measurement.

A surface detection system used to ensure that all tubing-conveyed perforating guns have fired, from the top shot to the bottom shot.

The portion of the pressure transient occurring after radial flow. Analysis of the late-time transient data provides characterization of outer boundaries such as faults or fluid contacts. This portion of the data appears only in transient tests of sufficient duration.

Referring to a type of conventional electrical log in which the current-emitting and the current-return electrodes (A and B) are placed close together on the sonde, with the measure electrode (M) several feet away and the measure return (N) far away. This arrangement is sensitive to the potential gradient between A and B. The spacing is defined by the distance from M to the midpoint between A and B. The most common spacing is 18 ft, 8 in. [5.7 m]. The lateral gives a sharper response to a bed boundary than a normal but also introduces several artifacts that can give misleading results.

A colloidal suspension or emulsion of specific organic materials. Certain latices may be used as cement additives. Latex is used to provide gas-migration control, improve durability and improve bonding. It also offers excellent fluid-loss control. Latex additives also impart some acid resistance to cement.

A slab of reservoirrock bounded above and below by another layer in vertical hydraulic communication.

A method of seismic inversion whereby the effects of rock layers having different seismic characteristics are removed from layers below.

A highly simplified description of a geological scenario. Although sometimes used for "quick and dirty" simulation models, this description is often not appropriate for detailed or accurate work. Generally, layer-cake geometry is an oversimplification of actual structure and stratigraphy of a reservoir. It assumes that the reservoir comprises a stack of conformable layers.

An advanced testing technique using a combination of transient-rate and pressure measurements and stabilized flow profiles to determine permeability and skin for each of several layers commingled in a well. The technique requires a series of flow-rate changes, with at least one flow-rate change for each layer to be characterized.

A commonly used (but strictly speaking, incorrect) version of lbm/bbl.

The abbreviation for concentration in US oilfield units, pound per barrel. One lbm/bbl is the equivalent of one pound of additive in 42 US gallons of mud. The "m" is used to denote mass to avoid possible confusion with pounds force (denoted by "lbf"). Lbm/bbl is sometimes written as PPB, but must not be confused with parts per billion. In SI units, the conversion factor is one pound per barrel equals 2.85 kilograms per cubic meter. For example, 10 lbm/bbl = 28.5 kg/m3.

A test to detect hydrogen sulfide in a fluid by discoloration of a paper moistened with the lead acetate solution. It is important to determine the presence and amount of hydrogen sulfide because this gas is extremely poisonous, highly flammable, explosive and corrosive.

(noun) The first cement slurry pumped during a primary cementing operation, designed with lower density and extended volume to fill the upper portion of the casing-borehole annulus. Lead cement is typically lighter than the tail cement that follows and may contain extenders such as bentonite or hollow microspheres to reduce cost and hydrostatic pressure.

The determination of the location of a leak in a pipeline. In onshore operations, this can be done by external detection or by using material balance leak-detection systems. In offshore operations, the task is more difficult because of the lack of inlet flow-rate measurements and the considerable solubility of natural gas in seawater at high pressures and low temperatures (seafloor level).In deepwater operations with multiphase flow, indications of a leak may not be present at the ocean surface or it could be considerably displaced from the site of origination. In these circumstances, an energy-balance technique based on the changes in frictional losses through the pipeline is a powerful tool.

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

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

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

A type of acoustic energy that propagates in one direction while being confined in the other two directions, in this case by the borehole wall. Leaky modes can be considered as multiply reflected and constructively interfering waves propagating in the borehole. Each time a compressional wave hits the borehole wall, part of the energy is reflected into the borehole, while the rest is converted to compressional or shear energy that radiates into the formation, hence the term 'leaky'. Leaky modes are dispersive, starting at a certain cutoff frequency with the formation compressional velocity and increasing towards the borehole fluid velocity at high frequency. In slow formations, where no head wave is generated because the borehole fluid is faster than the formation compressional wave, the low-frequency end of the leaky mode can be used to determine formation compressional velocity.The term 'hybrid mode' is used to describe a form of leaky mode that is associated with an altered zone.

Residual gas, mainly methane and ethane, that remains after the heavier hydrocarbons have been condensed in the wellhead. When the lean gas is liquefied, it is called liquefied natural gas (LNG).

A gas condensate with low condensate formation in the reservoir (when the bottomhole pressure is reduced below the dewpoint pressure).

In a glycoldehydrator, glycol that has been boiled and no longer contains any water. When the glycol is lean, it can be pumped back to the absorber for reuse.

Liquid hydrocarbon utilized to remove heavier components from the gas stream in a gas processing plant.

The contract that conveys the rights to explore and produce from the owner of the mineral rights (lessor) to a tenant (lessee), usually for a fee and with a specified duration. A lease usually includes a provision for sharing production.

The fastest route that a seismic ray can travel between two points, generally dictated by Fermat's principle.

A percentage share of production, or the value derived from production, which is granted to the lessor in the oil and gas lease, and which is free of the costs of drilling and producing.

The assembly on a coiled tubing reel that guides the tubing string onto the drum. Accurate spooling is necessary to avoid damaging the tubing and to ensure that the entire string can be run and retrieved without jamming. The levelwind functions automatically, although it incorporates a manual override to facilitate minor corrections.

An occasion when a governmental body offers exploration acreage for leasing by exploration and production companies, typically in return for a fee and a performance or work obligation, such as acquisition of seismic data or drilling a well. Exploration licenses are initially of limited duration (about 5 years) after which there might be a requirement to return half or more of the licensed acreage to the state. If hydrocarbons are discovered, a separate production license or production-sharing agreement is usually drawn up before development can proceed.

The period of time during which economically sustainable production levels may be expected from a well. The anticipated well life and the characteristics of the reservoir fluid are the two main factors in specifying the completion system components.

A lifting device used when performing coiled tubing operations from a semisubmersiblerig or drillship. The coiled tubing injector and pressure-control equipment are positioned within the lifting frame, which is attached to the flow head and running string and supported by the traveling blocks. This configuration enables the heave-compensation system of the rig to counteract the vessel motion.

A short drillstring component that is temporarily connected to the top of a tool assembly that is to be lifted vertically, such as when running or retrieving a tool string. The external profile on the upper section of the lifting sub is similar to that of the completion tubing, enabling the rig elevators to lift the assembled tool string safely.

Crude oil that has a high APIgravity, usually more than 40o.

Hydrocarbons with low molecular weight such as methane, ethane, propane and butane.

An operating condition during a snubbing operation in which the wellheadpressure and buoyancy forces are greater than the force resulting from the weight of the pipe or tubing string. In the light-pipe condition the string will be ejected from the wellbore if the gripping force of the slips is lost.

The component of a tree that is extracted in the paper-manufacturing process and used as an additive in drilling fluids. Specifically, lignin is a highly polymerized, amorphous material that makes up the middle lamella of woody fibers and cements the fibers together. Methoxy groups are abundant on the lignin structure, giving lignin many reactive sites and promoting its water solubility. In paper manufacturing, lignin is dissolved from wood chips. In the sulfite paper process, the liquor byproduct contains wood sugars and lignosulfonate. The wood sugars are removed and the lignosulfonate is used as a claydeflocculant. In the kraft paper process, lignin is solubilized by caustic soda. Kraft lignin must be further reacted to make a functional drilling-fluid additive.

The mineral leonardite, similar to brown coal. Lignite is found in surface deposits worldwide. Lignite is mined and put into piles where it can oxidize in the air before it is dried, ground and bagged for use in drilling fluids. The humic acid content of lignite, which varies widely, controls its solubility. The soluble and colloidal lignite components both help in fluid-loss control. Soluble components serve as clay deflocculants and improve filter cake quality. Colloidal lignite helps plug off the permeable parts of filter cake. When straight lignite is added to a mud, caustic soda is also needed to make it dissolve. Precaustisized lignite is available, which contains NaOH or KOH already mixed. Adding chromium salts improves high-temperature performance, but their use is limited by HSE concerns. Organophilic lignite is a straight lignite that has been treated with quaternary amine compounds to make it oil dispersible in oil- and synthetic-base muds.

A highly anionic polymer used to deflocculateclay-based muds. Lignosulfonate is a byproduct of the sulfite method for manufacturing paper from wood pulp. Sometimes it is called sulfonated lignin. Lignosulfonate is a complex mixture of small- to moderate-sized polymeric compounds with sulfonate groups attached to the molecule. LS became a popular deflocculant in the late 1950s as a replacement for quebracho. Chromium and iron compounds were admixed to get stability benefits at higher temperature. These were called chrome lignosulfonates (CLS) and ferro-chrome lignosulfonates (FCLS). There is less chrome is in most CLS than in the past (now about 2.5 to 3 %), and chrome-free products are available.

A type of water-base mud that is saturated with lime, Ca(OH)2, and has excess, undissolved lime solids maintained in reserve. Lime muds are classified according to excess lime content: (1) low-lime, 0.5 to 2 lbm/bbl, (2) medium-lime, 2 to 4 lbm/bbl and (3) high-lime, over 4 lbm/bbl. All lime muds have pH in the range of 12, and the filtrate is saturated with lime. Fluid-loss additives include starch, HP-starch, carboxymethylcellulose (CMC) or polyanionic cellulose (PAC). Prehydrated bentonite can improve the fluid loss and rheology of a lime mud. A maltodextrin in lime muds has been used as a claydeflocculant, a shale stabilizer and to increase calcium solubility. KCl in lime muds has been another innovation for successful drilling of hydratable shales. The ability to carry very high mud alkalinity (as excess lime) to neutralizeacid gases is one reason lime muds are used. H2S zones can be drilled with more safety and copious amounts of CO2 can be neutralized by a large excess of lime.

A carbonatesedimentaryrock predominantly composed of calcite of organic, chemical or detrital origin. Minor amounts of dolomite, chert and clay are common in limestones. Chalk is a form of fine-grained limestone.

A transform from raw log data chosen so that a log recorded in these units will give the correct porosity of the formation, providing the matrix is pure calcite and the pores are filled with fresh water. The unit, which may be in vol/vol or p.u., is most commonly used for neutron porosity logs but may also be used for density and acoustic logs. The definition is strictly true only if all borehole and other environmental corrections have been applied.

Display ranges chosen for the density and neutron porosity logs such that the two curves will overlay at all porosity values providing the matrix is pure calcite and the pores are filled with fresh water. The most common overlay spans two tracks, with the density reading from 1.95 to 2.95 g/cm3, and the neutron in limestone porosity units from 0.45 to −0.15 vol/vol.

A completion with only a portion of the productive interval open to flow, either by design or as a result of damage. Limited-entry completions in vertical wells are designed to avoid unwanted fluid production, such as gas from an overlying gas cap or water from an underlying aquifer. The effects of limited entry may be seen in perforated and gravel-packed wells when some of the perforations fail to clean up. This is also called a partial completion.The limited entry also results from partial penetration, which occurs when the productive formation is only partly drilled. This partial penetration represents a near-well flow restriction that results in a positive skin effect in a well-test analysis.

An injection pattern in which the injection wells are located in a straight line parallel to the production wells. In a line drive pattern, the injected fluid, which is normally water, steam or gas, creates a nearly linear frontal movement. A line drive pattern is also called direct line drive.

The solution to differential equations treating the well as a vertical line through a porous medium. The solution is nearly identical to the finite-wellbore solution. At very early times, there is a notable difference in the solutions, but the differences disappear soon after a typical well is opened to flow or shut in for a buildup test, and in practice the differences are masked by wellbore storage.

A synthetic hydrocarbon liquid made by the polymerization of ethylene, H2C=CH2. LAOs and other synthetic fluids are used in synthetic-base drilling fluids and other applications in which refined oils might otherwise be used if not for HSE concerns. LAOs have a linear structure with a double bond (olefin) at the end of the chain, making them more biodegradable than other olefins. LAOs can be catalytically reacted to move the double bond toward the center of the chain length to convert them to isomerized olefins, IOs.

A flow regime characterized by parallel flow lines in the reservoir. This results from flow to a fracture or a long horizontal well, or from flow in an elongated reservoir, such as a fluvialchannel, or as a formation bounded by parallel faults. Linear flow is recognized as a +1/2 slope in the pressure derivative on the log-log diagnostic plot. Its presence enables determination of the fracture half-length or the channel or reservoir width, if permeability can be determined independently.

What Is a Liner? A liner is a string of casing that does not extend to the surface but instead anchors to and hangs from the inside of the previous casing string, covering open wellbore from a point inside the host casing shoe down to the total depth or target production interval. Operators deploy liners to isolate troublesome formations, complete producing zones, and control well costs by running steel only where the wellbore demands it. Key Takeaways A liner is a casing string whose top terminates inside a previously run casing string rather than at the surface, suspended by a liner hanger. The liner overlap, typically 100 to 300 m (328 to 984 ft), is the length of liner inside the host casing; proper cement coverage across this section is critical for zonal isolation. Four principal liner types exist: drilling liner, production liner, tieback liner, and scab liner, each serving a distinct engineering function. Liner cementing must achieve pressure integrity from the casing shoe to the top of the liner to satisfy regulatory well-barrier requirements in all major jurisdictions. When a tieback string is subsequently run to surface, the combined assembly behaves identically to a full casing string, giving operators flexibility to defer that cost until it is operationally warranted. How a Liner Works When a rig drills below the shoe of the previous casing string, the new open hole section must eventually be isolated. Rather than running a full casing string from the wellhead to total depth (TD), which requires additional surface equipment, heavier hoisting loads, and more steel, the operator makes up a liner on the drill floor and runs it on a drill-pipe running string to the target setting depth. A liner hanger at the top of the liner string is positioned 100 to 300 m (328 to 984 ft) inside the host casing; when actuated, slips on the hanger grip the host casing inner wall and transfer the liner's weight to the host string rather than to the wellhead. The liner hanger simultaneously includes a packoff or seal element that isolates the liner-casing annulus during cementing operations. Once the liner hanger is set and the running string is released, the cementing operation begins. A calculated volume of cement slurry is pumped down the drill pipe, through the liner interior, out the float shoe or float collar at the liner toe, and up the annulus between the liner outer diameter and the open hole. A cementing plug driven behind the slurry displaces the cement out of the liner bore. The slurry must fill the annulus from the liner shoe up through the overlap zone to the top of the liner, where a cement plug or packer mechanically isolates the annular space from the wellbore interior. API 10A specifies cement slurry design requirements, and API RP 10D-2 addresses cement evaluation for liners. After the cement achieves compressive strength, typically 12 to 24 hours for Class G or Class H slurries, the operator pressure-tests the liner to confirm integrity before resuming operations. Liner selection relies on the same design criteria as any casing string: burst, collapse, tension, and compression ratings must be satisfied across all anticipated wellbore conditions. API 5CT specifies the steel grades used: J-55 and K-55 for shallow, low-pressure intervals; N-80 and L-80 for moderate depths or sour service; P-110 and Q-125 for high-pressure, high-temperature (HPHT) wells. In sour-gas environments containing hydrogen sulfide (H2S), operators must specify sour-service grades per NACE MR0175 / ISO 15156 to prevent sulfide stress cracking. Wall thickness selection follows the Lame burst equation for internal pressure and Barlow's formula for collapse, with design factors typically 1.1 to 1.25 applied to burst and 1.0 to 1.125 applied to collapse, consistent with API TR 5C3 and operator-specific casing design manuals. Liner Types Across International Jurisdictions Drilling Liner A drilling liner is set across unstable or high-pressure formations encountered while drilling to a deeper objective. Typical applications include reactive shales that swell and close the wellbore, abnormally pressured sand bodies that require isolation before the mud weight is reduced, or salt sections that creep and deform standard casing. By setting a drilling liner through the troublesome interval, the operator can resume drilling the deeper section with a smaller bit and casing program without the cost or delay of running a full string to surface. In Alberta's Deep Basin and Montney trend, drilling liners are common through the Fernie and Nikanassin shale formations before landing the wellbore in the Montney. Alberta Energy Regulator (AER) Directive 009, "Casing Requirements for Oil and Gas Wells," mandates that all casing and liner strings isolate formation fluids from fresh water zones and other geological zones that could be adversely affected by well operations, and that liner tops be pressure-tested to 70% of the internal yield pressure of the liner or 3,500 kPa (507 psi), whichever is less, as applicable to the liner design. Production Liner A production liner is set across the hydrocarbon-bearing interval after the well has reached total depth. It provides the conduit through which reservoir fluids will flow during the production phase, and it carries all perforations, completion hardware, and fracture stimulation ports. In unconventional multi-stage completions, a production liner is equipped with sliding sleeves, swell packers, or hydraulic-fracturing port collars spaced at intervals of 50 to 100 m (164 to 328 ft) along the lateral. The Bureau of Safety and Environmental Enforcement (BSEE) under 30 CFR Part 250 requires that deepwater Gulf of Mexico production liners be designed to withstand maximum anticipated surface pressure (MASP) plus a 500 psi (3,447 kPa) safety margin, and that a cement bond log (CBL) or similar cement evaluation log be run and evaluated before completing the well. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) in Australia imposes similar well-integrity standards under the Offshore Petroleum and Greenhouse Gas Storage (OPGGS) Act for production liners in the Carnarvon and Browse basins, with cement tops verified by temperature surveys or cement evaluation logs. Tieback Liner (Extension Liner) A tieback liner, also called a tieback string or extension liner, is run after a drilling liner has been set to extend the liner to surface, converting the partial liner into a full casing string. The tieback string stabs into a tieback receptacle (TBR) or liner top packer at the top of the existing liner hanger and is landed and cemented at the wellhead. Operators in the Norwegian North Sea frequently run tieback liners on subsea wells after confirming the drilling liner integrity, because running the tieback immediately avoids a second mobilization. NORSOK D-010, "Well Integrity in Drilling and Well Operations," classifies the tieback as a primary well barrier element and requires a barrier verification test after installation. Tieback liners are also common in West Texas Permian Basin horizontal wells where the operator wants the flexibility of assessing the lateral before committing to surface casing weight. Scab Liner A scab liner is a short casing patch run inside existing production casing to repair a leak, corroded section, or mechanically damaged zone without pulling the entire casing string. Scab liners are typically 30 to 150 m (98 to 492 ft) long and are cemented in place or expanded against the host casing wall using a swage tool. Saudi Aramco's Reservoir Management (EXPEC) engineering standards recognize scab liner repairs as an approved workover technique for Ghawar field carbonate wells where casing corrosion from CO2-laden produced water is a chronic issue. AER Directive 020 requires that any casing repair maintain pressure integrity equivalent to the original design criteria and that the repair be reported in the well record. Fast Facts Overlap length: 100 to 300 m (328 to 984 ft) inside host casing is the industry-standard overlap for liner hangers. Steel savings: A 3,000 m (9,843 ft) production liner replaces a full 4,500 m (14,764 ft) surface-to-TD string, cutting steel cost by roughly one-third. Cement top verification: Temperature surveys, CBL/VDL logs, or ultrasonic cement evaluation tools confirm cement placement to the top of liner. Common liner sizes: 4-1/2 in. (114 mm) and 5-1/2 in. (140 mm) production liners in tight-oil laterals; 7 in. (178 mm) and 9-5/8 in. (244 mm) drilling liners in deep vertical wells. Liner hanger load: Combined liner weight plus buoyed cement slurry weight during placement can exceed 500 kN (112,000 lbf) on large-diameter deep liners. Liner Cementing and Zonal Isolation Achieving pressure integrity across the liner overlap is the most critical element of any liner program. The cement slurry must displace drilling fluid from the narrow annular gap between the liner outside diameter and the host casing inside diameter, a space that can be as tight as 6 mm (0.25 in.) on inside-flush connections. Centralizers placed along the liner body reduce standoff eccentricity and improve mud displacement efficiency. Industry best practice per API RP 65-2 and the Society of Petroleum Engineers (SPE) recommends a minimum of 67% standoff in deviated wellbores and the use of turbulent-flow or plug-flow cement placement when the annular clearance is less than 19 mm (0.75 in.). Cement design for liner applications differs from open-hole cementing because the slurry must also traverse the liner-casing overlap without channeling through mud cake or gelled drilling fluid. Pre-flushes (chemical washes and spacer fluids) are pumped ahead of the cement slurry to break up filter cake, water-wet the surfaces, and create a compatible transition between the drilling fluid and cement. Spacer density is typically designed to be between the drilling fluid density and the cement slurry density to provide a graduated hydrostatic gradient and avoid u-tubing. For Montney multi-stage fracturing liners in Alberta, operators commonly design slurry with a density of 1,850 to 1,950 kg/m3 (15.4 to 16.2 lb/gal) using Class G cement with silica flour added for thermal stability above 110 deg C (230 deg F). A liner top packer or external casing packer (ECP) placed at the top of the liner immediately below the liner hanger packoff provides a backup mechanical seal in the event that primary cement fails to reach the liner top. This redundancy is required by NORSOK D-010 for all high-pressure gas wells where the liner top represents a barrier between the formation and a lower-integrity annulus. Following cement placement, the operator performs a liner-top integrity test (LTIT) by pressuring up against the closed-off liner annulus to verify no leak path exists. AER Directive 009 specifies a minimum test pressure equal to the maximum anticipated wellbore pressure at the liner top plus a safety margin, or 3,500 kPa (507 psi), whichever is greater.

What Is a Liner Hanger? A liner hanger is a downhole mechanical device that anchors a liner string at the bottom of the previously run casing string, transferring the combined weight of the liner and cement slurry from the liner body to the host casing wall through a set of hardened steel slips that grip the casing inner diameter when actuated by hydraulic pressure or mechanical rotation. Without a reliable liner hanger, suspended liner strings would fall to bottom under their own weight. Key Takeaways A liner hanger anchors a liner string inside the host casing string using slips that engage the casing inner diameter, bearing hanging loads that can exceed 1,361 metric tonnes (1,500 short tons) on large-diameter deepwater liners. Hydraulic liner hangers, set by applying surface hydraulic pressure to actuate a cone-and-slip mechanism, are the industry standard for deep, deviated, and HPHT wells where mechanical rotation cannot reliably be applied. The packoff seal element at the top of the liner hanger isolates the liner-casing annulus from the wellbore bore during cement placement, preventing cement from bypassing into the upper annulus ahead of schedule. Liner top packers (LTPs) and tieback receptacles (TBRs) can be integrated into the liner hanger assembly, providing enhanced annular sealing for high-pressure gas wells and a stabbing point for future tieback string installation. Regulatory frameworks in Canada (AER Directive 009), the United States (30 CFR Part 250), Australia (NOPSEMA), and Norway (NORSOK D-010) all classify the liner hanger as a primary well barrier element requiring function testing before the well is placed on production. How a Liner Hanger Works A liner hanger assembly is made up on the drill floor as the top component of the liner string, with the running tool stabbed into the hanger body from above and connected to the drill-pipe running string. The complete liner assembly, hanger body, packoff element, and liner joints below, is lowered through the blow-out preventer stack and into the wellbore on drill pipe, maintaining careful tally of pipe joints to confirm the setting depth when the liner hanger reaches its designed position inside the previous casing shoe. The target overlap depth is typically 100 to 300 m (328 to 984 ft) inside the host casing, providing sufficient grip length on a known, pressure-tested casing string. Once the assembly reaches the setting depth, the operator actuates the liner hanger. In a hydraulic hanger, the drill crew drops a ball from surface which seats on a ball seat inside the running tool, blocking flow through the drill string. Surface pump pressure is then applied until it reaches the hanger's rated setting pressure, commonly 10.3 to 13.8 MPa (1,500 to 2,000 psi), which drives a piston that forces a tapered cone downward, outwardly expanding a set of slips against the host casing wall. The serrated faces of the slips, machined from hardened alloy steel at a hardness of 55 to 65 HRC, bite into the casing inner diameter. When set, the hanger resists both downward load from liner weight and upward load from hydraulic pressure during fracture stimulation, which can reach 69 to 103 MPa (10,000 to 15,000 psi) in modern unconventional completions. The packoff element, an elastomeric or metal-to-metal ring located immediately above the slip assembly, seals the annulus between the hanger outer diameter and the host casing inner diameter. This seal confines cement slurry to the designed cement column below and prevents cement from filling the upper annulus above the liner top, where it could create well control complications during future wellhead work. After the slips are confirmed set through hook-load changes on the surface weight indicator, the running tool is released by right-hand rotation or by applying additional pressure to a collet release mechanism, and the drill string is picked up above the liner to the cement pumping position before the cement job begins. API Spec 11D1 and ISO 14310 define performance verification requirements for liner hanger systems, including rated load, pressure containment, and temperature ratings that manufacturers must test and publish. Liner Hanger Types Across International Jurisdictions Mechanical Liner Hanger A mechanical liner hanger is set by surface manipulation of the drill string, typically by applying 5 to 20 clockwise rotations of the drill pipe at the surface, which transmits torque through the running tool to engage a J-slot or ratchet mechanism that pushes the slip cone downward and sets the slips against the host casing. Some designs set on downward weight rather than rotation. Mechanical hangers require no wellbore pressure to set and are simpler than hydraulic designs because they have fewer downhole hydraulic components, reducing the risk of component failure. Their primary limitation is reliability in deviated or horizontal wellbores: below approximately 30 to 40 degrees of inclination, drill-pipe torque transmission becomes inconsistent, and there is no certainty that the rotation applied at surface is fully transmitted to the hanger setting mechanism. For this reason, mechanical hangers are most commonly used in vertical and near-vertical wells in conventional plays. In Alberta's conventional Viking and Cardium oil plays, where well depths are typically 1,000 to 2,500 m (3,281 to 8,202 ft) and deviations rarely exceed 15 to 20 degrees, mechanical liner hangers remain common on production liners because they are cost-effective, readily available from local supply yards, and sufficient for the well conditions. Alberta Energy Regulator (AER) Directive 009 requires a pressure test of the liner top after cementing regardless of hanger type, but the standard itself does not prescribe hydraulic versus mechanical actuation for low-risk wells. Hydraulic Liner Hanger A hydraulic liner hanger is set by applying hydraulic pressure to the drill string after a ball has been dropped from surface and seated on a ball seat in the running tool below the liner hanger body. The hydraulic piston translates pressure into a downward mechanical force on the cone, expanding the slips against the casing wall with a consistent, measurable setting force that is independent of wellbore inclination, drag, or torque. This reliability across all inclination angles makes hydraulic hangers the default choice for all directional and horizontal wells and for any well where uncertainty about downhole torque transmission would make mechanical setting unreliable. In the deepwater Gulf of Mexico, Bureau of Safety and Environmental Enforcement (BSEE) regulations under 30 CFR Part 250, Subpart D require that liner hanger systems for production wells be designed and tested to withstand the maximum anticipated surface pressure (MASP) with an appropriate safety factor, and that a cement evaluation log be run and reviewed by the lessee before the well is placed on production. Deep water adds complexity because subsea wellheads are accessed through long drill-string runs with high drag, making hydraulic actuation essential. Baker Hughes, Halliburton, and SLB (formerly Schlumberger) all offer hydraulic liner hanger systems rated to 103 MPa (15,000 psi) and 204 deg C (400 deg F) for the extreme HPHT conditions in plays such as the Norphlet and Wilcox trends in the deepwater Gulf of Mexico. Expandable Liner Hanger An expandable liner hanger uses a different load transfer mechanism: instead of discrete slip elements that point-load the casing wall, a cone is driven through a tubular sleeve, radially expanding the sleeve in a controlled, circumferentially uniform pattern until it contacts the host casing inner wall along its full length. The result is a large contact area that spreads the load across the casing, reducing stress concentration. Expandable hangers achieve very high load ratings, up to 2,268 metric tonnes (2,500 short tons) in some designs, and they also provide a pressure seal across the overlap zone without a separate packoff element. They are particularly valued in wells with irregular host casing inner diameters caused by wear, corrosion, or eccentric running, where conventional slip systems may not achieve full contact around the circumference. Saudi Aramco has adopted expandable liner hanger technology for deep Khuff carbonate wells in the Ghawar field, where wellbore temperatures exceed 150 deg C (302 deg F) and H2S partial pressures require specialized metallurgy throughout the liner assembly. NORSOK D-010, published by Standards Norway, requires that all liner hanger systems on the Norwegian Continental Shelf be qualified against a defined well barrier test matrix, including function tests at maximum and minimum temperature, load tests to rated capacity, and a sealing verification under both working and MAWOP (maximum allowable wellhead operating pressure) conditions. Expandable liner hangers that meet these criteria are regularly deployed on Equinor and Aker BP wells in the North Sea. Fast Facts Typical setting pressure: Hydraulic liner hangers set at 10.3 to 13.8 MPa (1,500 to 2,000 psi) applied at surface after ball drop. Load ratings: Standard liner hangers carry 91 to 454 metric tonnes (100 to 500 short tons); heavy-duty deepwater designs reach 1,361 metric tonnes (1,500 short tons). Slip hardness: Liner hanger slips are typically machined from 4140 or 4145 alloy steel and heat-treated to 55 to 65 HRC to bite through the casing hardness. Ball seat material: Drop balls in hydraulic systems are typically aluminum or composite, dissolving or milling out easily after setting so full bore is restored for completion fluid circulation. Temperature ratings: HPHT liner hanger systems are qualified to 204 deg C (400 deg F), with ultra-HPHT designs to 260 deg C (500 deg F) for geothermal and deep sedimentary basin applications. Liner Hanger Components and Setting Mechanics in Detail A complete liner hanger assembly consists of several subcomponents that work together to anchor, seal, and allow cement placement through the liner. The body is the main structural tube that connects the running tool above to the top joint of the liner string below; it carries the cone profile on its outer surface and is manufactured from AISI 4140 or 4145 low-alloy steel heat-treated to yield strengths of 689 to 862 MPa (100,000 to 125,000 psi). The slips are three or more arcuate segments of hardened steel with wicker teeth on their outer face; they ride on the cone profile and are held retracted during run-in by a shear ring or collet that releases when the setting force is applied. The cone is a tapered steel ring that translates the axial setting force into a radial outward force on the slips; a shallow taper angle, typically 15 to 22 degrees, provides a mechanical advantage that amplifies the hydraulic force. The packoff element, located immediately above the slips, can be a bonded elastomeric O-ring or T-seal for standard service or a metal-to-metal interference ring for HPHT service where elastomers are unreliable above 150 deg C (302 deg F). In hydraulic designs, the hydraulic chamber is a sealed annular piston space between the running tool and the hanger body. When surface pressure acts on the ball-and-seat, the pressure is communicated to this chamber through cross-ports in the running tool, driving the piston and the attached cone downward with a force equal to the net piston area multiplied by the applied pressure. A piston area of 32 cm2 (5 in2) at a setting pressure of 13.8 MPa (2,000 psi) produces approximately 44 kN (10,000 lbf) of setting force, more than sufficient to drive the cone under the slips and achieve full contact with the casing wall. After setting, a release mechanism, usually a J-slot that disengages when the drill string is rotated a quarter turn to the right and then picked up, separates the running tool from the hanger body so the running string can be retrieved to the cementing position inside the liner. The tieback receptacle (TBR), when included in the design, is a polished bore machined into the inside of the upper hanger body with a profile compatible with a tieback seal assembly. The tieback string, run at any point after primary cementing is complete, stabs a seal unit into the TBR and locks into a latch coupling, converting the suspended liner into a full casing string tied back to the wellhead. This feature gives operators the option to defer tieback costs until they have confirmed that the well is commercial, while retaining the ability to tie back if needed for production or well integrity reasons. The liner top packer (LTP) option adds an inflatable or compression-set packer element between the hanger body and the tieback receptacle; when set, it provides a secondary annular seal in addition to the primary cement and packoff seals, satisfying NORSOK D-010 dual well barrier requirements for high-pressure gas wells on the Norwegian Continental Shelf.

Pertaining to an attraction for oil by a surface of a material or a molecule. This term is applied to the oil-wetting behavior of treatment chemicals for oil muds. Lipophilic oil-mud additives are required because most minerals drilled and additives such as barite are naturally hydrophilic and must be rendered lipophilic.

Natural gas, mainly methane and ethane, which has been liquefied at cryogenic temperatures. This process occurs at an extremely low temperature and a pressure near the atmospheric pressure. When a gas pipeline is not available to transport gas to a marketplace, such as in a jungle or certain remote regions offshore, the gas may be chilled and converted to liquefied natural gas (a liquid) to transport and sell it. The term is commonly abbreviated as LNG.

A sea vessel used to transport liquefied petroleum gas (LPG). The term is commonly abbreviated as LNGC

Gas mainly composed of propane and butane, which has been liquefied at low temperatures and moderate pressures. The gas is obtainable from refinery gases or after the cracking process of crude oil.Liquefied petroleum gas is also called bottle gas. At atmospheric pressure, it is easily converted into gas and can be used industrially or domestically. The term is commonly abbreviated as LPG.

A material used in a liquid form to modify the properties of cement for use in oil- or gas-well cementing.

A phenomenon encountered during dry forward combustion in which an oil zone around the production well cannot be pushed forward by the heated oil. The fluid located in this zone is still at the original reservoir temperature. Therefore, the fluid is still highly viscous and normally not mobile.

A hygroscopic liquid used to remove water and water vapor from a gas stream. Some liquid desiccants are glycols (diethylene, triethylene and tetraethylene), which are substances that can be regenerated. Regeneration means that the water absorbed by these substances can be separated from them. Some liquid desiccants, such as methanol or ethylene, cannot be regenerated.

Liquid compounds such as propanes, butanes, pentanes and heavier products extracted from the gas flowstream.

The depth at which the first liquid is found in a well.

A technique for measuring the pore volume of a core sample from the difference in its weight when dry and when saturated with a liquid. A clean, dry sample is weighed and then evacuated for several hours in a vacuum chamber, flushing with CO2 to remove remaining air if necessary. A de-aerated liquid is introduced into the chamber and pressured to ensure complete saturation. The saturated sample is then weighed again. The difference in weight divided by the density of the liquid is the connected, or effective, pore volume.It is also common to measure the weight of the sample when immersed in the liquid. The grain and bulk volume can then be calculated as in the buoyancy method.

The electromagnetic force generated by a boundary between solutions of high salinity and low salinity. In a permeableformation, a liquid-junction potential is generated between the invaded zone and the undisturbed zone when the mudfiltrate and the formation water have different salinities. This potential is one component of the electrochemical potential, from which the spontaneous potential log is derived. The other, much larger component is the membrane potential at a shale boundary. The liquid-junction potential is reduced if there is clay in the permeable formation, since this generates another, local membrane potential with the opposite polarity to the liquid-junction potential.

The process by which unconsolidated sediments become sedimentaryrock. Sediments typically are derived from preexisting rocks by weathering, transported and redeposited, and then buried and compacted by overlying sediments. Cementation causes the sediments to harden, or lithify, into rock.

A mappable subdivision of a stratigraphic unit that can be distinguished by its facies or lithology-the texture, mineralogy, grain size, and the depositional environment that produced it.

The surface that separates rock bodies of different lithologies, or rock types. A contact can be conformable or unconformable depending upon the types of rock, their relative ages and their attitudes. A fault surface can also serve as a contact.

The macroscopic nature of the mineral content, grain size, texture and color of rocks.

The brittle outer layer of the Earth that includes the crust and uppermost mantle. It is made up of six major and several minor tectonic plates that move around on the softer asthenosphere. The lithosphere of the oceans tends to be thinner (in some oceanic areas, less than 50 km [30 miles] thick) and more dense than that of the continents (more than 120 km [70 miles] thick in places like the Himalayas) because of isostasy. The movement of the plates of the lithosphere results in convergence, or collisions, that can form mountain belts and subduction zones, and divergence of the plates and the creation of new crust as material wells up from below separating plates. The lithosphere and asthenosphere are distinguished from the crust, mantle and core of the Earth on the basis of their mechanical behavior and not their composition.

The pressure of the weight of overburden, or overlying rock, on a formation; also called geostatic pressure.

A seismic inversion technique that attempts to describe lithology of individual rock layers and evaluate properties and distribution of pore fluids through analysis of variation of reflected seismic amplitude with offset.

The study and correlation of strata to elucidate Earth history on the basis of their lithology, or the nature of the well log response, mineral content, grain size, texture and color of rocks.

Pertaining to an environment of deposition affected by tides, the area between high tide and low tide. Given the variation of tides and land forms from place to place, geologists describe littoral zones locally according to the fauna capable of surviving periodic exposure and submersion.

A term used to describe a cementslurry that remains liquid but is still capable of thickening or setting to become an unmovable solid mass. Some remedial operations treat the excess live cement slurry with a contaminant to extend the thickening time and allow its safe removal from the wellbore.

Oil containing dissolved gas in solution that may be released from solution at surface conditions. Live oil must be handled and pumped under closely controlled conditions to avoid the risk of explosion or fire.

The sensor component in a weight-indicator system that detects the tensional or compressional forces being imparted to the running string at surface. Load cells are hydraulically or electronically operated and are connected to the weight-indicator display system on the equipment operator's console.

Oil pumped into a wellbore in preparation for, or as part of, a treatment. Some treatments, such as hydraulic fracturing, involve pumping large volumes of fluid. Using load oil, often produced and processed from adjacent wells in the field, reduces the cost of fluids and can enhance the cleanup process when the treatment is complete.

The amount of local personnel, material and services that working interest owners are required to employ when drilling and operating a well, as specified under the terms of a concession agreement.

The fraction of a particular fluid measured in the vicinity of a small probe in a production well. The small, or local, probes respond digitally to the type of fluid in front of them, indicating gas, oil or water depending on the type of probe. The local holdup of oil, for example, is determined by the percentage of time the probe spends in front of oil.

A small sensor, part of a productionlogging tool, which determines the type of fluid in its vicinity as it moves up and down a production well. Typically there are four or more sensors, or probes, held on arms to measure the four quadrants of the well cross-section. The probes may be electrical, to distinguish hydrocarbon from water; optical, mainly to distinguish gas from liquid, but also oil from water; or dielectric, mainly to distinguish water from hydrocarbon, but also, with less resolution, oil from gas. They can detect bubbles that are larger than about 1 mm diameter. Their response is essentially digital, indicating either one fluid or the other, so that the percentage of time that they see a fluid is a direct measure of its holdup. The rate of change between the two fluids is known as the bubble count.The results can be averaged to give the mean holdup and bubble count, or converted into an image, showing the holdup or bubble count at different locations across the well at different depths. The image is particularly useful in highly deviated or horizontal wells where different flow regimes may be found in different quadrants.

A downhole device, run and retrieved on slickline, that is placed and anchored within the tubing string to provide a setting point for flow-control equipment such as valves, chokes and plugs. The three main types of lock use different means of locating and securing: a slip lock locates and anchors anywhere within the correct size of tubing; the collar lock locates in the space within tubing collars; and the nipple lock locates within completion nipple profiles.

(noun) A tubing-mounted receptacle with an internal locking profile that accepts and secures a flow-control device (such as a gas lift valve, chemical injection valve, or dummy valve) delivered and retrieved by wireline. The lock mandrel provides a gas-tight seal and mechanical anchor for the installed device.

A condition that may occur when a coiled tubing string is run into a horizontal or highly deviated wellbore. Lock-up occurs when the frictional force encountered by the string running on the wellbore tubular reaches a critical point. Although more tubing may be injected into the wellbore, the end of the tool string cannot be moved farther into the wellbore.

Associated with the information from a log. For example, a log print is a paper print on which log data have been recorded.

The average value of a set of measurements, calculated by taking the logarithms of the measurements, finding the arithmetic average of the logarithms and then taking the antilogarithm of the average.

(noun) The practice of acquiring continuous measurements of formation and borehole properties as a function of depth using specialised instruments conveyed on wireline, drillpipe, coiled tubing, or permanently installed fibre optic cables. Logging provides essential data for formation evaluation, reservoir characterisation, and well integrity assessment.

An operation in which a logging tool is lowered into a borehole and then retrieved from the hole while recording measurements. The term is used in three different ways. First, the term refers to logging operations performed at different times during the drilling of a well. For example, Run 3 would be the third time logs had been recorded in that well. Second, the term refers to the number of times a particular log has been run in the well. Third, the term refers to different runs performed during the same logging operation. For example, resistivity and nuclear logs may be combined in one tool string and recorded during the first run, while acoustic and nuclear magnetic resonance logs may be recorded during the second run.

The downhole hardware needed to make a log. The term is often shortened to simply "tool." Measurements-while-drilling (MWD) logging tools, in some cases known as logging while drilling (LWD) tools, are drill collars into which the necessary sensors and electronics have been built.Wireline logging tools are typically cylinders from 1.5 to 5 in. [3.8 to 12.7 cm] in diameter. Since the total length is more than can be conveniently handled in one piece, the logging tool is divided into different sections that are assembled at the wellsite. These sections consist of cartridges and sondes. Different measurements can be combined to make up a tool string. The total length of a tool string may range from 10 to 100 ft [3 to 30 m] or more. Flexible joints are added in long tool strings to ease passage in the borehole, and to allow different sections to be centralized or eccentralized. If the total length is very long, it is often preferable to make two or more logging runs with shorter tool strings.

The cabin that contains the surface hardware needed to make wirelinelogging measurements. The logging unit contains at the minimum the surface instrumentation, a winch, a depth recording system and a data recorder. The surface instrumentation controls the logging tool, processes the data received and records the results digitally and on hard copy. The winch lowers and raises the cable in the well. A depth wheel drives the depth recording system. The data recorder includes a digital recorder and a printer.

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

A type of multiply-reflected seismic energy that appears as an event. Long-path multiples generate distinct events because their travel path is much longer than primary reflections giving rise to them. They typically can be removed by seismic processing.

A sonic tool with a longer transmitter-to-receiverspacing (generally 10 to 15 ft) than a standard sonic tool. The rock near the borehole is sometimes altered by drilling fluids, stress relief, or both, causing a thin zone whose velocity is lower than that of the true formation. With standard spacings, the wave traveling through the altered zone may arrive first at the receiver, since this zone is closer to both transmitter and receiver. The increased spacing permits the wave traveling through the true formation to arrive first and be measured. The depth of investigation varies with slowness and transmitter-receiver spacing but is of the order of 2 to 3 ft. An increased transmitter-to-receiver spacing also allows better separation of waveforms relating to different acoustic waves, such as compressional, shear and Stoneley arrivals.

A plot of the longitudinal component of the dip vector computed from a dipmeter. Longitudinal plots are used in the SCAT (Statistical Curvature Analysis Technique) method of interpreting dipmeter data for geologicalstructure. They are especially useful in doubly plunging dip situations.

During a nuclear magnetic resonance measurement, the loss of energy by hydrogen atoms in a rock as they align themselves with the static magnetic field. The atoms behave like spinning bar magnets so that when a static magnetic field is applied, they initially precess about the field. Then, through interactions with nuclei and electrons, they lose energy, or relax, and align themselves with the magnetic field. The relaxation of the hydrogen atoms does not occur immediately but grows exponentially with a time constant T1. There are two mechanisms for longitudinal relaxation, surface relaxation and bulk relaxation.

An emulsion with large and widely distributed droplets. A loose emulsion can be easy to break.

What Is Lost Circulation? Lost circulation occurs when drilling fluid pumped down the drillstring flows out of the wellbore into the surrounding formation rather than returning to surface through the annulus, signaled by a reduction or complete cessation of mud returns at the shale shakers. The condition destabilizes hydrostatic pressure, threatens well control, and can consume millions of dollars in non-productive time and lost drilling fluid inventory on a single well. Key Takeaways Lost circulation is classified by severity: seepage losses below 10 barrels per hour (1.6 cubic metres per hour), partial losses of 10 to 100 barrels per hour (1.6 to 15.9 m3/hr), severe losses of 100 to 250 barrels per hour (15.9 to 39.7 m3/hr), and total losses above 250 barrels per hour (39.7 m3/hr). Causes include pre-existing natural fractures, drilling-induced fractures when equivalent circulating density (ECD) exceeds the formation fracture gradient, vugular carbonate cavities, and highly permeable gravel or rubble zones. Lost circulation materials (LCM) are sized and selected based on estimated fracture width or pore throat size, with the D90 bridging rule specifying LCM particle size at one-third or less of the fracture width to form a stable bridge. Simultaneous loss of circulation and influx of formation fluids (a kick) represents the most dangerous dual-problem scenario in drilling, requiring immediate crew response under the well's emergency response plan. Managed pressure drilling (MPD) reduces lost circulation in narrow mud-weight-window formations by applying surface backpressure to maintain equivalent circulating density within the fracture gradient envelope. How Lost Circulation Works During normal drilling operations, the drilling fluid column exerts hydrostatic pressure on the borehole wall equal to the product of mud weight and true vertical depth. When the drillstring is rotating and fluid is being circulated, friction adds an additional pressure component to produce the equivalent circulating density (ECD), expressed in pounds per gallon (lb/gal) or kilograms per cubic metre (kg/m3). If ECD exceeds the fracture gradient of the weakest exposed formation, the wellbore wall fractures and drilling fluid is injected into the newly opened fracture. Alternatively, if the drill bit penetrates a naturally fractured interval, a vugular carbonate cavity, or a high-permeability gravel zone, whole mud flows into the available void space. In both cases, the volume of mud in the annulus decreases, reducing hydrostatic head and potentially creating an underbalanced condition that allows formation fluids to enter the wellbore, turning a lost circulation event into a well control emergency. See well control for the response procedures that govern such scenarios. The drilling team monitors for lost circulation by tracking pit gain and pit loss on the mud volume totalizer, monitoring return flow rate against pump rate, and watching for changes in pump pressure. A sudden drop in pump pressure combined with reduced annular returns is the primary indicator of a thief zone. The driller immediately reduces pump rate to lower ECD, raises the mud weight alarm, and notifies the company man (drilling supervisor). The first diagnostic is to determine whether the loss is seepage (gradual, manageable with LCM additions to the active system) or partial-to-total (requiring a dedicated pill treatment or cement squeeze). In total loss situations with no returns, the driller maintains the blowout preventer in a ready state while attempting to restore hydrostatic pressure through an engineering squeeze program. Wellbore ballooning, also called wellbore breathing, is a reversible phenomenon that mimics lost circulation but has a different mechanism. In tight formations drilled slightly above fracture gradient, elastic fractures open during pump-on circulation and close when pumps are shut down, returning fluid to the annulus. A ballooning well appears to gain fluid when pumps stop, which is opposite to a kick; a shut-in drill pipe pressure (SIDPP) and shut-in casing pressure (SICP) reading of zero after pump shutdown confirms ballooning rather than a kick. Ballooning is managed by reducing ECD through lower mud weight, reduced pump rate, or MPD backpressure control. It does not require LCM treatment but signals the operator is drilling very close to the fracture gradient and any increase in ECD may convert the reversible event into an induced fracture loss. Lost Circulation Across International Jurisdictions Canada: AER Directive 036 and Alberta Formations The Alberta Energy Regulator (AER) governs well construction through Directive 036 (Drilling Blowout Prevention Requirements and Procedures) and Directive 008 (Surface Casing Depth Requirements). Directive 036 requires operators to document lost circulation events exceeding 50 barrels (7.95 m3) per event and to have an approved well control contingency plan before spudding. The Duvernay Formation in west-central Alberta is notorious for severe lost circulation when drilling through natural fracture networks in the over-pressured shale section; operators typically use a staged approach of diesel oil bentonite (gunk) squeezes and microfine cement treatments before setting the intermediate casing string. The Devonian Leduc and Beaverhill Lake carbonate reefs of central Alberta present vugular porosity and natural fracture permeabilities exceeding 10 darcies, where total losses with no surface returns are common during initial penetration of the reef. The Montney tight siltstone in the Peace River Arch area experiences ECD-induced fracture losses when operators push penetration rates, requiring ECD management software such as HydraCalc or comparable tools to keep circulating pressure below the fracture gradient in the relatively narrow window between pore pressure and fracture pressure in this formation. United States: BSEE and Deepwater Operations The Bureau of Safety and Environmental Enforcement (BSEE) regulates well control and casing design under 30 CFR Part 250 on the Outer Continental Shelf. BSEE regulations require operators to submit an Application for Permit to Drill (APD) that includes a casing and cementing program designed to prevent lost circulation, and to notify BSEE of any well control event including uncontrolled lost circulation that results in the shutdown of drilling operations. Deepwater Gulf of Mexico (GOM) wells present a particularly narrow mud weight window because the seafloor sediment fracture gradient is extremely low (often equivalent to 8.7 to 9.0 lb/gal, or 1,042 to 1,078 kg/m3 in water depth exceeding 1,500 metres / 4,921 feet). The shallow hazard zone in deepwater GOM, known colloquially as the "narrow pore-frac window," drives the design of dual-gradient drilling systems and subsea mudlift systems that decouple the hydrostatic riser pressure from the wellbore ECD. The Permian Basin in West Texas encounters karst dissolution features in Wolfcamp and Bone Spring carbonates where catastrophic vugular losses require purpose-built LCM programs using coarse granular materials at concentrations of 50 to 75 pounds per barrel (142 to 214 kg/m3). Australia: NOPSEMA and Carnarvon Basin The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) requires operators to include a Lost Circulation Management Program in their Well Operations Management Plan (WOMP) submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. The Carnarvon Basin offshore Western Australia, which hosts Woodside's Scarborough and Browse gas fields, encounters shallow hazard carbonate shoals and bioherm structures at relatively shallow depths below the seabed where lost circulation risks are highest. The Barrow Island area, operated by Chevron for the Gorgon LNG project, presents fractured basement granites beneath Cretaceous sediments where natural fracture permeability can cause partial to severe losses at depth. NOPSEMA requires a well control manual endorsed by a competent drilling engineer, and all lost circulation events that required a well control response must be reported through the Industry Reporting System within 3 days. Onshore operations in the Cooper-Eromanga Basin of South Australia encounter fractured Permian and Triassic sandstones with natural fracture systems that respond well to fibrous LCM treatments. Middle East: Saudi Aramco and Carbonate Challenges Saudi Aramco's operations in the massive Khuff carbonate formation (Permian age) and the Arab-D limestone reservoir of Ghawar present chronic lost circulation challenges due to natural fracture networks, dissolution vugs, and super-permeability streaks. Saudi Aramco's drilling engineering standards (SAES-J series) specify LCM pill specifications for HPHT Khuff wells, including graded calcium carbonate (CaCO3) pills at 50 to 100 lb/bbl (142 to 285 kg/m3), fibrous cellulose blends, and in severe cases, crosslinked polymer squeezes or neat Portland cement with accelerator packages sized for bottom-hole temperatures exceeding 175 degrees C (347 degrees F) in deep Khuff wells. The Abu Dhabi National Oil Company (ADNOC) encounters similar challenges in the Khuff and Upper Thamama carbonates of Abu Dhabi, where Zakum field development wells routinely require LCM programs budgeted as a standard well cost item rather than a contingency. Qatar Petroleum (QatarEnergy) addresses Khuff lost circulation at North Field through managed pressure completions and tailored LCM formulations developed in collaboration with service companies Halliburton, Schlumberger (SLB), and Baker Hughes. Norway: NORSOK D-010 and North Sea Chalk Norwegian drilling operations on the Norwegian Continental Shelf (NCS) are governed by the Petroleum Safety Authority Norway (Ptil) and follow the NORSOK D-010 standard (Well Integrity in Drilling and Well Operations), which specifies minimum requirements for well barrier elements including the drilling fluid column and LCM programs. The Ekofisk chalk formation in the Central Graben area, operated primarily by ConocoPhillips, presents specific lost circulation challenges because the high-porosity, low-density chalk (porosity 30 to 45 percent, bulk density 1.6 to 1.85 g/cm3 equivalent to 13.3 to 15.4 lb/gal) has a low overburden gradient and a correspondingly low fracture gradient, giving a very narrow ECD window. Equinor's Johan Sverdrup field in the Norwegian North Sea drills Draupne shale overlying fractured Zechstein carbonates where ECD management is critical to avoiding induced losses. NORSOK D-010 requires that any LCM pill formulation be compatible with the cementing program, so cement squeeze designs account for residual LCM in the fracture system. Norwegian operators must report all well control incidents, including significant lost circulation events, to Ptil within 24 hours under the Petroleum Activities Act. Fast Facts Industry cost: Lost circulation is estimated to cost the global drilling industry approximately $2 billion USD per year in non-productive time, lost fluid, and LCM materials. Severity thresholds: Seepage less than 10 bbl/hr (1.6 m3/hr); partial 10 to 100 bbl/hr (1.6 to 15.9 m3/hr); severe 100 to 250 bbl/hr (15.9 to 39.7 m3/hr); total/catastrophic greater than 250 bbl/hr (39.7 m3/hr). Most common LCM type: Granular calcium carbonate is the most widely used LCM in oil-based mud systems because it is acid-soluble and does not impair reservoir permeability after production commences. D90 bridging rule: LCM particles should have a D90 size (the diameter below which 90 percent of particles fall) equal to approximately one-third the estimated fracture width or pore throat diameter to form a stable bridge. Deepwater record: Some deepwater GOM and NCS wells have consumed more than 100,000 barrels (15,900 m3) of drilling fluid before a successful lost circulation treatment was achieved, at fluid costs of $100 to $400 per barrel for synthetic-base mud.

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

The collective term for substances added to drilling fluids when drilling fluids are being lost to the formations downhole. Commonly used lost-circulation materials include are fibrous (cedar bark, shredded cane stalks, mineral fiber and hair), flaky (mica flakes and pieces of plastic or cellophane sheeting) or granular (ground and sized limestone or marble, wood, nut hulls, Formica, corncobs and cotton hulls). Laymen have likened lost-circulation materials to the "fix-a-flat" materials for repair of automobile tires.

An oil mud designed and maintained with a minimum of colloid-sized solids, typically by omitting fatty-acid soap and lime, and minimizing organophilic clays and fluid-loss additives. Low-colloid oil mud, also called a relaxed filtrate oil mud, increases drilling rate. A disadvantage is that filtercake formed on sands is not tight, can quickly become very thick, and can cause pipe to stick by differential pressure.

A type of drilling-fluid solid having a lower density than the barite or hematite that is used to weight up a drilling fluid, including drill solids plus the added bentoniteclay. The mud engineer calculates the concentration of these and other types of solids on the basis of mud weight, retort analysis, chloride titrations and other information. Solids are reported as lbm/bbl or vol.%. Water is 1.0, barite 4.20, and hematite 5.505 g/cm3. Low-gravity solids are normally assumed to have a density of 2.60 g/cm3.

A mud that has fewer solids than conventional clay-based muds of the same density and similar use. Low-solids mud design and maintenance is accomplished primarily by substituting one or more polymers for the ordinary bentonite clay. Viscosity can be obtained either entirely by polymers or by using a premium quality (nontreated) bentonite along with the appropriate extender polymer. Together, these give rheology comparable to that of a higher concentration of ordinary bentonite. Polyanionic cellulose (PAC) may be needed for fluid-loss control. XC polymer can be effective for cuttings carrying. By combining premium bentonite and the right extender polymer, PAC and XC polymer, solids can be kept low, if solids control is required. This concept applies best to low-density muds, below about 13 lbm/gal, but has some validity in all muds .

Native clays that are generally unsuitable for use in a clay-based drilling mud. Low-yield clays are considered to be drill solids, although they may give high values for bentonite-equivalent in a mud according to the methylene blue test.

An oil mud designed and maintained with a minimum of colloid-sized solids, typically by omitting fatty-acid soap and lime, and minimizing organophilic clays and fluid-loss additives. Low-colloid oil mud, also called a relaxed filtrate oil mud, increases drilling rate. A disadvantage is that filter cake formed on sands is not tight, can quickly become very thick, and can cause pipe to stick by differential pressure.

A type of drilling-fluid solid having a lower density than the barite or hematite that is used to weight up a drilling fluid, including drill solids plus the added bentonite clay. The mud engineer calculates the concentration of these and other types of solids on the basis of mud weight, retort analysis, chloride titrations and other information. Solids are reported as lbm/bbl or vol.%. Water is 1.0, barite 4.20, and hematite 5.505 g/cm3. Low-gravity solids are normally assumed to have a density of 2.60 g/cm3.

A test to measure static filtration behavior of water mud at ambient (room) temperature and 100-psi differential pressure, usually performed according to specifications set by API, using a static filter press. The filter medium is filter paper with 7.1 sq. in. filtering area. A half-size cell is sometimes used, in which case the filtrate volume is doubled.

An enhanced oil recovery method that uses water with a low concentration of dissolved salts as a flooding medium. The sources of low-salinity water are typically rivers, lakes or aquifers associated with meteoric water.

A mud that has fewer solids than conventional clay-based muds of the same density and similar use. Low-solids mud design and maintenance is accomplished primarily by substituting one or more polymers for the ordinary bentonite clay. Viscosity can be obtained either entirely by polymers or by using a premium quality (nontreated) bentonite along with the appropriate extender polymer. Together, these give rheology comparable to that of a higher concentration of ordinary bentonite. Polyanionic cellulose (PAC) may be needed for fluid-loss control. XC polymer can be effective for cuttings carrying. By combining premium bentonite and the right extender polymer, PAC and XC polymer, solids can be kept low, if solids control is required. This concept applies best to low-density muds, below about 13 lbm/gal, but has some validity in all muds .

A low-solids mud in which there is no claydeflocculant chemical.

Antonym: high-specific-gravity solids

Native clays that are generally unsuitable for use in a clay-based drilling mud. Low-yield clays are considered to be drill solids, although they may give high values for bentonite-equivalent in a mud according to the methylene blue test.

A systems tract overlying a sequence boundary and overlain by a transgressive surface. Characterized by a progradational to aggradationalparasequence set, this systems tract commonly includes a basin-floor fan, a slope fan and a lowstand wedge. It is often abbreviated as LST.

A mud additive for lowering torque (rotary friction) and drag (axial friction) in the wellbore and to lubricate bit bearings if not sealed. Lubricants may be solids, such as plastic beads, glass beads, nut hulls and graphite, or liquids, such as oils, synthetic fluids, glycols, modified vegetable oils, fatty-acid soaps and surfactants.

A term initially applied to the assembly of pressure-control equipment used on slickline operations to house the tool string in preparation for running into the well or for retrieval of the tool string on completion of the operation. The lubricator is assembled from sections of heavy-wall tube generally constructed with integral seals and connections. Lubricator sections are routinely used on the assembly of pressure-control equipment for other well-intervention operations such as coiled tubing.

A measure of the degree of lubrication.

A descriptive term for the strong affinity that a solid material (usually a colloid) has for the liquid in which the solid is dispersed. For example, clay is a lyophilic colloid in water.

A descriptive term for the lack of affinity (or repulsion) that a solid material has for the liquid in which the solid is dispersed. For example clay is lyophobic to oil.