Provided herein are methods and systems for treating a tail gas of a Claus process to remove sulfur-containing compounds. The method includes combusting a tail gas of a Claus process in an excess of oxygen gas to yield a thermal oxidizer effluent. The thermal oxidizer effluent includes sulfur dioxide, water vapor, and oxygen. The effluent is routed to a quench tower and contacted with a dilute aqueous acid quench stream to yield sulfurous acid, hydrated sulfur dioxide, or both. The sulfurous acid or hydrated sulfur dioxide is oxidized with the excess oxygen from the thermal oxidizer effluent to yield sulfuric acid.
A method and a system for monitoring a mechanical device for internal corrosion are provided. An exemplary method includes placing a sampling thermoelectric polymer sheet (TEPS) on an external surface of the mechanical device to be monitored for internal corrosion, and placing a reference TEPS on an external surface of the mechanical device not susceptible to internal corrosion. A current from the sampling TEPS is measured, and a current from the reference TEPS is measured. Potential internal corrosion is identified from changes between the current from the sampling TEPS and the current from the reference TEPS.
A method for recovering hydrocarbons from a hydrocarbon bearing formation (1008) includes introducing a first solution having a first salt into the hydrocarbon bearing formation. A second solution is also introduced into the hydrocarbon bearing formation, wherein the second solution has a second salt and a foaming agent. The first salt and the second salt produces a nitrogen gas, and the nitrogen gas and the foaming agent produces a foam (210) formed in-situ within the formation. The foam forms a foam barrier (212), and carbon dioxide is introduced into the formation to form a gas cap (222), wherein the carbon dioxide gas cap has a gas front that is separated from the hydrocarbons by the foam barrier (212).
A system and method for generating base water and precipitate, including combining produced water with seawater to precipitate barium sulfate from barium in the produced water and from sulfate in the seawater, and separating the precipitate to give the base water and the precipitate. The base water may have less than a specified amount of sulfate and be utilized for hydraulic fracturing fluid. The precipitate may give a weighting agent for drilling.
Some implementations of the present disclosure provide a laser drilling tool assembly comprising: (i) a body that includes: a first segment configured to receive an input beam from a laser source and couple the input beam to provide an irradiation beam to irradiate a downhole target, and a second segment housing one or more purging pipes; and (ii) a tool head that includes: a retractable nozzle; and one or more optical sensing elements mounted on the retractable nozzle, wherein when the downhole target is being irradiated by the irradiation beam, the retractable nozzle is extended towards the downhole target such that the one or more optical sensing elements are positioned closer to the downhole target.
Systems and methods include a computer-implemented method for providing a photonic sensing system to perform an automated method to characterize displacement of equipment surfaces and monitor changes in real-time. A three-dimensional (3D) point cloud of one or more objects is generated by an analysis and presentation system using light information collected through structured light illumination by an array of structured-light sensors (SLSes) directed toward the one or more objects. Generating the point cloud includes defining points of the 3D point cloud that are relative to reference points on the one or more objects. Real-time contactless 3D surface measurements of the one or more objects are performed using the 3D point cloud. Changes in one or more parts of the one or more objects are determined by the an analysis and presentation system by analyzing the real-time contactless 3D surface measurements.
G01B 11/25 - Measuring arrangements characterised by the use of optical techniques for measuring contours or curvatures by projecting a pattern, e.g. moiré fringes, on the object
E21B 47/002 - Survey of boreholes or wells by visual inspection
E21B 47/007 - Measuring stresses in a pipe string or casing
G01B 11/16 - Measuring arrangements characterised by the use of optical techniques for measuring the deformation in a solid, e.g. optical strain gauge
G01B 11/245 - Measuring arrangements characterised by the use of optical techniques for measuring contours or curvatures using a plurality of fixed, simultaneously operating transducers
G01C 11/06 - Interpretation of pictures by comparison of two or more pictures of the same area
A method of forming a model (230) of a porous structure includes three dimensionally printing a mold (200) of the porous structure using a polycaprolactone mold material, filling the mold with a polymer mixture (220), and heating the filled mold at a temperature above a melting temperature of the mold material to cure the polymer mixture, where the cured polymer mixture (224) forms the model (230) of the porous structure.
B33Y 80/00 - Products made by additive manufacturing
B29C 37/00 - Component parts, details, accessories or auxiliary operations, not covered by group or
B29C 39/00 - Shaping by casting, i.e. introducing the moulding material into a mould or between confining surfaces without significant moulding pressure; Apparatus therefor
B29C 39/10 - Shaping by casting, i.e. introducing the moulding material into a mould or between confining surfaces without significant moulding pressure; Apparatus therefor for making articles of definite length, i.e. discrete articles incorporating preformed parts or layers, e.g. casting around inserts or for coating articles
B29C 64/106 - Processes of additive manufacturing using only liquids or viscous materials, e.g. depositing a continuous bead of viscous material
An apparatus for producing steam in-situ, the apparatus comprising an activated carbon container configured to hold activated carbon; a water supply fluidly connected to the activated carbon container, the water supply configured to provide water directly to the activated carbon container; an inter-container valve fluidly connected to the activated carbon container, the inter-container valve configured to let steam flow from the activated carbon container to a steam container; the steam container fluidly connected to the inter-container valve, the steam container configured to hold the steam that flows from the activated carbon container; and one or more release valves fluidly connected to the steam container, the one or more release valves configured to release steam from the steam container.
An apparatus for producing in-situ steam comprising a rotational joint, the steam generating tool comprising an optics unit configured to shape and manipulate laser energy delivered to the optics unit through the fiber optic cable to produce a laser beam, an optical cover, an activated carbon case configured to contain activated carbon, the activated carbon case comprising a laser end configured to allow the laser beam to pass while containing the activated carbon, a reinforced end configured to stop the laser beam while containing the activated carbon, wherein the laser beam travels from the optical cover to the laser end of the activated carbon case through the activated carbon case and ends at the reinforced end, and activated carbon, an outer case, wherein an annulus is formed between the outer case and the activated carbon case, and water supply pipes configured to carry water to the annulus.
A method to produce in-situ steam comprising the steps of producing a laser beam in a steam generator segment positioned in a wellbore in a formation; introducing the laser beam to an activated carbon container, where the activated carbon container comprises activated carbon; increasing a temperature of the activated carbon with the laser beam to produce a hot activated carbon; introducing water to the activated carbon container through a water supply line; producing steam in the activated carbon container when the water contacts the hot activated carbon; increasing pressure in the activated carbon container as steam is produced until a pressure set point of an inter-container valve is reached; releasing steam through the inter-container valve to a steam container; increasing a pressure in the steam container until a release set point of one or more release valves is reached; and releasing steam through the release valve to the formation.
E21B 36/04 - Heating, cooling, or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones using electrical heaters
E21B 47/135 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range using light waves, e.g. infrared or ultraviolet waves
E21B 27/00 - Containers for collecting or depositing substances in boreholes or wells, e.g. bailers for collecting mud or sand; Drill bits with means for collecting substances, e.g. valve drill bits
E21B 34/08 - Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
E21B 43/24 - Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
11.
HEATING A FORMATION OF THE EARTH WHILE DRILLING A WELLBORE
A method and an assembly for heating and evaluating a formation of the Earth while drilling a wellbore filled with drilling mud are described. A first drilling mud temperature at a depth in the wellbore is received from a first sensor by a controller. The formation proximal to the depth is heated by a heat source mounted to the assembly to a temperature greater than a formation temperature as the drilling assembly drills the wellbore. A second drilling mud temperature is received from a second sensor by the controller. The heat source is positioned in between the first sensor and the second sensor. A difference between the first drilling mud temperature and the second drilling mud temperature is compared to a threshold drilling mud temperature difference value by the controller. Based on a result of the comparison, the drilling assembly is controlled and directed in the formation.
Spoolable composite pipes (100) for oil and gas flowlines may include an inner extruded tubular liner (101), a reinforcement layer (102) surrounding the inner extruded tubular liner (101), and an outer extruded tubular (103) cover surrounding the reinforcement layer (102). In these spoolable composite pipes (100), the inner extruded tubular liner (101) may include an aliphatic polyketone. Internally lined pipes (200) for oil and gas flowlines may include inner extruded tubular liner (201) containing an aliphatic poly ketone, and a carbon steel pipe (202) surrounding the inner extruded tubular liner (201). The spoolable composite pipes (100) and the internally lined pipes (200) may be configured to operate at temperatures of up to about 110°C, and to carry hydrocarbons having an aromatic content of up to about 35% by volume of the total hydrocarbons content.
A method of evaluating a surfactant is provided. The method includes preparing a first emulsion comprising an aqueous phase, an oleaginous phase, and a first surfactant. Then the method includes determining an average droplet size of oleaginous phase droplets in the first emulsion. The method then includes preparing a second emulsion comprising the aqueous phase, the oleaginous phase, and a second surfactant, and then determining an average droplet size of oleaginous phase droplets in the second emulsion. After determining droplet sizes of both emulsions, the method includes comparing the average droplet size of the of the oleaginous phase droplets in the first emulsion to the average droplet size of the oleaginous phase droplets in the second emulsion, and based on the comparing of the average droplet sizes, determining a relative interfacial tension of the first surfactant as compared to the second surfactant.
C09K 8/584 - Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific surfactants
G01N 13/02 - Investigating surface tension of liquids
14.
NON-METALLICS ENHANCED RELIABILITY VIA EMBEDDED SENSORS (NERVES): OPTICAL AND ELECTRICAL SENSORY NERVES
A smart pipe segment for use in construction of a pipeline. The smart pipe segment includes a pipe body and a sensing nerve network that is associated with the pipe body and is configured to monitor a condition of the pipe segment in real-time. The sensing nerve network comprises optical nerves, electrical nerves or a combination thereof.
F16L 11/08 - Hoses, i.e. flexible pipes made of rubber or flexible plastics with reinforcements embedded in the wall
F16L 11/127 - Hoses, i.e. flexible pipes made of rubber or flexible plastics with arrangements for particular purposes, e.g. specially profiled, with protecting layer, heated, electrically conducting electrically conducting
G01B 11/16 - Measuring arrangements characterised by the use of optical techniques for measuring the deformation in a solid, e.g. optical strain gauge
G01D 5/353 - Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable using optical means, i.e. using infrared, visible or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre
Systems for facilitating fluid flow including a tubular segment (100) having a length (101), a tube wall (106) with a thickness (105), a tube wall exterior surface (103), and a tube wall interior surface (102). The tube wall interior surface (102) defines a conduit (107) configured to permit fluid flow along the length (101) of the tubular segment (100). The tube wall (106) may include a material configured to convey heat energy through the tube wall (106) and at least one heating element (112) coupled to an exterior surface (103) of the tube wall (106) along the length (101) of the tubular segment (100), at least one heating element (112) comprising an enabler material configured to receive electromagnetic energy, convert the electromagnetic energy into heat energy, and release the heat energy into the tube wall (106). The system may include a source of electromagnetic energy (113) associated with the at least one heating element (112). The source of electromagnetic energy (113) is configured to transmit electromagnetic energy into the heating element (112).
?Techniques for correlating a depth of drill bit cuttings include circulating a drilling fluid into a wellbore during a drilling process to form the wellbore in a subterranean formation; circulating a portion of uniquely identifiable particles from a container into the drilling fluid during the drilling process; circulating a return drilling fluid that includes the drilling fluid, cuttings from the subterranean formation, and the uniquely identifiable particles; separating the drilling fluid from the cuttings from the subterranean formation and the uniquely identifiable particles; capturing at least one image of the separated cuttings and the uniquely identifiable particles; and determining, based on the image, a depth of the subterranean formation.
A method including obtaining, by a computer processor (705), at least one key log in each of a set of training wells (102) located, at least partially, within a hydrocarbon reservoir (614), identifying a target formation bounding surface (202) in each of the set of training wells, and generating an initial depth surface for the target formation bounding surface (202) from the target formation bounding surface in each of the set of training wells. The method further including, determining from the initial depth surface an initial depth estimate of the target formation bounding surface at a location of a current well (106), forming an objective function based, at least in part on a. correlation between each key log in each of the set of training wells, and each corresponding key log in the current well, and optimizing the objective function by varying a depth shift between each of the set of training wells (102) and the current well (106), to determine an optimum depth shift that produces an extremum of the objective function. The method still further including combining the initial depth estimate of the target formation bounding surface at the location of the current well with the optimum depth shift to produce a final depth estimate of the target formation bounding surface (202) at the location of the current well (106).
An example system may be used to automate one or more processes relating to drill cutting handling, cleaning, and packing to produce consistently high-quality cleaned samples. In some implementations, an example system may employ cleaning processes including centrifugal and ultrasonic processes to clean a sample automatically without the aid of a human operator thereby increasing efficiency and quality of the produced samples for better subsequent sample analysis. A system may include an unloading module, a cleaning module, and packing module, all of which may be operated in combination with a robotic arm.
E21B 21/01 - Arrangements for handling drilling fluids or cuttings outside the borehole, e.g. mud boxes
E21B 49/00 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
G01N 1/08 - Devices for withdrawing samples in the solid state, e.g. by cutting involving an extracting tool, e.g. core bit
A method for formation properties prediction in near-real time. The method may include obtaining lab measurements of existing drill cuttings at a plurality of depths of a first well. The method may include obtaining historical drilling surface data at the plurality of depths from a plurality of wells. The method may include obtaining real-time digital photos and real-time drilling surface data of new drill cuttings at a new depth of a new well. The method may include generating, using a prediction model, predicted formation properties of the new drill cuttings based on the real-time digital photos, the real-time drilling surface data, and the new depth. The method may include predicting, using a near-real-time model and the predicted formation properties, near-real-time formation properties in the new well, wherein the prediction model comprises a historical model that employs a machine-learning algorithm.
A wellbore flow control system includes a production tubular member configured to run into a wellbore formed from a terranean surface and into a subterranean formation; a plurality of autonomous inflow control valves (AICVs) positioned on the production tubular member, each of the plurality of AICVs controllable based at least in part on at least one of a density or a viscosity of a formation fluid; and a plurality of sliding sleeves mounted in the production tubular member, each of the plurality of sliding sleeves mounted near a set of AICVs of the plurality of AICVs, each of the plurality of sliding sleeves controllable based on a wellbore drawdown pressure to fluidly couple or fluidly decouple an inner volume of the production tubular member with the subterranean formation through the particular set of AICVs.
A method including obtaining, for a subterranean region, a set of sedimentary pathways (204), a sediment attribute map, and an area of interest. From these inputs, a sedimentary fairway (210, 212, 218), and a sedimentary fairway attribute based on the location of the origin point (200) of each member of the set of sedimentary pathways (204), and a spatial location of the terminal point (202) of each member of the set of sedimentary pathways (204) are determined. Further, the method includes dividing the sedimentary fairway (210, 212, 218) into one or more sedimentary pathway domains and a sediment attribute profile for each sedimentary pathway domain based on a trajectory of each sedimentary pathway (204), and determining an intersection of the trajectory of each sedimentary pathway (204) with one or more boundaries of the area of interest. The method also includes determining a sedimentary attribute at the entry points, and a sedimentary attribute at the exit points of the set of sedimentary pathways with the area of interest, and a change in the sedimentary attribute between the entry and exit points.
A method of obtaining a relative amplitude preserved seismic volume acquired in a time-domain for a subterranean region of interest and transforming it into a low- frequency monospectral amplitude volume. The method further determines a seismic attenuation volume from the relative amplitude preserved seismic volume acquired in the time-domain. Furthermore, the method generates a low-frequency monospectral amplitude map for a surface of interest by averaging the low- frequency monospectral amplitude volume over a depth-window around the surface of interest, and generates a seismic attenuation map for a surface of interest by averaging the seismic attenuation volume over a depth-window' around the surface of interest. The method further determines an attribute map based on the seismic attenuation map and the low-frequency monospectral amplitude map for the surface of interest, and determines a presence of gas in the subterranean region of interest based on the attribute map.
A system for a carbon neutral cycle of gas production may include a molten salt reactor (114) configured to generate zero carbon dioxide (CO2) emissions electricity. The system may include a desalination unit (116) configured to receive the zero-CO2 emissions electricity from the molten salt reactor and produce a desalinated water. The system may include an electrolysis unit (105) configured to be powered by the zero- CO2 emissions electricity generated by the molten salt reactor and generate hydrogen (H2) and oxygen (O2) from the desalinated water. The system may include an oxy- combustion unit (108) configured to receive and combust a hydrocarbon fuel with the O2 from the electrolysis unit to produce electricity and CO2. The system may include a CO2 capture system (113) adapted to capture the CO2 produced by the oxy-combustion unit and a catalytic hydrogenation unit (103) configured to receive and convert H2 from the electrolysis unit and CO2 from the CO2 capture system to produce the hydrocarbon fuel.
A process for recovering a noncondensable gas from a gaseous mixture, the method comprising the steps of: supplying a gaseous mixture comprising a noncondensable component; supplying a sweep gas comprising a condensable component; introducing the gaseous mixture and the sweep gas to a swept membrane stage to obtain a retentate stream and a mixed permeate stream, the mixed permeate stream comprising at least a portion of the condensable component and at least a portion of the noncondensable component; introducing the mixed permeate stream to a vapor-liquid separator and subjecting the mixed permeate stream to thermodynamic conditions sufficient to condense most of the condensable component into a liquid, and obtain a raw noncondensable component stream, wherein the raw noncondensable component stream is enriched in the noncondensable component; and introducing the raw noncondensable component to a concentration unit to obtain a noncondensable component product stream enriched in the noncondensable component.
B01D 53/22 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by diffusion
C10L 3/00 - Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclasses , ; Liquefied petroleum gas
A hydrocarbon recovery method using artificial, fresh rain water is described. The method includes generating artificial, fresh rain water. A volume of the generated artificial, fresh rain water is mixed with a volume of brine water obtained from a brine water source to form a mixture having a water salinity that satisfies a threshold water salinity. The mixture is injected into an injection well formed in a subterranean zone. The injection well is fluidically coupled to a producing well formed in the subterranean zone to produce hydrocarbons residing in the subterranean zone. The mixture flows the hydrocarbons in the subterranean zone surrounding the producing well toward the producing well. The hydrocarbons are produced in response to injecting the mixture in the injection well.
Some methods of hydraulic fracturing of a subsurface formation include using a three-dimensional finite element model to simulate a deviated well with a wellbore casing, a cement adjacent to the wellbore casing, and a perforation cluster with at least two perforations. The FEM is applied (or solved) to determine a breakdown pressure of the deviated well based on an amount of tensile damage of the perforation cluster induced by an applied pressure representing injected hydraulic fluid. The FEM accounts for the 3D complex configuration of wellbore and perforation cluster. A deviated well is drilled and completed with a wellbore casing size, tubing size, wellhead, and hydraulic fracturing pump schedule selected at least in part based on the determined breakdown pressure before hydraulic fluid is injected into the deviated well at an injection pressure, which represents the required breakdown pressure to cause hydraulic fracturing of the rock of the subsurface formation.
In an example method, one or more processors receive a plurality of rock fragment images. Each of the rock fragment images represents respective rock fragments obtained from a subsurface formation during well bore drilling. The one or more processors select one or more portions of the rock fragment images, and generate a geological formation image based on the one or more selected portions of the rock fragment images. The geological formation image is indicative of one or more geological characteristics of the subsurface formation along the well bore.
A carbon dioxide containing fluid is flowed through a membrane in an open position. The membrane encapsulates an adsorbent bed operating at a first temperature. The adsorbent bed adsorbs at least a portion of the carbon dioxide of the carbon dioxide containing fluid. The membrane is adjusted to a closed position, thereby isolating the adsorbent bed and preventing fluid flow into and out of the membrane. The adsorbent bed is heated to a second temperature, thereby desorbing the carbon dioxide captured from the carbon dioxide containing fluid. The membrane is adjusted to the open position. The adsorbent bed is cooled to the first temperature.
B01D 69/02 - Semi-permeable membranes for separation processes or apparatus characterised by their form, structure or properties; Manufacturing processes specially adapted therefor characterised by their properties
B01D 53/02 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by adsorption, e.g. preparative gas chromatography
B01D 53/10 - Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases or aerosols by adsorption, e.g. preparative gas chromatography with moving adsorbents with dispersed adsorbents
A system and method for coupling pipes includes a first pipe (402) having a tapered, spigot end; and a second pipe (404) having a tapered, socket end adapted to internally receive the tapered, spigot end of the first pipe. The first pipe and the second pipe are made from a reinforced thermosetting resin (RTR) material (408). A thermal joining process is used to bond a thermoplastic material onto the RTR material of the first pipe (402), the second pipe (404), or both pipes. Upon application of thermal heating to the first and second pipes, the heat between the first pipe and the second pipe is sufficient to melt the thermoplastic material such that, when the heat is removed, the hardened thermoplastic material seals the first pipe (402) to the second pipe (404). A system and a method of coupling the first pipe and the second pipe may include the coupler made of RTR material.
B29C 65/34 - Joining of preformed parts; Apparatus therefor by heating, with or without pressure using heated elements which remain in the joint, e.g. "verlorenes Schweisselement"
B29C 65/36 - Joining of preformed parts; Apparatus therefor by heating, with or without pressure using heated elements which remain in the joint, e.g. "verlorenes Schweisselement" heated by induction
F16L 47/03 - Welded joints with an electrical resistance incorporated in the joint
F16L 47/06 - Connecting arrangements or other fittings specially adapted to be made of plastics or to be used with pipes made of plastics with sleeve or socket formed by or in the pipe end
30.
DAS SYSTEM FOR PRE-DRILL HAZARD ASSESSMENT AND SEISMIC RECORDING WHILE DRILLING
A system and method of obtaining a high SNR seismic while-drilling data and a robust velocity profile of a geological site having a main well and at least one uphole located in the vicinity of the main well, the seismic profile being obtained from seismic waves generated by a drilling device located at the main well. The method comprises deploying at least one distributed acoustic fiber optic cable vertically in the at least one uphole, at least a portion of the fiber optic cable being positioned at a depth exceeding a predetermined depth below the surface, receiving seismic data at recording station positioned on the at least one fiber optic cable at at least the predetermined depth, generating, at a processor a high SNR seismic while- drilling signal; yielding a reliable velocity profile from the seismic data received, and determining a presence of near surface hazards from the generated high SNR while drilling seismic data.
G01V 1/42 - Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators in one well and receivers elsewhere or vice-versa
A method for reducing water production from a hydrocarbon bearing subterranean formation includes identifying a high permeability zone in the formation and injecting a dense CO2 composition from a production well into the high permeability zone. The dense CO2 composition includes dense CO2 and a thickener soluble in the dense CO2. The thickener includes a copolymer that is the polymerized reaction product of monomers that include at least one alkenyl ether or dialkenyl ether monomer, at least one acrylate or methacrylate monomer, at least one structural monomer, and at least one allyl ester monomer. After injecting the dense CO2 composition into the high permeability zone, the method includes withdrawing hydrocarbons from the hydrocarbon bearing subterranean formation through the production well. The dense CO2 composition blocks pores in the high permeability zone to reduce or prevent flow of water from the high permeability zone into the production well.
A method for enhanced oil recovery from a hydrocarbon bearing subterranean formation includes withdrawing hydrocarbons from a production well extending into the formation, identifying a high permeability streak in the formation, and injecting a dense CO2 composition from an injection well into the high permeability streak. The dense CO2 composition includes dense CO2 and a thickener soluble in the dense CO2. The thickener includes copolymer. The method includes, after injecting the dense carbon dioxide composition into the high permeability streak, injecting an aqueous treatment fluid into the formation. The dense CO2 composition blocks the high permeability streak to divert at least a portion of the aqueous treatment fluid into bypassed regions of the formation during the injecting of the aqueous treatment fluid, and the injecting of the aqueous treatment fluid into the hydrocarbon bearing subterranean formation drives hydrocarbons in the hydrocarbon bearing subterranean formation towards the production well.
An expansion cone 2 useful for expanding an expandable tubular 3, the expansion cone includes: a base material 20 selected from a group consisting of alloyed steel, tungsten carbide coated alloyed steel, and cemented tungsten carbide; an intermediate buffering layer 26; and a coating 25 deposited on an outer surface of the intermediate buffering layer; wherein the intermediate buffering layer is deposited between an outer surface of the steel alloy base material and the coating, wherein the intermediate buffering layer is one or more selected from a group consisting of Silicon (Si), Titanium (Ti), and silicon carbide (SiC), and wherein the coating is a diamond containing coating.
A method includes taking at least one image of a plurality of returned cuttings (103) from a well (111) using a fluorescent imaging camera (124), analyzing the at least one image with an imaging processing system (125) to obtain detection data including a calculated percentage of a first emitted fluorescent light to formation cuttings, sending the detection data to an analysis and control program (130) to correlate the returned cuttings (103) with a depth in the well (111), and automatically controlling at least one drilling parameter for drilling the well (111) based on the detection data.
E21B 49/00 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
A method for reservoir simulation is disclosed. The method includes selecting a coarse grid size (300) for a plurality of grid blocks in a reservoir model of a reservoir, computing, by a computer processor and based at least on a fractional flow curve of oil and water, a water saturation at a water front within a grid block of the plurality of grid blocks and an average water saturation of the grid block (302, 304), and computing, by the computer processor and based at least on the water saturation at the water front within the grid block and the average water saturation of the grid block, a water saturation distribution in the reservoir by solving reservoir simulator equations (308), wherein solving the reservoir simulator equations comprises computing a single water saturation value for each of the plurality of grid blocks based on the coarse grid size.
A method for depth determination of drilled rock cuttings is disclosed. The taggant is injected and transported downhole along the mud stream (204, 205) and attaches to the rock cuttings. Taggant impregnated cuttings are detected at the surface (108) based on molecular weight, emission wavelengths or radio frequency characteristics for encoding the taggant. The identification code identifies the depth of the drill bit when the particular batch of the taggant is released into the mud. The detection data, in addition to mud properties, flow rates, drill volume and penetration rates, formation characteristics, and well specifications are transferred to and analyzed by a taggant analysis and control engine (202). The taggant analysis and control engine (202) controls an IoT controller (203) that adapts the parameters of the taggant injection pump (206) to achieve an intelligent controlled release to optimize the depth characterization process.
A reversible polycrystalline diamond compact (PDC) bit (200, 400) is disclosed. The reversible PDC bit (400) includes at least one blade (401a, 401b), at least one front cutter (402) disposed on a first side of the at least one blade (401a), and at least one rear cutter (403) disposed on a second side of the at least one blade (401b), wherein the first side is opposite to the second side along a circumferential direction of the reversible PDC bit (400), wherein rotating the reversible PDC bit (400) in a clockwise direction engages the at least one front cutter (402) to cut into a subterranean formation (104), and wherein rotating the reversible PDC bit (400) in a counter-clockwise direction engages the at least one rear cutter (403) to cut into the subterranean formation (104).
E21B 10/43 - Rotary drag type drill bits with teeth, blades or like cutting elements, e.g. fork-type bits, fish tail bits characterised by the arrangement of teeth or other cutting elements
E21B 10/46 - Drill bits characterised by wear resisting parts, e.g. diamond inserts
38.
A LOW PH-BASED OIL RECOVERY METHOD FOR CARBONATE RESERVOIRS
Systems and methods include a computer-implemented method for generating and using a graph/document structure to store reservoir simulation results. A graph is generated that represents reservoir simulation results of a reservoir simulation performed on a reservoir using a reservoir simulation model. The graph represents a full set of relational data and non-relational data included in the reservoir simulation results. The graph stores graph information and relational data in a graph/document structure. Objects of the reservoir, elements of the reservoir simulation results, and inputs of the reservoir simulation model are represented as vertices in the graph. Relationships between vertices are represented as edges in the graph. An edge is defined by a pair of vertices in the graph.
E21B 41/00 - Equipment or details not covered by groups
G01V 99/00 - Subject matter not provided for in other groups of this subclass
G06F 30/12 - Geometric CAD characterised by design entry means specially adapted for CAD, e.g. graphical user interfaces [GUI] specially adapted for CAD
G06F 30/20 - Design optimisation, verification or simulation
40.
ONLINE MEASUREMENT OF DISPERSED OIL PHASE IN PRODUCED WATER
Online measurement of dispersed oil phase in produced water can be implemented a method on-site of a flowline transporting a fluid that includes dispersed oil in water. A sample of the fluid flowed through the flowline is obtained. The sample includes the oil phase and the water phase. The sample is combined with a chemical element that can separate the oil phase in the sample from the water phase in the sample. The separated oil phase and the chemical element are transferred into a measurement cell. The chemical element is removed from the measurement cell. After the chemical element is removed from the measurement cell, a quantity of the oil phase in the sample in the measurement cell is determined by a capacitive measurement technique. The determined quantity of the oil phase in the sample is provided.
Systems and methods include a computer implemented method for evaluating rock physical properties. Drilling acoustic signals are received in real time during a drilling operation through rock at a drilling location. Transformed data is generated in a frequency domain from the drilling acoustic signals. The transformed data includes frequency and amplitude information for the drilling acoustic signals. De-noised transformed data is generated from the transformed data by filtering noise including background noise generated in a recording system and top drive rotation generated traces. A lithological significant frequency range that includes de-noised significant data points is determined from the de-noised transformed data. Physical properties of the rock are determined in real time using drill bit rotation rates and the amplitudes of the de-noised significant data points.
Cutters for a downhole drill bit can be formed by providing a catalyst-free synthesized polycrystalline diamond (PCD) having a cross-sectional dimension of at least 8 millimeters; providing a substrate comprising tungsten carbide; and attaching the synthesized PCD to the substrate comprising tungsten carbide to form a PDC cutter.
C04B 37/00 - Joining burned ceramic articles with other burned ceramic articles or other articles by heating
C04B 35/56 - Shaped ceramic products characterised by their composition; Ceramic compositions; Processing powders of inorganic compounds preparatory to the manufacturing of ceramic products based on non-oxides based on carbides
C04B 35/622 - Forming processes; Processing powders of inorganic compounds preparatory to the manufacturing of ceramic products
E21B 10/46 - Drill bits characterised by wear resisting parts, e.g. diamond inserts
B22F 7/08 - Manufacture of composite layers, workpieces, or articles, comprising metallic powder, by sintering the powder, with or without compacting of composite workpieces or articles from parts, e.g. to form tipped tools with one or more parts not made from powder
43.
DRILLING TOOLS MADE OF WURTZITE BORON NITRIDE (W-BN)
Systems and methods include a computer-implemented method can be used to make drilling tools from new wurtzite boron nitride (w-BN) superhard material. An ultra-high-pressure, high-temperature operation is performed on pure w-BN powder to synthesize w-BN and cubic boron nitride (c-BN) compact having a first size greater than particles of the pure w-BN powder. The ultra-high-pressure, high-temperature operation includes pressurizing the w-BN powder to a pressure of approximately 20 Gigapascal, heating the w-BN powder at a heating rate of 100 C/minute and cooling the w-BN powder at a cooling rate of 50 C/minute. The compact is cut to a second size smaller than the first size using laser cutting tools. The cut compact is bonded metallurgically, mechanically, or both metallurgically and mechanically onto a tool substrate to form the drilling tool.
E21B 10/55 - Drill bits characterised by wear resisting parts, e.g. diamond inserts the bit being of the rotary drag type, e.g. fork-type bits with preformed cutting elements
44.
COMPOSITIONS, SYSTEMS, AND METHODS FOR IRON SULFIDE SCALE IDENTIFICATION, PREVENTION, AND REDUCTION
Compositions and methods for prevention and reduction of iron sulfide scale formation, one method including detecting at least one component indicative of an iron sulfide scale precursor, the at least one component selected from the group consisting of: H2S;HS; S2-; S2- n; FeS(aq); Fe2+; Fe3+; and combinations of the same; preparing a composition to react with the iron sulfide scale precursor, the composition comprising at least one compound selected from the group consisting of: a methylating agent; a metal operable to react with sulfide species; a compound to increase the oxidation state of Fe2+; and combinations of the same; and applying the composition to the iron sulfide scale precursor to consume the iron sulfide scale precursor.
G01N 27/30 - Electrodes, e.g. test electrodes; Half-cells
G01N 27/42 - Measuring deposition or liberation of materials from an electrolyte; Coulometry, i.e. measuring coulomb-equivalent of material in an electrolyte
A well pad construction system includes a construction area (20), surface compaction equipment (22, 24) to compact the construction area (20), an excavator (34) disposed at the construction area (20) and movable to generate an excavated area (37), a cellar (14) disposed in the excavated area (37), controlled low-strength material (CLSM), and backfill equipment disposed around the excavated area. The backfill equipment (42) is moveable over the construction area (20) to pour CLSM into a gap (18) between the cellar (14) and surrounding medium in the excavated area for holding the cellar (14) in place and providing a firm well pad (10) from which a rig (50) may operate.
A drilling assembly that includes a drill string, a drill bit assembly, and a transmission sub disposed between the drill bit assembly and the drill string. The transmission sub includes a first tube attached to the drill string and a second tube rotationally coupled to a downhole end of the first tube. The second tube is coupled to the drill bit assembly. The transmission sub also includes a clutch assembly coupled to the first tube and has mechanical engagement features configured to simultaneously engage mechanical engagement features of the first tube and mechanical engagement features of the second tube to rotationally lock the first tube to the second tube. At least a portion of the clutch assembly moves along a longitudinal axis of the first tube to disengage the second mechanical engagement features of the second tube to rotationally unlock the first tube from the second tube.
KING FAHD UNIVERSITY OF PETROLEUM AND MINERALS (Saudi Arabia)
Inventor
Al-Nakhli, Ayman
Mahmoud, Mohamed Ahmed Nasr Eldin
Abstract
Reservoir stimulation treatment diversion methods, systems, and compositions, one method including identifying a reservoir requiring liquid stimulation treatment in a lesser-permeability portion of the reservoir; identifying a greater-permeability portion of the reservoir, the greater-permeability portion of the reservoir having a greater permeability than the lesser-permeability portion; disposing a gas in the greater-permeability portion of the reservoir; injecting a liquid stimulation treatment into the reservoir; and allowing the gas in the greater-permeability portion of the reservoir to divert the liquid stimulation treatment into the lesser-permeability portion to stimulate fluid production from the lesser-permeability portion of the reservoir.
C09K 8/504 - Compositions based on water or polar solvents
C09K 8/516 - Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
KING FAHAD UNIVERSITY OF PETROLEUM & MINERALS (Saudi Arabia)
Inventor
Saleh, Tawfik Abdo
Al-Arfaj, Mohammed Khalid
Rana, Azeem A.
Abstract
A water-based wellbore fluid may include an aqueous base fluid and a modified graphene shale inhibitor that comprises one or more substituents that are covalently bonded to graphene via a linking group. One of the one or more substituents may be a hydrocarbon group that has a number of carbon atoms in the range from 8 to 14.
Methods, systems, and computer-readable medium to perform operations for simulating performance of a reservoir that includes a wellbore. The operations include determining a constraint for an intelligent completion in a model of the wellbore, where the constraint includes a condition and a responsive action. The operations further include performing, in response to determining that the condition is satisfied, the responsive action. Further, the operations include determining, in response to performing the responsive action, transfer equations for the model of the wellbore. Yet further, the operations include building, using the transfer equations, a wellbore computation matrix for the model of the wellbore. In addition, the operations include solving the wellbore computation matrix and determining that a solution to the wellbore computation matrix has converged to an acceptable tolerance. The operations also include responsively determining that the converged solution is indicative of flow in the model of the wellbore.
Systems and methods for actuation of downhole devices are disclosed. The system includes a first cylindrical pipe having one or more first materials attached to an outer surface of the first cylindrical pipe, a second cylindrical pipe co-axial with the first cylindrical pipe and having a diameter greater than the first cylindrical pipe, the second cylindrical pipe comprising one or more second materials disposed on an inner surface of the second cylindrical pipe, wherein the first materials generate one or more signals when the first materials come in contact with the second materials, and a digital logic circuit configured to receive the one or more signals as input, and generate an output based on the input, the output configured for actuation of the downhole devices.
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
E21B 41/00 - Equipment or details not covered by groups
H10N 30/85 - Piezoelectric or electrostrictive active materials
E21B 34/06 - Valve arrangements for boreholes or wells in wells
H02N 2/18 - Electric machines in general using piezoelectric effect, electrostriction or magnetostriction producing electrical output from mechanical input, e.g. generators
51.
SYSTEMS AND METHODS FOR CONTROLLED RELEASE OF SENSOR SWARMS DOWNHOLE
Methods and systems for monitoring conditions within a wellbore of a subterranean well include extending a drill string into the subterranean well from a terranean surface. The drill string has an actuator assembly, a sensor compartment, and a plurality of sensors located within the sensor compartment. The actuator assembly is instructed to transmit a swarm release signal to a central power unit of the sensor compartment so that the central power unit of the sensor compartment releases certain of the plurality of sensors from the sensor compartment. Data from the sensors is transferred to a data processing system after the sensors reach the terranean surface.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
E21B 23/00 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
52.
DEPLOYING WELLBORE PATCH FOR MITIGATING LOST CIRCULATION
Systems, methods, and apparatuses for deploying a lost circulation fabric (LCF) to seal a lost circulation zone during a drilling operation. The LCF may be contained within a lost circulation fabric deployment system (LCFDS) that is coupled to a tubular of a drilling string. The LCFDS may include a controller and sensors to detect the presence of a lost circulation zone and deploy the LCF upon detection of the lost circulation zone. In some implementations, a plurality of LCFDSs may be disposed on the tubular and work in cooperation to deploy a plurality of LCFs to form a seal along the lost circulation zone.
Systems, methods, and apparatuses for deploying a lost circulation fabric (LCF) to seal a lost circulation zone during a drilling operation. The LCF may be contained within a lost circulation fabric deployment system (LCFDS) that is coupled to a tubular of a drilling string. The LCFDS may include a controller and sensors to detect the presence of a lost circulation zone and deploy the LCF upon detection of the lost circulation zone. In some implementations, a plurality of LCFDSs may be disposed on the tubular and work in cooperation to deploy a plurality of LCFs to form a seal along the lost circulation zone.
E21B 33/13 - Methods or devices for cementing, for plugging holes, crevices, or the like
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
Systems, methods, and apparatuses for deploying a lost circulation fabric (LCF) to seal a lost circulation zone during a drilling operation. The LCF may be contained within a lost circulation fabric deployment system (LCFDS) that is coupled to a tubular of a drilling string. The LCFDS may include a controller and sensors to detect the presence of a lost circulation zone and deploy the LCF upon detection of the lost circulation zone. In some implementations, a plurality of LCFDSs may be disposed on the tubular and work in cooperation to deploy a plurality of LCFs to form a seal along the lost circulation zone.
E21B 33/13 - Methods or devices for cementing, for plugging holes, crevices, or the like
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
A method for reducing condensate in a subsurface formation is disclosed. The method includes introducing a reactive mixture including an aqueous solution, urea, dopamine, a silica nanoparticle precursor, a silane grafting compound, and an alcohol compound into the subsurface formation. The method also includes allowing generation of ammonia through thermal decomposition of the urea and allowing the silica nanoparticle precursor to hydrolyze, thereby forming silica nanoparticles. The method further includes allowing the silane grafting compound to graft onto the silica nanoparticles, thereby forming functionalized silica nanoparticles. The method also includes allowing polymerization of the dopamine, thereby forming polydopamine. The method also includes allowing the functionalized silica nanoparticles to attach to the subsurface formation via the polydopamine, thereby reducing condensate in the subsurface formation.
C09K 8/86 - Compositions based on water or polar solvents containing organic compounds
C09K 3/18 - Materials not provided for elsewhere for application to surface to minimize adherence of ice, mist or water thereto; Thawing or antifreeze materials for application to surfaces
Methods for producing proppants with a polyurethane proppant coating are provided. The methods include forming aliphatic polycarbonate polyols from the copolymerization of epoxide and CO2 monomers, forming the polyurethane proppant coating by reacting the aliphatic polycarbonate polyols and at least one of diisocyanate monomers and isocyanate monomers, and coating proppant particles with the polyurethane proppant coating to produce coated proppants with polyurethane proppant coating.
Methods for producing proppants with a fluorinated polyurethane proppant coating are provided. The methods include coating the proppant particles with a strengthening agent, a strengthening agent, and a resin to produce proppants with fluorinated polyurethane proppant coating. Additionally, a proppant comprising a proppant particle and a fluorinated polyurethane proppant coating is provided. The fluorinated polyurethane proppant coating includes a strengthening agent, a strengthening agent, and a resin. The fluorinated polyurethane proppant coating coats the proppant particle. Additionally, a method for increasing a rate of hydrocarbon production from a subsurface formation through the use of the proppants is provided.
A composition includes an emulsion of nanocomposite in water and a proppant. The nanocomposite includes an epoxy resin and an organically modified montmorillonite compatible to the epoxy resin.
A system and method of evaluating and correcting for the effects of a near-surface anomaly on surface-to-borehole (STB) measurement data in a geological halfspace comprises transmitting electromagnetic radiation from an EM source located on a ground surface which is positioned over the near- surface anomaly, measuring EM fields at a plurality of remote EM receivers located on the surface at a far distance from the EM source, obtaining vertical STB measurement data downhole, determining an orientation and moment of a secondary source equivalent dipole associated with the near- surface anomaly excited by the radiation transmitted by the EM source based on measurements of the EM fields at the plurality of remote receivers, determining a correction factor for the secondary source equivalent dipole on the EM field measurements at the plurality of remote receivers, and removing the effects of the near surface anomaly on the vertical STB measurement data using the correction factor.
G01V 3/26 - Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination or deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device
60.
NANOPARTICLE COATED PROPPANTS AND METHODS OF MAKING AND USE THEREOF
Methods for producing proppant with nanoparticle proppant coating are provided. The methods include coating the proppant particles with a strengthening agent, functionalized nanoparticles, and unfunctionalized organic resin to produce proppant with nanoparticle proppant coating. Additionally, a proppant comprising a proppant particle and a nanoparticle proppant coating is provided. The nanoparticle proppant coating includes a strengthening agent, functionalized nanoparticles, and unfunctionalized organic resin. The nanoparticle proppant coating coats the proppant particle. Additionally, a method for increasing a rate of hydrocarbon production from a subsurface formation through the use of the proppant is provided.
KING ABDULLAH UNIVERSITY OF SCIENCE AND TECHNOLOGY (Saudi Arabia)
Inventor
Hveding, Frode
Ashry, Islam
Yuan, Mao
Ooi, Boon Siew
Arsalan, Muhammad
Abstract
Methods, systems, and apparatuses for simultaneous distributed temperature and vibration sensing using a multimode optical fiber (MMF) is disclosed. The distributed temperature and vibration sensing may include a single mode optical fiber (SMF) coupled to an MMF via a connection in which a central axis of the SMF is aligned with a central axis of the MMF. The connections provides of excitation of the fundamental mode within the MMF by light passing from the SMF into the MMF through the connection.
G01D 21/02 - Measuring two or more variables by means not covered by a single other subclass
G01K 11/324 - Measuring temperature based on physical or chemical changes not covered by group , , , or using changes in transmittance, scattering or luminescence in optical fibres using Raman scattering
G01D 5/353 - Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable using optical means, i.e. using infrared, visible or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre
G01H 9/00 - Measuring mechanical vibrations or ultrasonic, sonic or infrasonic waves by using radiation-sensitive means, e.g. optical means
The present disclosure is directed to systems, methods, and apparatuses for obtaining sensor data from sensors incorporated into a drill bit during a drilling operation to form a wellbore. The obtained sensor data may be used to control an aspect of the drilling operation. The sensors may be incorporated into drill bit cutters of a drill bit, a drill bit body of a drill bit, or both. Example sensors include acoustic sensors, pressure sensor, vibration sensor, accelerometers, gyroscopic sensors, magnetometer sensors, and temperature sensors.
E21B 47/107 - Locating fluid leaks, intrusions or movements using acoustic means
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
A drill bit includes multiple cutting devices and a microelectronics unit. Each cutting device of the multiple cutting devices includes a cutting layer formed to cut a rock formation and a capacitive sensor disposed adjacent the cutting layer. The capacitive sensor is configured to generate an electric field across the cutting layer and to transmit a signal corresponding to a voltage associated with the electric field. The microelectronics unit of the drill bit is configured to receive the signal from the capacitive sensor of each cutting device of the multiple cutting devices such that the microelectronics unit receives multiple signals and to determine an indicator of mechanical wear of the drill bit based on a change in the voltage associated with the electric field across the cutting layer of each cutting device of the multiple cutting devices using the multiple signals.
Methods of determining the integrity of a well are provided. The methods include mixing conductive materials into a fluid, introducing the fluid into the well, and allowing the conductive materials to coat a surface of a subsurface formation, thereby forming an electrically conductive data conduit coating. The methods further include transmitting data through the electrically conductive data conduit coating to determine the integrity of the well.
E21B 47/005 - Monitoring or checking of cementation quality or level
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
C09K 8/00 - Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
E21B 33/138 - Plastering the borehole wall; Injecting into the formation
65.
METHODS FOR THE PRODUCTION OF NANOCOMPOSITES FOR HIGH TEMPERATURE ELECTROCHEMICAL ENERGY STORAGE DEVICES
Presented here are nanocomposites and rechargeable batteries, In certain embodiments, a nanocomposite is resistant to thermal runaway, and useful as an electrode material in rechargeable batteries that are safe, reliable, and stable when operated at high temperature and high pressure. The present disclosure also provides methods of preparing rechargeable batteries. For example, rechargeable batteries that include nanocomposites of the present disclosure as an electrode material have, in some embodiments, an enhanced performance and stability over a broad temperature range from room temperature to high temperatures. These batteries fill an important need by providing a safe and reliable power source for devices operated at high temperatures and pressures such as downhole equipment used in the oil industry.
Systems, methods, and apparatuses for detecting components of a multiphasic flow are disclosed. A flowmeter may include a plurality of optical fibers disposed across a fluid flow. The optical fibers may generate backscattering of a portion of a laser beam transmitted along the optical fibers. The backscattering may be produced by a grating formed by zinc dicyanoaurate formed in each of the optical fibers. Heterodyne detection may be used to determine a Brillouin frequency shift that is used to determine strain and temperature measurements at different locations along the optical fibers. Artificial Intelligence uses the strain and temperature measurements to determine a flow regime of the fluid flow and flow rates of components forming the fluid flow.
G01F 1/74 - Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid
E21B 47/113 - Locating fluid leaks, intrusions or movements using light radiation
G01F 1/05 - Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects
G01F 1/688 - Structural arrangements; Mounting of elements, e.g. in relation to fluid flow using a particular type of heating, cooling or sensing element
G01K 11/322 - Measuring temperature based on physical or chemical changes not covered by group , , , or using changes in transmittance, scattering or luminescence in optical fibres using Brillouin scattering
67.
METHODS AND SYSTEMS FOR DETERMINING FRACTURE AND MATRIX PERMEABILITY OF A SUBSURFACE FORMATION
Methods and systems for determining fracture and matrix permeability of a subsurface formation. The system includes two upstream reservoirs and two downstream reservoirs, and a sample cell connecting to the reservoirs with valves. The sample cell has a confining pressure (CF) from a fluid. A horizontal plug sample with sleeve is placed in a measurement cell with the confining fluid (CF). A pressure gauge is connected to the small upstream reservoir, and a pressure gauge is connected to the small downstream reservoir. The results provide two sets of effective-stress-dependent permeability values (including fracture permeability and matrix permeability, respectively) for characterizing the reservoir properties.
A system and method for specifying a composition for a frac fluid including varying crosslinker concentration and high-temperature stabilizer concentration to determine a discrete fracture network (DFN) and hydrocarbon production correlative with the DFN.
A casing for a drilling operation has a body portion having a length, a first end and a second end, an outer diameter, an inner diameter, and a central axis that is common to the outer diameter and the inner diameter, and an external thread formed on the outer diameter of the body portion, wherein the external thread starts at a first predetermined distance from the first end and ends at a second predetermined distance from the second end. The external thread includes a spiral groove or a helical thread formed on the outer diameter of the body portion. The casing includes a coating at least partially encapsulating the external thread, wherein the coating includes at least one material selected from the group consisting of polycrystalline diamond particles, diamond like carbon (DLC), tungsten carbide, boron nitride, silicon carbide, silicon nitride, and combinations thereof.
A method and compounds for enhanced oil recovery (EOR) including flooding of a mixture of water and one or more of the compounds in a geological formation. The compounds have a fluoroalkyl group.
C09K 8/588 - Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
71.
CEMENT SLURRIES, CURED CEMENT AND METHODS OF MAKING AND USE OF THESE
Cement slurries, cured cements, and methods of making cured cement and methods of using cement slurries are provided. The cement slurries have, among other attributes, improved elasticity and self-healing properties and may be used, for instance, in the oil and gas drilling industry. The cement slurry comprises water, a cement precursor material, and a block copolymer composition. The block copolymer composition has at least one copolymer backbone, with each copolymer backbone comprising at least two hard segments. Furthermore, a soft segment is disposed between the at least two hard segments. The copolymer backbone has at least one anhydride group grafted onto the soft segment, and the anhydride group is crosslinked by an aminosilane crosslinker.
C09K 8/467 - Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
A system and method for flow synthesis of polymer nanoparticles in a continuous flow reactor having a channel. The polymer nanoparticles are synthesized from monomer in the presence of an initiator.
Systems, methods, and apparatuses for determining pore volume and pore volume compressibility of secondary porosity in rock samples is disclosed. In some implementations, determining a pore volume of a secondary porosity in a rock core sample may include saturating the rock sample with deuterium oxide (D2O) by applying a vacuum to the core sample covered by D2O; centrifuging the saturated rock sample at a selected rotational speed in the presence of a second fluid to displace a portion of the D2O from the rock sample with the second fluid; measuring the rock sample with low-field 1H nuclear magnetic resonance (NMR) to determine a volume of the second fluid within the rock sample; and determining a pore volume associated with a secondary porosity based on the volume of the second fluid within the rock sample.
G01N 15/08 - Investigating permeability, pore volume, or surface area of porous materials
G01N 24/08 - Investigating or analysing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects by using nuclear magnetic resonance
G01R 33/44 - Arrangements or instruments for measuring magnetic variables involving magnetic resonance using nuclear magnetic resonance [NMR]
74.
METHODS AND SYSTEMS FOR DETERMINING CORE PERMEABILITY IN PULSE DECAY EXPERIMENTS
Methods and systems method for determining core permeability of a subsurface formation. The method includes connecting an upstream reservoir to one end of a sample holder comprising a core sample of a subsurface formation, connecting a downstream reservoir to another end of the sample holder, providing a constant confining pressure within the sample holder, saturating the sample holder and the core sample with nitrogen at a saturation pressure, applying a pressure pulse to one end of the sample holder, and determining core permeability using the porosity of the mobile continuum when the pressure in the upstream reservoir, the downstream reservoir, and the mobile continuum is in equilibrium.
Real-time field data that is associated with a hydrocarbon reservoir drilling field is obtained. A carrying capacity index (CCI) and a cutting concentration annulus (CCA) are determined based on the real-time field data. In response to determining the CCI and CCA, the CCI is compared with a first predetermined value and the CCA is compared with a second predetermined value to obtain a comparison result. One or more parameters associated with the hydrocarbon reservoir drilling field are adjusted based on the comparison result through a user interface (UI).
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
A microchip (100) includes a PCB (102), a first contact feature (108) positioned along a first area of the PCB (102), a second contact feature (108) positioned along a second area of the PCB (102) that is disposed opposite the first area, a contact frame (110) including first and second contact members (124) respectively coupled to the first and second contact features (108) for signal communication between the first and second contact features (108) and an external electronic device, and a housing (112) enclosing an interior region of the microchip (100) and carrying the first and second contact members (124) of the contact frame (120).
Methods, systems, and computer-readable medium to perform operations including: obtaining, in real-time from one or more sensors of a drilling system, real-time drilling data of a drilling operation of drilling a wellbore; using the drilling data to calculate a carrying capacity index (CCI) of a drilling fluid and a cutting concentration in an annulus (CCA) of the wellbore; determining that at least one of the CCI and the CCA is outside a respective range; determining a corrective action to adjust the at least one of the CCI and the CCA to be within the respective range; and performing the corrective action.
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
78.
UNFOLDABLE DEVICE FOR CONTROLLING LOSS CIRCULATION
Embodiments of the disclosure provide an unfoldable device for controlling lost circulation in a target lost circulation zone in a borehole. The unfoldable device includes a sheet, a backbone, and a shell. The sheet has an unfolded state and a folded state. The backbone reinforces the sheet. The backbone includes a shape-memory material having an original state and a deformed state. The shell encapsulates the sheet in the folded state and the backbone in the deformed state. In some embodiments, the shell includes a degradable polymer that degrades in the borehole upon contact with a drilling fluid such that the sheet transitions to the unfolded state and the backbone transitions to the original state. The sheet in the unfolded state accumulates on a borehole wall at least partially covering an entrance to a macrochannel of the target lost circulation zone.
C09K 8/516 - Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
E21B 21/00 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
E21B 33/13 - Methods or devices for cementing, for plugging holes, crevices, or the like
Methods, systems, and computer-readable medium to perform operations including: determining, in real-time, values of drilling parameters of a drilling system drilling a wellbore; calculating, based on the values of the drilling parameters, a cuttings concentration in an annulus of the wellbore (CCA); calculating, based on the calculated CCA and a mud weight (MW) of a drilling fluid, an effective mud weight (MWeff) of the drilling fluid; and controlling, based on the effective mud weight, a component of the drilling system to adjust at least one of the drilling parameters.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 45/00 - Measuring the drilling time or rate of penetration
E21B 49/00 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
80.
REAL-TIME EQUIVALENT CIRCULATING DENSITY OF DRILLING FLUID
Methods, systems, and computer-readable medium to perform operations including: determining, in real-time, values of drilling parameters of a drilling system drilling a wellbore; calculating, based on the values of the drilling parameters, a cuttings concentration in an annulus of the wellbore (CCA); calculating, based on the calculated CCA and a mud weight (MW) of a drilling fluid, an effective mud weight (MWeff) of the drilling fluid; using the effective mud weight to calculate an equivalent circulating density (ECD) of the drilling fluid; and controlling, based on the equivalent circulating density, a component of the drilling system to adjust at least one of the drilling parameters.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
81.
AUTOMATED PRODUCTION OPTIMIZATION TECHNIQUE FOR SMART WELL COMPLETIONS USING REAL-TIME NODAL ANALYSIS
Systems and methods include a method providing automated production optimization for smart well completions using real-time nodal analysis including real-time modeling. Real-time well rates and flowing bottom-hole pressure data are collected by a multilateral well optimizing system at various choke settings for multiple flow conditions for each lateral of a multilateral well during regular field optimization procedures. Surface and downhole pressures and production metrics for each of the laterals are recorded for one lateral at a time. A multilateral well production model is calibrated using the surface and downhole pressures and the production metrics for each of the laterals. Flowing parameters of individual laterals are estimated using the multilateral well production model. An optimum pressure drop across each downhole valve is determined using the multilateral well production model. A productivity of each lateral is estimated using the model during the commingled production at various choke valves settings.
Systems, methods, and devices for performing real-time detecting and spatially- positioning a waterfront in an oil-producing reservoirs are disclosed. An example method of predicting movement of a waterfront in a reservoir may include generating a plurality of electrical signals having different frequencies with a surface electric source; injecting currents corresponding to the plurality of generated signals into the earth near a well extending into the reservoir with a surface dipole; sensing a vertical component of an electric field generated by each of the injected currents at a location in the reservoir with a sensor; detecting a location of the waterfront within the reservoir based on the received vertical components of the electric fields; and analyzing the detected vertical components of the electric fields taken on at least two different points in time with machine learning to predict a rate of movement of the waterfront within the reservoir.
E21B 47/113 - Locating fluid leaks, intrusions or movements using light radiation
E21B 47/125 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using earth as an electrical conductor
E21B 47/13 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range
A method for stimulating production of hydrocarbons from a sandstone formation includes the steps of injecting a stimulation fluid into the sandstone formation, the stimulation fluid formed from a hydrofluoric acid precursor and an oxidizer; injecting an ammonium containing compound into the sandstone formation; and injecting a nitrite containing compound into the sandstone formation. The method further includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation to initiate reaction of the ammonium containing compound and the nitrite containing compound to generate heat and nitrogen gas, where upon generation of heat within the formation the hydrofluoric acid precursor and the oxidizer react to form hydrofluoric acid in-situ to dissolve silica and silicate minerals and stimulate the sandstone formation. A treatment fluid for use in stimulating sandstone formations includes the stimulation fluid, the ammonium containing compound, and the nitrite containing compound.
Systems and methods include a method providing automated production optimization for smart well completions using real-time nodal analysis including comingled production calibration. Real-time well rates and flowing bottom-hole pressure data are collected at various choke settings for multiple flow conditions for each lateral of a multilateral well during regular field optimization procedures. Surface and downhole pressures and production metrics for each of the laterals are recorded for one lateral at a time during production of the well. Flowing parameters of individual laterals are estimated using the multilateral well production model. An optimum pressure drop across each downhole valve is determined using the multilateral well production model. Each lateral of the multilateral well is calibrated during the commingled production at various choke valves settings. The calibrating is done using the multilateral well production model, based at least in part on the optimum pressure drop across each downhole valve.
Systems and methods include a method for optimizing smart well completions using real-time nodal analysis including recommending changes to downhole settings. Real-time well rates and flowing bottom-hole pressure data at various choke settings for multiple flow conditions are collected for each lateral of a multilateral well. Recommended optimizing changes to downhole inflow control valve (ICV) settings for surface and subsurface ICVs are determined based on the real-time well rates and the flowing bottom-hole pressure data. The optimizing changes are designed to optimize production in the multilateral well. The recommended optimizing changes to the downhole ICV settings for the surface and subsurface ICVs in the laterals are provided for presentation to a user in a user interface of a multilateral well optimizing system. A user selection of one or more of the recommended optimizing changes is received. The recommended optimizing changes selected by the user are implemented.
A method for stimulating production of hydrocarbons from a sandstone formation includes the steps of injecting a stimulation fluid formed from a hydrofluoric acid generating precursor and an oxidizing agent, an ammonium containing compound, and a nitrite containing compound into the sandstone formation, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. The method further includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation to initiate reaction and generate heat and nitrogen gas. Upon generation of heat and degradation of the degradable encapsulation, the hydrofluoric acid generating precursor and the oxidizing agent react to form hydrofluoric acid in-situ to dissolve silica and silicate minerals and stimulate the sandstone formation. A treatment fluid for use in stimulating sandstone formations includes the stimulation fluid, the ammonium containing compound, and the nitrite containing compound.
A system and method for isolating a zone in a wellbore (102)having a sand screen (110) including applying hydrogel (118) into an annulus between the sand screen (110) and the geological formation (106) to form a hydrogel packer (202, 204) in the annulus.
A pressure regulator (107) is configured to manage a pressure downstream of a pump discharge (104F) during operation. A hydraulic piston (109) is exposed to pressure upstream of the pressure regulator (107) during operation. The hydraulic piston (109) extends into a first fluid reservoir (105B). The first fluid reservoir is defined by an inner surface of an outer housing of a subsurface safety valve (103). A subsurface safety valve (103) is fluidically couple to the hydraulic piston housing.
E21B 34/08 - Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
E21B 47/008 - Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
90.
METHOD FOR IMPROVING CEMENT TOUGHNESS USING A TRIAZINE-BASED POLYMERIC ADDITIVE
This document relates to methods for providing long-term zonal isolation in oil wells using cement compositions that contain triazine-based polymeric additives. The cement compositions containing the polymeric additives exhibit increased tensile strength, elastic strength, or both, without suffering a decrease in compressive strength, as compared to the same cement without the polymeric additive.
C09K 8/467 - Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
C04B 24/28 - Macromolecular compounds obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
B28C 5/00 - Apparatus or methods for producing mixtures of cement with other substances, e.g. slurries, mortars, porous or fibrous compositions
E21B 33/13 - Methods or devices for cementing, for plugging holes, crevices, or the like
91.
TESTING PETRO-PHYSICAL PROPERTIES USING A TRI-AXIAL PRESSURE CENTRIFUGE APPARATUS
A system for testing properties of a sample, the system including a test cell. The test cell includes a cell casing having a first end piece, a second end piece, and at least one wall extending between the first end piece and the second end piece. The cell casing defines a pressure boundary enclosing an interior region of the cell. The test cell further includes a sample chamber, a first reservoir, and a second reservoir disposed within the pressure boundary. The sample chamber defines an interior region. The first reservoir fluidly connects to the interior region of the sample chamber. The second reservoir fluidly connects to the interior region of the sample chamber. The test cell also has a piston assembly having a piston fluid chamber and a piston with a stem extending into the piston fluid chamber. The piston partially defines the sample chamber.
Systems and methods for identifying potential hydrocarbon traps in a subterranean region can include: receiving seismic data of the subterranean region, the seismic data acquired by at least one seismic sensor, the seismic data indicating positions of physical barriers to hydrocarbon flow in the subterranean region and using anisotropic lateral and upward erosion to identify possible locations of hydrocarbons.
A method of altering wettability of a subterranean formation penetrated by a well is described. A first oxidizer including a persulfate is introduced to the subterranean formation. A second oxidizer including a bromate is introduced to the subterranean formation. The well is shut in for a period of time to allow the first oxidizer and the second oxidizer to alter the wettability of the subterranean formation toward non-wetting of oil and of water.
A system and method for forming mineral or proppant in-situ in fractures in a geological formation via a fracturing fluid. The mineral or proppant is formed from rock in the geological formation.
A system for testing properties of a sample, the system including a test cell. The test cell includes a cell casing having a first end piece, a second end piece, and at least one wall extending between the first end piece and the second end piece. The cell casing defines a pressure boundary enclosing an interior region of the cell. The test cell further includes a sample chamber, a first reservoir, and a second reservoir disposed within the pressure boundary. The sample chamber defines an interior region. The first reservoir fluidly connects to the interior region of the sample chamber. The second reservoir fluidly connects to the interior region of the sample chamber. The test cell also has a piston assembly having a piston fluid chamber and a piston with a stem extending into the piston fluid chamber. The piston partially defines the sample chamber.
A porous micromodel network to simulate formation flows includes a substrate, two or more porous micromodels formed on the substrate and a fluid inlet formed on the substrate. The first porous micromodel defines a first fluidic flow pathway and is representative of a first hydrocarbon-carrying formation. Flow through the first fluidic flow pathway is representative of flow through the first hydrocarbon-carrying formation. The second porous micromodel is fluidically isolated from the first porous micromodel. The second porous micromodel defines a second fluidic flow pathway different from the first fluidic flow pathway. The second porous micromodel is representative of a second hydrocarbon-carrying formation different from the first hydrocarbon-carrying formation. Flow through the second fluidic flow pathway is representative of flow through the second hydrocarbon-carrying formation. The fluid inlet is fluidically configured to simultaneously flow fluid to the first fluidic flow pathway and the second fluidic flow pathway.
E21B 49/00 - Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
The present disclosure relates to methods of suspending proppants in a hydraulic fracturing fluid including adding a quantity of precursor nanoparticles including carbon nanotubes supported by metal oxide catalyst nanoparticles to the hydraulic fracturing fluid. The metal oxide catalyst nanoparticles and the hydraulic fracturing fluid are selected such that the metal oxide catalyst nanoparticles are dissolvable in the hydraulic fracturing fluid. The metal oxide catalyst nanoparticles dissolve in the hydraulic fracturing fluid, resulting in an amount of carbon nanotubes dispersed within the hydraulic fracturing fluid. The carbon nanotube dispersion increases the value of at least one of a Newtonian viscosity, a yield point, a plastic viscosity, and a density of the hydraulic fracturing fluid with the dispersed carbon nanotubes versus a similar or equivalent hydraulic fracturing fluid without the carbon nanotube dispersion. The method may further include adding proppants to the hydraulic fracturing fluid.
The present disclosure relates to methods of making nanocomposite coated proppants with a nanocomposite coating, including adding a quantity of precursor nanoparticles comprising carbon nanotubes supported by metal oxide catalyst nanoparticles to an uncured resin. The metal oxide catalyst nanoparticles and the uncured resin are selected such that the metal oxide catalyst nanoparticles are dissolvable in the uncured resin. The metal oxide catalyst nanoparticles are capable of dissolving in the uncured resin such that an amount of carbon nanotubes are dispersed within the uncured resin to form a nanocomposite coating. The method may further include coating proppant particles with the nanocomposite coating to make nanocomposite coated proppants.
A system and method for evaluating kerogen-rich shale (KRS) including measuring, via scanning microscopy, electrical conductivity of a KRS sample and a mechanical property of the KRS sample.
G01Q 60/24 - AFM [Atomic Force Microscopy] or apparatus therefor, e.g. AFM probes
G01Q 60/00 - Particular types of SPM [Scanning-Probe Microscopy] or apparatus therefor; Essential components thereof
G01N 23/2251 - Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups , or by measuring secondary emission from the material using electron or ion microprobes using incident electron beams, e.g. scanning electron microscopy [SEM]
In a dual injection method for hydrocarbon reservoir management, a production well (102a, 102b) is formed from a surface to a hydrocarbon-bearing zone (104) in the reservoir. A first injection well (106a) and a second injection well (106b) are formed from the surface to a first depth and a second depth, respectively, in a water-bearing zone (108) below the hydrocarbon-bearing zone, the second depth shallower than the first depth. A first injectant of a first type and a second injectant of a second type injected into the water-bearing zone through the first injection well and the second injection well, respectively.The second injectant is injected to sweep hydrocarbons in the hydrocarbon-bearing zone toward the production well. The first injectant is injected to sweep the second injectant toward the hydrocarbon-bearing zone. At least a portion of the hydrocarbons are produced through the production well.
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