Abstract: A method for generating a core description is disclosed. The method includes coring and collecting rock cores from geographical locations in the subterranean formation, detecting, using an augmented reality (AR) device worn by a user, content of an identifying tag of a rock core within a device view of the AR device to identify a well where the rock core is obtained, retrieving, by the AR device from a data repository, historical data of the well, activating, by the AR device, a sensor to acquire additional data from the rock core to supplement the historical data, and presenting, by the AR device, an AR image including a first image of the historical data and the additional data superimposed over a second image of the rock core, where the user generates the core description based on viewing the AR image.

Abstract: A system for validating a flow rate of a water injection well includes a first data source providing operating data associated with the well, a data repository, a digital model of the well, a second data source, and a processor. The processor is configured to obtain operating data, including a measured flow rate, historical data, and the digital model, determine a modelled flow rate using the digital model based on the historical injection data and the operating data, compare the measured flow rate with the modelled flow rate to determine a delta, receive a second measured flow rate from the second data source, compare the second measured flow rate to the modelled flow rate to determine a second delta, and in response to determining that the second delta does not exceed the threshold value, automatically generate a request for remediation of the first data source.

Abstract: A wellbore workover tool assembly to apply internal coatings to wellbore tubulars for workover operations includes a coating sub-assembly, a composition and a wellbore conveyance. The coating sub-assembly can be lowered through a wellbore tubular installed within a wellbore. The composition can be carried by the coating sub-assembly. The coating sub-assembly can coat the composition on an inner wall of the wellbore tubular. The composition can be configured to increase a mechanical strength of the wellbore tubular. The wellbore conveyance can be operatively coupled to the coating sub-assembly carrying the composition. The wellbore conveyance can lower and raise the coating sub-assembly through the wellbore as the coating sub-assembly coats the composition on the inner wall of the wellbore tubular.

Abstract: A composition of an invert emulsion oil-based drilling fluid is provided. The composition may include an oil phase and an aqueous phase. The oil phase may include an oleaginous fluid, an organophilic clay-based solid viscosifier, and a liquid viscosifier including a POSS. Further provided is a method of introducing the composition including the POSS into a wellbore. After introduction of the composition into the wellbore, the method includes maintaining wellbore conditions to provide a stable rheological property for a period up to about 96 hours in an HPHT section of a wellbore.

Abstract: A method of processing a hydrocarbon feed may comprise fractionating the hydrocarbon feed into a light stream, a middle stream and a heavy stream; hydrotreating the heavy stream to form a hydrotreated heavy stream; feeding the light stream to a first Fluid Catalytic Cracking (FCC) reaction zone; feeding the middle stream to a second FCC reaction zone; and feeding the hydrotreated heavy stream to a third FCC reaction zone, thereby producing a heavy product stream comprising light olefins; and feeding one or more of the product streams to one or more fractionators, thereby producing one or more finished product streams and one or more recycle streams comprising one or more of light cycle oil (LCO), heavy cycle oil (HCO), and slurry oil; and hydrotreating one or more of the recycle streams to form the hydrotreated heavy stream.

Abstract: A system and a method for forming a composite electrolyte structure are provided. An exemplary composite electrolyte structure includes, at least in part, polymer electrolyte preforms that are bonded into the composite electrolyte structure.

Abstract: A multiphase fluid is flowed from a flow pipe to a U-bend. Several differential pressures of the multiphase fluid flowing through the flow pipe and U-bend are measured. A mixture density of the multiphase fluid is determined at least based on the measured differential pressures. A total flow rate of the multiphase fluid is determined at least based on the measured differential pressures. In some cases, flow rates of each of the phases of the multiphase fluid can be determined at least based on the measured differential pressures.

Abstract: A downhole tool is disclosed that includes an expandable liner, an expansion cone, and an expansion cone driver connected to the expansion cone. The expandable liner includes an upper tubular body, a lower cone housing having an outer diameter greater than the upper tubular body, a eutectic alloy layer surrounding a circumference of the upper tubular body, and a bottom packer and a top packer extending around the upper tubular body and positioned around opposite ends of the eutectic alloy layer. The expansion cone has a cone body provided in the lower cone housing and a heater provided around an outer surface of the cone body.

Abstract: An apparatus, which is for connecting a first tubular and a second tubular in a downhole environment, includes a first component having a first component uphole end and a first component downhole end. The first component uphole end includes an uphole connection configured to connect to the first tubular. The apparatus includes a second component having a second component uphole end and a second component downhole end. The second component uphole end includes an extending portion and the second component downhole end includes a downhole connection configured to connect to the second tubular. The apparatus includes a weak point connection releasably connecting the first component downhole end to the second component uphole end. The weak point connection is releasable by applying uphole force on the first tubular, and the extending portion of the second component is exposed uphole by release of the weak point connection.

Abstract: A method of drilling a wellbore includes rotating a drill bit positioned at a distal end of a drill string and thereby drilling a portion of the wellbore, the drill bit including a bit body and one or more variable gauge pads removably coupled to the bit body, retrieving the drill bit to a well surface at a well site and removing a used variable gauge pad of the one or more variable gauge pads from the bit body at the well site, coupling a new variable gauge pad to the bit body in place of the used variable gauge pad, and extending the drill bit with the new variable gauge pad back into the wellbore and resuming drilling operations with the drill bit.

Abstract: A system includes a multiphase flow meter and a removable adjustment device. The multiphase flow meter includes a venturi having a throughbore with a first diameter, and a throat having a second diameter at a center of the venturi. The first diameter is larger than the second diameter. The removable adjustment device is installed in the throat. The removable adjustment device includes a plurality of fins; a fin controller configured to actuate the plurality of fins between an open position and a closed position; and a cover surrounding the plurality of fins.

Abstract: Processes and systems for stabilizing a condensate feed and mitigating fouling include providing a raw condensate, having greater than 2000 ppmv free and emulsified water, to a stabilizer feed drum. The free and emulsified water has greater than 40000 ppm salt. The stabilizer feed drum comprises a liquid-liquid separation parallel plate pack internals to separate the raw condensate into a water phase and an oil phase. The resulting oil phase comprises less than 500 ppmv free and emulsified water and is fed to a stabilizer system including a stabilizer column and one or more reboilers. In the stabilizer system, the oil phase is separated into a vapor and a stabilized condensate. The process includes operating the stabilizer column at an overhead pressure greater than 12 barg and a bottoms temperature greater than 135° C. The stabilized condensate has a true vapor pressure (TVP) of less than 3.8 barg.

Abstract: A method of constructing a mechanical earth model (MEM) includes integrating a density logging data set to compute vertical stress and applying correlation models or equations to estimate a pore pressure and mechanical properties. The method also includes calibrating the pore pressure with drill stem test data, calibrating the mechanical properties with laboratory tests on core plugs or on rock cuttings, estimating a minimum horizontal stress using correlation models, and calibrating the minimum horizontal stress with minifrac tests. The method further includes estimating a maximum horizontal stress using the correlation models while assuming one or more correlation parameters, calibrating the maximum horizontal stress with a global pattern of tectonic strains and a basin stress regime, evaluating one or more breakout regions using the MEM, a trajectory of a well, and a geometry of a pilot hole, and comparing the one or more breakout regions and a caliper logging data set.

Abstract: In accordance with one or more embodiments of the present disclosure, a rotary evaporator is disclosed. The rotary evaporator may include a base, an evaporation vessel, a rotary union, a motor for rotating the evaporation vessel, a heat jacket, a purge tube and a purge system. The evaporation vessel includes a mounting end that is coupled to the rotary union and an opposite end, with an opening defined in the opposite end and a reservoir in communication with the opening for receiving a sample through the opening. The heat jacket heats or cools the sample when contained in the evaporation vessel, and the purge system controllably supplies fluid to the evaporation vessel via the purge tube.

Abstract: Systems and methods for well field optimization are described. A system includes a well injection planner coupled to a machine learning (ML) engine. A computer-readable memory stores a trained model, input data, and predictive results data. The well injection planner is implemented on at least one processor and is configured to provide the trained model and the input data to an inference stage of the ML engine and to receive the predictive results data output from the inference stage. The input data includes at least water injection rate and voidage replacement data for a well field and the output predictive results data includes a cumulative oil production forecast result for the well field.

Abstract: A method to measure flow rate and water cut (WC) of a well includes: from a data set, for depths of two pressure gauges installed in the well, acquiring simulated pressures and corresponding simulated flow rates and simulated WCs; measuring pressures at the depths of the two pressure gauges via the two pressure gauges; comparing the measured pressures with the acquired simulated pressures, by calculating error values for the measured pressures with respect to the acquired simulated pressures; obtaining simulated flow rates and simulated WCs that correspond to the calculated error values not greater than a threshold; and averaging the simulated flow rates and simulated WCs that correspond to the simulated pressures that have the error values not greater than the threshold, to acquire an estimated flow rate and an estimated WC at the depths of the two pressure gauges.

Abstract: An electrical submersible pumping assembly includes a motor, a pump connected to the motor by a shaft, and a labyrinth type seal section between the motor and pump. Hydrostatic pressure is communicated between the motor and pump across the seal section and through a breather tube in the seal section that is configured to restrict fluid communication from the pump to the motor. A U-shaped bend is provided in the breather tube to increase its effective length. Optionally, a number of recycle loops are formed on the breather tube similar to a Tesla valve. In an alternative, the shaft includes a helical flight that directs fluid to a mechanical shaft seal between pump and seal section.

Abstract: A quench system for sulfur recovery including a quench line for delivering a CO2 rich off gas into a feed line of the sulfur recovery unit converter system, an oxidation air inlet for feeding an oxidation air to an oxidation air preheater, a feed preheater for receiving the heated oxidation air, the CO2 rich off gas, the process gas, or a combination thereof, a selective oxidation converter disposed downstream of the feed preheater for producing a converter effluent, an off gas control valve disposed in the quench line for controlling the CO2 rich off gas to the selective oxidation converter, wherein the CO2 rich off gas is used for quenching a potential fire, and cooling preheaters and a selective oxidation converter when temperature exceeds normal operating limits or fire is suspected.

Abstract: A method and a system for predicting well production of a reservoir using machine learning models and algorithms is disclosed. The method includes obtaining a training data set for training a machine learning (ML) model and selecting an artificial neural network model structure, the model structure including a number of layers and a number of nodes of each layer. Further, the method includes generating a plurality of individually trained ML models and calculating a model performance of each trained model by evaluating a difference between a model prediction and a well performance data. The plurality of top-ranked individually trained ML models is constrained using one or multiple known physical rules. A plurality of individual predicted well production data is generated using the geological, the completion, and the petrophysical data of interest and a final predicted well production data is generating based on the plurality of individual predicted well production data.

Abstract: A remote gas calibration (RGC) assembly is used for preventive maintenance of a gas sensor installed in an inaccessible location inside of a gas turbine equipment. The RGC assembly includes a connector adapted to couple to the gas sensor, where the connector is connected to a first end of a tubing, a needle valve adapted to control flow of gas through the tubing, where the needle valve is connected to a second end of the tubing, and a smart gas monitor in flow communication with the tubing and adapted to record data related to the flow of gas through the tubing. The tubing has a length that allows the needle valve to be placed in an accessible location external to the gas turbine equipment when the connector is coupled to the gas sensor.