Abstract: A Waventuri flowmeter includes a Venturi flowmeter with a multiphase fraction measurement device incorporated therein. The Waventuri flowmeter includes an inlet for receiving a wellbore fluid into the flowmeter, the inlet defining an inlet diameter and an outlet for discharging the wellbore fluid from the flowmeter, the outlet defining an outlet diameter. A flow path extends between the inlet and the outlet and includes a converging section downstream of the inlet and a diverging section downstream of the converging section. At least one sensor is operable to detect a parameter indicative of pressures of the wellbore fluid at the inlet and a throat between the converging and diverging sections. First and second permittivity sensors extend axially along the diverging and converging sections, respectively. The first and second permittivity sensors are operable to measure parameters indicative of multiphase volume fractions of the wellbore fluid within the diverging and converging sections.

Abstract: A system includes a pipeline for flowing a fluid therein and a multiphase sampler fluidly coupled to the pipeline. The multiphase sampler includes an inlet to receive a fluid sample of the fluid from the pipeline, a Tesla valve(s) coupled between the pipeline and the inlet of the multiphase sampler to direct a flow of the fluid sample into a sensing section, and an outlet to return the fluid sample back into the pipeline. The sensing section includes at least one sensor to determine a water-cut of the fluid sample. A method includes flowing a fluid through a pipeline, streaming off a fluid sample from the fluid into an inlet of a multiphase sampler, determining a water-cut of the fluid sample in a sensing section of the multiphase sampler, and directing the fluid sample back into the pipeline.

Abstract: A method for solving a multiphase fluid flow model with an iterative sol ve that is initialized using artificial intelligence. The method includes obtaining a set of equations, the set of equations including at least one equation, and the set of equations modeling a flow of a multiphase fluid, where the flow is characterized by a set of flow variables. The method further includes determining, with an artificial intelligence model, a predicted set of flow variables at a timestep given one or more prior sets of flow variables each previously determined at an associated prior timestep, and determining, with an iterative solver applied to the set of equations, the set of flow variables at the timestep, where the iterative solver is initialized with the predicted set of flow variables at the timestep.

Abstract: A fluid flows through a flowmeter system including a first conduit, a U-bend, and a second conduit. Various differential pressures of the fluid flowing through the flowmeter system are measured. The differential pressures of the fluid are measured by various pressure sensors (for example, differential pressure sensors) installed on the flowmeter system. Rheology of the fluid is characterized by performing calculations using the measured differential pressures of the fluid and relative positions of the pressure sensors throughout the flowmeter system.

Abstract: Systems and methods include a digital twin model for multiphase flows in the oil and gas industry. A digital twin replicating non-linear and non-monotonic dielectric properties of a multiphase mixture flowing through a pipe is generated. The digital twin includes a finite element method based electromagnetic model. The digital twin is calibrated, under controlled flow conditions at elevated pressures to generate a calibrated digital twin. The calibrated digital twin is validated using the multiphase mixture with respect to water-cut (WC) and gas volume fraction (GVF) to generate a validated digital twin. Flow rates of the multiphase mixture are received from the microwave-based sensor system. A composition of the multiphase mixture flowing through the pipe is estimated by processing the flow rates using the validated digital twin. An adjustment of a setting of an industrial equipment is triggered based on the composition of the multiphase mixture.

Abstract: An autonomous downhole tool includes a housing including at least one modular sleeve that rides on the housing and is configured to adjust to conceal or expose a shift latch that includes a latch profile. The latch profile is shaped to interface with a shift sleeve profile of a shift sleeve of a downhole valve installed in a wellbore tubular that extends through a wellbore formed from a terranean surface into a subterranean formation. The autonomous downhole tool includes an autonomous carrier coupled with the housing and including an actuator module configured to generate a shift force to adjust the shift sleeve on the downhole valve with the shift latch engaged with the shift sleeve through mechanical engagement of the latch profile with the shift sleeve profile.

Abstract: Technologies for multiphase flow measurement using micro-electro-mechanical sensing are described. An electromagnetic signal and an acoustic signal generated by reflections of a multiphase mixture flowing through a pipe are received. A differential pressure of the multiphase mixture is received. Flow rates of the multiphase mixture are received from a microwave-based sensor system. A water content of the multiphase mixture flowing through the pipe is determined by processing the electromagnetic signal. A flow velocity and a water-cut of the multiphase mixture flowing through the pipe is determined by processing the acoustic signal. A mass velocity of the multiphase mixture flowing through the pipe is determined by processing the differential pressure of the multiphase mixture. A composition of the multiphase mixture of the pipe in the industrial flow loop is estimated based on the water content, the flow velocity, and the mass velocity of the multiphase mixture.

Abstract: Methods and systems for determining a composition of a gas in a pipe using a plurality of pressure sensors disposed along the pipe. Each pressure sensor in the plurality of pressure sensors may include a diaphragm for sensing pressure that is aligned with an inner wall of the pipe, and the location of each pressure sensor in the plurality of pressure sensors may be known. The method generally includes obtaining a plurality of pressure signals from the plurality of pressure sensors, determining, using the plurality of pressure signals, a speed of sound of the gas, and determining, using the plurality of pressure signals, an attenuation of sound intensity of the gas. The method further includes determining, with a computational model, the composition of the gas, based on the determined speed of sound of the gas and the attenuation of sound intensity of the gas.

Abstract: A thru-tubing completion system includes a sub-surface completion unit (SCU) configured to pass through a production tubing disposed in a wellbore in at least an open holed portion of the wellbore and perform completion operations in the target zone. The SCU includes an expandable liner; and one or more SCU anchoring seals configured to be positioned in an un-deployed position and a deployed position. The un-deployed position of the one or more SCU anchoring seals enables the SCU to pass through the production tubing, and the deployed position of the one or more SCU anchoring seals provides a seal against a wall of the open holed portion of the wellbore to provide zonal isolation between regions in the wellbore. The one or more SCU anchoring seals includes a chemically active expandable metal configured to expand in the deployed position to provide the seal against the wall of the open holed portion of the wellbore.

Abstract: A system for water cut sensing in an oil-water flow includes a laser-based spectroscopy sensor and a computer system. The laser-based spectroscopy sensor includes a first set of lasers that expose the oil-water flow to a first incident signal, a first photodetector that collects a first transmitted signal, the first transmitted signal being a component of the first incident signal transmitted through the oil-water flow, a second set of lasers that expose the oil-water flow to a second incident signal, and a second photodetector that collects a second transmitted signal, the second transmitted signal being a component of the second incident signal transmitted through the oil-water flow. The computer system that calculates the water cut of the oil-water flow based on the first transmitted signal and the second transmitted signal.

Abstract: A method for water cut sensing in an oil-water flow involves obtaining a composite absorbance spectrum of the oil-water flow, obtaining a reference absorbance spectrum of a reference fluid, computing a slope for data points associated with the composite absorbance spectrum of the oil-water flow vs corresponding data points associated with the reference absorbance spectrum of the known fluid, and based on the slope, determining the water cut of the oil-water flow.

Abstract: A system includes a pipeline for flowing a fluid therein and a multiphase sampler fluidly coupled to the pipeline. The multiphase sampler includes an inlet to receive a fluid sample of the fluid from the pipeline, a Tesla valve(s) coupled between the pipeline and the inlet of the multiphase sampler to direct a flow of the fluid sample into a sensing section, and an outlet to return the fluid sample back into the pipeline. The sensing section includes at least one sensor to determine a water-cut of the fluid sample. A method includes flowing a fluid through a pipeline, streaming off a fluid sample from the fluid into an inlet of a multiphase sampler, determining a water-cut of the fluid sample in a sensing section of the multiphase sampler, and directing the fluid sample back into the pipeline.

Abstract: A method includes obtaining raw multiphase flow rate data from a first set of sensors disposed on a pipeline of a well and obtaining auxiliary data from a second set of sensors disposed on the pipeline. The method further includes preprocessing the raw multiphase flow rate data to form a preprocessed multiphase flow rate dataset (“preprocessed dataset”), and determining, with a first model processing the preprocessed dataset, a first cleansed flow rate dataset. The method further includes determining, with a second model processing the preprocessed dataset and the auxiliary data, a second cleansed flow rate dataset. The method further includes determining high quality flow rate data with a third model processing the preprocessed dataset, the first cleansed flow rate dataset, and the second cleansed flow rate dataset. The method further includes transmitting the high quality flow rate data to a control system of the well.

Abstract: A system, for measuring a dielectric property of a medium, includes: a resonator; an oscillator electrically coupled to the resonator and configured to generate an electrical signal representing an oscillation of the oscillator when the resonator is disposed in a vicinity of the medium; and measuring circuitry that receives the electrical signal. The measuring circuitry determines, from the electrical signal, at least one of a resonance frequency of the resonator and a quality factor of the resonator. The measuring circuitry determines, from the at least one of the resonance frequency and the quality factor, the dielectric property of the medium.

Abstract: Systems and methods for providing power to a device of a downhole tool within a subterranean well during production operations include an energy harvesting system located within a tubular. The energy harvesting system has a turbine assembly with a turbine rotary member rotating relative to a turbine housing. A turbine magnetic array has a plurality of turbine magnets arranged in a ring shape. A power generator assembly has an input shaft assembly operable to provide a rotational energy to a power generator. A generator magnetic array of the input shaft assembly has a plurality of generator magnets arranged in a ring shape. A turbine sleeve surrounds the input shaft assembly, and forms a sealed barrier between the input shaft assembly and the turbine assembly. The turbine sleeve is formed entirely of a non-magnetic material.

Abstract: A multimode Coriolis flow meter, methods, and systems may include a vibratable conduit configured to channel a flow of a multiphase fluid, a plurality of drivers connected to the vibratable conduit configured to induce a plurality of vibration modes to the vibratable conduit, and a plurality of sensors connected to the vibratable conduit and configured to generate a plurality of sensor signals of the vibratable conduit in response to the plurality of vibration modes. The multimode Coriolis flow meter may further include a Coriolis transmitter.

Abstract: The subject matter of this specification can be embodied in, among other things, a method for removing intermodal distortion that includes receiving a collection of distorted backscattered Rayleigh signals from a collection of modes of an optical fiber, where the collection of distorted backscattered Rayleigh signals are distorted by an intermodal coupling among the collection of modes, receiving a collection of distortion parameters that are descriptive of distortion effects of the intermodal coupling, and determining an undistorted backscattered Rayleigh signal based on the collection of distorted backscattered Rayleigh signals and the collection of distortion parameters.

Abstract: Systems and methods for a self-calibrating three-phase flow water-cut laser sensing using an unsupervised machine learning model are disclosed.

Abstract: Methods and systems for determining a composition of a gas in a pipe using a plurality of pressure sensors disposed along the pipe. Each pressure sensor in the plurality of pressure sensors may include a diaphragm for sensing pressure that is aligned with an inner wall of the pipe, and the location of each pressure sensor in the plurality of pressure sensors may be known. The method generally includes obtaining a plurality of pressure signals from the plurality of pressure sensors, determining, using the plurality of pressure signals, a speed of sound of the gas, and determining, using the plurality of pressure signals, an attenuation of sound intensity of the gas. The method further includes determining, with a computational model, the composition of the gas, based on the determined speed of sound of the gas and the attenuation of sound intensity of the gas.

Abstract: A method for determining a bulk velocity and a mixture speed of sound of a multi-phase fluid flowing in a pipe of a pipeline. The method includes the steps: obtaining a plurality of pressure signals from a plurality of pressure sensors, where each pressure sensor in the plurality of pressure sensors includes a diaphragm for sensing pressure, where the diaphragm of each pressure sensor is aligned with an inner wall of the pipe such that each pressure sensor is flush-mounted on the inner wall of the pipe; determining, using the plurality of pressure signals, a first time-of-flight of one or more flow eddies; determining, using the plurality of pressure signals, a second time-of-flight of one or more sound waves; determining, using the first time-of-flight, the bulk velocity of the multi-phase fluid; and determining, using the bulk velocity and the second time-of-flight, the mixture speed of sound of the multi-phase fluid.