Abstract: An apparatus for applying pressure to a pipe and measuring internal pressure. The apparatus including jacket disposed on the pipe, one or more of a first set of strain gauges disposed on a wall of the pipe, one or more of a second set of strain gauges disposed on the wall of the pipe, and a temperature sensor disposed on the wall of the pipe. The pipe has an inner diameter, an outer diameter, and a length.

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 method may include obtaining, from various sensors, acquired sensor data regarding various multiphase flows in a multiphase flow meter that are sampled at a predetermined sampling frequency. The acquired sensor data may describe various transient signals that correspond to various gas droplets. The method may further include generating, based on the acquired sensor data, a flow model for the multiphase flow meter. The method may further include updating the flow model to produce a first updated flow model using simulated flow data. The method may further include updating the first updated flow model to produce a second updated flow model using simulated sensor data. The second updated flow model may be used to determine one or more flow rates within a multiphase flow.

Abstract: An apparatus for applying pressure to a pipe and measuring internal pressure. The apparatus including jacket disposed on the pipe, one or more of a first set of strain gauges disposed on a wall of the pipe, one or more of a second set of strain gauges disposed on the wall of the pipe, and a temperature sensor disposed on the wall of the pipe. The pipe has an inner diameter, an outer diameter, and a length.

Abstract: A system includes a pipe, a multiphase fluid, and a measurement unit. The multiphase fluid is disposed within the pipe. The measurement unit is connected to the pipe and includes a cylindrical structure, a first magnet, a second magnet, a first coil, and a second coil. The cylindrical structure is submersed in the multiphase fluid and has a first end and a second end. The first magnet is connected to the first end of the cylindrical structure, and the second magnet is connected to the second end of the cylindrical structure. The first coil is wound around the outer circumferential surface of the pipe in a location corresponding to a location of the first magnet disposed within the orifice. The second coil is wound around the outer circumferential surface of the pipe in a location corresponding to a location of the second magnet disposed within the orifice.

Abstract: A woven sleeve includes a tubular member that includes circumferentially oriented fibers and axially oriented fibers. The tubular member is configured to adjust between a relaxed state in which the tubular member is positioned around a well tool and an extended state in which the tubular member is in tight contact with an outer surface of the well tool across substantially an entire inner surface of the tubular member to limit an extent to which the well tool can expand radially outward.

Abstract: A system includes a pipe, a multiphase fluid, and a measurement unit. The multiphase fluid is disposed within the pipe. The measurement unit is connected to the pipe and includes a cylindrical structure, a first magnet, a second magnet, a first coil, and a second coil. The cylindrical structure is submersed in the multiphase fluid and has a first end and a second end. The first magnet is connected to the first end of the cylindrical structure, and the second magnet is connected to the second end of the cylindrical structure. The first coil is wound around the outer circumferential surface of the pipe in a location corresponding to a location of the first magnet disposed within the orifice. The second coil is wound around the outer circumferential surface of the pipe in a location corresponding to a location of the second magnet disposed within the orifice.

Abstract: A method for determining CO2 mass flow rate of a multi-phase fluid flowing in a pipeline includes obtaining pressure signals from pressure sensors flush-mounted on the inner wall of the pipe that include a diaphragm for sensing pressure. The pressure signals determine a first time-of-flight of flow eddies and a second time-of-flight of sound waves. Using the first and second time-of-flight, bulk flow velocity and mixture speed of sound is determined. Static pressure sensors obtain a static pressure measurement and temperature sensors obtain a temperature measurement. The static pressure and temperature sensors are placed near the pressure sensors. A fluid composition sensor obtains fluid composition data. Based on the static pressure measurement, temperature measurement, and fluid composition data, single-phase fluid properties are determined. Based on the bulk flow velocity, mixture speed of sound, and single-phase fluid properties, CO2 mass flow rate of the multi-phase fluid is determined.

Abstract: A system for determining a flow rate of a fluid in a well includes an electrical submersible pump disposed in the well, a motor disposed on the electrical submersible pump, and a downhole sensor module connected to the motor. The electrical submersible pump includes a vertical axis. The system includes a metering module extending from the downhole sensor module including a plurality of dynamic pressure sensors along the vertical axis. The plurality of dynamic pressure sensors are connected to an outer diameter of the metering module. The plurality of dynamic pressure sensors are configured to measure a pressure fluctuation of the fluid. The system includes a processor configured to receive data from the plurality of dynamic pressure sensors and determine the flow rate of the fluid based on the received data.

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.

Abstract: A computer-implemented method for constrained multi-phase virtual flow metering and forecasting is described. The method includes predicting instantaneous flow rates and forecasting future target flow rates and well dynamics. The method includes constructing a virtual sensing model trained using forecasted target flow rates and well dynamics. The method includes building a constrained forecasting model by combining unconstrained flow forecasting models, well dynamics models, and virtual sensing models, wherein the constrained forecasting model forecasts multi-phase flow rates.

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: 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: 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 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: Presented here are nanocomposites and rechargeable batteries. In certain embodiments, nanocomposites 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.

Abstract: A woven sleeve includes a tubular member that includes circumferentially oriented fibers and axially oriented fibers. The tubular member is configured to adjust between a relaxed state in which the tubular member is positioned around a well tool and an extended state in which the tubular member is in tight contact with an outer surface of the well tool across substantially an entire inner surface of the tubular member to limit an extent to which the well tool can expand radially outward.

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 method of handling a wind turbine is provided including a nacelle coupled via a yawing system to a tower for protection against high wind load, the method including: supplying a control signal to a yawing actuator of the yawing system, while the nacelle is in a first orientation; exerting, by the yawing actuator, a torque to the nacelle relative to the tower, thereby turning the nacelle to a second orientation being a downwind orientation.

Abstract: A method of determining a fluid parameter includes receiving, by a processor and from a plurality of sensors coupled to a flexible tube, fluid information. The flexible tube includes a throat arranged in a first position with respect to a fixed end. The fluid information includes a strain or pressure at a first portion of the flexible tube and a strain or pressure at a second portion of the flexible tube. The method also includes determining a first fluid parameter of the fluid and transmitting, from the processor to a controller operationally coupled to the throat, second position information including a second position of the throat different than the first position. The method also includes receiving, with the throat in the second position, second fluid information and determining, based on the second fluid information, a second fluid parameter of the fluid.