A method of evaluating a stress state of a wellbore isolation barrier with an evaluation application receiving a data set, obtained from wellbore sensors, from a remote data source by one or more communication methods. The data set comprises periodic wellbore data indicative of the stress state of the wellbore isolation barrier. The evaluation application may determine a modeled stress state of the wellbore isolation barrier by evaluating a data set consisting of the received data. The evaluation application may generate an alert if the model stress state exceeds a user threshold.

A valve assembly can include a flow passage extending between an uphole end and a downhole end of the valve assembly, a flapper that pivots between an open position and a closed position, and a pump operable to pivot the flapper, the pump being positioned between the flapper and the downhole end. A method of testing a completion tubing string can include increasing pressure in the completion tubing string while a closure member of a valve assembly is in a closed position, thereby testing a pressure integrity of the completion tubing string on an uphole side of the closure member, and transmitting a pressure signal via a flow passage to a pressure sensor of the valve assembly, thereby causing the closure member to displace to an open position, the pressure sensor being connected to an electronic circuit positioned on a downhole side of the closure member.

A method for determining conditions in a wellbore extending through a subterranean formation includes deploying a plurality of sensor pods in the wellbore, wherein each sensor pod includes a housing and a plurality of sensors disposed in the housing. The method also includes measuring and recording a plurality of pressures and a plurality of temperatures with plurality of sensors of each sensor pod, dissolving the housings of the pods to release the plurality of sensors from the pods after measuring and recording the plurality of pressures and the plurality of temperatures, and lifting the sensors to the surface.

A method and system for determining a flow rate of at least a phase or a component of a fluid produced from an oil and gas well are presented hereinafter. The fluid is one of a multiphase and of a multicomponent fluid. The method comprises, in a training phase, collecting primary measurements of pressure, temperature, and additional flow parameter of the produced fluid. The primary measurements are carried out at the wellhead by a set of sensors installed in a flow line for the produced fluid. In the training phase, the method also comprises collecting a flow rate of at least one of the phases or components of the produced fluid simultaneously measured by a reference multiphase flow meter installed in the flow line. It also includes establishing a relationship between the pressure, temperature, and the additional flow parameter and the flow rate of the at least one of the phases or components of the produced fluid. The method also comprises, in a subsequent production phase, determining the flow rate of the at least one of the phases or components of the produced fluid based on the primary measurements of the pressure, temperature, and the at least one additional flow parameter and on the established relationship.

A system and method for a fully-integrated flow control module (FI-FCM) in a hydrocarbon reservoir is disclosed. The FI-FCM is a unibody structure or a single-piece machined body having a flow meter integrated to the unibody structure. A choke is to be associated within a provision of the FI-FCM that also has an entry flow path for reservoir fluid and an exit flow path for the reservoir fluid. The entry flow path and the exit flow path inside the unibody structure or the single-piece machined body. Fluid communication is enabled between the flow meter, which is upstream relative to the choke, and an entry flow path. The choke is to control flow between the entry flow path and the exit flow path.

A system for controlling tubing member assembly diameter includes a control unit, a computing device, a tubing member assembly, and an elastomer member. The tubing member assembly includes an outer pipe member that defines a static diameter and an inner pipe member having an outer surface and defining a dynamic diameter that changes from a first inner pipe member value to a second inner pipe member value. The elastomer member is disposed between the outer pipe member and the inner pipe member such that an inner area of the elastomer member is disposed on the outer surface of the inner pipe member. The elastomer member expands from a first position to a second position to constrict the dynamic diameter from the first inner pipe member value to the second inner pipe member value responsive to receiving an electrical signal from the control unit.

An electrical submersible well pump assembly has a SAW (surface acoustic wave) sensor on a motor shaft. A SAW electronic circuit mounts to the motor housing. The SAW electronic circuit has an antenna closely spaced to the SAW sensor for monitoring torque on the motor shaft. A controller at an upper end of the well supplies power to the motor. A motor gauge unit mounted to a lower end of the motor transmits signals to the controller. A signal line extends from the SAW electronic circuit to the motor gauge unit for transmitting signals from the SAW electronic circuit to the motor gauge unit, and from the motor gauge unit to the controller.

Systems and methods include a computer-implemented method for real-time flare network monitoring. Real-time flaring volume data is received from relief devices connected to a flare network. The real-time flaring volume data is analyzed in conjunction with heat and material balance information of the relief devices. A comprehensive molar balance is performed based on the analyzing, the balancing including losses/feed percentages for each component of the flare network including the relief devices throughout the flare network. Flaring data for the components is aggregated for each flare header. Real-time flare network monitoring information, including instantaneous component-wise flaring for each flare header in the flare network is provided for display to a user in a user interface.

A system for deploying an untethered drone is provided. The system includes a wellbore drone for being deployed into a wellbore, a magazine unit, and a control system. The wellbore drone is configured to perform at least one action based on a control command which is provided from an on-board control system embedded in the wellbore drone. The magazine unit includes one or more chambers. The magazine unit is configured to retain the wellbore drone in a corresponding one of the one or more chambers, prior to deployment of the wellbore drone into the wellbore, and dispense the wellbore drone for being deployed into the wellbore through a launcher unit. The control system includes at least one control interface for controlling at least a part of operations of the wellbore drone and the magazine unit.

A method and system for determining a flow rate of at least a phase or a component of a fluid produced from an oil and gas well are presented hereinafter. The fluid is one of a multiphase and of a multicomponent fluid. The method comprises, in a training phase, collecting primary measurements of pressure, temperature, and additional flow parameter of the produced fluid. The primary measurements are carried out at the wellhead by a set of sensors installed in a flow line for the produced fluid. In the training phase, the method also comprises collecting a flow rate of at least one of the phases or components of the produced fluid simultaneously measured by a reference multiphase flow meter installed in the flow line. It also includes establishing a relationship between the pressure, temperature, and the additional flow parameter and the flow rate of the at least one of the phases or components of the produced fluid. The method also comprises, in a subsequent production phase, determining the flow rate of the at least one of the phases or components of the produced fluid based on the primary measurements of the pressure, temperature, and the at least one additional flow parameter and on the established relationship.