A flow control system for a well includes a primary safety valve and a secondary safety valve disposable within a valve body of the primary safety valve. The secondary safety valve may include a control line port for receiving control fluid pressure from the same control line as the primary safety valve. A choke in fluid communication with the control line port delays a closing of the secondary safety valve relative to a closing of the primary safety valve in response to a decrease in the control fluid pressure.

A method is disclosed that includes deploying a jet pump assembly from a surface location into a production tubing of a depleted volatile oil reservoir, the jet pump assembly including retractable tubing, a jet pump and a retractable packer operatively connected with the retractable tubing. The jet pump assembly is positioned within the production tubing, the retractable packer is engaged to bridge a space between the jet pump assembly and a surface of the production tubing, and the jet pump is activated to pump toward the surface location a mixture comprising a power fluid and reservoir fluid. The method further includes disengaging the retractable packer and determining whether there is an underbalance condition. Also disclosed are a related jet pump assembly and bi-directional valve arrangement. The valve arrangement includes upper and lower valves, and retains power fluid in retractable tubing during retraction of a jet pump assembly from production tubing.

A valve assembly includes a valve body that defines an internal flow passageway between an inlet and an outlet, and a valve seat disposed in the valve body with a sealing surface perpendicular to the flow passageway. The valve assembly further includes a clapper pivotally correlated to the valve seat having a closed configuration extending across the valve seat configured to substantially close off the flow passageway, and an open configuration configured to substantially allow fluid flow in the flow passageway from the inlet to the outlet through the valve body. An annular valve seat seal is disposed within an annular groove formed in a surface of the valve seat, where the annular valve seat seal is disposed at an interface between the valve seat and the clapper when the clapper is in the closed configuration.

The well system includes a casing and production tubing and a control unit that can receive measurements of temperature and pressure of fluid in the tubing-casing annulus (TCA). A subsurface safety valve (SSSV) connected to the tubing can switch to an open or closed state in response to a change in pressure of the fluid. An expected thermal expansion or contraction of the TCA fluid is calculated based on the received measurements, and the control unit determines, based on the expected thermal expansion or contraction and on a calculated TCA volume, a volume necessary to be added to or released from the TCA to maintain the fluid within an optimal pressure range. The control unit can also receive an indication of an emergency condition and transmit a signal to activate a release valve to release from the TCA a volume of fluid sufficient to cause the SSSV to close.

A system for delivering hydraulic fracturing fluid to a wellbore is provided. The system includes a first frac tree connected to a first wellbore and a second frac tree connected to second wellbore. The system further includes a zipper module and a first single straight-line connection between the zipper module and the first frac tree. The system also includes a second single straight-line connection between the first frac tree and the second frac tree.

A well completion including an electric safety valve and a female inductive coupler is provided. A corresponding male inductive coupler is aligned with the female inductive coupler to provide for the transfer of power and/or telemetry during deployment. The male inductive coupler can be removed for normal operation. In the event of safety valve failure during operation, a service male inductive coupler and contingency safety valve can be deployed such that the service male inductive coupler is aligned with the female inductive coupler.

Disclosed herein are various embodiments of well control system for drilling an oil or gas well safely and efficiently by providing a mechanical actuator capable of transmitting a rotational force downhole, and converting the rotational force to an axial force for the purpose of operating downhole equipment, including subsurface safety valves, compressible bladder valves, and sliding sleeve valves. Because the actuator is mechanical and not hydraulic as in conventional equipment, the force applied is independent of the depth at which it is applied, overcoming a major deficiency seen in comparable hydraulic systems.

A well tool assembly can include a well barrier and a detachable sub connected to the well barrier. The detachable sub can include a sensor data receiver. A method of retrieving sensor data can include positioning a sensor on one side of a well barrier, connecting a detachable sub on an opposite side of the well barrier, the detachable sub including a sensor data receiver configured to receive sensor data from the sensor, and conveying the well barrier, the sensor and the detachable sub together into a well. A system can include a sensor, a detachable sub, and a well barrier positioned between the sensor and the detachable sub, the detachable sub including a sensor data receiver, a passage extending longitudinally through the detachable sub, and a closure that selectively opens and blocks the passage.

A frac system including a frac tree. The frac tree includes a frac head. The frac head defines a first inlet, a second inlet, and an outlet. The frac head receives frac fluid through the first inlet and directs the frac fluid to the outlet fluidly coupled to a wellhead. A valve couples to the second inlet of the frac head. A flapper valve is within the frac head. The flapper valve moves between an open position and a closed position to control fluid flow to the valve through the second inlet. The flapper valve aligns with a first axis of the outlet and the second inlet in the closed position and aligns with a second axis of the first inlet in the open position.

A differential fill valve assembly for application in float collars or shoes in a well casing can provide locking mechanisms to limit premature movement of an activating sleeve while facilitating desired advancement of the activating sleeve. The valve assembly comprises a backpressure flapper valve and an activating sleeve slidably disposed within a housing. The activating sleeve initially maintains the flapper valve in an open position while the activating sleeve is maintained in its position by upper and/or lower lock rings on either side of a shoulder of the activating sleeve. A tripping ball is dropped to seat in the activating sleeve. Pressure applied on the ball moves the activating sleeve downward, releasing the backpressure flapper valve, after which the tripping ball exits the bottom of the assembly. The lower lock ring maintains the activating sleeve in its lower position.