Saudi Arabian Oil Company

King Fahd University of Petroleum and Minerals

Chidirim Enoch Ejim

Jinjiang Xiao

Rafael Adolfo Lastra Melo

Brian Andrew Roth

Songlin Zhong

Rafael Adolfo Lastra

Hassan Mohamed Badr

Hattan M Banjar

Randall Alan Shepler

Muhammad Mustafa Kamal

Abdelsalam Mohammad AlSarkhi

A method includes providing an electrical submersible pump assembly with a pump, an intake, shroud base flanges, a protector, and a motor. The method includes coupling the shroud base flanges to an intake downhole end using fasteners and a set of protector top bolt holes. The method includes locating a closed end of an inverted shroud between the intake and the protector. The inverted shroud includes a shroud base on the closed end, and an opposite open end that is open toward the packer. The method includes coupling the inverted shroud to the shroud base flanges. The packer is located uphole of the opposite open end at a distance causing a mixing of a gas pocket with the well fluid to form a combined gas and liquid mixture and directing the combined gas and liquid mixture in a direction toward the intake.

Inverted shroud field assembly for gas accumulation prevention above ESPs and method of use

A system includes a packer sealed against a casing string deployed in the well, production tubing extending through the packer and configured to transport the production fluids to a surface location, and an electric submersible pump connected to the production tubing at a location downhole from the packer. The electric submersible pump is configured to pump the production fluids through the production tubing. The system further comprises a gas activated vent valve installed on the production tubing at a location downhole from the packer and configured to open using a pressure exerted on the gas activated vent valve by the gas and a vent line connected to an outlet of the gas activated vent valve, extending through the packer, and configured to transport the gas from the gas activated vent valve to the surface location when the gas activated vent valve is opened by the gas.

Gas-activated vent valve below packer for stable electrical submersible pump (ESP) operation in gassy wells

A method that includes disposing a packer and an ESP inside a production tubing bore. The ESP includes a pump, a discharge, a shroud, and a bypass sub coupled to the shroud. The shroud includes a closed end coupled to a base of the pump. The packer, coupled to an outer surface of the shroud, is located downstream of the bypass sub. The method includes circulating liquids from the pumping base through the discharge to a shroud open end downstream of the packer thereby sealing the packer between the outer surface and the production tubing bore. The method includes pumping, using the pump device, the liquids through the production tubing using the bypass sub and performing a production operation using the wellhead assembly to obtain an amount of gas production.

Reviving a well using through-tubing cable-deployed pump

A system includes an electric submersible pump and a flow regulating valve. The electrical submersible pump includes a pump that, when activated, receives a fluid disposed within a production tubing of a well through a pump intake and vents the fluid through a pump discharge to a surface location. The flow regulating valve includes a flow tube that blocks the fluid from entering the pump intake when the pump is inactive, a piston, connected to the flow tube, that moves the flow tube within the flow regulating valve, and a stinger that includes a conduit for the fluid to flow from the production tubing to the pump. The flow regulating valve further includes a spring that positions the piston within the flow regulating valve when the pump is inactive and a plurality of seals that pressure-seal a pressure chamber which houses a pressure force that is to be applied upon the piston.

Flow regulating valve

A downhole tool to log a horizontal or deviated wellbore includes a production unit and a logging unit. The production unit can fluidly couple to a production tubing positioned in a wellbore that includes a vertical portion and a horizontal portion. The production unit can be positioned in the vertical portion. The logging unit is coupled to a downhole end of the production unit. The logging unit includes a tractor and logging sensors. The tractor can detach from the logging unit and carry the sensors through the wellbore downhole of the production unit and into the horizontal portion. The sensors can perform logging operations within the wellbore, and the tractor can carry the sensors back to the logging unit. The tractor can be reattached to the logging unit.

Logging a deviated or horizontal well

A well site includes a wellbore extending from a surface to a target reservoir. A production tubing extends into the wellbore from the surface. The production tubing forms a flow conduit from the target reservoir to the surface. A pump is coupled to the production tubing to lift well fluids to the surface. A sand level device is coupled below the pump. The level device includes one or more transmitters to generate and transmit at least two signals down the wellbore and one or more receivers to receive the at least two signals reflected from a reflecting surface in the wellbore. A time duration of transmitting and receiving the at least two signals may correspond to a straight-line distance between the sand level device and the reflecting surface in the wellbore. The sand level device is configured to send an alarm when the straight-line distance does not surpass a predetermined threshold.

Methods and systems for a downhole sand level device

Systems and methods for providing artificial lift to wellbore fluids includes a pump, a motor, and a protector assembly forming an electric submersible pump system located in a wellbore. A solids isolator is located between the pump and the protector assembly. The solids isolator includes a tubular discharge body with an inner discharge bore. A body port extends through a sidewall of the discharge body. A sliding seal member is located within the discharge bore and moveable between a port open position where the body port is open to allow fluids to travel through the body port, and a port closed position, where fluids are prevented from traveling through the body port. The sliding seal member is ring shaped in cross section. The sliding seal member is biased to the port closed position when the pump is off and moveable to the port open position when the pump is on.

Sand shield for protecting inverted electric submersible pump at shutdown

A system includes an electric submersible pump (ESP) assembly configured to transport a fluid in a casing string of a well to a surface location. The ESP includes a pump configured to receive, upon activation, the fluid through a pump intake and vent the fluid through a pump discharge; an output shaft extending downhole from and fixed to the pump; and a control valve assembly. The control valve assembly includes a movable core of an electromagnet movable along a central axis of the system; a generator in electrical communication with the electromagnet, configured to generate electrical power to pull the movable core in an uphole direction upon activation of the pump of the electric submersible pump assembly; a shaft coupler coupling a generator input shaft and the output shaft; and a stinger having a conduit for the fluid to flow from the tubing string to the pump intake. The stinger includes at least one intake slot configured to receive the fluid; and an exit configured to vent the fluid to the pump intake of the electric submersible pump assembly. The control valve assembly also includes a flow tube connected to the movable core, the flow tube comprising an exterior surface creating fluid communication between the flow tube and the stinger before, when, or after the exterior surface uncovers the at least one intake slot of the stinger. The ESP also includes a spring configured to slide the movable core upon deactivation of the pump of the electric submersible pump assembly.

Method and system for power generation and use

Systems and methods for providing artificial lift to wellbore fluids includes a pump, a motor, and a protector assembly forming an electric submersible pump system located within a wellbore. A downhole packer is located downhole of the pump. A solids bypass device is located downhole of the pump. The solids bypass device has a flow tube with an inner bore, a bypass stinger that is a tubular member that circumscribes the flow tube, and drain ports extending through a sidewall of the bypass stinger. A sealing cap circumscribes the flow tube. The sealing cap is moveable between an open position, where the sealing cap is positioned to provide an external fluid flow path through the solids bypass device, and a closed position, where the sealing cap prevents fluid from traveling through the external fluid flow path. A biasing member biases the sealing cap towards the open position.

Solids bypass device for inverted electric submersible pump

A solids collector is disposed at an end of a tubing in a wellbore. At a top of the solids collector, a reservoir fluid stream carrying solids is separated into a solids-liquid stream that is reversed into an annulus in the solids collector and a gas stream that continues to move uphole in the wellbore. At an end of the annulus in the solids collector, the solids-liquid stream is separated into a liquid stream that moves up the tubing and solids that are accumulated in the solids collector.

Downhole solids handling in wells

A system includes an electric submersible pump assembly and a control valve assembly. The electric submersible pump assembly transports a fluid in a casing string of a well to a surface location and includes a pump that receives the fluid through a pump intake and vents the fluid through a pump discharge when activated. The electric submersible pump assembly further includes a shaft that is fixed to the pump and extends downhole from the pump. The control valve assembly includes a propeller shaft axially movable along a central axis of the system, a propeller attached to the propeller shaft that pushes the propeller shaft downhole when the pump of the electric submersible pump assembly is active, a shaft coupler that connects the propeller shaft and the shaft of the electric submersible pump assembly, and a stinger that has a conduit for the fluid to flow from the casing string to the pump intake. The stinger includes an entrance for receiving the fluid and an exit for venting the fluid to the pump intake of the electric submersible pump assembly. In addition, the control valve assembly includes a flow tube, connected to the propeller shaft, and a spring. The flow tube includes ports which create fluid communication between the flow tube and the stinger when the ports and the entrance of the stinger are aligned. The spring slides the propeller shaft when the pump of the electric submersible pump assembly is inactive.

Thrust force to operate control valve

An apparatus for gas-liquid separation includes a first separation region that receives a mixture of liquids and gases, at least a portion of the first separation region forms a conical section; a second separation region that receives liquids and gases from the first separation region; and a cross-over section fluidly connecting the second separation region to a tubing.

Downhole gas-liquid separator

A resettable packer system for pumping operations includes an inflatable packer that expands between the resettable packer system and a tubing wall or a casing wall, thereby creating a seal in a well and a pump that inflates the inflatable packer at a desired depth within the well when activated. The resettable packer system further includes an inner sleeve that includes ports for a fluid to pass through, an outer sleeve that is connected to the pump and creates a sealed fluid chamber with the inflatable packer when ports of the outer sleeve and the ports of the inner sleeve are misaligned. In addition, the inner sleeve slides axially along an inner surface of the outer sleeve, thereby aligning or misaligning the ports of the outer sleeve with the ports of the inner sleeve. Further, the inflatable packer contracts when the pump is inactive.

Resettable packer system for pumping operations

A motorized pump including a motor and a pump around the motor. The pump rotor is integrated with the motor rotor, wherein the pump rotor has vanes. The motorized pump may be employed as an electrical submersible pump (ESP) in a wellbore.

Motorized pump

A shaft in an electrical submersible pumping system is prevented from rotation in a backspin direction, which is in a direction opposite from its typical forward rotation during normal operation. Backspin rotation is prevented with a device that includes teeth coupled to the shaft and a stationary pawl disposed in a rotational path of the teeth. Each tooth has a forward surface that contacts the pawl during forward rotation of the shaft, the forward surfaces are each configured with a profile to slide along and past the pawl without impeding shaft rotation. Rotation in the backspin direction engages the pawl with rearward surfaces of the teeth, which are configured to impede shaft rotation when engaged. Fluid being handled by the pumping system flows through a passage in the device and absorbs friction generated thermal energy from the device.

Growing community of inventors

Dhahran, Saudi Arabia

Chidirim Enoch Ejim