A labyrinth section for a submersible pump includes an outer housing having a coupling sealingly engaged at each longitudinal end of the outer housing. An inner tube is sealingly engaged at each end to one of the couplings to define a sealed annular space. A plurality of labyrinth tube sections are disposed in the annular space, each comprising labyrinth tubes engaged with end plates. A plurality of the labyrinth tube sections enable movement of fluid through the labyrinth tubes, spaces external to the labyrinth tubes and between the end plates to fill the annular space. One of the labyrinth tube sections constrains fluid to move only within the labyrinth tubes and wherein the inner tube between the end plates of the one of the labyrinth tubes comprises a fluid port into an interior of the inner tube.

A labyrinth section for a submersible pump includes an outer housing having a coupling sealingly engaged at each longitudinal end of the outer housing. An inner tube is sealingly engaged at each end to one of the couplings to define a sealed annular space. A plurality of labyrinth tube sections are disposed in the annular space, each comprising labyrinth tubes engaged with end plates. A plurality of the labyrinth tube sections enable movement of fluid through the labyrinth tubes, spaces external to the labyrinth tubes and between the end plates to fill the annular space. One of the labyrinth tube sections constrains fluid to move only within the labyrinth tubes and wherein the inner tube between the end plates of the one of the labyrinth tubes comprises a fluid port into an interior of the inner tube.

A method and apparatus for separating of gas from liquids in a wellbore, the apparatus enabling the receiving of wellbore fluids into two or more production separation chambers, operating in parallel. The apparatus further enabling the receiving of production separation chamber fluids into a production pipe through a thief jet port disposed in a lower chamber beneath the production separation chambers. The apparatus further enabling extraction of bottom hole gas fluids in the wellbore from under the two or more production separation chambers and disposing the gas fluids back into the wellbore above the two or more production separation chambers.

A method and apparatus for separating of gas from liquids in a wellbore, the apparatus enabling the receiving of wellbore fluids into two or more production separation chambers, operating in parallel. The apparatus further enabling the receiving of production separation chamber fluids into a production pipe through a thief jet port disposed in a lower chamber beneath the production separation chambers. The apparatus further enabling extraction of bottom hole gas fluids in the wellbore from under the two or more production separation chambers and disposing the gas fluids back into the wellbore above the two or more production separation chambers.

A downhole tool and method therefor use a deviated flow path to prevent/mitigate fallback of solids during shutdown of an ESP. The deviated flow path leverages the direction of fallback downhole and the relative inertias of the solid particulates and the fluid to minimize fallback into the ESP. The particulates change flow direction more slowly than fluid, and thus largely avoid the deviated flow path to instead fall through a bypass path during fallback. This obviates the need for mechanical valves that may be subject to excessive mechanical wear or other issues associated with solid particulates.

A downhole tool and method therefor use a deviated flow path to prevent/mitigate fallback of solids during shutdown of an ESP. The deviated flow path leverages the direction of fallback downhole and the relative inertias of the solid particulates and the fluid to minimize fallback into the ESP. The particulates change flow direction more slowly than fluid, and thus largely avoid the deviated flow path to instead fall through a bypass path during fallback. This obviates the need for mechanical valves that may be subject to excessive mechanical wear or other issues associated with solid particulates.

A gas mitigation system for controlling the amount of gas that reaches a submersible pumping system deployed in a wellbore includes a well zone isolation device disposed in the wellbore between the submersible pumping system and a gas collecting region. The gas mitigation system further includes a back pressure control module and a gas vent line extending from the gas collecting region through the well zone isolation device to the back pressure control module. A liquid intake line extends from the well zone isolation device to an area of the wellbore upstream from the gas collecting region.

A gas mitigation system for controlling the amount of gas that reaches a submersible pumping system deployed in a wellbore includes a well zone isolation device disposed in the wellbore between the submersible pumping system and a gas collecting region. The gas mitigation system further includes a back pressure control module and a gas vent line extending from the gas collecting region through the well zone isolation device to the back pressure control module. A liquid intake line extends from the well zone isolation device to an area of the wellbore upstream from the gas collecting region.

Pumping of wellbore fluid to a surface may have a detrimental effect on the pump performance due to high gas concentrations in the fluid. A pump system that utilizes a helix gas separator provides greater pump efficiency by effectively removing the gas phase of the fluid. The wellbore fluid received at a pump system is directed from an intake to a gas separator that utilizes a stationary auger. The stationary auger induces rotational motion of the wellbore fluid causing the wellbore fluid to separate into a gas phase and a liquid phase. The stationary auger utilizes a tapered diameter and an opening between one or more helixes or vanes to separate a gas phase more efficiently from a liquid phase of a fluid.

Pumping of wellbore fluid to a surface may have a detrimental effect on the pump performance due to high gas concentrations in the fluid. A pump system that utilizes a helix gas separator provides greater pump efficiency by effectively removing the gas phase of the fluid. The wellbore fluid received at a pump system is directed from an intake to a gas separator that utilizes a stationary auger. The stationary auger induces rotational motion of the wellbore fluid causing the wellbore fluid to separate into a gas phase and a liquid phase. The stationary auger utilizes a tapered diameter and an opening between one or more helixes or vanes to separate a gas phase more efficiently from a liquid phase of a fluid.