Classifications

• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
  • F04B47/00—Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps
  • F04B47/06—Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth
  • F04B47/08—Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth the motors being actuated by fluid
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/129—Adaptations of down-hole pump systems powered by fluid supplied from outside the borehole
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
  • F04B23/00—Pumping installations or systems
  • F04B23/04—Combinations of two or more pumps
  • F04B23/08—Combinations of two or more pumps the pumps being of different types
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
  • F04B47/00—Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps
  • F04B47/06—Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth
  • F04B47/08—Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth the motors being actuated by fluid
  • F04B47/10—Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps having motor-pump units situated at great depth the motors being actuated by fluid the units or parts thereof being liftable to ground level by fluid pressure
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
  • F04B9/00—Piston machines or pumps characterised by the driving or driven means to or from their working members
  • F04B9/08—Piston machines or pumps characterised by the driving or driven means to or from their working members the means being fluid
  • F04B9/10—Piston machines or pumps characterised by the driving or driven means to or from their working members the means being fluid the fluid being liquid
  • F04B9/109—Piston machines or pumps characterised by the driving or driven means to or from their working members the means being fluid the fluid being liquid having plural pumping chambers
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
  • F04D1/00—Radial-flow pumps, e.g. centrifugal pumps; Helico-centrifugal pumps
  • F04D1/06—Multi-stage pumps
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
  • F04D13/00—Pumping installations or systems
  • F04D13/02—Units comprising pumps and their driving means
  • F04D13/04—Units comprising pumps and their driving means the pump being fluid driven
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
  • F04D13/00—Pumping installations or systems
  • F04D13/02—Units comprising pumps and their driving means
  • F04D13/04—Units comprising pumps and their driving means the pump being fluid driven
  • F04D13/046—Units comprising pumps and their driving means the pump being fluid driven the fluid driving means being a hydraulic motor of the positive displacement type
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
  • F04D13/00—Pumping installations or systems
  • F04D13/02—Units comprising pumps and their driving means
  • F04D13/06—Units comprising pumps and their driving means the pump being electrically driven
  • F04D13/08—Units comprising pumps and their driving means the pump being electrically driven for submerged use
  • F04D13/10—Units comprising pumps and their driving means the pump being electrically driven for submerged use adapted for use in mining bore holes
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
  • F04D13/00—Pumping installations or systems
  • F04D13/12—Combinations of two or more pumps

Definitions

• the present disclosure relates to a system that may be employed in recovering hydrocarbons from oil and gas wells. More specifically, the present disclosure is directed to various embodiments of a system for operating a hydraulically-powered submersible pump that uses a pump positioned subsea to supply the pressurized fluid to drive the submersible pump.
• submersible pumps positioned in the well is one common technique that is employed to increase the flow rate of hydrocarbons to economically acceptable levels.
• Such pumps may take a variety of forms, e.g., an electrical submersible pump (ESP), a hydraulic submersible pump (HSP), a progressing cavity pump, a jet pump, etc.
• An ESP or an HSP typically includes a multistage centrifugal pump.
• An ESP is operatively coupled to and driven by an electric motor.
• An HSP is operatively coupled to a hydraulic motor.
• the ESP or HSP may be installed inside the well in a tubing string, and it is typically situated at a certain depth within the well.
• An ESP is powered via an electrical umbilical that includes an electric cable that is connected to a source of electrical power, e.g., a generator, positioned on a topside facility, e.g., a platform, a ship, etc.
• An HSP is powered via a hydraulic umbilical, a tubing or pressurized fluid in an annular space that includes a conduit for the supply of pressurized fluid to the HSP, wherein the conduit is connected to a source of pressurized hydraulic fluid, e.g., a pump that is positioned on a topside facility, e.g., a platform, a ship, etc.
• a source of pressurized hydraulic fluid e.g., a pump that is positioned on a topside facility, e.g., a platform, a ship, etc.
• the HSP may be powered via pressurized fluid supplied via a tubing or via pressurized fluid supplied via an annular space.
• An ESP is typically positioned within a well or a Christmas tree by suspending it on the production tubing and strapping an electrical cable on the outside of the production tubing from the ESP to the wellhead or Christmas tree.
• the electrical cable is operatively coupled to the electrical motor portion of the ESP.
• Electrical connectors or penetrators are coupled to the opposite end of the electrical cable within the wellhead of Christmas tree production tubing hanger. Multiple electrical connections will be made to thereby establish electrical conductivity with the electrical umbilical so as to provide electrical power to the electrical motor portion of the ESP.
• a similar arrangement is made for HSPs except that a conduit, such as the annular space between the outside diameter of the production tubing and the inside diameter of the casing, extends between the HSP hanger and the HSP positioned down-hole.
• the conduit is operatively coupled to the hydraulic motor portion of the HSP, and high-pressure fluid is supplied to the hydraulic motor via the conduit so as to drive the pump portion of the HSP.
• a hydraulic connector that is in fluid communication with the conduit will be coupled to another hydraulic connector to thereby establish fluid communication with the hydraulic umbilical so as to provide a pressurized fluid to the hydraulic motor portion of the HSP.
• the working fluid for an HSP motor can be either a component of the fluid the HSP is pumping, or a separate working fluid dedicated to driving the HSP may be used.
• a typical problem encountered with the use of ESPs relates to reliability or longevity of electrical connectors and other electric components, e.g., electric motors. It is frequently the case that the electrical components that are responsible for powering the pump in an ESP fail for one reason or another leading to well downtime and/or expensive repairs.
• a hydraulic powered submersible pump utilizes a more robust power delivery system which has a significantly longer mean time to failure than electrically powered submersible pump systems.
• the use of a hydraulic umbilical to supply pressurized fluid from a pump positioned on a topside facility to drive an HSP becomes more problematic. For example, in a closed-loop system, as the water depth increases, the liquid head that must be overcome when the drive fluid is returned to the surface is becoming a very significant factor as it relates to system design and quality.
• the present disclosure is directed to various embodiments of a system for operating a hydraulically-powered submersible pump that may solve or reduce one or more of the problems identified above.
• the present disclosure is directed to various embodiments of a system for operating a hydraulically-powered submersible pump that uses a pump positioned subsea to supply the pressurized fluid to drive the submersible pump.
• a hydraulically-powered submersible pump that uses a pump positioned subsea to supply the pressurized fluid to drive the submersible pump.
• One illustrative system disclosed herein includes a submersible pump positioned in a well, a hydraulic motor that is operatively coupled to the submersible pump and a pressurized fluid supply pump that is positioned on or near a floor of the subsea environment and in fluid communication with the hydraulic motor.
• Another illustrative system disclosed herein includes a production tree positioned above a well, a submersible pump positioned in the well, a hydraulic motor that is operatively coupled to the submersible pump, a booster pump that is adapted to receive a hydrocarbon fluid from a production outlet of the tree and a pressurized fluid supply pump that is positioned on or near a floor of the subsea environment, wherein the pressurized fluid supply pump is in fluid communication with the hydraulic motor.
• the system may also include a separator that is adapted to receive a pressurized fluid from an outlet of the booster pump, and the pressurized fluid supply pump is in fluid communication with the hydraulic motor.
• Yet another illustrative system disclosed herein includes a production tree positioned above a well, a submersible pump positioned in the well, a hydraulic motor that is operatively coupled to the submersible pump, a booster pump positioned on or near a floor of the subsea environment, wherein the booster pump is adapted to receive a hydrocarbon fluid from a production outlet of the tree, and a separator that is adapted to receive a pressurized fluid from an outlet of the booster pump, wherein the separator comprises a fluid outlet that is in fluid communication with the hydraulic motor.
• Yet another illustrative system disclosed herein includes a production tree positioned above a well, a submersible pump positioned in the well, a hydraulic motor that is operatively coupled to the submersible pump, a booster pump positioned on or near a floor of the subsea environment, wherein the booster pump is adapted to receive a hydrocarbon fluid from a production outlet of the tree, and a valve that is in fluid communication with an outlet of the booster pump and adapted to receive a pressurized hydrocarbon fluid from the outlet of the booster pump and direct a portion of the pressurized hydrocarbon fluid to the hydraulic motor.
• Yet another illustrative system disclosed herein includes a production tree positioned above a well, a submersible pump positioned in the well, a hydraulic motor that is operatively coupled to the submersible pump, a booster pump that is adapted to receive a hydrocarbon fluid from a production outlet of the tree, a pressurized fluid supply pump that is positioned on or near a floor of the subsea environment, wherein the pressurized fluid supply pump is in fluid communication with the hydraulic motor, and a turbine comprising a shaft that is operatively coupled to the pressurized fluid pump, the turbine being in fluid communication with an outlet of the booster pump and adapted to receive a pressurized hydrocarbon fluid from the outlet of the booster pump, wherein the shaft is adapted to be rotated by the pressurized hydrocarbon fluid, and wherein the shaft is further adapted to drive the pressurized fluid pump via rotation of the shaft.
• Figures 1A-1G are various views of various illustrative embodiments of a system for operating a hydraulically-powered submersible pump that uses a pump positioned subsea to supply the pressurized fluid to drive the submersible pump.
• FIGS. 1A-1B are simplistic and schematic depictions of one illustrative embodiment of a system 10 that includes a hydraulically- powered submersible pump 30 (HSP) that is positioned down-hole in a well 11.
• HSP hydraulically- powered submersible pump 30
• the HSP 30 is generally comprised of a pump 3 OP and a hydraulic motor 3 OHM that is operatively coupled to the pump 3 OP.
• the pump 3 OP is intended to be representative of any type of pump that may be used to pump hydrocarbon fluids, e.g., a centrifugal pump, a progressing cavity pump, a jet pump, etc.
• the present invention should not be considered to be limited to any particular type or form of the pump 3 OP that may be used as part of the HSP 30.
• a pressurized fluid 70 that is used to actuate the HSP 30 to pump hydrocarbons out of the well 11 is supplied by an illustrative pressurized fluid supply pump 60 (PFS pump 60) that is positioned subsea, i.e., in the water.
• PFS pump 60 pressurized fluid supply pump 60
• the system 10 is comprised of production casing 12, production tubing 14 positioned within the production casing 12, a well head 16 that is coupled to the production casing 12, a tubing head 18, a production or Christmas tree 20 and a tree cap 22.
• the system 10 is further comprised of a sealing member 24, several sections of tubing that are generally designated with the reference numbers 32A, 32B and 32C, a production tubing hanger 34, a HSP hanger 35, and a plurality of hydraulic connectors 36, 38, 40, 42, 44 and 46.
• the illustrative PFS pump 60 is positioned on a schematically depicted skid 62 that is positioned on or near the sea floor 64.
• Figure IB is an enlarged view of the area of the system adjacent the HSP hanger 35.
• a schematically depicted isolation valve 48 (not shown in Figure 1A), e.g., a ball valve or a gate valve, is incorporated in the production tree 20.
• the isolation valve 48 is large enough to allow the HSP hanger 35 and the hydraulic connectors 36, 38 to pass therethrough during the installation of the HSP system in the well 11 and production tree 20, as will be described more fully below.
• the hydraulic connectors 36, 38 are depicted in a spaced-apart, un-mated condition. Additional details of the various aspects of the various systems disclosed herein will be discussed further below.
• the various components of the system 10 disclosed herein may be of traditional construction that may be made using traditional materials.
• the system 10 includes numerous clamps, bolts and seals for assembling the various components depicted in the attached figures to one another, but such details are not included in the attached drawings so as not to obscure the presently disclosed invention and because such details of construction are well known to those skilled in the art.
• the subsea PFS pump 60 is adapted to supply a pressurized fluid 70 to the hydraulic motor 30HM via the tubing 32, e.g., coiled tubing.
• the HSP 30 is positioned below the level of hydrocarbons (liquid and/or gas) in the well 11.
• the pump 3 OP of the HSP 30 has an intake 30A where hydrocarbons enter the pump
• the pressurized fluid 70 causes the hydraulic motor 3 OHM to rotate, which in turn, in the case where the submersible pump 3 OP is a centrifugal pump, causes the submersible pump 30P to rotate and thereby increases the pressure of the hydrocarbon fluids as they pass through the pump 3 OP. More specifically, hydrocarbons enter the pump 30P, as schematically depicted by the arrow 80, and leave the pump 3 OP as a pressurized hydrocarbon fluid 82 via various outlets (not shown) in the pump 3 OP. The pressurized hydrocarbon fluid 82 is discharged into the annular space 13 between the production tubing 14 and the tubing 32.
• the discharged fluid 70R from the hydraulic motor 3 OHM which is now at a relatively lower pressure, leaves the hydraulic motor 3 OHM via various outlets (not shown), and, in this embodiment of the system 10, is also discharged into the annular space 13 between the production tubing 14 and the tubing 32 where it co- mingles with the pressurized hydrocarbon fluid 82 that passed through the pump 30P.
• the production tree 20 includes a production outlet 20A where a production fluid 90 (a combination of the pressurized hydrocarbon fluid 82 and the discharged fluid 70R) exits the tree 20 and flows to other processing equipment, described more fully below, for further processing.
• the various systems 10 disclosed herein may be implemented using either open- loop or closed- loop type pumping systems.
• the PFS pump 60 depicted herein is intended to be representative in nature in that it represents any type of pump that may be used to increase the pressure of a fluid (gas or liquid, or a combination thereof) as it passes through the PFS pump 60.
• the PFS pump 60 may have any type of configuration, e.g., a centrifugal type pump, a positive displacement type pump, etc., it may be of any size or horsepower, and it may be adapted to pump a single phase fluid or a multi-phase fluid.
• the PFS pump 60 may be an electrical pump that is powered and controlled via an electrical umbilical (not shown) that is connected to an electrical power supply source positioned on a topside facility, e.g., a platform.
• the PFS pump 60 should not be considered as limited to any particular type or form of pump.
• the PFS pump 60 is of a size such that it alone is adapted to increase a pressure of a hydrocarbon fluid so that hydrocarbon fluid may flow from a floor of the subsea environment to a surface of the subsea environment without the need to further increase the pressure on the hydrocarbon fluids.
• the tubing 32 is also intended to be representative of any type of conduit, e.g., coiled tubing, that may be employed in a well to conduct and contain a pressurized fluid from one location to another location.
• Figures 1C-1G are process flow diagrams that schematically depict various illustrative examples of specific implementations of the system 10 as it relates to producing hydrocarbons from the well 11.
• Figure 1C depicts one illustrative system 10A that includes a plurality of subsea pumps 102, 104 and a schematically depicted liquid/gas separator 106.
• the production fluid 90 (a combination of the pressurized hydrocarbon fluid 82 and the discharged fluid 70R) may be a multi-phase fluid containing liquid and gaseous hydrocarbon components.
• the production fluid 90 exits the tree 20 via production outlet 20A (see Figure 1A) and flows to the pump 102 where its pressure is increased and where it thereafter leaves the pump 102 as a pressurized production or pressurized hydrocarbon fluid
• the pressurized production fluid 90P flows to the separator 106 where its liquid and gas components are separated.
• the separated production liquid 90PL may be transmitted to a topside facility or a pipeline for collection and/or transmission.
• the separated gas 90G may be transmitted to the surface for collection and/or transmission via a separate pipeline and riser.
• a portion of the separated production liquid 90PL is supplied to the pump 104 where its pressure is increased to the desired pressure level for driving the HSP 30 in the well 11. i.e., the output from the pump 104 is the pressurized fluid 70 that is used to drive the HSP 30.
• This pressurized fluid 90PL generally will have been treated with various types of flow assurance chemicals to prevent the formation of hydrates, scale, asphaltenes, etc.
• the pump 104 is the PFS pump 60.
• a choke may be positioned between the separator 106 and the pump 104 to regulate the flow of the production liquid 90PL to the pump 104.
• Various valves and flanged connections that would normally be provided to allow assembly of the components of the system 10A are not depicted so as not to obscure the presently disclosed inventions.
• the pump 102 may be booster pump that is adapted to pump a multi-phase fluid. Such booster pumps are typically employed to increase the pressure of the production fluid 90 so that it may be transmitted via a pipeline over relatively long distances.
• the pump 104 may be a pump that is adapted to pump a single phase fluid, e.g., the production liquid 90PL from the separator 106.
• the pumps 102, 104 are sometimes generically referred to as "mud-line" pumps as they are often positioned in one or more skids that are positioned on or near the sea floor.
• the pumps 102, 104 need not be positioned on the same skid.
• the sizing of the pumps 102, 104 may vary depending upon the particular application.
• FIG. 10B depicts another system 10B that employs the novel concepts disclosed herein.
• System 10B is substantially identical to system 10A described above except that, in system 10B, the pump 104 has been removed.
• a portion of the separated production liquid 90PL is at a sufficient pressure within the separator 106 such that it may be used to drive the HSP 30 in the well 11 without further increasing its pressure, i.e., the production liquid 90PL from the separator 106 is the pressurized fluid 70 that is used to drive the HSP 30.
• a choke may be positioned between the separator 106 and the HSP 30 to regulate the flow or pressure of the production liquid 90PL as it is supplied to the HSP 30.
• the pump 102 is the PFS pump 60.
• Figure IE depicts another illustrative system IOC that employs the novel concepts disclosed herein.
• System IOC is substantially identical to system 10B described above except that, in system IOC, the separator 106 has been removed.
• the pressurized production fluid 90P (after it leaves the pump 102) is at a sufficient pressure such that a portion of the pressurized production fluid 90P may be used to drive the HSP 30 in the well
• the pressurized production fluid 90P is the pressurized fluid 70 that is used to drive the HSP 30.
• a schematically depicted valve 112 may be positioned between the outlet of the pump 102 and the HSP 30 to direct a portion 90PA of the pressurized hydrocarbon fluid 90P to the HSP 30.
• a choke may be positioned between the valve 112 and the HSP 30 to regulate the flow or pressure of the liquid 90PA as it is supplied to the HSP 30.
• the portion of the pressurized production fluid 90P that is not used to drive the HSP 30 may be transmitted to a topside facility or a pipeline for collection and/or transmission.
• the pump 102 is the PFS pump 60.
• FIG. IF depicts yet another illustrative system 10D that employs the novel concepts disclosed herein.
• the system 10D includes the pump 102, a schematically depicted turbine 116 with an output shaft 116S that is operatively coupled to a pump 118.
• the turbine 116 is adapted to drive the pump 118.
• a separate fluid 120 is supplied to the intake of pump 118 from other sources, i.e., dead oil or other fluid from topsides that does not pose any flow assurance risks.
• the output from the pump 118 is the pressurized fluid 70 that is used to drive the HSP 30.
• the pump 118 is the PFS pump 60.
• FIG. 1G depicts yet another illustrative system 10E that employs the novel concepts disclosed herein.
• the system 10E includes a closed loop system 130 that includes the HSP 30, a fluid reservoir 134 and a pump 138.
• the system 10E includes a schematically depicted turbine 116 with an output shaft 116S that is adapted to drive the pump 138.
• the system 130 is a closed system, only pressurized hydrocarbon fluid 82 exits the production outlet 20A of the tree 20 (see
• the hydrocarbon fluid 82 is not co-mingled with discharged fluid from the HSP 30.
• the pressure of the hydrocarbon fluid 82 is increased as it passes through the pump 102 where it exits as hydrocarbon fluid 82P.
• the output from the pump 138 is the pressurized fluid 70 that is used to drive the HSP 30.
• the system 130 includes a feed or supply line 131 and a return line 132 whereby, after the pressurized fluid 70 passes through the HSP 30, it is returned to the reservoir 134.
• the liquid within the reservoir 134 is supplied to the intake of the pump 138 via line 136.
• the pump 138 is the PFS pump 60.
• the hydrocarbon fluid 82P that passes through the turbine 116 may be transmitted to a topside facility or a pipeline for collection and/or transmission.
• the system 10 may be assembled as follows. Initially, after the production tubing 14 is secured in the tubing hanger 34, the HSP hanger 35 is positioned and secured in the tree 20 via known locking or clamping mechanisms. The HSP 30 is secured to the HSP hanger 35 using a coiled tubing or similar conductor and run into the well 1 1 during the installation of the HSP hanger 35. The isolation valve 48 is closed after the process of running the HSP 30 into the well is complete and provides a pressure- barrier while the blow-out preventer (not shown) is removed from the tree 20. The seal member 24 provides a barrier seal between the production tubing 14 and the intake to the pump 30A of the HSP 30.
• the tree cap 22 is lowered into position and secured to the tree 20.
• the hydraulic connector 36 is not operatively coupled to the hydraulic connector 38.
• the isolation valve 48 is opened and the hydraulic connectors 36, 38 are operatively coupled to one another, using any of a variety of known techniques.
• a screw type assembly (not shown) may be provided in the tree cap 22 that, when actuated, causes the connector 38 to move downward through the open isolation valve 48 and into engagement with the connector 36.
• a piston-type assembly that, when actuated, also causes the connector 38 to move downward through the open isolation valve 48 and into engagement with the connector 36.

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• Engineering & Computer Science (AREA)
• Mechanical Engineering (AREA)
• General Engineering & Computer Science (AREA)
• Mining & Mineral Resources (AREA)
• Fluid Mechanics (AREA)
• Geology (AREA)
• Physics & Mathematics (AREA)
• Life Sciences & Earth Sciences (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Environmental & Geological Engineering (AREA)
• Structures Of Non-Positive Displacement Pumps (AREA)
• Jet Pumps And Other Pumps (AREA)

Priority Applications (6)

Applications Claiming Priority (1)

Publications (1)

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Cited By (4)

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• 2012
  • 2012-10-11 AU AU2012392172A patent/AU2012392172B2/en not_active Ceased
  • 2012-10-11 EP EP12780971.3A patent/EP2906780B1/fr not_active Not-in-force
  • 2012-10-11 WO PCT/US2012/059652 patent/WO2014058426A1/fr not_active Ceased
  • 2012-10-11 BR BR112015005332A patent/BR112015005332A2/pt not_active IP Right Cessation
  • 2012-10-11 SG SG11201502754WA patent/SG11201502754WA/en unknown
  • 2012-10-11 US US14/435,092 patent/US20150226208A1/en not_active Abandoned

Patent Citations (5)

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