WO2015065574A1 - Pompes submersibles à puissances multiples et à vitesse élevée, et compresseur - Google Patents

Pompes submersibles à puissances multiples et à vitesse élevée, et compresseur Download PDF

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Publication number
WO2015065574A1
WO2015065574A1 PCT/US2014/051947 US2014051947W WO2015065574A1 WO 2015065574 A1 WO2015065574 A1 WO 2015065574A1 US 2014051947 W US2014051947 W US 2014051947W WO 2015065574 A1 WO2015065574 A1 WO 2015065574A1
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WO
WIPO (PCT)
Prior art keywords
gas
driver
rotary pump
pump
magnetic bearing
Prior art date
Application number
PCT/US2014/051947
Other languages
English (en)
Inventor
Michael C. ROMER
Stan O. UPTIGROVE
Original Assignee
Exxonmobil Upstream Research Company
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Exxonmobil Upstream Research Company filed Critical Exxonmobil Upstream Research Company
Publication of WO2015065574A1 publication Critical patent/WO2015065574A1/fr

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Classifications

    • 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
    • E21B43/128—Adaptation of pump systems with down-hole electric drives
    • 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
    • E21B4/00—Drives for drilling, used in the borehole
    • E21B4/003—Bearing, sealing, lubricating details
    • 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
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0085—Adaptations of electric power generating means for use in boreholes
    • 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
    • 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
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E21B43/168—Injecting a gaseous medium
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/008—Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F16—ENGINEERING ELEMENTS AND UNITS; GENERAL MEASURES FOR PRODUCING AND MAINTAINING EFFECTIVE FUNCTIONING OF MACHINES OR INSTALLATIONS; THERMAL INSULATION IN GENERAL
    • F16C—SHAFTS; FLEXIBLE SHAFTS; ELEMENTS OR CRANKSHAFT MECHANISMS; ROTARY BODIES OTHER THAN GEARING ELEMENTS; BEARINGS
    • F16C32/00—Bearings not otherwise provided for
    • F16C32/04—Bearings not otherwise provided for using magnetic or electric supporting means
    • F16C32/0406—Magnetic bearings
    • F16C32/044—Active magnetic bearings
    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02K—DYNAMO-ELECTRIC MACHINES
    • H02K7/00—Arrangements for handling mechanical energy structurally associated with dynamo-electric machines, e.g. structural association with mechanical driving motors or auxiliary dynamo-electric machines
    • H02K7/08—Structural association with bearings
    • H02K7/09—Structural association with bearings with magnetic bearings
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F16—ENGINEERING ELEMENTS AND UNITS; GENERAL MEASURES FOR PRODUCING AND MAINTAINING EFFECTIVE FUNCTIONING OF MACHINES OR INSTALLATIONS; THERMAL INSULATION IN GENERAL
    • F16C—SHAFTS; FLEXIBLE SHAFTS; ELEMENTS OR CRANKSHAFT MECHANISMS; ROTARY BODIES OTHER THAN GEARING ELEMENTS; BEARINGS
    • F16C2352/00—Apparatus for drilling

Definitions

  • the present disclosure is directed generally to an apparatus and method for pumping fluids from a well.
  • the present disclosure is also directed generally to an apparatus and method for producing gas from a wellbore or injecting a fluid into a wellbore.
  • gas lifting is the primary artificial lift method used in offshore oil wells.
  • the reservoir draw-downs possible with gas lift are not as high as those that can be achieved with down hole pumps.
  • the proper application of pumps can lower the abandonment pressure of wells, increasing reserves captured per well, and reducing the number of wells required to economically deplete an asset.
  • high-volume oilfield submersible pumping systems are plagued by various issues that reduce their applicability, particularly in high-cost offshore environments and horizontal directionally drilled wells.
  • Electric submersible pumps and hydraulic submersible pumps (HSPs) are the primary high-volume pumping options available to industry today.
  • ESPs have reliability issues caused by induction motor, seal section, shaft, and power cable failures.
  • the seal section is particularly troublesome, as it is designed to provide a physical barrier between the motor internals and the wellbore fluids. When the seal fails, wellbore fluids can reach the thrust bearings and/or motor, resulting in system failure.
  • ESPs must be specially designed to handle produced gases, which further limits their use.
  • ESPs are commonly installed as part of the tubing string, which means they require a costly pulling rig for installation and replacement.
  • HSPs are newer to the industry and have so far shown improved reliability. They can be installed through tubing and can better handle produced gases. However, HSPs require a high-pressure, high-volume source of power fluid to operate. This results in additional topside surface pumping and separation requirements. In addition offshore facilities typically have limited surface space, so most installations cannot support the surface equipment necessary to operate HSPs.
  • Motor shaft power output is defined as the product of rotation speed and torque. A high-speed motor therefore provides a means for obtaining more power from the same length of motor, or the same power from a shorter length. The output of a pump is defined in terms of its hydraulic power, which is the product of flow rate and lifting pressure.
  • Centrifugal pump technology is characterized by the power output, which is proportional to the cube of the rotational speed. This relationship means that a relatively small increase in the rotational speed can give rise to a substantial power increase.
  • a 4" single- stage centrifugal pump operating at 24,000 rpm can produce 6300ft of head at ⁇ 6000bpd flow rate for 400hp.
  • About 300 typical ESP stages (4", 6000bpd rated, 3500rpm) would be required to achieve this same performance with similar horsepower - but the height of the stacked stages would be near 100ft!
  • Centrifugal pumps are frequently made with hundreds of impellers threaded on a common shaft, each impeller adding a little to the lifting pressure. Reducing the number of impellers by increasing the speed would therefore afford an improvement in reliability. As such, a high-speed motor and pump would present advantages in reliability due to reduced complexity, or alternatively yield a higher output for a similar size.
  • variable speed drives To power these motors, rather than direct connection to the utility supply.
  • Variable speed drives first convert utility AC power, typically at 60 Hz, to DC, and then by electronic switching convert the DC to a variable frequency alternating voltage.
  • the use of a variable speed drive confers advantages during starting when it can limit the motor current to a safe level, and during production when it can be used to manage flow rates.
  • variable speed drives by creating an artificial supply of 70 Hz or more, can operate the motor at higher speed than when directly connected to the utility supply, this is a limited capability. Performance is generally limited up to 80 Hz or about 4500 rpm.
  • the mechanical seal section is required in a conventional ESP system to separate the pump environment from the motor environment, transfer power from the motor to the pump stages, allow positive differential pressure for the electric motor over the pump environment, handle expansion/contraction of dielectric oil, and provide a clean environment for the thrust bearing system.
  • Thrust bearings are fluid-dynamic bearings that are located next to the seal section and absorb up- and down-thrust axial forces from the pump shaft.
  • the thrust bearing is typically lubricated with a dielectric oil that is shared with the electric motor and seal section.
  • the ESP motor When the ESP motor runs, it creates heat, causing the dielectric oil to expand. Some oil may be expelled into the wellbore through a check valve at the top of the mechanical seal section, never to be replaced. When the motor is stopped, it cools, decreasing the volume of the dielectric oil and reducing the pressure. A small amount of wellbore fluids (possibly with entrained solids) can be pulled into the motor during this thermal cycling process. Although the motor and thrust bearings are protected from encroaching wellbore fluid by the additional labyrinthine seal section next to the mechanical seal, excessive stops/starts or vibration will cause wellbore fluids to eventually reach the thrust bearing and foul it. The same fluids can electrically "short-out" the ESP motor.
  • an apparatus for removing fluids from a well includes a rotary pump for positioning within the well, the rotary pump including an inlet end and a discharge end, the rotary pump comprising at least one pump impeller intermediate the inlet end and discharge end, the at least one pump impeller rotating at a rate greater than about 3600 rpm; a driver for driving the at least one pump impeller to a rate greater than about 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary pump; a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump and/or driver, and a digital controller positioned within the wellbore to control the magnetic bearing system.
  • the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof.
  • the driver is a gas-powered expander having an inlet and a discharge end, the gas-powered expander driven by high-pressure gas from a down hole gas production zone.
  • the down hole gas production zone is regulated with a surface-controlled flow-control mechanism.
  • the gas-powered expander is driven by injected gas lift gas.
  • the injected gas lift gas enters the gas-powered expander inlet through a down hole gas lift mandrel.
  • the rotational speed or rate of the gas-powered expander is varied by adjusting characteristics of the gas lift gas.
  • the expanded gas is exhausted to a conduit to the surface.
  • the apparatus further includes additional electronic control and/or monitoring components, and the additional electronic control and/or monitoring components and digital controller are cooled with gas at the discharge end of the gas-powered expander.
  • the gas-powered expander operates at the same rotational speed or rate as the rotary pump impeller.
  • the driver is an electric motor.
  • the electric motor is a canned, seal-less motor. [0025] In some embodiments, the electric motor is magnetically coupled to the rotary pump.
  • the apparatus further includes a variable speed drive to control the speed or rate of the electric motor.
  • the driver is a hydraulic motor, the hydraulic motor having a power fluid inlet and a power fluid discharge.
  • the apparatus further includes a source of power fluid, the power fluid provided to the power fluid inlet from the surface through a conduit.
  • the apparatus further includes a surface power fluid pump, wherein the speed or rate of the hydraulic motor is controlled by the output of the surface power fluid pump.
  • the power fluid is provided to the hydraulic motor from a high-pressure liquid-producing zone.
  • the high-pressure liquid-producing zone is regulated from a surface-controlled, flow-control mechanism.
  • spent power fluid is discharged with the pump fluid.
  • the apparatus further includes a generator for converting a portion of the rotational energy of the apparatus to electrical power.
  • the magnetic bearing system is powered and controlled by the power produced by the generator.
  • the magnetic bearing system is canned to prevent encroachment of wellbore fluids and improve reliability.
  • the driver is connected to the rotary pump by a magnetic gear.
  • the magnetic gear generates electricity for onboard use.
  • the apparatus further includes onboard sensors, wherein at least a portion of the electricity generated powers the onboard sensors.
  • the onboard sensors are used for closed-loop control of the rotary pump.
  • the electricity generated powers wireless communications.
  • the apparatus further includes an electric or fiber optic cable run in conjunction with a deployment device to relay sensor and control information to the surface.
  • the apparatus further includes permanent sensors for incorporating into a completion to provide operational support.
  • the apparatus further includes one or more fluid control devices for incorporating into a completion to provide an additional well control barrier.
  • the apparatus further includes a Y-tool, the Y-tool when the rotary pump is placed in the well.
  • the driver drives the rotary pump impeller to a rate greater than about 7200 rpm, or greater than about 10,000 rpm.
  • a method of removing fluids from a well includes the steps of installing an apparatus in a wellbore, the apparatus comprising a rotary pump having an inlet end and a discharge end, the rotary pump including at least one pump impeller intermediate the inlet end and discharge end; a driver for driving the at least one pump impeller, the driver positioned within the wellbore and operatively connected to the rotary pump; a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system; operating the apparatus at a rate greater than about 3600 rpm; and removing fluids from the well.
  • an apparatus for producing fluids from a wellbore or injecting a fluid into a wellbore comprising a rotary compressor including an inlet end and a discharge end, the rotary compressor comprising at least one compressor stage intermediate the inlet end and discharge end, the at least one compressor stage rotating at a rate greater than 3600 rpm; a driver for driving the at least one compressor stage to a rate greater than about 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary compressor; a magnetic bearing system, the magnetic bearing system operatively connected to the high speed compressor and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system.
  • the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof.
  • the apparatus further includes a generator for converting a portion of the rotational energy of the apparatus to electrical power.
  • the driver is connected to the rotary compressor by a magnetic gear, the magnetic gear generating electricity for onboard use.
  • the driver is a gas-powered expander having an inlet and a discharge end, the gas-powered expander driven by high-pressure gas from a down hole gas production zone.
  • the gas-powered expander is driven by injected gas lift gas.
  • the injected gas lift gas enters the gas-powered expander inlet through a down hole gas lift mandrel.
  • the rotational speed or rate of the gas-powered expander is varied by adjusting characteristics of the gas lift gas.
  • the expanded gas is exhausted to a conduit to the surface.
  • the driver is an electric motor.
  • the electric motor is a canned, seal-less motor.
  • the electric motor is magnetically coupled to the rotary compressor.
  • the apparatus further includes a variable speed drive to control the speed or rate of the electric motor.
  • the driver is a hydraulic motor, the hydraulic motor having a power fluid inlet and a power fluid discharge.
  • the apparatus further includes a source of power fluid, the power fluid provided to the power fluid inlet from the surface through a conduit.
  • the apparatus further includes a surface power fluid pump, wherein the speed or rate of the hydraulic motor is controlled by the output of the surface power fluid pump.
  • the power fluid is provided to the hydraulic motor from a high-pressure liquid-producing zone.
  • the high-pressure liquid-producing zone is regulated from a surface-controlled, flow-control mechanism.
  • spent power fluid is discharged with the pump fluid.
  • the apparatus further includes a generator for converting a portion of the rotational energy of the apparatus to electrical power.
  • the magnetic bearing system is powered and controlled by the power produced by the generator.
  • the magnetic bearing system is canned to prevent encroachment of wellbore fluids and improve reliability.
  • the driver is connected to the rotary compressor by a magnetic gear.
  • the magnetic gear generates electricity for onboard use.
  • the apparatus further includes onboard sensors, wherein at least a portion of the electricity generated powers the onboard sensors.
  • the produced fluid is gas.
  • the driver drives the rotary compressor to a rate greater than about 10,000 rpm.
  • the driver drives the rotary compressor to a rate greater than about 100,000 rpm.
  • a method of producing fluids from a wellbore or injecting a fluid into a wellbore comprising installing an apparatus in a wellbore, the apparatus comprising a rotary compressor including an inlet end and a discharge end, the rotary compressor comprising at least one compressor stage intermediate the inlet end and discharge end, the at least one compressor stage rotating at a rate greater than about 3600 rpm; a driver for driving the at least one compressor stage, the driver positioned within the wellbore and operatively connected to one end of the rotary compressor; and a magnetic bearing system, the magnetic bearing system operatively connected to the rotary compressor and/or driver; and a digital controller positioned within the wellbore to control the magnetic bearing system; operating the apparatus at a rate greater than about 3600 rpm; and removing fluids from the well.
  • a wellbore comprising a borehole in fluid communication with a subterranean reservoir; an apparatus for removing or injecting fluids, the apparatus installed within the wellbore and comprising i) a rotary pump or rotary compressor, the rotary pump or rotary compressor including an inlet end and a discharge end, and at least one pump impeller or at least one intermediate compressor stage rotating at a rate greater than about 3600 rpm; ii) a driver for driving the at least one pump impeller or at least one intermediate compressor stage to a rate greater than above about 3600 rpm, the driver positioned within the wellbore and operatively connected to the rotary pump or rotary compressor; iii) a magnetic bearing system, the magnetic bearing system operatively connected to the rotary pump or rotary compressor and/or driver; and iv) a digital controller positioned within the wellbore to control the magnetic bearing system.
  • the driver is selected from a gas-powered expander, an electric motor, a hydraulic motor and combinations thereof.
  • the apparatus comprises a rotary pump for the production of reservoir fluids.
  • the apparatus comprises a rotary pump for the injection of fluids.
  • the apparatus comprises a rotary pump for the separation of production fluids.
  • the apparatus comprises a rotary compressor for enhancing fluid flow in a gas well.
  • the apparatus comprises a rotary compressor for increasing the gas velocity in a production well.
  • FIG. 1 presents a schematic view of an illustrative, non-exclusive example of an apparatus for removing fluids from a well, according to the present disclosure.
  • FIG. 2 presents another schematic view of an illustrative, non-exclusive example of an apparatus for removing fluids from a well, according to the present disclosure.
  • FIG. 3 presents a schematic view of an illustrative, non-exclusive example of an apparatus for removing fluids from a well, according to the present disclosure.
  • FIG. 4 presents a detailed schematic view of an illustrative, non-exclusive example of a down hole expander pump for removing fluids from a well, according to the present disclosure.
  • FIG. 5 presents a detailed schematic view of an illustrative, non-exclusive example of a down hole high speed magnetic electric submersible pump (ESP) for removing fluids from a well, according to the present disclosure.
  • ESP magnetic electric submersible pump
  • FIG. 6 presents a schematic view of an illustrative, non-exclusive example of an apparatus for producing gas from a wellbore or injecting a fluid into a wellbore, according to the present disclosure.
  • FIG. 7 presents another schematic view of an illustrative, non-exclusive example of an apparatus for producing gas from a wellbore or injecting a fluid into a wellbore, according to the present disclosure.
  • FIG. 8 presents a schematic view of an illustrative, non-exclusive example of an apparatus for producing gas from a wellbore or injecting a fluid into a wellbore, according to the present disclosure.
  • FIGS. 1-8 provide illustrative, non-exclusive examples of down hole high-speed submersible pumps having utility in connection with other wellbore-related methods and systems, according to the present disclosure of systems, and/or apparatus, and/or assemblies that may include, be associated with, be operatively attached to, and/or utilize such down hole high-speed submersible pumps.
  • like numerals denote like, or similar, structures and/or features; and each of the illustrated structures and/or features may not be discussed in detail herein with reference to FIGS. 1-8.
  • each structure and/or feature may not be explicitly labeled in FIGS. 1-8; and any structure and/or feature that is discussed herein with reference to FIGS. 1-8 may be utilized with any other structure and/or feature without departing from the scope of the present disclosure.
  • FIGS. 1-8 structures and/or features that are or are likely to be included in a given embodiment are indicated in solid lines in FIGS. 1-8, while optional structures and/or features are indicated in broken lines.
  • a given embodiment is not required to include all structures and/or features that are illustrated in solid lines therein, and any suitable number of such structures and/or features may be omitted from a given embodiment without departing from the scope of the present disclosure.
  • centrifugal pumping apparatus that has three primary components: 1) high-speed pump stages, 2) a seal-less multi-power driver, and 3) high- reliability bearings.
  • high-speed refers to rotational speeds or rates greater than about 3,600 rpm, which is approximately the operational condition of common submersible AC induction or synchronous motors.
  • the high-speed pump stages greatly reduce the number of pump stages required to produce the same amount of discharge pressure as a standard ESP with a similar diameter.
  • the high rotational speeds permit the pump to handle gas much more effectively than conventional ESPs.
  • the reduction in pump stages also reduce the mass that the pump driver has to spin on the pump shaft. This reduces the operational requirements for shaft strength and driver power.
  • a smaller driver and pump can provide a shorter overall pumping system, allowing much less costly rig-less, through-tubing deployments. These features also make it easier to deploy and function in directionally drilled horizontal wells.
  • power density or volumetric power density or volume specific power
  • power density is meant the amount of power, or time rate of energy transfer, per unit volume. Power density may be expressed in W/m 3 or HP/ft 3 . As may be appreciated, power density can be an important consideration where space is constrained, such as in down-hole applications.
  • Conventional motors employed in ESP applications generally have a power density range of about 530 to about 2000 W/m 3 (25 to 95 HP/ft 3 ).
  • the drivers contemplated herein advantageously have a power density of greater than about 2100 W/m 3 (about 100 HP/ft 3 ), or greater than about 3150 W/m 3 (about 150 HP/ft 3 ), or greater than about 4200 W/m 3 (about 200 HP/ft 3 ), or greater than about 6300 W/m 3 (about 300 HP/ft 3 ), or greater than about 8400 W/m 3 (about 400 HP/ft 3 ), or greater than about 10550 W/m 3 (about 500 HP/ft 3 ), or greater than about 12650 W/m 3 (about 600 HP/ft 3 ), or more.
  • the drivers contemplated herein can yield downhole pumps, injectors, and the like, which possess over twice the available power of conventional ESPs at roughly 1/3 the service length.
  • FIG. 1 presents a schematic view of an illustrative, non-exclusive example of an apparatus 10 for removing fluids from a well W, according to the present disclosure.
  • Apparatus 10 includes a rotary pump 12 for positioning within the well W.
  • Rotary pump 12 includes an inlet end 14 and a discharge end 16.
  • Rotary pump 12 further includes at least one pump impeller 15 intermediate inlet end 14 and discharge end 16.
  • Apparatus 10 further includes a driver for driving the at least one pump rotary pump impeller 15; the driver being positioned within the wellbore and operatively connected to rotary pump 12.
  • the driver comprises a gas- powered expander 18.
  • gas-powered expander 18 has an inlet 20 and a discharge end 24.
  • gas-powered expander 18 may be driven by high-pressure gas from a down hole gas production zone.
  • the down hole gas production zone may be regulated with a surface-controlled flow-control mechanism (not shown).
  • gas-powered expander 18 may be driven by injected gas lift gas G.
  • the injected gas lift gas G enters the gas-powered expander inlet through a down hole gas lift mandrel 22.
  • the rotational speed or rate of gas-powered expander 18 may be varied by adjusting the characteristics of the gas lift gas G.
  • expanded gas is exhausted to the pump discharge 16.
  • the expanded gas is exhausted to a conduit (not shown) to the surface.
  • the expander blades may be designed to match the design speed or rate of the pump stages of rotary pump 12, or an integral gear, including a magnetic gear, can reduce the expander speed or rate to an appropriate pump speed.
  • the magnetic gear can also incorporate a generator to produce electrical power for onboard uses.
  • the use of an expander driver eliminates the problematic seal section.
  • the expander-driven system may be deployed/retrieved with cable or coiled tubing.
  • apparatus 10 further includes a magnetic bearing system 26.
  • magnetic bearings can provide support for any ferromagnetic body without mechanical contact.
  • the advantages of magnetic bearing system 26 compared with traditional solutions include the absence of mechanical wear and friction, lubricant-free operation and therefore suitability for severe environments, active vibration control and unbalance compensation.
  • Magnetic bearing system 26 may be operatively connected to rotary pump 12 and/or gas-powered expander 18. In one embodiment, magnetic bearing system 26 is canned to prevent encroachment of wellbore fluids and improve reliability.
  • apparatus 10 includes magnetic bearing electronic controls 28, comprising a digital controller, and may also include subsurface monitoring components 30. In one form, the digital controller of magnetic bearing electronic controls 28 is positioned within the wellbore to control the magnetic bearing system. In one embodiment, electronic controls 28 and/or subsurface monitoring components 30 are cooled with gas at the discharge end of gas-powered expander 20. To power electronic components, a generator 32 for converting a portion of the rotational energy of apparatus 10 to electrical power may be provided. In one embodiment, magnetic bearing system 26 is powered and controlled by the power produced by generator 32.
  • gas-powered expander 18 operates at the same rotational speed or rate as rotary pump 12.
  • Apparatus 100 includes a rotary pump 1 12 for positioning within the well W.
  • Rotary pump 1 12 includes an inlet end 1 14 and a discharge end 1 16.
  • Rotary pump 1 12 further includes at least one pump impeller 115 intermediate inlet end 1 14 and discharge end 116.
  • the driver for driving the at least one pump rotary pump impeller 1 15 comprises an electric motor 1 18.
  • electric motor 118 has a first end 120 and a second end 122.
  • Electric motor 118 may be a high speed electric motor.
  • electric motor 118 may be a canned, seal-less motor.
  • electric motor 118 may be magnetically coupled to rotary pump 1 12 using a magnetic coupler 120.
  • electric motor 118 may also include a variable speed drive (not shown) to control the speed or rate of electric motor 118.
  • electric motor 1 18 may be a brushless DC motor, an AC induction motor, or a permanent magnet motor. As may be appreciated, these types of motors can be canned to protect the motor windings from well fluids. Electric motor 1 18 can permit pump installations in areas that did not have gas available for an expander-driven version. It also allows rotary pump 1 12 to be set deeper than the deepest available gas injection point. The electric motor-driven system may be deployed/retrieved with an electric cable or coiled tubing with an internal electric cable.
  • apparatus 100 further includes a magnetic bearing system 126.
  • Magnetic bearing system 126 may be operatively connected to rotary pump 1 12 and/or electric motor 118.
  • magnetic bearing system 126 is canned to prevent encroachment of wellbore fluids and improve reliability.
  • apparatus 100 includes magnetic bearing electronic controls 128, comprising a digital controller, and may also include subsurface monitoring components 130.
  • the digital controller of magnetic bearing electronic controls 128 is positioned within the wellbore to control the magnetic bearing system.
  • a generator 132 for converting a portion of the rotational energy of apparatus 100 to electrical power may be provided.
  • magnetic bearing system 126 is powered and controlled by the power produced by generator 132.
  • Apparatus 200 includes a rotary pump 212 for positioning within the well W.
  • Rotary pump 212 includes an inlet end 214 and a discharge end 216.
  • Rotary pump 212 further includes at least one pump impeller 215 intermediate inlet end 214 and discharge end 216.
  • the driver for driving the at least one pump rotary pump impeller 215 comprises a hydraulic motor 218, the hydraulic motor having a power fluid inlet 220 and a power fluid discharge 222.
  • Hydraulic motor 218, has a source of power fluid D (not shown), the power fluid D provided to the power fluid inlet 220 from the surface S through conduit 224.
  • a surface power fluid pump 250 is employed, with the speed or rate of hydraulic motor 218 controlled by the output of power fluid pump 250.
  • power fluid D may be provided to hydraulic motor 218 from a high- pressure liquid-producing zone, as those skilled in the art will plainly understand.
  • the high-pressure liquid-producing zone can be regulated from a surface-controlled, flow-control mechanism.
  • the spent power fluid may be discharged with the pump fluid.
  • Hydraulic motor 218 may be a bent-axis or inline piston motor, a screw turbine, Frances turbine, Pelton wheel or other type of impulse or reaction turbine.
  • the power fluid characteristics and operational speed may be optimized to reduce topside pumping and separation spatial requirements. These requirements could be further reduced by combining the pumping operation with gas lifting in the same well.
  • a gas lift expander drive could also be combined with the hydraulic drive to use the combination of both fluids to drive the rotary pump 212.
  • Hydraulic motor 218 may employ a labyrinth or lip seal to separate fluids.
  • the system of FIG. 3 may be deployed or retrieved with coiled tubing which could also serve as the power fluid conduit.
  • apparatus 200 further includes a magnetic bearing system 226.
  • Magnetic bearing system 226 may be operatively connected to rotary pump 212 and/or hydraulic motor 218.
  • magnetic bearing system 226 is canned to prevent encroachment of wellbore fluids and improve reliability.
  • apparatus 200 includes magnetic bearing electronic controls 228, comprising a digital controller, and may also include subsurface monitoring components 230.
  • the digital controller of magnetic bearing electronic controls 228 is positioned within the wellbore to control the magnetic bearing system.
  • a generator 232 for converting a portion of the rotational energy of apparatus 200 to electrical power may be provided.
  • magnetic bearing system 226 is powered and controlled by the power produced by generator 232.
  • FIG. 4 a schematic view of an illustrative, non-exclusive example of an apparatus 300 for removing fluids from a well W is shown.
  • well W has a casing 302 installed therein, casing 302 having tubing section 304 connected thereto.
  • fluid communication is provided by placing holes in the tubing walls to allow gas to flow into the expander.
  • Apparatus 300 includes a rotary pump 312.
  • Rotary pump 312 includes an inlet end 314 and a discharge end 316.
  • Rotary pump 312 further includes at least one pump impeller 315 intermediate inlet end 314 and discharge end 316.
  • Apparatus 300 further includes a driver for driving the at least one pump rotary pump impeller 315; the driver being operatively connected to rotary pump 312, for example, by a shaft 336.
  • the driver comprises a gas-powered expander 318.
  • gas-powered expander 318 has an inlet 320 and a discharge end 322.
  • apparatus 300 comprises a down hole expander pump.
  • gas-powered expander 318 may be driven by high-pressure gas from a down hole gas production zone.
  • gas-powered expander 318 may be driven by injected gas lift gas G.
  • tubing section 304 may be perforated/slotted, with plug 308 positioned between tubing 304 and casing 302 to inhibit the flow of gas G within the annulus defined by tubing 304 and casing 302.
  • the down hole gas production zone may be regulated with a surface-controlled flow-control mechanism (not shown).
  • the injected gas lift gas G may enter the gas-powered expander inlet 320 through a gas lift mandrel (not shown).
  • the rotational speed or rate of gas-powered expander 318 may be varied by adjusting the characteristics of the gas lift gas G.
  • expanded gas is exhausted to the discharge 322.
  • the expanded gas is exhausted to a conduit (not shown) to the surface.
  • apparatus 300 may include an auger/charge pump assembly 360.
  • Auger/charge pump assembly 360 serves to direct fluid into the inlet end 314 of rotary pump 312, preventing fluids from being blocked from entering due to high impeller speed.
  • apparatus 300 further includes a magnetic bearing system 326, which may include a first bearing set 340 and a second bearing set 342.
  • Magnetic bearing system 326 may be operatively connected to rotary pump 312 and/or gas-powered expander 318.
  • first bearing set 340 and second bearing set 342 may be spaced along shaft 336 for proper support.
  • magnetic bearing system 326 may be canned to prevent encroachment of wellbore fluids and improve reliability.
  • a thrust bearing 338 may also included.
  • Apparatus 300 may also include magnetic bearing electronic controls 328, comprising a digital controller, and may also include subsurface monitoring instrumentation components 330.
  • the digital controller of magnetic bearing electronic controls 328 is positioned within the wellbore to control the magnetic bearing system.
  • electronic controls 328 and/or subsurface monitoring components 330 are cooled with gas G at the discharge end of gas-powered expander 322.
  • a generator 332 may be provided for converting a portion of the rotational energy of apparatus 300 to electrical power.
  • magnetic bearing system 326 is powered and controlled by the power produced by generator 332.
  • the gas-powered expander 318 is connected to the rotary pump 312 by a magnetic gear 344.
  • the term "magnetic gear” is used herein to refer to any change speed gearbox in which an input shaft is coupled magnetically for rotation with an output shaft, without the need for any physical contact between the two, the torque driving the output shaft being magnetically generated.
  • Such a gearbox comprises an input shaft and a concentric output shaft both of which carry an array of permanent magnets.
  • the two arrays of magnets are separated from one another by an intermediate ring comprising an array of pole pieces.
  • the geometry of the permanent magnets and pole pieces determines the gearing ratio. Because an air gap exists between the pole pieces and the two arrays of permanent magnets, the internal parts of a magnetic gearbox do not require lubrication.
  • magnetic gear 344 may be used to generate electricity for onboard use.
  • gas-powered expander 318 operates at the same rotational speed or rate as rotary pump 312.
  • subsurface monitoring instrumentation components 330 include onboard sensors and a portion of the electricity generated by apparatus 300 powers the onboard sensors.
  • the onboard sensors are used for closed-loop control of rotary pump 312.
  • the ability to provide wireless communications to the surface may be provided.
  • a wireless communications card 350 may be provided.
  • electricity generated by converting a portion of the rotational energy of apparatus 300 may be used to power wireless communication card 350.
  • FIG. 5 a schematic view of an illustrative, non-exclusive example of an apparatus 400 for removing fluids from a well W is shown.
  • well W has a casing 402 installed therein, casing 402 having a tubing section 404 connected thereto.
  • fluid communication is provided by placing holes in the tubing walls to allow gas to flow into the expander.
  • Apparatus 400 includes a rotary pump 412.
  • Rotary pump 412 includes an inlet end 414 and a discharge end 416.
  • Rotary pump 412 further includes at least one pump impeller 415 intermediate inlet end 414 and discharge end 416.
  • Apparatus 400 further includes a driver for driving the at least one pump rotary pump impeller 415; the driver being positioned within the wellbore and operatively connected to rotary pump 412, for example, by a shaft 436.
  • the driver comprises an electric motor 418.
  • electric motor 418 has a first end 420 and a second end 422.
  • Electric motor 418 may be a high speed electric motor.
  • electric motor 418 may be a canned, seal-less motor.
  • electric motor 418 may be magnetically coupled to rotary pump 412 using a magnetic coupler, such as a magnetic gear (not shown).
  • electric motor 418 may also include a variable speed drive (not shown) to control the speed or rate of electric motor 418.
  • apparatus 400 may include an auger/charge pump assembly 460.
  • Auger/charge pump assembly 460 serves to direct fluid into the inlet end 414 of rotary pump 412, preventing fluids from being blocked from entering due to high impeller speed.
  • apparatus 400 further includes a magnetic bearing system 426, which may include a first bearing set 440 and a second bearing set 442.
  • Magnetic bearing system 426 may be operatively connected to rotary pump 412 and/or electric motor 418.
  • first bearing set 440 and second bearing set 442 may be spaced along shaft 436 for proper support of the rotating components.
  • magnetic bearing system 426 may be canned to prevent encroachment of wellbore fluids and improve reliability.
  • a thrust bearing (not shown) may also be included.
  • Apparatus 400 may also include magnetic bearing electronic controls 428, comprising a digital controller, and may also include subsurface monitoring instrumentation components 430.
  • the digital controller of magnetic bearing electronic controls 428 is positioned within the wellbore to control the magnetic bearing system.
  • a generator (not shown) may be provided for converting a portion of the rotational energy of apparatus 400 to electrical power.
  • magnetic bearing system 426 is powered and controlled by the power produced by the generator.
  • electric motor 418 may be connected to the rotary pump 412 by a magnetic gear (not shown).
  • the magnetic gear may be used to generate electricity for onboard use.
  • electric motor 418 operates at the same rotational speed or rate as rotary pump 412.
  • subsurface monitoring instrumentation components 430 include onboard sensors and a portion of the electricity generated by apparatus 400 powers the onboard sensors.
  • the onboard sensors are used for closed-loop control of rotary pump 412.
  • the ability to provide wireless communications to the surface may be provided.
  • a wireless communications card 450 may be provided.
  • electricity generated by converting a portion of the rotational energy of apparatus 400 may be used to power wireless communication card 450.
  • an electric or fiber optic cable (not shown) may be run in conjunction with a deployment device to relay sensor and control information to the surface.
  • permanent sensors may be employed for incorporating into a completion to provide operational support.
  • one or more fluid control devices may be incorporated into a completion to provide an additional well control barrier.
  • Y-tool may be employed when the rotary pump is placed in the well.
  • the well is an inclined well and is in fluid communication with a subterranean reservoir that produces sufficient gas to foul, interrupt, or cause significant pump efficiency losses.
  • the subterranean reservoir is gas- dominated.
  • FIG. 6 presents a schematic view of an illustrative, non-exclusive example of an apparatus 500 for producing gas from a wellbore or, alternatively, injecting a fluid into a wellbore, according to the present disclosure.
  • Apparatus 500 includes a rotary compressor 512 for positioning within the wellbore.
  • Rotary compressor 512 includes an inlet end 514 and a discharge end 516.
  • Rotary compressor 512 further includes at least one compressor stage 515 intermediate inlet end 514 and discharge end 516.
  • FIG. 6 depicts the case where apparatus 500 is used for production. Should apparatus 500 be used for the injection of fluids into a wellbore, apparatus 500 may be rotated 180 degrees, as those skilled in the art would plainly recognize.
  • Apparatus 500 further includes a driver for driving the at least one compressor stage 515; the driver being positioned within the wellbore and operatively connected to rotary compressor 512.
  • the driver comprises a gas-powered expander 518.
  • gas-powered expander 518 has an inlet 520 and a discharge end 524.
  • gas-powered expander 518 may be driven by high-pressure gas from a down hole gas production zone.
  • the down hole gas production zone may be regulated with a surface-controlled flow-control mechanism (not shown).
  • gas-powered expander 518 may be driven by injected gas lift gas G.
  • the injected gas lift gas G enters the gas-powered expander inlet through a down hole gas lift mandrel 522.
  • the rotational speed or rate of gas-powered expander 518 may be varied by adjusting the characteristics of the gas lift gas G.
  • expanded gas is exhausted to the pump discharge 516.
  • the expanded gas is exhausted to a conduit (not shown) to the surface.
  • apparatus 500 further includes a magnetic bearing system 526.
  • Magnetic bearing system 526 may be operatively connected to rotary compressor 512 and/or gas-powered expander 518.
  • magnetic bearing system 526 is canned to prevent encroachment of wellbore fluids and improve reliability.
  • apparatus 500 includes magnetic bearing electronic controls 528, comprising a digital controller, and may also include subsurface monitoring components 530.
  • electronic controls 528 and/or subsurface monitoring components 530 are cooled with gas at the discharge end of gas-powered expander 524.
  • the digital controller of magnetic bearing electronic controls 528 is positioned within the wellbore to control the magnetic bearing system.
  • a generator 532 for converting a portion of the rotational energy of apparatus 500 to electrical power may be provided.
  • magnetic bearing system 526 is powered and controlled by the power produced by generator 532.
  • gas-powered expander 518 operates at the same rotational speed or rate as rotary pump 512.
  • Apparatus 600 includes a rotary compressor 612 for positioning within a well.
  • Rotary compressor 612 includes an inlet end 614 and a discharge end 616.
  • Rotary compressor 612 further includes at least one compressor stage 615 intermediate inlet end 614 and discharge end 616.
  • the driver for driving the at least one compressor stage 615 comprises an electric motor 618.
  • electric motor 618 has a first end 620 and a second end 622.
  • Electric motor 618 may be a high speed electric motor.
  • electric motor 618 may be a canned, seal-less motor.
  • electric motor 618 may be magnetically coupled to rotary compressor 612 using a magnetic coupler 620.
  • electric motor 618 may also include a variable speed drive (not shown) to control the speed or rate of electric motor 618.
  • apparatus 600 further includes a magnetic bearing system 626.
  • Magnetic bearing system 626 may be operatively connected to rotary compressor 612 and/or electric motor 618.
  • magnetic bearing system 626 is canned to prevent encroachment of wellbore fluids and improve reliability.
  • apparatus 600 includes magnetic bearing electronic controls 628, comprising a digital controller, and may also include subsurface monitoring components 630.
  • the digital controller of magnetic bearing electronic controls 628 is positioned within the wellbore to control the magnetic bearing system.
  • a generator 632 for converting a portion of the rotational energy of apparatus 600 to electrical power may be provided.
  • magnetic bearing system 626 is powered and controlled by the power produced by generator 632.
  • Apparatus 700 includes a rotary compressor 712 for positioning within a well W.
  • Rotary compressor 712 includes an inlet end 714 and a discharge end 716.
  • Rotary compressor 712 further includes at least one compressor stage 715 intermediate inlet end 714 and discharge end 716.
  • the driver for driving the at least one compressor stage 715 comprises a hydraulic motor 718, the hydraulic motor having a power fluid inlet 720 and a power fluid discharge 722.
  • Hydraulic motor 718 has a source of power fluid D (not shown), the power fluid D provided to the power fluid inlet 720 from the surface, as shown in FIG.3.
  • a surface power fluid pump is employed, with the speed or rate of hydraulic motor 718 controlled by the output of the power fluid pump.
  • power fluid D may be provided to hydraulic motor 718 from a high- pressure liquid-producing zone, as those skilled in the art will plainly understand.
  • the high-pressure liquid-producing zone can be regulated from a surface-controlled, flow-control mechanism.
  • the spent power fluid may be discharged with the pump fluid.
  • apparatus 700 further includes a magnetic bearing system 726.
  • Magnetic bearing system 726 may be operatively connected to rotary compressor 712 and/or hydraulic motor 718.
  • magnetic bearing system 726 is canned to prevent encroachment of wellbore fluids and improve reliability.
  • apparatus 700 includes magnetic bearing electronic controls 728, comprising a digital controller, and may also include subsurface monitoring components 730.
  • the digital controller of magnetic bearing electronic controls 728 is positioned within the wellbore to control the magnetic bearing system.
  • a generator 732 for converting a portion of the rotational energy of apparatus 700 to electrical power may be provided.
  • magnetic bearing system 726 is powered and controlled by the power produced by generator 732.
  • the term "and/or" placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity.
  • Multiple entities listed with “and/or” should be construed in the same manner, i.e., "one or more" of the entities so conjoined.
  • Other entities may optionally be present other than the entities specifically identified by the "and/or” clause, whether related or unrelated to those entities specifically identified.
  • a reference to "A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities).
  • These entities may refer to elements, actions, structures, steps, operations, values, and the like.
  • the phrase "at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities.
  • This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one" refers, whether related or unrelated to those entities specifically identified.
  • At least one of A and B may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities).
  • each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.
  • adapted and “configured” should not be construed to mean that a given element, component, or other subject matter is simply "capable of performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

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Abstract

La présente invention concerne un appareil, un procédé et un système destinés à retirer des fluides d'un puits comprenant une pompe rotative à positionner dans le puits, la pompe rotative comportant une extrémité d'entrée et une extrémité de sortie, la pompe rotative comprenant au moins une roue de pompe entre l'extrémité d'entrée et l'extrémité de sortie, la ou les roues de pompe tournant à une vitesse supérieure à 3600 tr/min ; un dispositif d'entraînement destiné à entraîner la ou les roues de pompe à une vitesse supérieure à 3600 tr/min, le dispositif d'entraînement étant positionné dans le puits de forage et fonctionnellement relié à la pompe rotative ; un système de palier magnétique, le système de palier magnétique étant fonctionnellement relié à la pompe rotative et/ou au dispositif d'entraînement ; et un dispositif de commande numérique positionné dans le puits de forage afin de commander le système de palier magnétique. L'invention concerne aussi un procédé destiné à retirer les liquides d'un puits ainsi qu'un appareil et un procédé de production de gaz depuis un puits de forage ou d'injection d'un fluide dans un puits de forage.
PCT/US2014/051947 2013-10-29 2014-08-20 Pompes submersibles à puissances multiples et à vitesse élevée, et compresseur WO2015065574A1 (fr)

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US10385856B1 (en) 2018-05-04 2019-08-20 Lex Submersible Pumps FZC Modular electric submersible pump assemblies with cooling systems
CN113612348A (zh) * 2021-10-08 2021-11-05 东营市丰润通科技发展有限公司 基于超低速多转子永磁潜油电机的潜油螺杆泵
CN113612348B (zh) * 2021-10-08 2021-12-21 东营市丰润通科技发展有限公司 基于超低速多转子永磁潜油电机的潜油螺杆泵
WO2024028626A1 (fr) 2022-08-02 2024-02-08 Totalenergies Onetech Système de levage de fluide à placer dans un puits de production de fluide, installation et procédé de production de fluide associés
WO2024084260A1 (fr) 2022-10-21 2024-04-25 Totalenergies Onetech Système de levage de fluide à placer dans un puits de production de fluide, installation et procédé associés

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