WO2016044204A1 - Modulation de débit de système de pompage submersible électrique - Google Patents

Modulation de débit de système de pompage submersible électrique Download PDF

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Publication number
WO2016044204A1
WO2016044204A1 PCT/US2015/050079 US2015050079W WO2016044204A1 WO 2016044204 A1 WO2016044204 A1 WO 2016044204A1 US 2015050079 W US2015050079 W US 2015050079W WO 2016044204 A1 WO2016044204 A1 WO 2016044204A1
Authority
WO
WIPO (PCT)
Prior art keywords
flow
pumping system
modulation device
electric submersible
submersible pumping
Prior art date
Application number
PCT/US2015/050079
Other languages
English (en)
Inventor
Jahir Pabon
David Milton Eslinger
Jeffery Anderson
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Schlumberger Technology Corporation
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 Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited, Schlumberger Technology Corporation filed Critical Schlumberger Canada Limited
Publication of WO2016044204A1 publication Critical patent/WO2016044204A1/fr

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Classifications

    • 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
    • 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

Definitions

  • Electric submersible pumping systems are used in a variety of well applications for moving fluid.
  • electric submersible pumping systems may be used for artificial lift in producing fluids from a subterranean formation or for injection of fluids into the subterranean formation.
  • electric submersible pumping systems comprise a submersible pump powered by a submersible motor which is protected from the environmental fluids by a motor protector.
  • a system and methodology are provided for enhancing the usefulness of an electric submersible pumping system.
  • the effectiveness of the electric submersible pumping system can be improved through flow modulation.
  • the flow resulting from operation of the electric submersible pumping system may be controlled to create desirable effects, e.g. pressure pulses, which are able to enhance production and/or injection operations.
  • Figure 1 is a schematic view of an example of a flow modulation device combined with an electric submersible pumping system, according to an embodiment of the disclosure
  • Figure 2 is a schematic view of another example of a flow modulation device combined with an electric submersible pumping system, according to an embodiment of the disclosure
  • Figure 3 is a schematic view of another example of a flow modulation device combined with an electric submersible pumping system, according to an embodiment of the disclosure
  • Figure 4 is a schematic view of another example of a flow modulation device combined with an electric submersible pumping system for use in improving an injection operation, according to an embodiment of the disclosure
  • Figure 5 is an illustration of an example of a flow modulation device and a flow restrictor combined with an electric submersible pumping system, according to an embodiment of the disclosure
  • Figure 6 is a flowchart illustrating an operational example of a flow modulation device used with an electric submersible pumping system, according to an embodiment of the disclosure.
  • Figure 7 is a flowchart illustrating another operational example of a flow modulation device used with an electric submersible pumping system, according to an embodiment of the disclosure.
  • the present disclosure generally relates to a system and methodology comprising an electric submersible pumping system which works in cooperation with a flow modulation device.
  • an electric submersible pumping system which works in cooperation with a flow modulation device.
  • the flow resulting from operation of the electric submersible pumping system may be affected and used in a desired manner which facilitates production and/or injection operations.
  • the flow modulation device may be utilized to create pulsation, e.g. pressure pulses/waves, that are directed into a hydrocarbon reservoir to enhance production of hydrocarbons fluids.
  • pressure pulses can be used to increase the mobility of fluids in porous media, such as the porous media found in subterranean formations containing hydrocarbons.
  • An electric submersible pumping system may be combined with a flow modulation device to create desired pressure pulses in a flow generated by the electric submersible pumping system.
  • the flow modulation device may be constructed in many forms, including surface pumping devices, downhole mechanical devices, motor control devices, and/or other devices able to create pressure pulses, e.g. acoustic waves.
  • high-frequency pressure pulses have a relatively short penetration distance while low-frequency pressure pulses have deeper penetration.
  • the flow modulation device may be placed in the flow of fluid created by the electric submersible pumping system to cause higher amplitude, e.g. lower frequency and higher amplitude, pulses which are able to provide deep penetration into the surrounding formation.
  • a flow restrictor is placed in an annulus surrounding the electric submersible pumping system to further enhance the pulses and their penetration into the surrounding formation.
  • an example of an electric submersible pumping system 20 is illustrated as deployed in a wellbore 22 via a tubing or other conveyance 23.
  • the wellbore 22 is drilled into a formation/reservoir 24 and extends down from a surface location 26.
  • electric submersible pumping system 20 and conveyance 23 may extend down along the wellbore 22 from suitable surface equipment 27 disposed at the surface location 26.
  • the formation 24 may contain a reservoir of hydrocarbon fluids, such as oil and/or natural gas.
  • the electric submersible pumping system 20 may comprise a variety of components depending on the specifics of a given application, e.g. a production application or injection application.
  • electric submersible pumping system 20 comprises a submersible pump 28 powered by a submersible motor 30. Fluid may be drawn into pump 28 through a pump intake 32, and submersible motor 30 may be protected by a motor protector 34. Power is supplied to submersible motor 30 via a power cable 36 coupled with a control system 38, such as a surface control system.
  • the electric submersible pumping system 20 is combined with a flow modulation system/device 40 which is used to create desired effects on a flow of fluid 41 resulting from operation of the electric submersible pumping system 20.
  • the flow of fluid 41 may be directed upwardly for production or downwardly for injection depending on the application.
  • the electric submersible pumping system 20 is shown schematically, it should be understood that various configurations, components, and adaptations may be used to direct the flow of fluid 41 in the desired production or injection direction.
  • the desired effects may comprise pressure pulses applied to the flow of fluid 41 to create waves with a desired amplitude and frequency for deep penetration of the formation 24.
  • the pressure pulses may be used to enhance the release of
  • the flow modulation device 40 affects the flow of fluid in a manner which creates disturbances, e.g. pulses, carried upstream/downstream along the flow of fluid 41 to the formation 24.
  • the pulses propagate through the formation 24, a greater percentage of the hydrocarbon fluid is released for recovery and production.
  • the pulses may be established via fluid flowing into wellbore 22 for production or via fluid flowing out of wellbore 22 for injection.
  • the flow modulation device 40 may be employed with a production electric submersible pumping system 20 to directly enhance release of hydrocarbons for production.
  • some applications utilize the flow modulation device 40 with an injection electric submersible pumping system 20 to provide desired pulses to the injection fluid.
  • the pulsation in the injection fluid facilitates release of hydrocarbons which can then be produced by, for example, a cooperating pumping system in another wellbore.
  • the flow modulation device 40 may be a passive, e.g. static, device or a dynamic device.
  • the flow modulation device 40 is a dynamic device which may be controlled by a suitable controller, e.g. by the surface control system 38 or another suitable control system.
  • the surface control system 38 may comprise a motor controller 42 used to control submersible motor 30 and a flow modulation device controller 43 employed to control an actuatable valve or other type of flow modulation device 40 to produce a desired pulse amplitude and frequency.
  • the flow modulation device 40 is positioned along the fluid flow 41 on one side, e.g. a downstream side, of electric submersible pumping system 20.
  • the flow modulation device 40 may be positioned on a downstream side of submersible pump 28.
  • the flow modulation device 40 may be mounted to an output end of the submersible pump 28.
  • this downstream flow modulation device 40 may comprise a static choke, baffle, impeller, flow disruptor, or other suitable passive device held in a static position or allowed to move under the influence of fluid flow 41.
  • the flow modulation device 40 also may be an active device, such as an actively controlled valve or pulsator disposed in the fluid flow 41 and controlled by a suitable controller, such as control system 38.
  • control system 38 is located at the surface but the control system may be located downhole or at other suitable locations.
  • the flow modulation device 40 also may be located on an upstream side of at least a portion of the electric submersible pumping system 20.
  • the flow modulation device 40 may be positioned upstream of submersible pump 28 so as to affect the fluid flow 41 prior to entering submersible pump 28.
  • the flow modulation device 40 is positioned between submersible pump 28 and the pump intake 32.
  • the flow modulation device 40 may comprise a variety of passive devices or active devices, e.g. active devices controlled via control system 38, which act against the fluid flow 41 to create pulses along the fluid flow that are transmitted as waves to the surrounding formation 24.
  • the upstream flow modulation device 40 may be an actuatable valve which is controlled by control system 38 to repeatedly, e.g. periodically, change the flow area along which the flow of fluid 41 moves so as to create the desired pulses.
  • the flow modulation device 40 also may be positioned at other locations along the path of fluid flow 41.
  • the flow modulation device 40 may be positioned at other locations along electric submersible pumping system 20, conveyance 23, or surface equipment 27.
  • the flow modulation device 40 is positioned at or proximate surface location 26.
  • the flow modulation device 40 may be in the form of a choke or a valve controlled via control system 38.
  • FIG. 4 another embodiment is illustrated in which the flow modulation device 40 is combined with an embodiment of electric submersible pumping system 20 oriented for injection of fluids into the surrounding formation 24.
  • the electric submersible pumping system 20 may be arranged in various configurations to enable injection of fluids, including inverted configurations, configurations with various crossovers or directors, or other suitable configurations to direct the injection fluid out into the surrounding formation.
  • a packer 44 may be employed along the electric submersible pumping system 20 to facilitate injection of fluids into formation 24 through, for example, perforations.
  • an injection operation is performed in which injection fluids are injected into the surrounding formation 24, as represented by arrows 46.
  • the injection fluids are used to facilitate production of hydrocarbons via a second electric submersible pumping system 48 positioned in a second wellbore 50.
  • the flow modulation device 40 the flow of injection fluid may be affected in a desired manner to further enhance and facilitate production of hydrocarbons fluids via the second electric submersible pumping system 48.
  • the flow modulation device 40 may comprise various passive and/or active devices, as described above, to enable controlled creation of, for example, pulses in the injected fluid.
  • the pulses/waves travel into the formation 24 with the injected fluid 46 and facilitate release of hydrocarbons which can then flow into second wellbore 50 for production to the surface via second electric submersible pumping system 48.
  • the flow modulation device 40 can be positioned along second wellbore 50, e.g. along second electric submersible pumping system 48.
  • modulation devices 40 may be positioned along both wellbore 22 and second wellbore 50 for cooperation with electric submersible pumping system 20 and second electric submersible pumping system 48, respectively.
  • FIG. 5 another embodiment is illustrated in which flow modulation device 40 is combined with a flow restrictor 52.
  • the flow restrictor 52 is positioned in an annulus 54 of wellbore 22 outside of electric submersible pumping system 20.
  • the flow restrictor 52 may be located on an outside diameter of the electric submersible pumping system 20.
  • the flow restrictor 52 is positioned to restrict communication of annular pressure waves, such as pulses caused by flow modulation device 40, and this restriction enhances, e.g. amplifies, the pulses exerted on the surrounding formation 24.
  • the flow restrictor 52 is positioned to restrict propagation of pressure waves to a free fluid surface 56 disposed above the flow restrictor 52 along an annulus 54.
  • the annulus 54 is located within wellbore 22 and external to electric submersible pumping system 20.
  • the flow restrictor 52 effectively enhances the magnitude of the wellbore pressure waves and thus improves the recovery and production of hydrocarbon fluids from formation 24.
  • the flow modulation device 40 may be disposed upstream, downstream, or both with respect to submersible pump 28.
  • the flow modulation device 40 is positioned along a fluid flow path resulting from operation of the electric submersible pumping system 20, as represented by block 60.
  • the flow modulation device 40 and the electric submersible pumping system 20 are deployed downhole into wellbore 22 via, for example, conveyance 23, as represented by block 62.
  • the electric submersible pumping system is then operated to produce fluid flow 41 which may be in the form of a flow of
  • hydrocarbons produced from surrounding formation 24, as represented by block 64 are hydrocarbons produced from surrounding formation 24, as represented by block 64.
  • the passive and/or dynamic flow modulation device 40 creates desired flow effects, e.g. pulses, in the fluid flow 41, as represented by block 66.
  • the pulses are carried into the formation 24 via fluid flow 41 and via the fluid, e.g. hydrocarbons, contained in formation 24; and the pulses serve to enhance production of hydrocarbons from the formation 24.
  • pressure pulses of substantial magnitude e.g. substantial amplitude, may be propagated into the formation to greatly enhance recovery of the hydrocarbon fluid.
  • the flow restrictor 52 may be employed to further enhance the pulsation and to thus further aid recovery of hydrocarbons fluids, as represented by block 68.
  • the flow modulation device 40 is again positioned along a fluid flow path resulting from operation of the electric submersible pumping system 20, as represented by block 70.
  • the flow modulation device 40 and the electric submersible pumping system 20 are deployed downhole into wellbore 22 via, for example, conveyance 23, as represented by block 72.
  • the electric submersible pumping system is then operated to inject a flow of fluid into the surrounding formation 24 containing hydrocarbons, as represented by block 74.
  • the passive and/or dynamic flow modulation device 40 creates desired flow effects, e.g. pulses, in the flow of injection fluid, as represented by block 76.
  • the pulses created in the injection fluid are carried into the formation 24 and used to enhance production of hydrocarbons from the formation 24.
  • the pulsation created in the injection fluid may be used to aid recovery of hydrocarbons fluids which are then produced by a second electric submersible pumping system, e.g. system 48, in another wellbore.
  • the flow modulation device 40 may be used in various configurations and at various locations along fluid flow 41 to provide the desired pulsation.
  • the flow modulation device 40 may be located in the flow into intake 32 or in the flow out of a discharge of electric submersible pumping system 20. In either case, device 40 disrupts/modulates the flow and thus creates desired wellbore pressure waves.
  • the submersible pump 28 may be operated to lift fluid from the formation/reservoir 24 or to inject fluid into the formation/reservoir 24.
  • the flow modulation device 40 may be configured for a specific application and may be in the form of a surface choke, a valve at the discharge of the submersible pump 28, a valve at the intake to the submersible pump 28, or various other passive and/or dynamic devices which can be modulated to achieve the desired fluid flow effects.
  • the flow effects serve to direct substantial pulses/waves into the surrounding formation 24.
  • the modulated flow into or out of the electric submersible pumping system 20 may be controlled in one well to enhance the fluid recovery from at least one additional well.
  • aspects of the flow modulation can be accomplished by additional techniques, including motor speed modulation or modulation of the flow resistance upstream or downstream of the submersible pump 28.
  • the flow modulation device 40 enables direct creation of substantial pulsation by placing the device directly in the flow of fluid created by the electric submersible pumping system.
  • the flow modulation device 40 also may be combined with or used as part of other or additional flow modulation systems.
  • Examples of other or additional flow modulation systems include a suitable control system, e.g. motor controller 42, used to control a speed of the submersible motor 30.
  • the motor controller 42 may comprise a variable speed drive to control the rotational speed of the submersible motor 30 driving submersible pump 28.
  • the speed of submersible motor 30 may be controlled according to a waveform signal so as to create the desired pressure waves by changes in fluid momentum within the submersible pump 28. This enables transmission of the power created by the waveform signal acting on the submersible pump 28 to reservoir 24.
  • the flow modulation may be optimized into or out of the electric submersible pumping system 20 for enhancement of the pumping operation in the wellbore 22 and/or in an additional well or wells.
  • the results of the pressure pulsing may be monitored.
  • sensors may be located along electric submersible pumping system 20, conveyance 23, other locations along wellbore 22, and/or surface location 26 to monitor the enhancement to fluid production.
  • the pressure pulses may be tuned/modified, e.g. the amplitude and/or frequency of the pulses may be changed, so as to maximize the effectiveness of the pulses. Maximizing the effectiveness may comprise increasing the mobility of fluids in the surrounding formation.
  • the data obtained from monitoring may be used to stop the pressure pulses, at least temporarily, for a particular reservoir if the enhancement is not worth the cost.
  • the pressure pulses may be tuned by controlling the rotational speed of the submersible motor 30 via motor controller 42, e.g. a variable speed drive.
  • the motor controller 42 may be programmed with a control logic to continually vary or adjust a rotational speed of the submersible motor 30.
  • the changes in motor rotational speed cause corresponding changes in output of the submersible pump 28, e.g. changes in pulsing, so as to maximize the effectiveness of the pressure pulses.
  • embodiments of the electric submersible pumping system 20 described herein may be constructed in a variety of sizes and configurations and may include other and/or additional components.
  • additional components may be incorporated into the various flow modulation devices 40 depending on the desired control over fluid flow.
  • electric submersible pumping system 20 and the flow modulation device or devices 40 may be used to create a variety of pressure waves at desired amplitudes and frequencies to enhance production applications, injection applications, and/or other applications benefiting from the controlled, modulated flow of fluid.

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

Abstract

L'invention concerne un système et une méthodologie pour améliorer le fonctionnement d'un système de pompage submersible électrique. Dans des opérations de production et/ou d'injection, l'efficacité du système de pompage submersible électrique est améliorée à l'aide d'une modulation de débit. Par exemple, le débit résultant du fonctionnement du système de pompage submersible électrique peut être commandé de façon à créer des impulsions de pression, qui créent elles-mêmes des ondes aptes à améliorer des opérations de production et/ou d'injection.
PCT/US2015/050079 2014-09-15 2015-09-15 Modulation de débit de système de pompage submersible électrique WO2016044204A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201462050268P 2014-09-15 2014-09-15
US62/050,268 2014-09-15

Publications (1)

Publication Number Publication Date
WO2016044204A1 true WO2016044204A1 (fr) 2016-03-24

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Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20010007264A1 (en) * 2000-01-08 2001-07-12 Mcculloch Stephen Choke restrictor devices and methods
US20070034385A1 (en) * 2005-08-15 2007-02-15 Tips Timothy R Pulse width modulated downhole flow control
US20090047157A1 (en) * 2007-08-14 2009-02-19 Baker Hughes Incorporated Dual zone flow choke for downhole motors
US20110233936A1 (en) * 2010-03-26 2011-09-29 Schlumberger Technology Corporation Enhancing the effectiveness of energy harvesting from flowing fluid
US20120327742A1 (en) * 2010-03-02 2012-12-27 David John Kusko Borehole Flow Modulator and Inverted Seismic Source Generating System

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20010007264A1 (en) * 2000-01-08 2001-07-12 Mcculloch Stephen Choke restrictor devices and methods
US20070034385A1 (en) * 2005-08-15 2007-02-15 Tips Timothy R Pulse width modulated downhole flow control
US20090047157A1 (en) * 2007-08-14 2009-02-19 Baker Hughes Incorporated Dual zone flow choke for downhole motors
US20120327742A1 (en) * 2010-03-02 2012-12-27 David John Kusko Borehole Flow Modulator and Inverted Seismic Source Generating System
US20110233936A1 (en) * 2010-03-26 2011-09-29 Schlumberger Technology Corporation Enhancing the effectiveness of energy harvesting from flowing fluid

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