WO2016160296A1 - Système de pompage submersible ayant dérivation d'écoulement dynamique - Google Patents

Système de pompage submersible ayant dérivation d'écoulement dynamique Download PDF

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Publication number
WO2016160296A1
WO2016160296A1 PCT/US2016/021652 US2016021652W WO2016160296A1 WO 2016160296 A1 WO2016160296 A1 WO 2016160296A1 US 2016021652 W US2016021652 W US 2016021652W WO 2016160296 A1 WO2016160296 A1 WO 2016160296A1
Authority
WO
WIPO (PCT)
Prior art keywords
electric submersible
submersible pumping
recited
fluid
pumping system
Prior art date
Application number
PCT/US2016/021652
Other languages
English (en)
Inventor
Alejandro CAMACHO CARDENAS
David Milton Eslinger
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
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 Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Publication of WO2016160296A1 publication Critical patent/WO2016160296A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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
    • 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

Definitions

  • ESP ESP systems
  • fluids e.g. hydrocarbon-based fluids.
  • the ESP system may be conveyed downhole and used to pump oil from a downhole wellbore location to a surface collection location along a fluid flow path.
  • restrictive flow conditions may be planned, unplanned, or accidental, e.g. unnoticed.
  • the restrictive flow conditions can cause the ESP system to experience increased stress, e.g. increased pressure loads and temperatures, which can lead to accelerated wear and premature failure.
  • a system and methodology facilitate operation of an electric submersible pumping system.
  • the electric submersible pumping system pumps a fluid and creates a fluid flow along a primary flow path.
  • the fluid flow is monitored to detect a decrease in fluid flow rate which can be detrimental to the electric submersible pumping system.
  • Upon detecting the decrease in fluid flow rate at least a portion of the fluid flow is diverted away from the primary flow path to help normalize operation of the electric submersible pumping system.
  • Figure 1 is a schematic illustration of a well system comprising an example of an electric submersible pumping system positioned in a borehole, e.g. a wellbore, according to an embodiment of the disclosure
  • Figure 2 is a schematic illustration of a well system comprising another example of an electric submersible pumping system positioned in a borehole, e.g. a wellbore, according to an embodiment of the disclosure
  • Figure 3 is a schematic illustration of a well system comprising another example of an electric submersible pumping system positioned in a borehole, e.g. a wellbore, according to an embodiment of the disclosure.
  • Figure 4 is a schematic illustration of an example of a control system which may be used to obtain sensor data regarding operation of the electric submersible pumping system and/or perform control operations with respect to the electric submersible pumping system, according to an embodiment of the disclosure.
  • the present disclosure generally relates to a system and methodology which facilitate operation of an electric submersible pumping system.
  • fluid is pumped to create a fluid flow along a primary flow path.
  • the pumped fluid may be a production fluid, e.g. petroleum, or other well fluid directed along the primary flow path to a desired location, e.g. a surface collection location.
  • the fluid flow is monitored to detect a decrease in fluid flow rate which could be detrimental to the electric submersible pumping system.
  • the decrease in fluid flow rate may be a predetermined reduction in fluid flow along the primary flow path.
  • the decrease in fluid flow rate also can be due to many sources including, but not limited to: surface blockage, downhole blockage (either upstream or downstream of the electric submersible pumping system), change in well productivity, change in fluid composition (e.g. change in gas ratio or other constituent ratio change), change in fluid properties, and/or other sources.
  • surface blockage either upstream or downstream of the electric submersible pumping system
  • change in well productivity change in fluid composition (e.g. change in gas ratio or other constituent ratio change)
  • change in fluid properties e.g. change in gas ratio or other constituent ratio change
  • the fluid flow may be diverted by a controllable valve which is selectively actuated to divert the entire fluid flow or at least a desired portion of the fluid flow.
  • the valve serves as a dynamic recirculation valve which may be selectively actuated to direct at least some of the fluid flow back to an intake of the electric submersible pumping system.
  • At least some of the fluid flow is directed to a different location away from the intake of the electric submersible pumping system, e.g. to a location below the motor of the electric submersible pumping system to aid cooling of the motor.
  • Other types of flow diverter devices also may be employed for a given operation.
  • the system and methodology described herein may be used to prevent an electric submersible pumping system from operating at no-flow or low-flow conditions when a flow restriction occurs along the primary flow path.
  • the system utilizes the diverter device, e.g. diverter valve system, which can be dynamically opened and closed to divert at least a portion of the fluid flow away from the primary flow path and to thus keep the electric submersible pumping system operating with desired flow rates during the downstream flow restriction event. Opening and closing of the diverter device may be done on command or automatically by, for example, a processor-based controller.
  • the diverter device may be positioned to enable selective creation of an opening proximate a discharge of the electric submersible pumping system.
  • the opening proximate the discharge may be connected back to an intake of the pumping system to provide a controlled partial or total recirculation of the pumped fluid.
  • a sensor system may be used to monitor the fluid flow to determine a reduction in fluid flow indicative of the flow restriction.
  • the sensor system may be coupled with the processor-based controller or other type of control system.
  • the diverter device may be positioned at various distances from the electric submersible pumping system depending on a desired recirculation volume, pattern or timing, and/or other factors.
  • multiple diverter devices may be employed and operated simultaneously or independently with respect to each other. The multiple diverter devices may be used to set a desired recirculation regime or to act as a redundant system for backup purposes.
  • the well system 20 may comprise an electric submersible pumping system 24 having a variety of components depending on the particular application and/or environment in which it is operated.
  • the illustrated electric submersible pumping system 24 comprises a submersible electric motor 26, a motor protector 28, and a submersible pump 30 powered by the submersible electric motor 26.
  • the submersible pump 30 may be in the form of a centrifugal pump having two or more stages 32, e.g. compression stages, with each stage having an impeller and a diffuser.
  • the pump stages 32 may be characterized according to the angle of flow passages in the impellers, e.g. radial flow stages, mixed flow stages, or axial flow stages.
  • a thrust bearing 34 may be used to resist the net thrust load, e.g. down thrust load, resulting from rotation of the impellers.
  • the borehole 22 may be a wellbore drilled into a geologic formation 36 containing a desirable production fluid 38, e.g. petroleum.
  • the electric submersible pumping system 24 may be used with a variety of other types of boreholes and other types of fluids.
  • the wellbore 22 may be lined with a casing 40 and perforations 42 may be formed through the casing 42 enable flow of fluid, e.g. production fluid, between the surrounding formation 36 and the wellbore 22.
  • the electric submersible pumping system may be deployed in borehole 22 via a conveyance system 44 which may have a variety of configurations.
  • conveyance system 44 may comprise tubing 46, e.g. coiled tubing or production tubing, or another suitable conveyance, such as cable.
  • the conveyance system 44 is coupled with electric submersible pumping system 24 by a connector 48. Power may be provided to the submersible motor 26 via a power cable 50.
  • Electric power is provided to submersible motor 26 via power cable 50 so as to operate the submersible motor 26.
  • the submersible motor 26 powers the operation of submersible pump 30 which is then able to draw in fluid 38 through a pump intake 52 and to discharge the pumped fluid through a discharge 54.
  • the fluid flow pumped through discharge 54 flows along a primary flow path 56 to a desired location, e.g. a desired collection location at a surface 58 of the earth.
  • the primary flow path 56 is along an interior of tubing 46 but the primary flow path 56 can be disposed along an annulus surrounding conveyance 44 or along another suitable passage.
  • At least a portion of the fluid flow passes a diverter device 60 which is in fluid communication with discharge 54.
  • the diverter device 60 may be selectively actuated to divert at least a portion of the fluid flow from the primary flow path 56, as described in greater detail below.
  • the diverter device 60 may be positioned along tubing 46 and the fluid flow from discharge 54 may be directed through the diverter device 60.
  • submersible pump 30 is a centrifugal pump having a plurality of impellers which are rotated via a shaft powered by submersible motor 26. Rotation of the impellers causes fluid to be drawn in through the pump intake 52 so that it may be pumped through the stages 32 and directed to primary flow path 56 via discharge 54.
  • a restriction, e.g. blockage, of flow along primary flow path 56 causes a decrease in flow rate with respect to the fluid flowing along primary flow path 56. Consequently, the pump head (pressure) generally increases and the pump efficiency dramatically decreases which can lead to detrimental thrust loads and/or heat.
  • no-flow or low-flow condition also causes a lower amount of fluid flow past submersible motor 26 and thus a reduced cooling effect. This can lead to harmful temperature increments at the submersible motor 26 and/or other components of electric submersible pumping system 24.
  • system 20 is a well system and electric submersible pumping system 24 is deployed in wellbore 22 for production of petroleum or other desired fluids.
  • the electric submersible pumping system 24 is operated to pump a production fluid from a downhole location in wellbore 22 to a wellhead 62 via primary flow path 56.
  • the diverter device 60 may be shifted to a position which closes off fluid flow (or at least a portion of the flow) to wellhead 62.
  • the diverter device 60 effectively diverts the fluid flow, e.g. the entire fluid flow or at least a portion of the fluid flow, to another location to enable the electric submersible pumping system 24 to continue pumping fluid at a desired flow rate, e.g. a normal flow rate.
  • the diverter device 60 may be in the form of a valve 64 or a plurality of valve 64 which may be actuated to block flow along the primary flow path 56 and to divert that portion of the flow to another location.
  • Valve(s) 64 may be in the form of ball valves, sliding sleeves, spool valves, multi-position valves, and/or other suitable valves which may be controllably actuated between different flow positions.
  • the diverted flow is directed into the wellbore
  • the recirculation flow 66 may be routed through a dedicated tubing back to pump intake 52. In other applications, the recirculation flow 66 may be routed through a dedicated tubing back to pump intake 52. In other applications, the recirculation flow 66 may be routed through a dedicated tubing back to pump intake 52. In other applications, the recirculation flow 66 may be routed through a dedicated tubing back to pump intake 52. In other applications, the
  • recirculation flow may be routed below the submersible motor 26 and/or to other useful locations within the wellbore 22.
  • the fluid flow which is diverted and redirected to pump intake 52 may then be drawn into the electric submersible pumping system 24 and continually recirculated until the diverter device 60, e.g. valve(s) 64, is shifted to again direct increased flow along primary flow path 56.
  • the diverter device 60 e.g. valve(s) 64
  • shifting of the diverter device 60 back to the original position enables the production fluid to be pumped along primary flow path 56 to wellhead 62 rather than back to the pump intake 52.
  • the dynamic recirculation valve 64 (or other diverter device 60) may be shifted to a position such that a portion of the entire production fluid flow is directed along the primary flow path 56 to the wellhead 62 and the other portion of the production flow is directed back to the pump intake 52 or to another desired location.
  • the diverter device 60 and dynamic recirculation valve 64 may be selectively used in combination with pump intake 52 as a recirculation system.
  • actuation of the diverter device 60 may be controlled via a control system 68, e.g. a processor-based control system.
  • the control system 68 comprises a computer control system located at surface 58. It should be noted, however, the control system 68 may be located in whole or in part downhole, at the surface 58, and/or at locations remote from the wellsite.
  • information, e.g. data, on the restricted flow along primary flow path 56 may be provided to control system 68 via a sensor system 70. Based on data from sensor system 70, the diverter device 60 may be shifted to divert the entire fluid flow or a portion of the fluid flow to a desired location, e.g. a location proximate pump intake 52.
  • the actuation of diverter device 60 may be performed by an operator or autonomously by control system 68.
  • sensor system 70 comprises a variety of sensors which may be used to provide data to control system 68.
  • the system 20 also may comprise a downhole control system 72 disposed at the bottom end of submersible motor 26 or at another suitable location.
  • the downhole control system 72 may be used alone or in cooperation with control system 68 to, for example, control operation of submersible motor 26 and/or diverter device 60.
  • downhole control 72 may be used to collect sensor data and to provide the data to control system 68 and/or to receive and execute control instructions from control system 68.
  • the downhole control system 72 may be used to obtain sensor data from sensor system 70 and to control actuation of diverter device 60 and/or submersible motor 26 based on that sensor data.
  • control system 68 e.g. a surface control system, for obtaining data from sensor system 70 and for processing that data to determine the appropriate flow position for diverter device 60.
  • sensor system 70 a variety of sensors may be utilized to monitor desired parameters related to fluid flow along primary flow path 56, fluid flow along diverted flow path 66, operation of electric submersible pumping system 24, and/or other parameters.
  • the submersible motor 26 may be equipped with one or more sensors 74, e.g. temperature sensors and/or vibration sensors.
  • the sensor system 70 also may comprise sensors 76 positioned along motor protector 28 and those sensors may comprise vibration sensors, load sensors, and/or other desired sensors.
  • the sensor system 70 may comprise intake sensors 78, e.g. pressure sensors, temperature sensors, vibration sensors, and/or other desired sensors, located in or on pump intake 52.
  • the submersible pump 30 and/or discharge 54 also may be equipped with one or more sensors 80, e.g. pressure sensors, temperature sensors, vibration sensors, and/or other suitable sensors.
  • sensor system 70 comprises a flow rate sensor 82 which may be disposed between discharge 54 and diverter device 60 or at another suitable location.
  • Sensor system 70 also may utilize sensors 84 positioned in or at wellhead 62 and those sensors may comprise pressure sensors, temperature sensors, flow rate sensors, and/or other suitable sensors.
  • the various sensors of sensor system 70 are placed in communication with surface control 68 via suitable hardwired and/or wireless communication lines 86.
  • the surface control 68 may be a computer system having a processor-based control able to receive the data from the various sensors of sensor system 70 to determine the presence of a flow restriction or other anomaly indicating the desirability of actuating diverter device 60.
  • control system 68 may be used to determine whether the electric submersible pumping system 24 is operating outside a predetermined operating range.
  • the surface control system 68 (or otherwise located control system 68) may be programmed to autonomously control the flow position of diverter device 60.
  • sensor system 70 utilize sensors distributed at least in part in and/or on electric submersible pumping system 24 and those sensors are operatively coupled with the surface control system 68 and/or downhole control logic of downhole control system 72.
  • Control systems 68, 72 may be used alone or in combination to determine, for example, whether the electric submersible pumping system is operating outside a predetermined operating range based on signals from the sensor or sensors.
  • the control logic may be programmed to automatically adjust the speed of submersible motor 26 and/or to automatically actuate diverter device 60 and/or valves at wellhead 62.
  • the control system 68 and/or downhole control system 72 may be programmed to automatically actuate the dynamic recirculation valve 64/diverter device 60 to maintain operation of the electric submersible pumping system within a desired flow regime.
  • the diverter valve 64 may be actuatable to a plurality of variable positions to adjust the level of fluid flow diverted, e.g. recirculated.
  • the dynamic diverter valve 64 may be in the form of a valve actuatable between a fully open or fully closed flow position.
  • control logic in control system 68 (and/or downhole control system 72) may be programmed to automatically actuate the valve 64 to a desired position to achieve a desired flow operating point with respect to the electric submersible pumping system 24.
  • a closed loop control may be employed to provide feedback to the control system 68/72, thus enabling adjustment of flow in real time via actuation of the dynamic diverter valve 64 or other diverter device 60.
  • the control system 68/72 also may be used to autonomously determine whether to continue operation in the bypass/recirculation mode with a fully open diverter device 60.
  • the control system may be programmed to redirect at least a portion of the fluid flow until the downstream flow restriction along primary flow path 56 has been removed and the normalized operation of electric submersible pumping system 24 can be resumed. This ability to provide a controlled diversion of at least a portion of the fluid flow along primary flow path 56 can greatly prolong the run life of the electric submersible pumping system while protecting the system equipment during harmful transients.
  • the diverter device 60 may be actuated on command.
  • manual control may be used for operations where it is desired to keep the electric submersible pumping system 24 operating but without flow to the surface.
  • Manual control also may be used during well maintenance operations.
  • the control system may be switched between autonomous control and manual control.
  • An electric submersible pump control system in communication with a recirculating control system, also may be used to alter operating parameters of the electric submersible pumping system 24. The operating parameters may be altered to modify performance of the electric submersible pumping system 24 while recirculation is taking place (either automatically or on command).
  • Both the primary control system for the electric submersible pumping system 24 and the recirculation control system can work independently, in communication with each other, or as an integrated single control system.
  • surface control system 68 may be used to control electric submersible pumping system 24 and downhole control system 72 may be utilized as the recirculation control system.
  • the control capabilities of systems 68, 72 may be utilized in a variety of control regimes.
  • the diverter device 60 may be located proximate, e.g. slightly downstream of, pump discharge 54 or at positions between tandem submersible pumps 30. In some applications, a plurality of diverter devices 60 can be employed in cooperation with the electric submersible pumping system 24.
  • the sensors of sensor system 70 may be of a variety of types and may be located in a variety of arrangements and quantities along the overall system 20. In some applications, various sensors may be used to determine a flow condition of well system 20 in lieu of a dedicated flow meter. Additional sensors also may be used provide redundancy with respect to a flow meter type sensor.
  • a differential pressure may be created by, for example, an orifice, and this differential pressure may be used to dictate the flow position of the diverter device 60/valve 64.
  • the flow position may be based on logic programmed into surface control system 68 (and/or downhole control system 72).
  • the dynamic valve 64 (or other diverter device 60) may be actuated to completely block flow along primary flow path 56.
  • Such a closed operating configuration can be useful, for example, to enable clearing of operational transients such as gas-lock and gas slugs.
  • FIG. 4 an example of a computer-based processing system is illustrated.
  • the illustrated computer- based processing system will be referred to as surface control system 68.
  • the description may apply to downhole control system 72 and/or other types of control systems which are located, in whole or in part, downhole, at the surface, or at a remote location with respect to the wellsite.
  • control system 68 comprises a networked system 88 and includes one or more processors 90, memory and/or storage components 92, one or more input and/or output devices 94, and a bus 96. Instructions may be stored in one or more computer-readable media of memory/storage components 92. Such instructions may be read by one or more of the processors 90 via the communication bus 96 which may be in the form of a wired or wireless communication bus.
  • the one or more processors 90 may be used to execute such instructions and to implement (wholly or in part) one or more attributes of a methodology, e.g.
  • the computer- readable media may comprise a storage component such as a physical memory storage device in the form of a chip, a chip on a package, a memory card, or another suitable storage component.
  • control system components e.g. components 90, 92, 94,
  • the network system 88 may be used in combination with or may be distributed within network system 88.
  • the network system 88 may comprise distributed components 98 which may include one or more of the processors 90, memory/storage components 92, and/or input/output devices 94.
  • the various components may communicate over a network 100 which may comprise the Internet, an intranet, a cellular network, a satellite network, and/or other suitable networks.
  • the structure of well system 20 may be adjusted.
  • the electric submersible pumping system 24 may be combined with various other components for use in a wellbore or other type of borehole.
  • the diverter device 60 may comprise a variety of valves and/or other flow control and mechanisms.
  • the sensor system 70 also may comprise an individual sensor or a plurality of cooperating sensors to monitor flow rate and/or other parameters related to operation of the electric submersible pumping system 24.
  • the data from sensor system 70 may be provided to a variety of control systems which may be used to enable manual and/or autonomous control of the diverter device 60 and/or other components, e.g. submersible motor 26, of the well system 20.
  • the recirculation system 60, 64, 52 also may be combined with an alarm functionality to provide the option of triggering an alarm signal during, for example, a blockage event.
  • the alarm signal can be provided via selected communication channels and can be used to alert electric submersible pumping system operators of potential issues, thus enabling the taking of appropriate actions before the potential issues become problematic.

Abstract

L'invention concerne une technique qui facilite le fonctionnement d'un système de pompage submersible électrique. Le système de pompage submersible électrique peut être actionné pour créer un écoulement de fluide par pompage de fluide le long d'une trajectoire d'écoulement primaire. L'écoulement de fluide est contrôlé de façon à détecter une diminution de débit d'écoulement de fluide qui peut être préjudiciable au système de pompage submersible électrique. Lors de la détection de la diminution de débit d'écoulement de fluide, au moins une partie de l'écoulement de fluide est dérivée à partir de la trajectoire d'écoulement primaire pour aider à normaliser le fonctionnement du système de pompage submersible électrique.
PCT/US2016/021652 2015-04-03 2016-03-10 Système de pompage submersible ayant dérivation d'écoulement dynamique WO2016160296A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201562142664P 2015-04-03 2015-04-03
US62/142,664 2015-04-03

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WO2016160296A1 true WO2016160296A1 (fr) 2016-10-06

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN110513082A (zh) * 2018-05-21 2019-11-29 中国石油化工股份有限公司 一种电机保护器和包含其的管柱

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US7530392B2 (en) * 2005-12-20 2009-05-12 Schlumberger Technology Corporation Method and system for development of hydrocarbon bearing formations including depressurization of gas hydrates
US20090223662A1 (en) * 2008-03-05 2009-09-10 Baker Hughes Incorporated System, method and apparatus for controlling the flow rate of an electrical submersible pump based on fluid density
US20090288821A1 (en) * 2008-05-23 2009-11-26 Tesco Corporation (Us) Monitoring Flow Rates While Retrieving Bottom Hole Assembly During Casing While Drilling Operations
US20100139388A1 (en) * 2004-07-05 2010-06-10 Neil Griffiths Monitoring fluid pressure in a well and retrievable pressure sensor assembly for use in the method
US20100228502A1 (en) * 2009-03-03 2010-09-09 Baker Hughes Incorporated System and Method For Monitoring Fluid Flow Through an Electrical Submersible Pump

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20100139388A1 (en) * 2004-07-05 2010-06-10 Neil Griffiths Monitoring fluid pressure in a well and retrievable pressure sensor assembly for use in the method
US7530392B2 (en) * 2005-12-20 2009-05-12 Schlumberger Technology Corporation Method and system for development of hydrocarbon bearing formations including depressurization of gas hydrates
US20090223662A1 (en) * 2008-03-05 2009-09-10 Baker Hughes Incorporated System, method and apparatus for controlling the flow rate of an electrical submersible pump based on fluid density
US20090288821A1 (en) * 2008-05-23 2009-11-26 Tesco Corporation (Us) Monitoring Flow Rates While Retrieving Bottom Hole Assembly During Casing While Drilling Operations
US20100228502A1 (en) * 2009-03-03 2010-09-09 Baker Hughes Incorporated System and Method For Monitoring Fluid Flow Through an Electrical Submersible Pump

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN110513082A (zh) * 2018-05-21 2019-11-29 中国石油化工股份有限公司 一种电机保护器和包含其的管柱

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