WO2017184158A1 - Système de télémétrie hybride à pompe submersible électrique - Google Patents

Système de télémétrie hybride à pompe submersible électrique Download PDF

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Publication number
WO2017184158A1
WO2017184158A1 PCT/US2016/028767 US2016028767W WO2017184158A1 WO 2017184158 A1 WO2017184158 A1 WO 2017184158A1 US 2016028767 W US2016028767 W US 2016028767W WO 2017184158 A1 WO2017184158 A1 WO 2017184158A1
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WO
WIPO (PCT)
Prior art keywords
transmission line
power
circuitry
data
multiphase
Prior art date
Application number
PCT/US2016/028767
Other languages
English (en)
Inventor
Emmanuel Coste
Rejish JOSEPH
Patrick Zhiyuan Ma
Varun Vinaykumar Nyayadhish
William Goertzen
Gregory Howard MANKE
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
Priority to PCT/US2016/028767 priority Critical patent/WO2017184158A1/fr
Publication of WO2017184158A1 publication Critical patent/WO2017184158A1/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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
    • E21B17/206—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables with conductors, e.g. electrical, optical
    • 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
    • E21B47/135—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 using light waves, e.g. infrared or ultraviolet waves
    • 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
    • F04B17/00—Pumps characterised by combination with, or adaptation to, specific driving engines or motors
    • F04B17/03—Pumps characterised by combination with, or adaptation to, specific driving engines or motors driven by electric motors
    • 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
    • H—ELECTRICITY
    • H01—ELECTRIC ELEMENTS
    • H01B—CABLES; CONDUCTORS; INSULATORS; SELECTION OF MATERIALS FOR THEIR CONDUCTIVE, INSULATING OR DIELECTRIC PROPERTIES
    • H01B7/00—Insulated conductors or cables characterised by their form
    • H01B7/04—Flexible cables, conductors, or cords, e.g. trailing cables
    • H01B7/046—Flexible cables, conductors, or cords, e.g. trailing cables attached to objects sunk in bore holes, e.g. well drilling means, well pumps

Definitions

  • An electric submersible pump (ESP) system can include a pump driven by an electric motor.
  • an ESP system may be deployed in a well, for example, to pump fluid.
  • a system can include an electric submersible pump that includes a multiphase electric motor that includes a wye point; and a gauge operatively coupled to the wye point of the electric motor and operatively coupled to a transmission line where the gauge includes data transmission circuitry operatively coupled to the wye point and data transmission circuitry operatively coupled to the transmission line.
  • a system can include an electric submersible pump that includes an electric motor; a gauge operatively coupled to the electric submersible pump; a cable that includes multiphase power conductors to power the electric motor and a signal transmission line to carry signals generated by the gauge; a motor lead extension that includes multiphase power conductors to power the electric motor and a signal transmission line to carry signals generated by the gauge; and a penetrator that includes a cable side and a motor lead extension side to operatively couple the multiphase power conductors of the cable and the multiphase power conductors of the motor lead extension and to operatively couple the signal transmission line of the cable and the signal transmission line of the motor lead extension.
  • Various other apparatuses, systems, methods, etc. are also disclosed.
  • FIG. 1 illustrates examples of equipment in geologic environments; [0006; Fig. 2 illustrates an example of an electric submersible pump system;
  • FIG. 3 illustrates examples of equipment
  • FIG. 4 illustrates an example of a system that includes a motor
  • Fig. 5 illustrates an example of a cable that includes a transmission line
  • FIG. 6 illustrates an example of a cable that includes a transmission line
  • FIG. 7 illustrates an example of a system
  • Fig. 8 illustrates an example of a system
  • FIG. 9 illustrates an example of a system
  • Fig. 10 ustrates an example of an integrated motor lead extension
  • Fig. 1 1 ustrates an example of a pot head
  • Fig. 12 ustrates an example of a hanger system
  • Fig. 13 ustrates an example of an integrated cable
  • Fig. 14 ustrates examples of integrated cables
  • Fig. 15 ustrates an example of a packer penetrator system
  • FIG. 16 ustrates an example of a system
  • Fig. 17 ustrates an example of a method
  • Fig. 18 ustrates an example of an arrangement of components and an example of circuitry
  • Fig. 19 il ustrates an example of circuitry
  • FIG. 20 il ustrates an example of a system
  • Fig. 21 il ustrates examples of an architectures and an example of an interface card
  • Fig. 1 shows examples of geologic environments 120 and 140.
  • the geologic environment 120 may be a sedimentary basin that includes layers (e.g., stratification) that include a reservoir 121 and that may be, for example, intersected by a fault 123 (e.g., or faults).
  • the geologic environment 120 may be outfitted with any of a variety of sensors, detectors, actuators, etc.
  • equipment 122 may include communication circuitry to receive and to transmit information with respect to one or more networks 125.
  • Such information may include information associated with downhole equipment 124, which may be equipment to acquire information, to assist with resource recovery, etc.
  • Other equipment 126 may be located remote from a well site and include sensing, detecting, emitting or other circuitry. Such equipment may include storage and communication circuitry to store and to communicate data, instructions, etc.
  • one or more satellites may be provided for purposes of communications, data acquisition, etc.
  • Fig. 1 shows a satellite in communication with the network 125 that may be configured for communications, noting that the satellite may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).
  • Fig. 1 also shows the geologic environment 120 as optionally including equipment 127 and 128 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 129.
  • equipment 127 and 128 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 129.
  • a well in a shale formation may include natural fractures, artificial fractures (e.g. , hydraulic fractures) or a combination of natural and artificial fractures.
  • a well may be drilled for a reservoir that is laterally extensive. In such an example, lateral variations in properties, stresses, etc. may exist where an
  • the equipment 127 and/or 128 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.
  • the geologic environment 140 As shown in Fig. 1 , it includes two wells 141 and 143 (e.g., bores), which may be, for example, disposed at least partially in a layer such as a sand layer disposed between caprock and shale.
  • the geologic environment 140 may be outfitted with equipment 145, which may be, for example, steam assisted gravity drainage (SAGD) equipment for injecting steam for enhancing extraction of a resource from a reservoir.
  • SAGD steam assisted gravity drainage
  • SAGD is a technique that involves subterranean delivery of steam to enhance flow of heavy oil, bitumen, etc.
  • SAGD can be applied for Enhanced Oil Recovery (EOR), which is also known as tertiary recovery because it changes properties of oil in situ.
  • EOR Enhanced Oil Recovery
  • a SAGD operation in the geologic environment 140 may use the well 141 for steam-injection and the well 143 for resource production.
  • the equipment 145 may be a downhole steam generator and the equipment 147 may be an electric submersible pump (e.g. , an ESP).
  • steam injected via the well 141 may rise in a subterranean portion of the geologic environment and transfer heat to a desirable resource such as heavy oil.
  • a desirable resource such as heavy oil.
  • equipment 147 e.g. , an ESP
  • a surface facility e.g., via a wellhead, etc.
  • a production well includes artificial lift equipment such as an ESP
  • operation of such equipment may be impacted by the presence of condensed steam (e.g., water in addition to a desired resource).
  • condensed steam e.g., water in addition to a desired resource
  • an ESP may experience conditions that may depend in part on operation of other equipment (e.g. , steam injection, operation of another ESP, etc.).
  • Conditions in a geologic environment may be transient and/or persistent.
  • longevity of the equipment can depend on characteristics of the environment and, for example, duration of use of the equipment as well as function of the equipment.
  • uncertainty may arise in one or more factors that could impact integrity or expected lifetime of the equipment.
  • a period of time may be of the order of decades
  • equipment that is intended to last for such a period of time may be constructed to endure conditions imposed thereon, whether imposed by an environment or environments and/or one or more functions of the equipment itself.
  • FIG. 2 shows an example of an ESP system 200 that includes an ESP 210 as an example of equipment that may be placed in a geologic environment.
  • an ESP may be expected to function in an environment over an extended period of time (e.g. , optionally of the order of years).
  • commercially available ESPs such as the REDATM ESPs marketed by the REDATM ESPs marketed by the REDATM ESPs marketed by the REDATM ESPs marketed by the REDATM ESPs marketed by the REDATM ESPs marketed by
  • an ESP may find use in applications that call pump rates of the order of a thousand barrels per day or more.
  • an ESP may be disposed in a bore to a desired distance (e.g. , depth, etc.).
  • an ESP may be disposed in a bore at a distance, for example, of more than a thousand meters.
  • the ESP system 200 includes a network 201 , a well 203 disposed in a geologic environment (e.g. , with surface equipment, etc.), a power supply 205, the ESP 210, a controller 230, a motor controller 250 and a VSD unit 270.
  • the power supply 205 may receive power from a power grid, an onsite generator (e.g. , natural gas driven turbine), or other source.
  • the power supply 205 may supply a voltage, for example, of about 4.16 kV.
  • the well 203 includes a wellhead that can include a choke (e.g., a choke valve).
  • a choke e.g., a choke valve
  • the well 203 can include a choke valve to control various operations such as to reduce pressure of a fluid from high pressure in a closed wellbore to atmospheric pressure.
  • Adjustable choke valves can include valves constructed to resist wear due to high-velocity, solids-laden fluid flowing by restricting or sealing elements.
  • a wellhead may include one or more sensors such as a temperature sensor, a pressure sensor, a solids sensor, etc.
  • the ESP 210 it is shown as including cables 21 1 (e.g., or a cable), a pump 212, gas handling features 213, a pump intake 214, a motor 215, one or more sensors 216 (e.g., temperature, pressure, strain, current leakage, vibration, etc.) and optionally a protector 217.
  • cables 21 1 e.g., or a cable
  • gas handling features 213 e.g., gas handling features 213, a pump intake 214, a motor 215, one or more sensors 216 (e.g., temperature, pressure, strain, current leakage, vibration, etc.) and optionally a protector 217.
  • sensors 216 e.g., temperature, pressure, strain, current leakage, vibration, etc.
  • an ESP may include a REDATM Hotline high- temperature ESP motor.
  • a REDATM Hotline high- temperature ESP motor may be suitable for implementation in a thermal recovery heavy oil production system, such as, for example, SAGD system or other steam-flooding system.
  • an ESP motor can include a three-phase squirrel cage with two-pole induction.
  • an ESP motor may include steel stator laminations that can help focus magnetic forces on rotors, for example, to help reduce energy loss.
  • stator windings can include copper and insulation.
  • the one or more sensors 216 of the ESP 210 may be part of a digital downhole monitoring system. For example, consider the
  • a monitoring system such as the ENDURANTTM system may be included in an ESP system.
  • a monitoring system may include a base unit that operatively couples to an ESP motor (see, e.g., the motor 215), for example, directly, via a motor-base crossover, etc.
  • a base unit e.g., base gauge
  • a base unit may transmit information via a power cable that provides power to an ESP motor and may receive power via such a cable as well.
  • Such an approach to transmission of information may be referred to as a multiphase approach as it includes transmitting information via one or more electric motor conductors of a multiphase cable.
  • a system can include a dedicated approach to transmission of information, for example, where a transmission line or lines (e.g. , conductor, conductors, optical fiber, optical fibers, etc.) are dedicated to a monitoring system (e.g. , one or more sensors, a gauge, gauges, etc.).
  • a system can include equipment for implementing a multiphase approach and a dedicated approach.
  • a remote unit may be provided that may be located at a pump discharge (e.g. , located at an end opposite the pump intake 214).
  • a base unit and a remote unit may, in combination, measure intake and discharge pressures across a pump (see, e.g. , the pump 212), for example, for analysis of a pump curve.
  • alarms may be set for one or more parameters (e.g. , measurements, parameters based on measurements, etc.).
  • a system includes a base unit and a remote unit, such as those of the PHOENIXTM Multisensor xt150 system
  • the units may be linked via wires.
  • Such an arrangement can provide power from the base unit to the remote unit and can allow for communication between the base unit and the remote unit (e.g., at least transmission of information from the remote unit to the base unit).
  • a remote unit is powered via a wired interface to a base unit such that one or more sensors of the remote unit can sense physical phenomena.
  • the remote unit can then transmit sensed information to the base unit, which, in turn, may transmit such information to a surface unit via one or more electric motor conductors of a multiphase power cable configured to provide power to an ESP motor and/or via a dedicated line.
  • a system may transmit information simultaneously over one or more electric motor conductors of a multiphase power cable and over one or more transmission lines dedicated to a monitoring system.
  • the well 203 may include one or more well sensors 220, for example, such as the commercially available OPTICLINETM sensors or WELLWATCHER BRITEBLUETM sensors marketed by Schlumberger Limited (Houston, Texas). Such sensors are fiber-optic based and can provide for real time sensing of temperature, for example, in SAGD or other operations.
  • a well can include a relatively horizontal portion. Such a portion may collect heated heavy oil responsive to steam injection. Measurements of temperature along the length of the well can provide for feedback, for example, to understand conditions downhole of an ESP.
  • Well sensors may extend into a well, optionally beyond a position of an ESP.
  • the controller 230 can include one or more interfaces, for example, for receipt, transmission or receipt and transmission of information with the motor controller 250, a VSD unit 270, the power supply 205 (e.g., a gas fueled turbine generator, a power company, etc.), the network 201 , equipment in the well 203, equipment in another well, etc.
  • the power supply 205 e.g., a gas fueled turbine generator, a power company, etc.
  • the controller 230 may include or provide access to one or more modules or frameworks. Further, the controller 230 may include features of an ESP motor controller and optionally supplant the ESP motor controller 250.
  • the controller 230 may include the UNICONNTM motor controller 282 marketed by Schlumberger Limited (Houston, Texas).
  • the controller 230 may access one or more of the PIPESIMTM framework 284, the ECLIPSETM framework 286 marketed by Schlumberger Limited (Houston, Texas) and the PETRELTM framework 288 marketed by Schlumberger Limited (Houston, Texas) (e.g. , and optionally the OCEANTM framework marketed by Schlumberger Limited (Houston, Texas)).
  • the motor controller 250 may be a
  • the UNICONNTM motor controller can interface with fixed speed drive (FSD) controllers or a VSD unit, for example, such as the VSD unit 270.
  • FSD fixed speed drive
  • VSD unit for example, such as the VSD unit 270.
  • the UNICONNTM motor controller can connect to a SCADA system, the
  • the UNICONNTM motor controller can perform some control and data acquisition tasks for ESPs, surface pumps or other monitored wells.
  • the UNICONNTM motor controller can interface with the aforementioned PHOENIXTM monitoring system, for example, to access pressure, temperature and vibration data and various protection parameters as well as to provide direct current power to downhole sensors.
  • a system may include one or more interface cards that include circuitry that can interface with a transmission line or lines associated with a monitoring system, sensor unit (e.g., a gauge), etc.
  • a system may include one or more PHOENIXTM interface cards (PICs), which may, for example, provide current (e.g. , direct current) to electric motor conductors of a multiphase power cable that can be received by a sensor unit operatively coupled to a wye point of an electric motor.
  • PICs PHOENIXTM interface cards
  • an interface card may include interfaces that can be implemented in a multiphase approach and/or in a dedicated approach with respect to a monitoring system.
  • an INSTRUCTTM acquisition and control unit [0053] As an example, an INSTRUCTTM acquisition and control unit
  • an interface card may include circuitry that can receive signals as transmitted at least in part via a multiphase power cable that powers an electric motor where the signals include signals that originate at one sensor unit operatively coupled to a wye point of the electric motors.
  • the interface card or another interface card can receive signals that originate at the sensor unit operatively coupled to the wye point of the electric motor, however, where the signals are transmitted via a dedicated transmission line or lines.
  • an interface card can include a multiplexer where, for example, signals received via an interface may be from one or more sources. For example, consider signals received via one or more conductors of a multiphase power cable and signals received via one or more transmission lines dedicated to a monitoring system. As an example, such signals may be joined to a common transmission line or lines and an interface card may optionally operate to break-out signals associated with different transmission modes (e.g., a multiphase mode and a dedicated mode). As an example, an interface card may include circuitry that can demultiplex multiplexed signals (e.g. , multiplexed via a frequency based multiplexing technique and/or a time based multiplexing technique).
  • the UNICONNTM motor controller can monitor ESP system three-phase currents, three-phase surface voltage, supply voltage and frequency, ESP spinning frequency and leg ground, power factor and motor load.
  • a controller such as, for example, a FSD controller may implement control based in part on signals received via one or more ESP coupled sensor units.
  • the UNICONNTM motor controller can monitor VSD output current, ESP running current, VSD output voltage, supply voltage, VSD input and VSD output power, VSD output frequency, drive loading, motor load, three- phase ESP running current, three-phase VSD input or output voltage, ESP spinning frequency, and leg-ground.
  • a controller such as, for example, a VSD controller may implement control based in part on signals received via one or more ESP coupled sensor units.
  • the ESP motor controller 250 includes various modules to handle, for example, backspin of an ESP, sanding of an ESP, flux of an ESP and gas lock of an ESP.
  • the motor controller 250 may include any of a variety of features, additionally, alternatively, etc.
  • the VSD unit 270 may be a low voltage drive (LVD) unit, a medium voltage drive (MVD) unit or other type of unit (e.g. , a high voltage drive, which may provide a voltage in excess of about 4.16 kV).
  • the VSD unit 270 may receive power with a voltage of about 4.16 kV and control a motor as a load with a voltage from about 0 V to about 4.16 kV.
  • the VSD unit 270 may include commercially available control circuitry such as the
  • FIG. 3 shows cut-away views of examples of equipment such as, for example, a portion of a pump 320, a protector 370, a motor 350 of an ESP and a sensor unit 360.
  • the pump 320, the protector 370, the motor 350 and the sensor unit 360 are shown with respect to cylindrical coordinate systems (e.g. , r, z, ⁇ ).
  • cylindrical coordinate systems e.g. , r, z, ⁇
  • Various features of equipment may be described, defined, etc. with respect to a cylindrical coordinate system.
  • a lower end of the pump 320 may be coupled to an upper end of the protector 370
  • a lower end of the protector 370 may be coupled to an upper end of the motor 350
  • a lower end of the motor 350 may be coupled to an upper end of the sensor unit 360 (e.g. , via a bridge or other suitable coupling).
  • a shaft segment of the pump 320 may be coupled via a connector to a shaft segment of the protector 370 and the shaft segment of the protector 370 may be coupled via a connector to a shaft segment of the motor 350.
  • an ESP may be oriented in a desired direction, which may be vertical, horizontal or other angle.
  • the motor 350 is an electric motor that includes a connector 352, for example, to operatively couple the electric motor to a multiphase power cable, for example, optionally via one or more motor lead extensions (see, e.g., Fig. 4).
  • Power supplied to the motor 350 via the connector 352 may be further supplied to the sensor unit 360, for example, via a wye point of the motor 350 (e.g. , a wye point of a multiphase motor).
  • a connector may include features to connect one or more transmission lines dedicated to a monitoring system.
  • the connector 352 may include a socket, a pin, etc., that can couple to a transmission line dedicated to the sensor unit 360.
  • the sensor unit 360 can include a connector that can connect the sensor unit 360 to a dedicated transmission line or lines, for example, directly and/or indirectly.
  • the motor 350 may include a transmission line jumper that extends from the connector 352 to a connector that can couple to the sensor unit 360.
  • a transmission line jumper may be, for example, one or more conductors, twisted conductors, an optical fiber, optical fibers, a waveguide, waveguides, etc.
  • the motor 350 may include a high-temperature optical material that can transmit information.
  • the optical material may couple to one or more optical transmission lines and/or to one or more electrical-to-optical and/or optical-to-electrical signal converters.
  • Fig. 4 shows a block diagram of an example of a system 400 that includes a power source 401 as well as data 402 (e.g., information).
  • the power source 401 provides power to a VSD block 470 while the data 402 may be provided to a communication block 430.
  • the communication block 430 includes one or more interfaces 432 and 434 that can at least receive data via one or more of a multiphase transmission mode via one or more multiphase power cable conductors 41 1 and a dedicated transmission mode via one or more transmission lines 481 .
  • a choke as indicated by a choke block 440 may be implemented to handle signals carried by one or more of the electric motor conductors of the multiphase power cable 41 1 (e.g. , signals to and/or signals from).
  • the choke block 440 may include circuitry to handle signals carried by the
  • transmission line or lines 481 e.g. , signals to and/or signals from.
  • the data 402 may include instructions, for example, to instruct circuitry of the circuitry block 450, one or more sensors of the sensor block 460, etc.
  • the data 402 may be or include data communicated, for example, from the circuitry block 450, the sensor block 460, etc.
  • the data 402 may be or include sensor data (e.g. , sensor signals).
  • sensor data may be direct from a sensor and/or processed via ESP coupled circuitry associated with a downhole monitoring system.
  • sensor data of the one or more sensors of the sensor block 460 may be processed via circuitry of the circuitry block 450.
  • a power cable may be provided in a format such as a round format or a flat format with multiple conductors.
  • MLEs may be spliced onto a power cable to allow each of the conductors to physically connect to an appropriate corresponding connector of an electric motor (see, e.g. , the connector 352 of Fig. 3).
  • MLEs may be bundled within an outer casing (e.g. , a layer of armor, etc.).
  • the power cable 41 1 connects to a motor block 415, which may be a motor (or motors) of an ESP and be controllable via the VSD block 470.
  • the conductors of the power cable 41 1 electrically connect at a wye point 425.
  • the circuitry block 450 may derive power via the wye point 425 and may optionally transmit, receive or transmit and receive data via the wye point 425 (e.g., in a multiphase transmission mode). As shown, the circuitry block 450 may be grounded.
  • data may include commands, instructions,
  • the circuitry block 450 may receive an instruction via the wye point 425 where the instruction may instruct the one or more sensors 460 or, for example, other equipment; the circuitry block 450 may receive an instruction via the one or more transmission lines 481 where the instruction may instruct the one or more sensors of the sensor block 460 and/or circuitry of the circuitry block 450; and/or the one or more sensors of the sensor block 460 may receive an instruction via the one or more transmission lines 481 where the instruction may instruct the one or more sensors of the sensor block 460 and/or circuitry of the circuitry block 450.
  • a transmission line, a multiphase electric motor power cable and MLEs that can resist damaging forces, whether mechanical, electrical or chemical, may help ensure proper operation of a motor, circuitry, sensors, etc.; noting that a faulty power cable (or MLE) can potentially damage a motor, circuitry, sensors, etc.
  • an ESP may be located several kilometers into a wellbore. Accordingly, time and cost to replace a faulty ESP, power cable, MLE, sensor, circuitry, etc., may be substantial (e.g., time to withdraw, downtime for fluid pumping, time to insert, etc.).
  • a system may include a choke configured to receive signals that may be associated with more than one piece of downhole equipment.
  • a choke such as the choke 440 of Fig. 4 may tap one or more phases of a multiphase power cable and/or a transmission line or lines dedicated to a monitoring system and pass transmitted signals to communication circuitry such as the communication circuitry 430, which may optionally be configured to distinguish signals associated with one mode of transmission (e.g., a multiphase transmission mode) from signals associated with another mode of transmission (e.g. , a dedicated transmission mode).
  • a sensor unit may include multiple sensors.
  • one or more of sensors may sense information associated with operation of equipment driven by an electric motor.
  • one or more sensors may sense information associated with operation of an electric motor.
  • Table 1 shows some examples of types of measurements with examples of ranges and examples of rates.
  • a multiphase transmission mode may have a net bit rate of the order of about 12 bits per second, which may be achieved in an analog manner via current modulation.
  • a twisted pair of copper wires may be able to provide a higher bit rate.
  • BRI Basic Rate Interface
  • 2B+D, 2B1 D an Integrated Services Digital Network
  • ISDN Integrated Services Digital Network
  • the BRI configuration provides 2 bearer channels (B channels) at 64 kbit/s per channel and 1 data channel (D channel) at 16 kbit/s.
  • the B channels can be used for voice or user data, and the D channel can be used for a combination of data, control/signaling, and X.25 packet networking.
  • the 2 B channels can be aggregated by channel bonding providing a total data rate of 128 kbit/s (e.g., 128,000 bps).
  • the net bit rate of the Ethernet 100Base-TX physical layer standard is 100 Mbit/s, while the gross bitrate is 125 Mbit/s, due to the 4B5B (four bit over five bit) encoding.
  • the gross bit rate of a V.92 voiceband modem (e.g., with no additional error-correction code) may be up to 56,000 bit/s downstream and 48,000 bit/s upstream (e.g., without data compression).
  • one or more sensors may output data at rates that exceed a rate of one measurement a second.
  • a vibration sensor may output data at 10 Hz or more. Vibration analysis using data output at lower rates may be subject to uncertainty.
  • an electric motor may operate to rotate a shaft at about 3,500 revolutions per minute (e.g., consider operation at about 60 Hz). Vibration may be related to such a rotational speed.
  • vibration can describe oscillations of a mechanical system. Vibration may be defined by frequency (or frequencies) and amplitude. An excitation or oscillating force applied to a system may be considered to be vibration in a generic sense.
  • the ensemble or time-history of vibration may be considered sinusoidal or simple harmonic in form. Vibration encountered in practice often does not have such a regular pattern; however, for purposes of analysis, it may be considered to be a combination of sinusoidal quantities, for example, where individual sinusoids may be characterized by a respective frequency and a respective amplitude. Where a vibration ensemble repeats itself after a determined interval of time, the vibration may be considered to be periodic. Mechanical systems experiencing forced vibrations may continue under steady-state conditions as energy is being supplied to the system continuously, which can compensate for that dissipated by damping in the system. In a free vibrating system, vibration can be a continuing result of an initial disturbance. Theoretically, in the absence of damping, free vibration is assumed to continue indefinitely.
  • Eccentric Armature e.g., OD Motors or Journals
  • vibration may be related to rotational speed. As indicated in various examples of Table 2, a type or types of vibration may exceed rotational speed. For example, vibration associated with an anti-friction bearing of an electric submersible pump (ESP) may exceed five times the rotational speed. Where a rotational speed is about 60 Hz, the vibration may be at a frequency of about 300 Hz.
  • ESP electric submersible pump
  • a sampling rate for vibration measurements can be selected such that is about at least 2.56 times greater than the highest frequency to be discerned. Sampling at a rate higher than 2.56 times the particular frequency of interest can help to ensure that data collected are sufficient to reproduce the signal. As an example, to discern vibration with a frequency of 300 Hz, a sampling rate of about 768 Hz or more may be implemented.
  • LOR Lines of Resolution
  • a vibration analysis may consider sampling rate, sampling time and number of samples where sampling rate is the frequency at which measurements are captured from a sensor, sampling time is the length of time used for taking measurements and the number of samples can refer to the quantity of individual measurements recorded (e.g., the product of sampling rate and sampling time).
  • vibration in an ESP may be flow induced.
  • vibration may occur where amplitude of the vibration depends upon how a pump is operated with respect to a head-capacity curve.
  • flow induced vibration may be related to turbulence, geometry of diffusers with respect to impellers, hydraulic imbalances (e.g., a once per revolution vibration), multi-phase flows, cavitation, etc.
  • the one or more transmission lines 481 may be suitable for transmission of data at a net bit rate that exceeds about 10 Hz. As an example, the one or more transmission lines 481 may be suitable for transmission of data at a net bit rate that exceeds about 100 Hz. As an example, the one or more transmission lines 481 may be suitable for transmission of data at a net bit rate that exceeds about 500 Hz.
  • the one or more transmission lines 481 may be suitable for transmission of data at a net bit rate sufficient to transmit vibration data that can be analyzed to discern vibrations with frequencies of at least about 20 Hz (e.g., corresponding to about at least 1 /3 of a shaft rotational speed).
  • the one or more transmission lines 481 may be suitable for transmission of data at a net bit rate sufficient to transmit vibration data that can be analyzed to discern vibrations with frequencies of at least about 30 Hz (e.g., corresponding to about at least 1/2 of a shaft rotational speed).
  • the one or more transmission lines 481 may be suitable for transmission of data at a net bit rate sufficient to transmit vibration data that can be analyzed to discern vibrations with frequencies of at least about 60 Hz (e.g., corresponding to about at least a shaft rotational speed).
  • the one or more transmission lines 481 may be suitable for transmission of data at a net bit rate sufficient to transmit vibration data that can be analyzed to discern vibrations with frequencies of at least about 120 Hz (e.g., corresponding to about double a shaft rotational speed).
  • a transmission line can be a signal transmission line.
  • a transmission line can be an information transmission line.
  • a signal may be associated with a binary type of logic with two states where presence of the signal corresponds to one of the two states.
  • a signal may be a digital signal and/or an analog signal.
  • a signal may be information and/or carry information and may be continuous and/or discrete in time.
  • information may be coded information such as, for example, a state-based type of code (e.g. , consider Morse code with "on" and "off" states, etc.).
  • information can be or include data.
  • data can be measured data, which may be processed measured data, raw measured data, etc.
  • information can be indicative of a state such as, for example, an operational state of a piece of equipment, pieces of equipment, etc.
  • Fig. 5 shows an example of a multiphase power cable 510 that includes a layer 51 1 , conductors 512-1 , 512-2 and 512-3 and one or more transmission lines 515, which may be, for example, one or more optical fibers 517 and/or one or more wires 519 (e.g., a single wire, a twisted pair, etc.).
  • Fig. 6 shows an example of a multiphase power cable 610 that includes a layer 61 1 , conductors 612-1 , 612-2 and 612-3 and one or more transmission lines 615, which may be, for example, one or more optical fibers 617 and/or one or more wires 619 (e.g., a single wire, a twisted pair, etc.).
  • Fig. 7 shows an example of a system 700 that includes a gauge 701 coupled to an electric motor 702 where a cable 710 provides multiphase power to the electric motor 702 and where the cable 710 includes one or more transmission lines operatively coupled to the gauge 701 .
  • the cable 510 or the cable 610 may be included in the system 700.
  • Fig. 8 shows an example of a system 800 that includes a gauge 801 coupled to an electric motor 802 where a cable 810 provides multiphase power to the electric motor 802 and where one or more transmission lines 815 are operatively coupled to the gauge 801 .
  • the one or more transmission lines 815 may be, for example, one or more optical fibers 817 and/or one or more wires 819.
  • the system 800 may optionally include a first optical signal driver and/or optical signal decoder 896 and may optionally include a second optical signal driver and/or optical signal decoder 898.
  • a first optical signal driver and/or optical signal decoder 896 may optionally include a second optical signal driver and/or optical signal decoder 898.
  • signals generated at a gauge may be transmitted past "noisy" portions of an electrical motor of an ESP (e.g., between the blocks 896 and 898) as optical signals that are less immune to such noise when compared to electrical signals carried by an electrical conductor or conductors.
  • the one or more transmission lines 815 may include one or more wires and one or more optical fibers.
  • power supplied to the components 896 and 898 may be via one or more power supply, optionally power supplied via the cable 810 and/or parasitically derived via rotation of the electric motor 802, via fluid flow, etc.
  • the cable 710 provides multiphase power to the electric motor 702 and where the cable 710 includes one or more transmission lines operatively coupled to the gauge 701 .
  • the cable 510 or the cable 610 may be included in the system 700.
  • the cable 810 provides multiphase power to the electric motor 802 and the one or more transmission lines 815 are operatively coupled to the gauge 801 .
  • a submersible pump power delivery system can include an integrated member for downhole tool communication, which may be, for example, a cable that includes conductors to provide multiphase power to an electric motor and that includes one or more transmission lines for downhole tool communication.
  • an electrical submersible pump can be employed in providing artificial lift to enhance production from an oil well or another type of well.
  • an ESP may offer flexibility and control in terms of flow as well as one or more types of configurations that can suit particular well conditions.
  • an ESP can include a pump, a protector/seal section and a downhole AC induction motor that can drive the pump.
  • the motor can be supplied with power via a power delivery system (e.g., from suitably sized surface electrical equipment).
  • a sensor unit or gauge may be operatively coupled to an ESP motor, for example, to provide well information such as pressure, temperature and vibration.
  • such information can be monitored (e.g. , constantly, periodically, etc.) to assist an operator in decision making, for example, in an effort to enhance production on a real-time basis.
  • an ESP downhole power delivery system can include a variety of components. For example, consider the following listed components that can be in descending order of a completion placement: hanger penetrators or hanger feed-through; power cable; packer penetrator or packer feed-through or POD penetrator; and motor lead extension (MLE).
  • hanger penetrators or hanger feed-through power cable
  • packer penetrator or packer feed-through or POD penetrator and motor lead extension (MLE).
  • a system can include components that provide a dedicated path of telemetry for a downhole gauge. Such a system can allow for telemetry that does not transmit signals via multiphase electrical power conductors of a cable. In such an example, telemetry can be decoupled from various types of power cable issues (e.g., shorts, etc.).
  • a system can include components that, in the instance that a demand for non-power cable dependent telemetry arises, run-in-hole risks may be reduced, for example, if a signal wire would have to be run in a non- integrated fashion.
  • a system can include components that help to reduce handling of another member on a rig floor for a non-power cable dependent mode of communication, which may reduce rig time.
  • a system can include a power cable that includes three conductors for multiphase power delivery to a multiphase electric motor, for example, three conductor members, where the power cable includes an information
  • transmission member which may include a signal cable (e.g., a wire or wires), a fiber optic cable, etc.
  • a member may be a conduit that may optionally include one or more optical fibers and/or one or more wires.
  • a conduit may be suitable for flow of fluid (e.g. , chemical injection, sampling, etc.).
  • an ESP power delivery system can include various components, including, in ascending order of a completion configuration: MLE(s), packer penetrators and/or POD penetrators; a power cable (e.g. , round or flat); and hanger penetrators.
  • the power cable can include a tube or conduit that includes one or more transmission lines.
  • a tube may be an integrated signal wire carrying tube that is disposed within the power cable.
  • a ESP power delivery system can include one or more devices that serve as an interface for transition of power delivery member through a piece or pieces of completion equipment.
  • Fig. 9 shows an example of a system 900 that includes a power source 904 (e.g., VSD, etc.) and an ESP 906 where power is conveyed to the ESP 906 at least in part via an integrated cable 910 and an integrated MLE 920.
  • a hanger 950 is fit with a hanger penetrator 955 and a packer 960 is fit with a packer penetrator 965.
  • Such penetrators can optionally include features to accommodate a transmission member (e.g. , for signal and/or information transmission).
  • the system 900 is also shown as including a pot head 930 that can provide for operatively coupling members to an ESP (e.g., motor and/or gauge).
  • an MLE can be of a flat configuration (e.g. , planar where members are substantially side-by-side).
  • an MLE may be configured to accommodate pot head features and an MLE can include, for example, copper conductors, copper insulation material, other insulation material, a barrier layer or layers, and armor.
  • conditions can vary with respect to conditions of an ESP motor and/or fluid flow via completion perforation, which may be driven at least in part by an ESP during ESP operation.
  • Fig. 10 shows an example of an MLE 1020 that has a substantially flat configuration where a casing 1021 surrounds members 1022-1 , 1022-2, 1022-3 and 1024.
  • the member 1024 can include a metallic tube that may carry a plurality of signal wires, for example, to support downhole tool communication.
  • the casing 1021 can be an armor casing made of a suitably durable material (e.g., composite, metal, alloy, etc.).
  • a signal tube can run substantially parallel to the three conductors and an armor layer or casing can be utilized to surround and bind them together.
  • a material 1026 see, e.g.
  • the casing 1021 may be a material that can surround the material 1026 and the member 1024.
  • an exterior layer 1028 e.g., armor, etc. may surround the casing 1021.
  • a tube may be utilized as part of a transmission member to facilitate sealing at one or more junctures.
  • a fitting or fittings may be utilized to seal one or more transmission fibers and/or wires that can be broken out of the tube.
  • transmission lines e.g. , one or more fibers and/or wires
  • Fig. 1 1 shows an example of a portion of a system 1 100 that includes an MLE 1 120 and a pot head 1 130.
  • the MLE 1 120 includes a relatively flat portion 1 126 that breaks out to extensions that are operatively coupled to the pot head 1 130.
  • Three of the extensions 1 122-1 , 1 122-2 and 1 122-3 are for multiphase power conductor members and another one of the extensions 1 124 is for a transmission member.
  • the pot head 1 130 includes receptacles for the extensions 1 122-1 , 1 122-2, 1 122-3 and 1 124.
  • the extension 1 124 can be operatively coupled to a gauge which may be coupled to an electric motor of an ESP that is powered by conductors of at least two of the extensions 1 122-1 , 1 122-2 and 1 122-3.
  • a pot head can include a plurality of receptacles for operatively coupling to extensions that may be other than extensions of multiphase power conductors for a multiphase electric motor.
  • the pot head 1 130 may include a right side receptacle and a left side receptacle, each for receiving a member such as a transmission member.
  • a cable and/or a MLE may be twisted, oriented in one of two orientations, an option may exist for coupling a single transmission member to one or more receptacles of a pot head.
  • the pot head 1 130 as including the right side receptacle 1 124 (in the view of Fig.
  • a motor lead extension may include a side member where that side member may be operatively coupled to either the right side receptacle or the left side receptacle depending on orientation.
  • a transmission member is mentioned as a type of member that is other than a multiphase power conductor member for a multiphase electric motor.
  • a transmission member may function to transmit signal, power, information or a combination thereof.
  • the pot head 1 130 may optionally include one or more sensors that can be operatively coupled to the transmission member via the extension 1 124.
  • information about the pot head e.g. , temperature, vibration, electrical charge, etc.
  • information relayed to the pot head e.g., from one or more sensors, etc.
  • may be communicated e.g., to surface equipment.
  • FIG. 1 1 various features are shown that may help to guide and/or retain members as they are separated for coupling to receptacles.
  • recesses may be included that can help position a member or members to avoid contact with other components (e.g. , casing walls, cables, etc.).
  • a pot head can include receptacles for multiphase power members and a receptacle for the transmission member where the receptacle for the transmission member is interior to the receptacles for the multiphase power members such that the transmission member is protected by the multiphase power members (e.g., the multiphase power members receptacles being at a greater radius from a longitudinal axis of a pot head compared to a receptacle for a transmission member).
  • one or more components may include a signal booster for a transmission member.
  • a pot head, a penetrator, etc. may include signal boosting circuitry that can boost a signal in one or more transmission lines.
  • signal boosting circuitry may provide for enhanced signal to noise for signals (e.g., downhole measurements, etc.) received by surface equipment.
  • a signal booster may be provided as a unit that can include a battery that can store power to boost a signal.
  • a signal booster unit may include a power generator that can generate power, for example, responsive to fluid flow, etc.
  • a receptacle of a pot head can include or be operatively coupled to signal boosting circuitry such that a connection is made to the circuitry upon receipt of a
  • transmission member e.g. , a coupling end
  • a signal booster may be an optical signal booster that can boost optical signals carried by one or more optical fibers.
  • a receptacle can include an optical signal booster.
  • a packer penetrator can be a component or components that serve as an interface between a well safety device and a power delivery system.
  • a packer can be utilized to form a seal against a well and to offer a solid barrier to downhole pressure.
  • an ESP cable can be passed through a sealing device such as a packer through utilization of one or more packer penetrators.
  • penetrators can be configured for three conductors of three members of a multiphase power delivery cable.
  • an additional member may be included in a cable, which may be a transmission member (e.g., for interfacing with a gauge signal fiber and/or wire, etc.).
  • a plug-in mode of attachment to packer connectors can be built into a packer.
  • Fig. 12 shows an example of a system 1200 that includes a packer 1260, packer connectors 1261 and packer penetrator connectors 1266.
  • a system can include an integrated cable, an integrated packer penetrator and a packer connector.
  • a system can include a packer connector, an integrated packer penetrator and an integrated MLE. For example, consider a packer that includes an integrated packer penetrator that can operatively couple members of an integrated cable to one side of the packer to members of an integrated MLE to another, opposing side of the packer.
  • Fig. 13 shows examples of power cables 1300 and 1310.
  • the power cable 1300 includes a casing 1301 , three power conductor members 1302-1 , 1302-2 and 1302-3 and one transmission member 1305.
  • the power cable 1310 includes a casing 131 1 , three power conductor members 1312-1 , 1312-2 and 1312-3 and one transmission member 1315.
  • the transmission member 1315 may be about the same diameter as the conductor members 1312-1 , 1312-2 and 1312-3.
  • Fig. 14 shows examples of power cables 1400 and 1410.
  • the power cable 1400 includes a casing 1401 , three power conductor members 1402-1 , 1402-2 and 1402-3 and one transmission member 1405.
  • the power cable 1410 includes a casing 141 1 , three power conductor members 1412-1 , 1412-2 and 1412-3 and one transmission member 1415.
  • the transmission member 1415 may be about the same diameter as the conductor members 1412-1 , 1412-2 and 1412-3.
  • conductors of a cable may be arranged in a triad fashion, for example, substantially equidistantly placed from each other to deliver power to an installation that may be disposed in a well.
  • a cable can include a signal tube with one or more transmission lines.
  • such a tube may include a twisted-wire pair of conductors that may be dedicated to establishing a communication mode that can be independent of power cable conductors (e.g., without transmitting information signals via one or more multiphase conductors of a power cable).
  • a tube e.g., a signal tube
  • a tube can be of a selected diametric span and suitably geometrically arranged, for example, depending on an application.
  • a tube can include air space or may be encapsulated.
  • one or more transmission lines may be positioned within a tube via a spacer or spacers.
  • Fig. 15 shows an example of a system 1500 that includes two integrated cables 1510-1 and 1510-2, a hanger 1550 and a hanger penetrator 1555 that penetrates the hanger 1550 (e.g. , axially) and that operatively couples the two integrated cables 1510-1 and 1510-2.
  • a hanger penetrator can serve as an interface between a completion hanger and a power delivery system.
  • Completion hangers can define tie-off points on which an ESP, including the completion tubing, may be suspended within a well.
  • a hanger may be supported by casing and act to seal a wellbore.
  • power can be conveyed through the hanger via a hanger penetrator.
  • a hanger penetrator can be utilized to operatively couple the one or more transmission lines of one cable to one or more corresponding transmission lines of another cable.
  • cables operatively coupled via one or more penetrators may be referred to as a single power cable or, for example, a single integrated cable.
  • a penetrator can include a plug-in side and a pig-tail side.
  • a pig-tail may be a length of one or more fibers and/or one or more wires.
  • a penetrator can include a change in format, for example, to couple an integrated round cable to an integrated flat MLE.
  • a penetrator can include signal boosting circuitry.
  • a hanger penetrator can include signal boosting circuitry.
  • signal boosting may help to address a substantial step-out distance.
  • a hanger penetrator may include a power supply and/or include a connection to a power supply where such power can be utilized to power signal boosting circuitry.
  • a transmission line may be routed through a housing of an ESP and/or along an outer surface of a housing of an ESP.
  • a transmission line may run through slots of a stator of a motor.
  • a transmission line may couple directly to a gauge via a connector of a gauge.
  • a transmission line may be set in a groove of a housing.
  • a transmission line may be strapped to a housing.
  • a transmission line may be a wire transmission line or a fiber optic transmission line.
  • signal boosting circuitry can be coupled to a wire transmission line to boost wire- based transmissions or coupled to a fiber optic transmission line to boost optic- based transmissions.
  • a wire transmission line may carry electrical power to power circuitry of a gauge and/or other circuitry (e.g. , signal booster circuitry).
  • a wire transmission line e.g., or lines
  • a power cable can be susceptible to ground faults, where the conductors of the power cable are utilized for transmission, transmission can be at risk (e.g. , loss of downhole readings in the event of an electrical fault, in spite of a fully functional gauge).
  • a transmission member exists in an integrated power cable as a path for telemetry, reliability may be improved, for example, where an electrical fault event occurs.
  • An integrated approach can help to reduce risk of damage when compared to a separate transmission line approach and can reduce amount of surface equipment (e.g., rig site equipment). For example, where an integrated approach is taken, a single reel may be utilized rather than two separate reels at a rig site.
  • an integrated approach may be utilized for subsea, offshore or other types of applications.
  • Fig. 16 shows an example of a system 1600 that includes a dedicated link 1615 and a multiphase link 1610 that, for example, link downhole circuitry 1620 to one or more surface units.
  • the circuitry 1620 includes one or more analog to digital converters (ADCs) 1622, a data acquisition processor 1640, a power modulation block 1650 for the multiphase link 1610 and a telemetry block 1670 for the dedicated link 1615.
  • ADCs analog to digital converters
  • a data acquisition processor 1640 for the multiphase link 1610
  • a power modulation block 1650 for the multiphase link 1610
  • a telemetry block 1670 for the dedicated link 1615.
  • one or more sensors 1690 are shown as being operatively coupled to the circuitry 1620, noting that a sensor may output a digital signal and/or may output an analog signal.
  • a system such as the system 1600 may include circuitry suitable for SCADA.
  • a system such as the system 1600 may include circuitry that can implement a MODBUSTM protocol.
  • a system may operate as a MODBUSTM protocol terminal.
  • a system such as the system 1600 may include one or more busses, ports, etc.
  • a system such as the system 900 may include RS232 and/or RS485 capabilities (e.g. , for communication of information).
  • Fig. 16 also shows a power supply block 1605, which may be operatively coupled to the multiphase link 910, for example, to a wye point of an electric motor of an ESP where DC power may be available as "injected" into a multiphase power cable (e.g., via a choke, etc.).
  • the power supply block 905 may be operatively coupled to one or more capacitors, one or more batteries and/or one or more other power storage components.
  • an ESP can include a downhole gauge that can transmit data over electrical conductors of multiphase power lines (e.g., AC power lines) that are used to operate an electric motor of the ESP.
  • multiphase power lines e.g., AC power lines
  • a multiphase transmission mode can communicate via a common mode signal type, for example, signals can be referenced with respect to power cable metal or alloy armor as a ground (e.g., as in electrical contact with surrounding fluid, formation, casing, etc.).
  • noise may appear as associated with changes in ground, ground loops, etc. (e.g., consider impact on signal to noise ratio).
  • data from a gauge can be modulated over high frequency signals and sent through the three power line cables (e.g. , via MLEs, etc.).
  • a multiphase transmission mode may be a one-way communication mode (e.g., simplex) where a gauge keeps sending data at regular intervals, for example, as may be preset (e.g., fixed) in the gauge prior to
  • a multiphase transmission mode may be susceptible to issues associated with grounding.
  • a multiphase power cable may be in a normal state or in a ground fault state.
  • One or more ground faults may occur for any of a variety of reasons. For example, wear of internal and/or external components of a multiphase power cable may cause a ground fault for one or more of its conductors (e.g., where a conduction path exists between a conductor and ground).
  • a ground fault occurs, power at a wye point of a multiphase electric motor may be altered.
  • DC power is provided at a wye point (e.g. , injected via a choke)
  • a ground fault occurs, current at the wye point may be unbalanced and alternating.
  • Circuitry associated with a gauge may or may not be capable of deriving power from an unbalanced wye point and, further, may or may not be capable of data transmission via an unbalanced wye point.
  • a dedicated transmission line or lines may provide for a dedicated transmission mode with maximum data rates in excess of about 12 bps, which may be a maximum of a multiphase transmission mode implemented via electric motor conductors of a multiphase power cable.
  • a dedicated transmission mode with maximum data rates in excess of about 12 bps, which may be a maximum of a multiphase transmission mode implemented via electric motor conductors of a multiphase power cable.
  • implementation of a dedicated transmission mode may provide for transmission of vibration data. Such data may be suitable for monitoring ESP performance.
  • one or more ESP components may vibrate in a manner due to unbalance of phases supplied to an electric motor of the ESP.
  • one or more vibration sensors e.g., accelerometer-based, etc.
  • a gauge that includes one or more vibration sensors may transmit sensed vibration data via one or more transmission lines to equipment for analysis, which may be, for example, surface equipment.
  • a method may include adjusting operation of a gauge and/or associated circuitry, for example, to reduce risk of damage, to reduce risk of transmission of unreliable data, to reduce risk of insufficient power supply, etc.
  • a signal may be transmitted in response that acts to prohibit transmission of information via a multiphase transmission mode.
  • a signal may be transmitted in response that acts to at least electrically decouple one or more circuits from a wye point of an electric motor that is
  • an alternative power supply or power source may be activated to supply circuitry, optionally including one or more sensors, with an acceptable amount of power for a particular amount of time.
  • one or more capacitors, batteries, etc. may be activated as a power source or power sources.
  • such an approach may supply power sufficient for transmission of information via a dedicated transmission mode (e.g. , via one or more wires, one or more optical fibers, etc.).
  • the circuitry 1620 may provide for transmission of data via the multiphase link 1610 and via the dedicated link 1615 in a substantially simultaneous manner. For example, both links may transmit data at the same time. As an example, the multiphase link 1610 may transmit data at a lower rate than the dedicated link 1615. As an example, the multiphase link 1610 may transmit data at a lower resolution than the dedicated link 1615. As an example, circuitry such as the circuitry 1620 may be implemented to control how and when data are transmitted. For example, a method can include switching between various operating modes, for example, consider switching to a high resolution mode via the dedicated link 1615 for a period of time.
  • the method may include transmitting data via the dedicated link 1615 for a period of time that is sufficient to transmit enough data that can be analyzed to discern a particular frequency, which may be a vibrational frequency (e.g. , a fraction or a multiple of a shaft speed frequency).
  • a vibrational frequency e.g. , a fraction or a multiple of a shaft speed frequency
  • a system can include a dedicated telemetry line (e.g., a twisted pair) that extends from a gauge to surface equipment, which may be implemented in a manner that decouples telemetry via the dedicated telemetry line from power transmission to an electric motor.
  • a dedicated telemetry line e.g., a twisted pair
  • a system that includes equipment to implement a multiphase transmission mode and a dedicated transmission mode may be referred to as a hybrid system that can optionally implement a hybrid telemetry scheme (e.g., where data may be sent on both links, optionally simultaneously).
  • a hybrid system may be characterized by a low bandwidth mode via a power cable and a high bandwidth mode via one or more transmission lines (e.g., separate from conductors that provide multiphase power to an electric motor).
  • a hybrid system may offer some amount of redundancy.
  • Such a system may optionally utilize conductors of a multiphase power cable as a redundancy layer that can be utilized in case one or more dedicated transmission lines that can function for high bandwidth telemetry suffer a malfunction.
  • such a system may operate to handle sensor data (e.g. , acquired by one or more ADCs) and to send at least a portion of the sensor data via the circuitry 1620 (e.g., a data acquisition/processing module, etc.) to two different types of telemetry systems, optionally simultaneously.
  • the circuitry 1620 e.g., a data acquisition/processing module, etc.
  • surface equipment may record data from both telemetry systems, optionally simultaneously.
  • a hybrid ESP telemetry system can include equipment for a power modulating telemetry scheme and a dedicated telemetry scheme (e.g. , via one or more dedicated transmission lines).
  • Fig. 17 shows an example of a system 1700 that includes an ADC 1722, a data acquisition processor 1740, a power modulation block 1750, a telemetry block 1770 and a sensor 1790.
  • the telemetry block 1770 may include an optical signal driver 1772 and/or an electrical signal driver 1774.
  • the sensor 1790 may output an analog signal that can be converted to a digital signal via the ADC 1722.
  • the digital signal may be processed via the data acquisition processor 1740 and transmitted to the telemetry block 1770 and/or the power modulation block 1750.
  • the data acquisition processor 1740 may adjust data rate, resolution, time, etc. , as to the received digital signal. For example, the data acquisition processor 1740 may generate a digital data signal for the power modulation block 1750 and a different digital data signal for the telemetry block 1770. As an example, the data acquisition processor 1740 may determine whether the sensor 1790 is a vibration sensor associated with vibration that occurs on a particular time scale or another type of sensor associated with a physical
  • the data acquisition processor 1740 may select a transmission mode based on associated time scale.
  • vibration data may be sent via the telemetry block 1770 as it can have a maximum data rate that exceeds a maximum data rate of the power modulation block 1750.
  • Fig. 18 shows an approximate schematic diagram of an optical signal driver 1872.
  • a driver includes at least one optical element such as, for example, a light emitting diode (LED) that can be optically coupled to one or more optical fibers.
  • the optical signal driver 1872 can receive digital information (e.g. , transistor-transistor logic, TTL) and transform such information to optical emission pulses (e.g., for transmission via one or more optical fibers).
  • digital information e.g. , transistor-transistor logic, TTL
  • optical emission pulses e.g., for transmission via one or more optical fibers.
  • an ESP can include an optical signal driver and/or an optical signal decoder.
  • at least a portion of an ESP may include an optical fiber, optical fibers, an optical waveguide, optical waveguides, etc. that span at least a portion of an axial length of an ESP.
  • data may be transmitted via one or more of such components.
  • an ESP can include an optical signal driver, one or more optical signal carriers and an optical signal decoder.
  • signals generated at a gauge may be transmitted past "noisy" portions of an electrical motor of an ESP as optical signals that are less immune to such noise when compared to electrical signals carried by an electrical conductor or conductors.
  • an ESP can include an optical signal driver, one or more optical signal carriers and an optical signal decoder.
  • signals generated at surface equipment may be transmitted to a gauge of an ESP past "noisy" portions of an electrical motor of the ESP as optical signals that are less immune to such noise when compared to electrical signals carried by an electrical conductor or conductors.
  • Fig. 19 shows an example arrangement 1901 as to a power cable 191 1 , a motor 1915, a wye point 1925, circuitry 1950 and one or more sensors 1990.
  • the circuitry 1950 may be operatively coupled to the one or more sensors 1990.
  • the circuitry 1950 includes an electrical connection to a wye point of a motor, a transformer 1951 , a DC-DC converter 1952, a rectifier 1955, a telemetry driver 1956 and a controller 1958.
  • the circuitry 1950 may include various components such as diodes (D), Zener diodes (Z), capacitors (C), inductors (L), windings (W), resistors (R), etc.
  • the Zener diodes as an example, the Zener diode Z1 may be optional.
  • the circuitry 1950 may operate in State N (normal) or a State GF (ground fault), for example, with respect to the wye point.
  • a primary winding (W1 ) of the transformer 1951 acts to reduce detrimental impact of normal wye point unbalance and allows a DC power signal to proceed to the DC-DC converter 1952.
  • the DC-DC converter 1952 can convert the DC power signal and provide one or more converted DC power signals to the telemetry driver 1956, the controller 1958 and the one or more sensors 1960.
  • the primary winding (W1 ) of the transformer 1951 acts to reduce detrimental impact of the abnormal wye point unbalance and further cooperates with the secondary winding (W2) to allow the rectifier 1955 to derive a suitable DC power signal.
  • a positive DC tap point of the rectifier 1955 is electrically connected to the DC-DC converter 1952.
  • unbalance voltage of alternating current at the wye point can be stepped down via the transformer 1951 and then rectified via the rectifier 1955 to supply a suitable DC power signal to the DC-DC converter 1952, which may supply one or more DC power signals to the telemetry driver 1956, the controller 1958 and the one or more sensors 1960.
  • the rectifier 1955 may supply one or more DC power signals to the telemetry driver 1956, the controller 1958 and the one or more sensors 1960.
  • the rectifier 1955 may supply one or more DC power signals to the telemetry driver 1956, the controller 1958 and the one or more sensors 1960.
  • the 1955 may provide a DC power signal or signals suitable for powering the telemetry driver 1956, the controller 1958 or the one or more sensors 1960 (e.g., without reliance on the DC-DC converter 1952).
  • the telemetry driver 1956 includes an electrical connection to the wye point 1925.
  • Sensed information e.g. , data
  • the encoded information may be provided to the telemetry driver
  • modulation circuitry provides for signal modulation to carry the encoded information for transmission via the wye point of an electric motor.
  • the telemetry driver 1956 may alternatively or additionally receive information from the wye point. Where such information is modulated, encoded, or modulated and encoded, the circuitry 1950 may provide for demodulation, decoding or demodulation and decoding.
  • the telemetry driver 1956 may transmit information to a wye point of an electric motor at one or more frequencies (e.g., approximately 10 kHz or more) higher than a power supply frequency of power supplied to drive the electric motor, which may be less than approximately 100 Hz and, for example, in a range of about 30 Hz to about 90 Hz.
  • an electric motor may be supplied with power having a frequency of about 60 Hz.
  • transmitted data signals may be modulated using multichannel frequency shift keying (FSK), orthogonal frequency division multiplexing (OFDM), or phase shift keying (PSK).
  • FSK frequency shift keying
  • OFDM orthogonal frequency division multiplexing
  • PSK phase shift keying
  • telemetry may occur at one or more frequencies, which may include one or more frequencies greater than about 5 kHz, one or more frequencies greater than about 10 kHz, one or more frequencies greater than about 20 kHz, and/or one or more frequencies greater than about 30 kHz.
  • telemetry may be implemented using two frequencies, three frequencies, four frequencies, five frequencies or more than five frequencies.
  • an LC circuit may be formed by the capacitor C1 and the inductor L1 , for example, as disposed between the wye point and the telemetry driver 1956.
  • Such an LC circuit may be tuned, for example, for downhole signal transmissions, uphole signal transmission, etc.
  • one or more components in the circuitry 1950 may act to divide voltage, for example, with respect to paths electrically coupled to the wye point. For example, in a ground fault scenario, a high voltage (e.g., elevated voltage) may exist at the wye point.
  • an LC circuit may be part of a voltage divider to help ensure that a voltage does not exceed a voltage level that may risk damaging circuitry (e.g. , the telemetry driver 1956).
  • the capacitor C1 may be tuned with respect to a voltage level as to dividing voltage at the wye point, for example, where the voltage at the wye point may become elevated due to a ground fault as to one or more of the phases of the multiphase power conduction system.
  • circuitry may include voltage divider components that divide voltage with respect to a wye point where a telemetry driver is electrically coupled to the wye point along one branch and where circuitry such as a transformer, a DC-DC converter, etc. is electrically coupled to the wye point along another branch.
  • Fig. 20 shows an example of a system 2000, which includes a power cable 201 1 , motors 2015, a respective wye point of the wye points 2025, communication circuitry 2030, a choke 2040, a choke 2045, telemetry circuitry 2070 (e.g., for one or more dedicated transmission lines), a VSD unit and/or switchboard (SB) 2072, and a 3-phase step- up transformer 2074.
  • Fig. 20 also shows an alternative arrangement 2041 , for example, with a single phase choke that can connect to a wye point of the transformer 2074.
  • the motor 2015 may be operatively coupled to the power cable 201 1 .
  • the motors 2015 may include an associated sensor unit that is operatively coupled to the wye point 2025.
  • data transmitted via the wye point 2025 of the motor 2015 may be carried by the power cable 201 1 .
  • the choke 2040 includes electrical connections to each of the conductors for the 3-phase power. Such redundancy can allow the choke 2040 to receive modulated data signals provided to the wye point 2025, for example, regardless of the state of the individual conductors that electrically connect to the wye point 2025 (e.g. , assuming at least one non- faulted conductor).
  • the wye point 2025 may receive modulated data signals via circuitry such as, for example, the circuitry 1950 of Fig. 19, etc.
  • the choke 2040 includes an electrical connection to the communication circuitry 2030.
  • the communication circuitry 2030 may receive modulated signals from the choke 2040 and provide for conversion of such signals from analog to digital, provide for demodulation of such signals, provide for decoding of such signals or any combination thereof.
  • the communication circuitry 1330 may include data handling circuitry, for example, to further process data derived from signals transmitted via the choke 2040. Such further processing may include formatting, analyzing, etc. As to formatting, the data handling circuitry may provide for formatting data according to one or more data transmission protocols (e.g., Internet, proprietary, etc.).
  • the communication circuitry 2030 may be operatively coupled to the telemetry circuitry 2070.
  • Such circuitry may be operatively coupled to one or more transmission lines such as, for example, one or more dedicated transmission lines that can carry information generated at a gauge operatively coupled to the motor 2015.
  • the communication circuitry 2030 and/or the telemetry circuitry 2070 may optionally be linked to equipment shown in the examples of Figs. 1 , 2 and 3.
  • the communication circuitry 2030 and/or the telemetry circuitry 2070 may be linked to the network 125 of Fig. 1 or linked to the network 201 of Fig. 2 or to the sensor unit 360 of Fig. 3.
  • an implementation of the system 2000 of Fig. 20 may be in a geologic environment such as the geologic environment 120 and/or the geologic environment 140 of Fig. 1 .
  • the communication circuitry 2030 and/or the telemetry circuitry 2070 may include circuitry for digital signal processing (DSP). As an example, the communication circuitry 2030 and/or the telemetry circuitry 2070 may provide for handling signals modulated using frequency based and/or time based techniques. As an example, the communication circuitry 2030 and/or the telemetry circuitry 2070 may include circuitry for multichannel frequency shift keying (FSK), orthogonal frequency division multiplexing (OFDM), and/or phase shift keying (PSK). For example, the communication circuitry 2030 and/or the telemetry circuitry 2070 may include circuitry for demodulating signals modulating using one or more of FSK, OFDM, PSK, etc.
  • FSK frequency shift keying
  • OFDM orthogonal frequency division multiplexing
  • PSK phase shift keying
  • the communication circuitry 2030 and/or the telemetry circuitry 2070 may include circuitry for demodulating signals modulating using one or more of FSK, OFDM, PSK, etc.
  • the communication circuitry 2030 or other circuitry may provide for sampling each phase line of a 3-phase power cable individually for purposes of extracting data.
  • the choke 2040 may include a multiplexer controllable by the communication circuitry 2030 to allow the communication circuitry 2030 to select individual lines or optionally combinations of any two lines. In such a manner, if a ground fault does occur, the communication circuitry 2030 may provide for selecting the best individual line or combination of lines in an effort to improve performance (e.g., demodulation, decoding, etc.).
  • the system 2000 may include switching to the telemetry circuitry 2070 for purposes of data transmission, if not already implemented, and/or switching off the communication circuitry 2030 for purposes of data transmission, for example, where the telemetry circuitry 2070 has been implemented.
  • downhole equipment may provide for transmission of a test signal, which may optionally be modulated, encoded, etc.
  • the communication circuitry 2030 may control a multiplexer to test the quality of the test signal on each of line of a 3-phase power cable or combinations of lines of a 3- phase power cable (e.g. , where the test signal or information carried therein is known). Based on the quality (e.g., per one or more quality control metrics), the communication circuitry 2030 may control the multiplexer to receive signals via one or more lines of the 3-phase power cable.
  • a test may optionally provide information germane as to power quality, transmission quality, etc., for providing DC power to one or more pieces of downhole equipment (e.g.
  • the system 2000 may include switching to the telemetry circuitry 2070 for purposes of data transmission, if not already implemented, and/or switching off the communication circuitry 2030 for purposes of data transmission, for example, where the telemetry circuitry 2070 has been implemented.
  • FIG. 21 shows an example of an architecture 2101 , an example of an architecture 2107 and an example of an interface card 2109.
  • the architecture 2101 may implement a MODBUSTM specification. For example, consider an application layer 2103 that links to a master / slave layer 2105.
  • a master-slave type of system can include a node (the master node) that issues commands to one of the slave nodes and processes responses.
  • a slave node may transmit data upon receipt of a request from the master node.
  • MODBUSTM transmission over serial line systems may use one or more types of physical interfaces (e.g. , RS485, RS232, etc.).
  • RS485 TIA/EIA-485
  • RS485 four-wire interface may be implemented.
  • TIA/EIA-232-E (RS232) serial interface which may be used as an interface (e.g., shorter point to point communication).
  • an optical signal driver and/or an optical signal decoder may be implemented in an architecture.
  • communication circuitry 2130 as including one or more interfaces 2132 (e.g. , RS485 and/or RS232 interfaces), which may be operatively coupled to a gateway 2134.
  • the gateway 2134 may be operatively coupled to circuitry such as circuitry of the interface card 2109.
  • the architecture 2107 includes a dedicated line or bus, which may be operatively coupled to the communication circuitry 2130, the one or more interfaces 2132 and/or the gateway 2134.
  • the interface card 2109 can include one or more TCP/I P ports, one or more network I/O ports, etc.
  • the interface card 2109 includes a multiplexer, a processor and memory.
  • the multiplexer may be operable via execution of instructions stored in memory (e.g., flash, SDRAM, disk on chip, etc.) that may be executable by the processor.
  • the multiplexer may be controlled to receive signals via the one or more ports.
  • the interface card 2109 may include a backplane bus, for example, to communication information received via the one or more ports.
  • an interface card may be part of a controller.
  • the UNICONNTM controller may include an interface card (e.g., or interface cards) that may be configured to receive signals from a plurality of transmission links.
  • a system may include an INSTRUCTTM acquisition and control unit that includes one or more interface cards that may be configured to receive signals from a plurality of transmission links.
  • a MODBUSTM system may be implemented where two conductors (e.g. , a "two-wire" configuration ) may form a balanced twisted pair, on which bi-directional data may be transmitted (e.g., consider a bit rate of about 9600 bits per second).
  • a gateway may be included in a system.
  • MODBUSTM TCP/IP is a MODBUSTM protocol with a TCP wrapper.
  • a gateway may be implemented to convert from a current physical layer (RS232, RS485 or other) to Ethernet and, for example, to convert MODBUSTM protocol to MODBUSTM TCP/IP.
  • Fig. 22 shows an example of a method 2200 that includes a
  • transmission block 2202 for transmitting information (e.g., multiphase transmission mode information), a transmission block 2204 for transmitting information (e.g., dedicated transmission mode information) and a reception block 2206 for receiving information.
  • the reception block 2206 can provide at least a portion of received information to one or more example processes 2220, 2230 and 2240.
  • the example process 2220 includes a comparison block 2222 for comparing information such as multiphase transmission mode information and dedicated transmission mode information, an assessment block 2224 for assessing one or more cables and a control block 2226 for controlling transmission of information based at least in part on the assessing.
  • the example process 2230 includes an analysis block 2232 for analyzing information such as multiphase transmission mode information, an analysis block 2234 for analyzing information such as dedicated transmission mode information, and a control block 2226 for controlling one or more processes based at least in part on the one or more analyzings (e.g. , analyses).
  • an analysis block 2232 for analyzing information such as multiphase transmission mode information
  • an analysis block 2234 for analyzing information such as dedicated transmission mode information
  • a control block 2226 for controlling one or more processes based at least in part on the one or more analyzings (e.g. , analyses).
  • the example process 2240 includes a process block 2242 for processing information, a consolidation block 2244 for consolidating information and a storage block 2246 for storing information (e.g. , as consolidated).
  • Fig. 23 shows example plots 2300 of information including intake fluid pressure to an ESP, intake fluid temperature to an ESP, electric motor temperature of an ESP and vibration of an ESP.
  • a time scale of the order of days is shown where vibration information may be available with respect to a time scale of milliseconds.
  • a graphical user interface may include a control that allows for selection of a time or times and zooming in to a finer time scale such as zooming from days, hours, minutes, seconds, etc. , to, for example, milliseconds.
  • vibration data may be amplitude versus time data, acceleration versus time data, velocity versus time data, frequency data, etc.
  • a zoomed in section shows a waveform with respect to milliseconds that may be analyzed to discern a plurality of frequencies, indicated as frequencies f1 , f2 and f3.
  • frequencies f1 , f2 and f3 may be a lower frequency and f3 a higher frequency while f2 may be a frequency between f1 and f3.
  • these frequencies may correspond to different types of vibrations.
  • One or more of such vibrations may be associated with a particular phenomenon.
  • the electric motor temperature exhibits a peak, which was associated with scaling of a pump driven by the electric motor. Such a peak may trigger an alarm, for example, as the temperature rose from about 152 degrees F to about 176 degrees F (e.g., about a 25 degree F difference).
  • an ESP may be subject to a treatment such as, for example, a chemical treatment.
  • a chemical treatment e.g., acid
  • vibration data may be analyzed to determine what may be a cause of an ESP related issue.
  • vibration data may indicate types of vibration and/or associated components that may be vibrating.
  • a treatment and/or control scheme may be selected and/or tailored based at least in part on vibration data analysis.
  • vibration data may help to exclude and/or include components and/or phenomena, which, in turn, may facilitate mitigation of one or more issues or potential issues.
  • an alarm may be associated with an alarm time or time window.
  • vibration data for an alarm time or a time window may be accessed and analyzed where, for example, the vibration data is of a finer resolution than temperature data, pressure data, etc., which may have triggered an alarm.
  • the vibration data may be or have been transmitted via a dedicated transmission line or lines while the temperature data may be or have been transmitted via one or more conductors of a multiphase power cable.
  • a sensor may be or include an accelerometer and/or a velocity sensor and/or a displacement sensor (e.g., for sensing amplitude versus time, etc.).
  • an analysis can include performing a Fourier transform (e.g., FFT) on sensor data to convert time domain data to a frequency domain.
  • FFT Fourier transform
  • vibration parameters may include frequency and/or amplitude.
  • a method can include comparing frequency to rotational speed (e.g. , estimated rotational speed, etc.) of an electric motor.
  • information in a frequency domain may be associated with one or more known or possible issues (see, e.g., Table 2).
  • transmission mode e.g. , bits per minute
  • transmission quality e.g., bit depth
  • Fig. 24 shows an example of a system 2400, an example plot 2410 of measurements versus time for a gauge 2450 operatively coupled to an ESP and an example plot 2430 of measurements versus time for the gauge 2450 as transmitted via a dedicated transmission mode.
  • the system 2400 includes an electric submersible pump 2412 that includes an electric motor 2415 with a wye point and the gauge 2450 coupled to the wye point via a wye point interface 2451 and another interface 2452 that couples the gauge 2450 to one or more dedicated transmission lines.
  • an electric submersible pump 2412 that includes an electric motor 2415 with a wye point and the gauge 2450 coupled to the wye point via a wye point interface 2451 and another interface 2452 that couples the gauge 2450 to one or more dedicated transmission lines.
  • the system 2400 includes a multiphase power cable 241 1 operatively coupled to a power supply 2410 and operatively coupled to the electric motor 2415 of the electric submersible pump 2412 and communication circuitry 2430 operatively coupled to the multiphase power cable 241 1 where the communication circuitry 2430 receives signals carried by the multiphase power cable 241 1 as transmitted by the gauge 2450 of the electric submersible pump 2412 and as transmitted by the gauge 2450 of the electric submersible pump 2412 via the interface 2452.
  • intake pressures may correspond to conditions seen by the ESP 2412. As shown, the motor temperature for the motor 2415 of the ESP 2412 experiences a spike, which may indicate an issue as to that ESP 2412. As an example, higher resolution data as to temperature, pressure, etc., may be available as transmitted via the interface 2452, which is illustrated in the plot 2430 as intake pressure.
  • a system can include an electric submersible pump that includes a multiphase electric motor that includes a wye point; and a gauge operatively coupled to the wye point of the electric motor and operatively coupled to a transmission line where the gauge includes data transmission circuitry operatively coupled to the wye point and data transmission circuitry operatively coupled to the transmission line.
  • the gauge can include a controller that controls transmission of information via the data transmission circuitry operatively coupled to the wye point and that controls transmission of information via the data transmission circuitry operatively coupled to the transmission line.
  • the controller can include a simultaneous transmission mode that transmits information via the wye and that transmits information via the transmission line simultaneously.
  • a maximum net bit rate associated with data transmission circuitry operatively coupled to a transmission line can exceed a maximum net bit rate associated with data transmission circuitry operatively coupled to a wye point of an electric motor.
  • data transmission circuitry operatively coupled to a transmission line can transmit vibration sensor data.
  • a gauge can include one or more vibration sensors.
  • data transmission circuitry operatively coupled to a wye point can transmit temperature data and pressure data.
  • a gauge can include one or more temperature sensors and/or one or more pressure sensors.
  • a gauge can include one or more batteries.
  • a gauge can include power circuitry that derives electrical power via a wye point of an electric motor.
  • a power cable can be a multiphase power cable where, for example, a transmission line is disposed at least in part within the multiphase power cable.
  • a transmission line can be or include a twisted pair of wires.
  • a transmission line can be or include an optical fiber.
  • a wye point may be electrically connected to a connector of the multiphase electric motor.
  • a transmission line can be electrically connected to a connector of a gauge.
  • a transmission line can be electrically connected to a connector of a multiphase electric motor and isolated from multiphase conductors.
  • a multiphase electric motor can include a housing that includes a connector where a transmission line can be connected to the connector.
  • a system can include an electric submersible pump that includes an electric motor; a gauge operatively coupled to the electric
  • the cable can include a substantially round profile (e.g., cross-sectional profile) and the motor lead extension can include a
  • substantially flat profile e.g. , cross-sectional profile
  • a penetrator can include signal boosting circuitry that boosts signals carried by a signal transmission line.
  • the penetrator may include a battery or batteries, which may optionally be rechargeable.
  • a signal transmission line may optionally be switched to carry power to recharge a rechargeable battery of a penetrator.
  • a penetrator can be a packer penetrator.
  • a penetrator can be a hanger penetrator.
  • one or more methods described herein may include associated computer-readable storage media (CRM) blocks.
  • Such blocks can include instructions suitable for execution by one or more processors (or cores) to instruct a computing device or system to perform one or more actions.
  • a computer- readable storage medium is non-transitory and not a carrier signal.
  • one or more computer-readable media may include computer-executable instructions to instruct a computing system to output information for controlling a process.
  • such instructions may provide for output to sensing process, an injection process, drilling process, an extraction process, an extrusion process, a pumping process, a heating process, etc.
  • Fig. 25 shows components of a computing system 2500 and a networked system 2510.
  • the system 2500 includes one or more processors 2502, memory and/or storage components 2504, one or more input and/or output devices 2506 and a bus 2508.
  • instructions may be stored in one or more computer-readable media (e.g., memory/storage components 2504). Such instructions may be read by one or more processors (e.g., the processor(s) 2502) via a communication bus (e.g., the bus 2508), which may be wired or wireless.
  • the one or more processors may execute such instructions to implement (wholly or in part) one or more attributes (e.g. , as part of a method).
  • a user may view output from and interact with a process via an I/O device (e.g., the device 2506).
  • a computer-readable medium may be a storage component such as a physical memory storage device, for example, a chip, a chip on a package, a memory card, etc.
  • components may be distributed, such as in the network system 2510.
  • the network system 2510 includes components 2522- 1 , 2522-2, 2522-3, . . . 2522-N.
  • the components 2522-1 may include the processor(s) 2502 while the component(s) 2522-3 may include memory accessible by the processor(s) 2502.
  • the component(s) 2502-2 may include an I/O device for display and optionally interaction with a method.
  • the network may be or include the Internet, an intranet, a cellular network, a satellite network, etc.

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

Abstract

L'invention concerne un système, qui peut comprendre une pompe électrique submersible qui comprend un moteur électrique multiphasé qui comprend un point de connexion en étoile ; et un dispositif de mesure couplé de manière fonctionnelle au point de connexion en étoile du moteur électrique et couplé de manière fonctionnelle à une ligne de transmission, le dispositif de mesure comprenant des circuits de transmission de données couplés de manière fonctionnelle au point de connexion en étoile et des circuits de transmission de données couplés de manière fonctionnelle à la ligne de transmission.
PCT/US2016/028767 2016-04-22 2016-04-22 Système de télémétrie hybride à pompe submersible électrique WO2017184158A1 (fr)

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USD910465S1 (en) 2019-04-29 2021-02-16 Cornell Pump Company Monitoring device enclosure
US11622685B2 (en) 2019-04-29 2023-04-11 Cornell Pump Company LLC Remote equipment monitoring system
WO2023150102A3 (fr) * 2022-02-01 2023-09-14 Baker Hughes Oilfield Operations Llc Sonde thermique pour extension de conducteur de moteur

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US8833441B2 (en) * 2009-05-18 2014-09-16 Zeitecs B.V. Cable suspended pumping system
US20150029036A1 (en) * 2013-07-28 2015-01-29 Saudi Arabian Oil Company Systems and methods for ground fault immune data measurement systems for electronic submersible pumps
WO2015065930A1 (fr) * 2013-10-29 2015-05-07 Schlumberger Canada Limited Transmission de signal d'unités de détection multiples par câble d'alimentation
US20160069179A1 (en) * 2014-09-09 2016-03-10 Baker Hughes Incorporated Systems and Methods for Double Data Rate Communication Via Power Cable

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US7857060B2 (en) * 2008-10-10 2010-12-28 Baker Hughes Incorporated System, method and apparatus for concentric tubing deployed, artificial lift allowing gas venting from below packers
US8833441B2 (en) * 2009-05-18 2014-09-16 Zeitecs B.V. Cable suspended pumping system
US20150029036A1 (en) * 2013-07-28 2015-01-29 Saudi Arabian Oil Company Systems and methods for ground fault immune data measurement systems for electronic submersible pumps
WO2015065930A1 (fr) * 2013-10-29 2015-05-07 Schlumberger Canada Limited Transmission de signal d'unités de détection multiples par câble d'alimentation
US20160069179A1 (en) * 2014-09-09 2016-03-10 Baker Hughes Incorporated Systems and Methods for Double Data Rate Communication Via Power Cable

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Publication number Priority date Publication date Assignee Title
USD910465S1 (en) 2019-04-29 2021-02-16 Cornell Pump Company Monitoring device enclosure
US11622685B2 (en) 2019-04-29 2023-04-11 Cornell Pump Company LLC Remote equipment monitoring system
WO2023150102A3 (fr) * 2022-02-01 2023-09-14 Baker Hughes Oilfield Operations Llc Sonde thermique pour extension de conducteur de moteur
US11994132B2 (en) 2022-02-01 2024-05-28 Baker Hughes Oilfield Operations Llc Thermal probe for motor lead extension

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