WO2015020645A1 - Surveillance d'un dispositif de production de puits par détection à fibre optique - Google Patents

Surveillance d'un dispositif de production de puits par détection à fibre optique Download PDF

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Publication number
WO2015020645A1
WO2015020645A1 PCT/US2013/053979 US2013053979W WO2015020645A1 WO 2015020645 A1 WO2015020645 A1 WO 2015020645A1 US 2013053979 W US2013053979 W US 2013053979W WO 2015020645 A1 WO2015020645 A1 WO 2015020645A1
Authority
WO
WIPO (PCT)
Prior art keywords
downhole
parameter
signal
wellbore
operational parameter
Prior art date
Application number
PCT/US2013/053979
Other languages
English (en)
Inventor
Mikko Jaaskelainen
David Andrew Barfoot
Original Assignee
Halliburton Energy Services, Inc.
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 Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to CA2915722A priority Critical patent/CA2915722C/fr
Priority to PCT/US2013/053979 priority patent/WO2015020645A1/fr
Priority to US14/904,672 priority patent/US20160153277A1/en
Priority to ARP140102988A priority patent/AR097288A1/es
Publication of WO2015020645A1 publication Critical patent/WO2015020645A1/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
    • 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/008—Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions

Definitions

  • This disclosure relates to fiber optic systems used, for example, in wellbores.
  • Fiber optic cables are used to transmit light in fiber optic communications and optical sensing.
  • light can represent various signal types, such as temperature, pressure, strain, acceleration, and the like.
  • optical sensing can be used in a wellbore by communicating light between a source and downhole sensors or actuators (or both) along a fiber optic communication path.
  • Fiber optic sensing systems implemented in wellbores can include, e.g., fiber optic cables embedded in the wellbore's casing, or run down into the wellbore with a well tool (e.g., a logging tool string in a drill pipe string).
  • Wellbore temperatures can reach as high as 200° C (392° F) and wellbore pressures can reach as high as 30 kpsi.
  • Sensing techniques implemented in wellbores to monitor operations of the actuators or other components in the wellbore need to be capable of withstanding such harsh operating environments.
  • FIG. 1 illustrates an example wellbore system that includes a system to monitor performances of well flow devices.
  • FIG. 2 is a flowchart of an example process for monitoring and controlling an operation of a well flow device.
  • FIG. 3 illustrates an example plot of operating ranges for a well flow device.
  • FIG. 4 illustrates an example of a well flow device and sensors disposed in the wellbore of FIG. 1.
  • Downhole pumping systems can include well flow devices to displace fluids, for example, drilling fluids, production fluids or other wellbore fluids.
  • a well flow device include an electrical submersible pump (ESP), a hydraulic submersible pump, a jet pump, a progressive cavity pump, beam pumps, and other fluid displacement devices.
  • Well flow devices can be used to generate a pressure differential in the wellbore and to increase a movement of fluids in the wellbore during hydrocarbon production from the wellbore.
  • ESPs are often implemented in high flow rate applications. Because ESPs include electrical and mechanical moving parts, when implemented downhole in the wellbore, the ESPs are susceptible to fail.
  • This disclosure describes techniques to monitor and control the operation of well flow devices, in general, to improve the performance and lifetime of downhole pumping systems in which the well flow devices are implemented.
  • the operating ranges can provide parameters including, for example, power requirements, rotating frequency, efficiency, and similar operating parameters.
  • the operating parameters of the well flow devices are affected by downhole parameters including, for example, viscosity of the fluid, flow rate, pipe diameter, temperature, pressure at the well flow device, pressure drop across an inlet or an outlet (or both) of the well flow devices.
  • the operating parameters of the well flow devices can be determined at downhole locations and transmitted uphole, e.g., to a surface outside the wellbore. From the measured downhole parameters, the operating parameters of the well flow devices can be determined. Performances of the well flow devices can be monitored by comparing the determined operational parameters of the well flow devices with respective operating ranges. Responsive to the monitoring, operations of the well flow devices can be controlled such that the operating parameters remain within the operating ranges.
  • the fiber optic sensing techniques to measure downhole parameters implement fiber optic cables to transmit downhole parameters, measured downhole, to fiber optic sensing systems, disposed uphole (e.g., outside the wellbore).
  • the fiber optic cables can carry light signals that represent the downhole parameters from well flow devices that are located at remote downhole locations, e.g., hundreds or thousands of meters below the surface.
  • the fiber optic cables can be more reliable than electrical cables. Replacing electrical cables with fiber optic cables can negate telemetry problems that result from electrical ground faults that cut off telemetry because the fiber optic cables are immune to such ground fault failures. Also, by using fiber optic cables, electrical noise generated by high current electrical coils on a motor of the well flow device can be avoided.
  • the need for shielding the electrical cables to protect the electrical cables from radio frequency (RF) interference can also be avoided, resulting in a decrease in the weight of the telemetry system and cost to operate the same.
  • the fiber optic cable need not be directly attached to the well flow device, thereby minimizing the need for complex cable design and seals to connect the fiber optic cable to the well flow device such that the fiber optic cable is protected in the harsh downhole environment.
  • a ruggedness of the monitoring system can be enhanced by implementing electronics to directly sense the operating parameters and using the fiber optic cable as an indirect telemetry system.
  • the hybrid approach i.e., a combination of electronics and fiber optics
  • FIG. 1 illustrates an example wellbore system 100 that includes a system to monitor performances of well flow devices.
  • the wellbore system 100 includes a wellbore 102 in which a well flow device 104 is disposed at a downhole location.
  • One or more sensors e.g., a sensor 116) can be attached to or imbedded in the well flow device 104.
  • the well flow device can be an ESP that includes a motor 118 to which the sensor 116 can be attached.
  • the sensors can sense and measure the operational parameters of the well flow device 104.
  • Processing circuitry 106 can be connected to the well flow device 104 and to the one or more sensors to receive the operational parameters as downhole parameter signals.
  • the processing circuitry 106 can be rated for operation in the downhole wellbore conditions, e.g., at high temperatures, pressures or both.
  • the processing circuitry 106 is a Tl Delfino SM320F28335-HT digital signal controller which is rated for operation at up to 210 °C.
  • One or more fiber optic cables are run into the wellbore 102, e.g., in the casing 110.
  • One end of a fiber optic cable is disposed in proximity to the well flow device 104. The end of the fiber optic cable may or may not contact the well flow device 104.
  • Downhole parameter signals received by the processing circuitry 106 can be transmitted uphole to a fiber optic sensing system 112 that is coupled to the processing circuitry 106 via the fiber optic cable.
  • Electrical power can be transmitted from a power source 108 outside the wellbore 102 downhole to the sensors and to the processing circuitry 106 by a cable passed through a casing 110 in which the fiber optic cables are carried downhole.
  • a controller 114 disposed outside the wellbore 102, is connected to the fiber optic sensing system 112.
  • the controller 114 is configured to receive the downhole parameter signal from the fiber optic sensing system 102, and determine the operational parameter of the well flow device 104 based on the downhole parameter signal.
  • the controller 114 can include a computer system that includes a computer- readable medium storing instructions executable by data processing apparatus to perform operations.
  • the controller 114 can be implemented as a microprocessor. Processes performed by the components in the wellbore system 100 are described below with reference to FIG. 2.
  • FIG. 2 is a flowchart of an example process 200 for monitoring and controlling an operation of a well flow device.
  • the process 200 can be implemented by one or more of the processing circuitry 106, the fiber optic sensing system 112, and the controller 114, acting alone or in any combination.
  • a downhole parameter signal e.g., an electrical signal
  • the downhole parameter signal is converted into a vibration signal that represents the operational parameter of the well flow device 104.
  • the vibration signal is provided to a fiber optic cable resulting in a light signal carried by the fiber optic cable being modulated by the vibration signal.
  • the processing circuitry 106 is configured to implement the steps 204, 206, 208 and 210 of the process 200.
  • the processing circuitry 106 is configured to convert the downhole parameter signal into a vibration signal that represents the downhole parameter.
  • the processing circuitry 106 can include an analog-to-digital converter (ADC) to receive the downhole parameter signal from the sensor.
  • ADC analog-to-digital converter
  • the processing circuitry 106 can also include a floating point calculation unit to encode the downhole parameter signal, and a vibration transducer to convert the encoded downhole parameter signal into the vibration signal.
  • the vibration transducer can be coupled directly to the fiber optic cable through an attachment.
  • the fiber optic cable can be wound around the vibration transducer.
  • the vibration transducer can be separated from the fiber optic cable spatially or by a barrier, e.g., the casing 110 in which the fiber optic cables are carried.
  • the vibration transducer can be located away from the well flow device 104, e.g., at a distance that is sufficient to reduce interference from vibration noise generated by the well flow device 104.
  • the processing circuitry 106 can additionally include a pulse width modulation unit to transmit the vibration signal to the fiber optic cable.
  • the fiber optic sensing system 112 includes a distributed acoustic sensing (DAS) system to extract the downhole parameter signal from the fiber optic cable.
  • DAS distributed acoustic sensing
  • the DAS system causes the fiber optic cable to become a spatially distributed array of acoustic sensors using time domain multiplexing (TDM).
  • TDM time domain multiplexing
  • the DAS system can be configured to transmit two highly coherent laser pulses separated by a few meters downhole through the fiber optic cable. The propagating pulses generate Rayleigh backscatter.
  • the light received uphole at a detector will originate from two locations on the fiber optic cable based on the speed of the two pulses in the fiber optic cable.
  • the backscattered light from the two pulses will interfere with each other, producing a signal amplitude that is dependent on the amount of strain on the fiber optic cable at the downhole location where the backscattered light originated.
  • the downhole location is in proximity to the well flow device 104.
  • the backscatter represents the downhole parameter signal.
  • the strain on the fiber optic cable depends on a perturbation of the fiber optic cable by the processing circuitry 106.
  • the DAS system can include an interrogator to interrogate the downhole parameter signal extracted from the fiber optic cable.
  • the interrogator can provide spatially distributed vibration sensors that are intrinsic to the fiber optic cable.
  • the interrogator can be configured to interrogate one or more extrinsic fiber optic acoustic sensors. Such sensors can be, e.g., based on the use of fiber Bragg gratings (FBG) or Fabry-Perot cavities from point sensor-based interferometers.
  • FBG fiber Bragg gratings
  • Fabry-Perot cavities from point sensor-based interferometers.
  • the interrogator can identify the downhole parameter signal from the vibration signal based on the interrogation.
  • an operational parameter of the well flow device can be determined based on the vibration signal.
  • an operational parameter range for the operational parameter can be identified.
  • the determined operational parameter can be compared with the operational parameter range.
  • it can be determined if the operational parameter is within the operational parameter range. If the operational parameter is not within the operational parameter range (decision branch "NO"), then control signals can be transmitted downhole to control an operation of the well flow device. If the operation parameter is within the operational parameter range (decision branch "YES"), then the determined operational parameter can continue with the operational parameter range.
  • the controller 114 can be configured to implement steps 214, 216, 218, 219 and 220 of the process 200.
  • the operational parameter of the well flow device 104 e.g., an ESP
  • the downhole parameter signal can represent, e.g., viscosity of the fluid, flow rate, pipe diameter, temperature, pressure at the well flow device, pressure drop across the inlet or the outlet (or both) of the well flow device 104.
  • the controller 114 can receive a first downhole parameter signal that represents a pressure difference (p) across the well flow device 104 and a second downhole parameter signal that represents a flow rate (Q).
  • the controller 114 can determine work done by the well flow device 104 using Equation 1 :
  • the controller 114 can include (or be connected to) a computer-readable storage medium in which performance curves that represent operational parameter ranges for the well flow device 104 can be stored.
  • An example plot 300 of operating ranges for a well flow device is illustrated in FIG. 3.
  • the controller 114 is configured to determine that the determined operational parameter falls outside the operational parameter range (e.g., represented by the plot of operating ranges) in response to comparing the determined operational parameter with the operational parameter range.
  • the controller 114 is configured to transmit the control signals to the well flow device 104 to modify the operation of the well flow device such that the determined operational parameter falls within the operational parameter range.
  • the wellbore system 100 can include multiple sensors disposed at multiple remote locations in the wellbore 100 to measure the downhole parameters.
  • the multiple sensors can be used to determine the operational parameters of the well flow device 104 .
  • the multiple sensors can include, e.g., an outlet pressure sensor 402, a flow rate and densitometer sensor 404, an inlet pressure sensor 408, an accelerometer 410, a motor temperature sensor 412, and other similar sensors.
  • the processing circuitry 104 can include or be connected to the vibration transducer 406 to perturb one or more fiber optic cables (e.g., a fiber optic cable 450) based on the downhole parameter signals generated by one or more (or all) of the sensors shown in FIG. 4.
  • one or more of the relevant operational parameters of the well flow device 104 can be determined from the downhole parameter signals.
  • the system described in this disclosure monitors operation of the well flow device 104 (e.g., continuously, periodically, in response to operator input, or combinations of them) and optimizes the performance of the well flow device 104, thereby prolonging the device's lifetime.
  • vibration generated by the well flow device 104 can indicate conditions of the device 104.
  • additional harmonics at multiples of the device's rotation frequency will increase in amplitude.

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  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Remote Sensing (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Geophysics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Electromagnetism (AREA)
  • Measurement Of Mechanical Vibrations Or Ultrasonic Waves (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)
  • Measuring Volume Flow (AREA)

Abstract

Surveillance d'un dispositif de production de puits par détection à fibre optique. Un système selon l'invention comprend une circuiterie de traitement configurée pour être disposée en fond de trou dans un puits de forage. La circuiterie de traitement est configurée pour recevoir un signal de paramètre de fond qui représente un paramètre opérationnel d'un dispositif de production de puits situé dans le puits de forage, et perturber un câble à fibre optique, sur la base du signal de paramètre de fond, en vue de transmettre le signal de paramètre de fond sur le câble à fibre optique. Un système de détection à fibre optique est couplé à la circuiterie de traitement via le câble à fibre optique. Le système de détection à fibre optique est configuré pour être disposé à l'extérieur du puits de forage en vue d'extraire du câble à fibre optique le signal de paramètre de fond.
PCT/US2013/053979 2013-08-07 2013-08-07 Surveillance d'un dispositif de production de puits par détection à fibre optique WO2015020645A1 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
CA2915722A CA2915722C (fr) 2013-08-07 2013-08-07 Surveillance d'un dispositif de production de puits par detection a fibre optique
PCT/US2013/053979 WO2015020645A1 (fr) 2013-08-07 2013-08-07 Surveillance d'un dispositif de production de puits par détection à fibre optique
US14/904,672 US20160153277A1 (en) 2013-08-07 2013-08-07 Monitoring a well flow device by fiber optic sensing
ARP140102988A AR097288A1 (es) 2013-08-07 2014-08-07 Monitoreo de un dispositivo de flujo de pozo por detección con fibra óptica

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2013/053979 WO2015020645A1 (fr) 2013-08-07 2013-08-07 Surveillance d'un dispositif de production de puits par détection à fibre optique

Publications (1)

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WO2015020645A1 true WO2015020645A1 (fr) 2015-02-12

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US (1) US20160153277A1 (fr)
AR (1) AR097288A1 (fr)
CA (1) CA2915722C (fr)
WO (1) WO2015020645A1 (fr)

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WO2016133850A1 (fr) * 2015-02-16 2016-08-25 Schlumberger Technology Corporation Détermination de temps d'arrêt pour une pompe
WO2017074374A1 (fr) * 2015-10-29 2017-05-04 Halliburton Energy Services, Inc. Détection de course de pompe à boue à l'aide de détection acoustique distribuée

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US10122184B2 (en) * 2016-09-15 2018-11-06 Blackberry Limited Application of modulated vibrations in docking scenarios

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US20040141420A1 (en) * 2003-01-21 2004-07-22 Hardage Bob A. System and method for monitoring performance of downhole equipment using fiber optic based sensors
US20110002795A1 (en) * 2009-07-01 2011-01-06 Baker Hughes Incorporated System to Measure Vibrations Using Fiber Optic Sensors
US20120046866A1 (en) * 2010-08-23 2012-02-23 Schlumberger Technology Corporation Oilfield applications for distributed vibration sensing technology
US20130044310A1 (en) * 2007-12-21 2013-02-21 Leddartech Inc. Distance detection method and system
US20130148127A1 (en) * 2011-12-07 2013-06-13 Baker Hughes Incorporated Fiber Optic Measurement of Parameters for Downhole Pump Diffuser Section

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JP5734717B2 (ja) * 2011-03-24 2015-06-17 セミコンダクター・コンポーネンツ・インダストリーズ・リミテッド・ライアビリティ・カンパニー 浮動小数点数のビット長変換回路およびそれを用いた振動補正制御回路
US10030509B2 (en) * 2012-07-24 2018-07-24 Fmc Technologies, Inc. Wireless downhole feedthrough system
US10316643B2 (en) * 2013-10-24 2019-06-11 Baker Hughes, A Ge Company, Llc High resolution distributed temperature sensing for downhole monitoring

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20040141420A1 (en) * 2003-01-21 2004-07-22 Hardage Bob A. System and method for monitoring performance of downhole equipment using fiber optic based sensors
US20130044310A1 (en) * 2007-12-21 2013-02-21 Leddartech Inc. Distance detection method and system
US20110002795A1 (en) * 2009-07-01 2011-01-06 Baker Hughes Incorporated System to Measure Vibrations Using Fiber Optic Sensors
US20120046866A1 (en) * 2010-08-23 2012-02-23 Schlumberger Technology Corporation Oilfield applications for distributed vibration sensing technology
US20130148127A1 (en) * 2011-12-07 2013-06-13 Baker Hughes Incorporated Fiber Optic Measurement of Parameters for Downhole Pump Diffuser Section

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2016133850A1 (fr) * 2015-02-16 2016-08-25 Schlumberger Technology Corporation Détermination de temps d'arrêt pour une pompe
WO2017074374A1 (fr) * 2015-10-29 2017-05-04 Halliburton Energy Services, Inc. Détection de course de pompe à boue à l'aide de détection acoustique distribuée
EP3332083A4 (fr) * 2015-10-29 2018-07-11 Halliburton Energy Services, Inc. Détection de course de pompe à boue à l'aide de détection acoustique distribuée
US10794177B2 (en) 2015-10-29 2020-10-06 Halliburton Energy Services, Inc. Mud pump stroke detection using distributed acoustic sensing

Also Published As

Publication number Publication date
US20160153277A1 (en) 2016-06-02
AR097288A1 (es) 2016-03-02
CA2915722C (fr) 2019-02-26
CA2915722A1 (fr) 2015-02-12

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