CA2915722C - Monitoring a well flow device by fiber optic sensing - Google Patents
Monitoring a well flow device by fiber optic sensing Download PDFInfo
- Publication number
- CA2915722C CA2915722C CA2915722A CA2915722A CA2915722C CA 2915722 C CA2915722 C CA 2915722C CA 2915722 A CA2915722 A CA 2915722A CA 2915722 A CA2915722 A CA 2915722A CA 2915722 C CA2915722 C CA 2915722C
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- Prior art keywords
- downhole
- signal
- parameter
- wellbore
- operational parameter
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/008—Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
Abstract
Monitoring a well flow device by fiber optic sensing. A system includes processing circuitry configured to be disposed downhole in a wellbore. The processing circuitry is configured to receive a downhole parameter signal that represents an operational parameter of a well flow device in the wellbore, and perturb a fiber optic cable, based on the downhole parameter signal, to transmit the downhole parameter signal over the fiber optic cable. A fiber optic sensing system is coupled to the processing circuitry via the fiber optic cable. The fiber optic sensing system is configured to be disposed outside of the wellbore to extract, from the fiber optic cable, the downhole parameter signal.
Description
^
MONITORING A WELL FLOW DEVICE BY FIBER OPTIC SENSING
TECHNICAL FIELD
[0001] This disclosure relates to fiber optic systems used, for example, in wellbores.
BACKGROUND
MONITORING A WELL FLOW DEVICE BY FIBER OPTIC SENSING
TECHNICAL FIELD
[0001] This disclosure relates to fiber optic systems used, for example, in wellbores.
BACKGROUND
[0002] Fiber optic cables are used to transmit light in fiber optic communications and optical sensing. For example, in optical sensing, light can represent various signal types, such as temperature, pressure, strain, acceleration, and the like. In some applications, 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.
BRIEF DESCRIPTION OF THE DRAWINGS
(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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] FIG. 1 illustrates an example wellbore system that includes a system to monitor performances of well flow devices.
[0004] FIG. 2 is a flowchart of an example process for monitoring and controlling an operation of a well flow device.
[0005] FIG. 3 illustrates an example plot of operating ranges for a well flow device.
[0006] FIG. 4 illustrates an example of a well flow device and sensors disposed in the wellbore of FIG. 1.
[0007] Like reference numbers and designations in the various drawings indicate like elements.
= 1 = WO 2015/020645 DETAILED DESCRIPTION
= 1 = WO 2015/020645 DETAILED DESCRIPTION
[0008] This disclosure relates to monitoring a well flow device by fiber optic sensing.
Downhole pumping systems can include well flow devices to displace fluids, for example, drilling fluids, production fluids or other wellbore fluids. Examples of 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. For example, 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.
Downhole pumping systems can include well flow devices to displace fluids, for example, drilling fluids, production fluids or other wellbore fluids. Examples of 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. For example, 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.
[0009] Manufacturers of well flow devices, such as ESPs, provide performance curves identifying optimal operating ranges of the well flow devices. 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. By implementing fiber optic sensing techniques to measure the downhole parameters, 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.
[0010] 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.
Consequently, 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. Moreover, 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.
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.
Consequently, 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. Moreover, 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.
[0011] 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) can provide cost savings, increase in reliability, and better pump monitoring relative to monitoring systems that implement only electronics or only fiber optics.
[0012] 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. For example, 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. In certain instances, the processing circuitry 106 is a TI Delfinolm SM320F28335-HT digital signal controller which is rated for operation at up to 210 C.
[0013] 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.
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.
[0014] 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 112, and determine the operational parameter of the well flow device 104 based on the downhole parameter signal.
In some implementations, the controller 114 can include a computer system that includes a computer-readable medium storing instructions executable by data processing apparatus to perform operations. Alternatively or in addition, 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.
In some implementations, the controller 114 can include a computer system that includes a computer-readable medium storing instructions executable by data processing apparatus to perform operations. Alternatively or in addition, 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.
[0015] 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. At 204. a downhole parameter signal (e.g., an electrical signal) that represents an operational parameter of the well flow device 104 in the wellbore 102 (e.g., a wellbore pump) is received. At 206, the downhole parameter signal is converted into a vibration signal that represents the operational parameter of the well flow device 104. At 208, 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. At 210, the modulated light signal is transmitted uphole via the perturbed fiber optic cable.
= Z..
= Z..
[0016] In some implementations, the processing circuitry 106 is configured to implement the steps 204, 206, 208 and 210 of the process 200. For example, the processing circuitry 106 is configured to convert the downhole parameter signal into a vibration signal that represents the downhole parameter. To do so, the processing circuitry 106 can include an analog-to-digital converter (ADC) to receive the downhole parameter signal from the sensor. 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. To provide the vibration signal to the fiber optic cable, the vibration transducer can be coupled directly to the fiber optic cable through an attachment. Alternatively, thc fiber optic cable can be wound around the vibration transducer. In some implementations, 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.
[0017] At 212, the downhole parameter signal is extracted, uphole, from the fiber optic cable. In some implementations, the fiber optic sensing system 112 includes a distributed acoustic sensing (DAS) system to extract the downhole parameter signal from the fiber optic cable. The DAS system causes the fiber optic cable to become a spatially distributed array of acoustic sensors using time domain multiplexing (TDM).
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. At a particular time after the pulses are transmitted, 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. In the implementations described in this disclosure, 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 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. At a particular time after the pulses are transmitted, 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. In the implementations described in this disclosure, 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.
[0018] 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.
In some implementations, 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. The interrogator can identify the downhole parameter signal from the vibration signal based on the interrogation.
In some implementations, 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. The interrogator can identify the downhole parameter signal from the vibration signal based on the interrogation.
[0019] At 214, an operational parameter of the well flow device can be determined based on the vibration signal. At 216, an operational parameter range for the operational parameter can be identified. At 218, the determined operational parameter can be compared with the operational parameter range. At 219, 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.
[0020] In some implementations, the controller 114 can be configured to implement steps 214, 216, 218, 219 and 220 of the process 200. As described above, the operational parameter of the well flow device 104 (e.g., an ESP) can include at least one of power consumed, rotational frequency, or vibration generated by the well flow device 104. 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. For example, 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:
Hhp= 1.7 x 10-5xpxQ
(Equation 1) ' =
Hhp= 1.7 x 10-5xpxQ
(Equation 1) ' =
[0021] 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. In some implementations, 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. In response, 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.
[0022] In some implementations, 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 (FIG. 4) 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. As described above, one or more of the relevant operational parameters of the well flow device 104 can be determined from the downhole parameter signals. By measuring relevant operational parameters, 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.
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. As described above, one or more of the relevant operational parameters of the well flow device 104 can be determined from the downhole parameter signals. By measuring relevant operational parameters, 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.
[0023] In addition, vibration generated by the well flow device 104 can indicate conditions of the device 104. When the well flow device 104 becomes unbalanced due to mechanical wear or alignment problems, additional harmonics at multiples of the device's rotation frequency will increase in amplitude. By measuring these vibrations with a sensor, vibration monitoring techniques can be implemented to track the condition of the well flow device 104.
[0024] A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure.
Claims (19)
1. A system comprising:
processing circuitry to be disposed downhole in a wellbore, the processing circuitry to:
receive a downhole parameter signal that represents an operational parameter of a well flow device in the wellbore;
convert the downhole parameter signal into a vibration signal;
provide the vibration signal to a fiber optic cable, the vibration signal perturbing the fiber optic cable, based on the downhole parameter signal, to transmit the downhole parameter signal over the fiber optic cable; and a fiber optic sensing system coupled to the processing circuitry via the fiber optic cable, the fiber optic sensing system to be disposed outside of the wellbore, the fiber optic sensing systern to:
extract, from the fiber optic cable, the downhole parameter signal.
processing circuitry to be disposed downhole in a wellbore, the processing circuitry to:
receive a downhole parameter signal that represents an operational parameter of a well flow device in the wellbore;
convert the downhole parameter signal into a vibration signal;
provide the vibration signal to a fiber optic cable, the vibration signal perturbing the fiber optic cable, based on the downhole parameter signal, to transmit the downhole parameter signal over the fiber optic cable; and a fiber optic sensing system coupled to the processing circuitry via the fiber optic cable, the fiber optic sensing system to be disposed outside of the wellbore, the fiber optic sensing systern to:
extract, from the fiber optic cable, the downhole parameter signal.
2. The system of claim 1, wherein the fiber optic sensing system comprises a distributed acoustic sensing system further comprising an interrogator to interrogate the downhole parameter signal extracted from the fiber optic cable, the interrogator configured to be disposed outside the wellbore.
3. The system of claim 1, to convert the downhole parameter signal into the vibration signal, the processing circuitry further comprises:
an analog-to-digital converter to receive the downhole parameter signal;
a floating point calculation unit to encode the downhole parameter signal;
a vibration transducer to convert the encoded downhole parameter signal into the vibration signal; and a pulse width modulation unit to transmit the vibration signal to the fiber optic cable.
an analog-to-digital converter to receive the downhole parameter signal;
a floating point calculation unit to encode the downhole parameter signal;
a vibration transducer to convert the encoded downhole parameter signal into the vibration signal; and a pulse width modulation unit to transmit the vibration signal to the fiber optic cable.
4. The system of claim 1, further comprising a controller configured to be disposed outside the wellbore, the controller connected to the fiber optic sensing system and configured to:
receive the downhole parameter signal from the fiber optic sensing system; and determine the operational parameter of the well flow device based on the downhole parameter signal.
receive the downhole parameter signal from the fiber optic sensing system; and determine the operational parameter of the well flow device based on the downhole parameter signal.
5. The system of claim 4, wherein the controller is further configured to:
identify an operational parameter range for the operational parameter;
compare the determined operational parameter with the operational parameter range; and transmit control signals to the well flow device to control an operation of the well flow device in response to comparing the determined operational parameter with the operational parameter range.
identify an operational parameter range for the operational parameter;
compare the determined operational parameter with the operational parameter range; and transmit control signals to the well flow device to control an operation of the well flow device in response to comparing the determined operational parameter with the operational parameter range.
6. The system of claim 5, wherein the controller is further configured to:
determine that the determined operational parameter falls outside the operational parameter range in response to comparing the deterrnined operational parameter with the operational parameter range; and transmit the control signals to the well flow device to modify the operation of the well flow device such that the deterrnined operational parameter falls within the operational parameter range.
determine that the determined operational parameter falls outside the operational parameter range in response to comparing the deterrnined operational parameter with the operational parameter range; and transmit the control signals to the well flow device to modify the operation of the well flow device such that the deterrnined operational parameter falls within the operational parameter range.
7. The system of claim 5, wherein:
the fiber optic sensing system is further configured to extract a plurality of downhole pararneter signals, each downhole parameter signal representing a downhole pararneter at or near the well flow device; and the controller is further configured to deterrnine the operational pararneter range based, in part, on the plurality of downhole parameter signals.
the fiber optic sensing system is further configured to extract a plurality of downhole pararneter signals, each downhole parameter signal representing a downhole pararneter at or near the well flow device; and the controller is further configured to deterrnine the operational pararneter range based, in part, on the plurality of downhole parameter signals.
8. The system of claim 7, wherein the plurality of downhole pararneter signals represent at least one of viscosity of fluid in the wellbore, flow rate of thc fluid, wellbore diameter, wellbore temperature, pressure at the well flow device, or pressure drop across the well flow device.
9. The system of claim 1, wherein the well flow device is an electrical submersible pump, and the operational parameter is at least one of power consumed, rotational frequency, or vibration generated by the electrical submersible pump.
10. A method to monitor a performance of a wellbore pump in a wellbore, the method comprising:
receiving, downhole, an electrical downhole parameter signal representing an operational parameter of a wellbore pump in a wellbore;
converting, downhole, the electrical downhole parameter signal into a vibration signal that represents the operational parameter of the wellbore pump, the vibration signal to modulate, downhole, a light signal based on the vibration signal, the modulated light signal representing the operational parameter of the wellbore pump; and transmitting the modulated light signal to outside the wellbore.
receiving, downhole, an electrical downhole parameter signal representing an operational parameter of a wellbore pump in a wellbore;
converting, downhole, the electrical downhole parameter signal into a vibration signal that represents the operational parameter of the wellbore pump, the vibration signal to modulate, downhole, a light signal based on the vibration signal, the modulated light signal representing the operational parameter of the wellbore pump; and transmitting the modulated light signal to outside the wellbore.
11. The method of claim 10, wherein converting, downhole, the electrical downhole parameter signal into the vibration signal comprises:
converting, downhole, an analog electrical downhole parameter signal into a digital downholc parameter signal; and encoding, downhole, the digital downhole parameter signal into the vibration signal by implementing floating point calculation.
converting, downhole, an analog electrical downhole parameter signal into a digital downholc parameter signal; and encoding, downhole, the digital downhole parameter signal into the vibration signal by implementing floating point calculation.
12. The method of claim 10, wherein modulating, downhole, the light signal based on the vibration signal cornprises perturbing a fiber optic cable, based on the downhole pararneter signal, the perturbing resulting in the vibration signal.
13. The rnethod of clairn 10, further cornprising:
receiving, outside the wellbore, the rnodulated light signal representing the operational parameter of the wellbore pump;
interrogating the modulated light signal outside the wellbore; and determining the operational parameter in response to interrogating the modulated light signal outside the wellbore.
receiving, outside the wellbore, the rnodulated light signal representing the operational parameter of the wellbore pump;
interrogating the modulated light signal outside the wellbore; and determining the operational parameter in response to interrogating the modulated light signal outside the wellbore.
14. The method of claim 13, further comprising:
identifying an operational parameter range for the operational parameter;
comparing the determined operational parameter with the operational parameter range; and transmitting control signals to the wellbore pump to control an operation of the wellbore pump in response to comparing the determined operational parameter with the operational parameter range.
identifying an operational parameter range for the operational parameter;
comparing the determined operational parameter with the operational parameter range; and transmitting control signals to the wellbore pump to control an operation of the wellbore pump in response to comparing the determined operational parameter with the operational parameter range.
15. The method of claim 14, further comprising:
determining that the determined operational parameter falls outside the operational parameter range in response to comparing the determined operational parameter with the operational parameter range: and transmitting the control signals to the wellbore pump to modify the operation of the wellbore pump such that the determined operational parameter falls within the operational parameter range.
determining that the determined operational parameter falls outside the operational parameter range in response to comparing the determined operational parameter with the operational parameter range: and transmitting the control signals to the wellbore pump to modify the operation of the wellbore pump such that the determined operational parameter falls within the operational parameter range.
16. The method of claim 14, further comprising:
receiving one or more downhole parameter signals, each downhole parameter signal representing a downhole parameter at or near the wellbore pump: and determining the operational parameter range based, in part, on the downhole parameter signals.
receiving one or more downhole parameter signals, each downhole parameter signal representing a downhole parameter at or near the wellbore pump: and determining the operational parameter range based, in part, on the downhole parameter signals.
17. A non-transitory computer-readable medium storing instructions executable by data processing apparatus to perform operations comprising:
receiving, downhole, an electrical clownhole parameter signal representing an operational parameter of a wellbore pump in a wellbore;
converting, downhole, the electrical downhole parameter signal into a vibration signal that represents the operational parameter of the wellbore pump, the vibration signal to modulate, downhole a light signal based on the vibration signal, the modulated light signal representing the operational parameter of the wellbore pump; and transmitting the modulated light signal to outside the wellbore.
receiving, downhole, an electrical clownhole parameter signal representing an operational parameter of a wellbore pump in a wellbore;
converting, downhole, the electrical downhole parameter signal into a vibration signal that represents the operational parameter of the wellbore pump, the vibration signal to modulate, downhole a light signal based on the vibration signal, the modulated light signal representing the operational parameter of the wellbore pump; and transmitting the modulated light signal to outside the wellbore.
18. The medium of claim 17, wherein converting, downhole, the electrical downhole parameter signal into the vibration signal comprises:
converting, downhole, an analog electrical downhole parameter signal into a digital downhole pararneter signal;
encoding, downhole, the digital downhole parameter signal by implementing floating point calculation, and converting, downhole, the encoded digital downhole parameter signal into the vibration signal, wherein the operations further comprise transmitting the vibration signal to modulate the light signal by implementing pulse width modulation.
converting, downhole, an analog electrical downhole parameter signal into a digital downhole pararneter signal;
encoding, downhole, the digital downhole parameter signal by implementing floating point calculation, and converting, downhole, the encoded digital downhole parameter signal into the vibration signal, wherein the operations further comprise transmitting the vibration signal to modulate the light signal by implementing pulse width modulation.
19. The medium of claim 17, wherein the operations further comprise:
receiving, outside the wellbore, the modulated light signal representing the operational parameter of the wellbore pump:
interrogating the modulated light signal outside the wellbore;
deterrnining the operational parameter in response to interrogating the modulated light signal outside the wellbore;
identifying an operational pararneter range for the operational parameter;
comparing the determined operational parameter with the operational parameter range; and transmitting control signals to the wellbore pump to control an operation of the wellbore pump in response to comparing the determined operational parameter with the operational parameter range.
receiving, outside the wellbore, the modulated light signal representing the operational parameter of the wellbore pump:
interrogating the modulated light signal outside the wellbore;
deterrnining the operational parameter in response to interrogating the modulated light signal outside the wellbore;
identifying an operational pararneter range for the operational parameter;
comparing the determined operational parameter with the operational parameter range; and transmitting control signals to the wellbore pump to control an operation of the wellbore pump in response to comparing the determined operational parameter with the operational parameter range.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| PCT/US2013/053979 WO2015020645A1 (en) | 2013-08-07 | 2013-08-07 | Monitoring a well flow device by fiber optic sensing |
Publications (2)
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|---|---|
| CA2915722A1 CA2915722A1 (en) | 2015-02-12 |
| CA2915722C true CA2915722C (en) | 2019-02-26 |
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| CA2915722A Expired - Fee Related CA2915722C (en) | 2013-08-07 | 2013-08-07 | Monitoring a well flow device by fiber optic sensing |
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| US (1) | US20160153277A1 (en) |
| AR (1) | AR097288A1 (en) |
| CA (1) | CA2915722C (en) |
| WO (1) | WO2015020645A1 (en) |
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| WO2016133850A1 (en) * | 2015-02-16 | 2016-08-25 | Schlumberger Technology Corporation | Determining downtime for a pump |
| EP3332083A4 (en) * | 2015-10-29 | 2018-07-11 | Halliburton Energy Services, Inc. | Mud pump stroke detection using distributed acoustic sensing |
| US10122184B2 (en) * | 2016-09-15 | 2018-11-06 | Blackberry Limited | Application of modulated vibrations in docking scenarios |
Family Cites Families (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7028543B2 (en) * | 2003-01-21 | 2006-04-18 | Weatherford/Lamb, Inc. | System and method for monitoring performance of downhole equipment using fiber optic based sensors |
| WO2009079789A1 (en) * | 2007-12-21 | 2009-07-02 | Leddartech Inc. | Detection and ranging methods and systems |
| CA2708843C (en) * | 2009-07-01 | 2014-01-21 | 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 |
| JP5734717B2 (en) * | 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 | Floating-point number bit length conversion circuit and vibration correction control circuit using the same |
| US8537364B2 (en) * | 2011-12-07 | 2013-09-17 | Baker Hughes Incorporated | Fiber optic measurement of parameters for downhole pump diffuser section |
| 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 |
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2013
- 2013-08-07 US US14/904,672 patent/US20160153277A1/en not_active Abandoned
- 2013-08-07 WO PCT/US2013/053979 patent/WO2015020645A1/en active Application Filing
- 2013-08-07 CA CA2915722A patent/CA2915722C/en not_active Expired - Fee Related
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2014
- 2014-08-07 AR ARP140102988A patent/AR097288A1/en active IP Right Grant
Also Published As
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| AR097288A1 (en) | 2016-03-02 |
| US20160153277A1 (en) | 2016-06-02 |
| CA2915722A1 (en) | 2015-02-12 |
| WO2015020645A1 (en) | 2015-02-12 |
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