Note: Descriptions are shown in the official language in which they were submitted.
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WO 2015/020645
PCT/US2013/053979
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
[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.
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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.
[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
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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.
[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
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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.
[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.
[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.
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[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
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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.
[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)
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[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.
[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,
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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.
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