Note: Descriptions are shown in the official language in which they were submitted.
SYSTEMS AND METHODS FOR IDENTIFYING SHAFT FAILURE IN A PUMP
TECHNICAL FIELD
[0001] The present disclosure relates to identifying shaft failures
in pumps.
BACKGROUND
[0002] Pumps are used in a variety of applications, such as sewage,
water,
agriculture, petroleum and petrochemical pumping. Some pumps, for example,
centrifugal pumps, use rotational energy, which can be translated into
hydrodynamic energy causing the fluid in the pump to flow. These pumps
generally
comprise a shaft which is connected to a motor; the motor provides rotational
energy to the shaft, which in turn rotates impellers that are attached to the
shaft,
causing the fluid to gain pressure and velocity. In many applications, these
pumps
are installed in inaccessible locations, such as underground, making it
challenging
to diagnose problems with the pumps without physically removing the pumps from
their installed locations and inspecting the pumps.
[0003] By way of example, in steam-assisted gravity drainage (SAGD)
processes, electrical submersible pumps (ESP) are used to draw petroleum
products
from a reservoir deep in the ground. ESP systems typically include a motor
positioned below a centrifugal pump such that the pump intake is above the
motor
and the motor is continuously submersed in the petroleum product(s). By using
the
ESP system as such, a relatively small borehole can be used to access and
retrieve
large volumes the petroleum products deep in the ground.
[0004] As with most equipment, ESPs occasionally experience failures,
stop
working or have problems, such as broken components. While control systems can
show that there is an issue with the ESP, for example, by showing that the
pump is
not producing any petroleum products, the cause of the problems are often not
clear from the control systems, requiring the removal of the ESP system in
order to
diagnose the issue. Since the ESP system is installed in the small borehole,
it can
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Date Recue/Date Received 2022-01-21
be challenging to diagnose any problems arising with the ESP without pulling
the
entire ESP system from the borehole. Removing the ESP system from the borehole
is a costly process and results in substantial downtime for the boreholes.
[0005] Certain problems can be addressed without removing the ESP
system
from the borehole. Other problems, such as a shaft failure, have typically
only been
diagnosable by removing the ESP from the borehole. Accordingly, there is a
need to
identify whether a pump has a broken shaft without removing the pump from the
installed location.
SUMMARY
[0006] In one aspect, there is provided a method for identifying a failure
of a
rotor of a pumping system, the pumping system comprising a pump connected to a
drive with the rotor. The method comprising: monitoring torque being applied
to
the rotor and monitoring speed of the rotor such that monitored rotor data is
obtained; and determining if a rotor failure condition exists based on the
monitored
rotor data.
[0007] In some examples, the existence of the rotor failure condition
is
determined when the monitored rotor data defines rotor-failure indicative data
that
spans a time interval of less than ten (10) minutes and is representative of a
decrease of at least 50% in torque being applied to the rotor while there is
an
absence of variability in the speed of the rotor of greater than 10%.
[0008] In some examples, the decrease in applied torque is a decrease
of
100 /0, such that the decrease is with effect that there is an absence of
torque
being applied to the rotor.
[0009] In some examples, the decrease is a decrease from a baseline
applied
torque, and the baseline applied torque is at least 40 newton metres.
[0010] In some examples, the time interval, over which the rotor-
failure
indicative data spans, is less than five (5) minutes.
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[0011] In some examples, the absence of variability in the speed of
the rotor
is an absence of variability of greater than 5%.
[0012] In some examples, the existence of the rotor failure condition
is
determined when the monitored rotor data defines rotor failure-indicative data
that
spans a decreasing torque profile-defining time interval and has a duration of
less
than ten (10) minutes and is representative of a decreasing applied torque
profile
of torque being applied to the rotor while there is an absence of variability
in the
speed of the rotor of greater than 10%, and the decreasing applied torque
profile
defines a decrease in torque, being applied to the rotor, of at least 50%.
[0013] In some examples, the decrease in torque is a decrease of 100 /0,
such
that the decrease is with effect that there is an absence of torque being
applied to
the rotor.
[0014] In some examples, the decrease in torque is a decrease from a
baseline applied torque, such that the decreasing applied torque profile
defines the
baseline applied torque, and the baseline applied torque is at least 40 newton
metres.
[0015] In some examples, the decreasing torque profile-defining time
interval
is less than five (5) minutes.
[0016] In some examples, the absence of variability in the speed of
the rotor
is an absence of variability of greater than 5%.
[0017] In some examples, the monitored rotor data comprises monitored
torque data, the decrease in applied torque is a decrease from a baseline
applied
torque, such that the decreasing applied torque profile defines the baseline
applied
torque, the monitored torque data, within a preceding time interval of five
(5)
minutes that immediately precedes the decreasing torque profile-defining time
interval, defines torque data that is representative of a minimum applied
torque
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Date Recue/Date Received 2022-01-21
applied to the rotor during the preceding time interval, and the baseline
applied
torque has a value that is less than or equal to that of the minimum-applied
torque.
[0018] In some examples, the baseline applied torque is at least 40
newton
metres.
[0019] In some examples, the pump is a centrifugal pump.
[0020] In some examples, the pump is an electrical submersible pump.
[0021] In some examples, the pump comprises at least one impeller
mounted
on an impeller shaft portion of the rotor, and the rotor failure condition
comprises a
failure of the impeller shaft portion.
[0022] In some examples, the failure of the impeller shaft portion includes
a
snapped shaft.
[0023] In some examples, the drive comprises an electric motor.
[0024] In some examples, the monitoring of the applied torque is
effectuated
with a torque sensor, and the monitoring of the speed is effectuated with a
speed
sensor.
[0025] In some examples, the drive comprises an electric motor.
[0026] In some examples, the drive further comprises a variable
frequency
drive disposed in signal communication with the motor, and the variable
frequency
drive comprises the torque sensor and the speed sensor.
[0027] In some examples, the monitored rotor data is obtained during
pumping of fluid by the pumping system.
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[0028] In some examples, the method further comprises, in response to
determining that a rotor failure condition exists, suspending the rotation of
the
rotor.
[0029] In some examples, the method further comprises, in response to
determining that a rotor failure condition exists, presenting an indication of
the
rotor failure condition via an output device.
[0030] In some examples, the method further comprises, in response to
the
monitoring, sensing an absence of torque being applied to the rotor in the
absence
of a determination of an existence of a rotor failure condition, and
performing a
further analytical evaluation for determining a cause for the sensed absence
of
torque.
[0031] In some examples, the pumping system is disposed within a
wellbore
extending into a subterranean formation from a surface.
[0032] In some examples, the monitored rotor data is obtained during
pumping of fluid by the pumping system, and the pumping comprises pumping of
reservoir fluid from the subterranean formation to the surface.
[0033] In some examples, the reservoir fluid comprises oil.
[0034] In some examples, the method further comprises, in response to
determining that a rotor failure condition exists, suspending rotation of the
rotor.
[0035] In some examples, the method further comprises, after the
suspending of the rotation of the rotor, removing the pumping system from the
wellbore.
[0036] In some examples, the method further comprises, in response to
determining that a rotor failure condition exists, presenting an indication of
the
rotor failure condition via an output device.
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Date Recue/Date Received 2022-01-21
[0037] In some examples, the method further comprises, in response to
the
monitoring, sensing an absence of torque being applied to the rotor in the
absence
of a determination of an existence of a rotor failure condition, and
performing a
further analytical evaluation for determining a cause for the sensed absence
of
torque.
[0038] In some aspects, the present disclosure describes a system for
identifying a failure of a rotor of a pumping system. The system comprises one
or
more processor devices and one or more memories storing machine-executable
instructions which, when executed by the one or more processor devices, cause
the
system to perform any of the preceding example aspects of the method.
[0039] In some aspects, the present disclosure describes a system for
identifying a failure of a rotor of a pumping system, the pumping system
comprising a pump connected to a drive with the rotor. The system comprises a
torque sensor, a speed sensor, one or more processor devices, and one or more
memories storing machine-executable instructions, which when executed by the
one or more processor devices, cause the system to: monitor torque being
applied
to the rotor, using the torque sensor, and monitor speed of the rotor, using
the
speed sensor, such that monitored rotor data is obtained, and determine if a
rotor
failure condition exists, based on the monitored rotor data.
[0040] In some example aspects, the present disclosure describes a non-
transitory computer-readable medium storing machine-executable instructions
thereon. The instructions, when executed by one or more processors, cause the
processor to perform any of the preceding example aspects of the method.
[0041] In some embodiments, the techniques described herein can be
used to
identify when there is a shaft failure in a pump. In this respect, the
techniques
described herein can improve pump diagnostics and minimize the need to shut
down pump operation or remove the pump from its installed location for
maintenance.
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Date Recue/Date Received 2022-01-21
BRIEF DESCRIPTION OF THE DRAWINGS
[0042] Reference will now be made, by way of example, to the
accompanying
drawings which show example embodiments, and in which:
[0043] Figure 1 shows a schematic diagram of an electrical
submersible pump
(ESP) system;
[0044] Figure 2 is a graph illustrating applied torque as a function
of time for
an exemplary operation of a pump;
[0045] Figure 3 is a graph illustrating applied torque as a function
of time for
an exemplary operation of a pump, wherein, during the pump operation, the
rotor
experiences a brief, temporary increase in torque;
[0046] Figure 4 is identical to Figure 3, and further defines a
decreasing
applied torque profile, that is representative of the monitored rata data, and
spans
the decreasing torque profile-defining time interval; and
[0047] Figure 5 is similar to Figure 4, except that the applied
torque
decreases to a greater extent at time T2, than in Figure 4.
DETAILED DESCRIPTION
[0048] The present disclosure describes methods for identifying a
defective
rotor (e.g. impeller shaft) of a pump, based on monitored rotor data. The
monitored rotor data includes monitored torque data and monitored speed data.
[0049] The pump is connected to a drive via a rotor. In some embodiments,
for example, the rotor includes at least one shaft. Exemplary drives include
an
electrical motor, a diesel drive, a hydraulic motor or other means of
transmitting
energy to the shaft. In the present disclosure, the term "motor" will be used
to
refer to this drive, but it will be understood that any means of providing
energy to
the pump can be implemented. The motor converts electrical energy into
mechanical energy of a motor shaft, which defines a motor shaft portion of the
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Date Recue/Date Received 2022-01-21
rotor, to cause the pump to impart energy to a fluid and thereby cause the
fluid to
flow.
[0050] In some embodiments, for example, the pump is a centrifugal
pump
(i.e. pumps that use rotational energy to cause fluid to flow), such as, for
example,
an electrical submersible pump ("ESP"). Centrifugal pumps are comprised of an
impeller that rotates inside a pump casing. The impeller has a series of
blades
formed in a radial arrangement that can transmit kinetic energy to the fluid
upon
rotation of the impeller. The impeller is attached to the rotor. In this
respect, the
motor converts electrical energy to rotational energy of the rotor which, in
turn,
transmits the rotational energy to the impeller, such that the impeller is
caused to
rotate. In some embodiments, for example, the impeller is attached to an
impeller
shaft, which defines an impeller shaft portion of the rotor, and the impeller
shaft is
connected to the motor shaft portion, such that the rotational energy is
transmittable to the impeller via the motor shaft and the impeller shaft.
[0051] In some embodiments, for example, the motor is connected to the
pump using a fixed connection. When a pump and motor are connected in a fixed
connection, the pump and motor housing (casing) are fastened together, for
example, via flanges, and the pump impeller is mounted directly on the motor
shaft
such that the shaft, of the rotor, is common to both of the motor and the
pump. In
other example embodiments, the motor and the pump are in a direct connection,
in
which the motor and pump are not co-axially connected and thus a flexible
connection is used to allow for slight axial misalignment between the motor
and the
pump. Regardless of the means of connecting the two together, the motor and
pump can be configured such that when the motor shaft rotates, the pump shaft
rotates as well.
[0052] Fluid to be pumped enters the centrifugal pump at an intake.
While the
impeller rotates, the fluid acquires energy, primarily in the form of an
increase in its
velocity (i.e. an increase in kinetic energy). As the impeller rotates, the
centrifugal
force causes the fluid to be forced radially outward from the impeller into
the pump
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Date Recue/Date Received 2022-01-21
casing. The fluid is then directed out a discharge nozzle resulting in an
increase in
pressure at the pump outlet. This increase in pressure in the fluid is often
referred
to as pump head.
[0053] When there are problems with a pump, it can be difficult to
diagnose
the problems, especially when the problems arise due to internal components of
the
pumps. For example, many pumps are located within a casing that protects the
internal components of the pump from the exterior environment. While the
casing
can protect the interior components, it also requires the removal of the
casing to
identify what, if any, internal components have caused the issue. Pumps can
also
be installed in inaccessible locations or within larger systems that make it
challenging to access and observe the pump and its components. As such, when
problems arise with a pump due to a rotor (e.g. shaft) failure, it can be
difficult to
identify the particular cause of the problems and often requires removal of
the
pump from its installed location and/or dismantling of the pump which can
create
substantial downtime for the equipment or system in which the pump is used.
[0054] In some embodiments, for example, the pump is part of a system
for
producing reservoir fluid from a reservoir within a subterranean formation via
the
wellbore. "Reservoir fluid" includes fluid that is contained within a
reservoir. The
reservoir fluid can also include fluids injected into the reservoir for
effecting
stimulation of resident fluids within the reservoir. Reservoir fluid can be
liquid
material, gaseous material, or a mixture of liquid material and gaseous
material. In
some embodiments, for example, the reservoir fluid includes hydrocarbon
material,
such as oil, natural gas condensates, or any combination thereof. In those
embodiments where the reservoir fluid includes hydrocarbon material, in some
of
these embodiments, for example, the reservoir fluid also includes water.
[0055] In some embodiments, for example, the system includes a
production
string, including a reservoir production assembly, disposed within the
wellbore. The
reservoir production assembly includes a pump and a pressurized gas-depleted
reservoir flow conductor (e.g. production tubing). The pump includes a suction
(e.g.
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Date Recue/Date Received 2022-01-21
an intake) and a discharge. The pressurized gas-depleted reservoir flow
conductor
is fluidly coupled to the pump discharge for conducting reservoir fluids to
the
surface.
[0056] Electrical submersible pumps (ESP) are a type of centrifugal
pump that
are commonly used in hydrocarbon operations for lifting large volumes of
reservoir
fluid from a wellbore 118. Figure 1 shows an example embodiment of an ESP
system 100 deployed in a wellbore 118. An ESP system generally comprises a
centrifugal pump (i.e. the ESP) 106, a motor 102, a seal chamber section 104,
and
surface controls 108. These components are generally comprised within tubing
hung from the wellhead (i.e. the surface 120 of the well) with the pump at the
upper end and the motor at the lower end. In some embodiments, the ESP system
100 can include other components, such as a gas separator 114.
[0057] In some embodiments, the centrifugal pump 106 in an ESP system
100 is multi-staged, meaning that it is generally designed with two or more
impellers. The stages of the centrifugal pump 106 are generally stacked
vertically.
These impellers can be installed on the same shaft but can also be installed
on
different impeller shafts. The pump 106 can be designed to direct fluid from
the
discharge of one impeller to the inlet of the next impeller. The use of
several stages
in the centrifugal pump 106 allows the fluid to gain more pressure than with a
single stage. As the fluid being pumped leaves each stage of the pump 106, the
fluid has a higher pressure than it had upon entering the stage of the pump
106. As
the fluid passes through all of the pump stages, it gains pressure
incrementally
such that upon leaving the pump 106, the fluid has reached a desired discharge
pressure that provides the fluid with sufficient energy to travel to the
surface 120 of
the well.
[0058] ESP systems 100 are typically deployed in wellbores 118 with a
limited
diameter, which limits the ability of a single impeller to generate the
necessary
pump head. Accordingly, several stages are combined in order to maintain the
limited diameter of the well casing and supply the required pump head. Each
stage
Date Recue/Date Received 2022-01-21
of the pump 106 can add energy to the fluid in the form of increased velocity
and
pressure.
[0059] The motor 102 in an ESP system 100 is generally an
electromechanical
motor that can convert electrical energy into mechanical (i.e. rotational)
energy.
The motor 102 is located below the centrifugal pump 106 in an ESP system 100.
The motor 102 is generally designed to operate within the high temperatures
(e.g.
up to 500 F) and high pressures (e.g. up to 5000 psi) that exist within the
wellbore
118. The motor 102 in an ESP system 100 is located below the pump 106, for
submersion within wellbore fluids. This allows the wellbore fluids to act as
cooling
agents for the motor 102.
[0060] The seal chamber section 104 is located between the motor 102
and
the pump 106 and isolates the motor 102 from the well fluid. The seal section
104
also houses the thrust bearing that carries the axial thrust of the pump 106
and can
assist in equalizing the pressure within the wellbore 118 with the pressure
inside
the motor 102. The seal chamber section 104 is generally provided to provide
increased motor 102 protection.
[0061] The surface controls or surface equipment 108 includes a
variety of
equipment used in monitoring and controlling well performance and operation.
The
surface equipment 108 includes the well tubing head which is designed to
support
the downhole equipment (e.g. motor, seal section, centrifugal pump). The
surface
equipment 108 can also include a system controller 110 and a variable
frequency
drive (VFD). The system controller 110 can comprise a control and data
acquisition
system or other controller which allows operators and engineers to observe the
sensed data from a variety of components in the ESP system 100. The VFD uses
variable frequency and voltage to vary the speed of the rotor, as well as the
torque
applied to the rotor. The VFD is connected to the system controller 110 such
that
operators can monitor the applied frequency and voltage, and monitor the
corresponding torque being applied to the rotor, and also monitor the speed of
the
rotor. The VFD enables the ESP system 100 to operate continuously and provide
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Date Recue/Date Received 2022-01-21
variable flow and pressure control, which allows operators to respond to
changing
operating conditions, and provides increased productivity, flexibility in the
process
controls, and improved energy savings.
[0062] The ESP system 100 can also contain instruments 112, such as
downhole sensors, in order to monitor wellbore condition and ESP conditions,
such
as pump intake pressures and temperatures, pump discharge pressures and
temperatures, and vibration. These sensors 112 can be connected to the system
controller 110 such that the wellbore conditions and ESP conditions can be
monitored throughout the operational life of the ESP. The downhole instruments
112 can be located below the other ESP components, as depicted in Figure 1. In
other example embodiments, the downhole instruments 112 can be located at
various locations in the wellbore 126. For example, there can be sensors
located at
the intake of the pump 106, in order to monitor the conditions of the fluid,
wellbore
118 and the ESP system 100 at the pump intake.
[0063] The surface equipment 108 can also include an electrical supply
system, which can provide electrical energy to the motor 102, and any other
electrical equipment, such as monitoring instruments, controllers or other
necessary electrical equipment. Electrical energy can be provided to the motor
102,
and any other downhole electrical components, through a power cable 116
extending from the electrical supply system.
[0064] Operators can use the controller 110 to monitor the pump
parameters,
including those parameters monitored by the VFD (such as, for example, the
torque
applied to the rotor, and the speed of the rotor), for example, using a
computer or
a mobile device connected to the controller 110. These pump parameters can be
stored as data over time in order to review and monitor the pump historical
data.
This data can be continuously monitored (i.e. updated in real time), or can be
collected and stored discretely, for example data can be collected in one
minute
intervals.
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[0065] By monitoring the pump parameters, in particular the torque
being
applied to the rotor and the speed of the rotor, in this manner, operators are
able
to monitor the pump operation and identify potential and actual problems with
operation. In some embodiments, the controller 110 can be configured to
suspend
pump operation (i.e. suspend rotation of the rotor) when the controller
detects that
a rotor has failed. In other example embodiments, the controller 110 can be
configured to provide an alert or a notification to an output device, such as
a
computer or mobile device, to notify the operator(s) that the rotor has
failed. In
those embodiments where the pumping system is disposed within a wellbore, in
some of these embodiments, for example, after the suspending of pump
operation,
the pumping system is removed from the wellbore.
[0066] In some embodiments, for example, sensing of a decrease (e.g.
an
absence) in torque being applied to the rotor is not indicative of rotor
failure, such
that further analytical evaluation is performed for determining a cause for
the
decrease (e.g. absence) in torque being applied.
[0067] The components of an ESP system 100 are arranged in series,
with the
motor 102 at the lower end of the ESP system 100 and the surface controls 108
at
the top end (i.e. the surface 120). This arrangement allows the wellbore 118
to
have a limited diameter while allowing the system to pump large volumes of
reservoir fluid. This arrangement also allows the motor 102 and the pump 106
to
operate on the same shaft (of the rotor).
[0068] ESPs, like other mechanical equipment, are prone to equipment
failures and there are various problems which can impact the operation of the
ESP
system. For example, components can fail physically due to wear over time or
due
to solids or gases within the wellbore. Problems with an ESP can arise in a
variety
of circumstances, such as when the ESP has low productivity, or when the ESP
trips
due to a detected underload condition (i.e. the ESP is not lifting a
sufficient volume
of fluids).
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Date Recue/Date Received 2022-01-21
[0069] Due to the limited diameter of wellbores in which ESP systems
are
deployed, it can be challenging to diagnose problems with the ESP as they
arise.
The configuration of the wellbore mean that operators and engineers cannot
observe downhole conditions and thus cannot diagnose problems with ESPs
without
the use of other equipment. Moreover, even if other equipment, such as
downhole
sensors, suggest certain problems with the ESP system, it is still challenging
to
determine the specific cause of the problems without observing the equipment.
Thus, it is often necessary to remove the equipment from the wellbore in order
to
evaluate and diagnose the cause of the problems.
[0070] In order to remove the ESP equipment from the wellbore, production
from the wellbore must be stopped and the ESP system must be flushed of any
fluid
and removed from the wellbore in order to inspect the ESP system. This is a
time-
consuming and costly process, both in terms of the cost to remove the ESP
system
from the wellbore, but also in the loss of productivity of the well. However,
certain
problems, such as gas-locking, can be remedied without the need to remove the
equipment from the well. But, without being able to accurately diagnose the
cause
of the problems with the ESP system, the flushing and removal of the ESP
equipment is often required, even when the cause of the problems could have
been
solved without the removal of the ESP equipment.
[0071] A common issue with ESPs occurs when there is a rotor failure, for
example a fractured or snapped shaft. In the present disclosure, a rotor
failure can
include cracking, fracturing, breaking or snapping of a shaft . It will be
understood
that a rotor failure can refer to any problem with the rotor that causes the
rotor to
disengage from the impellers. When the rotor fails in an ESP, the system loses
productivity, but it is not clear, simply from the loss of productivity, that
the issue is
a rotor failure. In particular, when it is suspected that an ESP has a rotor
failure,
the ESP must be removed from the wellbore and inspected. Rotor failure
generally
occurs through two failure modes.
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Date Recue/Date Received 2022-01-21
[0072] The first failure mode occurs through the flux of solids (e.g.
sand)
and/or cold bitumen entering in the stages of the centrifugal pump. This
typically
results in a dramatic spike in torque and electric current for a short period
of time
(i.e. a few minutes or hours) before the shaft snaps. When the dramatic spike
in
torque and/or electric current is detected, the ESP can be programmed to trip
in
order to prevent the shaft from breaking. However, the rotor can still fail
even with
the ESP programmed to prevent rotor failures.
[0073] The second failure mode occurs due to a slow degradation of
the rotor
integrity. This degradation can occur when the motor and the pump have
different
outer diameters which results in shaft failure at the pump intake. The
degradation
can also occur due to low lubricity in the seal chamber section (i.e. low
lubricity of
the thrust bearing) which can cause excessive heat and eventual rotor failure
at the
thrust bearing.
[0074] Regardless of the failure mode of the rotor, pumps which use
rotational energy transmitted from a motor to the pump can behave in a similar
manner. With respect to ESPs, an indication that a rotor can have failed can
be
when the ESP trips. An ESP trip can be caused by a variety of conditions
within the
ESP and thus not every single ESP trip is indicative of a rotor failure.
[0075] When a possible rotor failure is detected, for example, when
the pump
has reduced or limited production, operators and engineers may know that there
is
a problem with the pumping system but cannot necessarily identify the source
of
the problem. Because identifying that a rotor has failed often requires the
removal
of the equipment from the installed location, operators and engineers will
generally
take time to troubleshoot the problem before resorting to the costly and time-
consuming process of removing the pump from the installed location.
[0076] Pump parameters, such as operating temperatures, operating
torques
(torque being applied to the rotor), operating speeds (speed of the rotor),
electrical
currency and frequency inputs, intake and outlet pressures, are often
monitored
throughout the pump operation, especially in large scale productions such as
the
Date Recue/Date Received 2022-01-21
ESPs deployed in hydrocarbon wells. Pump parameters can be monitored using
instrumentation such as instruments that can monitor temperature, pressure,
torque, and speed, and that can be deployed downhole. The use of such
instruments is often inadequate as the downhole conditions can affect the
efficiency
.. and accuracy of these instruments.
[0077] In ESP systems, certain parameters are monitored from the
controller
using the VFD, including the current and frequency applied to the motor, and
the
operating torque and speed. The present disclosure is directed to a method for
identifying a rotor failure using measurement of torque being applied to the
rotor
and measurement of speed of the rotor.
[0078] In order to identify a rotor failure in a pump, rotor data, in
particular,
data pertaining to the speed of the rotor and data pertaining to torque being
applied to the rotor, must be monitored throughout pump operation (such as,
for
example, while fluid (e.g. reservoir fluid) is being pumped by the pumping
system
(such as, for example, via a wellbore, from the subterranean formation to the
surface). The monitored torque data includes measurements of the torque being
applied to the rotor. Similarly, the monitored speed data includes
measurements of
the rotor speed as seen at the motor. In some embodiments, the torque data and
the speed data are collected via the VFD (with a torque sensor and a speed
sensor,
respectively) and stored in the controller. This data can be monitored
continuously,
or in discrete intervals, for example on a minute-by-minute basis. Based on
this
monitored rotor data, it is possible to determine a shaft failure condition
(i.e. a
rotor failure).
[0079] Under normal operation, the torque being applied to the rotor
and the
speed of the rotor are directly proportional. In other words, when the speed
of the
is increased, the torque will also increase. Similarly, when the speed is
decreased
the torque will also decrease.
[0080] Table 1 below shows example data from an ESP operating under
normal conditions. In this example, the ESP was tripped (i.e. taken out of
16
Date Recue/Date Received 2022-01-21
operation) resulting in torque and speed measurements of zero. However, prior
to
the torque and speed measurements being zero, the torque and speed
measurements showed very little variance and maintained the directly
proportional
relationship that is expected under normal operation.
Table 1: Example torque and speed measurements under normal ESP operation
1Speed 1Torque Current 1
1- 105G-8160-LM/HZ.CV 1105G-8160-105G-8160-
108-May-20 00:0009 72.459938051 20.267982 29.701251
1- ....
108-May-20 02:00:00 72.560218811- 199977471 29.5994
t -1-=
108-May-20 04:00:00+
72.59999847' ZO.330084 30
1 -I-
1 08-May-20 06:00:00 72.63948059 19.884888 29.69835
1 -1-
108-May-20 08:00:00 72.7609787 20.446655 30
1 4-
108-May-20 10:00:00 72.7000045: 20.025032 29
i
108-rviay-20 12:00:00 72.63848114 19.624931 30
? 1
108-May-20 1400:00 72.5 19.938204 29.6996,
1-
108-May-20 16:00001-
7 92.59999847 1 .774216 29.80319
t -1-
108-May-20 18:00:00+ 72.59999847' 20.243784 30
i- i- 1 -I-
08-May-20 20:00:00i- 72.66119385-1- ' 20.20335G 30
-F. _
108-May-20 22:00:004. 72.70000455 Z0.226774 29.30333
! 09-May-20 00:00:001 7270000458 20.341854 30
I _ '-t-
09-May-20 02:00:00 71300003052(299427 30
09-May-20 04:00:00 72.80000305 20.1i36647
29.31137
1
09-May-20 06:00:00 0 0 0
! 091-May-20 08:00:00 0 0 0
i 09-May-20 10:00:001 0 0 0
[0081] Thus, one indication that the pump is not operating normally
occurs
when the speed and torque measurements change and do not reflect this directly
proportional relationship. When the rotor fails, the rotor is no longer in
contact with
the impeller(s) and thus is not able to apply energy to the fluid. This
results in a
rapid and substantial decrease in torque while the speed of the rotor (as seen
at
the motor) remains substantially constant.
[0082] The torque that is being applied to the rotor, and the speed
of the
rotor, can be monitored throughout the operation of a pump. When the torque
and
speed measurements change over time, but remain proportional to one another,
the pump is operating normally. When there is a relatively substantial
decrease in
the torque being applied to the rotor, while there is an absence of
substantial
17
Date Recue/Date Received 2022-01-21
variability in the speed of the rotor (e.g. the speed remains substantially
constant),
this can be an indication of rotor failure.
[0083] However, a relatively substantial decrease in the torque being
applied
to the rotor, in parallel with an absence of substantial variability in the
speed of the
rotor, does not necessarily signify a rotor failure.
[0084] When the rotor has failed, the rate at which torque decreases
is
relatively fast in comparison to other potential problems with the pump. As
such,
when the decreasing torque time interval is less than five minutes, it is
indicative of
the rotor having failed. When the decreasing torque time interval is greater
than
five minutes, it is likely that the decrease in torque is attributable to
another cause,
rather than rotor failure, such as, for example, gas lock. Under gas lock
conditions,
the applied torque can substantially decrease, while the speed remains
substantially
constant. However, the decrease in applied torque, under gas lock conditions,
occurs over a much longer period of time versus the decrease in applied torque
.. associated with a failed rotor condition.
[0085] Table 2, below, shows an example of torque and speed
measurements
obtained during a pump failure in which gas lock was the cause of the pump
failure.
In this example, the torque measurement begins to decrease on March 26 at
approximately 20:00 and reaches a substantially zero torque value on March 27,
2020 at approximately 8:00 (as can be seen in the outlined box). Although the
gas
lock condition shows a decrease in torque occurring while the speed remains
substantially constant, it takes much longer, in this example between 10 and
12
hours, for the ESP system to reach a torque value of zero. In contrast, when
the
rotor has failed, the torque decreases rapidly such that the torque will
decrease to
.. substantially zero within less than five (5) minutes.
18
Date Recue/Date Received 2022-01-21
Table 2: ESP failure in Gas Lock Condition
!Speed 1Torque Current 1
!114G-8080-11J-11443-808ti114G-8080
t 25-Mar-20 18:00700t 83.900001513 14.97807 35.767031
-4-
25-Mar-20 20:00:00 83.80000305 76.:26 35.117991
:
25-Mar-70 27:00:00 83.80000305 81.91513 36.8829!
:
26-'Mr-2O 00:0000 83.81478119 75.12943 36..88242'
_ -4-
26-Mai-20 02:00:00 83.97161865 75.002331 34..88235!
_ _ +
26-Mar-20 04:00:00 S.3.84.325409 71.84753 33..46334!
I _ +
26-Mar-20 06:00:00 83.9283371 71.96714 34..88332
- _ --
26-Mar-20 08:00:00 K.77157593' 82.912231 37. 4- 8822:1
1 _ _ -
26-Mar-20 10:00:00 83.61373138! 73.7412.6 34.117631
-1-- 1-
26-Mar-20 12:00:00 83.784896851 74.11918 3536751!
-6 +
26-Mar-20 14:00:00 813.300003051 76.9531 361
-I- 6 +
j_26-Mar-20 16:00:00 83.771583561 0.5859.5 34.117491
26-Mar-20 18:00:00 83.843124391 76.80173 35.117661
F.26-Mar-20 20:00:00 83.70000458 i 79.49792. 361
;
26-Mar-20 22:00:00 83.099998471 37.9675 26.116361
.....
27-Mar-2.0 00:00:00 83.02837372 28.08414 251
!
27-Mar-2002:O0:00 83.02842712 21.56345 241
;
27-Mar-20 04:00:00 83.09999847! 22.11082 24.882771
27-Mar-2006d30:00 82.32839203 22.81944 23.882751
i
27-Mar-20 08:00:00 01 0 01
, 27-Mar-20 10:00:00 83.800003051 13.75489 23.76571!
[0086] In this regard, in order to identify whether the rotor of a
pump has
failed, the torque applied to the rotor, and the speed of the rotor
(collectively, the
monitored rotor data) are monitored during a monitoring time interval. A rotor
failure condition can be identified based on the monitored rotor data.
[0087] In some embodiments, for example, the rotor failure condition
is
identified based on monitored rotor data which is representative of a
substantial
decrease in torque being applied to the rotor, while there is an absence of
substantial variability in the speed of the rotor, and which is obtained over
a
relatively short time interval (a decreasing torque profile-defining time
interval). In
other words, a substantial decrease in the torque being applied to the rotor,
occurring while there is an absence of substantial variability in the speed of
the
rotor, and occurring over a relatively short time interval, signifies a rotor
failure. In
some embodiments, for example, the decrease, in torque being applied to the
rotor, is a decrease from a baseline applied torque.
19
Date Recue/Date Received 2022-01-21
[0088] Referring to Figure 2, in some embodiments, for example, the
monitored rotor data, upon which the determination of a rotor failure
condition is
based, defines rotor failure-indicative data that is representative of a
decreasing
applied torque profile (ATP), of torque being applied to the rotor, while
there is an
absence of substantial variability, in the speed of the rotor, and spanning
the
decreasing torque profile-defining time interval (defined by the time interval
between t1 and t2). The decreasing applied torque profile defines a
substantial
decrease in torque, being applied to the rotor, and the substantial decrease
in
torque is a decrease from a baseline applied torque (BAT), such that the
decreasing
applied torque profile defines the baseline applied torque (BAT).
[0089] In some embodiments, for example, the substantial decrease, in
torque being applied to the rotor, is a decrease of at least 50%, such as, for
example, at least 75%, such as, for example, at least 90%. In some
embodiments,
for example, the substantial decrease is 100%. Where the substantial decrease
is
100%, the substantial decrease is with effect that there is an absence of
torque
being applied to the rotor (such that the measured torque has a zero value).
[0090] In some embodiments, for example, the decreasing torque
profile-
defining time interval is less than ten (10) minutes, such as, for example,
less than
five (5) minutes, such as, for example, less than one (1) minute.
[0091] In some embodiments, for example the absence of substantial
variability, in the speed of the rotor, is an absence of variability of
greater than ten
(10) %, such as, for example, greater than five (5)%.
[0092] In some embodiments, for example, the baseline applied torque
is at
least 40 newton metres, such as, for example, at least 80 newton metres.
[0093] When the rotor failure condition is detected, operators and
engineers
can be notified that the pump must be removed from its installed location for
maintenance or replacement. For example, the controller can send an alarm or
notification to a computer, mobile device or other output device such that
operators
Date Recue/Date Received 2022-01-21
and engineers are aware that the problems with the pump are caused by a rotor
failure. In some embodiments, the controller can be configured to shut down
the
pumping system in response to the detection that the rotor has failed. By
shutting
down the pumping system, other equipment or pump components can be protected
from further damage caused by the failed rotor.
[0094] Referring to Figure 3, in some embodiments, for example, the
rotor,
briefly, experiences an increase in applied torque (i.e. torque-up) from an
initial
torque TQ1 to an increased torque TQ2, over the time interval defined between
time TO and time Ti, and then the applied torque decreases, over the time
interval
defined between time Ti and T2, such the applied torque returns to TQ3, below
its
initial torque TQ1 (in some embodiments, for example, the decrease could be
such
that the applied torque returns to TQ1), while the rotor speed does not vary
substantially. When this occurs, the decrease in applied torque, from the
applied
torque TQ2 to the applied torque TQ3, can be sufficiently substantial such
that the
system could, potentially, erroneously associate the monitored rotor data with
a
potential rotor failure, where the time interval defined between time Ti and
time T2
is sufficiently short (e.g. less than ten (10) minutes). For example, if TQ2
is 50%
greater than TQ1, and TQ3 is 10 /0 less than TQ1, then the decrease from TQ2
to
TQ3 is sufficiently substantial (the decrease is greater than 50%) to,
potentially,
erroneously associate the monitored rotor data with a potential rotor failure.
[0095] To mitigate versus this erroneous result, in some embodiments,
for
example, the monitored torque data, within a preceding time interval of five
(5)
minutes that immediately precedes the decreasing torque profile-defining time
interval, defines torque data that is representative of a minimum applied
torque,
applied to the rotor, during the preceding time interval, and the baseline
applied
torque, defined by the decreasing applied torque profile, has a value that is
less
than or equal to that of the minimum applied torque. In this respect, the
substantial decrease in torque, upon which the determination of a rotor
failure
condition is based, is measured from the "baseline applied torque", defined by
the
decreasing applied torque profile, and which has a value that is less than or
equal
21
Date Recue/Date Received 2022-01-21
to that of the "minimum applied torque", which is defined during the
"preceding
time interval".
[0096] In those cases where there is an increase in applied torque,
due to
torque-up, from TQ1 to TQ2, and a subsequent decrease in applied torque to
TQ3,
the decrease in applied torque is not measured from TQ2, as the baseline
applied
torque, defined by the decreasing applied torque profile, from which the
decrease is
measured, would be defined by TQ1 at time T1A, and the decrease in applied
torque would be measured by subtracting TQ3 from TQ1, the baseline applied
torque (BAT), as opposed to subtracting TQ3 from TQ2, and the decrease in
torque
may not be sufficient to be indicative of a rotor failure condition. For
example, and
referring to Figure 4, if TQ2 is 50% greater than TQ1, and TQ3 is 10% less
than
TQ1, then the decrease from TQ1 to TQ3 is not sufficiently substantial (the
decrease is less than 50%) to erroneously associate the monitored rotor data
with a
potential rotor failure (irrespective of whether the time interval defined
between
T1A and T2 is sufficiently short, as defined above), even though the decrease
from
TQ2 to TQ3 is greater than 50%, as most of the profile, between TQ2 and TQ3,
does not qualify as a "decreasing applied torque profile". This is because
most of
the profile, between TQ2 and TQ3, is defined before time T1A, which means that
only the monitored rotor data beyond time T1A (i.e. that portion of the
profile
ATP1) is eligible for consideration to identify a rotor failure condition, as
the
decrease in applied torque before time T1A is not "a decrease from the
baseline
applied torque", as the baseline applied torque is measured as being "a value
that
is less than or equal to that of the minimum applied torque". Alternatively,
and
referring to Figure 5, in those cases where TQ3 is more than 50% less than
TQ1,
and the time interval defined between time T1A and T2 is sufficiently short
(e.g.
less than ten (10) minutes), then the decrease is sufficiently substantial
(the
decrease is greater than 50%) to be indicative of a rotor failure condition.
[0097] Although the present disclosure describes methods and
processes with
steps in a certain order, one or more steps of the methods and processes can
be
22
Date Recue/Date Received 2022-01-21
omitted or altered as appropriate. One or more steps can take place in an
order
other than that in which they are described, as appropriate.
[0098] Although the present disclosure is described, at least in
part, in terms
of methods, a person of ordinary skill in the art will understand that the
present
disclosure is also directed to the various components for performing at least
some
of the aspects and features of the described methods, either by way of
hardware
components, software or any combination of the two. Accordingly, the technical
solution of the present disclosure can be embodied in the form of a software
product. A suitable software product can be stored in a pre-recorded storage
device
or other similar non-volatile or non-transitory computer readable medium,
including
DVDs, CD-ROMs, USB flash disk, a removable hard disk, or other storage media,
for
example. The software product includes instructions tangibly stored thereon
that
enable a processing device (e.g., a personal computer, a server, or a network
device) to execute examples of the methods disclosed herein. In general, the
software improves the operation of the hardware in one or more ways.
[0099] The present disclosure can be embodied in other specific forms
without
departing from the subject matter of the claims. The described example
implementations are to be considered in all respects as being only
illustrative and
not restrictive. Selected features from one or more of the above-described
implementations can be combined to create alternative implementations not
explicitly described, features suitable for such combinations being understood
within the scope of this disclosure.
23
Date Recue/Date Received 2022-01-21
