U.S. patent application number 14/135979 was filed with the patent office on 2015-06-25 for detection and identification of fluid pumping anomalies.
This patent application is currently assigned to Schlumberger Technology Corporation. The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Kai Hsu, Sepand Ossia.
Application Number | 20150176389 14/135979 |
Document ID | / |
Family ID | 53399469 |
Filed Date | 2015-06-25 |
United States Patent
Application |
20150176389 |
Kind Code |
A1 |
Hsu; Kai ; et al. |
June 25, 2015 |
Detection And Identification Of Fluid Pumping Anomalies
Abstract
A method for monitoring operation of a pumping system for
pumping anomalies is provided. In one embodiment, the method
includes operating a pump of a downhole tool to pump fluid through
the downhole tool and continually measuring an operational
parameter of the downhole tool over a period of time during pumping
of the fluid through the downhole tool. The measurements of the
operational parameter can be filtered, and the filtered
measurements can be monitored to enable detection of pumping
anomalies in the downhole tool. Additional systems, devices, and
methods are also disclosed.
Inventors: |
Hsu; Kai; (Sugar Land,
TX) ; Ossia; Sepand; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Assignee: |
Schlumberger Technology
Corporation
Sugar Land
TX
|
Family ID: |
53399469 |
Appl. No.: |
14/135979 |
Filed: |
December 20, 2013 |
Current U.S.
Class: |
166/250.01 ;
166/66 |
Current CPC
Class: |
E21B 49/10 20130101;
E21B 49/08 20130101 |
International
Class: |
E21B 47/00 20060101
E21B047/00; E21B 34/06 20060101 E21B034/06; E21B 47/06 20060101
E21B047/06 |
Claims
1. A method comprising: operating a pump of a downhole tool to pump
fluid through the downhole tool; continually measuring an
operational parameter of the downhole tool over a period of time
during pumping of the fluid through the downhole tool; filtering
the measurements of the operational parameter; and monitoring the
filtered measurements of the operational parameter to enable
detection of pumping anomalies in the downhole tool.
2. The method of claim 1, wherein operating the pump of the
downhole tool includes operating a bidirectional displacement pump
having a reciprocating piston and monitoring the filtered
measurements of the operational parameter enables detection of
half-stroking by the bidirectional displacement pump.
3. The method of claim 2, comprising identifying one or more
potentially faulty valves in the downhole tool based on position
data of the reciprocating piston and the detection of the
half-stroking by the bidirectional displacement pump.
4. The method of claim 1, wherein filtering the measurements of the
operational parameter includes applying a median filter to the
measurements of the operational parameter.
5. The method of claim 4, wherein the pump has a displacement
chamber for receiving the fluid and applying the median filter to
the measurements of the operational parameter includes applying the
median filter to measurements of the operational parameter within a
time window having a size that is less than the volume of the
displacement unit chamber divided by an operated flow rate of the
pump during the period of time.
6. The method of claim 1, wherein the operational parameter
includes inlet pressure measured within the downhole tool upstream
from the pump and monitoring the filtered measurements of the
operational parameter includes comparing filtered inlet pressure
measurements to a formation pressure for a formation from which the
fluid is drawn by the downhole tool.
7. The method of claim 1, wherein the operational parameter
includes outlet pressure measured within the downhole tool
downstream from the pump and monitoring the filtered measurements
of the operational parameter includes comparing filtered outlet
pressure measurements to a wellbore pressure for a wellbore in
which the downhole tool is disposed.
8. The method of claim 1, wherein the operational parameter
includes alternator current provided by an alternator to a motor
for driving the pump and monitoring the filtered measurements of
the operational parameter includes comparing filtered alternator
current measurements to a current threshold value, or wherein the
operational parameter includes pump flow rate and monitoring the
filtered measurements of the operational parameter includes
comparing filtered pump flow rate measurements to a flow rate
threshold value.
9. The method of claim 1, wherein continually measuring the
operational parameter, filtering the measurements of the
operational parameter, and monitoring the filtered measurements of
the operational parameter include continually measuring multiple
operational parameters over the period of time, filtering the
measurements of the multiple operational parameters, and monitoring
the filtered measurements of the multiple operational parameters to
enable detection of pumping anomalies in the downhole tool.
10. The method of claim 9, comprising aggregating results of the
monitoring of the filtered measurements of two or more of the
multiple operational parameters to reduce the likelihood of false
positives in the detection of pumping anomalies in the downhole
tool.
11. The method of claim 1, wherein continually measuring the
operational parameter of the downhole tool over the period of time
during pumping of the fluid through the downhole tool includes
measuring the operational parameter at a rate between 1 Hz and 10
Hz.
12. A method comprising: moving a piston within a pump in a
periodic manner; drawing fluid into a first chamber of the pump and
expelling fluid from a second chamber of the pump by moving the
piston in a first axial direction; changing the direction of
movement of the piston from the first axial direction to a second
axial direction opposite the first axial direction so as to draw
fluid into the second chamber of the pump and expel fluid from the
first chamber of the pump; obtaining measurements related to the
operation of the pump for a time window that is less than one-half
of the period of the movement of the piston within the pump;
filtering the measurements obtained for the time window; and
determining whether a fault condition exists for the pump based on
the filtered measurements.
13. The method of claim 12, wherein filtering the measurements
obtained for the time window includes applying a trimmed mean
filter to the measurements obtained for the time window.
14. The method of claim 12, wherein obtaining measurements related
to the operation of the pump includes obtaining at least one of an
inlet pressure upstream of the pump, an outlet pressure downstream
of the pump, or an alternator current.
15. The method of claim 12, wherein determining whether the fault
condition exists for the pump based on the filtered measurements
includes determining whether the magnitude of the difference
between a filtered pressure measurement and a reference pressure is
below a threshold value.
16. The method of claim 12, wherein the pump is disposed in a
downhole tool.
17. A downhole tool comprising: an intake configured to receive
formation fluid within a flowline of the downhole tool; a pump in
fluid communication with the flowline so as to enable the pump to
draw the formation fluid into the downhole tool via the flowline
and to expel the formation fluid from the downhole tool; a sensor
configured to measure an operational parameter of the downhole
tool; and a controller operable to detect pumping anomalies during
operation of the pump based on filtered measurements of the
operational parameter collected via the sensor.
18. The downhole tool of claim 17, wherein the controller is
operable to filter measurements of the operational parameter
collected via the sensor.
19. The downhole tool of claim 18, wherein the controller is
operable to apply a median filter to the measurements of the
operational parameter collected via the sensor and to compare the
filtered measurements of the operational parameter to a threshold
value to detect the pumping anomalies.
20. The downhole tool of claim 17, comprising a plurality of check
valves in fluid communication with the pump, wherein the controller
is operable to identify a proper subset of potentially faulty check
valves from the plurality of check valves based on a detected
pumping anomaly.
Description
BACKGROUND
[0001] Wells are generally drilled into subsurface rocks to access
fluids, such as hydrocarbons, stored in subterranean formations.
The formations penetrated by a well can be evaluated for various
purposes, including for identifying hydrocarbon reservoirs within
the formations. During drilling operations, one or more drilling
tools in a drill string may be used to test or sample the
formations. Following removal of the drill string, a wireline tool
may also be run into the well to test or sample the formations.
These drilling tools and wireline tools, as well as other wellbore
tools conveyed on coiled tubing, drill pipe, casing or other means
of conveyance, are also referred to herein as "downhole tools."
Certain downhole tools may include two or more integrated collar
assemblies, each for performing a separate function, and a downhole
tool may be employed alone or in combination with other downhole
tools in a downhole tool string.
[0002] In some instances, formation evaluation involves drawing
fluid from the formation into a downhole tool. A pump in the
downhole tool can be used to initiate a drawdown to cause fluid to
enter the downhole tool from the formation. Once drawn from the
formation, the fluid can be analyzed within the tool or samples of
the fluid can be stored within the tool for later analysis. The
pump can also be operated to route formation fluid within the tool
and expel the fluid into the wellbore.
SUMMARY
[0003] Certain aspects of some embodiments disclosed herein are set
forth below. It should be understood that these aspects are
presented merely to provide the reader with a brief summary of
certain forms the invention might take and that these aspects are
not intended to limit the scope of the invention. Indeed, the
invention may encompass a variety of aspects that may not be set
forth below.
[0004] In one embodiment of the present disclosure, a method
includes operating a pump of a downhole tool to pump fluid through
the downhole tool. An operational parameter of the downhole tool
can be continually measured over a period of time during pumping of
the fluid through the downhole tool. The method also includes
filtering the measurements of the operational parameter and
monitoring the filtered measurements to enable detection of pumping
anomalies in the downhole tool.
[0005] In another embodiment, a method includes moving a piston
within a pump in a periodic manner, drawing fluid into a first
chamber of the pump and expelling fluid from a second chamber of
the pump by moving the piston in a first direction, and changing
the direction of movement of the piston from the first direction to
an opposite, second direction so as to draw fluid into the second
chamber of the pump and expel fluid from the first chamber of the
pump. The method also includes obtaining measurements related to
the operation of the pump for a time window that is less than
one-half of the period of the movement of the piston within the
pump and filtering the measurements obtained for the time window.
Additionally, the method includes determining whether a fault
condition exists for the pump based on the filtered
measurements.
[0006] Another embodiment includes a downhole tool having an intake
for receiving formation fluid within a flowline of the downhole
tool. This downhole tool also includes a pump connected to the
flowline so that the pump can draw the formation fluid into the
downhole tool through the flowline and expel the formation fluid
from the downhole tool. A sensor of the downhole tool can measure
an operational parameter of the downhole tool and a controller of
the downhole tool can detect pumping anomalies during operation of
the pump based on filtered measurements of the operational
parameter collected by the sensor.
[0007] Various refinements of the features noted above may exist in
relation to various aspects of the present embodiments. Further
features may also be incorporated in these various aspects as well.
These refinements and additional features may exist individually or
in any combination. For instance, various features discussed below
in relation to the illustrated embodiments may be incorporated into
any of the above-described aspects of the present disclosure alone
or in any combination. Again, the brief summary presented above is
intended just to familiarize the reader with certain aspects and
contexts of some embodiments without limitation to the claimed
subject matter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] These and other features, aspects, and advantages of certain
embodiments will become better understood when the following
detailed description is read with reference to the accompanying
drawings in which like characters represent like parts throughout
the drawings, wherein:
[0009] FIG. 1 generally depicts a drilling system having a testing
tool in a drill string in accordance with one embodiment of the
present disclosure;
[0010] FIG. 2 generally depicts a testing tool deployed within a
well on a wireline in accordance with one embodiment;
[0011] FIG. 3 is a block diagram of components of a testing tool in
accordance with one embodiment;
[0012] FIG. 4 is a block diagram of components in one example of a
controller for the testing tool of FIG. 3;
[0013] FIG. 5 depicts one example of a pump and a network of check
valves that can be used in the testing tool of FIG. 3 for pumping
fluid through the testing tool in accordance with one
embodiment;
[0014] FIG. 6 graphically depicts various measured operational
parameters for a pumping system in accordance with one
embodiment;
[0015] FIG. 7 is a flow chart representing a method for measuring
and filtering operational parameters of a pumping system to detect
pumping anomalies in accordance with one embodiment;
[0016] FIG. 8 is a flow chart representing the application of a
filter to a measured operational parameter in accordance with one
embodiment;
[0017] FIG. 9 is a flow chart representing the determination of a
condition of a pumping system based on measured inlet pressure data
in accordance with one embodiment;
[0018] FIG. 10 is a flow chart representing the determination of a
condition of a pumping system based on measured outlet pressure
data in accordance with one embodiment;
[0019] FIG. 11 is a flow chart representing the determination of a
condition of a pumping system based on measured alternator current
data in accordance with one embodiment;
[0020] FIG. 12 graphically depicts the detection of half-stroking
by a pump from filtered inlet pressure data in accordance with one
embodiment;
[0021] FIG. 13 graphically depicts the detection of half-stroking
by the pump from filtered alternator current data in accordance
with one embodiment;
[0022] FIG. 14 graphically depicts the detection of half-stroking
by the pump from both inlet pressure data and outlet pressure data
in accordance with one embodiment;
[0023] FIG. 15 is a flow chart representing a technique for
aggregating status indications from multiple data sources to
determine a pumping condition in accordance with one embodiment;
and
[0024] FIG. 16 generally depicts motion of a piston within a pump
and two fault conditions associated with half-stroking in
accordance with one embodiment.
DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS
[0025] It is to be understood that the present disclosure provides
many different embodiments, or examples, for implementing different
features of various embodiments. Specific examples of components
and arrangements are described below for purposes of explanation
and to simplify the present disclosure. These are, of course,
merely examples and are not intended to be limiting.
[0026] When introducing elements of various embodiments, the
articles "a," "an," "the," and "said" are intended to mean that
there are one or more of the elements. The terms "comprising,"
"including," and "having" are intended to be inclusive and mean
that there may be additional elements other than the listed
elements. Moreover, any use of "top," "bottom," "above," "below,"
other directional terms, and variations of these terms is made for
convenience, but does not mandate any particular orientation of the
components. Further, all ranges specified herein are intended to be
inclusive absent a contrary indication.
[0027] The present disclosure generally relates to detecting
pumping anomalies during operation of a pump, such as a pump within
a downhole tool. As described below, such anomalies can include
"half-stroking" or "no-stroking" by the pump. More specifically,
some embodiments of the present disclosure relate to measuring one
or more operational parameters related to the pumping, applying a
filter to the one or more measured operational parameters, and
monitoring the filtered parameters to detect pumping anomalies. In
at least some embodiments, the measured operational data can be
filtered and monitored in real-time by a downhole tool having the
pump, and the status of the pump can be transmitted from the
downhole tool to the surface.
[0028] As generally noted above, downhole tools are deployed in
various ways to facilitate formation evaluation. By way of example,
and now turning to the drawings, a drilling system 10 with such a
downhole tool is depicted in FIG. 1 in accordance with one
embodiment. While certain elements of the drilling system 10 are
depicted in this figure and generally discussed below, it will be
appreciated that the drilling system 10 may include other
components in addition to, or in place of, those presently
illustrated and discussed. As depicted, the system 10 includes a
drilling rig 12 positioned over a well 14. Although depicted as an
onshore drilling system 10, it is noted that the drilling system
could instead be an offshore drilling system. The drilling rig 12
supports a drill string 16 that includes a bottomhole assembly 18
having a drill bit 20. The drilling rig 12 can rotate the drill
string 16 (and its drill bit 20) to drill the well 14.
[0029] The drill string 16 is suspended within the well 14 from a
hook 22 of the drilling rig 12 via a swivel 24 and a kelly 26.
Although not depicted in FIG. 1, the skilled artisan will
appreciate that the hook 22 can be connected to a hoisting system
used to raise and lower the drill string 16 within the well 14. As
one example, such a hoisting system could include a crown block and
a drawworks that cooperate to raise and lower a traveling block (to
which the hook 22 is connected) via a hoisting line. The kelly 26
is coupled to the drill string 16, and the swivel 24 allows the
kelly 26 and the drill string 16 to rotate with respect to the hook
22. In the presently illustrated embodiment, a rotary table 28 on a
drill floor 30 of the drilling rig 12 is constructed to grip and
turn the kelly 26 to drive rotation of the drill string 16 to drill
the well 14. In other embodiments, however, a top drive system
could instead be used to drive rotation of the drill string 16.
[0030] During operation, drill cuttings or other debris may collect
near the bottom of the well 14. Drilling fluid 32, also referred to
as drilling mud, can be circulated through the well 14 to remove
this debris. The drilling fluid 32 may also clean and cool the
drill bit 20 and provide positive pressure within the well 14 to
inhibit formation fluids from entering the wellbore. In FIG. 1, the
drilling fluid 32 is circulated through the well 14 by a pump 34.
The drilling fluid 32 is pumped from a mud pit (or some other
reservoir, such as a mud tank) into the drill string 16 through a
supply conduit 36, the swivel 24, and the kelly 26. The drilling
fluid 32 exits near the bottom of the drill string 16 (e.g., at the
drill bit 20) and returns to the surface through the annulus 38
between the wellbore and the drill string 16. A return conduit 40
transmits the returning drilling fluid 32 away from the well 14. In
some embodiments, the returning drilling fluid 32 is cleansed
(e.g., via one or more shale shakers, desanders, or desilters) and
reused in the well 14.
[0031] In addition to the drill bit 20, the bottomhole assembly 18
also includes a downhole tool with various instruments that measure
information of interest within the well 14. For example, as
depicted in FIG. 1, the bottomhole assembly 18 includes a
logging-while-drilling (LWD) module 44 and a
measurement-while-drilling (MWD) module 46. Both modules include
sensors, housed in drill collars, that collect data and enable the
creation of measurement logs in real-time during a drilling
operation. The modules could also include memory devices for
storing the measured data. The LWD module 44 includes sensors that
measure various characteristics of the rock and formation fluid
properties within the well 14. Data collected by the LWD module 44
could include measurements of formation pressure, gamma rays,
resistivity, neutron porosity, formation density, sound waves,
optical density, and the like. The MWD module 46 includes sensors
that measure various characteristics of the bottomhole assembly 18
and the wellbore, such as orientation (azimuth and inclination) of
the drill bit 20, torque, shock and vibration, the weight on the
drill bit 20, and downhole temperature and pressure. The data
collected by the MWD module 46 (or by other modules of the
bottomhole assembly 18) can be used to control drilling operations.
The bottomhole assembly 18 can also include one or more additional
modules 48, which could be LWD modules, MWD modules, or some other
modules. It is noted that the bottomhole assembly 18 is modular,
and that the positions and presence of particular modules of the
assembly could be changed as desired.
[0032] The bottomhole assembly 18 can also include other modules.
As depicted in FIG. 1 by way of example, such other modules include
a power module 50, a steering module 52, and a communication module
54. In one embodiment, the power module 50 includes a generator
(such as a turbine) driven by flow of drilling mud through the
drill string 16. In other embodiments, the power module 50 could
also or instead include other forms of power storage or generation,
such as batteries or fuel cells. The steering module 52 may include
a rotary-steerable system that facilitates directional drilling of
the well 14. The communication module 54 enables communication of
data (e.g., data collected by the LWD module 44 and the MWD module
46) between the bottomhole assembly 18 and the surface. In one
embodiment, the communication module 54 communicates via mud pulse
telemetry, in which the communication module 54 uses the drilling
fluid 32 in the drill string as a propagation medium for a pressure
wave encoding the data to be transmitted.
[0033] The drilling system 10 also includes a monitoring and
control system 56. The monitoring and control system 56 can include
one or more computer systems that enable monitoring and control of
various components of the drilling system 10. The monitoring and
control system 56 can also receive data from the bottomhole
assembly 18 (e.g., data from the LWD module 44, the MWD module 46,
and the additional module 48) for processing and for communication
to an operator, to name just two examples. While depicted on the
drill floor 30 in FIG. 1, it is noted that the monitoring and
control system 56 could be positioned elsewhere, and that the
system 56 could be a distributed system with elements provided at
different places near or remote from the well 14.
[0034] Another example of using a downhole tool for formation
testing within the well 14 is depicted in FIG. 2. In this
embodiment, a testing tool 62 is suspended in the well 14 on a
cable 64. The cable 64 may be a wireline cable with at least one
conductor that enables data transmission between the testing tool
62 and a monitoring and control system 66. The cable 64 may be
raised and lowered within the well 14 in any suitable manner. For
instance, the cable 64 can be reeled from a drum in a service
truck, which may be a logging truck having the monitoring and
control system 66. The monitoring and control system 66 controls
movement of the testing tool 62 within the well 14 and receives
data from the tool 62. In a similar fashion to the monitoring and
control system 56 of FIG. 1, the monitoring and control system 66
may include one or more computer systems or devices and may be a
distributed computing system. The received data can be stored,
communicated to an operator, or processed, for instance. While the
testing tool 62 is here depicted as being deployed by way of a
wireline, in some embodiments the tool 62 (or at least its
functionality) is incorporated into or as one or more modules of
the bottomhole assembly 18 of the drill string 16, such as the LWD
module 44 or the additional module 48.
[0035] The testing tool 62 can take various forms. While it is
depicted in FIG. 2 as having a body including a probe module 70, a
fluid analysis module 72, a pump module 74, a power module 76, and
a fluid storage module 78, the testing tool 62 may include
different modules in other embodiments. The probe module 70
includes a probe 82 that may be extended (e.g., hydraulically
driven) and pressed into engagement against a wall 84 of the well
14 to hydraulically couple the probe to a formation and to draw
fluid from the formation into the testing tool 62 through an intake
86. As depicted, the probe module 70 also includes setting pistons
88 that may be extended outwardly to engage the wall 84 and push
the end face of the probe 82 against another portion of the wall
84. In some embodiments, the probe 82 includes a sealing element or
packer that isolates the intake 86 from the rest of the wellbore.
In other embodiments, the testing tool 62 could include one or more
inflatable packers that can be extended from the body of the tool
62 to circumferentially engage the wall 84 and isolate a region of
the well 14 near the intake 86 from the rest of the wellbore. In
such embodiments, the extendable probe 82 and setting pistons 88
could be omitted and the intake 86 could be provided in the body of
the testing tool 62, such as in the body of a packer module housing
an extendable packer. Further, in certain embodiments, the intake
may be provided within a packer (e.g., as a drain within a single
packer) that can be expanded to press the intake against the wall
84.
[0036] The pump module 74 draws fluid from the formation into the
intake 86, through a flowline 92, and then either out into the
wellbore through an outlet 94 or into a storage container (e.g., a
bottle within fluid storage module 78) for transport back to the
surface when the testing tool 62 is removed from the well 14. The
fluid analysis module 72 includes one or more sensors for measuring
properties of the drawn formation fluid (e.g., fluid density,
optical density, and pressure) and the power module 76 provides
power to electronic components of the testing tool 62.
[0037] The drilling and wireline environments depicted in FIGS. 1
and 2 are examples of environments in which a testing tool may be
used to facilitate analysis of a downhole fluid. The presently
disclosed techniques, however, could be implemented in other
environments as well. For instance, the testing tool 62 may be
deployed in other manners, such as by a slickline, coiled tubing,
or a pipe string.
[0038] As noted above, the testing tool 62 can take various forms.
In one embodiment, generally depicted in FIG. 3 as a testing tool
100 (which may also be referred to as a sampling tool), the tool
includes a probe module 102, a combined pump-analysis module 104,
and a fluid storage module 106. The probe module 102 includes an
intake 110, which can be provided in an extendable probe as
described above with respect to FIG. 2. The intake 110 allows fluid
to be drawn from a formation into a flowline 112 of the tool 100.
The probe module 102 can include various components. As presently
depicted, the probe module 102 includes a pressure test chamber 114
(which may also be referred to as a pretest chamber), a pump 116, a
flowline isolation valve 118, a pretest isolation valve 120, an
exhaust valve 122, and a pressure gauge 126, although in other
embodiments the probe module 102 could include other components in
addition to or in place of those generally illustrated in FIG.
3.
[0039] The tool 100 can be used to measure formation pressure by
placing the intake 110 in fluid communication with the formation
while isolating the intake 110 from wellbore pressure (e.g.,
through sealing engagement of the extendable probe against the
wellbore). The pump 116 is then actuated to draw fluid into the
flowline 112 and the pressure test chamber 114. Particularly, in
the presently depicted embodiment, the pump 116 is provided in the
form of a piston positioned within the pressure test chamber 114.
With the intake 110 isolated from wellbore pressure, the flowline
isolation valve 118 and the exhaust valve 122 closed, and the
pretest isolation valve 120 open, the piston of pump 116 can be
retracted to increase the volume of the pressure test chamber 114.
As the piston is retracted in this manner, the pressure at the
intake 110 falls. Once this pressure falls sufficiently below the
formation pressure (in order to breach mud cake formed on the
wellbore face), fluid flows from the formation into the tool 100
via the intake 110. The piston of pump 116 can then be stopped and
fluid pressure within the pressure test chamber 114 increases
toward equilibrium with the formation pressure as fluid from the
formation passes into the tool 100 via the intake 110. The
resulting pressure of the pressure test chamber 114 can then be
read via the pressure gauge 126.
[0040] The depicted probe module 102 also includes a controller 132
for operating various components of the probe module. The
controller 132 could operate such components directly or in
conjunction with other components or systems, such as a hydraulic
control system for actuating hydraulic components. The controller
132 can also receive pressure measurements taken by the pressure
gauge 126 and use those measurements in controlling operation of
the probe module 102. For example, the controller 132 can command
the pump 116 to begin operating to lower the pressure within the
tool (e.g., by retracting a piston in the pressure test chamber
114), detect a pressure increase (via pressure gauge 126) in the
tool indicative of formation fluid breaching the mud cake and
flowing into the tool 100, and then command that the pump 116 stop
to allow the pressure within the pressure test chamber 114 reach
equilibrium with the formation from which the fluid is drawn. The
controller 132 can also command the pump 116 to expel fluid from
the chamber 114 and can control the rate at which the pump 116
operates.
[0041] Also, the controller 132 can command operation of the valves
118, 120, and 122 either directly (in the case of electromechanical
valves) or via a hydraulic system (in the case of hydraulically
actuated valves). The flowline isolation valve 118 can be an
independently controlled valve, such as a solenoid valve actuated
by the controller 132 to selectively isolate other modules of the
tool 100 from the intake 110. The pretest isolation valve 120 can
be opened by the controller 132 to permit fluid communication
between the pressure test chamber 114 and the flowline 112, and the
exhaust valve 122 can be opened to allow fluid to be expelled into
the wellbore via an outlet 130.
[0042] The module 104 is depicted as including a pump 140, a
pressure gauge 142 upstream from the pump 140, additional sensors
144, a pressure gauge 146 downstream from the pump 140, a
controller 148, a valve network 150 for controlling flow to and
from the pump 140, and another valve 152. The pump 140 is operable
to route fluid through the tool 100 via the flowline 112 when the
flowline isolation valve 118 is open. In one embodiment described
in greater detail below with respect to FIG. 5, the pump 140 is a
dual-piston reciprocating pump in which a shared rod drives two
pistons in separate chambers such that movement of the shared rod
in one direction causes a suction stroke in a first chamber and a
discharge stroke in a second chamber. The direction of the shared
rod can be reversed to then cause a discharge stroke in the first
chamber and a suction stroke in the second chamber. In other
embodiments, the pump 140 can be provided in different forms.
Indeed, any pump capable of routing fluid within the tool 100 could
be used. Further, the pump 140 can be driven in any suitable
manner. For example, in some embodiments the pump is driven by an
electric motor via a screw actuator.
[0043] With the valve 118 opened, operation of the pump 140 creates
a pressure differential between the formation hydraulically coupled
to the intake 110 and the flowline 112 upstream of the pump 140.
This generally causes fluid to flow from the formation into the
flowline 112 and to be routed through the tool 100 by operation of
the pump 140. The fluid pumped out of the pump 140 can be routed
out into the wellbore via outlet 154 or, if desired, directed to
the fluid storage module 106 by the valve 152 to enable collection
of a sample of the fluid. With fluid being routed through the tool
100 by the pump 140, properties of the fluid can be measured via
the pressure gauges 142 and 146 and the additional sensors 144. The
additional sensors 144 can include any suitable sensors and may be
used to take additional measurements related to fluid routed
through the tool 100. These additional measurements could include
temperature, fluid density, optical density, electrical
resistivity, fluorescence, and contamination, to name but a few
examples. Further, in at least some embodiments, additional sensors
144 are used to measure current from an alternator to a motor for
driving the pump 140 and to measure torque of the motor. While the
module 104 is depicted as including both pumping and analytical
functionality, it will be appreciated that the additional sensors
144 could instead be provided in a separate module (e.g., another
fluid analysis module) of the tool 100. Likewise, either or both of
the pressure gauges 142 and 146 could also be located elsewhere
within the tool 100.
[0044] The controller 148 directs operation (e.g., by sending
command signals) of the pump 140 to control the flow of fluid
routed through the tool by the pump 140. The controller 148 can,
for example, initiate pumping by the pump 140 to begin routing
formation fluid from the intake 110 through the tool 100 and vary
the rate at which the pump 140 operates to control flow
characteristics of the routed fluid. The controller 148 can also
receive data from the pressure gauges 142 and 146 and the
additional sensors 144. This data can be stored by the controller
148 or communicated to another controller or system for analysis.
In at least one embodiment, the controller 148 also analyzes data
received from the pressure gauges 142 and 146 or from the
additional sensors 144. For example, as discussed in greater detail
below, the controller 148 can monitor outputs from the pressure
gauges 142 and 146 and the additional sensors 144 to detect pumping
anomalies within the tool 100.
[0045] The controller 148 could also vary operation of the pump 140
based on pressure measurements (e.g., from gauges 142 and 146) and
could operate the valve 152 to divert fluid to storage devices 158
of the fluid storage module 106 based on analysis of the collected
data indicating that collection of a fluid sample is desired. The
storage devices 158 can include bottles or any other suitable
vessels for retaining fluid samples for later retrieval at the
surface. In at least some embodiments, the valve 156 is a check
valve to inhibit back flow from the module 106 to the module 104,
and the valve 160 is a pressure relief valve to enable fluid to
vent from the module 106 to the wellbore via outlet 162 if the
pressure exceeds a given threshold.
[0046] The controllers 132 and 148 of at least some embodiments are
processor-based systems, an example of which is provided in FIG. 4
and referred to as controller 168. In this depicted embodiment, the
controller 168 includes at least one processor 170 connected, by a
bus 172, to volatile memory 174 (e.g., random-access memory) and
non-volatile memory 176 (e.g., flash memory and a read-only memory
(ROM)). Data 180 and coded application instructions 178 (e.g.,
software that may be executed by the processor 170 to enable the
control and analysis functionality described herein, including the
monitoring of operational data for pumping anomalies within the
tool 100) are stored in the non-volatile memory 176. For example,
the application instructions 178 can be stored in a ROM and the
data can be stored in a flash memory. The instructions 178 and the
data 180 may be also be loaded into the volatile memory 174 (or in
a local memory 182 of the processor) as desired, such as to reduce
latency and increase operating efficiency of the controller
168.
[0047] An interface 184 of the controller 168 enables communication
between the processor 170 and various input devices 186 and output
devices 188. The interface 184 can include any suitable device that
enables such communication, such as a modem. In some embodiments,
the input devices 186 include one or more sensing components of the
tool 100 (e.g., the pressure gauges 126, the pressure gauge 142, an
additional sensor 144, or the pressure gauge 146) and the output
devices 188 include the pumps 116 and 140 and the valves 118, 120,
122, and 152, or other devices that operate such pumps or valves.
The output devices 188 could also include displays, printers, and
storage devices that allow output of data received or generated by
the controller 168.
[0048] As noted above, in at least one embodiment the pump 140 is
provided as a dual-piston reciprocating pump. An example of such a
pump 140 and an associated valve network 150 is generally
illustrated in FIG. 5 in accordance with one embodiment. In this
specific example, the pump 140 is depicted as a bidirectional
positive displacement pump for pumping fluid from a formation 190
via a probe 82, and the valve network 150 is depicted as having
check valves 192, 194, 196, and 198. The check valves 192 and 194
are connected to an inlet line 230, while the check valves 196 and
198 are connected to an outlet line 232 (e.g., toward valve 152 in
FIG. 3). These check valves collectively operate to control flow of
fluid to and from the pump 140.
[0049] The depicted pump 140 includes a shared rod 202 with pistons
204 and 206 on opposite sides of a divider 208. The volumes of
displacement unit chambers 212 and 214 within the pump 140 change
as the rod 202 and pistons 204 and 206 reciprocate, which generally
causes one of these chambers to draw fluid in while causing the
other of these chambers to expel fluid. More specifically, as the
rod 202 is moved to the left, the volume of the chamber 212
(between the piston 204 and the divider 208) increases and the
volume of the chamber 214 (between the piston 206 and the divider
208) decreases. It will be appreciated that wells are often kept in
an overbalanced state, in which wellbore pressure exceeds the
formation pressure to inhibit hydrocarbons or other fluids from
flowing into the well, during drilling and sampling operations. The
increase in the volume of the chamber 212 causes the pressure
within this chamber to decrease (also known as the drawdown
pressure) below the formation pressure, resulting in pressure
decreases within a connecting line 216 and the inlet line 230 and
in formation fluid being drawn into the chamber 212 via the inlet
line 230, the check valve 192, and the connecting line 216. At the
same time, the decrease in the volume of the chamber 214 increases
pressure within the chamber 214, a connecting line 218, and the
outlet line 232 above the wellbore pressure, causing fluid within
the chamber 214 to be expelled out the connecting line 218, through
check valve 198, and out of the tool 100 into the wellbore via the
outlet line 232.
[0050] Once the rod 202 reaches the end of its axial travel to the
left, the rod 202 can be moved in the opposite axial direction
(i.e., to the right in FIG. 5). This, in essence, switches the
operation of the chambers 212 and 214. That is, as the rod 202
moves to the right, the volume of the chamber 212 decreases to
increase pressure within and expel fluid from the chamber 212
(through the connecting line 216, the check valve 196, and the
outlet line 232) and the volume of the chamber 214 increases to
decrease pressure within and draw fluid into the chamber 214
(through the inlet line 230, the check valve 194, and the
connecting line 218). Slack chambers 222 and 224 are isolated from
the chambers 212 and 214 by the pistons 204 and 206. These slack
chambers 222 and 224 are connected together by a fluid line 226 and
can be filled with a control fluid (e.g., hydraulic oil), which can
be pushed back and forth between the slack chambers by movement of
the pistons 204 and 206.
[0051] The rod 202 can be moved within the pump 140 in any suitable
manner. For instance, in some embodiments the rod is driven by a
motor 234 via a screw actuator. As depicted in FIG. 5, the motor
234 is an electric motor that draws current from an alternator 236
driven by a turbine 238 (e.g., a mud turbine of power module 50).
An additional sensor 144 can be connected as shown in FIG. 5 to
measure alternator current drawn by the motor 234. In another
embodiment, the pump can be driven hydraulically using the
hydraulic pressures in the chambers 222 and 224.
[0052] During normal operation of the pump 140 and the valve
network 150 depicted in FIG. 5, the two working sides of the pump
alternate between suction and discharge as described above. But if
one of the check valves 192, 194, 196, or 198 ceases to check fluid
(e.g., from debris caught between a poppet and seat of the check
valve), one of the displacement chambers 212 and 214 could become
inactive. That is, it would not produce fluid from the formation
and, at the same time, would not pump fluid into the wellbore. Such
a condition is known as "half-stroking." In some instances in which
multiple check valves cease to check fluid, both displacement
chambers 212 and 214 could become inactive even with continued
motion of the rod 202 (i.e., a condition known as
"no-stroking").
[0053] FIG. 6 depicts one example of sensor responses of the tool
100 during fluid pumping before and after the onset of
half-stroking by the pump 140. The top two subplots show the inlet
pressure recorded by the pressure gauge 142 and the outlet pressure
recorded by the pressure gauge 146, while the lower two subplots
show the current supplied by the alternator 236 for operating the
pump 140 and the relative position of the piston assembly (rod 202
and pistons 204 and 206) within the pump 140.
[0054] The time of onset of half-stroking by the pump 140 is
represented by line 244 in FIG. 6 (with normal operation
represented to the left of the line 244 and half-stroking operation
represented to the right of the line 244). As may be seen from
these subplots, during normal operation the inlet pressure
generally remains below the formation pressure (represented here by
line 240) and the outlet pressure generally remains above the
wellbore pressure (represented here by line 242).
[0055] The sawtooth features of the charted piston assembly
position indicate the back-and-forth movement of the piston
assembly between the two ends of the pump. When one of the pistons
204 and 206 reaches either end of the chambers 212 or 214, the
piston assembly will stop momentarily as it reverses direction.
This causes the transitory "spike" features depicted during normal
operation in FIG. 6 (i.e., the inlet pressure rising toward the
formation pressure, the outlet pressure falling toward the wellbore
pressure, and the alternator current dropping toward zero). As
depicted in FIG. 6, the piston assembly moves in a periodic manner
at equal rates of speed when stroking from a first end to a second
end and from the second end back to the first end (e.g., from
right-to-left and from left-to-right) such that the period of its
movement is equal to the sum of the times for the forward and
backward strokes. In other embodiments, however, these strokes can
be asymmetric and vary in speed, with strokes in one direction
being completed faster than strokes in the other direction.
[0056] As noted above, half-stroking begins at a time represented
by line 244 in FIG. 6. This pumping anomaly can be recognized by
the inlet pressure response. In this half-stroking condition,
during one stroke the inlet pressure drops in response to producing
fluid from the formation, as is the case with normal operation.
During the reverse stroke, however, the inlet pressure does not
show the same response because one check valve is not functioning
properly. Consequently, the inlet pressure remains at about the
formation pressure during the reverse stroke. In this stroke, no
formation load is realized and, therefore, the current drawn from
the alternator (and the torque applied) by the motor drops to a low
level as shown in FIG. 6; thus, the alternator current or the motor
torque can also be used to detect half-stroking by the pump 140.
Still further, in some instances the outlet pressure can be used to
detect the pumping anomaly. For example, if the fluid expelled from
the pump 140 is routed past the pressure gauge 146 (e.g., to sample
storage 158 and outlet 162), half-stroking is characterized by the
measured outlet pressure alternatingly dropping to and returning
from a level close to the wellbore pressure, as depicted to the
right of line 244 in FIG. 6. In some instances, however, the
expelled fluid may be routed through the valve 152 toward the
outlet 154 without passing to the pressure gauge 146. In such
instances, the outlet pressure measured by the pressure gauge 146
would not contain the diagnostic information that would enable
identification of pumping anomalies. From the above, it will be
appreciated that half-stroking can be diagnosed based on the
alternating pattern of signals between normal and anomalous levels.
Further, while not depicted in FIG. 6, a no-stroking condition can
be diagnosed based on signals remaining at anomalous levels during
consecutive (i.e. forward and back) strokes of the pump, rather
than alternating between the anomalous and normal levels with each
stroke.
[0057] With the foregoing in mind, one example of a process for
detecting fluid pumping anomalies is generally represented by flow
chart 250 in FIG. 7. In this embodiment, a pump (e.g., pump 140) is
operated to pump fluid and operational parameters related to the
pumping are measured, as represented at blocks 252 and 254. These
measurements can include any suitable measurements that can be
analyzed for identifying pumping anomalies, such as inlet pressure
upstream from the pump (e.g., measured with pressure gauge 142),
outlet pressure downstream from the pump (e.g., measured with
pressure gauge 146), alternator current drawn by a pump motor
(e.g., measured with a sensor 144), pump motor torque (e.g.,
measured with another sensor 144), or pump flow rate measured by a
flow meter (which could be provided upstream or downstream from the
pump), to name a handful of examples. Further, the measurements may
be taken continually (such as at a set sampling rate) over a period
of time during pumping. In at least some embodiments, the pump is
integrated into a downhole tool within a well, although the present
techniques can be applied to pumps in non-wellbore or non-oilfield
contexts in other embodiments.
[0058] As represented at block 256, the measured operational
parameters are then filtered in any suitable manner. As described
in greater detail below, in some instances this includes applying a
median filter or a trimmed mean filter to the measured operational
parameters. The filtered measurements can be monitored for pumping
anomalies (block 258). While the measured operational parameters
can be sent to the surface for such filtering and monitoring in
some instances, in other embodiments the measured operational
parameters are filtered and monitored in real-time by a controller
(e.g., the controller 148) in a downhole tool while in a well. In
still other embodiments, the sensors and gauges measuring the
operational parameters could filter the measured parameters before
transmitting them to the controller. The filtering of the measured
operational parameters can remove noise (keeping the smooth,
underlying measurement response) and transitory spikes in the
measurement signal (from the stopping of the piston assembly as it
reverses direction) that could otherwise cause false alarms in the
detection of pumping anomalies.
[0059] Based on the monitoring of the filtered operational
parameters, pumping anomalies, which may also be referred to as
fault conditions, can be identified (block 260). Further, one or
more valves suspected of malfunctioning can also be identified
(block 262). For example, in one embodiment the identification of a
pumping anomaly and the piston position data can be used to
identify a proper subset of valves of the valve network 150 (i.e.,
in the case of the apparatus depicted in FIG. 5, one or more of,
but less than four of, check valves 192, 194, 196, and 198) as
possibly malfunctioning.
[0060] In some embodiments, filtering the measured operational
parameters includes using a real-time algorithm with a moving
window (or buffer) to contain the most recent T.sub.w-seconds of
operational parameter data (e.g., inlet pressure data, outlet
pressure data, or alternator current). The operational parameter
data can be sampled at any desired rate, such as at a rate between
1 Hz and 10 Hz in some embodiments and at a rate of 4 Hz in at
least one embodiment. A median filter can then be applied to the
data in the buffer to sort the data in descending (or ascending)
order and output the data point in the middle of sorted array. Any
suitable size (i.e., T.sub.w) may be chosen for the moving window.
In at least some embodiments, T.sub.w is less than the volume (V)
of fluid the pump is constructed to displace during one full stroke
(e.g., the maximum volume of the displacement unit chamber 212 that
occurs when the piston 204 is moved fully to the left in FIG. 5)
divided by the operated flow rate (q) of the pump. That is:
T w < v q ( 1 ) ##EQU00001##
Stated differently, the time window T.sub.w can be shorter than the
length of time used for one full stroke of the pump (i.e., less
than one-half the period of movement of the piston assembly
assuming constant pumping speed). The time window T.sub.w can also
be sized sufficiently large to prevent an operational parameter
measured during a transitory spike in the signal (such as a spike
associated with a piston reversal in the pump) from being selected
as the median value when the median filter is applied. In at least
one embodiment:
T w .apprxeq. 0.75 v q ( 2 ) ##EQU00002##
Further, the output of the median filter (i.e., the filtered
operational parameters) may be offset or delayed by the half of the
window size (i.e. T.sub.w/2) in order to align with the raw data in
time.
[0061] One example of the application of a median filter is
generally represented in flow chart 270 of FIG. 8. In this example,
a measured operational parameter 272 is added (block 274) to a
buffer 276, such as a first-in, first-out (FIFO) buffer that stores
the most recent T.sub.w-seconds of operational parameter data. In
at least some embodiments, including that represented in FIG. 8,
the newly added operational parameter 272 can also be added (block
278) to a sorted buffer 280. The sorted buffer 280 can generally
include the same operational parameter data for the most recent
T.sub.w-seconds, as in the buffer 276, but the data in the buffer
280 can be sorted by magnitude rather than by time. When a new
measured operational parameter 272 is to be added to both buffers
276 and 280, the oldest measured operational parameter is removed
from both buffers. The new measured operational parameter 272 can
then be sorted into the buffer 280. This allows the new measured
operational parameter 272 to be stored in the appropriate
sequential location in the buffer 280 by comparing its magnitude to
those already in the buffer 280, rather than by placing the new
measured operational parameter 272 at the beginning and then
re-sorting the entire buffer 280. The median entry in the buffer
280 can be selected (block 282) as the filtered operational
parameter, which can then be output (block 284) and monitored for
pumping anomalies. In at least some instances, this arrangement
increases operating efficiency and reduces the burden on
computational resources, such as those of a downhole tool.
[0062] Although the previous example includes a median filter
applied to the measured operational data, other filters could also
or instead be used. For example, filtering can be done using a
trimmed mean (or truncated mean) filter. Using such a filter, the
measured operational data is sorted in descending (or ascending)
order, like the median filter. The average of the middle x % (where
x is any suitable value, such as 20) of the sorted array is then
taken and output as the filtered result. Indeed, the median filter
can be interpreted as one case of a trimmed filter in which just
the middle data point is taken.
[0063] Various examples of processes for monitoring operational
parameters of a pumping system and detecting the pumping status
(normal or anomaly) are generally represented in FIGS. 9-11.
Beginning with FIG. 9, a flow chart 290 generally represents
determining the pumping status using inlet pressure data (e.g., as
measured by pressure gauge 142 for pump 140). In this example, the
inlet pressure is measured (block 292) and added to a buffer (block
294). A suitable filter, such as a median filter or trimmed mean
filter, is applied (block 296) to output a filtered operational
parameter. The filtered output P.sub.fil is compared (block 298)
with the formation pressure P.sub.f (data block 300), which can be
obtained from a pretest or in some other suitable manner. If they
are sufficiently close, i.e., if:
|P.sub.fil-P.sub.f|<.DELTA.P (3)
where .DELTA.P is a differential pressure threshold 302, an anomaly
(or failure) indicator can be triggered (e.g., by setting a
condition bit in a memory of the controller 148 to "1"); otherwise,
the normal indicator is registered (e.g., by setting the condition
bit to "0"). In at least some embodiments, the threshold 302 is a
small differential pressure (e.g., between 5 psi and 10 psi). In
one embodiment, the threshold 302 may be set as a percentage (e.g.,
ten percent or twenty percent) of the expected difference between
the filtered inlet pressure and the formation pressure during
normal operation. The detected status or condition can then be
output (block 304) to another system or user, or stored for later
reference.
[0064] Outlet pressure data (e.g., as measured by pressure gauge
146 for pump 140) could also be used to detect the pumping status,
as generally represented in flow chart 310 of FIG. 10. The process
represented in this figure includes measuring outlet pressure
(block 312), adding the measured outlet pressure to a buffer (block
314), and applying a filter (e.g., median or trimmed mean) to the
measured outlet pressure (block 316). The filtered output pressure
can then be compared (block 318) with the wellbore pressure (data
block 320) to determine the pumping status. For instance, in one
embodiment the magnitude of the difference between the filtered
output pressure and the wellbore pressure is compared to a
differential pressure threshold 322, which may be the same as or
different from the differential pressure threshold 302 above. An
anomaly indicator can be triggered if the magnitude of the
difference is less than the differential pressure threshold 322;
otherwise, normal operation can be registered. The detected pumping
condition (anomalous or normal) can then be output (block 324), as
above.
[0065] By way of further example, the alternator current drawn by a
pump motor can also be used for detecting pumping anomalies. As
generally represented in flow chart 330, one process includes
measuring the alternator current (block 332), such as the current
drawn by the motor 234 in FIG. 5; adding the measurement to a
buffer (block 334); and applying a filter, such as a median or
trimmed mean filter, to the measured alternator current (block
336). The filtered alternator current can be compared (block 338)
to a current threshold 340 to determine the pumping status. The
current threshold 340 can be set to a value below the expected,
filtered alternator current associated with normal operation of the
pumping system. Like the pressure examples above, an anomaly
indicator can be triggered if the filtered alternator current is
less than the current threshold 340 and operation can be indicated
as normal in other cases. The pumping condition determined from the
alternator current can also be output as above (block 342).
[0066] In addition to inlet pressure, outlet pressure, and
alternator current, it will be appreciated that other operational
parameters (e.g., motor torque and flow rate) could also be used to
determine the pumping status in a manner similar to those described
above. For example, during pumping, flow should generally be
present upstream and downstream from the pump, with transitory
spikes in the flow rate measurement signal caused by the piston
assembly stopping as it reverses direction. If the flow rate were
measured, it could be added to a buffer and then filtered in the
same manner described above. Then, the filtered flow rate could be
compared to a threshold value (below the expected, filtered flow
rate during normal operation) and an anomaly indicator can be
triggered if the filtered flow rate falls below the threshold, such
as near zero.
[0067] FIG. 12 generally depicts the detection of pumping anomalies
(half-stroking in the present example) based on filtering of the
measured inlet pressure data of FIG. 6. The measured inlet pressure
data is again represented in the top subplot; the middle subplot
shows the output of a median filter applied to the measured inlet
pressure data, although other filters could be used; and the bottom
subplot shows the detected pumping condition, where zero indicates
normal and one indicates an anomaly. As can be seen from the middle
subplot, the applied filter serves to remove the spike features
from the measured inlet pressure data, but retain the shape
indicative of an actual anomaly (e.g., half-stroking). It is again
noted that the spike features in the inlet pressure data are caused
by the piston stop (when changing direction) during normal
operation. Accordingly, the time window and filter may be selected
so as to prevent these transitory spikes from triggering the
anomaly indicator, while preserving the shape of a true anomaly in
the filtered data to enable the anomaly to be detected as described
above. It will be appreciated from the foregoing discussion that
the measured outlet pressure data could also be used to detect
pumping anomalies, and that the filtering in such a case also
serves to remove spike features while retaining the general shape
of the measurement signal to allow pumping anomalies to be detected
from the filtered outlet pressure data. FIG. 13 similarly depicts
the detection of pumping anomalies based on filtering of the
measured alternator current data of FIG. 6. Again, the filtering
serves to remove transitory noise (such as the spikes associated
with piston reversal) while retaining the general shape of the
measurement signal, allowing pumping anomalies (half-stroking in
this example) to be accurately identified through the above
techniques.
[0068] While monitoring one operational parameter may enable
detection of pumping anomalies, in some embodiments multiple
operational parameters (which can be measured with multiple
sensors) can be monitored for detecting anomalous operation. For
example, as generally depicted in FIG. 14, both inlet pressure and
outlet pressure could be used to detect pumping anomalies. As may
be seen from this figure, the anomalies detected using the inlet
pressure can be consistent with those detected using the outlet
pressure. Though not shown in FIG. 14, it will be appreciated that
the inlet and outlet pressures can be filtered as described
above.
[0069] In certain embodiments, the operational parameters from
multiple sensors can be used to detect pumping anomalies. For
example, as represented by flow chart 350 in FIG. 15, one
embodiment includes a process for using pumping conditions
determined from inlet pressure data, outlet pressure data, and
alternator current data (data blocks 352, 354, and 356). These
conditions can be determined in any suitable manner, such as
through the techniques described above with respect to FIGS. 7-11.
The process includes aggregating (block 358) the condition
indications determined from each of the different data sources and
determining (block 360) a pumping condition, such as half-stroking
or no-stroking, based on the aggregated condition indicators. In at
least one embodiment, the detected conditions of data blocks 352,
354, and 356, can be combined in a multiplicative fashion. For
instance, each of the individual detected conditions of data blocks
352, 354, and 356 can be represented as "0" (normal) or "1"
(anomaly), and these indicators can multiplied (e.g., combined with
a Boolean "AND" operator). In such a case, if each of the
conditions expressed in data blocks 352, 354, and 356 indicate an
anomaly, the result of the combination of these expressions will
also indicate the anomaly (e.g., return a "1"); otherwise, the
result of the combination of these expressions will not indicate
the anomaly (e.g., return a "0"). This integration of the results
from multiple types of operational data may thus increase
robustness and reliability of the detection while reducing false
positives.
[0070] Further, as represented at block 362, the process can also
include identifying valves suspected to be malfunctioning when a
pumping anomaly is detected. In at least some embodiments, this
identification can be based on the detected operational parameters
in combination with the piston position information for a positive
displacement pump. By way of example, in FIG. 16 the top subplot
depicts position information for the piston assembly in pump 140.
Viewing this subplot from left to right, the upwardly rising
portions of the plot (i.e., from the horizontal axis to the upper
tips of the depicted sawtooth features) represent strokes of the
piston rod 202 and its pistons 204 and 206 in one direction (to the
right in FIG. 5) and the downwardly falling portions of the plot
(i.e., from the upper tips of the sawtooth features back to the
horizontal axis) represent strokes of the piston assembly in an
opposite direction (to the left in FIG. 5).
[0071] As described above, the rightward movement of the piston
assembly during normal pumping operation causes fluid to be drawn
into the pump 140 through the check valve 194 and fluid to be
expelled from the pump through the check valve 196, while the check
valves 192 and 198 remain closed. The leftward movement of the
piston assembly during normal pumping operation causes fluid to be
drawn into the pump 140 through the check valve 192 and to be
expelled from the check valve 198, while the check valves 194 and
196 remain closed.
[0072] Each of the middle and lower subplots of FIG. 16 generally
depicts an upper signal corresponding to outlet pressure and a
lower signal corresponding to inlet pressure. The outlet pressure
(which can be the measured outlet pressure or the filtered outlet
pressure) is shown as alternating between a pressure equivalent to
the wellbore pressure (line 242) and a pressure above the wellbore
pressure, while the inlet pressure (which can be the measured or
filtered inlet pressure) is shown as alternating between a pressure
equivalent to the formation pressure (line 240) and a pressure
below the formation pressure. As will be appreciated from the above
discussion with respect to FIG. 6, each of the middle and bottom
subplots depicts a half-stroking condition of the pump 140. More
specifically, the middle subplot represents a first fault condition
in which the half-stroking occurs during the rightward movement of
the piston assembly, while the bottom subplot represents a second
fault condition in which the half-stroking occurs during the
leftward movement of the piston assembly. Further, half-stroking
during the rightward movement of the piston assembly, as in the
middle subplot, suggests that one or both of the check valves 192
and 198 are faulty (e.g., stuck in an open position). Similarly,
half-stroking during the leftward movement of the piston assembly,
as in the bottom subplot, suggests that one or both of the check
valves 194 and 196 are faulty. Consequently, through the use of
sensed operational data and known position data for the piston
assembly, a proper subset of the check valves can be identified as
suspect for later investigation or replacement.
[0073] In embodiments in which determinations on pumping conditions
are made by a controller of a downhole tool, the process
represented in FIG. 15 can also include sending information to the
surface (block 364). The sent information can include the condition
determined at block 360 and the suspect valves identified in block
362, as well as the conditions determined from the individual
operational parameters represented by data blocks 352, 354, and
356. Further, such information could also or instead be stored
(block 366) in a memory device of the downhole tool (e.g.,
non-volatile memory 176 depicted in FIG. 4). The stored information
could be communicated to the surface at a later time, or could be
accessed once the downhole tool is retrieved from a well.
[0074] The foregoing outlines features of several embodiments so
that those skilled in the art may better understand aspects of the
present disclosure. Those skilled in the art should appreciate that
they may readily use the present disclosure as a basis for
designing or modifying other processes and structures for carrying
out the same purposes or achieving the same advantages of the
embodiments introduced herein. Those skilled in the art should also
realize that such equivalent constructions do not depart from the
spirit and scope of the present disclosure, and that they may make
various changes, substitutions and alterations herein without
departing from the spirit and scope of the present disclosure.
* * * * *