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.

Description

BACKGROUND

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.

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

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.

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.

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.

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.

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

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:

FIG. 1 generally depicts a drilling system having a testing tool in a drill string in accordance with one embodiment of the present disclosure;

FIG. 2 generally depicts a testing tool deployed within a well on a wireline in accordance with one embodiment;

FIG. 3 is a block diagram of components of a testing tool in accordance with one embodiment;

FIG. 4 is a block diagram of components in one example of a controller for the testing tool of FIG. 3;

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;

FIG. 6 graphically depicts various measured operational parameters for a pumping system in accordance with one embodiment;

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;

FIG. 8 is a flow chart representing the application of a filter to a measured operational parameter in accordance with one embodiment;

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;

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;

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;

FIG. 12 graphically depicts the detection of half-stroking by a pump from filtered inlet pressure data in accordance with one embodiment;

FIG. 13 graphically depicts the detection of half-stroking by the pump from filtered alternator current data in accordance with one embodiment;

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;

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

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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”).

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.

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).

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.

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.

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.

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.

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.

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_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_w) may be chosen for the moving window. In at least some embodiments, T_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:

$\begin{array}{cc}{T}_w<\frac{v}{q}& \left(1\right)\end{array}$

Stated differently, the time window T_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_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:

$\begin{array}{cc}{T}_w\approx 0.75\frac{v}{q}& \left(2\right)\end{array}$

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_w/2) in order to align with the raw data in time.

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_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_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.

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.

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_fil is compared (block 298) with the formation pressure P_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_fil−P_f|<ΔP  (3)

where ΔP 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.

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.

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).

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.