Patent Application
20180120865
The subject matter disclosed herein relates to systems and methods for detecting solids in a fluid.
Hydrocarbon fluids, such as oil and gas, may be found in subterranean formations located beneath the Earth's surface. In order to obtain the hydrocarbon fluids, a well may be drilled to create a passage between the subterranean formation and the surface where hydrocarbon fluids are to be collected. Hydraulic fracturing (often referred to as fracking or fracing) is a process commonly used to increase the flow of hydrocarbon fluids from a subterranean formation. Hydraulic fracturing involves pumping a fluid (e.g., a fracturing fluid) containing a proppant (e.g., sand) into a subterranean formation at a high pressure. The high pressure fracturing fluid may create fractures (e.g., cracks) in the subterranean formation and/or may increase the size of pre-existing fractures in the subterranean formation to facilitate the release of oil and gas from the subterranean formation. The fluid produced from the well (e.g., production fluid) may include oil, gas, and water, and the production fluid may be routed to various processing equipment, such as one or more separators to separate the oil, gas, and water of the production fluid into separate components. In some instances, the production fluid may also include solid particles, such as the proppant from the hydraulic fracturing fluid. The solid particles in the production fluid may erode or damage various equipment, such as pipelines, valves, and oil/gas/water separators.
In one embodiment, a solids detector includes a valve including a valve body configured to be coupled to a conduit. The valve is configured to control a flow of a fluid through the conduit. Additionally, the solids detector includes a receptor coupled to the valve body and configured to extend at least partially into a flow path of the fluid through the valve body. Further, the solids detector includes a sensor coupled to the valve body and the receptor. The sensor is configured to receive an acoustic wave generated due to one or more solid particles in the fluid impacting the receptor. Additionally, the sensor is configured to generate an electrical signal based on the acoustic wave. The electrical signal is indicative of one or more impact energies of the one or more solid particles that impacted the receptor.
In one embodiment, a system configured to produce oil and gas from a well includes a conduit configured to flow a fluid produced by the well. Additionally, the system includes a solids detector coupled to the conduit and configured to generate an electrical signal in response to detecting one or more solid particles in the fluid. Further, the system includes a controller configured to receive the electrical signal from the solids detector. The controller is also configured to determine an action based at least in part on the electrical signal. The action, when executed, adjusts a flow rate of the fluid through the conduit or adjusts a flow path of the fluid through the system.
In one embodiment, a solids detector includes a receptor configured to extend at least partially into a flow path of a fluid through a conduit. The receptor is configured to generate an acoustic wave in response to one or more solid particles impacting the receptor. The receptor includes a first end and a second end opposite the first end. Additionally, the solids detector includes a first sensor coupled to the first end of the receptor. Further, the solids detector includes a second sensor coupled to the second end of the receptor. The receptor is configured to transfer the acoustic wave to the first and second sensors, and the first and second sensors are configured to generate first and second electrical signals, respectively, based on the acoustic wave. The first and second electrical signals are each indicative of one or more impact energies of the one or more solid particles that impacted the receptor.
These and other features, aspects, and advantages of the present invention 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:
One or more specific embodiments will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
Certain embodiments or implementations illustrating aspects of the present disclosure are described and/or depicted with reference to the present figures. It should be understood, however, that there is no intent to limit example embodiments to the particular forms disclosed, but to the contrary, example embodiments are to cover all modifications, equivalents, and alternatives falling within the scope of the present invention. Indeed, the present examples are intended to facilitate and simplify explanation of the present approach and to provide useful context for understanding the disclosed subject matter. These description and example should, therefore, not be read to explicitly or implicitly limit application of the described devices and/or techniques to the contexts of the examples.
When introducing elements of various embodiments of the present invention, 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. Furthermore, any numerical examples in the following discussion are intended to be non-limiting, and thus additional numerical values, ranges, and percentages are within the scope of the disclosed embodiments.
The present discussion relates to the use of solid detectors (e.g., solid measurement devices or solid sensors) to detect solid particles in a fluid flow and/or to measure one or more characteristics of solid particles in a fluid flow. For example, in certain embodiments, the disclosed solid detector may measure a volume, quantity, concentration, and/or size distribution of solid particles in a fluid flow. In some embodiments, the solids detector may include a receptor that is configured to be impacted by solid particles in the fluid flow. Additionally, the solids detector may include a sensor that is configured to generate an electrical signal based on an acoustic wave generated in response to the solid particles impacting the receptor. In some embodiments, the sensor may include the receptor. In certain embodiments, the sensor may be affixed to the receptor, and the receptor may be configured to transfer the generate acoustic wave to the sensor. In some embodiments, the receptor and the sensor of the solids detector may be coupled to a valve body of a valve.
Additionally, as discussed below, the electrical signal generated by the sensor may be used to control a system having the fluid to reduce erosion and/or damage that may result from the solid particles in the fluid. In some embodiments, a controller of the system may determine one or more actions based on an analysis of the electrical signal, and the one or more actions, when executed, may reduce or block damage to one or more components of the system. In certain embodiments, the one or more actions may adjust a flow rate of the fluid in the system or a flow path of the fluid through the system. For example, the one or more actions may include adjusting a position of a choke to adjust a flow rate of the fluid or adjusting a position of a valve disposed in a conduit configured to flow the fluid to adjust a flow path of the fluid through the system.
Turning to the figures,
The oil and/or gas production system 12 may include a wellhead 16 configured to establish fluid communication with the well 14. Additionally, the oil and/or gas production system 12 may include a tree 18 (e.g., a production tree, a Christmas tree, etc.) configured to couple to the wellhead 16. The tree 18 may include a variety of flow paths, valves, fittings, and controls for controlling the flow of fluids into and out of the well 14. During operation, the tree 18 may route fluids (e.g., production fluid) produced by the well 14 to a production flowline 20. The production fluid may include oil, gas, and/or water.
In some embodiments, the tree 18 may be coupled to the production flowline 20 via a flow control device 22 (e.g., a choke, a choke valve). In some embodiments, the tree 18 may include the flow control device 22. The flow control device 22 may be configured to control the flow of the production fluid from the well 14 and/or to control the pressure in the well 14. For example, in some embodiments, decreasing the size of an opening of the flow control device 22 may decrease the flow rate of the production fluid from the well 14 and may increase the pressure in the well 14. Additionally, increasing the size of the opening of the flow control device 22 may increase the flow rate of the production fluid from the well 14 and may decrease the pressure in the well 14.
The production flowline 20 may be configured to route the production fluid to one or more oil and/or gas processing devices 24 (e.g., fluid processing devices). It should be appreciated that while the production flowline line 20 is illustrated as a single flowline, the production flowline 20 may include two or more flowlines (e.g., conduits, pipes, pipelines, jumpers, risers, etc.). Further, it should be appreciated that while the production flowline line 20 is illustrated as directly coupled to the one or more oil and/or gas processing devices 24, the production flowline 20 may be coupled to (e.g., indirectly coupled to) the one or more gas/processing devices 24 via one or more intermediate components (e.g., manifolds, pipeline end terminations, etc.).
In certain embodiments, the one or more oil and/or gas processing devices 24 may include distillation columns, rotating machinery, pumps, compressors, heat exchangers, separators, or any other suitable equipment. For example, as illustrated, the one or more oil and/or gas processing devices 24 may include one or more separators (e.g., gas/liquid separators, liquid/liquid separators, oil/gas/water separators, etc.) configured to separate oil, gas, and water in the production fluid into separate components. The one or more separators may be configured to route the oil to an oil flowline 28, the gas to a gas flowline 30, and the water to a water flowline 32.
As noted above, the production fluid may include oil, gas, and/or water. In some situations, the production fluid may also include solid particles, such as sand and/or rocks from the subterranean formation. In some embodiments, the oil and/or gas production system 12 may include a hydraulic fracturing system (e.g., a fracking system or fracing system), which may be configured to increase the production of oil and/or gas from the well 14 by pumping a fluid (e.g., a fracturing fluid) containing a proppant (e.g., solid particles, sand, ceramic particles, etc.) into the subterranean formation at a high pressure. In particular, the high pressure fracturing fluid may create fractures (e.g., cracks) in the subterranean formation and/or may increase the size of pre-existing fractures in the subterranean formation to facilitate the release of oil and gas from the subterranean formation. While most of the injected fracturing fluid may remain underground, a portion of the injected fracturing fluid may return to the surface and is typically referred to as “flowback.” As such, the production fluid may include proppant from the fracturing fluid. The solid particles in the production fluid may erode and/or damage various components of the oil and/or gas production system 12, such as the production flowline 20, the one or more oil and/or gas processing devices 24, and/or the flow control device 22, which may reduce the life of the various components and may increase the downtime and operating costs of the oil and/or gas production system 12 associated with repairing and/or replacing damaged components.
As discussed below, the solids management system 10 may be configured to detect solid particles in the production fluid and/or to measure one or more parameters of the solid particles in the production fluid, such as the volume, quantity, concentration, and/or size distribution of solid particles in the production fluid. Additionally, as discussed below, the solids management system 10 may be configured to determine one or more actions (e.g., control actions, operational decisions, etc.) based on the detection of solid particles in the production fluid and/or based on the measured parameters of the solid particles in the production fluid. In particular, the solids management system 10 may be configured to determine one or more actions that, when executed, may reduce, block, or prevent erosion and/or damage to one or more components of the oil and/or gas production system 12 caused by solid particles in the production fluid. Further, the solids management system 10 may be configured to automatically execute the one or more determined actions and/or to provide user-perceivable indications indicative of the one or more determined actions to a user (e.g., via an output device), which may prompt the user to execute the one or more determined actions. As such, the solids management system 10 may facilitate the reduction of damage to one or more components of the oil and/or gas production system 12 caused by solid particles in the production fluid, which may increase the life of the one or more components and may decrease the downtime and operating costs of the oil and/or gas production system 12.
With the foregoing in mind, the solids management system 10 may include one or more solids detectors 40 (e.g., solids measurement devices, solids sensors, sand detectors, etc.) configured to detect the presence of one or more solid particles in the production fluid. In certain embodiments, the one or more solids detectors 40 may be configured to measure one or more parameters of the solid particles in the production fluid, such as a volume, quantity, concentration, and/or size distribution of solid particles in the production fluid. In some embodiments, the one or more solids detectors 40 may be configured to measure flow rate of the production fluid. In certain embodiments, the solids management system 10 may include one or more flow meters 42 configured to measure the flow rate of the production fluid.
As discussed in below with respect to
In some embodiments, the solids management system 10 may include a controller 44, which may include or may be operatively coupled to an input/output (I/O) device 46 configured to receive inputs from a user and/or to provide information to a user. For example, the I/O device 46 may include a display, computer, monitor, cellular or smart phone, tablet, other handheld device, speaker, keyboard, or the like. The controller 44 may be configured to receive data (e.g., signals, sensor feedback, etc.) from the one or more solids detectors 40. For example, one or more solids detectors 40 may include a wireless transmitter 48 (e.g., a wireless transceiver) configured to wirelessly transmit data to a wireless receiver 50 (e.g., a wireless transceiver) of the controller 44. In certain embodiments, the wireless transmitter 48 may be configured to wirelessly transmit the data to a cloud-based system (e.g., a cloud server, a cloud storage device, etc.), and the controller 44 may be configured to download the data from the cloud-based system. In some embodiments, one or more solids detectors 40 may be communicatively coupled to the controller 44 via a wired connection (e.g., a cable). Additionally, the controller 44 may be configured to receive data from the one or more flow meters 42 via a wireless connection (e.g., a wireless transmitter of the flow meter 42), via a wired connection, or via the cloud-based system.
The solids detectors 40 may be configured to transmit raw data, processed data, and/or measured parameters of the solid particles in the production fluid to the controller 44. In certain embodiments, the controller 44 may be configured to determine one or more parameters of the solid particles in the production fluid (e.g., solids parameters), such as volume, quantity, concentration, and/or size distribution, based on raw and/or processed data from the solids detectors 40. Additionally, the controller 44 may cause the I/O device 46 to provide one or more user-perceivable indications relating to the one or more solids parameters. For example, the controller 44 may cause the I/O device 46 to display the one or more measured solids parameters. The measured solids parameters may facilitate a user in assessing possible erosion of the oil and/or gas production system 12, as well as assessing the subterranean formation and the hydraulic fracturing operation.
Further, in some embodiments, the controller 44 may be configured to determine one or more actions (e.g., a control actions, an operational decision, etc.) based on the detection of solid particles in the production fluid and/or based on the measured solids parameters. In particular, the controller 44 may determine one or more actions that, when executed, may reduce, block, or prevent erosion and/or damage to one or more components of the oil and/or gas production system 12 caused by solid particles in the production fluid. For example, erosion and/or damage may be reduced, blocked, or prevented by stopping the flow of the production fluid from the well 14 or by reducing the flow rate of the production fluid from the well 14. Additionally, erosion and/or damage may be reduced by increasing the pressure in the well 14. In particular, the pressure differential between the well 14 and the surrounding subterranean formation may cause sand to flow from the subterranean formation to the well 14. Thus, increasing the pressure of the well 14 may decrease the pressure differential, thereby reducing the likelihood of sand entering the well 14 from the subterranean formation. As noted above, the size of the opening of the flow control device 22 (e.g., choke) may adjusted to adjust the flow of production fluid from the well 14 and the pressure in the well 14. In some embodiments, an actuator 52 may be configured to adjust the size of the opening of the flow control device 22. In certain embodiments, the actuator 52 may include one or more of a manual actuator, an electric actuator, a hydraulic actuator, or a pneumatic actuator.
Accordingly, in some embodiments, the controller 44 may determine that the size of the opening of the flow control device 22 should be adjusted (e.g., reduced) to reduce the flow rate of production fluid from the well 14, to stop the flow of production fluid from the well 14 (e.g., during well shut down or well shut-in), or to increase the pressure in the well 14 based on an analysis of one or more measured solids parameters. For example, the controller 44 may determine that the size of the opening of the flow control device 22 should be adjusted (e.g., reduced) in response to a determination that one or more measured solid parameters violate a respective threshold (e.g., greater than an upper threshold or less than a lower threshold). In certain embodiments, the controller 44 may determine that the size of the opening of the flow control device 22 should be adjusted (e.g., increased) to increase the flow rate of production fluid from the well 14 and/or to decrease the pressure of fluid from the well 14 in response to a determination that the one or more measured solids parameters do not violate respective thresholds.
In some embodiments, the controller 44 may determine a size for the opening of the flow control device 22 based on an analysis of one or more measured solids parameters, such as by comparing one or more measured solids parameters to one or more respective thresholds. For example, the controller 44 may compare a measured solids parameter to a plurality of tiered or graded thresholds that successively increase in value, and each threshold may be associated with a size for the opening of the flow control device 22. By way of example, the controller 44 may determine a first size for the opening if a measured solids parameter is greater than a first threshold. Additionally, the controller 44 may determine a second size for the opening that reduces the flow rate of the production fluid from the well 14 and increases the pressure in the well 14 as compared to the first size if the measured solids parameter is greater than a second threshold that is greater than the first threshold.
Further, in some embodiments, the controller 44 may determine that the flow rate of production fluid from the well 14 should be reduced and/or the pressure in the well 14 should be increased to a greater extent in response to a determination that two or more measured solids parameters each violate a respective threshold. For example, the controller 44 may compare a first solids parameter (e.g., size or diameter of the solid particles) to a first threshold associated with a first size of the opening and may compare a second solids parameter (e.g., flow rate, concentration, etc.) to a second threshold associated with a second size of the opening. In certain embodiments, the controller 44 may determine that the opening of the flow control device 22 should be adjusted to a third size that results in a reduced production fluid flow rate and an increased well pressure as compared to the first and second sizes in response to a determination that the first and second measured solids parameters each violate the respective threshold.
Additionally, erosion and/or damage to components of the oil and/or gas production system 12 may be reduced, blocked, or prevented by adjusting the flow path of the production fluid through the oil and/or gas production system 12. For example, erosion and/or damage to the oil and/or gas processing devices 24 may be reduced, blocked, or prevented by diverting the flow of the production fluid from the oil and/or gas processing devices 24. In some embodiments, the oil and/or gas production system 12 may include a bypass valve 54 disposed in the production flow line 20 that may be controlled to divert the production fluid from the oil and/or gas processing devices 24. For example, the bypass valve 54 that may be configured to route the production fluid to the oil and/or gas processing devices 24 when the bypass valve 54 is in a first position (e.g., an open position) and to divert the production fluid away from the oil and/or gas processing devices 24 when the bypass valve 54 is in a second position (e.g., a closed position). In certain embodiments, an actuator 56 may be configured to adjust the position of the bypass valve 54. In some embodiments, the actuator 56 may include one or more of a manual actuator, an electric actuator, a hydraulic actuator, or a pneumatic actuator. Further, in some embodiments, the bypass valve 54 may be configured to route the production fluid to a solids tank 58 (e.g., a sand tank, a frack tank, etc.) when the bypass valve 54 is in the second position. In certain embodiments, the bypass valve 54 may be configured to route the production fluid to a solids separator 60 (e.g., a sand separator) configured to separate or remove the solid particles from the production fluid. The separated solid particles may be routed from the solids separator 60 to the solids tank 58. In certain embodiments, the resulting production fluid (e.g., containing oil, gas, and/or water) may be routed from the solids separator 60 to the oil and/or gas processing devices 24.
Accordingly, in some embodiments, the controller 44 may determine that the production fluid should be diverted from the oil and/or gas processing devices 24 in response to a determination that the production fluid includes solid particles or in response to a determination that one or more measured solids parameters violates a respective threshold. For example, the controller 44 may determine that the bypass valve 54 should be actuated to the second position in response to a determination that the production fluid includes solid particles or in response to a determination that one or more measured solids parameters violates a respective threshold. Further, the controller 44 may continue to monitor the production fluid while the bypass valve 54 is in the second position to determine when the bypass valve 54 should be actuated to the first position. For example, the controller 44 may determine that the bypass valve 54 should be actuated to the first position in response to a determination that the production fluid does not include solid particles or in response to a determination that the measured solids parameters do not violate respective thresholds.
Further, in some embodiments, the controller 44 may cause the I/O device 46 to provide user-perceivable indications (e.g., alerts, alarms, messages, graphical indications, etc.) indicative of the one or more determined actions (e.g., adjusting the size of the opening of the flow control device 22 and/or adjusting the position of the bypass valve 54) to a user. For example, the controller 44 may cause the I/O device 46 to display the one or more determined actions, which may prompt the user to execute the one or more determined actions. For example, the user may manually adjust the actuator 52 to adjust the size of the opening of the flow control device 22 and/or may manually adjust the actuator 56 to adjust the position of the bypass valve 54.
In certain embodiments, the controller 44 may be configured to automatically execute the one or more determined actions. For example, the controller 44 may be configured to send a control signal (e.g., a wired and/or wireless control signal) to the actuator 52, which may cause the actuator 52 to adjust the size of the opening of the flow control device 22 (e.g., to a size specified by the control signal). Additionally, the controller 44 may 44 may be configured to send a control signal (e.g., a wired and/or wireless control signal) to the actuator 56, which may cause the actuator 56 to adjust the position of the bypass valve 54.
In some embodiments, the solids detector 40 may include a controller 62 configured to perform one or more of the above-described functions of the controller 44. For example, the controller 62 may determine one or more actions (e.g., adjusting the size of the opening of the flow control device 22 and/or adjusting the position of the bypass valve 54) based on the detection of solid particles in the production fluid and/or based on the measured solids parameters, as discussed above with respect to the controller 44. Additionally, in certain embodiments, the controller 62 may be configured to automatically execute the determined actions, as discussed above with respect to the controller 44. Further, in certain embodiments, the controller 62 may be configured to cause the I/O device 46 to display the determined actions. For example, the controller 62 may transmit the determined actions to the controller 44, which may cause the I/O device 46 to display the determined actions. In some embodiments, the controller 44 may determine the actions and may cause the controller 62 to execute the determined actions. Further, in certain embodiments, a user may input a desired action via the I/O device 46, and the controller 44 and/or the controller 62 may be configured to execute the action inputted by the user. For example, the user may determine an action based on one or more measured solids parameters displayed on the I/O device 46.
As illustrated, the solids detector 40 may include a housing 84 (e.g., body) that is configured to be coupled to the conduit 82. In certain embodiments, the housing 84 may be coupled to the conduit 82 via one or more fasteners 86, such as one or more bolts, screws, nuts, threaded connections, and the like. While the housing 84 is illustrated as a single structural component in
Additionally, the solids detector 40 may include a receptor 88 (e.g., a probe, a rod, etc.) configured to be impacted by one or more of the solid particles 80 entrained in the fluid. As illustrated, the receptor 88 may extend through an opening 90 formed in the conduit 82 when the housing 84 is coupled to the conduit 82. In some embodiments, the receptor 88 may be coupled to the housing 84. In some embodiments, the receptor 88 may extend substantially crosswise (e.g., perpendicular) to a longitudinal axis 92 of the conduit 84 and/or crosswise to a flow direction 94 of the fluid through the conduit 82. In some embodiments, the receptor 88 may extend across at least 50%, 60%, 70%, 80%, or 90% of a diameter 96 of the conduit 82. In certain embodiments, as discussed below, the receptor 88 may extend across the entire diameter 96. In some embodiments, the receptor 88 may be cylindrical, rectangular, or any other suitable shape.
Further, the solids detector 40 may include one or more sensors 98 (e.g., an acoustic sensor, an acoustic wave sensor) configured to convert acoustic waves (e.g., mechanical waves, stress/strain waves, vibrations, etc.) into electrical signals. For example, as discussed below, the one or more sensors 98 may include a magnetostrictive sensor, a piezoelectric sensor, an accelerometer, and/or a capacitive sensor. The one or more sensors 98 may be acoustically coupled to the receptor 88. For example, in some embodiments, the one or more sensors 98 may be in physical (e.g., mechanical) contact with and/or coupled to (e.g., affixed to) the receptor 88. As illustrated, in some embodiments, the sensor 98 may abut and/or be coupled to a radial surface 99 of the receptor 88 relative to the longitudinal axis 92 of the conduit 82. In certain embodiments, the sensor 98 may abut and/or may be coupled to an axial surface 100 of the receptor 88 relative to the longitudinal axis 92 of the conduit 82. In some embodiments, as discussed below, the sensor 98 and the receptor 88 may be integrally formed. For example, the sensor 98 may include the receptor 88. In certain embodiments, one or more sensors 98 may be coupled to and supported by the housing 84. Additionally, the one or more sensors 98 may be non-rated (e.g., not wet, not exposed to the flow of fluid through the conduit 82). For example, in some embodiments, one or more sensors 98 may be external to the conduit 82 (e.g., disposed in the housing 94). In certain embodiments, as discussed below, one or more sensors 98 may be embedded in the receptor 88 such that the one or more sensors 98 are disposed in the conduit 82 and blocked from the fluid through the conduit 82 by the receptor 88.
During operation, an acoustic wave (e.g., a mechanical wave, a stress/strain wave, a vibration, etc.) may be generated due to one or more of the solid particles 80 impacting the receptor 88. The receptor 88 may transfer the generated acoustic wave to sensor 98. The sensor 98 may generate an electrical signal (e.g., an electrical pulse signal, an output signal, etc.) based on the acoustic wave generated in response to one or more solid particles 80 impacting the receptor 88, and the electrical signal may vary with (e.g., be proportional to) the impact energies of the one or more solid particles 80 that impacted the receptor 88. As discussed below, the electrical signal may include current, voltage, capacitance, frequency, and/or magnetic field (e.g., magnetic field strength or flux). The impact energy and, by extension, the generated electrical signal may vary with (e.g., be proportional to) the flow rate of the solid particles 80 and the mass of the solid particles 80, which may be correlated with the size (e.g., diameter or volume) of the solid particles 80. Accordingly, as discussed below, the electrical signal may be used to determine one or more parameters of the solid particles 80, such as the mass, size (e.g., diameter, volume, etc.), density, flow rate, quantity, and/or concentration.
In certain embodiments, the receptor 88 may be rigidly coupled to the housing 84 such movement of the receptor 88 relative to the housing 84 is reduced, minimized, or blocked. Additionally, in some embodiments, the receptor 88 may be made from one or more rigid (e.g., stiff) and/or abrasion resistant materials, such as tungsten carbide, silicon carbide, steel (carbon steel, stainless steel, etc.), and so forth. In some embodiments, the receptor 88 may be coated with an abrasion resistant coating. The stiffness or rigidity of the receptor 88 may facilitate the detection of very small impact forces on the receptor 88 and the transfer of acoustic waves generated in response to very small impact forces to the sensor 98. Additionally, it may be desirable to form the receptor 88 from one or more materials that are resistant to abrasion, such as tungsten carbide, silicon carbide, or steel, to reduce erosion of the receptor 88 due to the solid particles 80. In some embodiments, a blind flange (e.g., a plate) configured to cover an end of the conduit 82 may be used as the receptor 88 Further, in some embodiments, as discussed below, the receptor 88 may be formed from one or more conductive materials, such as one or more metals.
In some embodiments, the solids detector 40 may include circuitry 102 (e.g., data acquisition circuitry, processing circuitry, and/or control circuitry). For example, the circuitry 102 may be configured to receive the electrical signal from the sensor 98. In some embodiments, the circuitry 102 may include one or more amplifiers 104 configured to amplify the received electrical signal and/or one or more filters 106 configured to filter the received electrical signal. In some embodiments, the circuitry 102 (e.g., the controller 62) may be configured to dynamically adjust the amplifiers 104 based on the flow rate of the solid particles 80, which may be determined by the solids detector 40 or the flowmeter 42. For example, as discussed below, the one or more filters 106 may be configured to filter the electrical signal based on frequency and/or amplitude, and different frequencies or amplitudes may be correlated with different particle sizes (e.g., diameter, volume, etc.) and/or masses. Further, in some embodiments, the circuitry 102 may include the controller 62. As discussed below, in some embodiments, the controller 62 may be configured to determine one or more parameters of the solid particles 80, such as the mass, size (e.g., diameter, volume, etc.), density, flow rate, quantity, and/or concentration, based on the electrical signal. Additionally, as discussed above, the controller 62 may be configured to determine the one or more actions based on the parameters and/or to execute the one or more actions.
Further, as noted above, the solids detector 40 may include the transmitter 48. The transmitter 48 may be configured to wirelessly transmit a raw (e.g., unprocessed) electrical signal, a processed (e.g., amplified and/or filtered) electrical signal, and/or one or more determined parameters to the controller 44 and/or to a cloud-based system. In certain embodiments, the solids detector 40 may be communicatively coupled to the controller 44 via a wired connection. Further, in some embodiments, the solids detector 40 may include a power source 108 (e.g., a battery, a capacitor, etc.), which may be configured to power the sensor 98, the transmitter 48, and/or the controller 62. The transmitter 48, the circuitry 102, and the power source 108 may be coupled to the housing 84. For example, as illustrated, the transmitter 48, the circuitry 102, and the power source 108 may be disposed within the housing 84. In some embodiments, the transmitter 48, the circuitry 102, and/or the power source 108 may be coupled to an outer surface 110 of the housing 84.
Additionally, the magnetostrictive sensor 130 may include a magnetic field generating device 134 configured to generate one or more magnetic fields. For example, in some embodiments, the magnetic field generating device 134 may include one or more magnet 136 (e.g., permanent magnets and/or electromagnets) configured to generate a constant magnetic field. Additionally or alternatively, the magnetic field generating device 134 may include a conductive coil 138 (e.g., an excitation coil) and a current source 140 that provides a current to the conductive coil 138 to generate a magnetic field. The current source 140 provide an alternating current (AC) to generate an AC magnetic field or a direct current (DC) to generate a DC magnetic field. As illustrated, the conductive coil 138 may surround the magnetostrictive element 132.
The magnetic field generating device 134 may induce a magnetic field (e.g., a magnetic flux) in the magnetostrictive element 132. Magnetostrictive materials can change shape or size in response to an applied magnetic field, which is typically referred to as the magnetostrictive effect or the direct magnetostrictive effect. Additionally, the magnetic susceptibility or permeability of magnetostrictive materials can change in response to an applied force (e.g., mechanical stress), which is typically referred to as the inverse magnetostrictive effect or the Villari effect. The acoustic wave transferred to the magnetostrictive element 132 may apply a force on the magnetostrictive element 132, which may change the magnetic susceptibility or permeability of the magnetostrictive element 132 in accordance with the inverse magnetostrictive effect. The change in magnetic susceptibility or permeability of the magnetostrictive element 132 may cause a change in the magnetic field (e.g., magnetic flux) induced in the magnetostrictive element 132.
Additionally, the magnetostrictive sensor 130 may also include a magnetic field detecting device 142 (e.g., a magnetometer) configured to detect a change in the magnetic flux. For example, the magnetic field detecting device 142 may include a conductive coil 144 (e.g., a sensing coil), which may surround the magnetostrictive element 132, and a sensor 146 (e.g., a current sensor or a voltage sensor) configured to measure the current through the conductive coil 144 or the voltage across the conductive coil 144. Specifically, the change in the magnetic flux may induce a voltage and a current in the conductive coil 144. Accordingly, the induced voltage and/or current may be indicative of and/or correlated to the change in the magnetic flux, the change in the magnetic susceptibility or permeability of the magnetostrictive element 132, the mechanical force (e.g., acoustic wave) applied to the magnetostrictive element 132, and the impact energies of the solid particles 80 that impacted the receptor 88. The magnetostrictive sensor 130 may be configured to output or provide the measured induced voltage or current as the electrical signal to the circuitry 102 and/or the transmitter 48.
As illustrated, the first conductive plate 166 may be coupled to (e.g., affixed to) the receptor 88. In some embodiments, the receptor 88 and the first conductive plate 166 may be moveable relative to the housing 84 and the second conductive plate 168. For example, the receptor 88 may be coupled to the housing 84 via a flexible or deformable element, such as a spring 172. Additionally, the second conductive plate 168 may be fixed relative to the housing 84. For example, the second conductive plate 168 may be coupled to the housing 84 via a fixed support 174. As noted above, in some embodiments, the receptor 88 and the sensor 98 may be integrally formed. That is, the sensor 98 may include the receptor 88. For example, in some embodiments, the receptor 88 may be formed from one or more conductive materials, such as one or more metals, and the receptor 88 may include the first conductive plate 166.
As such, the receptor 88 and the first conductive plate 166 may be configured to move relative to the second conductive plate 168 due to one or more solid particles 80 impacting the receptor 88, which may change (e.g., decrease) a distance 176 (e.g., gap) between the first and second conductive plates 166 and 168. As will be appreciated, the capacitance of the capacitor 164 is inversely proportional to the distance 176 between the first and second conductive plates 166 and 168, and thus, the measured capacitance may be indicative of the impact energies of the one or more solid particles 80 that impacted the receptor 88. The capacitive sensor 160 may be configured to output or provide the measured capacitance as the electrical signal to the circuitry 102 and/or the transmitter 48.
During operation, one or more solid particles 80 may impact the receptor 88, which may generate an acoustic wave in response to the impacts of the one or more solid particles 80. Additionally, the receptor 88 may transfer the acoustic signal to first electrode 184, which may cause a mechanical deformation of the piezoelectric element 182. The piezoelectric element 182 may generate an electrical charge (e.g., a voltage) based on the mechanical deformation. The piezoelectric sensor 180 may be configured to provide or output a voltage signal (e.g., an electrical signal, an electrical pulse signal) indicative of the mechanical deformation and the impact energies of the solid particles 80 that impacted the receptor 88 to the circuitry 102. In particular, the first and second electrodes 184 and 186 may be coupled to the circuitry 102 via leads 188 to provide the voltage signal to the circuitry 102.
For example, in the illustrated embodiment, the pulse signal 190 may be filtered to extract or identify a first subset 194 of the plurality of pulses 192 where each pulse in the first subset 194 has a first frequency or amplitude corresponding to a first diameter (e.g., approximately five micrometers (μm)). Additionally, the pulse signal 190 may be filtered to extract or identify a second subset 196 of the plurality of pulses 192 where each pulse in the second subset 196 has a second frequency or amplitude corresponding to a second diameter (e.g., approximately ten μm). Further, the pulse signal 190 may be filtered to extract or identify a third subset 198 of the plurality of pulses 192 where each pulse in the third subset 198 has a third frequency or amplitude corresponding to a third diameter (e.g., approximately fifteen μm). The pulse signal 190 may be filtered using the one or more filters 106 of the solids detector 40, one or more filters of the controller 44, or one or more filters of any other suitable circuitry or processor-based device.
Additionally, the pulses 192 may be counted or summed over a period of time using the controller 62 and/or the controller 44 to determine a quantity or flow rate of the plurality of solid particles 80. Further, the controller 62 and/or the controller 44 may be configured to determine a quantity or flow rate for each identified diameter of the solid particles 80. For example, the controller 62 and/or the controller 44 may be configured to determine a quantity or flow rate of the pulses 192 in the first subset 194, a quantity or flow rate of the pulses 192 in the second subset 196, and a quantity or flow rate of the pulses 192 in the third subset 198. Additionally, the controller 62 and/or the controller 44 may determine the percentage or concentration of solid particles 80 have a particular diameter relative to a total number of solid particles 80 detected for a period of time. For example, in the illustrated embodiment, the pulse signal 190 includes sixteen pulses 192 over a period of time, and the first subset 194 associated with the first diameter includes four pulses 192. Accordingly, the controller 62 and/or the controller 44 may determine that approximately 25% of the pulses 192 for the period of time have the first diameter.
The second sensor 220 may be electrically connected to the circuitry 102, the transmitter 48, and/or the processor 108, and the second sensor 220 may be configured to provide the generated electrical signal (e.g., the electrical pulse signal 190) to the circuitry 102 and/or the transmitter 48, which may transmit the signal to the controller 44, another processor-based device, or the cloud-based system. The controller 62 and/or the controller 44 may be configured to compare the electrical signals generated by the sensor 98 and the second sensor 220 to determine whether the receptor 88 was impacted by a single solid particle 80 or an aggregate or group of solid particles 80. The controller 62 and/or the controller 44 may be configured to triangulate the location of the impact and process the locational information to assess the size of particle impacting the receptor 88 based on the electrical signals generated by the sensor 98 and the second sensor 220 (e.g., based on a comparison of the electrical signal generated by the sensor 98 and the electrical signal generated by the second sensor 220). For example, the electrical signal generated by sensor 98 (e.g., one or more pulses of the electrical signal generated by the sensor 98) and the electrical signal generated by the second sensor 220 (e.g., one or more pulses of the electrical signal generated by the second sensor 220) may have one or more varying characteristics, such as amplitude, phase, shape, and so forth, that may be analyzed by the controller 62 and/or the controller 44 to determine whether the receptor 88 was impacted by a single solid particle 80 or an aggregate or group of solid particles 80, to triangulate the location of the impacts, and/or and to process the locational information to assess the size of the solid particles that impacted the receptor 88.
The plurality of piezoelectric sensors 180 may be disposed in any suitable arrangement. For example, in some embodiments, two or more piezoelectric sensors 180 of the plurality of piezoelectric sensors 180 may disposed directly adjacent to one another. In some embodiments, two or more neighboring piezoelectric sensors 180 of the plurality of piezoelectric sensors 180 may be spaced apart from another. Additionally, the leads 188 of the plurality of piezoelectric sensors 180 may extend through the channel 226 to the circuitry 102. In some embodiments, each piezoelectric sensor 180 of the plurality of piezoelectric sensors 180 may be independently connected to the circuitry 102. For example, each piezoelectric sensor 180 of the plurality of piezoelectric sensors 180 may be separately connected to the circuitry 102 via leads 188 of the respective piezoelectric sensor 180. In some embodiments, the controller 62 and/or the controller 44 may be configured to compare the electrical signals generated by the plurality of piezoelectric sensors 180 to determine whether the receptor 88 was impacted by a single solid particle or an aggregate of solid particles. Further, the controller 62 and/or the controller 44 may be configured to determine the locations of the impacts based on analysis of the electrical signals from the plurality of piezoelectric sensors 180 and/or may be configured to use the locational information to assess the size of the solid particles that impacted the receptor 88. In certain embodiments, the solids detector 40 may include two or more receptors 88, where each receptor 88 is coupled to and configured to transfer an acoustic wave to at least one sensor 98. For example, as illustrated in
As illustrated, the second receptor 228 may be disposed at an angle 234 relative to the receptor 88. That is, the second receptor 228 may extend crosswise relative to the receptor 88. In some embodiments, the angle 334 may be between approximately 5 degrees(°) and 175°, 20° and 160°, 35° and 145°, 50° and 130°, 65° and 115°, 80° and 100°, or 85° and 95°. In certain embodiments, the second receptor 228 may be generally perpendicular to the receptor 88. Further, the second receptor 228 may be spaced apart from the receptor 88 along the length of the conduit 82 such that generated acoustic waves are not transferred between the receptor 88 and the second receptor 228. For example, as illustrated in
As noted above, in some embodiments, the housing 84 of the solids detector 40 may include the housing (e.g., body) of a valve, such as a butterfly valve, a ball valve, a globe valve, or a gate valve, or the housing of a flowmeter, such as the flowmeter 42. In particular, the receptor 88 and/or the sensor 98 of the solids detector 40 may be disposed in or integrally formed with a valve or a flowmeter. For example,
As discussed above, in some embodiments, the solids detector 40 may include the controller 62, which may be configured to determine one or more solids parameters based on the electrical signal generated by the sensor 98. Additionally, as discussed above, in some embodiments the controller 62 may be configured to execute one or more actions that may reduce or block damage that may be caused by the solid particles 80, such as adjusting the position of (e.g., opening or closing) the bypass valve 54. (see
The controller 44 and/or 62 may include one or more processors, microprocessors, microcontrollers, integrated circuits, application specific integrated circuits, programmable logic controllers, control circuitry, and so forth. Additionally, the controller 44 and/or 62 may include one or more memory devices, which may be provided in the form of tangible and non-transitory machine-readable medium or media having instructions recorded thereon for execution by a processor. The set of instructions may include various commands that instruct the processor to perform specific operations such as the methods and processes of the various embodiments described herein. The set of instructions may be in the form of a software program or application. The memory devices may include volatile and non-volatile media, removable and non-removable media implemented in any method or technology for storage of information such as computer-readable instructions, data structures, program modules or other data. The computer storage media may include, but are not limited to, RAM, ROM, EPROM, EEPROM, flash memory or other solid state memory technology, CD-ROM, DVD, or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other suitable storage medium.
This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.
