Shaker screen condition monitoring

Abstract

A shale shaker system includes a shaker screen and a fluid sampling loop coupled to a collection device or shaker sump of the shale shaker system. The fluid sampling loop may include one or more of a pump, a pressure sensor, a blowdown valve, a flowmeter, or a strainer. The fluid sampling loop is used to monitor the condition or health of the shaker screen. The shale shaker system may include a flushing loop for cleaning the strainer. Related methods include using pressure differentials, flow rates, or other metrics in a fluid sampling loop to monitor the condition or health of shaker screens. The methods may include flushing the fluid sampling loop to clean it.

Description

SHAKER SCREEN CONDITION MONITORINGCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims benefit of U.S. provisional patent application No. 63 / 602,254 filed November 22, 2023, entitled “Systems and Methods for Shaker Screen Condition Monitoring”, which is incorporated herein in its entirety for all purposes.STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable.BACKGROUND

[0003] Vibrating screening devices (“shale shakers”) are integral in process flows as a means to separate unwanted materials from desired materials. Though vibrating screening devices overwhelmingly find use in oil and gas exploration and production, other industries such as mining, rely on screening devices with the linear vibration and fine screening capabilities of shale shakers. The process industry also utilizes screening and shaker equipment in a variety of separation applications as can be seen in chemical, paper, sand, powder, plastic, and other separation plants.

[0004] In the oil and gas industry, drilling fluid (also known as “mud”) is a critical component during well construction. For example, to obtain hydrocarbons from a subterranean earthen formation, a wellbore may be formed using a drilling system including a drill string configured to convey a drilling fluid into a borehole. The drill string may include a drill bit located at an end thereof and configured to cut into the earthen formation. In certain applications, the drilling fluid is configured to provide hydrostatic well control, and lubricate the drill bit. The drilling fluid may simultaneously cool the bit and carry solid material produced by the drill bit, known as drill cuttings, to the surface through an annulus formed between the drill string and the borehole. The cuttings and debris carried to the surface by the drilling fluid provide useful information, among other things, about the wellbore being formed and the drilling process. The drilling fluids are a mixture of various chemicals in a water or oil based solution and can be very expensive to make. For both environmental reasons and to reduce the cost of drilling operations, it is normal therefore to recover and re-use drilling fluid, but this requires the solids to be removed from the drilling fluid to avoid operational issues and equipment damage. Thus,to permit re-use of a drilling fluid, a series of screening devices known as shale shakers are used at the surface to separate the drilled cuttings and other solids from the drilling fluid. The drilling fluid is then circulated through the drilling assembly again, while the drill cuttings are sent to a separate storage tank for analysis or to discard them.BRIEF DESCRIPTION OF THE DRAWINGS

[0005] For a detailed description of disclosed exemplary embodiments, reference will now be made to the accompanying drawings in which:

[0006] Figure 1 is a schematic view of an embodiment of an exemplary drilling system in accordance with principles disclosed herein;

[0007] Figure 2 is a schematic view of an embodiment of an exemplary well circulation system in accordance with principles disclosed herein;

[0008] Figure 3 is a top view of an embodiment of an exemplary shaker screen in accordance with principles disclosed herein;

[0009] Figure 4 is a top view of an embodiment of an exemplary damaged shaker screen in accordance with principles disclosed herein, including enlarged portions A, B, and C of the shaker screen;

[0010] Figure 5 is a schematic view of an embodiment of an exemplary shaker screen condition monitoring system in accordance with principles disclosed herein;

[0011] Figure 6 is a perspective view of a pump and fluid routing portion of the shaker screen condition monitoring system of Figure 5;

[0012] Figure 7 is a schematic view of another embodiment of an exemplary shaker screen condition monitoring system in accordance with principles disclosed herein;

[0013] Figure 8 is a perspective view of a pump and fluid routing portion of the shaker screen condition monitoring system of Figure 7;

[0014] Figure 9 is a perspective view of yet another embodiment of an exemplary shaker screen condition monitoring system in accordance with principles disclosed herein;

[0015] Figure 10 is a perspective view of still another embodiment of an exemplary shaker screen condition monitoring system in accordance with principles disclosed herein;

[0016] Figure 11 is various views of an embodiment of an exemplary motor mount of Figure 10 in accordance with principles disclosed herein; and

[0017] Figure 12 is a schematic view of an embodiment of an exemplary computing system for implementing shaker screen condition monitoring in accordance with principles disclosed herein.DETAILED DESCRIPTION

[0018] The following discussion is directed to various embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

[0019] In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to... .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection as accomplished via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation.

[0020] As described above, vibrating screening devices are used to separate unwanted materials from desired materials. Generally, vibrating screening devices are referred to as “shale shakers” because vibrational motion, or “shaking,” is used in the filtration process. For the oil and gas industry, whether onshore or offshore, drilling is considered one of the first steps in the process of extracting hydrocarbon-based resources, and shale shakers are very important in the drilling process because they are the first line of defense against solids contamination, as solid bypassing the shale shakers can causesignificant operational costs. In addition to the cost of having to filter the same solids more than once, increased chemical consumption, fluid dilution, reduced drilling speed, and damaged equipment are additional effects of solids contamination in drilling fluid.

[0021] A shale shaker typically consists of a shaker table, and a plurality of filter screen components aligned adjacent to each other within a shaker bed to filter cuttings from the drilling mud. The filter screen components are mainly the frame, and wire mesh which is sized according to target specific sized particles to be removed, whereby one or more mesh layers are employed to prevent solids above a certain diameter from passing through. The maximum particle size that a given shaker screen will allow to pass through is known as the filtration “cut point.” The screen mesh layer(s) act as a sieving mechanism while the frame provides structural integrity to the mesh while it operates under vigorous vibration, temperature, and load. Because of the vigorous vibration applied to the screens during the filtration process, the fine mesh stainless steel wire cloth of the shaker screens eventually becomes damaged as a result of friction between the screen and the cuttings. The screens eventually wear the mesh down and abrasions, tears, and punctures in the screen begin to pass larger more damaging particles into the active drilling fluid system. A screen failure or damage may have occurred when the wire mesh panels degrade or break to the point where particles outside the desired range pass through the screen, which can lead to changes in fluid properties, damage to equipment further upstream and issues with the drilling process. It is therefore desired to identify when damage occur to the screen panel that allows particles above the target range to pass through, and notify an operator so preventive or corrective actions may be taken.

[0022] Traditionally, visual inspections are conducted periodically by rig personnel to identify these screen damage, and then decide whether to repair the damaged screen cells, replace the screen, or to continue operating with the screen in its current condition. However, it is often difficult for rig personnel to visually identify damaged screens since they are constantly covered by mud and cuttings while the shakers are operating. Usually, an operator may have to wait for the mud on the shaker to clear before inspecting the shaker screens. Additionally, monitoring shaker screens is not the operator’s only job, so frequently, screen damage is only identified many hours or even days after defects arise and high volumes of solids bigger than the cut point have passed through without being filtered. Accordingly, embodiments described herein are directed to systems and methods for shaker screen condition monitoring without the need forrig personnel to visually inspect the shaker screens and without having to wait for the mud on the shaker screen to clear, or halt operation of the shale shaker. Although used for shaker screen condition monitoring, the systems and methods disclosed herein may be used for monitoring both shaker screen condition and defects in the seals associated with a shaker screen.

[0023] Embodiments of systems and methods for shaker screen condition monitoring described herein comprise sampling a portion of used drilling fluid which has passed through the shaker screens, and pumping the drilling fluid sample through a loop containing one or more strainers, and one or more sensors to monitor the condition or health of the shaker screen. As used herein, a strainer refers to any device capable of separating suspended particles from fluids (e.g., drilling fluids). In some embodiments, a shaker screen condition monitoring system includes one or more shaker screens comprising a plurality of screen cells having multiple layers in a sandwiched arrangement, one or more fluid inlets or ports, one or more fluid outlet ports, one or more fluid pumps, one or more strainers having one or more inlet and outlet ports and a replaceable filter element, one or more sensors, and one or more blowdown valves for cleaning out the strainers. In some embodiments, a shaker screen condition monitoring system may include one or more pressure sensors for measuring fluid pressure or pressure differential across the one or more strainers, and / or observing the fluid flow rate across the one or more strainers. In some embodiments, a shaker screen condition monitoring system may also include multiport valves for altering fluid flow direction to flush out any accumulation or debris in the fluid sampling loop. In some embodiments, a shaker screen condition monitoring system may include one or more flowmeters for measuring the flowrate across the one or more strainers. In some embodiments, a shaker screen condition monitoring system may include one or more flowmeters, and one or more pressure sensors placed upstream of the strainer to detect fluid flow through the shale shaker and thereby prevent false reading by the flowmeters.

[0024] In some embodiments a shaker screen condition monitoring system may also include a vibrating motor for moving viscous fluid across the system to prevent accumulation or clogging. For example, if a fluid sample has cuttings or solid material, the filter element in the strainer may become blocked creating a flow restriction resulting in fluid pressure increase or pressure differential between the inlet and outlet of the strainer which may be measured by the one or more pressure sensors. Ablockage in the strainer may also reduce or completely seize fluid flow across the one or more strainers which may be visually observed or measured by the one or more flowmeters. Particularly, an operator may identify the condition or health of the shaker screen by monitoring pressure sensor readings and observing the flowrate across the strainers, monitoring flowmeter readings, or by monitoring pressure sensor and flowmeter readings. Additionally, the timing or frequency of blockage in the strainers may indicate the severity of the shaker screen damage. In some embodiments, the pressure sensors and flow meters may be coupled to a computing system on the rig or in a remote location which may notify rig personnel when the measured pressure and / or flowrate exceeds a predefined threshold. In some embodiments, information obtained from a shaker screen condition monitoring system may be used to train a machine learning algorithm to detect the condition of a shaker screen and the severity of damage to the shaker screen.

[0025] Referring to Figure 1 , an embodiment of an exemplary well or drilling system 10 for drilling or producing hydrocarbons from a well or wellbore in accordance with principles disclosed herein is shown. In this exemplary embodiment, drilling system 10 generally includes a vertical support structure or derrick 12 supported by a drilling platform 14. Platform 14 includes a drill deck or rig floor 16 supporting a rotary table 18 selectively rotated by a prime mover (not shown), such as an electric motor, controlled by a motor controller. Derrick 12 includes a traveling block 20 controlled by a drawworks 22 for raising and lowering a drillstring 24 suspended from traveling block 20. Drillstring 24 of drilling system 10 extends downward through the rotary table 18, a blowout preventer (BOP) stack 26, and into a wellbore 3 that extends into a subterranean earthen formation 5 along a central or longitudinal axis 15 from the surface 7. Drillstring 24 is formed from a plurality of drill pipe joints 28 connected end-to-end. In this exemplary embodiment, a bottom-hole-assembly (BHA) 30 is attached to the lowermost pipe joint 28 and a drill bit 32 is attached to the downhole end of BHA 30. In other embodiments, drilling system 10 may comprise an offshore drilling system that includes a drillstring that extends through a marine riser and into a subsea wellbore.

[0026] In this embodiment, drill bit 32 is rotated with rotary table 18 via drillstring 24 and BHA 30. By rotating drill bit 32 with weight-on-bit (WOB) applied thereto, the drill bit 32 disintegrates the subsurface formations to drill wellbore 3. In some embodiments, a topdrive may be used to rotate the drillstring 24 rather than rotation by the rotary table 18. In some applications, a downhole motor (mud motor) 35 is disposed in the drillstring 24to rotate the drill bit 32 in lieu of or in addition to rotating the drillstring 24 from the surface 7. Particularly, the mud motor 35 may rotate the drill bit 32 when a drilling fluid passes through the mud motor 35 underpressure. In this exemplary embodiment, a casing string 34 is installed and extends downward generally from the surface 7 into at least a portion of wellbore 3. In some embodiments, casing string 34 is cemented within the wellbore 3 to isolate various vertically-separated earthen zones and prevent fluid transfer between the zones. BOP stack 26 is secured to the uphole end of casing string 34. Casing string 34 may comprise multiple tubular members, such as pieces of threaded pipe that are joined end-to-end to form liquid-tight or gas-tight connections, to prevent fluid and pressure exchange between wellbore 3 and the surrounding earthen zone.

[0027] An annular space or annulus 36 is formed between both the sidewall 9 of wellbore 3 and drillstring 24 and between inner surface of casing string 34 and drillstring 24. In other words, annulus 36 extends through wellbore 3 and casing string 34. BOP stack 26 includes an annular space or flow path in fluid communication with annulus 36. An operator or drilling control system of drilling system 10 may selectively and controllably open and close one or more BOPs of BOP stack 26 to allow, to restrict, or to inhibit the flow of drilling fluid or another fluid through annulus 36. In this exemplary embodiment, drilling system 10 includes a drilling fluid circulation system 50 to circulate drilling fluid or mud 40 down drillstring 24 and back up annulus 36.

[0028] Referring to Figures 1 and 2, an embodiment of an exemplary drilling fluid circulation system 50 in accordance with principles disclosed herein is shown. Drilling fluid circulation system 50 includes a drilling fluid reservoir or mud tank 42, a supply pump 44, a supply line 46 connected to the outlet of supply pump 44, a kelly 48 for supplying drilling fluid 40 to the drillstring 24, and a shale shaker 52 for separating used drilling mud 40 from drill cuttings. Drilling fluid 40 generally functions to cool drill bit 32, remove cuttings from the bottom of wellbore 3, and maintain a desired pressure or pressure profile in wellbore 3 during drilling operations. In this exemplary embodiment, drilling fluid 40 is mixed in the mud tank 42, and pumped by the mud pumps 44 through supply line 46 and kelly 48 through the BOP 26 down the drillstring 24 to the drill bit 32. Next, the drilling fluid 40 exits the nozzles of the drill bit 32 and flows up the annulus 36 between drillstring 24 and wellbore 3, thereby lifting cuttings to the surface 7. The cuttings laden drilling fluid 40 flows over shale shaker 52, where the drilling fluid 40 is separated from the cuttings and other solid particles by shaker screen 60. The screened drilling fluid 40 can then be directed back to the mud tank 42 to be re-used. While drilling system 10and drilling fluid circulation system 50 are described generally, it may be understood that the configuration of drilling system 10 and drilling fluid circulation system 50 may vary in other embodiments from that shown in Figures 1 and 2.

[0029] Referring now to Figure 3, an embodiment of an exemplary shaker screen assembly 60 in accordance with principles disclosed herein is shown. The shaker screen assembly 60 may include a perforated plate 62 on which is mounted a plurality of screen cells 70 comprising one, two, three or more layers of screening material in a sandwiched arrangement, i.e., screen, mesh, and / or cloth made for example, of stainless-steel wire, plastic wires, or molded cloth. The layers of the screening material (e.g., screen cell layers 72, 74, and 76) may be bonded together, for example, by being glued, welded, and / or sintered in any manner and bonded to the plate 62 in any suitable manner. The plate 62 includes a plurality of side holes 64 on each of two opposite sides for receiving releasable fasteners for mounting the screen assembly 60 in a suitable shale shaker, e.g., shale shaker 52 of Figure 2.

[0030] Referring now to Figure 4, an embodiment of an exemplary damaged shaker screen in accordance with principles disclosed herein is shown. As described above, each one of the pluralities of screen cells 70 of shaker screen 60 may include one, two, three or more cell layers in a sandwiched arrangement (e.g., cell layers 72, 74, and 76 of Figure 3). For example, depending on which screen cell layer or layers is damaged, screen cell condition may be classified as undamaged A, missing or torn top layer B, or cell blowout C. In an embodiment, cell blow-outs may occur when all the cell layers (for example, cell layers 72, 74, and 76 of Figure 3) are damaged to the point where there is an unimpeded path for large particles in the drilling fluid (e.g., drilling fluid 40 of Figure 2) to pass through the screen cell. When there is a missing or torn top layer, only the coarser middle and bottom layers remain to limit the size of particles passing through. Thus, an operator may decide that a shaker screen with only a missing or torn top layer requires a repair without the need to completely remove or replace the entire shaker screen.

[0031] As previously described, shale shakers form the first phase of solids control in many industries including oil and gas drilling. To identify shaker screen defects and prevent damage to drilling equipment, drilling rig operators may periodically inspect shaker screens for defects. However, periodic inspection of shaker screens by rig personnel may not be effective and could lead to expensive delays and down time because of the presence of drilling fluid on the shaker screens while the shaker is inoperation. Accordingly, embodiments described herein are directed to systems, which may be referred to as shaker screen condition monitoring systems, for monitoring the condition of shaker screens and associated seals without the need for rig personnel to visually inspect the shaker screens and without having to wait for the mud on the shaker screen to clear or halt operation of the shale shaker.

[0032] Referring now to Figures 5-6, an embodiment of an exemplary shaker screen condition monitoring system 100 in accordance with principles disclosed herein is shown. In some embodiments, shaker screen condition monitoring system 100 includes a fluid sampling loop comprising at least one fluid sampling loop inlet or port 103 fluidly coupled to the mud tank, at least one fluid sampling loop outlet or port 104 fluidly coupled to the mud tank, and one or more shaker screens 120 mounted within the mud tank, each shaker screen 120 comprising a plurality of screen cells (for example, screen cell 70 of Figure 3), each screen cell having a plurality of cell layers (for example, cell layers 72, 74, and 76 of Figure 3). The fluid sampling loop further includes at least one strainer 110, each strainer comprising a filter element (not shown) with a mesh size equal to or greater than the mesh on shaker screen 120, one or more fluid pumps 130, a blowdown valve 140 coupled to the strainer 110 to release clogging and clean out solid material in the strainer, and pressure sensors 150 located on either side of, or upstream and downstream of, strainer 110 and in fluid communication with strainer 110. Strainer 110 may be located upstream or downstream of pump 130. While two pressure sensors 150 are shown in Figures 5-6, other numbers of pressure sensors may be used.

[0033] As described above and best shown in Figure 5, used drilling fluid 40 may flow from a drilling fluid inlet 101 in the mud tank over shaker screen 120 where cuttings and other solid materials are separated from the drilling fluid and discarded through an outlet 102 in the mud tank. After flowing over and then through shaker screen 120, drilling fluid 40 flows into a shaker sump 105 downstream of shaker screen 120 where a portion or sample of drilling fluid 40 that has passed through shaker screen 120 may be drawn into fluid sampling loop inlet 103 and pumped by fluid pump 130 through the sampling loop containing strainer 110. Pump 130 may be of any type suitable for fluid movement, and the fluid sample may be drawn from any portion downstream of the shaker screen. For example, the fluid sample may be drawn from manifolds or inlet ports located in sump 105. The manifold may be designed to have an adjustable orientation to draw fluid from a preferred location in sump 105. Furthermore, the fluidsample may be drawn by providing in sump 105 a tray having drain holes for collecting the fluid sample. The tray may form part of the shale shaker design. As the fluid sample flows across strainer 110, if solid material or debris is present in the fluid sample, the mesh in the filter element of strainer 110 may become blocked thereby creating a fluid flow restriction in strainer 1 10, resulting in a pressure increase that may be measured by pressure sensors 150.

[0034] In some embodiments, there are two pressure sensors 150, and they may be located on either side of strainer 110 as shown in Figure 5, and the differential pressure between the two sensors may indicate flow restriction within strainer 110. In other embodiments, one pressure sensor 150 is used, and pressure sensor 150 may be located upstream of strainer 110 and pressure readings in pressure sensor 150 may indicate flow restriction within strainer 1 10. Additionally, flow restriction in strainer 110 may also result in a decrease or complete seizure of fluid flow across strainer 110, which may be visually observed by an operator. In still other embodiments, there are no pressure sensors, and the discharge flowrate in the sampling loop may be used to assess flow restriction in strainer 110. For example, the discharge flow rate in the sampling loop may reduce as accumulation of solid material increases in strainer 110. Particularly, by monitoring pressure sensors 150 and / or by observing the flow rate across strainer 1 10, an operator may identify the condition of shaker screen 120.

[0035] In some embodiments, after detecting a shaker screen defect and repairing or replacing shaker screen 120, blowdown valve 140 may be used to clean out strainer 110 and remove any solid material that may be clogged in the filter of strainer 110 prior to resuming operation of shaker screen condition monitoring system 100. Cleaning strainer 110 may be accomplished by opening the attached blowdown valve 140, thereby forcing accumulated material in strainer 110 through a separate outlet (not shown) and discarding them.

[0036] Additionally, in some embodiments, shaker screen condition monitoring system 100 may be configured to alert an operator when sensor pressure or pressure differential across strainer 110 exceeds a predefined threshold. For example, pressure sensors 150 may be coupled to a computing system located on the rig or at a remote center for managing rig operations, such that an operator may be notified when the sensor pressure or pressure differential across strainer 110 is greater than or equal to a threshold value. For example, if sensor pressure or pressure differential across strainer 1 10 is less than or equal to 10 psi, an operator may be notified, and theoperator may decide to continue operating the shale shaker, but if sensor pressure or pressure differential across strainer 110 is greater than 10 psi, an operator may decide to stop operation of the shale shaker for inspection and repair or replacement of the shaker screen.

[0037] Referring now to Figures 7-8 another embodiment of an exemplary shaker screen condition monitoring system 200 in accordance with principles disclosed herein is shown. Shaker screen condition monitoring system 200 includes features in common with shaker screen condition monitoring system 100 shown in Figures 5-6, and shared components are labelled similarly. Particularly, in this exemplary embodiment, shaker screen condition monitoring system 200 generally includes one or more flushing inlets 203 fluidly coupled to the mud tank, flushing outlets 204 fluidly coupled to the mud tank, strainer 210 for filtering and flushing, and one or more multiport valves 240 (Figure 8) fluidly coupled to strainer 210 and used to alter fluid flow direction to flush the sampling loop of any accumulated fluid (e.g., high viscosity fluid), solid materials or debris. In some embodiments, fluid flows into the flushing loop from flushing inlet 203 and through strainer 210, and is pumped through strainer 210 to loosen and / or remove any clogging in strainer 210. The fluid used for flushing may be drilling fluid which has passed through shaker screen 120 or may be fluid suctioned from a separate source. After flushing, the fluid flows out through flushing outlets 204 into the shaker sump (e.g., sump 105 of Figure 5) or through a separate return line, and the fluid sampling loop may resume operation as described in shaker screen condition monitoring system 100. The multiport valves 240 and the one or more blowdown valves 140 may be manual or have different levels of automation.

[0038] Referring now to Figure 9, another embodiment of an exemplary shaker screen condition monitoring system 300 in accordance with principles disclosed herein is shown. Shaker screen condition monitoring system 300 includes a fluid collection tray (not shown) having a length equal to the outlet of a shale shaker (e.g., shale shaker 52 of Figure 2) and a height of about 4 inches for capturing fluid exiting the shale shaker, fluid sampling inlet 303, one or more shaker screens (e.g., shaker screen 120 of Figure 5), at least one strainer 310 (each strainer have a mesh size matching the mesh size on the shaker screen), one or more flowmeters 360 coupled to the strainer 310 and one or more pressure sensors 350 coupled to the shale shaker. In some embodiments, the one or more flowmeters 360 may be located upstream and downstream of strainer 310. Each strainer 310 comprises a filter element. As fluidwhich has passed through the shaker screen (e.g., drilling fluid 40 of Figure 1 ) flows from the fluid collection tray and into fluid sampling inlet 303, the fluid is directed to strainer 310 under the fluid’s momentum from the shale shaker sump such that if there are any debris or solid materials, strainer 310 may become blocked thereby causing a flow restriction which may be detected by the one or more flowmeters 360 downstream of strainer 310. Particularly, if the strainer element of strainer 310 is blocked with debris or solid materials, fluid may not pass through thereby resulting in a decrease in fluid flow or no flow at all. In some embodiments, shaker screen condition monitoring system 300 may include one or more pressure sensors 350 located upstream of strainer 310 to detect fluid flow through the shale shaker, thereby preventing a false reading by the flowmeter 360.

[0039] In some embodiments, the one or more flowmeters 360 may be coupled to a computing system on the rig or at a remote location which may activate an alert system to notify an operator when the flow rate across strainer 310 falls below a predefined threshold value. For example, if flowmeter 360 reads a non-zero value above the predefined threshold, the computing system may not indicate a screen failure and no alert is sent. But, if flowmeter 360 reads zero, and pressure sensors 350 record increased value, the computing system may indicate screen failure and notify the operator. Additionally, if flowmeter 360 reads zero, and pressure sensor 350 records no pressure increase, the computing system may indicate the shale shaker is currently not in operation (i.e., mud pumps off, drilling halted, etc.). While Figure 9 shows a shaker screen condition monitoring system 300 with one pressure sensor 350 and one flowmeter 360, it may be understood that shaker screen condition monitoring system 300 may comprise one or more flow meters as described, and one or more pressure sensors.

[0040] Referring now to Figure 10 another embodiment of shaker screen condition monitoring system 400 in accordance with principles disclosed herein is shown. Shaker screen condition monitoring system 400 includes features in common with shaker screen condition monitoring system 300 shown in Figure 9. Particularly, shaker screen condition monitoring system 400 includes a vibrating motor 480 coupled to a strainer 410 having a filter element, and one or more flowmeters 460 located upstream and downstream and fluidly coupled to strainer 410. Vibrating motor 480 may be mounted to strainer 410 to excite the system and allow more viscous drilling fluid to pass through strainer 410 thereby preventing clogging. Vibrating motor 480 may bemounted with a motor mount 490. The design of motor mount 490 is shown in Figure 12.

[0041] A computer system 500 suitable for implementing one or more embodiments disclosed herein is shown. For example, the notification or operator alert for shaker screen condition monitoring systems described above may comprise the computing system 500 or at least some of the features of computing system 500 such as a desktop computer, notebook computer, a tablet computer, a smartphone, a network server, or other suitable device known in the art. In some embodiments, the computing system embodying the notification or operator alert for the shaker screen condition monitoring system may comprise a plurality of separate computer systems located on a drilling platform 14 and / or locations remote from the drilling platform 14. Computing system 500 includes a processor 502 (which may be referred to as a central processor unit or CPU) that is in communication with memory devices including secondary storage 504, read only memory (ROM) 506, random access memory (RAM) 508, input / output (I / O) devices 510, and network connectivity devices 512. The processor 502 may be implemented as one or more CPU chips. It is understood that by programming and / or loading executable instructions onto computing system 500, at least one of the CPU 502, the RAM 508, and the ROM 506 are changed, transforming computing system 500 in part into a particular machine or apparatus having the novel functionality taught by the present disclosure.

[0042] Additionally, after the system 500 is turned on or booted, the CPU 502 may execute a computer program or application. For example, the CPU 502 may execute software or firmware stored in the ROM 506 or stored in the RAM 508. In some cases, on boot and / or when the application is initiated, the CPU 502 may copy the application or portions of the application from the secondary storage 504 to the RAM 508 or to memory space within the CPU 502 itself, and the CPU 502 may then execute instructions that the application is comprised of. During execution, an application may load instructions into the CPU 502, for example, load some of the instructions of the application into a cache of the CPU 502. In some contexts, an application that is executed may be said to configure the CPU 502 to do something, e.g., to configure the CPU 502 to perform the function or functions promoted by the subject application. When the CPU 502 is configured in this way by the application, the CPU 502 becomes a specific purpose computer or a specific purpose machine.

[0043] Secondary storage 504 may be used to store programs which are loaded into RAM 508 when such programs are selected for execution. For example, the processor 502 may be configured to execute instructions retrieved from storage 504 to analyze sensor data received from the one or more pressure sensors and or one or more flowmeters. To perform this operation, computing system 500 may comprise a machine learning algorithm configured to train the processors 502 to analyze the condition of the shaker screen and determine severity of damage. The processor 502 may also compare sensor readings to a predefined threshold and alert an operator.

[0044] The ROM 506 is used to store instructions and perhaps data which are read during program execution. ROM 506 is a non-volatile memory device which typically has a small memory capacity relative to the larger memory capacity of secondary storage 504. The secondary storage 504, the RAM 508, and / or the ROM 506 may be referred to in some contexts as computer readable storage media and / or non-transitory computer readable media. I / O devices 510 may include printers, video monitors, liquid crystal displays (LCDs), touch screen displays, keyboards, keypads, switches, dials, mice, track balls, voice recognizers, card readers, paper tape readers, or other well- known input devices.

[0045] The network connectivity devices 512 may take the form of modems, modem banks, Ethernet cards, universal serial bus (USB) interface cards, wireless local area network (WLAN) cards, radio transceiver cards, and / or other well-known network devices. The network connectivity devices 512 may provide wired communication links and / or wireless communication links. These network connectivity devices 512 may enable the processor 502 to communicate with the Internet or one or more intranets. With such a network connection, it is contemplated that the processor 202 might receive information from the network, or might output information to the network.

[0046] The processor 502 executes instructions, codes, computer programs, scripts which it accesses from hard disk, optical disk, flash drive, ROM 506, RAM 508, or the network connectivity devices 512. While only one processor 502 is shown, multiple processors may be present. Thus, while instructions may be discussed as executed by a processor, the instructions may be executed simultaneously, serially, or otherwise executed by one or multiple processors. Instructions, codes, computer programs, scripts, and / or data that may be accessed from the secondary storage 504, for example, hard drives, optical disks, and / or other device, the ROM 506, and / or the RAM 508 maybe referred to in some contexts as non-transitory instructions and / or non-transitory information.

[0047] In an embodiment, computing system 500 may comprise two or more computers in communication with each other that collaborate to perform a task. For example, but not by way of limitation, an application may be partitioned in such a way as to permit concurrent and / or parallel processing of the instructions of the application. Alternatively, the data processed by the application may be partitioned in such a way as to permit concurrent and / or parallel processing of different portions of a data set by the two or more computers. In an embodiment, the functionality disclosed above may be provided by executing the application and / or applications in a cloud computing environment. Cloud computing may comprise providing computing services via a network connection using dynamically scalable computing resources.

[0048] While disclosed embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1 ), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

CLAIMSWhat is claimed is:

1. A system, comprising: a shale shaker comprising one or more shaker screens, each shaker screen having a plurality of screen cells; and a fluid sampling loop comprising: one or more fluid sampling inlet ports configured to receive a sample of drilling fluid that has passed through the shaker screen; one or more fluid sampling outlet ports configured to discharge sampled drilling fluid from the fluid sampling loop into a shaker sump; one or more fluid pumps configured to pump the sampled drilling fluid through the fluid sampling loop; one or more pressure sensors; one or more blowdown valves; and one or more strainers, each strainer comprising a filter element having a mesh size greater or equal to a mesh size on the shaker screen, one or more inlet ports, and one or more outlet ports, wherein the strainer is fluidly coupled to the blowdown valve and the sensor.

2. The system of claim 1 , wherein the blowdown valve is configured to loosen solid material or debris clogged in the strainer.

3. A system, comprising: a shale shaker comprising one or more shaker screens, each shaker screen having a plurality of screen cells; a fluid sampling loop comprising one or more fluid sampling inlet ports configured to receive a sample of drilling fluid that has passed through the shaker screen, one or more fluid sampling outlet ports configured to discharge fluid from the fluid sampling loop into a shaker sump, one or more fluid pumps configured to pump fluid through the sampling loop, one or more blowdown valves, and one or more strainers, wherein the strainer comprises a filter element having a mesh size greater or equal to a mesh sizeon the shaker screen, one or more inlet ports, and one or more outlet ports, and wherein the blowdown valve is coupled to the strainer; and a fluid flushing loop comprising a flushing fluid, one or more multiport valves configured to altera direction of fluid flow in the fluid sampling loop, one or more flushing inlets, one or more flushing outlets, and one or more strainers, wherein the strainer is coupled to the multiport valve.

4. The system of claim 3, wherein the flushing fluid is the same or different from the sampled fluid.

5. The system of claim 3, wherein the flushing loop and the sampling loop are the same or different.

6. The system of claim 3, wherein the direction of fluid flow in the flushing loop is opposite the direction of fluid flow in the sampling loop.

7. A system, comprising: a shale shaker comprising one or more shaker screens, each shaker screen having a plurality of screen cells; a fluid collection device; one or more fluid inlet ports configured to receive a portion or sample of drilling fluid that has passed through the shaker screen from the fluid collection device; one or more fluid outlet ports configured to discharge fluid into a shaker sump; one or more flowmeters; and one or more strainers, each strainer having a mesh size equal to a mesh size on the shaker screen, one or more inlet ports, and one or more outlet ports, wherein the strainer is coupled to the flowmeters.

8. The system of claim 7, further comprising one or more pressure sensors placed upstream of the strainer and coupled to the shale shaker, wherein the pressure sensor is configured to detect fluid flowing in the shaker.

9. The system of claim 7, wherein one flowmeter is placed upstream of the strainer, and another flowmeter is placed downstream of the strainer.

10. The collection device of claim 7, comprising a length equal to an outlet of the shale shaker.11 . The system of claim 7, further comprising a vibrating motor.

12. The vibrating motor of claim 11 , comprising a motor mount for installing the vibrating motor on the system.

13. A method, comprising: receiving a sample of a drilling fluid which has passed through a shaker screen through a fluid sampling loop inlet port; pumping the drilling fluid sample through a fluid sampling loop, the fluid sampling loop comprising one or more strainers, the strainers having one or more inlet ports, one or more outlet ports, and a filter element having a mesh size greater or equal to a mesh size on the shaker screen; wherein the strainer is coupled to one or more sensors and one or more blowdown valves; and discharging the sampled fluid through a fluid sampling loop outlet into a shaker sump.

14. The method of claim 13, further comprising observing a flowrate across the strainer.

15. A method, comprising: receiving a flushing fluid through a fluid flushing loop inlet port; pumping the flushing fluid through a fluid flushing loop, the fluid flushing loop comprising one or more strainers, the strainers having one or more inlet ports, one or more outlet ports, and a filter element having a mesh size greater or equal to a mesh size on a shaker screen coupled to the fluid flushing loop; and one or more multiport valves, wherein the strainer is coupled to the multiport valve; discharging the flushing fluid through a fluid flushing loop outlet into a shaker sump; receiving a sample of a drilling fluid which has passed through a shaker screen through a fluid sampling loop inlet port;pumping the sampled fluid through a fluid sampling loop, the fluid sampling loop comprising one or more blowdown valves, one or more strainers, the strainers having one or more inlet ports, one or more outlet ports, and a filter element having a mesh size greater or equal to a mesh size on the shaker screen; wherein the strainer is coupled to one or more sensors and one or more blowdown valves; and discharging the sampled fluid through a fluid sampling loop outlet into a shaker sump.

16. The method of claim 15, wherein the flushing fluid and the sampled fluid are the same or different.

17. The method of claim 15, further comprising observing a flowrate across the strainers.

18. A method, comprising: receiving a sample of a drilling fluid which has passed through a shaker screen from a fluid collection device; passing the sampled fluid through one or more strainers, the strainers having one or more inlet ports, one or more outlet ports, and a filter element having a mesh size greater or equal to a mesh size on the shaker screen, wherein the strainer is coupled to one or more flowmeters; observing a flowrate across the flowmeters; and discharging the sampled fluid through a fluid outlet into a shaker sump.

19. The method of claim 18, further comprising one or more pressure sensors, wherein the pressure sensor is located upstream of the strainer, and coupled to a shale shaker.

20. The method of claim 19, comprising observing readings from the pressure sensors.

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