METHOD FOR PERFORMING WELL OPERATIONS AND SYSTEM FOR DETERMINING A WELL BOTTOM PARTICLE VOLUME

Abstract

A method for performing well operations and a system for determining a volume of bottomhole particles. A well system for handling bottomhole particles. The well system may include a mud pump, an agitator including a corrugated vibrating screen, a drill string, an imaging device, and a data acquisition system that may include a processor.The processor can be programmed to determine a cross-sectional area of ​​a portion of the corrugated vibrating screen occupied by bottomhole particles in a first image based on the first image, a known corrugated vibrating screen profile, and a known distance and angle between the imaging device and the corrugated vibrating screen; to determine a volume of bottomhole particles in the portion of the corrugated vibrating screen in the first image based on the cross-sectional area occupied by bottomhole particles, a velocity of the bottomhole particles passing through the corrugated vibrating screen, and an image generation rate.

Description

1 / 28 “METHOD FOR PERFORMING WELL OPERATIONS AND SYSTEM FOR DETERMINING A WELL BOTTOM PARTICLE VOLUME” Fundamentals

[0001] This section is intended to provide relevant background information to facilitate a better understanding of the various aspects of the modalities described. Therefore, these statements should be read in this light, and not as admissions of prior art.

[0002] Increasing the effectiveness of pumping, sweeping, drilling, fracturing, etc. operations can reduce the cost of hydrocarbon recovery operations. One approach to increasing the effectiveness of such operations is to observe the characteristic features of various particles that return from the bottom of the well to the Earth's surface during different hydrocarbon recovery operations.

[0003] Often, returned particles are observed as they move through a flat vibrating screen. However, corrugated vibrating screens are becoming increasingly common in the oilfield, and the methods used to observe particles on a flat vibrating screen cannot be used with corrugated vibrating screens because of the bumps and grooves formed on the corrugated vibrating screen. Brief description of the drawings

[0004] Well system embodiments including a downhole particle management system are described with reference to the following figures. The same numbers are used in all figures to refer to similar features and components. The features represented in the figures are not necessarily shown to scale. Certain features of the embodiments may be shown exaggerated in scale or in a somewhat schematic way, and some element details may not be shown in the interest of clarity and conciseness.

[0005] FIG. 1 is a block diagram of a system for determining a bottom-hole particle volume in a corrugated vibrating screen, according to one or more embodiments;

[0006] FIG. 2 is a schematic diagram of a well system arranged in a well, according to one or more modalities; Petition 870260011094, dated 05 / 02 / 2026, page 11 / 45 2 / 28

[0007] FIG. 3 is a flowchart of operations for evaluating and possibly altering downhole drilling operations based on the analysis of downhole fragment and cuttings volume, according to one or more modalities;

[0008] FIG. 4 is a continuation of the flowchart in FIG. 3;

[0009] FIG. 5 is a continuation of the flowchart in FIG. 4;

[0010] FIG. 6 is a schematic diagram of a fracturing operation, according to one or more modalities;

[0011] FIG. 7 is a flowchart of operations for evaluating and using the results of a fracturing operation, according to one or more modalities; and

[0012] Fig. 8 is a block diagram of a computer, according to one or more modalities. Detailed description

[0013] The following description includes examples of systems, methods, techniques, and program flows that describe multiple modalities. However, it is understood that this disclosure can be practiced without these specific details. For example, this disclosure refers to drilling and fracturing operations for downhole particle analysis. Aspects of this disclosure may also be applied to any other applications that return downhole particles to the surface. In other cases, instances of well-known instruction, protocols, structures, and techniques have not been shown in detail so as not to obscure the description.

[0014] Several modalities refer to the processing and analysis of downhole particles returned from a well to the Earth's surface. For example, downhole particles may be fragments and drilling cuttings that return to the surface of the well bottom during well drilling. In another example, downhole particles may be proppants and any other particles (e.g., portions of the formation) that return to the surface during or after hydraulic fracturing operations.

[0015] The methods use one or more cameras, a corrugated vibrating screen, and volume calculations to determine the volume of bottomhole particles per unit depth of the well. A projected or theoretical volume can be calculated based on Petition 870260011094, dated 05 / 02 / 2026, page 12 / 45 3 / 28 in parameters of the well being drilled (e.g., diameter). Furthermore, the projected volume can be calculated as a function of time. At the well surface, bottomhole particles, such as fragments and cuttings, can be captured in a corrugated vibrating screen, allowing drilling fluid to be removed. The volume of fragments and cuttings passing through the corrugated vibrating screen during a selected time period can then be measured. These volume measurements can be recorded. Deviations from the projected or theoretical volume can be recorded, and the parties can be notified on and / or off the well site.

[0016] In some modalities, the results of this analysis can be used to modify various hydrocarbon recovery operations. For example, if particles are received at the surface as a result of drilling operations, the drilling operations can be modified. For example, drilling can be stopped, or a well direction can be changed. Other examples of modified drilling operations may include replacing parts of the drill string (e.g., the drill bit), a change in drilling mud weight or flow rate, performing a well cleaning, etc. For hydraulic fracturing operations, the results of this analysis can be used to project the potential hydrocarbon recovery of this current well. Furthermore, the results of this analysis can be used in drilling subsequent wells in a similar geographic region.For example, if a level of proppants that are not retained in the formation is too high (returning to the surface instead), the direction or depth of subsequent well drilling may be altered. Alternatively, or additionally, the location or number of fractures in subsequent holes may be changed.

[0017] Returning now to FIG. 1, FIG. 1 is a block diagram of an example system 100 for processing and analyzing bottomhole particles. The system 100 includes a combination of an imaging device 102 and one or more processors 104. The imaging device 102 and the processors 104 are located above the surface 106 of a geological formation. In one or more embodiments, the imaging device 102 and the processors 104 are part of a data acquisition system 108. Petition 870260011094, dated 05 / 02 / 2026, p. 13 / 45 4 / 28

[0018] System 100 also includes logic 110 which includes a programmable data acquisition subsystem. Logic 110 can be used to acquire images from the imaging device 102 and other data, such as bottomhole information, including drill bit depth during a drilling operation.

[0019] System 100 also includes a memory 112 used to store the acquired images as well as other data (for example, in a database 114). The memory 112 is communicatively coupled to the processor(s) 104.

[0020] In one or more embodiments, the imaging device 102 includes one or more cameras to be used in combination with one or more illumination sources 116 to illuminate bottomhole particles 118 deposited on an agitator 120 that includes a corrugated vibrating screen 122. The cameras are focused on the corrugated vibrating screen 122 to capture time-lapse images of bottomhole particles 118 as they move through one or more vibrators 120.

[0021] The imaging device 102 is connected to the data acquisition system 108 which includes the logic 110 and then to a computer (comprising one or more processors 104). Alternatively, the imaging device 102 may connect directly to a computer. Images from the imaging device 102 may be analyzed in real time, i.e., as they are generated by the imaging device 102, to provide the volume of bottomhole particles 118 moving through a specified portion 124 of the wavy shale agitator 122. In other embodiments, the images may be analyzed at a later time.

[0022] As part of the processing and analysis of the bottomhole particles 118, the distance between the imaging device 102 and the corrugated vibrating screen 122 is measured. The distance measurement can be the distance between the imaging device 102 and a fixed point on the corrugated vibrating screen 122 or the average distance between the imaging device 102 and the corrugated vibrating screen 122. The angle between the imaging device 102 and a horizontal plane extending through the corrugated vibrating screen 122 is also measured. Each image generated by the imaging device 102, together with the distance measurement, the angle measurement, and the predetermined profile of the undulations on the corrugated vibrating screen 122, is used to Petition 870260011094, dated 05 / 02 / 2026, page 14 / 45 5 / 28 Determine the actual cross-sectional area of ​​the corrugated vibrating screen 122 that is occupied by the bottom-hole particles 118 in the specified portion 124 of the corrugated vibrating screen 122 for the respective image.

[0023] The volume of bottomhole particles 118 traversing portion 124 of the corrugated vibrating screen in an image can then be determined based on the occupied cross-sectional area of ​​portion 124 of the corrugated vibrating screen 122 in the image, a rate at which images are generated, and the velocity of the bottomhole particles 118 traversing the corrugated vibrating screen 122. As a non-limiting example, if 30 images are generated every second, the volume of bottomhole particles associated with a single image can be calculated by multiplying the velocity, in units of distance per second, by the occupied cross-sectional area in the image and dividing the total by 30, the number of images per second. The cumulative volume of bottomhole particles traversing the corrugated vibrating screen over a selected time period can then be calculated by adding the volumes associated with each image during the selected time period.

[0024] The velocity of the bottomhole particles 118 can be determined using a tracking approach of a particle over a certain distance for a certain period of time. For example, the imaging device 102 can be used to track one or more of the bottomhole particles 118 to determine the velocity. Other methods, such as the use of a radar gun, can also be used to determine the velocity of the particles. In addition, inaccuracies due to vibration in the agitator 120 must be filtered out when determining the velocity. This can be done by mounting a reference target on a static portion of the agitator 120 and capturing the pixel motion using the imaging device 102. Other methods, such as the use of accelerometers, can be used to determine the vibrational motion of the corrugated vibrating screen 122.

[0025] Returning now to FIG. 2, FIG. 2 is a schematic diagram of a well system 200, according to one or more embodiments. As shown in FIG. 2, the well system 200 may include a drilling rig 202 located on the surface 204 of a well 206. Oil and gas well drilling is commonly carried out using Petition 870260011094, dated 05 / 02 / 2026, page 15 / 45 6 / 28 Multiple drill pipes connected together to form a drill string 208 which is lowered via a rotary table 210 into a well 212. In the exemplary embodiment, a drilling platform 214 is fitted with a tower 216 supporting a winch.

[0026] The drilling rig 202 provides support for the drill string 208. The drill string 208 operates to penetrate the rotary table 210 to drill the well 212 through subsurface formations 218. The drill string 208 includes a drill pipe 220 and a bottom assembly 222 located in the lower portion of the drill string 208. In one or more embodiments, the drill string may also include a kelly 224.

[0027] The downhole composition 222 may include drill collars 224, a downhole tool 226, and a drill bit 228. The drill bit 228 is rotated to create a well 212 by penetrating the surface 204 and subsurface formations 218. The downhole tool 226 may comprise any of a number of different tool types including MWD tools, LWD tools, and others.

[0028] During drilling operations, the drill string 208 can be rotated by the rotary table 210. Additionally, or alternatively, the bottom assembly 222 can also be rotated by a motor (e.g., a mud motor) that is located at the bottom of the well. Drill collars 224 can be used to add weight to the drill bit 228. Drill collars 224 can also operate to stiffen the bottom composition 222, allowing the bottom composition 222 to transfer the added weight to the drill bit 228 and in turn assist the drill bit 228 in penetrating the surface 204 and subsurface formations 218.

[0029] During drilling operations, a mud pump 230 pumps drilling fluid (also known as drilling mud) from a mud tank 232 through a hose 234 to the drill pipe 220 and down to the drill bit 228.Drilling fluid flows out of drill bit 228 and is returned to the surface 204 through an annular area 236 between drill pipe 220 and well sides 212. The drilling fluid can then return. Petition 870260011094, dated 05 / 02 / 2026, page 16 / 45 7 / 28 to the mud tank 232 where such fluid is filtered. In some embodiments, the drilling fluid may be used to cool the drill bit 228, as well as to provide lubrication for the drill bit 228 during drilling operations. In addition, the drilling fluid may be used to remove bottomhole particles, such as fragments and cuttings from the subsurface formation 218 created by the operation of the drill bit 228.

[0030] With reference now to FIGS. 1 and 2, the well system 200 includes a corrugated vibrating screen 122 for receiving drilling mud, and one or more image processing systems 100 as described previously. The corrugated vibrating screen 122 may also be part of the shaker deck 126. The image processing system 100 may be configured so that the imaging devices 102 have a field of view that includes the corrugated vibrating screen 122, operating as described previously.

[0031] The processed data (e.g., downhole particle volume) can be displayed to show the changes that have occurred and the operating conditions that are likely to be associated with these types of changes. Thus, the 200 system may include a display 128 to show the changes and operating conditions. These conditions can be used to implement real-time control of the drilling operation (e.g., if falling shale is indicated by an increase in downhole particle volume, the weight on the drill bit can be reduced, or drilling can be stopped completely). The 200 well system may also include a transmitter 130 that is used to send the data (e.g., downhole particle volume) to a workstation 132, to generate an alarm, perform further processing / analysis, or for real-time operational control.

[0032] It should also be understood that apparatus and systems of various modalities can be used in applications other than pumping and drilling operations, and thus, various modalities should not be so limited. The illustrations of system 100 and system 200 are intended to provide a general understanding of the structure of various modalities, and are not intended to serve as a complete description of all the elements and features of apparatus and systems that may make use of the structures. Petition 870260011094, dated 05 / 02 / 2026, p. 17 / 45 8 / 28 described in this document.

[0033] Examples of operations for analyzing and using the volume of fragments and cuttings are now described. FIGS. 3-5 are flowcharts of operations for evaluating and possibly altering downhole drilling operations based on the analysis of downhole fragment and cuttings volume, according to some modalities. The operations of flowcharts 300-500 of FIGS. 3-5 continue between each other through transition points AD. The operations of flowcharts 300-500 can be performed by software, firmware, hardware, or a combination thereof. The operations of flowchart 300 begin at block 302.

[0034] In block 302, a projected volume of fragments and cuttings projected to return to the surface during the drilling of a well for a unit of depth and time is determined. For example, with reference to FIGS. 1 and 2, processors 104 calculate the projected volume of fragments and cuttings based on the determined unit of depth and time of the drilling operations. The projected volume can also account for the size (e.g., diameter) of the drill bit 228 and / or reamer. The projected volume of fragments and cuttings for the determined depth and time interval can be calculated as a function of time.

[0035] To determine the depth at which bottomhole particles from which fragments and cuttings originate in the bottomhole, drill depth and delay can be monitored. Drill depth can be derived from the amount of pipe in the well. For example, drill depth can be based on the number of pipe joints in the borehole and knowledge of the length of all joints, or by monitoring extraction work and determining how much the block has moved when adding pipe to the wellbore. Delay can be determined based on a drill bit location, the pumping rate in both strokes and volume per unit time, and the volume of the annular space.

[0036] When a formation foot is drilled, and knowing the size of the drill bit and reamer, the volume of the formation can be calculated based on a unit of depth of the formation that was drilled, the size of the drill bit, and the size of the reamer. The return of this volume of formation to the surface can be Petition 870260011094, dated 05 / 02 / 2026, p. 18 / 45 9 / 28 determined based on the delay.

[0037] The camera system and software can measure the volume of rock returning to the surface. The computer system can maintain a discrete or cumulative volume of fragments and cuttings per discrete depth interval and / or as a discrete cumulative volume of fragments and cuttings per discrete time. Data in the form of images and / or volumes can be stored at the well site and / or transmitted off-site. If drilling fluid is not removed from the fragments and cuttings, an incorrect volume would be calculated. If the vibrating screens become flooded with fragments and cuttings or fluid, an incorrect volume would also be calculated. In some embodiments, drilling fluid retained in the fragments and cuttings will not be calculated, and no method will be used to remove wetting from the fragments and cuttings. Drilling fluid left in the fragments and cuttings can be considered a measurement error.

[0038] In block 304, a well is drilled with a drill string that includes sections of drill pipe and a drill bit. For example, with reference to FIGS. 1 and 2, drill bit 228 included in the lower portion of drill string 208 drills well 212. Drill string 208 includes one or more sections of drill pipe 220.

[0039] In block 306, fragments and cuttings and actual fluid are captured in a corrugated vibrating screen for the unit depth and drilling time. For example, with reference to FIGS. 1 and 2, fragments and cuttings from subsurface formation 218 are created during the operation of drill bit 228. Drilling fluid is used to remove the fragments and cuttings. The drilling fluid and the fragments and cuttings are returned to the surface 204 during the drilling of well 212 for the determined unit depth and time. The corrugated vibrating screen 122 receives the drilling fluid, which includes the fragments and cuttings. The drilling fluid may be filtered before or after being received by the vibrating screen 122 to remove the drilling fluid from the fragments and cuttings before analysis.

[0040] In block 308, a drill bit depth is determined based on the number of drill pipe joints. The drill bit depth can Petition 870260011094, dated 05 / 02 / 2026, p. 19 / 45 10 / 28 can be calculated if the number of drill pipe joints and the lengths of each respective drill pipe joint are known. For example, with reference to FIGS. 1 and 2, the depth of drill bit 228 is determined based on the number of drill pipe joints 220 and the known lengths of each of the drill pipe joints 220.

[0041] In block 310, a pumping rate of drilling fluid through the drill pipe is determined. The pumping rate can be given in pump strokes or volume of fluid pumped per minute. For example, with reference to FIGS. 1 and 2, the pumping rate, in addition to other drilling parameters, can be stored in memory 112. Processors 104 can retrieve the pumping rate from memory 112.

[0042] In block 312, a volume of the annular space is determined. For example, with reference to FIGS. 1 and 2, processor 104 can calculate the volume of the annular area 236. Processor 104 can determine the volume based on the well diameter 212, drill pipe diameter 220, and drill bit depth 228.

[0043] In block 314, a delay is determined based on the drill bit depth, pumping rate, and annular space volume. The annular volume at the particular measured depth corresponding to the drill bit is determined based on the known drill bit depth and annular space volume. The delay can then be calculated using the resulting annular volume and pump rate. For example, referring to FIGS. 1 and 2, processors 104 can calculate the delay based on the drill bit depth 228, the annular area volume 236, and the mud pump pumping rate 230. The operations of flowchart 300 continue from transition point A to transition point A of flowchart 400 shown in FIG. 4. From transition point A of flowchart 400, the operations continue in block 402.

[0044] In block 402, a depth from which actual fragments and gravel are associated is determined based on the drill bit depth and delay. The drill bit depth can be tracked at each depth and time unit. For example, with reference to FIGS. 1 and 2, processors 104 can retrieve from memory 112 the drill bit depth 228. Petition 870260011094, dated 05 / 02 / 2026, p. 20 / 45 11 / 28 recorded at the previous time that corresponds to the delay time. For example, if the delay is determined to be 25 minutes and the current depth of drill bit 228 is 5,000 meters, processor 104 can retrieve the depth of drill bit 228 with a timestamp corresponding to 25 minutes earlier.

[0045] In block 404, a time-series of bottomhole particles, such as fragments and gravel, are captured as fragments and gravel move through a corrugated vibrating screen. For example, with reference to FIGS. 1 and 2, imaging device 102 captures images of fragments and gravel as bottomhole particles move through the corrugated vibrating screen 122.

[0046] In block 406, the velocity of the actual fragments and gravel in the agitator is measured. The velocity of the fragments and gravel can be determined using the traditional approach of tracking a particle over a certain distance for a certain period of time. For example, with reference to FIGS. 1 and 2, the imaging device 102 in combination with a velocity capture algorithm can be used to track the velocity of the particle / fragments and gravel. Other methods using radar can also be used to determine the velocity of the particles. To filter out noise in the form of agitator vibration 120, a reference target can be mounted on a static portion of the agitator. Pixel motion can be captured using the imaging device 102. An algorithm can be selected to capture pixel motion in the agitator 120.Other methods using accelerometers can also be used to establish the baseline of vibrations in the vibrating screen.

[0047] In block 408, a volume of the actual fragments and gravel is measured for the unit depth and time based on images generated by an imaging device, the image generation rate, the corrugated vibrating screen undulation profile, and the angle and distance between the corrugated vibrating screen and the imaging device. The volume is calculated as described above with reference to FIGS. 1 and 2.

[0048] In block 410, it is determined whether the difference between the measured volume and the projected volume exceeds an error threshold. The error threshold indicates a deviation from the projected volume. Petition 870260011094, dated 05 / 02 / 2026, page 21 / 45 12 / 28 of the measured volume that can be attributed to error. The error threshold may account for drilling fluid remaining in the fragments and cuttings after the fragments and cuttings are returned to the surface and deposited on the vibrating screen. For example, with reference to FIGS. 1 and 2, fragments and cuttings 118 containing remnants of drilling fluid may be deposited on the vibrating screen 122. The drilling fluid remaining at the time of analysis of the fragments and cuttings 118 contributes to the measurement error and is therefore taken into account in the error threshold. Processors 104 can determine whether the error threshold is exceeded after calculating the difference between the measured volume and the projected volume.

[0049] In block 412, if the difference between the measured volume and the projected volume does not exceed the error threshold, the current drilling parameters are maintained. A difference between the measured volume and the projected volume of fragments and cuttings, discrete or cumulative, that does not exceed the error threshold indicates that the current drilling parameters are maintaining formation stability and safe conditions, for example, with reference to FIGS. 1 and 2, drilling well 212 with drill bit 228 and / or reamer will be maintained with the current set of parameters, such as the weight of the drilling fluid. The operations of flowchart 400 continue from transition point D to transition point D of flowchart 500 shown in FIG. 5. From transition point D of flowchart 500, the operations are completed.

[0050] In block 414, if the difference between the measured volume and the projected volume exceeds the error threshold, trends in other indicators of inadequate hole cleaning are captured. Other indicators of inadequate hole cleaning include changes in torque, drag, equivalent circulating density, and vertical pipe pressure. For example, with reference to FIGS. 1 and 2, processors 104 can obtain improper hole cleaning indicator data over a unit of depth and / or time for storage in memory 112. For example, processors 104 can obtain current drilling parameters, mud weight, drill bit depth 228, etc. The data obtained for the time or depth interval can be entered into calculations to determine the indicator values ​​(e.g., calculating vertical pipe pressure). The combination of such indicators can be combined to create Petition 870260011094, dated 05 / 02 / 2026, page 22 / 45 13 / 28 is a positive indicator of inadequate hole cleaning.

[0051] In block 416, it is determined whether the measured volume is less than the projected volume. For example, with reference to FIGS. 1 and 2, processors 104 can make the determination based on a comparison of the measured volume and the projected volume. If the measured volume is greater than the projected volume, the operations of flowchart 400 continue from transition point B to transition point B of flowchart 500 shown in FIG. 5. From transition point B of flowchart 500, the operations continue in block 504.

[0052] In block 418, if the measured volume is less than the projected volume, a notification or alarm is generated. For example, with reference to FIGS. 1 and 2, processors 104 can generate the notification or alarm that is sent to display 128. The notification or alarm could indicate that an accumulation of debris and cuttings is occurring at the bottom of the well. This information, when coupled with information such as changes in torque, drag, equivalent circulation density, vertical pipe pressure, etc., can lead to a positive indicator for inadequate well cleaning. An accumulation of debris and cuttings indicates that hole cleaning efforts should increase. Insufficient hole cleaning could lead to packing, increased bottomhole pressure, and / or possible formation fracturing. The notification or alarm could also indicate that the drill bit and / or reamer has reduced in diameter. Reducing the diameter of the drill bit and / or reamer can lead to drill stroke.The operations in flowchart 400 continue from transition point C to transition point C of flowchart 500 shown in FIG. 5. From transition point C of flowchart 500, the operations continue in block 502.

[0053] In block 502, the drilling is modified by increasing hole cleaning and / or replacing the reamer and / or drill bit. Hole cleaning may be increased due to receiving a notification that a buildup of debris and cuttings is occurring at the bottom of the well. Additionally, the drill bit and / or reamer may be replaced as a result of receiving a notification that the drill bit and / or reamer has reduced in diameter. For example, with reference to FIGS. 1 and 2, drill bit 228 is replaced to address the reduction. Petition 870260011094, dated 05 / 02 / 2026, page 23 / 45 14 / 28 in the resulting diameter from drilling well 212. The cleanliness of well 212 can also be increased if fragments and cuttings from the subsurface formation 218 accumulate in the well. The cleanliness of well 212 can be increased by adjusting the properties of the drilling fluid, increasing the flow rate, altering the rate of penetration, etc.

[0054] In block 504, if the measured volume is greater than the projected volume, a notification or alarm is sent. For example, with reference to FIGS. 1 and 2, processors 104 can generate the notification or alarm that is sent to display 128. The notification or alarm may indicate that the borehole is collapsing and that mitigation efforts should be taken to stabilize the well. The notification or alarm could also indicate that the borehole pressure has exceeded the weight of the drilling fluid.

[0055] In block 506, drilling is modified by increasing the weight of the drilling fluid. The weight of the drilling fluid must be increased as a result of identifying that the pore pressure of the formation is greater than the weight of the drilling fluid. For example, with reference to FIGS. 1 and 2, the density of the drilling fluid pumped from mud well 232 at the bottom of the well can be increased (e.g., by adding barite).

[0056] Returning now to FIG. 6, FIG. 6 represents a schematic diagram of a fracturing operation, according to some modalities. In FIG. 6, a 600 formation composed of porous and permeable rocks that include hydrocarbons, for example, in a reservoir, is located in an onshore or offshore environment. The 600 formation may be located in the range of a few hundred feet to thousands of feet below a ground surface. A 602 well is drilled to penetrate the 600 formation and to allow the production of hydrocarbons from the 600 formation.

[0057] Well 602 of FIG. 6 is formed at any angle suitable for reaching the hydrocarbon portion of formation 600. For example, well 602 may follow a near-vertical, partially vertical, angled, or even partially horizontal path through formation 600. Well 602 may be lined with a protective casing 604 that extends through formation 600. The protective casing 604 may include a casing, sealing casing, tubing, or piping and is made of any material, including steel, alloys, or polymers, among others. The protective casing 604 of FIG. 6 is Petition 870260011094, dated 05 / 02 / 2026, p. 24 / 45 15 / 28 extends vertically downward and continues horizontally to extend further through the 600 formation. In other examples, well 602 may be fully or partially cased or completely open, i.e., without protective casing.

[0058] Hydrocarbons are located in the pore space of formation 600 and can be produced when the pore spaces are connected and the permeability is such that hydrocarbons flow out of formation 600 and into well 602. In some cases, formation 600 may have low permeability and hydrocarbons do not flow readily, or production is impaired due to formation damage. To stimulate and extract hydrocarbons, a reservoir stimulation treatment program is initiated to break, fracture, or induce dilation of existing natural fractures in the rock of formation 600. The reservoir stimulation treatment program may include drilling protective casing 604, or installing specific stimulation protective casing equipment, to create entry points from formation 606, for example, boreholes, sliding stimulation sleeves, etc.The entry points of formation 606 provide a pathway for hydrocarbons to flow from formation 600 and into well 602.

[0059] Mechanical isolation and compartmentalization tools can be used so that the entry points of formation 606 segment formation 600 into any number of production zones where fracturing programs can be carried out. As shown in FIG. 6, formation 600 includes a first production zone 608, a second production zone 610, and a third production zone 612. Each zone 608, 610, 612 can be stimulated individually or simultaneously with other zones, depending on the mechanical isolation and compartmentalization system employed. It should be understood that the number of zones in FIG. 6 is an exemplary embodiment and that a wide variety of other examples, including increasing or decreasing the number of zones in formation 600, is possible.

[0060] In one or more embodiments, the reservoir stimulation treatment program includes injecting proppant (such as a pressurized treatment fluid 614) into well 602 to stimulate one or more of the production zones 608, 610, 612. The treatment fluid 614 may be stored in the injection equipment 618, such as a tank. Petition 870260011094, dated 05 / 02 / 2026, page 25 / 45 16 / 28 of storage or piping. The treatment fluid 614 is pumped from the injection equipment 618 and into the well 602 with a pressure greater than the fracture gradient or formation crack opening pressure 600.

[0061] Other suitable programs may be used to flow the treatment fluid 614 into well 602, for example, through a conduit such as piping or spiral tubing located within well 602. As the treatment fluid 614 flows through the formation entry points 606, the increased pressure created by the flowing treatment fluid 614 cracks the formation 600 to create or further enlarge a fracture network 616. The fracture network 616 of FIG. 6 may include high-flow-capacity fractures 620 and low-flow-capacity fractures 622. The high-flow-capacity fractures 620 are located in areas of lower relative total stress of the stimulation range where fluids from a conventional hydraulic fracturing treatment can be injected with little or no mechanical manipulation.Low flow capacity fractures 622 are located in areas of higher relative total stress, where little or no fluid from a conventional hydraulic fracturing treatment would be injected without mechanical manipulation.

[0062] The treatment fluid 614 includes a carrier fluid, i.e., a fracturing fluid 624, and may also include a stimulation material 626. The fracturing fluid 624 may include energized or non-energized water, brine, gels, cross-linked fluids, mineral or organic acids, non-aqueous base fluids, or any other type of fluid capable of fracturing the formation 600 and carrying the stimulation material 626 into the fractures 620, 622. The stimulation material 626 is suspended in the fracturing fluid 624 and sediments in high-flow-capacity fractures 620 or low-flow-capacity fractures 622 to keep the fractures open to allow hydrocarbon flow from the reservoir and into the well 602. The stimulation material 626 may include proppant, such as small spheres composed of sand, ceramic material, plastics and resins, or other intensification materials. conductivity.

[0063] Treatment fluid 614 may also include additives to optimize the fracturing program. The types of additives used may vary depending on the properties of the formation 600 and the composition of treatment fluid 614, among other factors. Petition 870260011094, dated 05 / 02 / 2026, page 26 / 45 17 / 28 factors. In particular, additives may include stabilizers, surfactants, foaming agents, gel breakers, fluid loss additives, friction reducers, scale inhibitors, biocides, and pH control additives and the like. In embodiments, an additive (i.e., a flow restriction material (FCM) 628) can be stored in the FCM injection equipment 630 to be injected into well 602. Consequently, the FCM 628 can flow simultaneously with the treatment fluid 614 into well 602. The FCM 628 can be a particulate, rheological, or chemical additive that partially restricts or redistributes the flow of the treatment fluid 614 to an area of ​​higher relative stress, for example, the low flow capacity fractures 622, without completely diverting the fluid 614 from the area of ​​lower total stress, for example, the area where the high flow capacity fractures 620 are located.

[0064] Examples of operations for analyzing and using bottomhole particles returned to the surface from fracturing operations are now described. FIG. 7 is a flowchart of operations for evaluating and using the results of a fracturing operation, according to some modalities. The operations in flowchart 700 can be performed by software, firmware, hardware, or a combination thereof. The operations in flowchart 700 begin in block 702.

[0065] In block 702, a well fracturing operation is performed by pumping a known volume of proppant (e.g., sand) into the well. For example, with reference to FIG. 22, injection equipment 618 pumps fracturing fluid 624 into well 602. Fluid 624 contains a known volume of proppant. The proppant may remain in fractures 606 in well 602 to keep fractures 606 open.

[0066] In block 704, the velocity of the proppants through the corrugated vibrating screen is determined. The velocity of the proppants is determined using a process similar to that used during the determination of the velocity of the bottomhole particles, as described with reference to FIGS. 3-5.

[0067] In block 706, it is determined whether the volume of proppant returned to the surface is less than the volume of proppant pumped into the well. The volume of proppant returned to the surface is determined using a process similar to that used during downhole particle volume analysis, as described with reference to FIGS. 3-5. Petition 870260011094, dated 05 / 02 / 2026, page 27 / 45 18 / 28 An error threshold for the volume of proppant returned to the surface can be applied. If the volume of proppant returned to the surface exceeds the error threshold, the fracturing operations can be defined as not being performed adequately. For example, an error threshold of 10% of the initial volume can be established. If the volume of proppant returned to the surface exceeds 10% of the volume initially pumped in well 602, it is determined that an insufficient amount of proppant remained in fractures 606.

[0068] In block 708, if the volume of proppant returned to the surface is not less than the volume of proppant pumped into the well, a notification or alarm indicating that the fracturing operation was successful is sent. For example, with reference to FIGS. 1 and 6, processors 104 can generate the notification or alarm that is sent to display 128. A fracturing operation can be considered successful if essentially all the proppant remains in the fractures 606 (for example, the percentage of proppant pumped into the well 602 that is returned to the surface is within the error threshold).

[0069] In block 710, if the volume of proppant returned to the surface is less than the volume of proppant pumped into the well, a notification or alarm indicating that the result of the fracturing operations was below standard is sent. For example, with reference to FIGS. 1 and 6, processors 104 can generate the notification or alarm that is sent to display 128.

[0070] In block 712, hydrocarbon recovery from the current well is projected based on the results of the fracturing operation. The volume of proppant remaining in well 602 as a result of fracturing can be used to determine the projected hydrocarbon recovery. Subsequent operations to determine hydrocarbon recovery from fracturing operations can leverage knowledge of the proppant remaining in well 602 and / or the shapes and sizes of dislodged and / or remaining particles in formation 600.

[0071] In block 714, subsequent drilling and / or fracturing operations in the same or similar subsurface formations are modified based on the outcome of the fracturing operation. For example, if a low volume of proppant is obtained. Petition 870260011094, dated 05 / 02 / 2026, page 28 / 45 19 / 28 remaining in fractures 606 (i.e., the volume of proppant returned to the surface exceeds the error threshold), subsurface formations with similar properties to the current formation can be avoided for subsequent fracturing operations. The completion of the fracturing stages can also be altered.

[0072] Returning now to FIG. 8, FIG. 8 represents a block diagram of an example 800 computer, according to some embodiments. The 800 computer includes an 802 processor (possibly including multiple processors, multiple cores, multiple nodes and / or multithreading implementation, etc.). The computer includes 804 memory. The 804 memory may be system memory (e.g., one or more of cache, SRAM, DRAM, zero-capacitor RAM, dual-transistor RAM, eDRAM, EDO RAM, DDR RAM, EEPROM, NRAM, RRAM, SONOS, PRAM, etc.) or any one or more of the possible embodiments already described above in machine-readable media. The computer system also includes an 806 bus (e.g., PCI, ISA, PCI-Express, bus, NuBus, etc.) and an 808 network interface (e.g., a Fibre Channel interface, an Ethernet interface, an Internet Small Computer System interface, a SONET interface, a wireless interface, etc.).Although represented as a computer, some models may be any type of device or apparatus used to perform the operations described in this document.

[0073] The computer also includes an analyzer 810 and a controller 812. The analyzer 810 can perform processing and analysis of downhole particles (as described above). The controller 812 can control the different operations that may occur in response to the analysis results. For example, the controller 812 can communicate instructions to the appropriate equipment, devices, etc. to alter drilling operations. Any of the functionalities described above can be partially (or fully) implemented in hardware and / or in the processor 802. For example, the functionality can be implemented with an application-specific integrated circuit, in the logic implemented in the processor 802, in a coprocessor on a peripheral device or card, etc. Furthermore, embodiments may include fewer components or additional components not illustrated in FIG.8 (e.g., video cards, sound cards, additional network interfaces, peripheral devices, etc.). O. Petition 870260011094, dated 05 / 02 / 2026, page 29 / 45 20 / 28 processor 802 and network interface 808 are coupled to bus 806. Although illustrated as being coupled to bus 806, memory 804 can be coupled to processor 802.

[0074] It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by program code. The program code can be provided to a processor of a general-purpose computer, special-purpose computer, or other programmable machine or device.

[0075] As will be appreciated, aspects of the disclosure may be incorporated as a system, method, or program code / instructions stored on one or more machine-readable media. Therefore, aspects may take the form of hardware, software (including firmware, resident software, microcode, etc.), or a combination of software and hardware aspects which may generally be referred to in this document as a circuit, module, or system. The functionality presented as individual modules / units in the example illustrations may be arranged differently according to any platform (operating system and / or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.

[0076] Any combination of one or more machine-readable media may be used. A machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device that employs any or a combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of machine-readable storage media would include the following: a portable computer floppy disk, a hard disk drive, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc (CD-ROM) read-only memory, an optical storage device, a magnetic storage device, or any Petition 870260011094, dated 05 / 02 / 2026, page 30 / 45 21 / 28 appropriate combination of the above. In the context of this document, a machine-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction-executing system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium.

[0077] Although aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, the techniques for processing and analyzing downhole particles, as described in this document, can be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

[0078] A machine-readable signal medium may include a propagated data signal with machine-readable program code embedded therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electromagnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium other than a machine-readable storage medium that can communicate, propagate, or carry a program for use by or in connection with an instruction-executing system, apparatus, or device.

[0079] Program code embedded in a machine-readable medium may be transmitted using any suitable medium, including, but not limited to, wireless cable, steel cable, fiber optic cable, RF, etc., or any suitable combination thereof.

[0080] The computer program code for performing operations for disclosure aspects may be written in any combination of one or more programming languages, including an object-oriented programming language such as Java, RTM, C++, or similar; a dynamic programming language such as Python; a scripting language such as Petition 870260011094, dated 05 / 02 / 2026, page 31 / 45 22 / 28 Perl programming or PowerShell scripting language; and conventional procedural programming languages, such as the C programming language or similar programming languages. The program code can run entirely on a standalone machine, can run in a distributed manner across multiple machines, and can run on one machine while providing results and / or accepting input on another machine.

[0081] The program code / instructions can also be stored on a machine-readable medium that can direct a machine to operate in a particular way, so that the instructions stored on the machine-readable medium produce a manufacturing article including instructions that implement the function / action specified in the block or blocks of the flowchart and / or block diagram.

[0082] The use of the apparatus, systems and methods disclosed in this document can provide the capability to monitor changes in downhole particles (e.g., fragments and cuttings), so that the impact of drilling fluid properties and activities in the field can be assessed immediately. This capability can be used to increase efficiency by redirecting pumping and drilling operations in real time.

[0083] Additional examples include:

[0084] Example 1 is a wellbore system for handling downhole particles. The wellbore system includes a mud pump, an agitator, a drill string, an imaging device, and a data acquisition system. The agitator includes a corrugated vibrating screen. The drill string is in fluidic communication with the mud pump and the agitator. The imaging device is operable to capture images over a period of time of the downhole particles as the downhole particles move through the corrugated vibrating screen. The data acquisition system is in electronic communication with the imaging device and includes a processor.The processor is programmed to determine a cross-sectional area of ​​a portion of the corrugated vibrating screen occupied by bottomhole particles in a first image of the images based on the first image, in a known corrugation profile of the corrugated vibrating screen, a distance. Petition 870260011094, dated 05 / 02 / 2026, pages 32 / 45 23 / 28 known between the imaging device and the corrugated vibrating screen and a known angle between the imaging device and the corrugated vibrating screen. The processor is further programmed to determine a volume of bottomhole particles in the portion of the corrugated vibrating screen in the first image based on the cross-sectional area occupied by bottomhole particles, a velocity of the bottomhole particles passing through the corrugated vibrating screen, and an image generation rate.

[0085] In Example 2, the embodiments of any preceding paragraph or combination thereof also include wherein the processor is further programmed to determine an actual cumulative volume of bottomhole particles passing through the corrugated vibrating screen during the time period by adding the volume of bottomhole particles in multiple images.

[0086] In Example 3, the embodiments of any preceding paragraph or combination thereof further include wherein the processor is also programmed to determine a projected volume of bottomhole particles during the time period. The processor is further programmed to determine whether a difference between the actual cumulative volume of bottomhole particles and the projected volume of bottomhole particles exceeds an error threshold.

[0087] In Example 4, the modalities of any preceding paragraph or combination thereof also include wherein the processor is also programmed to send a notification of the occurrence of a bottomhole condition based on the determination of the error threshold.

[0088] In Example 5, the modalities of any preceding paragraph or combination thereof also include wherein the processor is further programmed to modify the operation of the well system based on the determination of the error threshold.

[0089] In Example 6, the embodiments of any preceding paragraph or combination thereof further include wherein the bottomhole particles comprise proppant particles.

[0090] Example 7 is a method for performing well operations. The method involves capturing images of bottomhole particles over a period of time by Petition 870260011094, dated 05 / 02 / 2026, pp. 33 / 45 24 / 28 using an imaging device as bottomhole particles move through a corrugated vibrating screen. The method also includes determining, using a processor, a cross-sectional area of ​​a portion of the corrugated vibrating screen occupied by bottomhole particles in a first image based on the first image, a known corrugation profile of the corrugated vibrating screen, a known distance between the imaging device and the corrugated vibrating screen, and a known angle between the imaging device and the corrugated vibrating screen. The method further includes determining, using the processor, a volume of bottomhole particles in the portion of the corrugated vibrating screen based on the cross-sectional area occupied by bottomhole particles, a velocity of the bottomhole particles, and an image generation rate.

[0091] In Example 8, the modalities of any preceding paragraph or combination thereof further include determining an actual cumulative volume of bottomhole particles passing through the corrugated vibrating screen during the time period by adding the volume of bottomhole particles in multiple images.

[0092] In Example 9, the modalities of any preceding paragraph or combination thereof further include determining a projected volume of downhole particles during the time period. The method further includes determining whether a difference between the actual cumulative volume of downhole particles and the projected volume of downhole particles exceeds an error threshold.

[0093] In Example 10, the modalities of any preceding paragraph or combination thereof also include sending a notification of the occurrence of a bottomhole condition based on the determination of the error threshold.

[0094] In Example 11, the modalities of any preceding paragraph or combination thereof also include modifying well operations based on the determination of the error threshold.

[0095] In Example 12, the modalities of any preceding paragraph or combination thereof also include where well operations comprise drilling a well.

[0096] In Example 13, the modalities of any preceding paragraph or combination Petition 870260011094, dated 05 / 02 / 2026, pages 34 / 45 25 / 28 of the same also include wherein the well operations comprise fracturing a well.

[0097] In Example 14, the embodiments of any preceding paragraph or combination thereof also include wherein the downhole particles comprise proppant particles.

[0098] Example 15 is a system for determining a volume of bottomhole particles in a corrugated vibrating screen of a well system. The system includes an operable imaging device to capture images over a period of time of the bottomhole particles as the bottomhole particles move through the corrugated vibrating screen. The system also includes a data acquisition system in electronic communication with the imaging device and including a processor. The processor is programmed to determine a cross-sectional area of ​​a portion of the corrugated vibrating screen occupied by the bottomhole particles in an image of the images based on the image, on a known corrugation profile of the corrugated vibrating screen, a known distance between the imaging device and the corrugated vibrating screen, and a known angle between the imaging device and the corrugated vibrating screen.The processor is further programmed to determine a volume of bottomhole particles in the corrugated vibrating screen portion based on the cross-sectional area occupied by bottomhole particles, a velocity of the bottomhole particles, and an image generation rate.

[0099] In Example 16, the embodiments of any preceding paragraph or combination thereof also include wherein the processor is further programmed to determine an actual cumulative volume of bottomhole particles passing through the corrugated vibrating screen during the time period by adding the volume of bottomhole particles across multiple images.

[00100] In Example 17, the embodiments of any preceding paragraph or combination thereof further include wherein the processor is also programmed to determine a projected volume of bottomhole particles during the time period. The processor is further programmed to determine whether a difference between the actual cumulative volume of bottomhole particles and the projected volume of bottomhole particles exists. Petition 870260011094, dated 05 / 02 / 2026, pages 35 / 45 A 26 / 28 wellbore exceeds an error threshold.

[00101] In Example 18, the modalities of any preceding paragraph or combination thereof also include wherein the processor is further programmed to send a notification of the occurrence of a bottomhole condition based on the determination of the error threshold.

[00102] In Example 19, the embodiments of any preceding paragraph or combination thereof also include wherein the processor is further programmed to modify the operation of the well system based on the determination of the error threshold.

[00103] In Example 20, the embodiments of any preceding paragraph or combination thereof also include wherein the bottomhole particles are proppant particles.

[00104] As used in this document, the term approximately includes all values ​​within 5% of the target value; for example, approximately 100 includes all values ​​from 95 to 105, including 95 and 105.

[00105] For the above embodiments and examples, a non-transient machine-readable storage device may comprise instructions stored therein, which, when executed by a machine, cause the machine to perform operations, the operations comprising one or more features similar or identical to the features of methods and techniques described above. The physical structures of such instructions may be operated by one or more processors. A system for implementing the described algorithm may also include an electronic apparatus and a communication unit. The system may also include a bus, wherein the bus provides electrical conductivity between the system components. The bus may include an address bus, a data bus, and a control bus, each configured independently.The bus can also use common conductive lines to provide one or more address, data, or control lines, the use of which can be regulated by one or more processors. The bus can be configured so that system components can be distributed. The bus can also be organized as part of a communication network, allowing communication with control locations situated remotely from the system. Petition 870260011094, dated 05 / 02 / 2026, pages 36 / 45 27 / 28

[00106] In various system embodiments, peripheral devices, such as monitors, additional storage memory, and / or other control devices, may operate in combination with one or more processors and / or memory modules. Peripheral devices may be arranged to operate in conjunction with display unit(s) with instructions stored in the memory module to implement the user interface for managing the display of anomalies. Such a user interface may operate in combination with the communications unit and the bus. Various system components may be integrated so that processing identical or similar to the processing schemes discussed with respect to various embodiments in this document may be performed.

[00107] As used in this document, the term electronic communication includes wired communication between electronic components and / or electronic devices and wireless communication between electronic components and / or electronic devices. Electronic communication also includes electronic components and / or electronic devices that are in electronic communication, wired or wireless, through intermediate electronic components and / or electronic devices.

[00108] In an effort to provide a concise description of these embodiments, all the features of an actual implementation may not be described in the descriptive report. It should be understood that in the development of any such implementation, as in any engineering project or undertaking, numerous implementation-specific decisions must be made to achieve the specific objectives of the developers, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Furthermore, it should be understood that such a development effort may be complex and time-consuming, but, despite this, it would be a routine design, fabrication, and manufacturing task for those skilled in the art having the benefit of this disclosure.

[00109] Certain terms are used throughout the description and claims to refer to particular features or components. As will be understood by one skilled in the art, different people may refer to the same feature or component by different names. This document does not intend to distinguish between components. Petition 870260011094, dated 05 / 02 / 2026, pp. 37 / 45 28 / 28 or features that differ in name but not in function.

[00110] Reference throughout this descriptive report to a modality, the modality, modalities, some modalities, certain modalities, or similar language means that a particular feature, structure, or characteristic described in relation to the modality may be included in at least one modality of this disclosure. Thus, such phrases or similar language throughout this descriptive report may, but do not necessarily, all refer to the same modality.

[00111] The embodiments disclosed should not be interpreted or otherwise used as limiting the scope of the disclosure, including claims. It will be fully recognized that the different teachings of the embodiments discussed can be employed separately or in any suitable combination to produce desired results. Furthermore, one skilled in the art will understand that the description has broad application and the discussion of any embodiment is intended only to be illustrative of that embodiment and is not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. Petition 870260011094, dated 05 / 02 / 2026, pp. 38 / 45

Claims

1 / 3 CLAIMS 1. A method for carrying out well operations, the method characterized by comprising: - capturing images of bottomhole particles over a period of time by means of an imaging device as the bottomhole particles move through a corrugated vibrating screen; - determining, by means of a processor, a cross-sectional area of ​​a portion of the corrugated vibrating screen that is occupied by bottomhole particles in a first image of the images based on the first image, on a known corrugation profile of the corrugated vibrating screen, a known distance between the imaging device and the corrugated vibrating screen and a known angle between the imaging device and the corrugated vibrating screen;e - to determine, using the processor, a volume of bottomhole particles in the portion of the corrugated vibrating screen based on the cross-sectional area occupied by bottomhole particles, a velocity of the bottomhole particles, and an image generation rate.

2. Method, according to claim 1, characterized in that it further comprises determining an actual cumulative volume of bottomhole particles passing through the corrugated vibrating screen during the time period by adding the volume of bottomhole particles in multiple images.

3. A method according to claim 2, characterized in that it further comprises: - determining a projected volume of bottomhole particles during the time period; and - determining whether a difference between the actual cumulative volume of bottomhole particles and the projected volume of bottomhole particles exceeds an error threshold.

4. Method, according to claim 3, characterized in that it further comprises sending a notification of the occurrence of a bottomhole condition based on the determination of the error threshold.

5. Method, according to claim 3, characterized in that it further comprises modifying well operations based on the determination of the error threshold. Petition 870260011094, dated 05 / 02 / 2026, pp. 39 / 45 2 / 3 6. Method according to claim 1, characterized in that the well operations comprise drilling a well.

7. Method according to claim 1, characterized in that the well operations comprise fracturing a well.

8. Method according to claim 1, characterized in that the well bottom particles comprise proppant particles.

9. System for determining a volume of bottomhole particles in a corrugated vibrating screen of a well system, the system characterized by comprising: - an operable imaging device for capturing images over a period of time of the bottomhole particles as the bottomhole particles move through the corrugated vibrating screen; and - a data acquisition system in electronic communication with the imaging device and comprising a processor programmed to: - determine a cross-sectional area of ​​a portion of the corrugated vibrating screen occupied by the bottomhole particles in an image based on the image, on a known corrugation profile of the corrugated vibrating screen, a known distance between the imaging device and the corrugated vibrating screen, and a known angle between the imaging device and the corrugated vibrating screen;e - determine a volume of bottomhole particles in the corrugated vibrating screen portion based on the cross-sectional area occupied by bottomhole particles, a velocity of the bottomhole particles, and an image generation rate.

10. System according to claim 9, characterized in that the processor is further programmed to determine an actual cumulative volume of bottomhole particles passing through the corrugated vibrating screen during the time period by adding the volume of bottomhole particles in multiple images.

11. System, according to claim 10, characterized in that the processor is further programmed to: - determine a projected volume of bottomhole particles during the time period; and - determine whether a difference between the actual cumulative volume of bottomhole particles and the projected volume of bottomhole particles exceeds an error threshold.

12. System according to claim 11, characterized in that the processor is also programmed to send a notification of the occurrence of a bottomhole condition based on the determination of the error threshold.

13. System according to claim 11, characterized in that the processor is further programmed to modify the operation of the well system based on the determination of the error threshold.

14. System according to claim 9, characterized in that the well bottom particles are proppant particles. Petition 870260011094, dated 05 / 02 / 2026, pp. 41 / 45

Images