WO2025101675A1 - System and methods to model plug unseating based on wellbore flow - Google Patents

Abstract

Systems and methods presented herein relate to techniques for modeling forces subjected to a plug (e.g., formed of a diversion material) and determining a plug unseating output that may provide a remedy to a plug unseating.

Description

IS23.1226-WO-PCT SYSTEM AND METHODS TO MODEL PLUG UNSEATING BASED ON WELLBORE FLOW CROSS-REFERENCE TO RELATED APPLICATION [0001] This application claims priority to and the benefit of U.S. Provisional Patent Application Serial No.63/596,768, entitled “Systems and Methods to Model Plug Unseating Based on Wellbore Flow,” filed November 7, 2023, which is hereby incorporated by reference in its entirety for all purposes. BACKGROUND [0002] The present disclosure generally relates to systems and methods for generating a plug unseating output. [0003] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind. [0004] It may be appreciated that stimulation diversion processes and systems have been in use for years. Typically, stimulation diversion processes and systems are comprised of downhole production logging tools (PLT), radioactive tracers with gamma ray detection tools and fiber optic strings measuring distributed temperature. These measurements in the PLT usually have single pressure, single flow meter, gamma ray and temperature. The data from IS23.1226-WO-PCT these downhole tools are real time when an electric cable and/or fiber optic fiber is connected inside the coiled tubing string, or in memory mode when the data is collected after the job. [0005] Stimulation diversion processes are remarkably complex. One process that occurs during stimulation diversion processes is plug formation. In general, a plug, such as a particulate plug/cake, may form on an entry point (e.g., perforation holes in cased hole wells and open fractures in openhole wells) into a wellbore seats on the desired entry point in the wellbore. Unseating of the plug may result in an unsuccessful stimulation diversion. However, it may be difficult to determine a likelihood of the plug unseating. SUMMARY [0006] A summary of certain embodiments described herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. [0007] Certain embodiments of the present disclosure include a method. The method includes utilizing a physics-based model to predict unseating of diversion material based on drag forces, pressure forces, buoyancy forces, cake cohesion, chemical degradation of particulates, or a combination thereof. [0008] Certain embodiments of the present disclosure include a system. The system includes one or more memory storing a physics-based model to predict unseating of diversion material based on drag forces, pressure forces, buoyancy forces, cake cohesion, chemical degradation of particulates, or a combination thereof. The system also includes a control IS23.1226-WO-PCT system comprising one or more processors. The control system is configured to measure one or more flow parameters in a wellbore using one or more downhole tools. The system is also configured to determine one or more forces subjected to a plug formed in a perforation within the wellbore based on the one or more flow parameters and the physics-based model. Further, the system is configured to generate a plug unseating output based on the one or more forces. Further still, the system is configured to adjust operation of one or more downhole components based on the plug unseating output. [0009] Certain embodiments of the present disclosure include a method. The method includes measuring one or more flow parameters in a wellbore using one or more downhole tools. The method also includes determining one or more forces subjected to a plug formed in a perforation within the wellbore based on the one or more flow parameters. The one or more forces includes one or more buoyancy forces, F_b, in an axial wellbore direction proximate to the plug and one or more perforation forces, Fp, along a perforation axis towards a perforation tip of the plug. Further, the method includes determining an unseating force, F_u, and a seating force, F_s, based on F_b and F_p. Further still, the method includes determining internal and surface friction forces, ^^^_^^_^^^, based on a radius of the perforation. Even further, the method includes generating a plug unseating output based on a comparison of F_u and F_s to F_f. Even further, the method includes adjusting an injection schedule of one or more flow control devices based on the plug unseating output. [0010] Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of IS23.1226-WO-PCT the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter. BRIEF DESCRIPTION OF THE DRAWINGS [0011] Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings, in which: [0012] FIGS.1 and 2 are schematic illustrations of an oilfield well that traverses a hydraulically-fractured hydrocarbon-bearing reservoir as well as a downhole well tool for milling out plugs that isolate a number of intervals offset from one another along the length of the well, in accordance with embodiments of the present disclosure; [0013] FIG.3 is a schematic illustration of a well system that obtains sensor data to dynamically update information related to operation and control of a downhole well tool, in accordance with embodiments of the present disclosure; [0014] FIG.4 illustrates a well control system that may include a surface processing system to control the well system described herein, in accordance with embodiments of the present disclosure; [0015] FIG.5A illustrates a first cross-sectional view of a plug on a wellbore, in accordance with embodiments of the present disclosure; [0016] FIG.5B illustrates a second cross-sectional view of a plug on a wellbore, in accordance with embodiments of the present disclosure; IS23.1226-WO-PCT [0017] FIG.6 illustrates a graph of draft coefficient versus Reynolds number for a hemisphere plug, in accordance with embodiments of the present disclosure; [0018] FIG.7 illustrates a graph of forces acting on a plug extending into a wellbore, in accordance with embodiments of the present disclosure; and [0019] FIG.8 illustrates a flow diagram for generating a plug unseating output, in accordance with embodiments of the present disclosure. DETAILED DESCRIPTION [0020] One or more specific embodiments of the present disclosure will be described below. These described embodiments are only examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. [0021] When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that IS23.1226-WO-PCT there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. [0022] As used herein, the terms “connect,” “connection,” “connected,” “in connection with,” and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element.” Further, the terms “couple,” “coupling,” “coupled,” “coupled together,” and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements.” As used herein, the terms “up” and “down,” “uphole” and “downhole”, “upper” and “lower,” “top” and “bottom,” and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements. Commonly, these terms relate to a reference point as the surface from which drilling operations are initiated as being the top (e.g., uphole or upper) point and the total depth along the drilling axis being the lowest (e.g., downhole or lower) point, whether the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface. [0023] As used herein, a fracture shall be understood as one or more cracks or surfaces of breakage within rock. Fractures can enhance permeability of rocks greatly by connecting pores together and, for that reason, fractures can be induced mechanically in some reservoirs in order to boost hydrocarbon flow. Certain fractures may also be referred to as natural fractures to distinguish them from fractures induced as part of a reservoir stimulation. Fractures can also be grouped into fracture clusters (or “perf clusters”) where the fractures of a given fracture cluster (perf cluster) connect to the wellbore through a single perforated zone. As used herein, the term IS23.1226-WO-PCT “fracturing” refers to the process and methods of breaking down a geological formation and creating a fracture (i.e., the rock formation around a well bore) by pumping fluid at relatively high pressures (e.g., pressure above the determined closure pressure of the formation) in order to increase production rates from a hydrocarbon reservoir. [0024] In addition, as used herein, the terms “real time”, ”real-time”, or “substantially real time” may be used interchangeably and are intended to described operations (e.g., computing operations) that are performed without any human-perceivable interruption between operations. For example, as used herein, data relating to the systems described herein may be collected, transmitted, and/or used in control computations in “substantially real time” such that data readings, data transfers, and/or data processing steps occur once every second, once every 0.1 second, once every 0.01 second, or even more frequent, during operations of the systems (e.g., while the systems are operating). In addition, as used herein, the terms “automatic” and “automated” are intended to describe operations that are performed are caused to be performed, for example, by a processing system (i.e., solely by the processing system, without human intervention). [0025] As mentioned above, a plug, such as a particulate plug or cake, may form on an entry point (e.g., perforation holes in cased hole wells and open fractures in openhole wells) into a wellbore seats on the desired entry point in the wellbore. The plug may unseat as a function of changing injection rate, buoyancy forces, drag forces, flux redistribution, diversion material degradation and other relevant parameters. This is because these changes result in multiple forces acting on the exposed area of the diverter plug material. Unseating of the plug may result in an unsuccessful stimulation diversion. Accordingly, it may be advantageous to IS23.1226-WO-PCT develop techniques for determining a likelihood of a plug unseating and adjusting operations when the likelihood exceeds a threshold. [0026] Accordingly, the present disclosure relates to techniques for generating a plug unseating output. In general, the techniques include determining forces that may be subject to a plug and generating a plug unseating output that may be used to adjust operations based on a likelihood of the plug unseating. The techniques may include measuring one or more flow parameters in the wellbore using one or more downhole tools. Further, the techniques may include determining one or more forces subjected to a plug based on the one or more flow parameters. Further still, the techniques may include generating a plug unseating output based on the one or more forces. In this way, the likelihood of a plug unseating may be accurately determined, thereby enabling operations within a wellbore to be adjusted accordingly. [0027] It should be noted that the present techniques may be used in applications where solid particulates may accumulate. For example, the present techniques may be used in applications that include solid particulates that may form permeable filter cakes inside perforations. One technique that may be utilized to achieve diversion with particulates is to control and predict particulates bridging in the perforations such that perforation plugging can start. Modeling this physical process is relatively challenging as it depends on, for example, wellbore dynamics at the time of particles aggregation including parameters such as injection rate, diverter system fluid formulation, concentration of diverter material, size of particulates, size of perforation and so on. Today, no reliable model can predict the volume utilized for particulates flowing through a perforation to bridge, with realistic fluid-particulates systems in realistic flow conditions. IS23.1226-WO-PCT [0028] With the foregoing in mind, FIGS.1 and 2 are schematic illustrations of an example well system 10 that has undergone perforation and fracturing applications. As illustrated, in certain embodiments, a platform and derrick 12 may be positioned over a wellbore 14 that traverses a hydrocarbon-bearing reservoir 16 by rotary drilling. While certain elements of the well system 10 are illustrated in FIGS.1 and 2, other elements of the well (e.g., blow-out preventers, wellhead “tree”, etc.) have been omitted for clarity of illustration. In certain embodiments, the well system 10 includes an interconnection of pipes, including vertical and horizontal casing 18, tubing 20 (e.g., coiled tubing), transition 22, and a production liner 24 that connect to a surface facility (as illustrated in FIG.3) at the surface 26 of the well system 10. In certain embodiments, the tubing 20 extends inside the casing 18 and terminates at a tubing head (not shown) at or near the surface 26. In addition, in certain embodiments, the casing 18 contacts the wellbore 14 and terminates at a casing head (not shown) at or near the surface 26. In certain embodiments, the production liner 24 and/or the horizontal casing 18 have aligned radial openings termed “perforation zones” 28 that allow fluid communication between the production liner 24 and the hydraulically fractured hydrocarbon-bearing reservoir or formation 16. [0029] In certain embodiments, a number of plugs 30 may be disposed in the well system 10 at positions offset from one another along the longitudinal length of the wellbore 14 in order to provide hydraulic isolation between certain intervals of the well system 10 with a number of perforation zones 28 in each interval. In certain embodiments, each plug 30 may include one or more expanding slips and seal members for anchoring and sealing the plug 30 to the production liner 24 or the casing 18. In addition, in certain embodiments, each plug 30 may be formed IS23.1226-WO-PCT primarily from composite materials (or other suitable materials) that enables the plug 30 to be milled-out for removal as described in greater detail herein. [0030] In certain embodiments, a bottom hole assembly (“BHA”) 32 may be run inside the casing 18 by the tubing 20 (which may be coiled tubing or drill pipe). As illustrated in FIG.2, in certain embodiments, the BHA 32 may include a downhole motor 34 that operates to rotate a milling tool 36. In certain embodiments, the downhole motor 34 may be driven by hydraulic forces carried in milling fluid supplied from the surface 26 of the well system 10. In certain embodiments, the BHA 32 may be connected to the tubing 20, which is used to run the BHA 32 to a desired location within the wellbore 14. It is also contemplated that, in certain embodiments, the rotary motion of the milling tool 36 may be driven by rotation of the tubing 20 effectuated by a rotary table or other surface-located rotary actuator. In such embodiments, the downhole motor 34 may be omitted. [0031] In certain embodiments, the tubing 20 may also be used to deliver milling fluid (arrows 38) to the milling tool 36 to aid in the milling process and carry cuttings and possibly other fluid and solid components in fluid 40 (referred to herein as “return fluid”) that flows up the annulus between the tubing 20 and the casing 18 (or via a return flow path provided by the tubing 20, in certain embodiments) for return to the surface facility (as illustrated in FIG.3). In certain embodiments, the BHA 32 may be located such that the milling tool 36 is positioned in direct contact with a plug 30. In such embodiments, the rotary motion of the milling tool 36 mills away the plug 30 into cuttings that flow as part of the return fluid 40 that is returned to the surface facility (as illustrated in FIG.3). It is also contemplated that the return fluid 40 may include remnant proppant (e.g., sand) or possibly rock fragments that result from the hydraulic fracturing application, and flow within the well system 10 during the plug mill-out process. IS23.1226-WO-PCT After the plug 30 is removed by the milling, a flow path is opened past the drill plug. Under certain conditions, fracturing fluid and possibly hydrocarbons (oil and/or gas), proppants and possibly rock fragments may flow from the fractured reservoir 16 through the perforations 28 in the newly opened interval and back to the surface 26 of the well system 10 as part of the return fluid 40. In certain embodiments, the BHA 32 may be supplemented behind the rotary drill by an isolation device such as, for example, an inflatable packer that may be activated to isolate the zone below or above it, and enable local pressure tests. [0032] FIG.3 is a schematic illustration of the well system 10 of FIGS.1 and 2. As illustrated in FIG.3, in certain embodiments, the well system 10 may include a downhole well tool 42 that is moved along the wellbore 14 via coiled tubing 20. In certain embodiments, the downhole well tool 42 may include a variety of drilling/cutting tools coupled with the coiled tubing 20 to provide a coiled tubing string 44. In the illustrated embodiment, the downhole well tool 42 includes a milling tool 36, which may be powered by a motor 34 (e.g., a positive displacement motor (PDM), or other hydraulic motor). In certain embodiments, the milling tool 36 may be used to mill out a plug 30 or plugs 30 disposed along the wellbore 14. Although described primarily herein as relating to embodiments for milling out plugs 30, in other embodiments, other type of milling targets may be milled out, such as cement, obstructions along the wellbore 14, naturally occurring obstructions such as deposits from formation fluid or injected fluid, objects left in the wellbore 14 from previous operations, warped or deformed completion tubulars, and so forth. In certain embodiments, the wellbore 14 may be an open wellbore or a cased wellbore defined by a casing 18. As described herein, in certain embodiments, the wellbore 14 may be vertical or horizontal or inclined. It should be noted the downhole well tool 42 may be part of various types of BHAs 32 coupled to the coiled tubing 20. IS23.1226-WO-PCT In certain embodiments, the plug(s) 30 may be disposed along the wellbore 14 within a downhole completion. [0033] Particularly, in certain embodiments, the plug(s) 30 may be disposed along a horizontal section of the wellbore 14. Once delivered in place, such plug(s) 30 may be anchored and sealed against the casing 18. Once anchored and sealed, perforation may be applied above the plug 30 through the casing 18, as illustrated in FIG.2. The perforation application may be followed by hydraulic applications to direct high pressure fracturing fluid through the casing perforations 28 into the adjacent formation 16, to cause fracturing of reservoir rock for easier production. Typical hydraulic fracturing fluid may contain other substances such as proppant, sand, fiber, etc., to keep the fractures open after the completion of hydraulic fracturing. The placement, anchoring, perforation, and fracturing process may be repeated by moving from downhole to uphole interval by interval, until the entire formation and production zone are treated as designed. [0034] Upon completion and treatment, such plugs 30 may be removed before producing the well. In general, removal of such plugs 30 may include milling out operations, usually by coiled tubing 20. To improve the efficacy of plug mill-outs, in certain embodiments, the well system 10 also may include a downhole sensor package 46 having a plurality of downhole sensors 48. In certain embodiments, the sensor package 46 may be mounted along the coiled tubing string 44, although certain downhole sensors 48 may be positioned at other downhole locations in other embodiments. In certain embodiments, data from the downhole sensors 48 may be relayed uphole to a surface processing system 50 (e.g., a computer-based processing system) disposed at the surface 26 and/or other suitable location of the well system 10. IS23.1226-WO-PCT [0035] In certain embodiments, the data may be relayed uphole in substantially real time (e.g., relayed while it is detected by the downhole sensors 48 during operation of the downhole well tool 42) via a wired or wireless telemetric control line 52, and this real-time data may be referred to as edge data. For example, in certain embodiments, during a milling operation, the real-time data may be in the form of torque data (e.g., torque applied by the downhole hydraulic motor 34) and thrust data (e.g., weight on bit with respect to a milling bit). In certain embodiments, the torque data and thrust data may be combined to establish torque-thrust curves that, in turn, may be used to determine various parameters related to certain plugs 30 or other targets and/or operation of the milling tool 36. In certain embodiments, the telemetric control line 52 may be in the form of an electrical line, fiber-optic line, or other suitable control line for transmitting data signals. In certain embodiments, the telemetric control line 52 may be routed along an interior of the coiled tubing 20, within a wall of the coiled tubing 20, or along an exterior of the coiled tubing 20. In addition, as described in greater detail herein, additional data (e.g., surface data) may be supplied by surface sensors 54 and/or stored in memory locations 56. By way of example, historical data and other useful data may be stored in a memory location 56 such as cloud storage 58. [0036] As illustrated, in certain embodiments, the coiled tubing 20 may deployed by a coiled tubing unit 60 and delivered downhole via an injector head 62. In certain embodiments, the injector head 62 may be controlled to slack off or pick up on the coiled tubing 20 so as to control the tubing string weight and, thus, the weight on bit (WOB) acting on the bit of the milling tool 36 (or other downhole well tool 42). [0037] In certain embodiments, fluid 38 may be delivered downhole under pressure from a pump unit 64. In certain embodiments, the fluid 38 may be delivered by the pump unit 64 IS23.1226-WO-PCT through the downhole hydraulic motor 34 to power the downhole hydraulic motor 34 and, thus, the milling tool 36. In certain embodiments, the fluid 40 is returned uphole, and this flow back of fluid is controlled by suitable flowback equipment 66. In certain embodiments, the flowback equipment 66 may include chokes and other components/equipment used to control flow back of the return fluid 40 in a variety of applications, including well treatment applications. [0038] In certain embodiments, the downhole well tool 42 may be moved along the wellbore 14 via the coiled tubing 20 under control of the injector head 62 so as to apply a desired tubing weight and, thus, to achieve a desired rate of penetration (ROP) as the milling tool 36 is operated to mill through the plugs 30. In certain embodiments, the controlled movement of the well tool 42 via the coiled tubing 20 may be used in a variety of applications other than milling out plugs 30. Depending on the specifics of a given application, various types of data may be collected downhole, and transmitted to the surface processing system 50 in substantially real time to facilitate improved operation of the downhole well tool 42. For example, the data may be used to fully or partially automate the downhole operation, to optimize the downhole operation, and/or to provide more accurate predictions regarding components or aspects of the downhole operation. [0039] As described in greater detail herein, the pump unit 64 and the flowback equipment 66 may include advanced sensors, actuators, and local controllers, such as PLCs, which may cooperate together to provide sensor data to, receive control signals from, and generate local control signals based on communications with, respectively, the surface processing system 50. In certain embodiments, as described in greater detail herein, the sensors may include flow rate, pressure, and fluid rheology sensors, among other types of sensors. In addition, as described in IS23.1226-WO-PCT greater detail herein, the actuators may include actuators for pump and choke control of the pump unit 64 and the flowback equipment 66, respectively, among other types of actuators. [0040] FIG.4 illustrates a well control system 68 that may include the surface processing system 50 to control the well system 10 described herein. In certain embodiments, the surface processing system 50 may include one or more analysis modules 70 (e.g., a program of computer-executable instructions and associated data) that may be configured to perform various functions of the embodiments described herein. In certain embodiments, to perform these various functions, an analysis module 70 executes on one or more processors 72 of the surface processing system 50, which may be connected to one or more storage media 74 of the surface processing system 50. Indeed, in certain embodiments, the one or more analysis modules 70 may be stored in the one or more storage media 74. [0041] In certain embodiments, the one or more processors 72 may include a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, a digital signal processor (DSP), or another control or computing device. In certain embodiments, the one or more storage media 74 may be implemented as one or more non-transitory computer-readable or machine-readable storage media. In certain embodiments, the one or more storage media 74 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices. Note that the computer-executable instructions and associated data of the IS23.1226-WO-PCT analysis module(s) 70 may be provided on one computer-readable or machine-readable storage medium of the storage media 74, or alternatively, may be provided on multiple computer- readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media are considered to be part of an article (or article of manufacture), which may refer to any manufactured single component or multiple components. In certain embodiments, the one or more storage media 74 may be located either in the machine running the machine-readable instructions, or may be located at a remote site from which machine-readable instructions may be downloaded over a network for execution. [0042] In certain embodiments, the processor(s) 72 may be connected to a network interface 76 of the surface processing system 50 to allow the surface processing system 50 to communicate with the various downhole sensors 48 and surface sensors 54 described herein, as well as communicate with the actuators 78 and/or PLCs 80 of the surface equipment 82 (e.g., the coiled tubing unit 60, the pump unit 64, the flowback equipment 66, and so forth) and of the downhole equipment 84 (e.g., the BHA 32, the downhole motor 34, the milling tool 36, the downhole well tool 42, and so forth) for the purpose of controlling operation of the well system 10, as described in greater detail herein. In certain embodiments, the network interface 76 may also facilitate the surface processing system 50 to communicate data to cloud storage 58 (or other wired and/or wireless communication network) to, for example, archive the data or to enable external computing systems 86 to access the data and/or to remotely interact with the surface processing system 50. [0043] It should be appreciated that the well control system 68 illustrated in FIG.4 is only one example of a well control system, and that the well control system 68 may have more or IS23.1226-WO-PCT fewer components than shown, may combine additional components not depicted in the embodiment of FIG.4, and/or the well control system 68 may have a different configuration or arrangement of the components depicted in FIG.4. In addition, the various components illustrated in FIG.4 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits. Furthermore, the operations of the well control system 68 as described herein may be implemented by running one or more functional modules in an information processing apparatus such as application specific chips, such as application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), programmable logic devices (PLDs), systems on a chip (SOCs), or other appropriate devices. These modules, combinations of these modules, and/or their combination with hardware are all included within the scope of the embodiments described herein. [0044] FIG.5A illustrates a first cross-sectional view of a plug 30 on a wellbore 14, in accordance with embodiments of the present disclosure. As shown, the plug 30 is a hemispherical plug disposed on an inner surface of a wellbore 14. The plug 30 extends into a perforation 92. While the plug 30 is illustrated as being a hemispherical plug, in other embodiments, the plug 30 may be represented as a conical plug, a cylindrical plug, and other at least partially isotropic volumes (e.g., uniform dimensions in at least two directions, such as at least along two of an x-axis, a y-axis, or a z-axis.) FIG.5B illustrates a second cross-sectional view of a plug 30 on a wellbore 14, in accordance with embodiments of the present disclosure. [0045] Once the particulate starts extending into the wellbore 14 from the perforation entrance, the plug 30 (e.g., hemisphere as shown in FIGS.5A and 5B) is subject to multiple forces, the balance of which may lead to the plug 30 unseating from the perforation. The forces IS23.1226-WO-PCT may include one or more of drag forces exerted by the fluid flowing in the wellbore 14, ^^^^_^^^^; pressure forces ^^^_^^_^^^ due to flow within the plug 30; buoyancy forces, ^^^^_^^^^; and internal and surface friction forces, ^^^_^^_^^^. [0046] In certain embodiments, ^^^_^^_^^^ may be represented as a critical lift-off pressure drop Δ^^^^_^^^^ problem, shown in Eqn.1: _{^^^^ = ^^^^ 2 ^^^^ ^^^^^^^^^^^^^^^^^^^^ Δ^^^^^^^^ (1)}

the plug inside the perforation 92, particulates type and perforation roughness. ^^^^_{^^^^^^^^^^^^^^^^} is the perforation radius. It is believed that the hemispherical plug 30 remains attached to the perforation entrance when flow is stopped at a stage where only buoyancy can unseat the plug 30. Therefore, it should be noted that the unseating force ^^^_^^_^^^ is advantageous for determining the likelihood of the plug 30 unseating. [0047] It is believed that the hemispherical plug 30 breaks away from the part of the cake inside the perforation when the forces acting along the wellbore axis are sufficiently large (e.g., exceed one or more threshold forces). This assumption is motivated by visual observation of unseating during the flow loop experiments. Therefore, the force balances are performed on the hemisphere only. The component of the buoyancy force in the axial wellbore direction is given by Eqn. (2). If we also assume that the entrance of the perforation acts as a pulley between the forces acting in the wellbore flow direction and those acting in the perforation flow direction, then all forces can be considered acting along the same axis. The buoyancy force F_b may be expressed as follows: ^^ _2^^^^^^ ³ ^⃗^ _{^^^^^^ ^^^^} = _{(1 − ^^^^^^^^) − ^^^^}

IS23.1226-WO-PCT _{^⃗^^^^^^^ = ^^^^^^^^ ^^^^ (3) ^⃗^^^^^^^^^^^ = ^^^^^^^^ cos^^^^ ^^^^ (3.1) ^⃗^^^^^^^^^^^ = ^^^^^^^^ sin^^^^ cos^^^^ ^⃗^^^ (3.2) ^⃗^^^^^^^^^^^ = ^^^^^^^^ sin^^^^ sin^^^^ ^�^�^�^⃗ (3.3)}

and azimuth axis, respectively. ^^^_^^_^^^ is the radius of the hemispherical cake in the wellbore 14 at the entrance of the perforation. ^^^^ is the gravity acceleration, ^^^^_^^^^ (^^^^_^^^^) is the wellbore fluid (particulates) density, ^^^^ is the wellbore inclination angle and ^^^^ is the perforation azimuth. _{Vectors ^⃗^^^, ^^^^, ^�^�^�^⃗ and ^^^^ are the unit vectors of the perforation axis (pointing radially towards} perforation tip),

axis (pointing towards increasing depths), azimuthal axis, and vertical (pointing downwards) axis. (see FIGS.5A and 5B). [0048] The pressure (^^^^) forces, due to flow through the hemisphere, apply on the periphery of the hemisphere in the wellbore ^^^_^^_^^^^^^^, on the casing wall ^^^_^^_^^^^^^^, and at the perforation entrance ^^^_^^_^^^^^^^. The resultant of these three forces along the perforation axis towards the perforation tip may be represented as: _{^^^^ ^^^ = ^^ 2 ^^^^^ ^^^^^^^^^^ ^^^^ (4) ^^^^ = ^^^^�^^^^2 − ^^^^2 �^^^^ −} ^{^^^^} _{^^^^^^^^^^^^^^^^} ^{^^^^} �_{^^^^ − ^^^^} 2 ^_{^^^^^^^ ^^^^ ^^^^^^^^^^^^^^^^} ^{2^^^^} _^^^^ ^{^^^^} _{^^^^ ^^^^ ^^^^^^^^^^^^^^^^�} (5)

IS23.1226-WO-PCT where ^^^^_{^^^^^^^^^^^^^^^^} is counted positively when flow enters the perforation from the wellbore 14, ^^^^ is the viscosity of the fluid flowing through the cake, and ^^^^_^^^^ is the cake permeability.

drag force resulting from the viscous stress applied by the fluid flowing around the hemisphere surface, and by the pressure relative distribution there, acts along the wellbore flow direction Eqn. (8). _{^⃗^^^ ^^^^} ² ^_{^^^ = sign(^^^^^^^^) ^^^^^^^^} 2 ^^^^_^^^^^^^^_^ ² ^_^^ ^^^^_^^^^ ^^^^ (8) ^^^^_^^^^ is the

depths. The expression for the drag coefficient ^^^^_^^^^ for a hemisphere mounted on the inner wall of a pipe may be difficult to determine. However, it is believed that the drag coefficient may be related to the ratio ^^^_^^_^^^/^^^_^^_^^^ and the Reynolds number. However, the values of ^^^^_^^^^ may be half the value of ^^^^_^^^^ for a sphere, in the 10³-10⁶ Reynolds number range (e.g., Reynolds number based on hemisphere radius), it is assumed that this ratio holds for all ^^^_^^_^^^-based Reynolds numbers whatever ^^^_^^_^^^/^^^_^^_^^^. [0049] FIG.6 illustrates a graph 100 of draft coefficient versus Reynolds number for a hemisphere plug 30, in accordance with embodiments of the present disclosure. As referred to herein, the “Reynolds number” refers to a dimensionless parameter that indicates a type of flow (e.g., laminar or turbulent) of a fluid through a conduit. [0050] In the following [^^^^]⁺ ([^^^^]⁻) is equal to ^^^^ if ^^^^ is positive (negative), 0 otherwise. The modulus ^^^_^^_^^^ of the force trying to unseat the plug 30 is given by Eqn. (9): − _{^^^^^^^^ =�^⃗^^^^^^^ + ^⃗^^^^^^^^^^^ + ^⃗^^^^^^^^^^^ −��^⃗^^^^^^^^^^^ + ^⃗^^^^^^^�. ^⃗^^^� ^⃗^^^� =�^^^^^^2 ^^^^^^ + ^^^^^^^2 ^^^^^ + ^^^^^^^2 ^^^^^ (9)}

IS23.1226-WO-PCT [0051] The modulus Fs of the force trying to seat the plug 30 is given by Eqn. (10). + ^{^^^^ ^^^^} + _{^^^^ =��^⃗^^^ + ^⃗^^^^�. ^⃗^^^� =�^^^ ^^^^^^^^^^^^^^^^ ^^^^ ^^^^^^^^ ^^^ ^^^^^ sin^^^^ cos^^^^ +} ^{2^^^^} _{^^^^ �^^^^^^^^3 − ^^^^^^^^^^^^^^^^^^^^��} (10)

14, in accordance with embodiments of the present disclosure. _{[0053] If ^^^^^^^^ − ^^^^^^^^ > ^^^^^^^^, the plug may be unseated. FIG. 7 illustrates a graph 120 depicting a magnitude of all forces, assuming ^^^^^^^^ = 0 and a vertical well (^^^^ = 0), during injection with the parameters listed in Table 1 and for various values of ^^^^^^^^^^^^^^^^^^^^⁄ ^^^^^^^^ where ^^^^^^^^ is the flow rate} in the wellbore 14 and q_perf is the flow rate entering the perforation (e.g., along ^⃗^^^ as shown in FIGS.5A and 5B). In practice, this ratio can span many orders of magnitude. It is believed _{that, during injection, relatively small ^^^^^^^^^^^^^^^^^^^^⁄ ^^^^^^^^ may correspond to plug unseating being likely} (e.g., 50% or greater change of plug unseating occurring, 60% or greater change of plug unseating occurring, 70% or greater change of plug unseating occurring, 80% or greater change of plug unseating occurring, 90% or greater change of plug unseating occurring). However, unseating may occur when downhole pressure changes (e.g., corresponding to pump rate changes) inverse the flow in a perforation for a time period. ^^^^_^^^^ ^^^^_^^^^ ^^^^_^^^^ ^^^^_^^^^3 ^^^^_{^^^^^^^^^^^^^^^^} ^^^^ ^^^^_^^^^ ^^^_^^_^^^ (kg/m³) (kg/m³) (mm) (mm) (cP) (mD) (cm) 1000 1240 0.2 50 3 1 1000 8 Table 1- Flow parameters used to produce the graph in FIG.7. [0054] In general, FIG. 7 shows forces acting on the part of the plug 30 extending into the _{wellbore 14. Pressure forces ^^^^^^^^^^^^ are for ^^^^^^^^^^^^^^^^^^^^⁄ ^^^^ −^^^^ ^^^^ = 10 .} IS23.1226-WO-PCT [0055] Based on this model, multiple sensitivity runs may be conducted to optimize the injection rate schedule to mitigate the probability to unseat the particulate/diverter cake. The injection rate schedule may include the fracturing treatment pumping, diverter pumping, and transitioning between the two, or modifying operation of one or more other flow control devices providing a fluid into the wellbore (e.g., the pump unit 64 and the flowback equipment 66). [0056] FIG.8 illustrates a flow diagram of a process 140 for generating a plug unseating output, in accordance with embodiments of the present disclosure. One or more steps of the process 140 may be performed by the processor 72 or any suitable processor. [0057] At block 142, the process 140 includes measuring one or more flow parameters in the wellbore 14 using one or more downhole tools 42. The downhole tools 42 may be any tool capable to determining flow parameters discussed with respect to FIGS.5A and 5B, such as ACTive or production logging tools (PLT), downhole cameras, or distributed temperature sensing (DTS) tools. [0058] At block 144, the process 140 includes determining one or more forces subjected to a plug 30 based on the one or more flow parameters. In general, the one or more forces may be any one or combination of the forces discussed with respect to FIGS.5A and 5B. In some embodiments, to calculate the one or more forces, the processor 72 (e.g., or any suitable processor) may utilize one or more of the Eqns. (1)-(10). [0059] At block 146, the process 140 includes generating a plug unseating output based on the one or more forces. The plug unseating output may be a control signal, alert, or otherwise that corresponds to adjusts operation of a downhole tool 42 based on a likelihood of a plug unseating. For example, the plug unseating output may cause a display to depict information related to the likelihood of the plug unseating, thereby informing a user of a corrective action to IS23.1226-WO-PCT be taken. In some embodiments, the plug unseating output may arrange the information in particular positions on a display when the likelihood exceeds a threshold. In some embodiments, the plug unseating output may cause diversion operations to halt. In some embodiments, the plug unseating output may modify an injection rate schedule. [0060] As one non-limiting example of the process 140, the processor 140 may determine flow parameters such as qperf and qw. Then, the processor 140 may determine Fu and Fs and compare a combination of these values (e.g, F_u – Fs) to F_f. If the combination is greater than Ff, then the processor 140 may determine that an unseating is likely. Accordingly, the processor 140 may determine an injection schedule to reduce or prevent the unseating from occurring. Additionally or alternatively, the processor 140 may generate a visualization indicating the forces and the comparison (e.g., to Ff) to aid an operator in determining whether and/or to what extent an injection schedule may be adjusted. [0061] Technical effects of the present disclosure include a model that utilizes flow parameters to determine forces subjected to a plug 30 that may cause the plug to unseat. The disclosed techniques may be capable of determining diversion pill failure. As compared to certain conventional models, the techniques provide an estimation of a failure of a plug 30 based on predicted or actual flow parameters. [0062] The specific embodiments described above have been illustrated by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.

Claims

IS23.1226-WO-PCT CLAIMS 1. A method comprising: measuring one or more flow parameters in a wellbore using one or more downhole tools; determining one or more forces subjected to a plug formed in a perforation within the wellbore based on the one or more flow parameters; and generating a plug unseating output based on the one or more forces. 2. The method of claim 1, comprising adjusting operation of one or more downhole components based on the plug unseating output. 3. The method of claim 1, where the one or more forces comprises one or more buoyancy forces, F_b, in an axial wellbore direction proximate to the plug. 4. The method of claim 3, where the one or more forces comprises one or more perforation forces, F_p, along a perforation axis towards a perforation tip of the plug. 5. The method of claim 4, wherein generating the plug unseating output based on the one or more forces comprises: determining an unseating force, F_u, and a seating force, F_s, based on F_b and F_p; determining internal and surface friction forces, ^^^_^^_^^^, based on a radius of the perforation; and generating the plug unseating output based on a comparison of F_u and F_s to F_f. IS23.1226-WO-PCT 6_{. The method of claim 5, wherein the comparison is based on ^^^^^^^^ − ^^^^^^^^ > ^^^^^^^^.} 7. The method of claim 5, wherein F_s is determined based on: + ^^^^ ^_{^^ + ^⃗^^^�. ^⃗^^^� =�^^^^ sin^^^^ cos^^^ ^^^^^^^} ^^^^ + ^_{^^^ =��^⃗ ^^^^^^^^^ ^^^^ ^^^^^^^^ ^^^^ ^^^^ ^ +} 2^^^^ _{�^^^^^^^^3 − ^^^^^^^^^^^^^^^^^^^^�� ^^^^} where

formed on the plug in the wellbore, and ^^^^_^^^^ is permeability of the cake, r_perf is the radius of the perforation, ^^^^ is a viscosity of a fluid flowing through the cake, ^^^^ is a wellbore inclination angle, and ^^^^ is a perforation azimuth. 8. The method of claim 1, wherein generating the plug unseating output comprises optimizing an injection rate schedule by determining one or more of: an injection rate at which particulate/diversion material is pumped; an injection rate at which a stimulation treatment followed by particulate/diversion material is pumped; and a transition of injection rate from treatment to a diversion pill and vice versa is conducted. 9. The method of claim 1, wherein determining the one or more forces subjected to the plug formed in the perforation comprises utilizing a physics-based model to predict unseating of diversion material based on drag forces, pressure forces, buoyancy forces, cake cohesion, chemical degradation of particulates, or a combination thereof. IS23.1226-WO-PCT 10. The method of claim 9, wherein the physics-based model is calibrated using data relating to prior experiments. 11. A system, comprising: one or more memory storing a physics-based model to predict unseating of diversion material based on drag forces, pressure forces, buoyancy forces, cake cohesion, chemical degradation of particulates, or a combination thereof. a control system comprising one or more processors, wherein the control system is configured to: measure one or more flow parameters in a wellbore using one or more downhole tools; determine one or more forces subjected to a plug formed in a perforation within the wellbore based on the one or more flow parameters and the physics-based model; generate a plug unseating output based on the one or more forces; and adjust operation of one or more downhole components based on the plug unseating output. 12. The system of claim 11, wherein the one or more forces comprises an unseating force, F_u, and a seating force, F_s.

IS23.1226-WO-PCT 13. The system of claim 12, wherein the control system is configured to generate the plug unseating output by: determining internal and surface friction forces, ^^^_^^_^^^, based on a radius of the perforation; and generating the plug unseating output based on a comparison of Fu and Fs to Ff. 14. The system of claim 13, wherein F_s is determined based on: + ^^^^ ^^^^ + ^_{^^^ =��^⃗^^^ + ^⃗^^^� ^^^^^^^^^^^^^^^^ ^^^^ ^^^^^^^^ ^^^^ . ^⃗^^^� =�^^^^^^^^ sin^^^^ cos^^^^ +} 2^^^^ _{�^^^^^^^^3 − ^^^^^^^^^^^^^^^^^^^^�� ^^^^} where

formed on the plug in the wellbore, and ^^^^_^^^^ is permeability of the cake, r_perf is the radius of the perforation, ^^^^ is a viscosity of a fluid flowing through the cake, ^^^^ is a wellbore inclination angle, ^^^^ is a perforation azimuth, and F_b is a buoyancy force in an axial wellbore direction proximate to the plug. 15. The system of claim 11, wherein the physics-based model is calibrated using data relating to prior experiments. 16. The system of claim 11, wherein the control system is configured to adjust operation of the one or more downhole components by adjusting an injection schedule of one or more flow control devices providing a fluid into the wellbore. 17. The system of claim 11, wherein the one or more downhole components comprises one or more pump units configured to provide a fluid into the wellbore. IS23.1226-WO-PCT 18. A method, comprising: measuring one or more flow parameters in a wellbore using one or more downhole tools; determining one or more forces subjected to a plug formed in a perforation within the wellbore based on the one or more flow parameters, wherein the one or more forces comprises: one or more buoyancy forces, Fb, in an axial wellbore direction proximate to the plug; and one or more perforation forces, Fp, along a perforation axis towards a perforation tip of the plug; determining an unseating force, F_u, and a seating force, F_s, based on F_b and F_p; determining internal and surface friction forces, ^^^_^^_^^^, based on a radius of the perforation; generating a plug unseating output based on a comparison of F_u and F_s to F_f; and adjusting an injection schedule of one or more flow control devices based on the plug unseating output. 19. The method of claim 18, wherein Fs is determined based on: + ^^^^_^^^ ^^^^ + ^_{^^^ =� ^^^^^^^^^^^^^ ^^^^ �^⃗^^^^^^^^^^^ + ^⃗^^^^^^^�. ^⃗^^^� =�^^^^^^^^ sin^^^^ cos^^^^ + �^^^^^^^^3 − ^^^^^^^^^^^^^^^^^^^^��} where

formed on plug in the wellbore, and ^^^^_^^^^ is permeability of the cake, rperf is the radius of the perforation, ^^^^ is a viscosity of a fluid flowing through the cake, ^^^^ is a wellbore inclination angle, ^^^^ is a perforation azimuth, and Fb is a buoyancy force in an axial wellbore direction proximate to the plug. IS23.1226-WO-PCT 20. The method of claim 18, wherein Fp is determined based on: ^^^^ ^ ^_{^^^^^^^ − ^^^^_^^^^^^^^ − ^^^^_^^^^^^^^ ) ^^^^ ⃗ = ^^^^^^^^^^^^^^^} ^^^ ^_{^^^ ⃗_^^^^ = (^^^^_ ^} 2^^^^ _{�^^^^^^^^ − ^^^^^^^^^^^^^^^^^^^^� ^⃗^^^ ^^^^} where a force applied on

a casing wall, and ^^^_^^_^^^^^^^ is a force applied at an entrance of the perforation.