IS21.4273-WO-PCT SYSTEMS AND METHODS FOR OPTIMIZING HYDRAULIC FRACTURING CROSS-REFERENCE TO REPLATED APPLICATION [0001] This application claims priority to and the benefit of U.S. Provisional Patent Application Serial No.63/367,385, entitled "Systems and Methods for Optimizing Hydraulic Fracturing,” filed June 30, 2022, which is hereby incorporated by reference in its entirety for all purposes. FIELD OF INVENTION [0002] The present disclosure generally relates to systems and methods for optimizing hydraulic fracturing and, more specifically, to optimizing hydraulic fracturing job design through the use of an advanced wellbore proppant transport model and coupled hydraulic fracture simulator. BACKGROUND [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] A wellbore stimulation job utilizes several well service systems at a wellsite. A stimulation job for a horizontal wellbore may include dividing the wellbore into numerous IS21.4273-WO-PCT individual operations or stages. For example, a wellbore stimulation job may be divided into sixty or more individual stimulation operations or stages. The process utilizes individual pumping and wireline operations (e.g., pump-down and perforating operations) between each stimulation stage (e.g., hydraulic fracturing) to isolate the wellbore and perforate a casing. Such pumping and wireline operations also include wellhead fluid control valves associated with the wellbore. [0005] Multistage hydraulic fracturing in horizontal wells is a well-established technology for development of unconventional and tight conventional oil and gas reservoirs. Plug-and-perf completion is the most common method for these horizontal wells. Usually, multiple perforation clusters are stimulated simultaneously within a single stage of treatment. Accordingly, multiple hydraulic fractures can be simultaneously initiated. In this case, several simultaneously propagating fractures interact via hydraulic connection through the wellbore and are also subject to the alteration of local stresses induced by neighboring fractures due to a stress shadow effect. This complex interaction can cause non-uniform and temporary varying distribution of slurry and proppant among multiple fractures, which in turn creates variable dimensions and non-equally propped hydraulic fractures. In such a situation, certain zones might be under-stimulated and, consequently, well productivity may be suboptimal. 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. IS21.4273-WO-PCT [0007] Certain embodiments of the present disclosure include a method that includes simulating, via a wellbore flow simulator being executed by one or more processing devices, a distribution of proppant between a plurality of perforation clusters of a wellbore during a hydraulic fracturing job design. The method also includes simulating, via a hydraulic fracture simulator being executed by the one or more processing devices, one or more hydraulic fractures propagating through a subterranean formation through which the wellbore extends. The method further includes automatically adjusting, via fracturing design software executed by the one or more processing devices, the hydraulic fracturing job design by dynamically exchanging data relating to the distribution of the proppant and the one or more hydraulic fractures between the wellbore flow simulator and the hydraulic fracture simulator. [0008] Certain embodiments of the present disclosure also include a data processing system that includes one or more processors configured to execute instructions stored on one or more memory media, wherein the instructions, when executed by the one or more processors, cause the data processing system to simulate, via a wellbore flow simulator being executed by the data processing system, a distribution of proppant between a plurality of perforation clusters of a wellbore during a hydraulic fracturing job design; to simulate, via a hydraulic fracture simulator being executed by the data processing system, one or more hydraulic fractures propagating through a subterranean formation through which the wellbore extends; and to automatically adjust, via fracturing design software executed by the data processing system, the hydraulic fracturing job design by dynamically exchanging data relating to the distribution of the proppant and the one or more hydraulic fractures between the wellbore flow simulator and the hydraulic fracture simulator. IS21.4273-WO-PCT [0009] 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 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 [0010] Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings, in which: [0011] FIG.1 is a schematic view of at least a portion of an example implementation of a wellsite system, in accordance with embodiments of the present disclosure; [0012] FIG.2 is a schematic view of a portion of an example implementation of the wellsite system shown in FIG.1, in accordance with embodiments of the present disclosure; [0013] FIG.3 is a schematic view of at least a portion of a processing device (or system), in accordance with embodiments of the present disclosure; [0014] FIG.4 illustrates a flow diagram of an example algorithm for perforation cluster efficiency optimization, which may be executed by one or more processing devices, in accordance with embodiments of the present disclosure; IS21.4273-WO-PCT [0015] FIG.5 illustrates a flow diagram of fracturing simulation software of FIG.4, in accordance with embodiments of the present disclosure; [0016] FIG.6 illustrates a wellbore section with multiple perforation clusters, in accordance with embodiments of the present disclosure; [0017] FIG.7 illustrates certain changes in the fracturing design software to account for results from the wellbore flow simulator, in accordance with embodiments of the present disclosure; [0018] FIG.8 illustrates the results for cases with different number of perforations per cluster, in accordance with embodiments of the present disclosure; [0019] FIG.9 illustrates footprint for a screenout case, in accordance with embodiments of the present disclosure; [0020] FIG.10 illustrates individual fracture lengths and cumulative mass of proppant received by different clusters for the screenout case illustrated in FIG.9, in accordance with embodiments of the present disclosure; [0021] FIG.11 illustrates a configuration of a simulated case for a uniform proppant distribution case, in accordance with embodiments of the present disclosure; and [0022] FIG.12 illustrates initial oil production rate for a uniform and a non-uniform proppant distribution case in accordance with embodiments of the present disclosure. IS21.4273-WO-PCT DETAILED DESCRIPTION [0023] 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. [0024] 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 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. [0025] 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 IS21.4273-WO-PCT 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. [0026] 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 “fracturing” refers to the process and methods of breaking down a geological formation and creating a fracture (i.e., the rock formation around a wellbore) 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. [0027] In addition, as used herein, the terms “real time”, ”real-time”, or “substantially real time” may be used interchangeably and are intended to describe operations (e.g., computing operations) that are performed without any human-perceivable interruption between operations. IS21.4273-WO-PCT 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 frequently, during operations of the systems (e.g., while the systems are operating). In addition, as used herein, the terms “continuous”, “continuously”, or “continually” are intended to describe operations that are performed without any significant interruption. For example, as used herein, control commands may be transmitted to certain equipment every five minutes, every minute, every 30 seconds, every 15 seconds, every 10 seconds, every 5 seconds, or even more often, such that operating parameters of the equipment may be adjusted without any significant interruption to the closed-loop control of the equipment. [0028] In addition, as used herein, the terms “automatic”, “automated”, “autonomous”, and so forth, are intended to describe operations that are performed are caused to be performed, for example, by a computing system (i.e., solely by the computing system, without human intervention). Indeed, it will be appreciated that the data processing systems described herein may be configured to perform any and all of the data processing and control functions described herein automatically. [0029] As described above, complex interaction of multiple hydraulic fractures may lead to non-uniform and temporary varying distribution of slurry and proppant among the fractures, which in turn creates variable dimensions and non-equally propped hydraulic fractures, thereby leading to certain zones being under-stimulated and, consequently, well productivity being suboptimal. Preventing this suboptimal conditional is often addressed through different silos (e.g., perforation, fracturing schedule, completion, introduction of diverters) without IS21.4273-WO-PCT consideration to other silos. However, without considering all factors, simultaneously, a less than optimum solution may be achieved. Using computational models, perforation design, completion, and pumping schedule may be altered to ensure the most uniform stimulation of the reservoir, homogeneous drainage, and maximum well productivity. [0030] For example, one conventional method is to calculate proppant amount delivered into fractures based on calculation of dimensionless parameters characterizing fracturing fluid flow during the treatment and usage of pre-calculated dependencies of proppant amount on these dimensionless parameters. However, this method does not involve a computational model of fractures themselves and, thus, does not account for mutual fractures’ influence during the stimulation. [0031] Another conventional method utilizes a model of one-dimensional proppant transport within the well, considering fluid elasticity effects and proppant settling and resuspension. However, this method provides neither a method to adjust distribution of fracturing fluid and proppant among fractures nor a method to optimize resulting well productivity. [0032] Another conventional method is to predict proppant placement along a fracturing stage using computational fluid dynamics simulations for a limited set of perforation orientations, interpolation of pre-calculated results for arbitrary perforation orientation, training of a machine learning model, and calculation of proppant distribution using the trained model. However, this method also does not account for dynamics of fracture propagation. [0033] Another conventional method is to determine and optimize distribution of proppant across perforation clusters within the fracturing stage. This method utilizes algorithms and methods of optimization of perforation count per clusters within the stage, perforation diameters, IS21.4273-WO-PCT and pumping rate to achieve desired perforation friction and minimize deviation of proppant distribution. The method also incorporates reservoir stress variability and stress-shadowing into optimization workflow. However, in this method, proppant distribution uniformity is considered as a target variable for optimization, and the method does not include estimations of individual fractures and well productivity. [0034] Another conventional method is to simulate a transient proppant slurry flow in a wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, proppant transport efficiency, and dynamic pressure coupling with the hydraulic fractures that is numerically coupled to an advanced hydraulic fracture simulator that models fracture growth, fluid flow, proppant transport inside complex hydraulic fracture networks, and mechanical interaction between adjacent hydraulic fractures. [0035] The embodiments described herein provide systems and methods to improve cluster efficiency and maximize multistage hydraulically fractured well productivity. In particular, the embodiments described herein include simulation of completion parameters (e.g., casing inner diameter, deviation angle, and so forth), perforation parameters (e.g., hole size, standoff, phasing, and so forth), and hydraulic fracture parameters (e.g., width, net pressure, proppant size, pump rate, and so forth) to understand the proppant distribution across a stage’s clusters. If the distribution of proppant is found to be suboptimal, changes to the perforation parameters (e.g., larger holes via different perforation gun selection) or pump schedule (e.g., rate or proppant size) or the addition of diversion pills, for example, may be simulated. The design loop of parameter selection Æ simulation Æ evaluation may be repeated as many times as needed to meet the practical design considerations. In addition, the loop may even be conducted during pumping IS21.4273-WO-PCT execution to validate the pre-execution assumptions or update design parameters if more accurate information becomes available. [0036] FIG.1 is a schematic view of at least a portion of an example implementation of a wellsite system 10. FIG.1 illustrates multiple wellbores 12 each extending from a terrain surface of a wellsite 14, a partial sectional view of a subterranean formation 16 penetrated by the wellbores 12, and various pieces of wellsite equipment or components of the wellsite system 10 located at the wellsite 14. The wellsite system 10 may facilitate recovery of oil, gas, and/or other materials that are trapped in the subterranean formation 16. In certain embodiments, each wellbore 12 may include a casing 18 secured by cement (not shown). The wellsite system 10 may be configured to transfer various materials and additives from corresponding sources to a destination location for blending or mixing and subsequent injection into one or more of the wellbores 12 during fracturing and other stimulation operations. In certain embodiments, such operations may be partially or fully automated using at least one controller, as described in greater detail herein. [0037] In certain embodiments, the wellsite system 10 may include a mixing unit 20 (referred to hereinafter as a “mixer”) fluidly connected to one or more tanks 22 and a container 24. In certain embodiments, the container 24 may contain a first material and the tanks 22 may contain a liquid. In certain embodiments, the first material may be or include a hydratable material or gelling agent, such as cellulose, clay, galactomannan, guar, polymers, synthetic polymers, and/or polysaccharides, among other examples. In addition, in certain embodiments, the liquid may be or include an aqueous fluid, such as water or an aqueous solution including water, among other examples. In certain embodiments, the mixing unit 20 may be configured to receive the first material and the liquid, via two or more conduits or other material transfer IS21.4273-WO-PCT means (hereafter simply “conduits”) 26, 28, and mix or otherwise combine the first material and the liquid to form a base fluid, which may be or include what is known in the art as a gel. In certain embodiments, the mixing unit 20 may then discharge the base fluid via one or more conduits 30. [0038] In certain embodiments, the wellsite system 10 may further include another mixing unit 32 fluidly connected to the mixing unit 20 and another container 34. In certain embodiments, the container 34 may contain a second material that may be appreciably different than the first material. For example, the second material may be or include a proppant material, such as quartz, sand, sand-like particles, silica, and/or propping agents, among other examples. In certain embodiments, the mixing unit 32 may be configured to receive the base fluid from the mixing unit 20 via the one or more conduits 30, and the second material from the container 34 via one or more conduits 36, and mix or otherwise combine the base fluid and the second material to form a mixed fluid, which may be or include what is known in the art as a fracturing fluid. In certain embodiments, the mixing unit 32 may then discharge the mixed fluid via one or more conduits 38. [0039] In certain embodiments, the mixed fluid may be communicated from the mixing unit 32 to a common manifold 40 via the one or more conduits 38. In certain embodiments, the common manifold 40 may include a low-pressure distribution manifold 42, a high-pressure collection and discharge manifold 44, as well as various valves and diverters, which may be collectively configured to direct the flow of the mixed fluid in a predetermined manner. In certain embodiments, the common manifold 40 may receive the mixed fluid from the one or more conduits 38 and distribute the mixed fluid to a fleet of pump units 46 via the low-pressure distribution manifold 42. The common manifold 40 may be known in the art as a missile or a IS21.4273-WO-PCT missile trailer. Although the fleet is illustrated as including four pump units 46, in other embodiments, the fleet may include other quantities of pump units 46 within the scope of the present disclosure. [0040] Each pump unit 46 may include a pump 48, a prime mover 50, and perhaps a heat exchanger 52. In certain embodiments, each pump unit 46 may receive the mixed fluid from a corresponding outlet of the low-pressure distribution manifold 42 of the common manifold 40, via one or more conduits 54, and discharge the mixed fluid under pressure into a corresponding inlet of the high-pressure collection and discharge manifold 44 via one or more conduits 56. In certain embodiments, the mixed fluid may then be discharged from the high-pressure collection and discharge manifold 44 via one or more conduits 58. [0041] The tanks 22, the containers 24, 34, the mixing units 20, 32, the pump units 46, the manifold 40, and the conduits 26, 28, 30, 36, 38, 54, 56, 58 may collectively form a treatment (e.g., stimulation) fluid system. As described herein, the treatment fluid system of the wellsite system 10 may be configured to transfer additives and produce a fracturing fluid that may be pressurized and injected into a selected wellbore 12 during hydraulic fracturing operations. However, it is to be understood that the treatment fluid system may also or instead be configured to transfer other additives and mix other treatment fluids that may be pressurized and injected into the selected wellbore 12 during other well and/or reservoir treatment operations, such as acidizing operations, chemical injection operations, and other stimulation operations, among other examples. Accordingly, unless described otherwise, the one or more mixed fluids being produced and pressurized by the treatment fluid system for injection into a selected wellbore 12 may be referred to hereinafter simply as “a treatment fluid.” IS21.4273-WO-PCT [0042] In certain embodiments, the treatment fluid may be received by a fracturing manifold 60, which may selectively distribute the treatment fluid between the wellbores 12 via a plurality of corresponding fluid conduits 62 extending between the fracturing manifold 60 and each wellbore 12. In certain embodiments, the fracturing manifold 60 may include a plurality of remotely operated fluid flow control valves 64 (e.g., frac valves, shut-off valves), each remotely operable to fluidly connect (and disconnect) the one or more of the fluid conduits 58 to (and from) a selected one or more of the fluid conduits 62 and, thus, facilitate injection of the treatment fluid into a selected one or more of the wellbores 12. The fracturing manifold 60 may be known in the art as a zipper manifold. [0043] Each wellbore 12 may be capped by a plurality (e.g., a stack) of fluid flow control devices 66, 68, which may include or form a Christmas tree (e.g., a frac tree) including fluid flow control valves (e.g., master valves, wing valves, swab valves, etc.), spools, flow crosses (e.g., goat heads, frac heads, etc.), and fittings individually and/or collectively configured to direct and control (e.g., permit and prevent) flow of the treatment fluid into the wellbore 12 and to direct and control flow of formation fluids out of the wellbore 12. In certain embodiments, the fluid flow control valves of the fluid flow control device 66, 68 may be configured to close selected tubulars or pipes, such as the casing 18 or production tubing extending within the wellbore 12, to selectively facilitate fluid access to the wellbore 12. In certain embodiments, the fluid flow control devices 66, 68 may also include or form a blow-out preventer (BOP) stack selectively operable to prevent flow of the formation fluids out of the wellbore 12. In certain embodiments, the fluid flow control devices 66, 68 may be directly or indirectly mounted on top of a wellhead 70 (e.g., tubing head adapter) terminating the wellbore 12 at the surface of the wellsite 14. In certain embodiments, each fluid flow control valve 64 of the fracturing manifold 60 may be IS21.4273-WO-PCT fluidly connected to a corresponding fluid flow control device 66 via one or more fluid conduits 62, to facilitate selective fluid connection between the common manifold 40 and one or more of the wellbores 12. Thus, the fluid flow control valves 64 of the fracturing manifold 60 and the fluid flow control valves of the fluid flow control devices 66, 68 may collectively form a fluid flow control valve system configured to fluidly connect (and disconnect) one of the treatment fluid system and a pump-down system, as described herein, to (and from) a selected one or more of the wellbores 12. [0044] In certain embodiments, a downhole intervention and/or sensor assembly, referred to herein as a tool string 72, may be conveyed within a selected one of the wellbores 12 via a conveyance line 74 operably coupled with one or more pieces of equipment at the wellsite 14. In certain embodiments, the tool string 72 may include a perforating tool configured to perforate the casing 18 and a portion of the formation 16 surrounding the wellbore 12 during perforating operations. In certain embodiments, the conveyance line 74 may be or include a cable, a wireline, a slickline, a multiline, an e-line, coiled tubing, and/or other conveyance means. [0045] In certain embodiments, the conveyance line 74 may be operably connected to a conveyance device 76 (e.g., a wireline or coiled tubing conveyance unit) configured to apply an adjustable tension to the tool string 72 via the conveyance line 74 to convey the tool string 72 through the wellbore 12. In certain embodiments, the conveyance device 76 may be or include a winch conveyance system including a reel or drum 78 storing thereon a wound length of the conveyance line 74. The drum 78 may be rotated by a rotary actuator (e.g., an electric motor, a hydraulic motor, etc.) (not shown) to selectively unwind and wind the conveyance line 74 to apply an adjustable tensile force to the tool string 72 to selectively convey the tool string 72 into and out of the wellbore 12. In certain embodiments, the conveyance line 74 may be directed, IS21.4273-WO-PCT guided, and/or injected (e.g., pushed downhole) into the wellbore 12 by an injection device 80 (e.g., a sheave, a pulley, a coiled tubing injector), one or more of which may be supported above the wellbore 12 via a mast, a derrick, a crane, and/or another support structure (not shown). In certain embodiments, the conveyance line 74 may include and/or be operable in conjunction with means for communication between the tool string 72, the conveyance device 76, and/or one or more other portions of the surface equipment, including a tool string control system. [0046] The tool string 72 may be deployed into or retrieved from the wellbore 12 via the conveyance device 76 through the fluid flow control devices 66, 68, the wellhead 70, and/or a sealing and alignment assembly 82 mounted on the fluid flow control devices 66, 68 and configured to seal the conveyance line 74 during deployment, conveyance, intervention, and other wellsite operations performed via the tool string 72. The injection device 80 may, thus, guide the conveyance line 74 between the conveyance device 76 and the sealing and alignment assembly 82. In certain embodiments, the sealing and alignment assembly 82 may include a lock chamber (e.g., a lubricator, an airlock, a riser, etc.) mounted on the fluid flow control devices 66, 68, and a stuffing box configured to seal around the conveyance line 74 at the top of the lock chamber. In certain embodiments, the stuffing box may be configured to seal around an outer surface of the conveyance line 74, such as via annular packings applied around the surface of the conveyance line 74 and/or by injecting a fluid between the outer surfaces of the conveyance line 74 and an inner wall of the stuffing box. [0047] In certain embodiments, the sealing and alignment assembly 82 and the injection device 80 may be disconnected from above a wellbore 12 that was perforated and is now ready for stimulation (e.g., fracturing operations), and may be installed or connected above a wellbore 12 that is to be perforated in preparation for stimulation. In certain embodiments, the sealing and IS21.4273-WO-PCT alignment assembly 82 and the injection device 80 may be moved from wellbore 12 to wellbore 12 and supported above a wellbore 12 by a crane or other lifting equipment. The conveyance device 76, the sealing and alignment assembly 82, the injection device 80, the tool string 72, and the conveyance line 74 may collectively form at least a portion of a perforating system configured to convey the tool string 72 (including a perforating tool) within and out of a wellbore 12 and to perforate the wellbore 12. [0048] In certain embodiments, the wellsite system 10 may further include a pump-down system configured to inject a fluid (e.g., water) into a selected one of the wellbores 12 to perform pump-down operations to convey the tool string 72 to an intended depth along the wellbore 12. The pump-down operations may be utilized to move the tool string 72 along the wellbore 12 to facilitate wellbore plugging and perforating (“plug and perf”) operations. For example, the tool string 72 may be conveyed through the wellbore 12 to fluidly isolate an upper formation zone that has not yet been perforated from a lower formation zone that has already been perforated, and then perforate the upper formation zone. In certain embodiments, the pumping system may include a pump unit 84 configured to inject the fluid from a fluid container 86 into the selected one of the wellbores 12 containing the tool string 72 via a corresponding fluid flow control device 68 (or wellhead 70). Each pump unit 84 may include a fluid pump 88, a prime mover 90 for actuating the fluid pump 88, and perhaps a heat exchanger 92. In certain embodiments, the fluid pump 88 of the pump unit 84 may be fluidly connected to the fluid container 86 and to each fluid flow control device 68 (which may be or form a portion of the wellhead 70) via a plurality of conduits 94, which may be or form a fluid distribution manifold. In certain embodiments, pump-down and plug and perf operations may be performed in a selected wellbore 12 while stimulation operations are simultaneously performed in one or more other wellbores 12. IS21.4273-WO-PCT Accordingly, when a wellbore 12 is selected to be plugged and perforated, the sealing and alignment assembly 82, the injection device 80, and the conveyance device 76 may be installed at and/or moved to the selected wellbore 12. Then, the tool string 72 may be conveyed through the wellbore 12 via the pump-down operations and utilized to perform the plug and perf operations. [0049] In certain embodiments, the fracturing manifold 60 may include an arrangement of flow fittings and manual and remotely actuated fluid flow control valves 64, and may be configured to selectively isolate wellbores 12 by directing the treatment fluid from the common manifold 40 to a selected one or more of the wellbores 12 in which plug and perf operations have been completed and are ready to be fractured. Such operation of the fracturing manifold 60 (which may be automated or semi-automated using at least one controller, in certain embodiments) may improve the speed of transitioning between wellbores 12, and may reduce or eliminate manual adjustments, which may also reduce safety risks. Thus, the fracturing manifold 60 may be configured to facilitate “zipper” fracturing operations, which may provide improved (perhaps nearly continuous) utilization of the frac crew and equipment, resulting in substantial improvement to the effective use of the fracturing resources and, thus, to the overall economics of the well. [0050] In certain embodiments, the wellsite system 10 may include one or more control centers 96, each having a controller 98 (e.g., a processing device, a computer, a programmable logic controller (PLC), etc.), which may be configured to monitor and provide control to one or more portions of the wellsite system 10. The controller(s) 98 may monitor and control corresponding equipment of the treatment fluid system, the pump-down system (e.g., the pump unit 84), the plug and perf system (e.g., the conveyance device 76, the tool string 72), and the IS21.4273-WO-PCT flow control valve system (e.g., the fracturing manifold 60, the fluid flow control devices 66, 68). In certain embodiments, the controller(s) 98 may be communicatively connected to the various wellsite equipment described herein, and perhaps other equipment, and may be configured to receive sensor signals from and transmit control signals to such equipment to facilitate automated or semi-automated operations described herein. For example, the controller(s) 98 may be communicatively connected to and configured to monitor and control one or more portions of the mixing units 20, 32, the pump units 46, 84, the common manifold 40, the fracturing manifold 60, the fluid flow control devices 66, 68, the injection device 80, the conveyance device 76, and/or various other wellsite equipment (not shown). The controller(s) 98 may store control commands, operational parameters and set-points, coded instructions, executable programs, and other data or information, including for implementing one or more aspects of the operations described herein. Communication between the control center(s) 96 (and the controller(s) 98) and the various wellsite equipment of the wellsite system 10 may be implemented via wired and/or wireless communication means. For clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure. [0051] A field engineer, equipment operator, or field operator 100 (collectively referred to hereinafter as a “wellsite operator”) may operate one or more components, portions, or systems of the wellsite equipment and/or perform maintenance or repair on the wellsite equipment. For example, the wellsite operator 100 may assemble the wellsite system 10, operate the wellsite equipment (e.g., via a controller 98) to perform the stimulation operations, check equipment operating parameters, and repair or replace malfunctioning or inoperable wellsite equipment, IS21.4273-WO-PCT among other operational, maintenance, and repair tasks, collectively referred to hereinafter as wellsite operations. The wellsite operator 100 may perform wellsite operations by himself or with other wellsite operators. [0052] In certain embodiments, the controller(s) 98 may be communicatively connected to one or more human-machine interface (HMI) devices, which may be utilized by the wellsite operator(s) 100 for entering or otherwise communicating the control commands to the controller(s) 98, and for displaying or otherwise communicating information from the controller(s) 98 to the wellsite operator(s) 100. In certain embodiments, the HMI devices may include one or more input devices 102 (e.g., a keyboard, a mouse, a joystick, a touchscreen, etc.) and one or more output devices 104 (e.g., a video monitor, a printer, audio speakers, etc.). In certain embodiments, the HMI devices may also include a mobile communication device(s) 106 (e.g., a smart phone). [0053] In certain embodiments, one or more of the containers 24, 34, 86, the mixing units 20, 32, the pump units 46, 84, the fracturing manifold 60, the conveyance device 76, and the control center(s) 96 may each be disposed on corresponding trucks, trailers, and/or other mobile carriers 108, 110, 112, 114, 116, 118, 120, 122, 124, 126, respectively, such as may permit their transportation to the wellsite 14. However, in certain embodiments, one or more of the containers 24, 34, 86, the mixing units 20, 32, the pump units 46, 84, the fracturing manifold 60, the conveyance device 76, and the control center(s) 96 may each be skidded or otherwise stationary, and/or may be temporarily or permanently installed at the wellsite 14. In certain embodiments, the common manifold 40 and/or other equipment described herein or otherwise forming a portion of the wellsite system 10 may similarly be mobile, skidded, or otherwise installed at the wellsite 14. IS21.4273-WO-PCT [0054] FIG.2 is a schematic view of a portion of an example implementation of the wellsite system 10 shown in FIG.1. As illustrated, the wellsite system 10 includes one of the wellbores 12 extending from the surface of the wellsite 14 into the formation 16. In certain embodiments, the wellbore 12 may be capped by the wellhead 70 terminating the wellbore 12 at the surface of the wellsite 14. In certain embodiments, the fluid flow control devices 66, 68 may be mounted on top of the wellhead 70. In certain embodiments, the fluid flow control device 66 may be fluidly connected to the fracturing manifold 60 via a corresponding conduit 62. In certain embodiments, the fluid flow control device 68 may be fluidly connected to the pump unit 84 via a corresponding conduit 94. In certain embodiments, each fluid flow control device 66, 68 may include a plurality of manually and/or remotely (e.g., electrically, pneumatically, hydraulically) operated (i.e., actuated) fluid flow control valves, each configured to selectively open and close selected tubulars or pipes, such as the casing 18 extending within the wellbore 12, to a corresponding fluid conduit 62, 94. For example, the fluid flow control device 66 may include a remotely operated fluid flow control valve 128 (e.g., a wing valve) remotely configured to fluidly connect the conduit 62 to the wellbore 12 and, thus, fluidly connect the fracturing manifold 60 to the wellbore 12. In certain embodiments, the fluid flow control device 66 may further include a remotely operated access valve 130 (e.g., swab valve) remotely configured to open top of the fluid flow control device 66 to permit vertical access to the wellbore 12 by a tool string 72. In certain embodiments, the fluid flow control device 68 may include a remotely operated fluid flow control valve 132 (e.g., wing valve) remotely configured to fluidly connect the conduit 94 to the wellbore 12 and, thus, fluidly connect the pump unit 84 to the wellbore 12. [0055] In certain embodiments, the tool string 72 may be conveyed through the wellbore 12 via a conveyance line 74 operably coupled with a winch conveyance device 76. In certain IS21.4273-WO-PCT embodiments, the conveyance line 74 may be operably connected to the conveyance device 76 that is configured to apply an adjustable tension to the tool string 72 via the conveyance line 74 to convey the tool string 72 through the wellbore 12. In certain embodiments, the conveyance device 76 may be or include a winch conveyance system including a reel or drum 78 storing thereon a wound length of the conveyance line 74. In certain embodiments, the drum 78 may be rotated by a rotary actuator 134 (e.g., an electric motor, a hydraulic motor, etc.) to selectively unwind and wind the conveyance line 74 to apply an adjustable tensile force to the tool string 72 to selectively convey the tool string 72 along the wellbore 12. In certain embodiments, the conveyance device 76 may be carried by a truck, trailer, or another vehicle 136. [0056] In certain embodiments, the pump unit 84 may be configured to inject a fluid (e.g., water) into each wellbore 12 via the conduits 94 to perform pump-down operations to convey the tool string 72 to an intended depth along the wellbore 12. The pump-down operations may be utilized to move the tool string 72 along the wellbore 12 to facilitate the plug and perf operations. As described herein, the tool string 72 may be conveyed through the wellbore 12 to fluidly isolate an upper portion of the wellbore 12 extending through an upper formation zone that has not yet been perforated from a lower portion of the wellbore 12 extending through a lower formation zone that has already been perforated, and then perforate the upper formation zone. [0057] In certain embodiments, the conveyance device 76 may include a controller 138 communicatively connected to the winch conveyance device 76 and the tool string 72, such as may permit the controller 138 to receive sensor signals from and transmit control signals to such equipment to convey the tool string 72 downhole and perform various downhole operations described herein. In certain embodiments, the controller 138 may be electrically or otherwise communicatively connected to the rotary actuator 134 of the drum 78 to selectively unwind and IS21.4273-WO-PCT wind the conveyance line 74 to apply an adjustable tensile force to the tool string 72 to selectively convey the tool string 72 into and out of the wellbore 12. In certain embodiments, the controller 138 may be electrically or otherwise communicatively connected to the tool string 72 via a conductor 140 extending through at least a portion of the tool string 72, through the conveyance line 74, and externally from the conveyance line 74 at the wellsite surface 142 via a rotatable joint or coupling (e.g., a collector) carried by the drum 78. In certain embodiments, the conductor 140 may transmit and/or receive electrical power, data, and/or control signals between the controller 138 and one or more portions of the tool string 72. In certain embodiments, the controller 138 may be communicatively connected to the tool string 72 and/or various portions thereof, such as various sensors and actuators of the tool string 72, via the conductor 140 to facilitate monitoring and/or control operations of the tool string 72. [0058] The controller 138 may be communicatively connected to one or more HMI devices, which may be utilized by a wellsite operator 100 (e.g., tool string operator, winch conveyance system operator) for entering or otherwise communicating control commands to the controller 138, and for displaying or otherwise communicating information from the controller 138 to the wellsite operator 100. The HMI devices may include one or more input devices 102 and one or more output devices 104. The HMI devices may also include a mobile communication device 106 carried by the wellsite operator 100. [0059] In certain embodiments, the tool string 72 may be deployed into or retrieved from the wellbore 12 through the fluid flow control devices 66, 68, the access valve 130, and a sealing and alignment assembly 82 mounted above the access valve 130 and configured to seal the conveyance line 74 during deployment, conveyance, intervention, and other wellsite operations performed by the tool string 72. In certain embodiments, the sealing and alignment assembly 82 IS21.4273-WO-PCT may include a lock chamber 144 (e.g., a lubricator, an airlock, a riser) mounted above the access valve 130, a stuffing box 146 configured to seal around the conveyance line 74 at the top of the lock chamber 144, and an injection device 80 (i.e., a pulley) configured to guide the conveyance line 74 into the stuffing box 146. In certain embodiments, a guide pulley 148 may guide the conveyance line 74 between the injection device 80 and the conveyance device 76. In certain embodiments, the stuffing box 146 may be configured to seal around an outer surface of the conveyance line 74, such as via annular packings applied around the surface of the conveyance line 74 and/or by injecting a fluid between the outer surface of the conveyance line 74 and an inner wall of the stuffing box 146. [0060] In certain embodiments, the conveyance line 74 may be or include a flexible conveyance line, such as a wire, a cable, a wireline, a slickline, a multiline, an e-line, and/or other conveyance means. In certain embodiments, the conveyance line 74 may include one or more metal support wires or cables configured to support the weight of the downhole tool string 72. In certain embodiments, the conveyance line 74 may also include one or more electrical and/or optical conductors 140 configured to transmit electrical energy (i.e., electrical power) and electrical and/or optical signals (e.g., information, data) therethrough, such as may permit the transmission of electrical energy, data, and/or control signals between the tool string 72 and the controller 138. [0061] In certain embodiments, the tool string 72 may include a cable head 150 physically and/or electrically connecting the conveyance line 74 to the tool string 72, such as may permit the tool string 72 to be suspended and conveyed through the wellbore 12 via the conveyance line 74. In certain embodiments, the cable head 150 may provide telemetry and/or power distribution to the tool string 72. The tool string 72 may include at least a portion of one or more downhole IS21.4273-WO-PCT devices, modules, subs, and/or other tools 152 configured to perform intended downhole operations. In certain embodiments, the tools 152 of the tool string 72 may include a telemetry/control tool, such as may facilitate communication between the tool string 72 and the controller 138 and/or control of one or more portions of the tool string 72. In certain embodiments, the telemetry/control tool may include a downhole controller (not shown) communicatively connected to the controller 138 via the conductor 140 and to other portions of the tool string 72. In certain embodiments, the tools 152 of the tool string 72 may further include one or more inclination and/or directional sensors, such as one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for determining the orientation and/or direction of the tool string 72 within the wellbore 12. In certain embodiments, the tools 152 of the tool string 72 may also include a depth correlation tool, such as a casing collar locator (CCL) for detecting ends of casing collars by sensing a magnetic irregularity caused by the relatively high mass of an end of a collar of the casing 18. In certain embodiments, the depth correlation tool may also or instead be or include a gamma ray (GR) tool that may be utilized for depth correlation. [0062] In certain embodiments, the tool string 72 may also include one or more perforating guns or tools 154 configured to perforate or form holes though the casing 18, the cement, and the portion of the formation 16 surrounding the wellbore 12 to prepare the well for fracturing. In certain embodiments, each perforating tool 154 may contain one or more shaped explosive charges operable to perforate the casing 18, the cement, and the formation 16 upon detonation. In certain embodiments, the tool string 72 may also include a plug 156 and a plug setting tool 158 that, when activated, sets the plug 156 at a predetermined position within the wellbore 12, such as to isolate or seal an upper portion (e.g., zone) of the wellbore 12 from a lower portion IS21.4273-WO-PCT (e.g., zone) of the wellbore 12 and, in certain embodiments, disconnects the borehole assembly (BHA) from the plug 156. The plug 156 may be permanent or retrievable, facilitating the lower portion (e.g., zone) of the wellbore 12 to be permanently or temporarily isolated or sealed from the upper portion (e.g., zone) of the wellbore 12 before perforating operations. [0063] In certain embodiments, the treatment fluid system may further include a control center 96 containing a controller 160 (e.g., a processing device, a computer, a PLC, etc.), which may be configured to monitor and provide control to one or more portions of the treatment fluid system. The controller 160 may be communicatively connected to the various equipment of the treatment fluid system and may be configured to receive sensor signals from and transmit control signals to such equipment to facilitate automated or semi-automated operations described herein. For example, the controller 160 may be communicatively connected to and configured to monitor and control one or more portions of the mixing units 20, 32, the pump units 46, the common manifold 40, and/or various other wellsite equipment (not shown). The controller 160 may store control commands, operational parameters and set-points, coded instructions, executable programs, and other data or information, including for implementing one or more aspects of the operations described herein. Communication between the control center 96 (and the controller 160) and the various equipment of the treatment fluid system may be implemented via wired and/or wireless communication means. For clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure. [0064] In certain embodiments, the controller 160 may be communicatively connected to one or more HMI devices, which may be utilized by a wellsite operator 100 (e.g., fracturing system operator) for entering or otherwise communicating control commands to the controller 160, and IS21.4273-WO-PCT for displaying or otherwise communicating information from the controller 160 to the wellsite operator 100. In certain embodiments, the HMI devices may include one or more input devices 102 and one or more output devices 104. In addition, in certain embodiments, the HMI devices may also include a mobile communication device 106 carried by the wellsite operator 100. [0065] In certain embodiments, the pump-down system may further include a controller 162 (e.g., a processing device, a computer, a PLC, etc.) disposed in association with the pump unit 84 and/or fluid container 86. The controller 162 may be configured to monitor and provide control to one or more portions of the pump-down system. The controller 162 may be communicatively connected to the various equipment of the pump-down system and may be configured to receive sensor signals from and transmit control signals to such equipment to facilitate automated or semi-automated operations described herein. For example, the controller 162 may be communicatively connected to and configured to monitor and control one or more portions of the pump unit 84, the fluid container 86, and/or various other wellsite equipment (not shown). The controller 162 may store control commands, operational parameters and set-points, coded instructions, executable programs, and other data or information, including for implementing one or more aspects of the operations described herein. Communication between the controller 162 and the equipment of the pump-down system may be implemented via wired and/or wireless communication means. For clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure. [0066] In certain embodiments, the controller 162 may be communicatively connected to one or more HMI devices, which may be utilized by a wellsite operator 100 (e.g., pump-down operator) for entering or otherwise communicating control commands to the controller 162, and IS21.4273-WO-PCT for displaying or otherwise communicating information from the controller 162 to the wellsite operator 100. In certain embodiments, the HMI devices may include one or more input devices 102 and one or more output devices 104. In addition, in certain embodiments, the HMI devices may also include a mobile communication device 106 carried by the wellsite operator 100. [0067] In certain embodiments, the wellsite system 10 may further include a central controller 164 (e.g., a processing device, a computer, a PLC, etc.) configured to monitor and provide control to one or more portions of the wellsite system 10. The controller 164 may store control commands, operational parameters and set-points, coded instructions, executable programs, and other data or information, including for implementing one or more aspects of the operations described herein. The controller 164 may be communicatively connected to the various equipment of the wellsite system 10 and may be configured to receive sensor signals from and transmit control signals to such equipment to facilitate automated or semi-automated operations described herein. For example, in certain embodiments, the controller 164 may be communicatively connected to the controller 138 and configured to monitor and control one or more portions of the plug and perf system (e.g., the conveyance device 76, the tool string 72) via the controller 138. In addition, in certain embodiments, the controller 164 may be further communicatively connected to the controller 160 and configured to monitor and control one or more portions of the treatment fluid system (e.g., the mixing units 20, 32, the pump units 46) via the controller 160. In addition, in certain embodiments, the controller 164 may be further communicatively connected to the controller 162 and configured to monitor and control one or more portions of the pump-down system (e.g., the pump unit 84, the fluid container 86) via the controller 162. In addition, in certain embodiments, the controller 164 may be further communicatively connected to the fluid flow control devices 66, 68 (e.g., the fluid flow control IS21.4273-WO-PCT valves 128, 132) and the access valve 130 associated with each wellbore 12 and the fracturing manifold 60 (e.g., fluid flow control valves 64), such as may permit the controller 164 to monitor and control the fluid flow control devices 66, 68, the access valves 130, and the fracturing manifold 60. The controller 164 may, thus, monitor and/or control injection of treatment fluid via the fluid flow control device 66 and injection of water or other fluid via the fluid flow control device 68 into one or more selected wellbores 12. [0068] Communication between the controller 164 and the controllers 138, 160, 162, the fluid flow control devices 66, 68, the access valves 130, and the fracturing manifold 60 may be implemented via wired and/or wireless communication network 166 (e.g., a local area network (LAN), a wide area network (WAN), the internet, etc.). For clarity and ease of understanding, details of such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure. [0069] In certain embodiments, the controller 164 may be communicatively connected to one or more HMI devices, which may be utilized by a wellsite operator 100 for entering or otherwise communicating control commands to the controller 164, and for displaying or otherwise communicating information from the controller 164 to the wellsite operator 100. In certain embodiments, the HMI devices may include one or more input devices 102 and one or more output devices 104. In addition, in certain embodiments, the HMI devices may also include a mobile communication device 106 carried by the wellsite operator 100. In certain embodiments, the controller 164, the HMI devices 102, 104, and the wellsite operator 100 may be located at the wellsite surface 142. For example, the controller 164 may be installed or housed in a control center (e.g., a facility, a trailer, etc.) housing one of the other controllers 138, 160, 162. IS21.4273-WO-PCT However, the controller 164, the HMI devices 102, 104, and the wellsite operator 100 may also or instead be located off-site (e.g., a data center) at a distance from the wellsite surface 142. [0070] As described herein, the central controller 164 and/or the wellsite operator 100 using the central controller 164 may monitor and provide control to one or more portions of the wellsite system 10 via direct communication with selected wellsite equipment and/or indirect communication with selected wellsite equipment via dedicated equipment controllers 138, 160, 162 for controlling such wellsite equipment. For example, during pump-down operations, after the tool string 72 is made up and positioned within a selected one of the wellbores 12 below the wellhead 70, the controller 164 and/or the wellsite operator 100 using the controller 164 may initialize operation of the pump unit 84 to pump a fluid (e.g., water) from the fluid container 86. The controller 164 and/or the wellsite operator 100 may also cause the remotely operated fluid flow control valve 132 of the fluid flow control device 68 to open to permit the fluid to be injected into the wellbore 12 containing the tool string 72. The fluid may be injected into the wellbore 12 when the tool string 72 is conveyed within a vertical portion of the wellbore 12 just below the fluid flow control device 68 or when the tool string 72 stops descending within the wellbore 12 by way of gravity. The fluid injected into the wellbore 12 may flow downhole, as indicated by arrows 168, thereby forming an increased pressure zone behind (i.e., uphole from) the tool string 72 that is greater than fluid pressure in front of (i.e., downhole from) the tool string 72. Such pressure differential may push or otherwise impart a downhole-directed force operable to move the tool string 72 in the downhole direction. The fluid flowing downhole 168 may also or instead cause friction or drag while the fluid flows around or past the tool string 72, as indicated by arrows 170. The friction may drag or otherwise impart a downhole-directed force operable to move the tool string 72 in the downhole direction. During the pump-down IS21.4273-WO-PCT operations, the fluid passing 170 the tool string 72 may escape from the wellbore 12 into the formation 16 in front of the tool string 72 via previously made perforations 172, as indicated by arrows 174, thereby permitting the fluid pumped into the wellbore 12 to continually flow around or past the tool string 72 until the tool string 72 is conveyed to an intended depth within the wellbore 12. [0071] In certain embodiments, while the fluid is being injected into the wellbore 12 by the fluid pump unit 84 during the pump-down operations, the controller 164 and/or the wellsite operator 100 may operate the conveyance device 76 to selectively rotate the drum 78 to unwind the conveyance line 74 to permit the pumped fluid to move the tool string 72 downward along the wellbore 12 at an intended speed and to an intended depth. In certain embodiments, after the tool string reaches the intended depth, the controller 164 and/or the wellsite operator 100 may shut off the pump unit 84 and close the fluid flow control valve 132. [0072] In certain embodiments, while the fluid is being injected into the wellbore 12 by the fluid pump unit 84 during the pump-down operations, the controller 164 and/or the wellsite operator 100 may also operate the treatment fluid system to mix and pump the treatment fluid, open the fluid flow control valve 128 of the fluid flow control device 66, and operate a corresponding fluid flow control valve 64 of the fracturing manifold 60 of one or more of the other wellbores 12 not undergoing the pump-down operations to direct the treatment fluid therein. [0073] In certain embodiments, after the plug and perf operations of the wellbore 12 are complete, the controller 164 and/or the wellsite operator 100 may operate the conveyance device 76 to pull the tool string 72 out of the wellbore 12 through the fluid flow control devices 66, 68 IS21.4273-WO-PCT and close the access valve 130. Thereafter, the controller 164 and/or the wellsite operator 100 may operate the treatment fluid system to mix and pump the treatment fluid, open the fluid flow control valve 128 of the fluid flow control device 66, and operate a corresponding fluid flow control valve 64 of the fracturing manifold 60 to direct the treatment fluid into the newly perforated wellbore 12. [0074] FIG.3 is a schematic view of at least a portion of a processing device 176 (or system) that may be or form at least a portion of one or more processing devices, equipment controllers, and/or other electronic devices shown in one or more of the FIGS.1 and 2. Accordingly, the following description refers to FIGS.1-3, collectively. One or more of the processing devices 176 may be used to perform the data processing and control described in greater detail herein. [0075] In certain embodiments, the processing device 176 may be or include, for example, one or more processors, controllers, special-purpose computing devices, personal computers (PCs, e.g., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, industrial PCs (IPCs), PLCs, servers, internet appliances, and/or other types of computing devices. In certain embodiments, the processing device 176 may be or form at least a portion of the controllers 98, 138, 160, 162, 164 shown in FIGS.1 and 2 and/or local controllers associated with one or more instances of the wellsite equipment shown in FIGS.1 and 2. Although it is possible that the entirety of the processing device 176 is implemented within one device, it is also contemplated that one or more components or functions of the processing device 176 may be implemented across multiple devices, some or an entirety of which may be at the wellsite and/or remote from the wellsite. IS21.4273-WO-PCT [0076] The processing device 176 may include a processor 178, such as a general-purpose programmable processor. The processor 178 may include a local memory 180, and may execute machine-readable and executable program code instructions 182 (i.e., computer program code) present in the local memory 180 and/or another memory device. The processor 178 may execute, among other things, the program code instructions 182 and/or other instructions and/or programs to implement the example methods, processes, and/or operations described herein. For example, the program code instructions 182, when executed by the processor 178 of the processing device 176, may cause the equipment described herein to perform example methods and/or operations described herein. The program code instructions 182, when executed by the processor 178 of the processing device 176, may also or instead cause the processor 178 to receive and process sensor data (e.g., sensor measurements), and output control commands to the wellsite equipment based at least in part on programming, predetermined set-points, and the received sensor data. [0077] The processor 178 may be, include, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based at least in part on a multi-core processor architecture, as non-limiting examples. Examples of the processor 178 include one or more INTEL microprocessors, microcontrollers from the ARM and/or PICO families of microcontrollers, and embedded soft/hard processors in one or more FPGAs. [0078] In certain embodiments, the processor 178 may be in communication with a main memory 184, such as may include a volatile memory 186 and a non-volatile memory 188, IS21.4273-WO-PCT perhaps via a bus 190 and/or other communication means. In certain embodiments, the volatile memory 186 may be, include, or be implemented by random-access memory (RAM), static RAM (SRAM), synchronous dynamic RAM (SDRAM), dynamic RAM (DRAM), RAMBUS dynamic RAM (RDRAM), and/or other types of RAM devices. In certain embodiments, the non-volatile memory 188 may be, include, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 186 and/or non-volatile memory 188. [0079] In certain embodiments, the processing device 176 may also include an interface circuit 192, which is in communication with the processor 178, such as via the bus 190. In certain embodiments, the interface circuit 192 may be, include, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. In certain embodiments, the interface circuit 192 may include a graphics driver card. In certain embodiments, the interface circuit 192 may include a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). [0080] In certain embodiments, the processing device 176 may be in communication with various sensors, video cameras, actuators, processing devices, equipment controllers, and other devices of the wellsite system 10 via the interface circuit 192. The interface circuit 192 may facilitate communications between the processing device 176 and one or more devices by utilizing one or more communication protocols, such as an Ethernet-based network protocol (e.g., ProfiNET, OPC, OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 IS21.4273-WO-PCT communication, or the like), a proprietary communication protocol, and/or another communication protocol. [0081] In certain embodiments, one or more input devices 194 may also be connected to the interface circuit 192. The input devices 194 may permit human wellsite operators 100 to enter the program code instructions 182, which may be or include control commands, operational parameters, operational thresholds, and/or other operational set-points. The program code instructions 182 may further include modeling or predictive routines, equations, algorithms, processes, applications, orchestration level programs, and/or other programs configured to perform example methods and/or operations described herein. In certain embodiments, the input devices 194 may be, include, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples. [0082] In certain embodiments, one or more output devices 196 may also be connected to the interface circuit 192. The output devices 196 may permit visualization or other sensory perception of various data, such as sensor data, status data, and/or other example data. In certain embodiments, the output devices 196 may be, include, or be implemented by video output devices (e.g., a liquid crystal display (LCD), a light-emitting diode (LED) display, a cathode-ray tube (CRT) display, a touchscreen, etc.), printers, and/or speakers, among other examples. In certain embodiments, the one or more input devices 194 and the one or more output devices 196 connected to the interface circuit 192 may, at least in part, facilitate the HMIs described herein. [0083] In certain embodiments, the processing device 176 may include a mass storage device 198 for storing data and program code instructions 182. The mass storage device 198 may be IS21.4273-WO-PCT connected to the processor 178, such as via the bus 190. In certain embodiments, the mass storage device 198 may be or include a tangible, non-transitory storage medium, such as a floppy disk drive, a hard disk drive, a compact disk (CD) drive, and/or digital versatile disk (DVD) drive, among other examples. The processing device 176 may be communicatively connected to an external storage medium 200 via the interface circuit 192. In certain embodiments, the external storage medium 200 may be or include a removable storage medium (e.g., a CD, DVD, or flash disk drive), such as may be configured to store data and program code instructions 182. [0084] As described herein, the program code instructions 182 and other data (e.g., sensor data or measurements database) may be stored in the mass storage device 198, the main memory 184, the local memory 180, and/or the removable storage medium 200. Thus, the processing device 176 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 178. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code instructions 182 (i.e., software or firmware) thereon for execution by the processor 178. The program code instructions 182 may include program instructions or computer program code that, when executed by the processor 178, may perform and/or cause performance of example methods, processes, and/or operations described herein. [0085] As described above, the embodiments described herein provide systems and methods to improve cluster efficiency and maximize multistage hydraulically fractured well productivity. Completion optimization in hydraulic fracturing operations requires understanding the interaction between simultaneously propagating multiple fractures and the distribution of fluid IS21.4273-WO-PCT and proppant among the fractures during the treatment. Diagnostic methods often reveal that propagation of fractures within a single stage is relatively uneven. Nonuniform growth is caused by a relatively complex interplay between fracture mechanics and hydrodynamics of proppant transport in the wellbore 12 and perforations 172. [0086] FIG.4 illustrates a flow diagram of an example algorithm 202 for perforation cluster efficiency optimization, which may be executed by one or more processing devices 176, as described in greater detail herein. As illustrated, in certain embodiments, input parameters relating to formation properties 204, completion design 206, pumping schedule 208, and pumped material properties 210 are used. In certain embodiments, the formation properties 204 include stress distribution along lateral, stresses and elastic moduli distributions, parameters of natural fractures (e.g., orientation, length, toughness, friction coefficient, cohesion, and so forth), and possibly their distributions along lateral. In certain embodiments, the formation properties 204 that are most important are specific to the simulated well or lateral section under consideration. In certain embodiments, the completion design 206 includes casing properties (e.g., grade, weight, inner and outer diameters, and so forth) and specification of perforation guns (e.g., phasing, shot density, diameter, chargers, and so forth) used to connect the wellbore 12 with the formation 16. In certain embodiments, the pumping schedule 208 describes a number of pumping steps including duration of each pumping step, pumping rate, fluid pumped, concentration of additives and proppant, and so forth. In certain embodiments, the material properties 210 include fluid rheological parameters, proppant mean diameter, density, erosion rate, and so forth. [0087] At the first step of the algorithm 202, perforation design software 212 is run to simulate perforation tunnel properties given parameters of perforation gun and casing (e.g., from IS21.4273-WO-PCT the completion design 206). Depending on these parameters, as well as the formation properties 204, perforation parameters 214 such as perforation diameters and penetration depths for individual perforations within clusters may be obtained. [0088] The next step of the algorithm 202 involves simulation of fracturing treatment with fracturing design software 216, which accepts the perforation parameters 214 simulated by the perforation design software 212, as well as the formation properties 204, the pumping schedule 208, and the material properties 210 as inputs. Outputs of the fracturing design software 216 may include fracture parameters 218 such as geometries of created fractures, final cumulative distributions of proppant and fluid among multiple perforation clusters within the stage, distribution of proppant within fractures, and so forth. [0089] The fracture parameters 218 (including proppant distribution) may then be exported to production simulation software 220 for fracture productivity estimation based on the formation properties 204 (e.g., permeability, porosity, natural fracture parameters, and so forth) as inputs. In certain embodiments, productivity of a particular stage or simulated hydrocarbon production 222 for a given pressure drawdown may be used as a target variable for optimization. [0090] Finally, an optimization procedure (e.g., implemented by an optimization module 224) involves simulation of a number of scenarios differing in selection of perforation guns, pumped materials, and pumping schedule. In certain embodiments, the scenarios may be ranked with respect to simulated production and altered further to achieve better productivity. The entire optimization procedure is specifically tailored to a particular well and stage of stimulation because each step of the algorithm 202 involves parameters specific for the particular stage and reservoir region stimulated. In certain embodiments, certain control commands, operational IS21.4273-WO-PCT parameters, set-points, and so forth, of the equipment of the wellsite system 10 described herein may be automatically implemented based at least in part on the optimized hydraulic fracturing job design that is determined by the optimization module 224. In addition, the optimization module 224 may also automatically adjust the completion design 206 based at least in part on the optimized hydraulic fracturing job design that is determined by the optimization module 224, such that the perforation design software 212 may, in turn, automatically update the perforation parameters 214. In addition, the optimization module 224 may also automatically adjust the pumping schedule 208 based at least in part on the optimized hydraulic fracturing job design that is determined by the optimization module 224. In addition, the optimization module 224 may also automatically adjust properties (e.g., density, viscosity, and so forth) of fluids being used based at least in part on the optimized hydraulic fracturing job design that is determined by the optimization module 224. [0091] FIG.5 illustrates a flow diagram of the fracturing design software 216 of FIG.4. Multiple factors affect the proppant transport distribution and proppant placement in the clusters, and the final decision on the best (i.e., optimal) design scenario is based on the results of two combined models: a wellbore flow simulator 226 and a hydraulic fracture simulator 228. In certain embodiments, the wellbore flow simulator 226 accepts the pumping schedule 208 at the inlet to the stimulated section of the well, the material properties 210, and the perforation parameters 214 as inputs. In addition, in certain embodiments, the hydraulic fracture simulator 228 accepts the formation properties 204 and the material properties 210 as inputs. A key feature of the wellbore flow simulator 226 is its ability to simulate uneven distribution of proppant among clusters caused by proppant grains inertia and/or slurry stratification. Further, the wellbore flow simulator 226 and the hydraulic fracture simulator 228 dynamically (e.g., in an IS21.4273-WO-PCT iterative fashion) exchange pressures 230 at the near-wellbore zones of the fractures and proppant flow rate distributions 232 among fractures during the simulation to obtain consistent distribution of pressures 230 and rates 232 satisfying physical constraints imposed by both reservoir and perforation parameters. [0092] Proppant distribution between clusters is a key parameter of interest during the primary fracturing and refracturing in relatively long horizontal wells. It is affected by various physical effects taking place between perforation clusters. FIG.6 illustrates a wellbore section 234 with multiple perforation clusters 236. A gradual decrease in flow rate towards the toe of the well may cause formation of a bank of settled proppant 238. This, in turn, may drastically change the slurry flow regime from fully suspended to sliding bed flow with a corresponding alteration of frictional pressure drop. Moreover, the proppant accumulated in the lower part of the pipe may move significantly slower than the average flow. As such, certain sub-optimal scenarios may arise including, but not limited to proppant missing perforations 240, upstream clusters receiving lower concentration of proppant 242, and downward perforations 172 in a downstream cluster 236 receiving more proppant than upstream ones 244. Proppant lag relative to fluid in the wellbore 12 may be important in simulation of refracturing in long laterals. [0093] Another important characteristic of proppant transport in wellbores 12 during fracturing is the proppant transport efficiency (PTE), which is defined as a ratio of volumetric proppant flow rate going into a perforation 172 or perforation cluster 236 to the rate of proppant in the well immediately upstream of the perforations 172. The dynamics of transport in a well may cause uneven distribution of proppant between clusters 236, under-stimulated reservoir zones, and suboptimal completion performance. IS21.4273-WO-PCT [0094] In certain embodiments, a numerical model may simulate the transient proppant slurry flow in the wellbore 12, considering proppant transport and settling including bed formation 238, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport through perforations 172. In certain embodiments, a model may be numerically coupled to an advanced hydraulic fracture simulator that models fracture growth, fluid flow, proppant transport inside complex hydraulic fracture networks, and mechanical interaction between adjacent hydraulic fractures. In certain embodiments, the coupled model enables comprehensive simulations and captures the mutual influence of the transport of proppant in the wellbore 12 and the propagation of fractures. [0095] FIG.7 illustrates certain changes in the fracturing design software 216 to account for results from the wellbore flow simulator 226. As illustrated, a fracture may be propagated 246 accounting for stress shadow and interaction with a discrete fraction network (DFN), and the data structure may be updated 248. Then, coupled fluid flow and elasticity equations in the fracture network may be solved 250 using injection pressure of the fracture network, injection rate, and wellbore placement, among other feedback, received from the wellbore flow simulator 226, and may be iteratively re-solved by updating 252 the time step dt based on mass balance. Then, proppant transport may be applied 254 using updated wellbore proppant and fluid placement, among other feedback, received from the wellbore flow simulator 226, width profiles may be updated 256, updated schedules and output checks may be provided 258, and the process may be iterated 260 for a next time step. [0096] Selected results of a sensitivity study demonstrate effects of various single parameters on proppant distribution among clusters 236. The simulations have been performed for relatively simple pumping schedules 208 involving single carrier fluid and single proppant to avoid IS21.4273-WO-PCT interference of multiple effects altering slurry and proppant allocation. At the same time, many factors can affect the proppant distribution between clusters 236. Moreover, the effects of different parameters on distribution uniformity are of opposite direction. For more complex (field) cases, it is important to understand the effect of all parameters on the proppant (and fluid) distribution, and depending on the desired goal, create the appropriate design case. [0097] As an example, a case was investigated involving slick water, linear, and cross-linked gels and three proppants at different stages of pumping schedule (e.g., less viscous fluid and smaller proppant pumped at the beginning, and more viscous fluids carrying larger proppant after that). Considering the relative complexity of the treatment design, multiple options for the perforation design were tested to achieve the most uniform distribution of the proppant between clusters 236. FIG.8 illustrates the results for cases with different number of perforations 172 per cluster 236. The base case with 8 perforations per each of 4 clusters (8–8–8–8, shown in green) shows the notably skewed final proppant distribution with more proppant towards the heel and less proppant towards the toe. As illustrated, the best design was achieved for 5-6-7-7 (from the heel to the toe) perforations 172 per clusters 236 (shown in orange) with nearly uniform (close to 0.25) proppant distribution. [0098] A simulation is setup to investigate the behavior of the model in the case when the fractures experience a screenout event. The resulting fracture footprint, fractures length, and total mass of proppant received by different clusters 236 are illustrated in FIGS.9 and 10. The proppant distribution observed in this case (FIG.10) is caused by the combination of phenomena related to proppant transport in the wellbore12 and the fractures. IS21.4273-WO-PCT [0099] A reservoir simulation study was also conducted to illustrate the effect of non- uniform distribution of proppant on the hydrocarbon production rate. Two hydraulic fracturing simulations were run for the comparison. The first hydraulic fracturing simulation included physical effects leading to uneven distribution of proppant among clusters 236. The simulation was tuned using leak-off rate to achieve screenout and investigate the extreme case of distribution non-uniformity. In the second hydraulic fracturing simulation, proppant distribution was forced to be perfectly uniform. The same leak-off rate was used for this uniform proppant distribution case. The created hydraulic fractures were incorporated in the reservoir mesh to simulate production from the fractures. Production from a single stage was used to capture the production behavior of the two cases. FIG.11 illustrates the configuration of the simulated case for the uniform proppant distribution case. [00100] The early production rate of oil was used to compare the two cases in order to avoid boundary effects arising from the pressure front reaching the edge of the simulated reservoir region. The well was produced with a constant tubing head pressure. Because of possible pressure interference between stages of the same well and neighbor wells, longer-term simulation would require specification of the entire well completion, as well as position and fracture designs for the neighbor wells. As such, the analysis may be limited to the single stage simulation, as it is enough to illustrate the effect of proppant distribution on the production. A comparison of oil production rate is presented in FIG.12. [00101] It is observed that the initial production is lower in the case of non-uniform proppant distribution compared to the synthetic perfectly uniform case. This result illustrates the fact that highly non-uniform distribution of proppant can create situations when proppant placed in the reservoir is utilized sub-optimally. Integrated simulations can help to close the optimization loop IS21.4273-WO-PCT between fracturing treatment design and ultimate hydrocarbon production with accounting for the influence of all important factors. [00102] 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. [00103] In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, for example, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words “means for” together with an associated function.