System and method for determining drill bit behavior

Abstract

A method of predicting behavior of a downhole tool implemented in a wellbore includes receiving geometric data associated with the downhole tool. The geometric data can indicate a bend angle of the downhole tool based on the tool bending at a bend point. The method also includes generating a simplified model of the downhole tool based on the geometric data, the generating the simplified model including determining an effective bend point and an effective bend angle based on a longitudinal axis of the wellbore. The method also includes receiving an operating parameter for the downhole tool, and simulating operation of the downhole tool based on applying the operating parameter to the simplified model. The method also includes determining one or more behavior characteristics of the downhole tool based on the simulation.

Description

Cross-references to related applications

[0001] This application claims priority to U.S. non-provisional application No. 18 / 426453, filed January 30, 2024, the entire contents of which are incorporated herein by reference and shall be considered a part of this specification. Background Technology

[0002] Wellbores can be drilled into surface locations or the seabed for various exploration or extraction purposes. For example, wellbores can be drilled to access fluids (such as liquid and gaseous hydrocarbons) stored in underground formations and to extract fluids from the formations. Wellbores used for producing or extracting fluids can be formed in the formations using drilling tools such as drill bits for drilling wellbores and reamers for enlarging the diameter of the wellbore.

[0003] In many cases, it may be necessary to understand and / or characterize the behavior of downhole tools in response to specific downhole operations and / or specific downhole conditions. However, downhole systems are typically very complex and nuanced, with many interacting components. Therefore, performing a detailed analysis of a downhole system by modeling and / or simulating the behavior of many or all of these components can be computationally burdensome and potentially overly complex. In some cases, it may be necessary to isolate the response of a specific downhole tool (such as a drill bit) in order to focus on the specific behavior of that component and / or to simulate operations associated with that component in a simplified and rapid manner. Therefore, systems and methods for simplifying the modeling and / or simulation of downhole operations to capture the behavior of specific downhole components may be advantageous. Summary of the Invention

[0004] In some embodiments, a method for predicting the behavior of a downhole tool implemented in a wellbore includes receiving geometric data associated with the downhole tool. The geometric data may indicate the bending angle of the downhole tool based on bending points of the tool. The method further includes generating a simplified model of the downhole tool based on the geometric data, the generation of the simplified model including determining effective bending points and effective bending angles based on the longitudinal axis of the wellbore. The method further includes receiving operating parameters for the downhole tool and simulating the operation of the downhole tool based on applying the operating parameters to the simplified model. The method further includes determining one or more behavioral characteristics of the downhole tool based on the simulation. In some embodiments, the method is performed by a system. In some embodiments, the method is performed as instructions stored on a computer-readable medium.

[0005] This summary is provided to introduce a series of concepts further described in the detailed description. The summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter. Additional features and aspects of embodiments of this disclosure will be set forth herein and will be apparent in part from the description, or may be learned by practice of such embodiments. Attached Figure Description

[0006] To describe how the above and other features of this disclosure can be obtained, a more specific description will be presented by reference to the specific embodiments of this disclosure shown in the accompanying drawings. For better understanding, the same elements have been denoted by the same reference numerals throughout the drawings. While some in the drawings may be schematic or exaggerated representations of concepts, at least some in the drawings may be drawn to scale. It should be understood that the drawings depict some exemplary embodiments, which will be described and explained in more specific and detailed manner by means of the drawings, in which: Figure 1 This is an example of a downhole system according to at least one embodiment of the present disclosure; Figure 2 An example environment in which a drill bit behavior system is implemented according to at least one embodiment of the present disclosure is shown; Figure 3 An example implementation of a drill bit behavior system as described herein, according to at least one embodiment of the present disclosure, is shown; Figure 4-1 A schematic representation of an example embodiment of a guidance system that can be used to guide downhole tools according to at least one embodiment of the present disclosure is shown; Figure 4-2 At least one embodiment of the present disclosure as described herein is shown. Figure 4-1 An example of a simplified downhole model of a guidance system; Figure 4-3 A schematic representation of an example embodiment of a guidance system that can be used to guide downhole tools according to at least one embodiment of the present disclosure is shown; Figure 4-4 At least one embodiment of the present disclosure as described herein is shown. Figure 4-3 An example of a simplified downhole model of a guidance system; Figure 5 An example workflow of a drill bit behavior system as described herein, according to at least one embodiment of the present disclosure, is shown; Figure 6 Examples of various features of reports generated by a drill bit behavior system as described herein, according to at least one embodiment of this disclosure; Figure 7A flowchart illustrating a method or series of actions for predicting the behavior of a downhole tool implemented in a wellbore, as described herein, according to at least one embodiment of this disclosure; and Figure 8 It shows some components that may be included within a computing system. Detailed Implementation

[0007] This disclosure generally relates to systems and methods for determining the behavior of downhole tools associated with simulated operations of downhole tools in a wellbore. Computer-implemented bit behavior systems can receive various types of data associated with one or more downhole tools, the wellbore, the formation, and / or the operation of interest. Based on the data, the bit behavior system can determine the geometry of the downhole system. The geometry of the system may include one or more angles, lengths, positions, orientations, or other geometries associated with the geometry of a particular downhole tool. In many cases, downhole systems may be intricate, detailed, and / or complex, and it may not be necessary to analyze and / or characterize one or more behaviors, responses, movements, or other characteristics of each component of the downhole system. For example, in cases where there is interest in the response of the drill bit, it may be desirable to model the behavior of the drill bit without determining the responses of one or more additional components. In some embodiments, the bit behavior system determines a simplified downhole model to focus on the response of a particular downhole tool, such as a drill bit. The bit behavior system can determine a simplified geometry of the downhole tool that may align one or more lengths, angles, positions, etc., with the longitudinal axis of the wellbore. A drill bit behavior system can apply operating parameters to simulate the operation of downhole tools, such as weight on bit, surface RPM, motor RPM, other operating parameters, or combinations thereof. These operating parameters can be applied to a simplified model, and in this way, the drill bit behavior system can isolate the behavior of the drill bit without considering the response of one or more additional downhole components.

[0008] A drill bit behavior system can simulate specific downhole conditions, formation characteristics, operating parameters, drill bit characteristics, other downhole parameters, or combinations thereof for a specific downhole operation to determine various behavioral characteristics of the drill bit in response to the simulated operation. For example, a drill bit behavior system can determine one or more behavioral characteristics related to the drill bit's durability, steerability, stability, or efficiency. In this way, a drill bit behavior system can help understand how a particular downhole tool responds in a given downhole operation and / or provide valuable behavioral characteristics of the drill bit without considering the complexity of the entire large downhole system.

[0009] As will be discussed in further detail below, this disclosure includes numerous practical applications with the features described herein that provide benefits and / or solve problems associated with simulating the behavior of downhole tools. This document discusses some exemplary benefits in conjunction with various features and functionalities provided by drill bit behavior systems implemented on one or more computing devices. It should be understood that the benefits explicitly discussed in conjunction with one or more embodiments described herein are provided by way of example and are not intended to exhaustively list all possible benefits of drill bit behavior systems.

[0010] For example, as described herein, downhole systems are often complex and sophisticated systems and may include numerous components that perform various functions of downhole operations. As an illustrative example, simulating a complete and / or accurate representation of a downhole system may include modeling the components of the downhole system, including various parts of the drill string, drive / steering systems, numerous downhole tools, the drilling rig, and other components. These components may interact with each other and / or with the wellbore in unique ways. Such simulations may take into account loads on each component, including dynamic or varying loads on each component, as well as the inertial movement of the components. Drive systems such as rotary steering systems or bending downhole motors can actively influence one or more of the orientation, rotation, orientation, other spatial or other parameters, or combinations thereof, of various components. In this way, achieving a high level of completeness in simulating a downhole system can be difficult and, where possible, can result in slow and costly computations. Furthermore, among the many factors at play in complex simulations, it may be difficult to characterize and / or understand the behavior of specific downhole tools and their behavior in response to specific applied parameters.

[0011] The drill bit behavior system disclosed herein simplifies the modeling of downhole systems to isolate the behavior of specific downhole tools. For example, by simplifying the geometry of the downhole steering system to represent the downhole tool as having an effective bend angle at its effective bend point relative to the longitudinal axis of the wellbore (e.g., on the longitudinal axis of the wellbore), operating parameters of interest can be applied to (or near) the effective bend point of the downhole tool to understand how the drill bit specifically responds to these parameters. This can help isolate specific drill bit behaviors under given simulation conditions and in response to specific (e.g., steering) parameters applied to the drill bit, which might be difficult to achieve in more complex models where drill bit behavior may be mixed with and / or influenced by the behavior of various other components. In this way, the simplified model can help understand how the drill bit itself will respond and / or behave due to steering / drive effects, unaffected by the influences that other downhole components may have on the drill bit. This simplified modeling performed by the drill bit behavior system can additionally lead to simpler computations, which can provide the added benefits of performing simulations faster, more efficiently, and at a lower cost.

[0012] Additional details about the system described herein will now be provided with reference to the illustrative drawings illustrating exemplary embodiments. For example, Figure 1 An example of a downhole system 100 for drilling into surface formation 101 to form a wellbore 102 is shown. The downhole system 100 includes a drilling rig 103 for rotating a drilling tool assembly 104 extending downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottom hole assembly (“BHA”) 106, and a drill bit 110 attached to the downhole end of the drill string 105.

[0013] The drill string 105 may include several joints of the drill pipe 108 connected end-to-end via a tool joint 109. The drill string 105 transmits drilling fluid through a center bore and transmits rotational power from the drilling rig 103 to the BHA 106. In some embodiments, the drill string 105 may also include additional downhole drilling tools and / or components, such as sub-sections, shortings, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid exits through nozzles, orifices, or other openings of selected size in the drill bit 110 to cool the drill bit 110 and its cutting structures, and to transport drill cuttings out of the wellbore when the wellbore 102 is drilled.

[0014] BHA 106 may include drill bit 110, other downhole drilling tools, or other components. Example BHA 106 may include additional or other downhole drilling tools or components (e.g., connected between drill string 105 and drill bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, downhole reamers, casing shoes, hydraulic disconnect joints, slappers, vibration or damping tools, other components, or combinations of the foregoing.

[0015] Generally, downhole system 100 may include other downhole drilling tools, components, and accessories, such as specialized valves (e.g., kerb plugs, blowout preventers, and safety valves). Additional components included in downhole system 100 may be considered part of drilling tool assembly 104, drill string 105, or BHA 106, depending on their location within downhole system 100.

[0016] Drill bit 110 in BHA 106 can be any type of drill bit suitable for degrading downhole materials. For example, drill bit 110 can be a drill bit suitable for drilling into surface formation 101. Example drill bit types for drilling into surface formations are fixed-cutting or scraper bits. In other embodiments, drill bit 110 can be a milling shoe for removing metal, composite materials, elastomers, other downhole materials, or combinations thereof. For example, drill bit 110 can be used with a directional drilling tool to mill into casing 107 fitted onto wellbore 102. Drill bit 110 can also be a flat-end milling shoe for milling away tools, plugs, cement, other materials, or combinations thereof within wellbore 102. Cuttings or other rock debris generated by using the milling shoe can be lifted to the surface 111 or allowed to fall downhole. Drill bit 110 may include one or more cutting elements for degrading surface formation 101.

[0017] BHA 106 may also include components for guiding or directing the trajectory of drill bit 110. For example, BHA 106 may include a rotary steering system (RSS) and / or a directional downhole motor. Based on the mechanisms of these steering systems, BHA 106 can be guided underground to reach, bypass, and / or travel relative to one or more downhole targets. In many cases, simulating, quantifying, and conceptualizing the behavior of drill bit 110 (e.g., individually) in response to the guidance of the steering system may be advantageous. In some embodiments, downhole system 100 includes one or more client devices 112 or is associated with one or more client devices, on which a drill bit behavior system 120 is implemented (e.g., implemented on one, several, or across multiple client devices 112). The drill bit behavior system 120 can help simulate and determine the behavioral characteristics of one or more downhole tools (e.g., drill bit 110).

[0018] Figure 2 An example environment 200 in which a drill bit behavior system 120 is implemented, according to one or more embodiments described herein, is shown. Figure 2 As shown, environment 200 includes one or more server units 114. Server units 114 may include one or more computing devices (e.g., including processing units, data storage, etc.) organized in an architecture with various network interfaces for connecting to one or more client systems and providing data management and distribution across those client systems. Figure 2As shown, server device 114 can be connected to one or more client devices 112 via network 116 and can communicate with said one or more client devices (directly or indirectly). Network 116 may include one or more networks and may use one or more communication platforms and / or technologies suitable for transmitting data. Network 116 may refer to any data link that enables the transmission of electronic data between devices in environment 200. Network 116 may refer to a hardwired network, a wireless network, or a combination of a hardwired network and a wireless network. In one or more embodiments, network 116 includes the Internet. Network 116 may be configured to facilitate communication between various computing devices via Wellfield Information Transfer Standard Markup Language (WITSML) or similar protocols, or any other protocol or form of communication.

[0019] Client device 112 can refer to various types of computing devices. For example, one or more client devices 112 may include mobile devices such as mobile phones, smartphones, personal digital assistants (PDAs), tablet computers, laptop computers, or any other portable devices. Alternatively or additionally, client device 112 may include one or more non-mobile devices such as desktop computers, server devices, surface or downhole processors or computers (e.g., associated with sensors, systems, or functions of a downhole system), or other non-portable devices. In one or more embodiments, client device 112 includes a graphical user interface (GUI) (e.g., the screen of a mobile device) thereon. Alternatively or additionally, one or more of client devices 112 may be communicatively coupled (e.g., wired or wireless) to a display device thereon having a graphical user interface for providing the display of system content. Server device 114 can similarly refer to various types of computing devices. Each device in the apparatus of environment 200 may include, as described below... Figure 8 The described features and / or functions.

[0020] like Figure 2 As shown, environment 200 may include a drill behavior system 120 implemented on one or more computing devices. The drill behavior system 120 may be implemented on one or more client devices 112, server devices 114, and combinations thereof. Alternatively, the drill behavior system 120 may be implemented across client devices 112 and / or server devices 114, such that different portions or components of the drill behavior system 120 are implemented on different computing devices within environment 200. In this way, environment 200 may be a cloud computing environment, and the drill behavior system 120 may be implemented across one or more devices within the cloud computing environment to leverage the processing power, memory capacity, connectivity, speed, etc., provided by such cloud computing environments to facilitate the features and functions described herein.

[0021] Figure 3 An example embodiment of a drill bit behavior system 120 as described herein, according to at least one embodiment of the present disclosure, is shown. The drill bit behavior system 120 may include a data manager 122, a model engine 126 for generating a simplified downhole model 124, and a simulation engine 128. The drill bit behavior system 120 may also include a data storage device 130 storing downhole tool data 132, operating parameter data 134, drill bit behavior characteristics 136, and formation data 138. While one or more embodiments described herein describe features and functions performed by specific components 122-128 of the drill bit behavior system 120, it should be understood that specific features described in conjunction with one component of the drill bit behavior system 120 may, in some examples, be performed by one or more other components of the drill bit behavior system 120.

[0022] By way of example, one or more of the data receiving, collecting, or storing features of data manager 122 may be delegated to other components of drill bit behavior system 120. As another example, while a simplified downhole model 124 may be generated by model engine 126, in some cases, some or all of these features may be performed by simulation engine 128 (or other components of drill bit behavior system 120). Indeed, it should be understood that some or all of a particular component may be combined with other components, and a particular function may be performed by one of components 122-128 of drill bit behavior system 120 or by multiple components across that component.

[0023] In addition, although Figure 1 For example, a drill bit behavior system 120 implemented on a client device 112 of a downhole system is depicted; however, it should be understood that some or all of the features and functions of the drill bit behavior system 120 may be implemented on multiple client devices 112 and / or server devices 114 or across these multiple client devices and / or server devices. For example, data may be input and / or received by a data manager 122 on a (e.g., local) client device, while a simplified downhole model 124 may be generated and / or simulated on one or more remote devices, server devices, or cloud devices. Indeed, it should be understood that some or all of specific components 122–128 may be implemented on multiple client devices 112 and / or server devices 114 or across these multiple client devices and / or server devices, including individual functions of specific components performed across multiple devices.

[0024] As mentioned above, the drill bit behavior system 120 includes a data manager 122. The data manager 122 can receive various types of data associated with the downhole system and store the data in a data storage device 130. The data manager 122 can receive data from various sources, such as sensors, exploration tools, downhole tools, other (e.g., client) devices, user input, etc.

[0025] In some implementations, data manager 122 receives downhole tool data 132. Downhole tool data 132 may include information associated with drilling tool assemblies of the downhole system. For example, downhole tool data 132 may identify components and configurations of drilling tool assemblies, such as the number of drill pipes, or the components and composition of the BHA.

[0026] In some implementations, downhole tool data 132 includes drill bit data, or information associated with downhole tools (such as drill bits) in the drilling tool assembly. Drill bit data may indicate the type of drill bit and may identify the shape or geometry of the drill bit. Drill bit data may include information associated with one or more cutting elements of the drill bit, such as their location, orientation, type, shape, size, geometry, wear condition, other information, or combinations thereof. Drill bit data may indicate the material composition or structure of the drill bit and / or cutting elements.

[0027] In some implementations, downhole tool data 132 includes information associated with the guidance system of the drilling tool assembly. For example, downhole tool data 132 may indicate the type of guidance assembly, such as an RSS or directional downhole motor guidance system. Downhole tool data 132 may identify components of the guidance system, such as stabilizers, subs (e.g., flexible subs and / or bent subs), actuators, bearings, bent housings, blades, gaskets, or any other components, and their locations. Downhole tool data 132 may indicate the operation and / or function of the guidance system. For example, downhole tool data 132 may indicate the bias direction and / or guidance direction of the guidance system. Downhole tool data 132 may indicate the orientation and / or orientation (e.g., tool face orientation) of one or more components, such as the orientation of bent or flexible subs, the orientation of the drill bit, etc. Downhole tool data 132 may indicate the azimuth and / or dip angle of the drill string at one or more locations and / or measurement depths.

[0028] In some implementations, downhole tool data 132 includes information associated with (e.g., local) geometry of the BHA and / or steering system. For example, the RSS may operate based on a portion of the curved BHA (e.g., utilizing one or more stabilizers as fulcrums) to achieve a change of direction at the drill bit. Downhole tool data 132 may include information that can identify or help determine the geometry of one or more portions and / or components of the steering system and / or BHA to facilitate modeling and / or simplification of the characteristics of the drill bit behavior system 120 described herein. In another example, a directional downhole motor steering system may operate based on the ability of the motor housing to be actuate to bend and / or angle to guide the drill bit in the corresponding direction. Therefore, downhole tool data 132 may accordingly include information that can identify or help determine the relevant geometry (e.g., geometric data).

[0029] In some embodiments, downhole tool data 132 includes information associated with the wellbore (e.g., planned or existing). For example, downhole tool data 132 may indicate the length, depth, size, shape, trajectory, other features, or combinations thereof of the wellbore. In some embodiments, the data manager receives information data 138. Formation data 138 may include information associated with the formation in which the downhole tool will pass through, penetrate, or otherwise locate. For example, formation data 138 may include information about the geological features of rocks that may be encountered during one or more downhole operations. For example, formation data 138 may indicate the material and / or composition of the formation, including the hardness of the formation. Formation data 138 may indicate one or more layers and / or boundaries of the formation, including the orientation and / or dip of the layers. Formation data 138 may indicate the presence of different particles and / or modules dispersed throughout the formation (e.g., layers), including the material and / or hardness of the particles. Formation data 138 may indicate the presence of pores and / or cavities dispersed throughout the formation. Formation data 138 may indicate the degree of homogeneity and / or uniformity of the formation (e.g., with respect to grains and / or cavities). Formation data 138 may include data from gamma-ray sensors, resistivity sensors, porosity sensors, density sensors, acoustic sensors, calipers, core samples, any other formation data, or combinations thereof.

[0030] Data manager 122 can store any information associated with downhole tools and / or drilling tool components in data storage device 130 as downhole tool data 132.

[0031] In some implementations, data manager 122 receives user input. Data manager 122 may receive user input, for example, via either client device 112 and / or server device 114. Any data described herein may be entered or supplemented via user input. For example, in some cases, some or all of the downhole tool data 132 is received by data manager 122 as user input. User input may be received in association with one or more functions or features of drill bit behavior system 120, such as generating a portion of simplified downhole model 124, or any other feature described herein.

[0032] In some implementations, data manager 122 receives operational parameter data 134. Operational parameter data 134 can be any information associated with actual, planned, simulated, or otherwise operational or functional changes of the downhole system. For example, operational parameter data 134 can be associated with drilling operations of the downhole system. Operational parameter data 134 can be associated with directional operations of the downhole system. Operational parameter data 134 can be associated with any other operation of the downhole system, such as the delivery or tripping of one or more downhole tools.

[0033] Operational parameter data 134 may indicate one or more parameters of an associated operation. For example, operational parameter data 134 may indicate the weight on bit (WOB) and / or rate of penetration (ROP) of the downhole tool. Operational parameter data 134 may indicate the rotational speed (revolutions per minute or RPM) of one or more components. For example, operational parameter data 134 may indicate the surface RPM provided or exhibited by surface components of the downhole system, such as the surface RPM generated due to the rotation of the drill string and / or drilling tool assemblies. Operational parameter data 134 may indicate downhole or motor RPM. Motor RPM may indicate the rotational speed of the downhole tool driven by a downhole motor. Motor RPM may be independent of surface RPM. For example, in some cases, the downhole motor may drive the rotation of the downhole tool in addition to the rotation of the drill string (e.g., the rest of the drill string) caused by surface RPM. In some cases, the downhole system may not rotate at surface RPM, and the downhole motor may drive the rotation of the downhole tool based solely on motor RPM. In this way, the rotation of downhole tools can be driven by surface RPM, motor RPM, or a combination of both.

[0034] In this way, data manager 122 receives various types of data to facilitate the techniques described herein. Data manager 122 can receive data from various sources. For example, some data can be accessed by data manager 122 in databases, records, or libraries. Data can be observed, measured, or recorded, for example, by sensors or measuring devices in the downhole system. In some embodiments, data is received from another computing device or system associated with drill bit behavior system 120. As mentioned above, some data can be received or entered as user input by the operator or administrator of drill bit behavior system 120.

[0035] In some implementations, some or all of the data is generated, determined, or created to characterize planned, hypothetical, or simulated scenarios and / or operations of the downhole system. For example, while this document has described data received and / or stored by data manager 122 in conjunction with the implementation of downhole tools and / or downhole systems in the wellbore, it should be understood that in some implementations, some or all of the data is associated with planned or simulated downhole operations. For example, the data may be associated with a downhole tool implemented in the wellbore, but its purpose may be to simulate or test one or more potential further operations of that downhole tool. In another example, the data may be purely associated with planning or simulating potential or future wellbore operations. In this way, the techniques described herein can be applied to a variety of situations and applications, including physical (existing) implementations as well as virtual, simulated, or planned implementations.

[0036] Figure 4-1 A schematic representation of an example embodiment of a guidance system 440, which can be used to guide downhole tools according to at least one embodiment of the present disclosure, is shown. The guidance system 440 may be a bit-directing guidance system, such as a guidance system that can be implemented by a directional or bending downhole motor. The guidance system 440 may be implemented in the wellbore 441 and may be part of the BHA of the downhole system. The BHA and / or guidance system 440 may be connected to one or more drill pipes to position the guidance system 440 and / or BHA in the wellbore 441, and / or apply rotation, force, etc., to downhole components, as described herein. To illustrate the various features and functions of the drill bit behavior system 120, Figure 4-1 The guidance system 440 in the middle may be depicted as having one or more exaggerated features.

[0037] The guidance system 440 can be connected to a downhole tool, such as drill bit 442. As mentioned above, in some cases, it may be necessary to change the direction or orientation of drill bit 442 in order to guide it. To achieve this, the guidance system 440 may include one or more components having a hinge or joint 443 that can be actuated to achieve bending or angulation. For example, joint 443 may be implemented as part of a downhole motor of the guidance system 440 having a hinged, bendable housing design to change the orientation of drill bit 442. Joint 443 may bend at a bend point 444 and may bend to a bend angle 445. The bend angle 445 may be the angle between the longitudinal axis of drill bit 442 and the adjacent bend portion of the BHA above joint 443. In this way, the bend angle 445 may be a measure of the degree of hinge or level of joint 443.

[0038] The guidance system 440 may include a stabilizer 446 to aid in guiding the drill bit 442. The stabilizer 446 may be a component of the guidance system 440 configured to engage the wellbore 441. For example, the stabilizer 446 may be configured to engage the wellbore 441 and maintain the relative position of the BHA within the wellbore 441, such as being located at or approximately at the center of the wellbore 441. In some embodiments, this stabilizing and / or centering function of the stabilizer 446 aids in guiding the drill bit 442 based on the articulation of the joint 443. For example, when the joint bends, the bottom or free end of the BHA (e.g., the drill bit 442) may be biased or movable toward the wall of the wellbore 441 (e.g., to the left, as shown). The drill bit 442 may engage the wall of the wellbore 441, thereby driving the joint 443 in the opposite direction (e.g., to the right, as shown).

[0039] In some implementations, stabilizer 446 engages wellbore 441 and provides opposing balancing forces to drill bit 442, allowing drill bit 442 to pivot or rotate about pivot point 451. In this way, stabilizer 446 can act as a fulcrum to guide drill bit 442 and drive it (at least to some extent) into the wall of wellbore 441.

[0040] In some implementations, the axial force, or WOB 447, is applied to the steering system 440 and / or the BHA via the drill string. WOB 447 can be a force resulting from the weight of the drilling tool assembly attached above or on the wellbore, a force applied by the surface drilling rig, or a combination of both. Because the drill bit 442 is at an angle to the centerline or longitudinal axis 450 of the wellbore 441, the axial WOB 447 can be transmitted to the drill bit, with at least some lateral component. This can cause the drill bit 442 to engage (and form) the bottom of the wellbore 441 at an angle, thereby guiding the drill bit 442.

[0041] In some embodiments, the steering system 440 is rotated by a surface RPM 448. The surface RPM 448 can be caused by surface equipment, such as a drilling rig, driving the rotation of the entire drill string. For example, the surface RPM 448 can be transmitted to the steering system 440 and / or the BHA via multiple drill pipes as described herein. In some embodiments, the drill bit 442 is rotated by a motor RPM 449. The motor RPM 449 can be the rotation of the drill bit 442 driven by a downhole motor (e.g., a mud motor) of the steering system 440. In this way, the rotation of the drill bit 442 can be driven (and / or described by) by the surface RPM 448, the motor RPM 449, or a combination of both.

[0042] As mentioned above, the drill bit behavior system 120 includes a model engine 126. In some embodiments, the model engine 126 models the guidance system 440, which includes the BHA and the drill bit 442. For example, Figure 4-1 The schematic representation shown can represent the modeling of the guidance system 440 by the model engine 126.

[0043] In some implementations, model engine 126 determines the geometry associated with guidance system 440. For example, based on downhole tool data 132, model engine 126 can determine the bend angle 445 of joint 443. Model engine 126 can identify the location of bend point 444. For example, as shown, in some cases, bend point 444 may be offset or not aligned with the axis 450 of the wellbore. This may be due to the aforementioned bend or offset characteristics of guidance system 440. Similarly, model engine 126 can identify the location of pivot point 451 of drill bit 442 about which it pivots. For example, as shown, in some cases, pivot point 451 may be offset or not aligned with the axis 450 of the wellbore. This may be because stabilizer 446 is not exactly equal to the specification or diameter of the wellbore, and when stabilizer is biased toward one side of wellbore 441, pivot point 451 may be slightly offset from axis 450 accordingly. As shown in Figure 4-5, due to this effect, there may be a gap 453 between the stabilizer 446 and the wellbore 441.

[0044] In some implementations, model engine 126 determines the bend length 454. The bend length 454 can be the length measured from the downhole end of drill bit 442 to the bend point 444. For example, the bend length 454 can be a measurement from the joint 443 of guide system 440 to the furthest downhole extension of BHA.

[0045] Model engine 126 can determine various loads, forces, or other dynamics applied to drill bit 442. For example, model engine 126 can identify WOB 447 applied to BHA from downhole tool data 132. Model engine 126 can identify surface RPM 448 and / or motor RPM 449 from downhole tool data 132. Model engine 126 can determine various lengths, angles, positions, etc., of the geometry of BHA and / or steering system 440, as well as applied forces, rotations, etc., so that model engine 126 can model or simulate the operation of the downhole system and can predict or determine the final response or behavior of drill bit 442. Model engine 126 can determine any other dynamics applied or exhibited by the downhole system, such as rate of penetration (ROP), in order to model the response of drill bit 442.

[0046] As discussed above, a downhole system may include multiple components and / or tools arranged along the entire length of a drilling tool assembly. For example, a drilling tool assembly may include multiple drill pipes, drill collars, subs, tool joints, stabilizers, drill bits and reamers, steering systems, and other components. Such a complex system of components can represent complex and dynamic systems that are difficult to model and characterize. For example, the components may all be (at least indirectly) connected, and the movement, forces, torques, stresses, etc., exhibited by one component may correspondingly affect those quantities exhibited by other components. Additionally, many components may engage the wellbore wall, which may further affect the behavior of one or more components. Furthermore, the alignment (or misalignment) of the components of the downhole system with the wellbore axis 450 can further complicate the modeling of component behavior. For example, as discussed above, the bend point 444 and pivot point 451 may be offset from the axis 450 of the wellbore 441. Therefore, the BHA, steering system 440, drill bit 442, etc., may be misaligned with the axis 450 of the wellbore 441, making it computationally more difficult to model the behavior of drill bit 442 (e.g., its behavior relative to the wellbore 441). This effect may be even more pronounced when considering that similar misalignment can propagate along many components of the drill string, as the drill string and wellbore 441 are often not perfectly straight, aligned, and perpendicular, but may frequently exhibit curved and / or arcuate geometries. Therefore, attempting to model and consider all components, details, and geometries of the downhole system to simulate drill bit behavior may be overly complex and computationally difficult and / or slow.

[0047] In some implementations, model engine 126 generates a simplified downhole model 124-1. The simplified downhole model 124-1 may include a simplified representation of one or more of drill bit 442, BHA, and / or steering system 440. For example, based on downhole tool data 132 and / or on the length, position, angle, etc., of the geometry discussed above, model engine 126 may determine an effective bend point 452. The effective bend point 452 may be a point located at the intersection of the longitudinal axis of drill bit 442 and the wellbore axis 450. In this way, the effective bend point 452 may be located at and / or aligned with axis 450. Due to the geometry of steering system 440, the effective bend point 452 may be located in the downhole direction of bend point 444.

[0048] Figure 4-2 An example of a simplified downhole model 124-1 of the guidance system 440 as described herein, according to at least one embodiment of the present disclosure, is shown. A model engine 126 can generate the simplified downhole model 124-1 to facilitate the simulation and / or characterization of the behavior of the drill bit 442. For example, the model engine 126 can determine an effective bending length 455 of the simplified downhole model 124-1. The effective bending length 455 can be measured from the end of the drill bit 442 to the effective bending point 452. Based on the fact that the effective bending point 452 is located at the wellbore axis 450, the effective bending length 455 can extend from the wellbore axis 450. For example, the effective bending length 455 can form an effective bending angle 456 with respect to the wellbore axis 450. Due to the mechanical mechanisms of the bending action of the guidance system 440 (e.g., the geometry of the guidance system 440 pivoting about a pivot point 451), the effective bending length 455 can be shorter than the bending length 454, and the effective bending angle 456 can be smaller than the bending angle 445. In some implementations, model engine 126 determines the effective bending angle 456 based on the geometry discussed above to facilitate the determination of the effective bending length 455, for example, by performing trigonometric analysis. For instance, model engine 126 can determine the offset distance 457 of the end or tip of drill bit 442 relative to the wellbore axis 450. Based on the offset distance 457 and the effective bending angle 456, model engine 126 can calculate the effective bending length 455 using trigonometric functions. In this way, the simplified downhole model 124-1 can simulate the geometry of the steering system 440 as if it were aligned and / or bent at the wellbore axis 450. For example, as... Figure 4-2 As shown, the simplified downhole model 124-1 can represent the rest of the drill string as straight or aligned with the wellbore axis 450. Therefore, the simplified downhole model 124-1 can reduce the downhole system from a complex, detailed system to a simpler system that focuses on the drill bit 442 and its relationship to the wellbore 441.

[0049] The simplified model 124-1 can facilitate modeling the behavior and / or response of drill bit 442 to one or more applied downhole stimuli. For example, one or more of WOB 447, surface RPM 448, and motor RPM 449 can be simulated for drill bit 442 based on the simplified geometry of the simplified downhole model 124-1 relative to the wellbore. In some embodiments, the effective bend point 452 is modeled as a fixed point, and one or more applied downhole dynamics can be simulated for drill bit 442 at (e.g., at the fixed) effective bend point 452. For example, WOB 447 can be simulated as a force applied to drill bit 442 from effective bend point 452 (e.g., taking into account the component force due to effective bend angle 456). In another example, surface RPM 448 can be applied to drill bit 442 from effective bend point 452 by simulating the effective bend length rotated about wellbore axis 450 (e.g., tilted at effective bend angle 456). In another example, motor RPM 449 can be applied to drill bit 442 from the effective bending point 452 by simulating the rotation of drill bit 442 (and / or effective bending length 455) about its own longitudinal axis. In some embodiments, both motor RPM 448 and motor RPM 449 can be applied in this manner to represent the combined rotation of drill bit 442. In this way, the behavior of drill bit 442 can be simulated in a simplified way by focusing on specific angles, lengths, forces, etc., associated with drill bit 442, without considering some of the more detailed complexities of the complex and sophisticated downhole system as a whole.

[0050] Figure 4-3 A schematic representation of an example embodiment of a guidance system 460, which can be used to guide downhole tools according to at least one embodiment of the present disclosure, is shown. The guidance system 460 may be an RSS (Resistant Strand System). As will be described in detail below, the techniques described herein are equally applicable to downhole systems implementing RSS, for example, as a supplement to or alternative to directional downhole motor guidance systems.

[0051] The steering system 460 may be included as part of the BHA (Bottom Automated Harness) of the downhole system and may be connected to one or more drill pipes at the top end of the well to position the steering system 460 and / or the BHA within the wellbore 441, and / or apply rotation, force, etc., to downhole components, as described herein. To illustrate the various features and functions of the drill bit behavior system 120, Figure 4-3 The guidance system 460 in the middle may be depicted as having one or more exaggerated features.

[0052] The steering system 460 may be a bit-pointing steering system and may guide or direct the drill bit 442 by forcibly bending one or more components. For example, the steering system 460 may apply a bias force 461 to the flexible component 462 of the drill bit 442 in the well. The bias force 461 may be applied based on the contact of a stabilizer, actuator, or other downhole tool with the wall of the wellbore 441. The bias force 461 may cause the flexible component 462 to bend. For example, the steering system 460 may include one or more stabilizers 446 that may contact the wall of the wellbore 441 and counteract the bias force 461. This may cause the flexible component 462 to bend between the stabilizers 446, which act as fulcrums for bending the flexible component 462. Based on the downhole location of the drill bit 442 at the bend of the flexible component 462, the drill bit 442 may be pointed or guided in the opposite direction of the bend accordingly. In this way, the steering system 460 may guide the drill bit 442 to effectively guide it.

[0053] Model engine 126 can determine the geometry associated with guidance system 460. As described above in relation to guidance system 440, the geometry of guidance system 460 may exhibit one or more complexities, which may make detailed analysis of the behavior of drill bit 442 computationally difficult. For example, the curved flexible component 462 complicates the analysis of drill bit dynamics. Additionally, as... Figure 4-3 As shown, the bending of the flexible component 462 causes a shift in the bending angle 463 of the drill bit 442 and / or one or more other (e.g., surface) components of the drill string. As another example, the drill bit 442 may be offset at an angle relative to the wellbore axis 450. The fact that the fulcrum of the stabilizer 446 used to achieve the bending of the flexible component 462 may also be offset relative to the wellbore axis 450 (e.g., as shown by gap 453) can further complicate matters. Therefore, given the complexity of the geometry shown, applying WOB 447 and / or surface RPM 448 (or any other downhole dynamics) to the steering system 460 to determine the final behavior of the drill bit 442 may be computationally demanding and inefficient.

[0054] As discussed above, model engine 126 can generate a simplified downhole model 124-2 suitable for the guidance system 460. For example, based on downhole tool data 132, and / or based on various lengths, positions, angles, etc., determined by model engine 126 for the guidance system 460, model engine 126 can determine an effective bend point 464. The effective bend point 464 can be a point located at the intersection of the longitudinal axis of drill bit 442 and the wellbore axis 450. In this way, the effective bend point 464 can be located at and / or aligned with axis 450.

[0055] Figure 4-4 An example of a simplified downhole model 124-2 of the guidance system 460 as described herein, according to at least one embodiment of the present disclosure, is shown. Similar to the description above, model engine 126 can generate the simplified downhole model 124-2 to facilitate the simulation and / or characterization of drill bit behavior. Model engine 126 can determine the effective bending length 465 of the simplified downhole model 124-2 based on the effective bending angle 466 and the offset distance 467. The simplified downhole model 124-2 can simulate the geometry of the guidance system 440 as if it were composed of straight segments and / or straight components, and as if these components effectively bent at the wellbore axis 450, as shown. Therefore, the simplified downhole model 124-2 can simplify the downhole system from a complex, highly detailed system to a simpler system focused on the drill bit 442 and its relationship to the wellbore 441.

[0056] As discussed above, the simplified downhole model 124-2 can help simulate the behavior and / or response of the drill bit 442 to one or more applied downhole dynamics. For example, the effective bend point 464 can be modeled as a fixed point, and WOB 447 and / or surface RPM 448 can be simulated as applied to the drill bit 442 relative to (e.g., from) the effective bend point 464. However, in embodiments without a directional downhole motor, the drill bit response can be simulated via the simplified downhole model 124-2 without introducing the applied motor RPM.

[0057] Figure 5 An example workflow of a drill bit behavior system 120 as described herein, according to at least one embodiment of the present disclosure, is shown. As mentioned above, the drill bit behavior system 120 includes a simulation engine 128. The simulation engine 128 can run simulations of the downhole system (more specifically, the drill bit) by implementing a simplified downhole model 124 to determine one or more drill bit behavior characteristics 136 representing the simulated response or behavior of the drill bit.

[0058] In some implementations, simulation engine 128 applies downhole tool data 132 to a simplified downhole model 124. For example, simulation engine 128 may incorporate downhole tool data 132 to consider various aspects of the drill bit, such as drill bit type, size, shape, geometry, and overall wear condition. Simulation engine 128 may incorporate downhole tool data 132 to consider various aspects of the drill bit's cutting and / or contact elements, such as the location, orientation, number, type, shape, size, geometry, and individual wear conditions of the cutting and / or contact elements. Downhole tool data 132 may be incorporated to consider the material or composition of the drill bit and / or cutting elements. In this way, simulation engine 128 can simulate various details of the drill bit that relate to determining an accurate simulated response of the drill bit.

[0059] In some implementations, simulation engine 128 applies operating parameter data 134 to a simplified downhole model 124. For example, as discussed above, one or more applied downhole dynamics of the drill bit, such as weight on bit (WOB), surface RPM, motor RPM, or any other relevant parameters (e.g., ROP), can be simulated based on the simplified downhole model 124. As mentioned above, these applied dynamics can be applied to the drill bit based on modifications and / or simplified geometry of the simplified downhole model 124 to capture the drill bit's response without modeling or simulating some of the more complex details of other components of the downhole system. For example, WOB, surface RPM, and / or motor RPM can be incorporated based on (e.g., a fixed) effective bend point and based on the forces, rotations, etc., applied from the effective bend point. In this way, simulation engine 128 can simulate various operating parameters or conditions of interest to determine the corresponding drill bit response.

[0060] In some embodiments, simulation engine 128 applies formation data 138 to a simplified downhole model 124. For example, the simulation engine may simulate the interaction between the drill bit and the wellbore (e.g., wellbore formation) based on one or more characteristics of a specific formation of interest. Simulation engine 128 may simulate one or more geological features of the formation rocks. Simulation engine 128 may simulate one or more layers of the formation (including formation dip). Simulation engine 128 may simulate one or more particles, modules, and / or cavities dispersed throughout the formation. In some embodiments, simulation engine 128 simulates non-homogeneous or heterogeneous formations. For example, simulation engine 128 may simulate formations with one or more non-homogeneous or inconsistent compositions, properties, characteristics, materials, etc. For example, the simulated formation may exhibit variations in lithology, porosity, permeability, mineral composition, physical and / or chemical characteristics, structural complexity, fluid presence and / or saturation, or any other (e.g., non-homogeneous) properties. In this way, simulation engine 128 can simulate relevant details of a specific formation of interest to determine the corresponding drill bit response.

[0061] Based on operational simulation and a simplified downhole model 124, and based on various drill bit, operational, and / or formation features incorporated in the simulation, simulation engine 128 can determine one or more drill bit behavior characteristics 136. Drill bit behavior characteristics 136 may include various metrics characterizing how the drill bit might move, wear, guide, respond, perform, or otherwise behave under specific simulated conditions. For example, drill bit behavior characteristics may characterize the distribution of forces and loads on the drill bit, the removal of rock by the drill bit, and the shocks and vibrations (e.g., accelerations) experienced by the drill bit. In some embodiments, simulation engine 128 determines one or more drill bit behavior characteristics related to the drill bit's durability, guideability, stability, and efficiency.

[0062] In some implementations, simulation engine 128 determines one or more resultant or contact forces based on the drill bit's contact with the wellbore. For example, simulation engine 128 may determine forces on one or more (or each) cutting elements of the drill bit. In another example, simulation engine 128 may determine forces on one or more gauge pads or other contact surfaces of the drill bit designed to manage the drill bit's cutting depth. Simulation engine 128 may determine forces in three dimensions, and / or may determine the three-dimensional components of forces on the cutting elements and / or contact surfaces.

[0063] In some implementations, the determined forces help determine the durability characteristics of the drill bit. For example, the determined forces can help characterize the degree or level of damage or wear of the cutting elements. For instance, simulation engine 128 can determine the operating rate of some or all of the cutting elements (or the drill bit as a whole). The operating rate can be correlated with the forces experienced by the cutting elements at the corresponding speed. Simulation engine 128 can identify whether certain cutting elements or certain areas of the drill bit are overloaded in order to determine how the drill bit may be damaged or worn.

[0064] In some implementations, the determined forces help determine directional characteristics. For example, the determined forces may include lateral cutting forces, which are associated with the drill bit's ability to cut laterally or to cut using cutting elements located on the lateral side of the drill bit. Lateral cutting forces may be associated with the drill bit's ability to steer, guide, or otherwise form a wellbore in the lateral direction. For example, lateral cutting forces may be associated with the drill bit's ability to generate doglegs.

[0065] In some embodiments, the determined forces help determine stability characteristics. For example, as mentioned, the determined forces can be three-dimensional. In some embodiments, the resultant force of the drill bit (e.g., the sum of all forces acting on all cutting elements and / or all contact surfaces) has at least a lateral or transverse component. Therefore, the resulting resultant force may be an unbalanced force, which may tend to deflect or push the drill bit in a certain direction. Simulation engine 128 can determine the unbalanced forces to characterize the stability of the drill bit. For example, unbalanced forces can help characterize the drill bit's ability to maintain a straight line during straight drilling operations and / or its ability to maintain a directional orientation during steerable operations.

[0066] In some implementations, simulation engine 128 determines various other metrics or measurements associated with durability. For example, simulation engine 128 may determine one or more of the following parameters: torque, bending, stress, strain, shock, vibration, or any other relevant parameters for the drill bit and / or one or more other downhole components. These parameters can help understand how individual components of the downhole system fail or wear in response to specific simulated conditions. For example, understanding the torque and bending moments exhibited by the drill bit can help understand the loads on the drill bit or other downhole components and can help determine the wear experienced by these components.

[0067] In some implementations, simulation engine 128 determines one or more efficiency characteristics. For example, simulation engine 128 may determine the mechanical rate of penetration (ROP) of the drill bit. Simulation engine 128 may determine the quality of the wellbore formed under simulated conditions. For example, simulation engine 128 may identify one or more wellbore enlargement areas, such as enlargement due to surface RPM applied during bit bending or guiding (e.g., using a downhole directional motor). In this way, simulation engine 128 can determine various drill bit behavior characteristics to help better understand the specific details of how the drill bit may respond to specific conditions simulated for downhole operations. This can be facilitated by a simplified downhole model 124 (e.g., a simplified geometry of the simplified downhole model 124). For example, the behavior, response, and / or influence of one or more other downhole components may be ignored or disregarded in order to focus on the behavior of the drill bit itself. This can help improve the computational efficiency, speed, accuracy, etc., of the drill bit behavior system 120 in determining drill bit behavior characteristics 136, for example, relative to analyzing a more complex and in-depth representation of the downhole system.

[0068] Figure 6 These are examples of various features of a report 600 generated by simulation engine 128 according to at least one embodiment of this disclosure. Simulation engine 128 can generate reports including... Figure 6 One or more of the features shown and described in Report 600.

[0069] In some embodiments, report 600 is associated with specific operating parameters of a simulated downhole operation. For example, as shown, report 600 may be associated with operating parameters of a simulated operation with an effective bending angle of 1°, a surface RPM of 60, and a motor RPM of 200. In some embodiments, report 600 shows or depicts a representation of the wellbore produced by the downhole operation simulation. For example, report 600 shows a horizontal top view cross section 601 and section 602 of the wellbore. Cross section 601 and section 602 may show the reaming effect of the operation on the wellbore. Cross section 601 may show the rotation path of the drill bit. For example, cross section 601 shows that, due to, for example, the effective bending angle applied by the surface RPM combined with the directional downhole motor, the drill bit follows a vortex-like motion as it forms the wellbore.

[0070] In some embodiments, report 600 illustrates a representation 603 of one or more forces acting on one or more cutting elements of the drill bit. For example, report 600 may depict normal and / or tangential forces on one or more cutting elements. This can help identify larger forces exhibited by one or more cutting elements or regions of the drill bit, such as helping to identify (e.g., net) unbalanced forces of the drill bit. Report 600 may depict any features described herein, and may additionally omit any features described in report 600. Report 600 may provide a representation of any drill bit behavior characteristics described herein.

[0071] Figure 7 A flowchart is shown of a method 700 or a series of actions for predicting the behavior of a downhole tool implemented in a wellbore, according to at least one embodiment of this disclosure. Although Figure 7 Actions according to one implementation are shown, but alternative implementations may include additions, omissions, reordering, and / or modifications. Figure 7 Any action by [them]. Figure 7 The action can be performed as part of a method. Alternatively, a non-transitory computer-readable medium can include actions that cause a computing device to perform when executed by one or more processors. Figure 7 The system can execute instructions for action. In a further implementation, the system can execute... Figure 7 The action.

[0072] In some embodiments, method 700 includes the action 710 of receiving geometric data associated with a downhole tool, wherein the geometric data indicates the bending angle of the downhole tool based on the bending of the downhole tool at a bending point. For example, the downhole tool may include a stabilizer, and the downhole tool may bend based on the stabilizer engaging the wall of the wellbore. The downhole tool may bend about a fulcrum at the stabilizer. The fulcrum may not be aligned with the longitudinal axis of the wellbore. Similarly, the bending point may not be located at the longitudinal axis of the wellbore. The geometric data may also indicate the bending length of the downhole tool. In some embodiments, the downhole tool is a bottomhole assembly of a downhole system, and the bottomhole assembly includes a drill bit.

[0073] In some implementations, method 700 includes receiving stratigraphic data. For example, the stratigraphic data may be associated with heterogeneous strata. The stratigraphic data may indicate the dip angle of the strata.

[0074] In some embodiments, method 700 includes action 720 of generating a simplified model of the downhole tool based on geometric data, the action including determining an effective bend point based on the longitudinal axis of the wellbore, and determining an effective bend angle based on the longitudinal axis of the wellbore. The effective bend angle may be smaller than the bend angle. The bend point may be located in the downhole direction of the bend point. In some embodiments, the effective bend point is determined at the intersection between the longitudinal axis of the downhole tool and the longitudinal axis of the wellbore. In some embodiments, generating the simplified model includes determining an effective bend length based on the effective bend point.

[0075] In some implementations, method 700 includes the action 730 of receiving operating parameters for the downhole tool. For example, operating parameters may include the weight on bit (WOB) associated with the downhole tool. Operating parameters may include surface RPM associated with the rotational speed of the downhole tool above the bend point, and motor RPM associated with the rotational speed of the downhole tool below the bend point. The motor RPM can be calculated from a motor model using flow rate and simulated bit torque, which may vary due to formation variations.

[0076] In some embodiments, method 700 includes actions 740 that simulate the operation of a downhole tool based on applying operating parameters to a simplified model. The operation may be a guiding operation. For example, simulating the operation may include applying WOB, surface RPM, and / or motor RPM to a simplified model. In some embodiments, operating parameters are applied to the downhole tool based on effective bend angles and effective bend points. In some embodiments, formation data is incorporated to simulate the downhole tool in a specific formation of interest, or to simulate downhole tool behavior when encountering formation changes.

[0077] In some embodiments, method 700 includes action 750 to determine one or more behavioral characteristics of the downhole tool based on the simulation. For example, one or more behavioral characteristics may include one or more of unbalanced forces acting on the downhole tool, lateral cutting forces acting on the downhole tool, and shocks and vibrations acting on the downhole tool. One or more behavioral characteristics may include one or more of forces acting on the cutting elements of the downhole tool and the operating rate of the cutting elements. One or more behavioral characteristics may include torque and bending associated with the downhole tool. One or more behavioral characteristics may include one or more of wellbore enlargement and wellbore mass.

[0078] Now go to Figure 8 The figure illustrates certain components that may be included within a computer system 800. One or more computer systems 800 may be used to implement the various apparatuses, components, and systems described herein.

[0079] Computer system 800 includes processor 801. Processor 801 can be a general-purpose single-chip or multi-chip microprocessor (e.g., an advanced RISC (Reduced Instruction Set Computer) machine (ARM)), a special-purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. Processor 801 can be referred to as a central processing unit (CPU). Although in Figure 8 The computer system 800 shows only a single processor 801, but in alternative configurations, a combination of processors (e.g., ARM and DSP) can be used.

[0080] The computer system 800 also includes a memory 803 that communicates electronically with the processor 801. The memory 803 may include a computer-readable storage medium and may be any available medium accessible by a general-purpose or special-purpose computer system. A computer-readable medium storing computer-executable instructions is a non-transitory computer-readable medium (device). A computer-readable medium carrying computer-executable instructions is a transmission medium. Therefore, by way of example and non-limitation, embodiments of this disclosure may include at least two distinct types of computer-readable media: a non-transitory computer-readable medium (device) and a transmission medium.

[0081] Both non-transitory computer-readable media (devices) and transmission media can be temporarily used to store or carry software instructions in the form of computer-readable program code that allows execution of embodiments of the present disclosure. Non-transitory computer-readable media can also be used to persistently or permanently store such software instructions. Examples of non-transitory computer-readable storage media include physical memory (e.g., RAM, ROM, EPROM, EEPROM, etc.), optical disc storage (e.g., CD, DVD, HDDVD, Blu-ray disc, etc.), storage devices (e.g., disk storage, magnetic tape storage, floppy disk, etc.), flash memory or other solid-state storage or memory, or any other non-transmission media that can be used to store program code in the form of computer-executable instructions or data structures and that can be accessed by a general-purpose or special-purpose computer, whether such program code is stored in the form of software, hardware, firmware, or a combination thereof.

[0082] Instruction 805 and data 807 may be stored in memory 803. Instruction 805 may be executable by processor 801 to implement some or all of the functions disclosed herein. Execution of instruction 805 may involve using data 807 stored in memory 803. Any of the various examples of modules and components described herein may be implemented in part or in whole as instruction 805 stored in memory 803 and executed by processor 801. Any of the various examples of data described herein may be in data 807 stored in memory 803 and used during the execution of instruction 805 by processor 801.

[0083] The computer system 800 may also include one or more communication interfaces 809 for communicating with other electronic devices. The communication interface 809 may be based on wired communication technology, wireless communication technology, or both. Some examples of the communication interface 809 include Universal Serial Bus (USB), Ethernet adapters, wireless adapters operating according to the Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, Bluetooth® wireless communication adapters, and infrared (IR) communication ports.

[0084] Communication interface 809 can connect computer system 800 to a network. A "network" or "communication network" can generally be defined as one or more data links that enable the transmission of electronic data between computer systems and / or modules, engines, or other electronic devices or combinations thereof. When information is transmitted or provided to a computing device via a communication network or another communication connection (hardwired, wireless, or a combination of hardwired and wireless), the computing device appropriately considers the connection as a transmission medium. The transmission medium may include a communication network and / or data link, carrier wave, wireless signal, etc., which can be used to carry desired program or template code means or instructions in the form of computer-executable instructions or data structures and can be accessed by a general-purpose or special-purpose computer.

[0085] Computer system 800 may also include one or more input devices 811 and one or more output devices 813. Some examples of input devices 811 include a keyboard, mouse, microphone, remote control, buttons, joystick, trackball, touchpad, and light pen. Some examples of output devices 813 include speakers and printers. A particular type of output device typically included in computer system 800 is a display device 815. Display device 815 used with the embodiments disclosed herein can utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, etc. A display controller 817 may also be provided for converting data 807 stored in memory 803 into one or more of text, graphics, or moving images (as applicable) displayed on display device 815.

[0086] Various components of the computer system 800 can be coupled together via one or more buses, which may include one or more of a power bus, control signal bus, status signal bus, data bus, other similar components, or combinations thereof. For clarity, Figure 8 The various buses are referred to as Bus System 819.

[0087] The techniques described herein can be implemented in hardware, software, firmware, or any combination thereof, unless specifically described as being implemented in a particular manner. Any features described as modules, components, etc., can also be implemented together in an integrated logic device or individually as discrete but interoperable logic devices. If implemented in software, the techniques can be implemented at least in part through a non-transitory processor-readable storage medium comprising instructions that, when executed by at least one processor, perform one or more of the methods described herein. The instructions can be organized into routines, programs, objects, components, data structures, etc., which can perform specific tasks and / or implement specific data types, and can be combined or distributed as needed in various implementation schemes.

[0088] Furthermore, upon arrival at various computer system components, program code in the form of computer-executable instructions or data structures can be automatically or manually transferred from the transmission medium to a non-transitory computer-readable storage medium (or vice versa). For example, computer-executable instructions or data structures received via a network or data link can be cached in memory (e.g., RAM) within a network interface module (NIC) and then ultimately transferred to the computer system RAM and / or a less volatile, non-transitory computer-readable storage medium at the computer system location. Therefore, it should be understood that non-transitory computer-readable storage media can be included in computer system components that also (or even primarily) utilize the transmission medium.

[0089] Industrial applicability In some embodiments, the downhole system is described as being used to drill into surface formations to form a wellbore. The downhole system includes a drilling rig for rotating a drilling tool assembly that extends downward into the wellbore. The drilling tool assembly may include a drill string, a bottom hole assembly (“BHA”), and a drill bit attached to the downhole end of the drill string.

[0090] The drill string may include several joints of drill pipe connected end-to-end via tool fittings. The drill string transmits drilling fluid and transfers rotational power from the drilling rig to the BHA through a central bore. In some embodiments, the drill string also includes additional downhole drilling tools and / or components, such as sub-sections, jumpers, etc. The drill pipe provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid exits through nozzles, orifices, or other openings of selected size in the drill bit to cool the drill bit and its cutting structures, and to lift cuttings out of the wellbore as it is drilled.

[0091] A BHA may include a drill bit, other downhole drilling tools, or other components. Example BHAs may include additional or other downhole drilling tools or components (e.g., connected between the drill string and the drill bit). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, downhole reamers, casing shoes, hydraulic disconnect joints, slappers, vibration or damping tools, other components, or combinations of the foregoing.

[0092] Generally, downhole systems may include other downhole drilling tools, components, and accessories, such as specialized valves (e.g., kerb plugs, blowout preventers, and safety valves). Additional components included in a downhole system may be considered part of the drilling tool assembly, the drill string, or BHA 106, depending on their location within the downhole system.

[0093] The drill bit in a BHA can be any type of drill bit suitable for degrading downhole materials. For example, the drill bit can be suitable for drilling into surface formations. Example drill bit types for drilling into surface formations are fixed-cutting or scraper bits. In other embodiments, the drill bit can be a milling shoe for removing metals, composites, elastomers, other downhole materials, or combinations thereof. For example, the drill bit can be used with a directional drilling tool to mill into casing fitted onto the wellbore. The drill bit can also be a flat-end milling shoe for milling away tools, plugs, cement, other materials, or combinations thereof from within the wellbore. The chips or other cuttings formed by using the milling shoe can be lifted to the surface or allowed to fall downhole. The drill bit may include one or more cutting elements for degrading surface formations.

[0094] The BHA may also include components for guiding or directing the drill bit's trajectory. For example, the BHA may include a rotary steerable system (RSS) and / or a directional downhole motor. Based on the mechanisms of these steerable systems, the BHA can be guided underground to reach, bypass, and / or travel relative to one or more downhole targets. In many cases, simulating, quantifying, and conceptualizing the behavior of the drill bit (e.g., individually) in response to the guidance of the steerable system may be advantageous. In some embodiments, the downhole system includes or is associated with one or more client devices on which a drill bit behavior system is implemented (e.g., implemented on one, several, or across multiple client devices). The drill bit behavior system can help simulate and determine the behavioral characteristics of one or more downhole tools (e.g., drill bits).

[0095] In some embodiments, a drill bit behavior system is implemented according to one or more embodiments described herein. In some embodiments, the environment includes one or more server devices. The server devices may include one or more computing devices (e.g., including processing units, data storage, etc.) organized in an architecture with various network interfaces for connecting to one or more client systems and providing data management and distribution across those client systems. The server devices can connect to one or more client devices via a network and can communicate with those client devices (directly or indirectly). The network may include one or more networks and may use one or more communication platforms and / or technologies suitable for transmitting data. A network may refer to any data link that enables the transmission of electronic data between devices in the environment. A network may refer to a hardwired network, a wireless network, or a combination of hardwired and wireless networks. In one or more embodiments, the network includes the Internet. The network may be configured to facilitate communication between various computing devices via Well Site Information Transmission Standard Markup Language (WITSML) or similar protocols, or any other protocol or form of communication.

[0096] Client devices can refer to various types of computing devices. For example, one or more client devices may include mobile devices such as mobile phones, smartphones, personal digital assistants (PDAs), tablet computers, laptop computers, or any other portable devices. Alternatively or additionally, client devices may include one or more non-mobile devices such as desktop computers, server devices, surface or downhole processors or computers (e.g., associated with sensors, systems, or functions of a downhole system), or other non-portable devices. In one or more embodiments, a client device includes a graphical user interface (GUI) (e.g., the screen of a mobile device) thereon. Additionally, or alternatively, one or more client devices may be communicatively coupled (e.g., wired or wireless) to a display device having a graphical user interface thereon for providing the display of system content. Server devices can similarly refer to various types of computing devices. Each device in the environment may include the features and / or functions described below.

[0097] An environment may include a drill behavior system implemented on one or more computing devices. The drill behavior system may be implemented on one or more client devices, server devices, or combinations thereof. Alternatively, the drill behavior system may be implemented across client devices and / or server devices, such that different parts or components of the drill behavior system are implemented on different computing devices within the environment. In this way, the environment may be a cloud computing environment, and the drill behavior system may be implemented across one or more devices within the cloud computing environment to leverage the processing power, storage capacity, connectivity, speed, etc., provided by such a cloud computing environment to facilitate the features and functions described herein.

[0098] In some implementations, according to at least one embodiment of this disclosure, an example implementation of the drill bit behavior system is described herein.

[0099] The drill bit behavior system may include a data manager, a downhole model engine for generating downhole models, and a simulation engine. The drill bit behavior system may also include a data storage device storing drill bit geometry data, operational parameter data, drill bit behavior characteristics, and formation data. While one or more embodiments described herein describe features and functions performed by specific components of the drill bit behavior system, it should be understood that specific features described in conjunction with one component of the drill bit behavior system may, in some examples, be performed by one or more other components of the drill bit behavior system.

[0100] As an example, one or more of the data receiving, collecting, or storing features of the data manager can be delegated to other components of the drill bit behavior system. As another example, while a simplified downhole model can be generated by a downhole model engine, in some cases, some or all of these features can be performed by the simulation engine (or other components of the drill bit behavior system). In fact, it should be understood that some or all of a particular component can be combined into other components, and a particular function can be performed by one component of the drill bit behavior system or by multiple components across that component.

[0101] Furthermore, while the drill bit behavior system has been described as being implemented on the client devices of the downhole system, it should be understood that some or all of the features and functions of the drill bit behavior system may be implemented on multiple client devices and / or server devices or across such multiple client devices and / or server devices. For example, data may be input and / or received by a data manager on a (e.g., local) client device, while the downhole model may be generated and / or simulated on one or more remote devices, server devices, or cloud devices. In fact, it should be understood that some or all of a particular component may be implemented on multiple client devices and / or server devices or across such multiple client devices and / or server devices, including individual functions of a particular component performed across multiple devices.

[0102] As mentioned above, the drill bit behavior system includes a data manager. The data manager receives various types of data associated with the downhole system and stores the data in a data storage device. The data manager can receive data from various sources, such as sensors, exploration tools, downhole tools, other devices (e.g., client devices), user input, etc.

[0103] In some implementations, the data manager receives downhole tool data. Downhole tool data may include information associated with drilling tool components of the downhole system. For example, downhole tool data may identify the parts and configuration of a drilling tool component, such as the number of drill pipes, or the components and composition of the BHA.

[0104] In some implementations, downhole tool data includes drill bit data, or information associated with downhole tools (such as drill bits) in the drilling tool assembly. Drill bit data may indicate the type of drill bit and may identify its shape or geometry. Drill bit data may include information associated with one or more cutting elements of the drill bit, such as their location, orientation, type, shape, size, geometry, and / or wear condition. Drill bit data may indicate the material composition or structure of the drill bit and / or cutting elements.

[0105] In some implementations, downhole tool data includes information associated with the guidance system of the drilling tool assembly. For example, downhole tool data may indicate the type of guidance assembly, such as an RSS or directional downhole motor guidance system. Downhole tool data may identify components of the guidance system, such as stabilizers, subs (e.g., flexible subs and / or bent subs), actuators, bearings, bent housings, blades, gaskets, or any other components, and their locations. Downhole tool data may indicate the operation or function of the guidance system. For example, downhole tool data may indicate the bias direction or guidance direction of the guidance system. Downhole tool data may indicate the orientation or orientation of one or more components (e.g., tool face orientation), such as the orientation of bent or flexible subs, the orientation of the drill bit, etc. Downhole tool data may indicate the azimuth or inclination of the drill string at one or more locations and / or at the measured depth.

[0106] In some implementations, downhole tool data includes information associated with (e.g., local) geometry of the BHA and / or steering system. For example, an RSS may operate based on a portion of the curved BHA (e.g., utilizing one or more stabilizers as fulcrums) to achieve a change of direction at the drill bit. Downhole tool data may include information that can identify or help determine the geometry of one or more portions or components of the steering system and / or BHA to facilitate modeling and / or simplification of the characteristics of the drill bit behavior system described herein. In another example, a directional downhole motor steering system may be based on the ability of the motor housing to be actuate to bend and / or angle to guide the drill bit in a corresponding direction. Therefore, downhole tool data may accordingly include information that can identify or help determine the relevant geometry (e.g., geometric data).

[0107] In some embodiments, downhole tool data includes information associated with (e.g., planned or existing) wellbore. For example, downhole tool data may indicate the length, depth, size, shape, and / or trajectory of the wellbore. In some embodiments, a data manager receives informational data. Formation data may include information associated with the formation in which the downhole tool will traverse, penetrate, or otherwise locate. For example, formation data may include information about the geological characteristics of rocks that may be encountered during one or more downhole operations. For example, formation data may indicate the material or composition of the formation, including the hardness of the formation. Formation data may indicate one or more layers or boundaries of the formation, including the orientation or dip of the layers. Formation data may indicate the presence of different particles or modules dispersed throughout the formation (e.g., layers), including the material or hardness of the particles. Formation data may indicate the presence of pores or cavities dispersed throughout the formation. Formation data may indicate the degree of homogeneity or uniformity of the formation (e.g., with respect to particles and / or cavities). Formation data may include data from gamma-ray sensors, resistivity sensors, porosity sensors, density sensors, acoustic sensors, calipers, core samples, or any other formation data.

[0108] The data manager can store any information associated with downhole tools and / or drilling tool components into a data storage device as downhole tool data.

[0109] In some implementations, the data manager receives user input. The data manager may receive user input, for example, via either a client device and / or a server device. Any data described herein may be entered or supplemented via user input. For example, in some cases, some or all of the downhole tool data is received by the data manager as user input. User input may be received in association with one or more functions or features of the drill bit behavior system, such as generating a portion of the downhole model, or any other feature described herein.

[0110] In some implementations, the data manager receives operational parameter data. Operational parameter data can be any information associated with the actual, planned, simulated, or otherwise operation or function of the downhole system. For example, operational parameter data can be associated with drilling operations of the downhole system. Operational parameter data can be associated with steering operations of the downhole system. Operational parameter data can be associated with any other operation of the downhole system, such as the delivery or tripping of one or more downhole tools.

[0111] Operational parameter data can indicate one or more parameters of an associated operation. For example, operational parameter data can indicate the weight on bit (WOB) and / or rate of penetration (ROP) of a downhole tool. Operational parameter data can indicate the rotational speed (revolutions per minute or RPM) of one or more components. For example, operational parameter data can indicate the surface RPM provided or exhibited by surface components of the downhole system, such as the surface RPM generated by the rotation of the drill string and / or drilling tool assemblies. Operational parameter data can indicate downhole or motor RPM. Motor RPM can indicate the rotational speed of a downhole tool driven by a downhole motor. Motor RPM can be independent of surface RPM. For example, in some cases, in addition to the rotation of the drill string (e.g., the rest of the drill string) caused by surface RPM, the downhole motor can also drive the rotation of the downhole tool. In some cases, the downhole system may not rotate at surface RPM, and the downhole motor may drive the rotation of the downhole tool based solely on motor RPM. In this way, the rotation of the downhole tool can be driven by surface RPM, motor RPM, or a combination of both.

[0112] In this way, the data manager receives various types of data to facilitate the techniques described herein. The data manager can receive data from various sources. For example, some data can be accessed by the data manager in databases, records, or libraries. Data can be observed, measured, or recorded, for example, through sensors or measuring devices in the downhole system. In some implementations, data is received from another computing device or system associated with the drill bit behavior system. As mentioned above, some data can be received or entered by the operator or administrator of the drill bit behavior system as user input.

[0113] In some implementations, some or all of the data is generated, determined, or created to characterize planned, hypothetical, or simulated scenarios and / or operations of the downhole system. For example, while this document has described data received and / or stored by the data manager in conjunction with the implementation of downhole tools and / or downhole systems in the wellbore, it should be understood that in some implementations, some or all of the data is associated with planned or simulated downhole operations. For example, the data may be associated with a downhole tool implemented in the wellbore, but its purpose may be to simulate or test one or more potential further operations of that downhole tool. In another example, the data may be purely associated with planning or simulating potential or future wellbore operations. In this way, the techniques described herein can be applied to a variety of situations and applications, including physical (existing) implementations as well as virtual, simulated, or planned implementations.

[0114] In some implementations, exemplary embodiments of a steering system that can be used to guide downhole tools are described herein. The steering system may be a bit-pointing steering system, such as a steering system that can be implemented by a directional or bending downhole motor. The steering system may be implemented in the wellbore and may be part of the BHA (Bottom Assist Assembly) of the downhole system. The BHA and / or steering system may be connected to one or more drill pipes to position the steering system and / or BHA in the wellbore and / or apply rotation, force, etc., to downhole components, as described herein.

[0115] A guidance system can be connected to downhole tools, such as drill bits. As mentioned above, in some cases, it may be necessary to change the direction or orientation of the drill bit in order to guide it. To achieve this, the guidance system may include one or more components with hinged or jointed elements that can be actuated to achieve bending or angulation. For example, a joint may be implemented as part of the downhole motor of the guidance system, which has a hinged, bending housing design to change the orientation of the drill bit. The joint can bend at the bending point and can be bent to a bending angle. The bending angle can be the angle between the longitudinal axis of the drill bit and the adjacent bend of the BHA above the joint. In this way, the bending angle can be a measure of the degree of hinge or level of the joint.

[0116] The guidance system may include a stabilizer to aid in guiding the drill bit. The stabilizer may be a component of the guidance system configured to engage the wellbore. For example, the stabilizer may be configured to engage the wellbore and maintain the relative position of the BHA within the wellbore, such as being located at or approximately at the center of the wellbore. In some embodiments, this stabilizing and / or centering function of the stabilizer aids in guiding the drill bit based on the articulation of the joint. For example, when the joint bends, the bottom or free end of the BHA (e.g., the drill bit) may be biased or movable toward the wall of the wellbore. The drill bit may engage the wall of the wellbore, thereby driving the joint in the opposite direction.

[0117] In some implementations, the stabilizer engages the wellbore and provides opposing balancing forces to the drill bit, allowing the drill bit to pivot or rotate about a pivot point. In this way, the stabilizer can act as a fulcrum to guide the drill bit and drive it (at least to some extent) into the wellbore wall.

[0118] In some implementations, the axial force, or WOB, is applied to the steering system and / or BHA via the drill string. The WOB can be a force generated by the weight of the drilling tool assembly attached above or on the wellbore, a force applied by the surface drilling rig, or a combination of both. Because the drill bit is at an angle to the centerline or longitudinal axis of the wellbore, the axial WOB can be transmitted to the drill bit, with at least some lateral component. This can cause the drill bit to engage (and form) the bottom of the wellbore at an angle, thereby guiding the drill bit.

[0119] In some embodiments, the steering system rotates at surface RPM. Surface RPM can be caused by surface equipment, such as a drilling rig, driving the rotation of the entire drill string. For example, surface RPM can be transmitted to the steering system and / or BHA via multiple drill pipes as described herein. In some embodiments, the drill bit rotates at motor RPM. Motor RPM can be the rotation of the drill bit driven by a downhole motor (e.g., a mud motor) of the steering system. In this way, the rotation of the drill bit can be driven (and / or described by) by surface RPM, motor RPM, or a combination of both.

[0120] As mentioned above, the drill bit behavior system includes a downhole modeling engine. In some embodiments, the downhole modeling engine models the steering system, including the BHA and the drill bit. In some embodiments, the modeling engine determines the geometry associated with the steering system. For example, based on downhole tool data, the modeling engine can determine the bending angle of the joint. The modeling engine can identify the location of the bending point. For example, in some cases, the bending point may be offset or not aligned with the wellbore axis. This may be due to the bending or offset characteristics of the steering system described above. Similarly, the modeling engine can identify the location of the pivot point around which the drill bit pivots. For example, in some cases, the pivot point may be offset or not aligned with the wellbore axis. This may be because the stabilizer is not exactly equal to the wellbore specification or diameter, and the pivot point may be slightly offset from the axis accordingly when the stabilizer is biased towards one side of the wellbore. In some embodiments, a gap may exist between the stabilizer and the wellbore due to this effect.

[0121] In some implementations, the model engine determines the bend length. The bend length can be the length measured from the downhole end of the drill bit to the pivot point. For example, the bend length can be a measurement from the guide system joint to the furthest downhole extension of the BHA.

[0122] The model engine can determine various loads, forces, or other dynamics applied to the drill bit. For example, the model engine can identify the WOB applied to the BHA from downhole tool data. The model engine can identify surface RPM and / or motor RPM from downhole tool data. The model engine can determine various lengths, angles, positions, etc., of the geometry of the BHA and / or steering system, as well as applied forces, rotations, etc., so that the model engine can model or simulate the operation of the downhole system and predict or determine the final response or behavior of the drill bit. The model engine can determine any other dynamics applied or exhibited by the downhole system, such as the rate of penetration (ROP), to model the drill bit's response.

[0123] As discussed above, a downhole system can include multiple components and / or tools arranged along the entire length of a drilling tool assembly. For example, a drilling tool assembly can include multiple drill pipes, drill collars, subs, tool joints, stabilizers, drill bits and reamers, steering systems, and other components. Such a complex system of components can represent complex and dynamic systems that are difficult to model and characterize. For example, the components may all be (at least indirectly) connected, and the movement, forces, torques, stresses, etc., exhibited by one component may correspondingly affect those quantities exhibited by other components. Additionally, many components may engage the wellbore wall, which can further influence the behavior of one or more components. Furthermore, the alignment (or misalignment) of components in a downhole system with the wellbore axis can further complicate modeling component behavior. For example, as discussed above, bend points and pivot points can be offset from the wellbore axis. Therefore, BHAs, steering systems, drill bits, etc., may be misaligned with the wellbore axis, making it computationally more difficult to model the behavior of the drill bit (e.g., its behavior relative to the wellbore). This effect can be even more pronounced when considering that similar misalignments can propagate along many components of the drill string, as drill strings and wellbores are often not perfectly straight, aligned, and perpendicular, but may frequently exhibit curved and / or arcuate geometries. Therefore, attempting to model and account for all components, details, and geometries of the downhole system can be overly complex and computationally difficult and / or slow.

[0124] In some implementations, the model engine generates a simplified downhole model. This simplified downhole model may include a simplified representation of one or more of the drill bit, BHA, and / or steering system. For example, based on downhole tool data and / or on the length, position, angle, etc., of the geometry discussed above, the model engine can determine the effective bend point. The effective bend point may be a point located at the intersection of the drill bit's longitudinal axis and the wellbore axis. In this way, the effective bend point may be located at and / or aligned with the axis. Due to the geometry of the steering system, the effective bend point may be located in the downhole direction of the bend point.

[0125] In some implementations, the model engine generates a simplified downhole model to facilitate the simulation and / or characterization of drill bit behavior. For example, the model engine can determine the effective bending length of the downhole model of the drill bit. The effective bending length can be measured from the tip of the drill bit to the effective bending point. Based on the fact that the effective bending point is located at the wellbore axis, the effective bending length can extend from the wellbore axis. For example, the effective bending length can form an effective bending angle with respect to the wellbore axis. Due to the mechanical mechanisms of the bending action of the steering system (e.g., the geometry of the steering system pivoting about a pivot point), the effective bending length can be shorter than the bending length, and the effective bending angle can be smaller than the bending angle. In some implementations, the model engine determines the effective bending angle based on the geometry discussed above to facilitate the determination of the effective bending length, for example, by performing trigonometric analysis. For example, the model engine can determine the offset distance of the tip or end of the drill bit relative to the wellbore axis. Based on the offset distance and the effective bending angle, the model engine can calculate the effective bending length using trigonometric functions. In this way, the simplified downhole model can simulate the geometry of the steering system as if it were aligned and / or bent at the wellbore axis. For example, a simplified model can represent the rest of the drill string as a straight line or aligned with the wellbore axis. Therefore, a simplified model can reduce a downhole system from a complex, highly detailed system to a simpler system that focuses on the drill bit and its relationship to the wellbore.

[0126] Simplified models can facilitate modeling the behavior and / or response of the drill bit to one or more applied downhole stimuli. For example, one or more of WOB, surface RPM, and motor RPM can be simulated for the drill bit based on a simplified geometry of the downhole model relative to the wellbore. In some embodiments, the effective bend point is modeled as a fixed point, and one or more applied downhole dynamics can be simulated at the drill bit at (e.g., a fixed) effective bend point. For example, WOB can be simulated as a force applied to the drill bit from the effective bend point (e.g., taking into account the component force due to the effective bend angle). In another example, surface RPM can be applied to the drill bit from the effective bend point by simulating the effective bend length rotating about the wellbore axis (e.g., tilting at the effective bend angle). In another example, motor RPM can be applied to the drill bit from the effective bend point by simulating the drill bit (and / or the effective bend length) rotating about its own longitudinal axis with motor RPM. In some embodiments, both motor RPM and motor RPM can be applied in this manner to represent the combined rotation of the drill bit. In this way, the behavior of the drill bit can be simulated in a simplified way by focusing on specific angles, lengths, forces, etc., associated with the drill bit, without having to consider the more detailed and complex aspects of the overall complex downhole system.

[0127] In some implementations, exemplary embodiments of a guidance system that can be used to guide downhole tools are described herein. The guidance system may be an RSS (Resistant Strand System). As will be described in detail below, the techniques described herein are equally applicable to downhole systems implementing RSS, for example, as a supplement to or alternative to directional downhole motor guidance systems.

[0128] The steering system may be included as part of the BHA of the downhole system and may be connected to one or more drill pipes at the uphole end to position the steering system and / or BHA in the wellbore and / or apply rotation, force, etc. to downhole components, as described herein.

[0129] A steering system can be a bit-pointing steering system and can guide or direct the drill bit by forcibly bending one or more components. For example, the steering system can apply a bias force to a flexible component of the drill bit on the wellbore. The bias force can be applied based on the contact of a stabilizer, actuator, or other downhole tool with the wellbore wall. The bias force can cause the flexible component to bend. For example, the steering system may include one or more stabilizers that can contact the wellbore wall and counteract the bias force. This may cause the flexible component to bend between the stabilizers, which act as fulcrums for bending the flexible component. Based on the downhole location of the drill bit at the bend in the flexible component, the drill bit can be pointed or guided in the opposite direction of the bend accordingly. In this way, the steering system can guide the drill bit to effectively direct it.

[0130] The model engine can determine the geometry associated with the steering system. As described above regarding steering systems, the geometry of the steering system may exhibit one or more complexities, which can make detailed analysis of drill bit behavior computationally difficult. For example, bent flexible components complicate the analysis of drill bit dynamics. Furthermore, the bending of flexible components causes a shift in the bending angle of one or more other (e.g., surface) components of the drill bit and / or drill string. As another example, the drill bit may be offset at an angle relative to the wellbore axis. The fact that the fulcrum of the stabilizer used to achieve the bending of the flexible components may also be offset relative to the wellbore axis (e.g., as shown by the gap) can further complicate matters. Therefore, given the complexity of the geometry, applying WOB and / or surface RPM (or any other downhole dynamics) to the steering system to determine the final behavior of the drill bit can be computationally demanding and inefficient.

[0131] As discussed above, the model engine can generate simplified downhole models suitable for the guidance system. For example, based on downhole tool data and / or on various lengths, positions, angles, etc., determined by the model engine for the guidance system, the model engine can determine the effective bend point. The effective bend point can be a point located at the intersection of the longitudinal axis of the drill bit and the axis of the wellbore. In this way, the effective bend point can be located on the axis and / or aligned with the axis.

[0132] Similar to the description above, the model engine can generate simplified downhole models to facilitate the simulation and / or characterization of drill bit behavior. The model engine can determine the effective bending length of the simulated downhole model based on the effective bending angle and offset distance. The simulated downhole model can model the geometry of the steering system as if it were composed of straight segments and / or straight components, and as if these components effectively bend along the wellbore axis. Therefore, the simplified model can reduce the complexity and detail of the downhole system to a simpler system focused on the drill bit and its relationship to the wellbore.

[0133] As discussed above, simplified models can help simulate the behavior and / or response of the drill bit to one or more applied downhole dynamics. For example, the effective bend point can be modeled as a fixed point, and the WOB and / or surface RPM can be simulated as applied to the drill bit relative to (e.g., from) the effective bend point. However, in embodiments without a directional downhole motor, the drill bit response can be simulated via a simplified downhole model without introducing the applied motor RPM.

[0134] In some implementations, this document describes an example workflow for a drill bit behavior system. As mentioned above, a drill bit behavior system includes a simulation engine. The simulation engine can run simulations of the downhole system (more specifically, the drill bit) by implementing a simplified downhole model in order to determine one or more drill bit behavior characteristics that represent the simulated response or behavior of the drill bit.

[0135] In some implementations, the simulation engine applies downhole tool data to a simplified downhole model. For example, the simulation engine can incorporate downhole tool data to consider various aspects of the drill bit, such as its type, size, shape, geometry, and overall wear condition. It can also incorporate downhole tool data to consider various aspects of the drill bit's cutting and / or contact elements, such as their location, orientation, number, type, shape, size, geometry, and individual wear conditions. The material or composition of the drill bit and / or cutting elements can also be considered. In this way, the simulation engine can simulate various details of the drill bit that relate to determining an accurate simulated response.

[0136] In some implementations, the simulation engine applies operational parameter data to a simplified downhole model. For example, as discussed above, one or more applied downhole dynamics of the drill bit, such as weight on bit (WOB), surface RPM, motor RPM, or any other relevant parameters (e.g., ROP), can be simulated based on the simplified downhole model. As mentioned above, these applied dynamics can be applied to the drill bit based on modifications and / or simplified geometry of the simplified downhole model to capture the drill bit's response without modeling or simulating some of the more complex details of other components of the downhole system. For example, WOB, surface RPM, and / or motor RPM can be incorporated based on (e.g., a fixed) effective bend point and based on the forces, rotations, etc., applied from the effective bend point. In this way, the simulation engine can simulate various operational parameters or conditions of interest to determine the corresponding drill bit response.

[0137] In some implementations, the simulation engine applies formation data to a simplified downhole model. For example, the simulation engine may simulate the interaction between the drill bit and the wellbore (e.g., wellbore formation) based on one or more characteristics of a specific formation of interest. The simulation engine may simulate one or more geological features of the formation rocks. The simulation engine may simulate one or more layers of the formation (including formation dip). The simulation engine may simulate one or more particles, modules, and / or cavities dispersed throughout the formation. In some implementations, the simulation engine simulates non-homogeneous or heterogeneous formations. For example, the simulation engine may simulate formations with one or more non-homogeneous or inconsistent compositions, properties, characteristics, materials, etc. For example, the simulated formation may exhibit variations in lithology, porosity, permeability, mineral composition, physical and / or chemical characteristics, structural complexity, fluid presence and / or saturation, or any other (e.g., non-homogeneous) properties. In this way, the simulation engine can simulate relevant details of a specific formation of interest to determine the corresponding drill bit response.

[0138] Based on operational simulations and simplified downhole models, and using various drill bit, operational, and / or formation features incorporated into the simulation, the simulation engine can determine one or more drill bit behavioral characteristics. Drill bit behavioral characteristics can include various metrics used to characterize how the drill bit might move, wear, guide, respond, perform, or otherwise behave under specific simulated conditions. For example, drill bit behavioral characteristics can characterize the distribution of forces and loads on the drill bit, the removal of rock by the drill bit, and the shocks and vibrations (e.g., accelerations) experienced by the drill bit. In some embodiments, the simulation engine determines one or more drill bit behavioral characteristics related to the drill bit's durability, guideability, stability, and efficiency.

[0139] In some implementations, the simulation engine determines one or more resultant or contact forces based on the drill bit's contact with the wellbore. For example, the simulation engine may determine the forces on one or more (or each) cutting elements and / or contact elements of the drill bit. In another example, the simulation engine may determine the forces on one or more gauge pads or other contact surfaces of the drill bit designed to manage the drill bit's cutting depth. The simulation engine may determine the forces in three dimensions, and / or may determine the three-dimensional components of the forces on the cutting elements and / or contact surfaces.

[0140] In some implementations, the determined forces help determine the durability characteristics of the drill bit. For example, the determined forces can help characterize the degree or level of wear on the cutting elements. For instance, a simulation engine can determine the operating rate of some or all of the cutting elements (or the drill bit as a whole). The operating rate can be correlated with the forces experienced by the cutting elements at the corresponding speed. The simulation engine can identify whether certain cutting elements or certain areas of the drill bit are overloaded in order to determine how the drill bit may wear.

[0141] In some implementations, the determined forces help determine directional characteristics. For example, the determined forces may include lateral cutting forces, which are associated with the drill bit's ability to cut laterally or to cut using cutting elements located on the lateral side of the drill bit. Lateral cutting forces may be associated with the drill bit's ability to steer, guide, or otherwise form a wellbore in the lateral direction. For example, lateral cutting forces may be associated with the drill bit's ability to generate doglegs.

[0142] In some implementations, the determined forces help determine stability characteristics. For example, as mentioned, the determined forces can be three-dimensional. In some implementations, the resultant force of the drill bit (e.g., the sum of all forces acting on all cutting elements) has at least a lateral or transverse component. Therefore, the resulting resultant force may be an unbalanced force, which may tend to deflect or push the drill bit in a certain direction. The simulation engine can determine the unbalanced forces to characterize the stability of the drill bit. For example, unbalanced forces can help characterize the drill bit's ability to maintain a straight line during straight drilling operations and / or its ability to maintain a directional orientation during steerable operations.

[0143] In some implementations, the simulation engine determines various other metrics or measurements associated with durability. For example, the simulation engine may determine one or more of the following parameters for the drill bit and / or one or more other downhole components: torque, bending, stress, strain, shock, vibration, or any other relevant parameters. These parameters can help understand how individual components of the downhole system wear in response to specific simulated conditions. For instance, understanding the torque and bending moments exhibited by the drill bit can help understand the loads on the drill bit or other downhole components and can help determine the wear experienced by these components.

[0144] In some implementations, the simulation engine determines one or more efficiency characteristics. For example, the simulation engine can determine the mechanical rate of penetration (ROP) of the drill bit. The simulation engine can determine the quality of the wellbore formed under simulated conditions. For example, the simulation engine can identify one or more wellbore enlargement areas, such as enlargement due to surface RPM applied during bit bending or guiding (e.g., using a downhole directional motor). In this way, the simulation engine can determine various drill bit behavior characteristics to help better understand the specific details of how the drill bit may respond to specific conditions simulated for downhole operations. This can be facilitated by simplified downhole models (e.g., simplified geometry of a simplified downhole model). For example, the behavior, response, and / or influence of one or more other downhole components can be ignored or disregarded to focus on the behavior of the drill bit itself. This can help improve the computational efficiency, speed, accuracy, etc., of determining drill bit behavior characteristics using a drill bit behavior system, for example, relative to analyzing more complex and in-depth representations of the downhole system.

[0145] In some embodiments, the simulation engine generates one or more reports that include some or all of the features described below. In some embodiments, the reports are associated with specific operating parameters of the simulated downhole operation. For example, a report may be associated with operating parameters of a simulated operation where the effective flex angle is 1°, the surface RPM is 60, and the motor RPM is 200. In some embodiments, the reports show or depict a representation of the wellbore produced by the downhole operation simulation. For example, the report may include a horizontal top-view cross-section and profile of the wellbore. The cross-section and profile may show the reaming effect of the operation on the wellbore. The cross-section may show the rotation path of the drill bit. For example, the cross-section may show the degree of vortexing experienced by the drill bit during wellbore formation due to, for example, the effective flex angle applied by the surface RPM combined with the directional downhole motor.

[0146] In some implementations, the report illustrates a representation of one or more forces acting on one or more cutting elements of the drill bit. For example, the report may depict normal and / or tangential forces on one or more cutting elements. This can help identify larger forces exhibited by one or more cutting elements or regions of the drill bit, such as helping to identify (e.g., net) unbalanced forces in the drill bit. The report may depict any features described herein, and may additionally omit any features described in the report. The report may provide a representation of any drill bit behavior characteristics described herein.

[0147] In some implementations, this document describes a method or series of actions for predicting the behavior of downhole tools implemented in a wellbore.

[0148] In some embodiments, the method includes receiving geometric data associated with a downhole tool, wherein the geometric data indicates the bending angle of the downhole tool based on a bending point. For example, the downhole tool may include a stabilizer, and the downhole tool may bend based on the stabilizer engaging the wellbore wall. The downhole tool may bend about a pivot point at the stabilizer. The pivot point may not be aligned with the longitudinal axis of the wellbore. Similarly, the bending point may not be located at the longitudinal axis of the wellbore. The geometric data may also indicate the bending length of the downhole tool. In some embodiments, the downhole tool is a bottomhole assembly of a downhole system, and the bottomhole assembly includes a drill bit.

[0149] In some implementations, the method includes receiving stratigraphic data. For example, the stratigraphic data may be associated with heterogeneous strata. The stratigraphic data may indicate the dip angle of the strata.

[0150] In some embodiments, the method includes actions such as generating a simplified model of a downhole tool based on geometric data, the actions including determining an effective bend point based on the longitudinal axis of the wellbore, and determining an effective bend angle based on the longitudinal axis of the wellbore. The effective bend angle may be smaller than the bend angle. The bend point may be located in the downhole direction of the bend point. In some embodiments, the effective bend point is determined at the intersection between the longitudinal axis of the downhole tool and the longitudinal axis of the wellbore. In some embodiments, generating the simplified model includes determining an effective bend length based on the effective bend point.

[0151] In some implementations, the method includes receiving operating parameters of the downhole tool. For example, operating parameters may include the weight on bit (WOB) associated with the downhole tool. Operating parameters may include surface RPM associated with the rotational speed of the downhole tool above the bend point, and motor RPM associated with the rotational speed of the downhole tool below the bend point.

[0152] In some embodiments, the method includes simulating the actions of a downhole tool by applying operating parameters to a simplified model. The actions may be directional actions. For example, simulating actions may include applying a WOB, surface RPM, and / or motor RPM to a simplified model. In some embodiments, operating parameters are applied to the downhole tool based on effective bend angles and effective bend points. In some embodiments, formation data is incorporated to simulate the downhole tool in a specific formation of interest.

[0153] In some implementations, the method includes determining the actions of one or more behavioral characteristics of the downhole tool based on the simulation. For example, one or more behavioral characteristics may include one or more of unbalanced forces acting on the downhole tool, lateral cutting forces acting on the downhole tool, and shocks and vibrations acting on the downhole tool. One or more behavioral characteristics may include one or more of forces acting on the cutting elements of the downhole tool and the operating rate of the cutting elements. One or more behavioral characteristics may include torque and bending associated with the downhole tool. One or more behavioral characteristics may include one or more of wellbore enlargement and wellbore mass.

[0154] In some implementations, certain components may be included in a computer system. One or more computer systems may be used to implement the various apparatuses, components, and systems described herein.

[0155] A computer system includes a processor. A processor can be a general-purpose single-chip or multi-chip microprocessor (e.g., an advanced RISC (Reduced Instruction Set Computer) machine (ARM)), a special-purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. A processor can be referred to as a central processing unit (CPU). Although only a single processor has been described, combinations of processors (e.g., ARM and DSP) can be used in alternative configurations.

[0156] The computer system also includes memory that communicates electronically with the processor. The memory may include a computer-readable storage medium and may be any available medium accessible by a general-purpose or special-purpose computer system. A computer-readable medium storing computer-executable instructions is a non-transitory computer-readable medium (device). A computer-readable medium carrying computer-executable instructions is a transmission medium. Therefore, by way of example and non-limitation, embodiments of this disclosure may include at least two distinct types of computer-readable media: a non-transitory computer-readable medium (device) and a transmission medium.

[0157] Both non-transitory computer-readable media (devices) and transmission media can be temporarily used to store or carry software instructions in the form of computer-readable program code that allows execution of embodiments of the present disclosure. Non-transitory computer-readable media can also be used to persistently or permanently store such software instructions. Examples of non-transitory computer-readable storage media include physical memory (e.g., RAM, ROM, EPROM, EEPROM, etc.), optical disc storage (e.g., CD, DVD, HDDVD, Blu-ray disc, etc.), storage devices (e.g., disk storage, magnetic tape storage, floppy disk, etc.), flash memory or other solid-state storage or memory, or any other non-transmission media that can be used to store program code in the form of computer-executable instructions or data structures and that can be accessed by a general-purpose or special-purpose computer, whether such program code is stored in the form of software, hardware, firmware, or a combination thereof.

[0158] Instructions and data may be stored in memory. Instructions may be executable by a processor to perform some or all of the functions disclosed herein. Executing instructions may involve using data stored in memory. Any of the various examples of modules and components described herein may be implemented, in whole or in part, as instructions stored in memory and executed by a processor. Any of the various examples of data described herein may be data stored in memory and used during the execution of instructions by the processor.

[0159] Computer systems may also include one or more communication interfaces for communicating with other electronic devices. Communication interfaces may be based on wired communication technologies, wireless communication technologies, or both. Some examples of communication interfaces include Universal Serial Bus (USB), Ethernet adapters, wireless adapters operating according to the Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, Bluetooth® wireless communication adapters, and infrared (IR) communication ports.

[0160] A communication interface connects a computer system to a network. A "network" or "communication network" can generally be defined as one or more data links that enable the transmission of electronic data between a computer system and / or modules, engines, or other electronic devices or combinations thereof. When information is transmitted or provided to a computing device via a communication network or another communication connection (hardwired, wireless, or a combination of hardwired and wireless), the computing device appropriately considers the connection as a transmission medium. The transmission medium may include the communication network and / or data link, carrier wave, wireless signal, etc., which can be used to carry desired program or template code means or instructions in the form of computer-executable instructions or data structures and can be accessed by a general-purpose or special-purpose computer.

[0161] Computer systems may also include one or more input devices and one or more output devices. Some examples of input devices include keyboards, mice, microphones, remote controls, buttons, joysticks, trackballs, touchpads, and light pens. Some examples of output devices include speakers and printers. A particular type of output device typically included in a computer system is a display device. Display devices used with the embodiments disclosed herein can utilize any suitable image projection technology, such as liquid crystal displays (LCDs), light-emitting diodes (LEDs), gas plasma, electroluminescence, etc. A display controller may also be provided for converting data stored in memory into one or more of text, graphics, or moving images (as applicable) displayed on the display device.

[0162] Various components of a computer system can be coupled together via one or more buses, which may include one or more of a power bus, a control signal bus, a status signal bus, a data bus, other similar components, or combinations thereof.

[0163] The techniques described herein can be implemented in hardware, software, firmware, or any combination thereof, unless specifically described as being implemented in a particular manner. Any features described as modules, components, etc., can also be implemented together in an integrated logic device or individually as discrete but interoperable logic devices. If implemented in software, the techniques can be implemented at least in part through a non-transitory processor-readable storage medium comprising instructions that, when executed by at least one processor, perform one or more of the methods described herein. The instructions can be organized into routines, programs, objects, components, data structures, etc., which can perform specific tasks and / or implement specific data types, and can be combined or distributed as needed in various implementation schemes.

[0164] Furthermore, upon arrival at various computer system components, program code in the form of computer-executable instructions or data structures can be automatically or manually transferred from the transmission medium to a non-transitory computer-readable storage medium (or vice versa). For example, computer-executable instructions or data structures received via a network or data link can be cached in memory (e.g., RAM) within a network interface module (NIC) and then ultimately transferred to the computer system RAM and / or a less volatile, non-transitory computer-readable storage medium at the computer system location. Therefore, it should be understood that non-transitory computer-readable storage media can be included in computer system components that also (or even primarily) utilize the transmission medium.

[0165] The description below from paragraphs

[0176] –[01XX] includes various embodiments, which may be arranged and combined in any way where feasible. For example, embodiments of

[0176] may be used in conjunction with any or all of the embodiments described in the following paragraphs. Embodiments describing the action of a method may be combined with embodiments describing, for example, a system or apparatus. Any arrangement or combination of the following paragraphs is deemed to be disclosed herein in order to provide “clearly deducible support” for any modifications to the claims based on the following paragraphs. Furthermore, the following paragraphs provide support such that any combination of the following paragraphs does not produce an “intermediate generalization.”

[0166] The description below from paragraphs

[0177] –

[0194] includes various embodiments, which may be arranged and combined in any way where feasible. For example, the embodiments of

[0177] may be used in conjunction with any or all of the embodiments in the following paragraphs. Embodiments describing the action of a method may be combined with embodiments describing, for example, systems and / or apparatuses. Any arrangement or combination of the following paragraphs is deemed to be disclosed herein in order to provide “clearly deducible support” for any modifications to the claims based on the following paragraphs. Furthermore, the following paragraphs provide support such that any combination of the following paragraphs does not produce an “intermediate generalization.”

[0167] In some embodiments, a method for predicting the behavior of a downhole tool implemented in a wellbore includes receiving geometric data associated with the downhole tool, wherein the geometric data indicates the bending angle of the downhole tool based on bending at bending points. In some embodiments, the method includes generating a simplified model of the downhole tool based on the geometric data, the generation of the simplified model including determining effective bending points based on the longitudinal axis of the wellbore and determining effective bending angles 456 based on the longitudinal axis 450 of the wellbore 441. In some embodiments, the method includes receiving operating parameters of the downhole tool. In some embodiments, the method includes: simulating the operation of the downhole tool based on applying the operating parameters to the simplified model; and determining one or more behavioral characteristics of the downhole tool based on the simulation.

[0168] In some implementations, the operating parameters include the weight on drill bit (WOB) associated with the downhole tool, and simulating the operation of the downhole tool includes applying the WOB to the simplified model.

[0169] In some implementations, the operating parameters include surface RPM associated with the rotational speed of the downhole tool above the bend point, and motor RPM associated with the rotational speed of the downhole tool below the bend point.

[0170] In some implementations, the effective bending angle is smaller than the bending angle, and the effective bending point is located in the downhole direction of the bending point.

[0171] In some implementations, the effective bending point is determined at the intersection between the longitudinal axis of the downhole tool and the longitudinal axis of the wellbore.

[0172] In some embodiments, the downhole tool includes a stabilizer, and the downhole tool bends based on the stabilizer engaging the wall of the wellbore, and the downhole tool bends about a fulcrum at the stabilizer.

[0173] In some implementations, the fulcrum is not aligned with the longitudinal axis of the wellbore.

[0174] In some implementations, the bend point is not located at the longitudinal axis of the wellbore.

[0175] In some implementations, simulating the operation of the downhole tool further includes applying the operating parameters to the downhole tool based on the effective bending angle and the effective bending point.

[0176] In some implementations, the one or more behavioral characteristics include one or more of the following: unbalanced forces acting on the downhole tool, lateral cutting forces acting on the downhole tool, and shocks and vibrations acting on the downhole tool.

[0177] In some implementations, the one or more behavioral characteristics include one or more of the force acting on the cutting element of the downhole tool and the operating rate of the cutting element.

[0178] In some implementations, the one or more behavioral characteristics include torque and bending associated with the downhole tool.

[0179] In some implementations, the one or more behavioral characteristics include one or more of the wellbore enlargement and the wellbore mass.

[0180] In some embodiments, the method further includes receiving formation data, and applying the operating parameters to the simplified model includes incorporating the formation data to simulate the downhole tool in a specific formation of interest.

[0181] In some implementations, the formation data is associated with heterogeneous formations.

[0182] In some implementations, the formation data indicates the dip angle of the formation.

[0183] In some implementations, the operation of the downhole tool is a guiding operation performed by the downhole tool using a downhole motor.

[0184] In some implementations, the downhole tool is a bottom hole assembly of a downhole system, and the bottom hole assembly includes a drill bit.

[0185] The implementation of the drill bit behavior system has been described primarily with reference to wellbore drilling operations; the drill bit behavior system described herein can be used in applications other than wellbore drilling. In other embodiments, the drill bit behavior system according to this disclosure can be used outside of wellbores or other downhole environments used for exploring or producing natural resources. For example, the drill bit behavior system of this disclosure can be used in boreholes used for laying utility pipelines. Therefore, the terms “wellbore,” “borehole,” etc., should not be construed as limiting the tools, systems, assemblies, or methods of this disclosure to any particular industry, field, or environment.

[0186] This document describes one or more specific embodiments of the present disclosure. These described embodiments are examples of the currently disclosed technology. Additionally, to provide a brief description of these embodiments, not all features of an actual embodiment may be described in this specification. It should be understood that when developing any such actual implementation in any engineering or design project, numerous implementation-specific decisions will be made to achieve the developer's specific goals, such as compliance with system-related and business-related constraints, which may vary from embodiment to embodiment. Furthermore, it should be understood that such development work may be complex and time-consuming, but will remain a routine task in design, fabrication, and manufacturing for those skilled in the art who benefit from this disclosure.

[0187] Furthermore, it should be understood that references to "one embodiment" or "implementation" in this disclosure are not intended to be construed as excluding the existence of additional embodiments that also incorporate the described features. For example, any element described with respect to an embodiment herein may be combined with any element of any other embodiment described herein. As will be appreciated by one of ordinary skill in the art as covered by embodiments of this disclosure, the figures, percentages, ratios, or other values ​​stated herein are intended to include, and also include, other values ​​that are "about" or "approximately" said values. Therefore, the values ​​should be interpreted broadly enough to cover values ​​that are at least close enough to the value to perform the desired function or achieve the desired result. The values ​​include at least the variations expected in a suitable manufacturing or production process and may include values ​​within 5%, 1%, 0.1%, or 0.01% of the value.

[0188] In view of this disclosure, those skilled in the art will recognize that equivalent constructions do not depart from the spirit and scope of this disclosure, and that various changes, substitutions, and modifications may be made to the embodiments disclosed herein without departing from the spirit and scope of this disclosure. Equivalent constructions (including the functional “apparatus plus function” clause) are intended to cover structures described herein as performing said functions, including structural equivalents operating in the same manner and equivalent structures providing the same function. The applicant’s explicit intent is not to invoke apparatus plus function or other functional requirements in any claim, except for those claims where the phrase “apparatus for…” appears with the associated function. Every addition, deletion, and modification to the embodiments falling within the meaning and scope of the claims will be included in the claims.

[0189] As used herein, the terms “approximately,” “about,” and “substantially” mean a quantity close to the stated amount, which is within standard manufacturing or process tolerances or still performs the desired function or achieves the desired result. For example, the terms “approximately,” “about,” and “substantially” can refer to a quantity less than 5%, less than 1%, less than 0.1%, and less than 0.01% of the stated amount. Furthermore, it should be understood that any direction or frame of reference in the foregoing description is only relative direction or movement. For example, any reference to “up” and “down,” or “above” or “below”, describes only the relative position or movement of the relevant element.

[0190] This disclosure may be embodied in other specific forms without departing from the spirit or characteristics thereof. The described embodiments should be considered illustrative rather than restrictive. Therefore, the scope of this disclosure is indicated by the appended claims rather than by the foregoing description. Variations in the meaning and scope of equivalent forms of the claims are to be included within the scope of the claims.

Claims

1. A method for predicting the behavior of a downhole tool 442 implemented in a wellbore 441, comprising: Receive geometric data associated with the downhole tool 442, wherein the geometric data indicates the bending angle 445 of the downhole tool 442 based on the bending angle 445 of the downhole tool 442 at the bending point 444; Based on the geometric data, a simplified model 124-1 of the downhole tool 442 is generated. The generation of the simplified model includes: The effective bending point 452 is determined based on the longitudinal axis 450 of the wellbore; and The effective bending angle 456 is determined based on the longitudinal axis 450 of the wellbore 441; Receive the operating parameters of the downhole tool 442; The operation of the downhole tool 442 is simulated by applying the operating parameters to the simplified model 124-1; and The simulation is used to determine one or more behavioral characteristics of the downhole tool 442.

2. The method of claim 1, wherein the operating parameters include the weight on drill bit (WOB) associated with the downhole tool, and simulating the operation of the downhole tool includes applying the WOB to the simplified model.

3. The method of claim 1 or 2, wherein the operating parameters include a surface RPM associated with the rotational speed of the downhole tool above the bend point, and a motor RPM associated with the rotational speed of the downhole tool below the bend point.

4. The method of claim 3, wherein the effective bending angle is less than the bending angle, and wherein the effective bending point is located in the downhole direction of the bending point.

5. The method according to any one of claims 1 to 4, wherein the effective bending point is determined at the intersection between the longitudinal axis of the downhole tool and the longitudinal axis of the wellbore.

6. The method according to any one of claims 1 to 5, wherein the downhole tool includes a stabilizer, the downhole tool bends based on the stabilizer engaging the wall of the wellbore, and wherein the downhole tool bends about a fulcrum at the stabilizer.

7. The method of claim 6, wherein the fulcrum is not aligned with the longitudinal axis of the wellbore.

8. The method according to any one of claims 1 to 7, wherein the bending point is not located at the longitudinal axis of the wellbore.

9. The method according to any one of claims 1 to 8, wherein simulating the operation of the downhole tool further comprises applying the operation parameters to the downhole tool based on the effective bending angle and the effective bending point.

10. The method according to any one of claims 1 to 9, wherein the one or more behavioral characteristics include one or more of an unbalanced force acting on the downhole tool, a lateral cutting force acting on the downhole tool, and an impact and vibration acting on the downhole tool.

11. The method according to any one of claims 1 to 10, wherein the one or more behavioral characteristics include one or more of the force acting on the cutting element of the downhole tool and the operating rate of the cutting element.

12. The method according to any one of claims 1 to 11, wherein one or more behavioral characteristics include torque and bending associated with the downhole tool.

13. The method of any one of claims 1 to 12, further comprising receiving formation data, and wherein applying the operating parameters to the simplified model includes incorporating the formation data to simulate the downhole tool in a particular formation of interest.

14. The method of claim 13, wherein the formation data is associated with heterogeneous formations.

15. The method according to any one of claims 1 to 14, wherein the operation of the downhole tool is a guiding operation performed by the downhole tool using a downhole motor.

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