Systems, methods, and apparatus for borehole imaging

Abstract

A method of imaging a subterranean formation includes identifying engagement data from an engagement sensor. The engagement data corresponds to an engagement of the instrumented engagement element with a borehole in the subterranean formation. The method includes identifying rotation data from a rotation sensor. The rotational data corresponds to a rotational orientation of the engagement data relative to the bore. The method includes mapping the bond data to the rotation data to generate oriented bond data.

Description

[0001] Cross-references to related applications

[0002] This disclosure claims priority to U.S. Provisional Application No. 63 / 502,148, filed May 15, 2023, the entire contents of which are incorporated herein by reference. Background Technology

[0003] Wells can be drilled into surface locations or the seabed for various exploration or extraction purposes. For example, wells can be drilled to access fluids stored in underground formations, such as liquid and gaseous hydrocarbons, and to extract the fluids from the formation. Wells used to produce or extract fluids can be formed in soil formations using drilling tools such as drill bits for drilling wells and reamers for enlarging the diameter of the well.

[0004] Wellbores can extend deep underground, often several kilometers. Accurately detecting and mapping the features of geological formations to identify the source of oil, gas, or other valuable resources is important and often challenging. This is typically achieved by imaging the wellbore using wireline tools. These tools are usually lowered into the wellbore and equipped with sensors that measure various parameters, such as the gamma-ray emission, resistivity, and acoustic properties of the surrounding rock. These measurements are then used to create an image of the wellbore. Additional tools can be used to obtain core samples of the formation. Specialized coring bits can be deployed downhole to cut and remove a portion of the wellbore so that it can be examined and analyzed at the surface.

[0005] However, operating wireline and coring tools can be expensive, partly because they are typically only available when the well is not being actively drilled. Images produced by wireline tools often have limited resolution, which can significantly limit their usefulness. Collecting formation cores can be arduous and costly, potentially limiting the amount of cores that can actually be collected. Therefore, techniques for imaging the wellbore during drilling and / or facilitating the mapping of downhole formation characteristics can offer significant advantages over conventional techniques such as those utilizing wireline and coring tools. Summary of the Invention

[0006] In some embodiments, a method for imaging a formation includes identifying engagement data from an engagement sensor. The engagement data corresponds to the engagement of an instrumented engagement element with a borehole in the formation. The method includes identifying rotation data from a rotation sensor. The rotation data corresponds to the rotational orientation of the engagement data relative to the borehole. The method includes mapping the engagement data to the rotation data to generate oriented engagement data.

[0007] In other embodiments, a method of imaging a formation includes identifying engagement data from an engagement sensor. The engagement data corresponds to an engagement with a borehole in the formation. The method includes identifying depth data from a depth sensor. The depth data corresponds to a depth of the engagement data relative to the borehole. The method includes mapping the engagement data to the depth data to generate mapped engagement data.

[0008] In other embodiments, a method of imaging a formation includes identifying engagement data from an engagement sensor. The engagement data corresponds to an engagement with a borehole in the formation. The method includes identifying rotation data from a rotation sensor or identifying depth data from a depth sensor. The rotation data corresponds to a rotational orientation of the engagement data relative to the borehole, and the depth data corresponds to a depth of the engagement data relative to the borehole. The method includes identifying lithology data from a lithology sensor. The lithology data corresponds to one or more physical characteristics of the formation. The method includes mapping the engagement data to the lithology data and the rotation data to generate mapped data, or mapping the engagement data to the lithology data and the depth data to generate mapped engagement data.

[0009] In yet other embodiments, a method of determining a geological feature on a formation includes receiving engagement data from an engagement sensor. The engagement data corresponds to an engagement with a borehole of the formation. The method includes defining a data feature in the engagement data. The method includes determining a geological feature of the formation based on identifying a plurality of instances of the data feature, each instance occurring periodically relative to a rotation of a downhole tool.

[0010] In yet other embodiments, a method of mapping a formation includes identifying first engagement data from a first engagement sensor. The first engagement data corresponds to a first engagement with a borehole in the formation. The method includes identifying second engagement data from a second engagement sensor. The second engagement data corresponds to a second engagement with the borehole. The method includes mapping the first engagement data to the second engagement data to generate mapped engagement data.

[0011] This Summary is provided to introduce some concepts in a simplified form that are further described below in the DETAILED DESCRIPTION. This Summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter.

[0012] Additional features and advantages of the embodiments of the present disclosure will be set forth in the description that follows, and in part will be apparent from the description, or can be learned by practice of these embodiments. The features and advantages of the embodiments can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims, or can be learned by practice of the embodiments described herein. BRIEF DESCRIPTION OF DRAWINGS

[0013] In order to describe the manner in which the above-recited and other features of the present disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the same reference numbers are used throughout the various drawings to designate like components. While some of the drawings can be schematic or exaggerated representations of concepts, at least some of the drawings can be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0014] Figure 1 One embodiment of a drilling system for drilling a formation to form a borehole is shown in accordance with at least one embodiment of the present disclosure;

[0015] Figure 2 is a bottom view of a downhole end of an embodiment of a drill bit in accordance with at least one embodiment of the present disclosure;

[0016] Figure 3 An example computing device having a downhole imaging system implemented thereon is shown in accordance with at least one embodiment of the present disclosure;

[0017] Figure 4 An example information flow between components of a downhole imaging system is shown in accordance with at least one embodiment of the present disclosure;

[0018] Figure 5 An example information flow between components of a downhole imaging system is shown in accordance with at least one embodiment of the present disclosure;

[0019] Figure 6 An example information flow between components of a downhole imaging system is shown in accordance with at least one embodiment of the present disclosure;

[0020] Figures 7-1 to 7-5 is example image data generated by an image generation engine of a downhole imaging system in accordance with at least one embodiment of the present disclosure;

[0021] Figure 8 An example information flow between components of a downhole imaging system is shown in accordance with at least one embodiment of the present disclosure;

[0022] Figure 9 An example information flow between components of a downhole imaging system is shown in accordance with at least one embodiment of the present disclosure;

[0023] Figure 10 A flow diagram of a method or series of acts for using a downhole imaging system as discussed herein is shown in accordance with at least one embodiment of the present disclosure;

[0024] Figure 11A flow diagram illustrating a method or series of actions for using a downhole imaging system as discussed herein is shown in accordance with at least one embodiment of the present disclosure;

[0025] Figure 12 A flow diagram illustrating a method or series of actions for using a downhole imaging system as discussed herein is shown in accordance with at least one embodiment of the present disclosure; and

[0026] Figure 13 A flow diagram illustrating a method or series of actions for using a downhole imaging system as discussed herein is shown in accordance with at least one embodiment of the present disclosure; and

[0027] Figure 14 A flow diagram illustrating a method or series of actions for using a downhole imaging system as discussed herein is shown in accordance with at least one embodiment of the present disclosure; and

[0028] Figure 15 Certain components that can be included within a computer system are shown. DETAILED DESCRIPTION

[0029] The present disclosure relates generally to apparatuses, systems, and methods for mapping a formation or downhole environment. For example, a drilling system can implement one or more tools for engaging a borehole. An instrumented engagement element can be implemented in conjunction with one or more downhole tools and can engage a borehole and / or degrade a borehole. The instrumented engagement element can include one or more sensors for making engagement measurements (e.g., drilling, milling, reaming, stabilizing, steering, other measurements, or combinations thereof) associated with engagement of the engagement element and the borehole, such as force measurements. In at least one embodiment described herein, observed downhole measurements (and / or changes in observed downhole measurements) facilitate determining and / or mapping one or more characteristics of a borehole. A downhole measurement system can make one or more additional measurements of or related to a downhole environment. For example, a downhole imaging system can make force measurements, rotational measurements, depth measurements, lithology measurements, other downhole measurements (e.g., drilling, milling, reaming, stabilizing, steering, other measurements, or combinations thereof), or combinations thereof to perform one or more techniques described herein.

[0030] The downhole system can include a computing device that can implement a downhole imaging system. For example, the downhole imaging system can be a computer-implemented method, or one or more aspects of the downhole imaging system can be performed as a computer-implemented method. The downhole imaging system can receive one or more measurements discussed above as sensor data. The downhole imaging system can map (e.g., correlate) data. For example, the downhole imaging system can correlate portions of the junction measurements with portions of other measurements (e.g., force measurements, rotation measurements, depth measurements, lithology measurements, other downhole measurements, or combinations thereof) to, for example, orient the junction measurements relative to the borehole. Data mapped in this way can include oriented junction data. The downhole imaging system can map any other data or portions of data. For example, the downhole imaging system can map the junction data to a global reference frame, for example, so that the junction data can be generally associated with a formation.

[0031] The downhole imaging system can generate one or more images based on, for example, the oriented (e.g., mapped) junction data. The images can visually present or illustrate the oriented junction data in the form of a graph, a plot, a picture, other visual representation, or combinations thereof. The images can illustrate the junction data relative to a rotational position or a local angle within the borehole. The images can illustrate the junction data relative to a rotational position and / or a global angle within a formation in which the borehole is located. The images can illustrate one or more geological features of the formation, such as a fracture or a fissure.

[0032] The downhole imaging system can identify and / or can facilitate identification of one or more geological features of the formation. For example, the downhole imaging system can generate feature data indicative of one or more geological features of the formation based on the sensor data, based on the mapped data, based on the generated images, or based on any other data. The downhole imaging system can transmit the data to one or more drilling devices. For example, the downhole imaging system can send the sensor data, the mapped data, the feature data, the generated images, or combinations thereof to one or more drilling devices.

[0033] As will be discussed in further detail below, the present disclosure includes a number of practical applications having the features described herein that provide benefits and / or solve problems associated with identifying geological features and / or characterizing formations. Some example benefits are discussed herein in connection with various features and functions provided by a downhole imaging system implemented on one or more computing devices. It should be understood that the explicitly discussed benefits related to one or more embodiments described herein are provided by way of example only and are not intended to exhaustively recite all possible benefits of a downhole imaging system nor are they intended to limit the scope of the claims.

[0034] For example, identifying and / or mapping the geological features and / or structure of formations or reservoirs can be crucial for the effective planning and execution of drilling operations. The downhole imaging techniques discussed in this paper can detect and / or facilitate the detection of geological features of formations, such as fractures, cracks, formation boundaries, formation angles, etc. Identifying and / or understanding such geological features can be invaluable for determining, for example, where subsurface resources may be located, how to drill through and / or penetrate certain formations, completion strategies, risk factors associated with certain formations, and other factors. Therefore, implementing the downhole imaging techniques described herein to detect and / or map the geological features of formations can provide significant cost, time, and / or resource savings by offering a better understanding of the formation being drilled and increased confidence in features assumed to exist within the formation.

[0035] In addition to the usual detection of geological features, the downhole imaging techniques described herein can generate images of boreholes to facilitate the identification and / or confirmation of geological features. For example, junction measurements associated with a geological feature can be transformed into photographic images of the borehole, which can help determine the location, orientation, magnitude, or general presence of the geological feature. In fact, the downhole imaging techniques described herein can substantially provide photographs of the borehole.

[0036] Furthermore, some conventional borehole surveying and / or characterization methods require specialized tools to be implemented in the borehole by stopping or pausing drilling operations. In some cases, removing drilling tools from the borehole to perform conventional imaging techniques results in costly downtime for the drilling system. The borehole images described herein can be generated based on data acquired during drilling operations, and in some cases, images can also be generated during drilling operations or in real time. In this way, formations can be mapped and / or characterized without the downtime costs of some conventional methods, thus saving costs and resources. Therefore, various and / or any number of images of the borehole can be generated, for example, at any depth of the borehole and / or for any duration (e.g., length) of the borehole. In contrast, the downtime associated with some conventional borehole characterization techniques can impose practical limitations on the extent or duration to which such techniques can be implemented. In practice, the imaging techniques described herein can be practically implemented to image any part (or the entirety) of the borehole with virtually no operational limitations on duration, detail, etc.

[0037] Some conventional borehole exploration and / or characterization methods require specialized tools implemented in the borehole as part of the drilling tool assembly and / or as part of the BHA, such as Measurement While Drilling (MWD) and / or Logging While Drilling (LWD) tools. MWD and LWD tools are typically implemented above or above one or more downhole (e.g., drilling) tools, such as drill bits or reamers. MWD and LWD tools can perform measurements and / or facilitate the generation of borehole-associated images. However, because these tools are located above the drilling tools (e.g., up to 100 feet), any information collected by these measurement tools can only be used to make delayed decisions about the operation of drilling tools located further below the borehole. In other words, MWD and LWD tools cannot be practically implemented to make real-time decisions about, for example, the current junction and / or current formation associated with one or more drilling tools. In contrast, the techniques described herein can be implemented to perform measurements at the junction of one or more drilling tools with the formation. In this way, real-time information related to the proximity of the drilling tools can be used to inform decisions about the operation of the drilling tools.

[0038] Furthermore, while conventional MWD and LWD tools can perform measurements and / or facilitate the generation of borehole images, such measurements and / or images typically have limited resolution. The imaging technique disclosed herein can generate images with improved resolution compared to, for example, conventional borehole images. The manufacture and downhole implementation of MWD and LWD imaging tools are also typically very expensive. Exposing expensive instruments to harsh downhole environments carries the possibility of instrument damage or loss. In contrast, the imaging technique described herein can be achieved through simple and inexpensive instrumentation combined with joining elements that may have been designed and / or configured to withstand harsh downhole environments.

[0039] Furthermore, a technique commonly used to collect and / or analyze specific information about formations is the acquisition of core samples. Special drill bits are used downhole to remove borehole samples and bring them to the surface so they can be analyzed to gather information about the formation. This can be expensive and time-consuming, as it requires stopping drilling operations and removing downhole tools from the borehole. The imaging technique described in this paper can generate virtual core images by incorporating lithological data (e.g., data associated with the physical properties of the formation) into the aforementioned images. In this way, a virtual representation of the core sample can be analyzed to characterize the formation in roughly the same way as conventionally performed methods, but without the costly downtime. Therefore, virtual core images can offer significant cost and resource savings compared to conventional core sampling techniques.

[0040] As illustrated in the foregoing discussion and as will be discussed in further detail herein, this disclosure uses various terms to describe the features and advantages of the methods and systems described herein. Some of these terms will be discussed in further detail below.

[0041] As used herein, a “data feature” can refer to any characteristic or distinguishable instance of data or a portion of data. For example, a data feature can correspond to one or more instances of data above, below, or within a threshold, or instances of threshold variation in data. A data feature can correspond to one or more data instances that occur the number of times a threshold is reached. A data feature can correspond to one or more instances that deviate from or occur outside a threshold level, expected range, or other defined data limit. In fact, a data feature can be any other element, aspect, pattern, variance, outlier, or correlation of data, or a combination thereof.

[0042] As used herein, "borehole feature" can refer to a physical feature present or detected in a borehole. For example, a borehole feature can be a fracture or crack detected in a portion of the borehole. Borehole features can correspond to data features or can be identified based on data features, such as orientation relative to a local reference frame of the borehole. For example, a borehole feature can be an indication of a fracture within the borehole at a 95° angle. In this way, a borehole feature can be a local indication of a physical feature present or detected in the borehole (e.g., in contrast to a global indication of physical features throughout the formation).

[0043] As used herein, “geological feature” can refer to a physical feature present or detected in the strata where the borehole is located. For example, a geological feature can be a fracture or crack detected relative to or associated with a larger stratum. Geological features can correspond to data features and / or borehole features, or can be identified based on data features and / or borehole features, for example, oriented relative to a global reference frame of the entire Earth’s strata. For example, a geological feature can be an indication of a fracture extending from east to west in a stratum. In this way, a geological feature can be a global indication of physical features that are typically present and / or detected in strata.

[0044] As used herein, "borehole image" can refer to an image relating to a borehole in the formation or an image relating to the removal of material from the formation to form the borehole. In some cases, a borehole image can correspond to a completed or full-diameter borehole, such that the image substantially resembles or represents, for example, a view of the inner wall or circumference of a completed borehole. In some cases, a borehole image can correspond to an intermediate or provisional diameter of the borehole, which may be further expanded to the completion diameter. In this way, a borehole image can represent or substantially resemble a borehole wall with a reduced diameter, which may no longer be present in the borehole, or can correspond to formation material that has been removed downhole, making it no longer visible, for example, during physical inspection.

[0045] Figure 1An embodiment of a downhole system is shown. Figure 1 The downhole system is a drilling system 100 used to drill through formation 101 (e.g., a downhole formation) to form a wellbore or borehole 102. In some embodiments, the downhole system is a drilling system, a milling system, a reaming system, a stabilization system, a steering system, other downhole systems, or a combination thereof. The drilling system 100 may include a drilling rig 103 for rotating a drilling tool assembly 104 that extends downward into the borehole 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.

[0046] 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 central bore and transmits rotational power from the drilling rig 103 to the BHA 106. In some embodiments, the rotational power is transmitted by one or more mud motors located in the borehole 102. In some embodiments, the drill string 105 also includes additional components such as short sections, short joints, 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 orifices of selected size in the drill bit 110 to cool the drill bit 110 and the cutting structures thereon, and to remove cuttings from the borehole 102 when it is drilled out.

[0047] BHA 106 may include drill bit 110 or other components. An exemplary BHA 106 may include additional or other components (e.g., coupled 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, reamers, sprue mills, hydraulic disconnectors, slappers, vibration or damping tools, other components, or combinations thereof. BHA 106 may also include a rotary steerable system (RSS). The RSS may include an orientation drilling tool that changes the orientation of drill bit 110, thereby altering the trajectory of borehole 102. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame (e.g., gravity, magnetic north, and / or true north). Using measurements obtained from the geostationary position, the RSS can position drill bit 110, change the path of drill bit 110, and guide the orientation drilling tool along its projected trajectory.

[0048] Typically, drilling system 100 may include other drilling components and accessories, such as specialized valves (e.g., kerb plugs, blowout preventers, and safety valves). Additional components included in drilling system 100 may be considered part of drilling tool assembly 104, drill string 105, or BHA 106, depending on their location within drilling system 100.

[0049] Drilling system 100 may include sensor 111. For example, sensor 111 may be located in a downhole tool of drilling system 100, such as drill bit 110, reamer, stabilizer, or any other downhole tool. Sensor 111 may be an engagement sensor. For example, sensor 111 may perform one or more engagement measurements corresponding to engagement with a borehole. Sensor 111 may be included in an instrumented engagement element implemented in drill bit 110. Sensor 111 may be a force sensor for measuring the forces associated with engagement of the instrumented engagement element with borehole 102. Drill bit 110 in BHA 106 may be any type of drill bit suitable for degrading downhole materials. For example, drill bit 110 may be a drill bit suitable for drilling formation 101. Example types of drill bits used for drilling formations are fixed cutter or scraper bits. In other embodiments, drill bit 110 may be a mill for removing downhole metal, composite materials, elastomers, other downhole materials, or combinations thereof. For example, drill bit 110 can be used with a directional drilling tool to grind into the casing 107 that lines the borehole 102. Drill bit 110 can also be a chip mill for grinding away tools, plugs, cement, other materials, or combinations thereof within the borehole 102. The cutting chips or other debris generated by using the mill can be lifted to the surface or allowed to fall downhole.

[0050] Drilling system 100 may include a computing device 112. The computing device can communicate data with sensor 111 to receive one or more signals from sensor 111. In some embodiments, the computing device 112 is located at the surface of borehole 102. For example, the computing device 112 may be a drilling computer or any other user equipment located at the surface of borehole 102 (e.g., at or associated with drilling rig 103). In some embodiments, the computing device 112 is located within borehole 102. For example, the computing device may be associated with and / or located within a component of a drilling tool assembly, such as a downhole tool (e.g., drill bit 110). The computing device 112 may be positioned immediately adjacent to sensor 111 within borehole 102, or it may be located at another location within borehole 102. In this way, sensor 111 may transmit one or more signals to computing device 112, such as one or more measurements taken within borehole 102.

[0051] The computing device 112 may include a downhole imaging system 120 for performing one or more of the downhole imaging techniques described herein. For example, the computing device may include a processor and a memory. The memory may contain one or more instructions that, when executed, cause the processor to perform one or more functions of the downhole imaging system 120, as will be described in detail herein.

[0052] Figure 2This is a bottom view of the downhole end of an embodiment of drill bit 210. Drill bit 210 may include a drill bit body 213 from which a plurality of blades 214 protrude. At least one of the blades 214 may have a plurality of cutting elements 215 connected thereto. In some embodiments, at least one of the cutting elements 215 is a planar cutting element, such as a shearing cutting element. In other embodiments, at least one of the cutting elements 215 may be a non-planar cutting element, such as a tapered cutting element (e.g., a STINGER™ cutting element) or a ridged cutting element.

[0053] In some embodiments, the drill bit 210 includes an instrumentation engagement element 216. The instrumentation engagement element 216 may include instruments (e.g., sensors) for performing one or more downhole measurements using the drill bit 210. For example, the instrumentation engagement element 216 may include one or more sensors for measuring force, pressure, temperature, etc.

[0054] According to at least one embodiment of this disclosure, the instrumented engagement element 216 includes a sensor engagement element and an engagement sensor. The instrumented engagement element 216 can engage (e.g., contact, press, degrade) a borehole, and the sensor can perform, for example, measurements corresponding to forces on the instrumented engagement element 216. For example, the instrumented engagement element 216 can contact or engage the borehole as the drill bit 210 rotates, and the instrumented engagement element 216 can experience changing dynamics (e.g., forces) as it passes over and / or traverses physical features of the borehole. These changes can be measured by the engagement sensor. The instrumented engagement element 216 can be coupled to a computing device (such as...) Figure 1 The computing device 112 communicates data to transmit one or more signals corresponding to one or more measurements performed by the engagement sensor. In some embodiments, the engagement measurements help create or generate graphs, plots, images, or maps of the engagement between the sensor engagement element and / or the drill bit 210 and the borehole. In some embodiments, the engagement measurements help identify one or more borehole features and / or geological features. In some embodiments, the engagement measurement values ​​may be force measurements, and graphs, plots, images, maps, etc., may be generated based on the force measurements.

[0055] although Figure 2The combined use of instrumented engagement elements 216 with drill bit 210 has been described; however, it should be understood that any downhole tool (e.g., a drill bit) according to any embodiment of this disclosure may include two or more instrumented engagement elements 216. For example, drill bit 210 may include 2, 3, 4, 5 or more instrumented engagement elements 216 for performing multiple measurements. In some embodiments, the instrumented engagement elements 216 are each identically oriented and / or configured. In some embodiments, one or more of the instrumented engagement elements 216 are oriented and / or configured differently from another of the instrumented engagement elements 216. For example, a first engagement element assembly may be oriented to perform engagement measurements corresponding to axial forces, and a second engagement element assembly may be oriented to perform engagement measurements corresponding to rotational forces or torques. In some embodiments, the plurality of instrumented engagement elements 216 are configured with respect to axial forces but positioned at different radii and / or behind different main cutting elements. In some embodiments, the plurality of instrumented engagement elements 216 are configured with respect to rotational forces at the same radius to ensure more accurate measurements. One or more of the plurality of instrumented engagement elements 216 may be oriented and / or configured and / or combined in any other manner to perform one or more measurements associated with the drill bit and / or formation, as described herein.

[0056] The embodiments shown herein illustrate downhole tools (e.g., drill bits) with instrumentation assemblies having various components in a specific configuration and / or orientation. However, it should be understood that the instrumentation assemblies of this disclosure are not limited to implementation solely in drill bits of drilling systems. Rather, the techniques described herein can be used in conjunction with any downhole tool. For example, one or more instrumented engagement elements 216 as described herein can be implemented in reamers, stabilizers, or any other downhole tool (e.g., downhole tools that contact and / or engage the inner wall of a borehole).

[0057] Furthermore, it should be understood that the instrumented engagement element 216 described herein in various embodiments is not limited to a cutting engagement element, or a configuration in which the borehole is cut, lengthened, widened, etc. Therefore, the instrumented engagement element 216 can be any type of engagement element for engaging or mating with a borehole. For example, one or more downhole tools can implement the instrumented engagement element 216 with an ultrahard (e.g., diamond) tip or coating, which is not necessarily intended or limited to cutting formations. For example, a stabilizer may include one or more instrumented engagement elements 216 (such as stabilizer liners) for engaging a borehole for the purpose of stabilizing or centering one or more components of a drilling tool assembly rather than cutting. Such instrumented engagement elements 216 can be implemented to perform the techniques described herein. Other downhole tools can implement other engagement elements for purposes that may not necessarily be limited to cutting boreholes. In other words, the instrumented engagement element 216 described herein can be any engagement element implemented in conjunction with any downhole tool.

[0058] Furthermore, it should be understood that the instrumented engagement element 216 of this disclosure is not limited to the configurations and / or orientations shown and described herein. For example, the instrumented engagement element 216 may be oriented at an angle to the vertical direction, in the radial or outward direction, or in any other orientation for engaging a borehole as described herein. In this way, any type of downhole tool may include instrument assemblies (including engagement elements) having any configuration for performing downhole measurements, and the instrument assemblies may be configured, oriented, and adapted to function in accordance with the manner in which a given downhole tool engages a borehole.

[0059] Figure 3 An exemplary computing device 312 is shown, on which a downhole imaging system 320 is implemented according to at least one embodiment of the present disclosure. In some embodiments, the downhole imaging system 320 includes a sensor data manager 321, a mapping engine 322, a feature detection manager 323, an image generation engine 324, and a communication module 325. In some embodiments, the downhole imaging system 320 includes a data storage device 326. While one or more embodiments described herein describe features and functions performed by specific components 321-325 of the downhole imaging system 320, it should be understood that in some examples, a specific feature described in conjunction with one component of the downhole imaging system 320 may be performed by one or more other components of the downhole imaging system 320.

[0060] For example, as will be discussed below, one or more features of the downhole imaging system 320 may be delegated to other components of the downhole imaging system 320. As another example, while the mapping of sensor data may be performed by the mapping engine 322, in some cases, some or all of these features may be performed by the feature detection manager 323 (or any other component of the downhole imaging system 320). In fact, 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 or more of components 321-325 of the downhole imaging system 320.

[0061] As just mentioned, the downhole imaging system 320 includes a sensor data manager 321. The sensor data manager 321 can receive downhole measurements 317 from one or more sensors 311. For example, the sensors 311 may include engagement sensors and / or rotation sensors, which can transmit engagement and / or rotation measurements to the sensor data manager 321. The downhole measurements 317 may be measurements acquired, for example, in a borehole. The downhole measurements 317 may also be measurements acquired at the surface or any other location. In this way, the downhole measurements are not limited to measurements acquired downhole, but may include any measurements related to downhole drilling or drilling systems, as described herein.

[0062] In some embodiments, sensor data manager 321 receives downhole measurement values ​​317 and records or stores them in data memory 326 as sensor data 327. For example, sensor data manager 321 may store one or more raw signals associated with downhole measurement values ​​317 as sensor data 327. In another example, sensor data manager 321 may perform one or more operations on downhole measurement values ​​317 (e.g., raw signals) to modify, adjust, filter, compress, amplify, segment, and combine one or more of the following. This may be done before storing downhole measurement values ​​317 as sensor data 327, or as a supplement to storing the raw signals of downhole measurement values ​​317 as sensor data 327. In some embodiments, sensor data manager 321 transmits or transfers sensor data 327 to one or more components of downhole imaging system 320, such as mapping engine 322. In this way, downhole imaging system 320 may receive and / or store one or more downhole measurement values ​​317 from sensor 311.

[0063] As described above, the downhole imaging system 320 includes a mapping engine 322. In some embodiments, the mapping engine 322 receives data, such as sensor data 327, from a sensor data manager 321. The mapping engine 322 can also access a data storage device 326 to receive data. The mapping engine 322 can map any data accessible to the downhole imaging system 320. For example, the mapping engine 322 can associate one or more specific instances of data with one or more other specific instances of data. In this way, the mapping engine 322 can generate mapped data 328. The mapping engine 322 can store the mapped data 328 in the data storage device 326.

[0064] As described above, the downhole imaging system 320 includes a feature detection manager 323. In some embodiments, the feature detection manager 323 detects and / or facilitates the detection of data features, borehole features, geological features, other downhole features, or combinations thereof. For example, the feature detection manager 323 may analyze the data it receives (e.g., perform one or more operations on it) to determine data features of the formation and / or corresponding geological features. The feature detection manager 323 may detect features in any data and / or may incorporate any type of data to determine features, such as incorporating user input or incorporating image data. The feature detection manager 323 may generate and / or store indications of the detected features as feature data 329. In this way, the downhole imaging system 320 can identify data features, borehole features, geological features, other downhole features, or combinations thereof.

[0065] As described above, the downhole imaging system 320 includes an image generation engine 324. In some embodiments, the image generation engine 324 generates image data 330 based on any data discussed herein, which may include one or more plots, graphs, images, pictures, maps, any other visual representations, or combinations thereof. For example, image data 330 may present joint measurements (e.g., forces) relative to rotational measurements. The image generation engine 324 may apply color scales and / or color spectra to the data and generate a photographic representation of the borehole in this manner. Color scales / color spectra as described herein may include grayscale scales / spectral data. The image generation engine 324 may merge lithological data with the images and generate a virtual representation of a formation core sample in this manner, including a description of one or more physical properties of the formation. In some embodiments, image data 330 illustrates one or more borehole features and / or geological features. This can facilitate the identification of geological features, such as through a feature detection manager 323. In this way, the downhole imaging system 320 can generate image data 330.

[0066] As described above, the downhole imaging system 320 includes a communication module 325. The communication module 325 can be configured to communicate with one or more drilling rigs. The communication module 325 can transmit any data described herein. The communication module 325 can communicate with one or more drilling rigs located on the surface and / or in the borehole. In this way, data collected and / or processed and / or generated by the downhole imaging system 320 can be transmitted to one or more devices associated with the drilling system.

[0067] In some embodiments, the downhole imaging system 320 includes a data storage device 326 thereon storing various data and / or data types. For example, the data storage device 326 may store one or more of sensor data 327, mapping data 328, feature data 329, and image data 330. In some embodiments, the data storage device 326 stores borehole data 331. The borehole data 331 may include and / or identify information about the borehole relative to the formation or a global reference frame relative to the formation. For example, the borehole data may include the azimuth, dip, and geographic location of the borehole relative to the global reference frame of the formation. The borehole data 331 may include any other information related to a globally oriented borehole.

[0068] The techniques discussed herein (various embodiments of the downhole imaging system described herein) can be discussed in some cases regarding information flow or the transmission of data and / or the transfer of data from one or more components of the downhole imaging system to one or more other components of the downhole imaging system. However, it should be understood that in some cases, such information flow can be an illustrative tool for describing one or more aspects of the invention and does not imply limitation or requirement of information transmission from one component to another. For example, in some cases, one or more components of the downhole imaging system may access a data storage device to access and / or retrieve data, rather than receiving data directly from another component. In this way, one or more data elements can be transferred between various components of the downhole imaging system, and / or various components may access a data storage device to access one or more data elements.

[0069] Figure 4 An exemplary information flow between components of a downhole imaging system 420 according to at least one embodiment of the present disclosure is illustrated. In some embodiments, the downhole imaging system 420 includes a sensor data manager 421, a mapping engine 422, a feature detection manager 423, an image generation engine 424, and a communication module 425.

[0070] As just mentioned, the downhole imaging system 420 includes a sensor data manager 421. The sensor data manager 421 can communicate with one or more sensors 411. The sensor data manager 421 can receive one or more downhole measurements 417 from one or more sensors 411.

[0071] In some embodiments, sensor 411 includes engagement sensor 432. Sensor data manager 421 can receive one or more signals from engagement sensor 432 as engagement data 433. Engagement data 433 may include one or more engagement measurements acquired by engagement sensor 432, for example, corresponding to engagement of a downhole tool (e.g., a drill bit) with a borehole. For example, the drill bit may include an instrumented engagement element, and the instrumented engagement element may include engagement sensor 432. The instrumented engagement element may be configured to engage the borehole, for example, during drilling with the drill bit. The instrumented engagement element may experience dynamics (e.g., axial forces) due to its engagement with the borehole. These dynamics may change as the instrumented engagement element traverses and / or passes over physical features of the borehole (e.g., due to rotation of the drill bit). Engagement sensor 432 may measure the corresponding dynamics and / or changes in dynamics and may send these measurements as engagement data 433 to sensor data manager 421. In some embodiments, sensor data manager 421 stores engagement data 433 in data storage device 426 of downhole imaging system 420. For example, sensor data manager 421 can store the engagement data 433 as part of sensor data 427. In this way, downhole imaging system 420 can receive engagement data 433, and engagement data 433 can be accessed by one or more components of downhole imaging system 420.

[0072] In some embodiments, the engagement data 433 is based on one or more forces experienced or exhibited by the instrumented engagement element or associated therewith. For example, the engagement sensor 432 may measure forces, strain, stress, pressure, deformation, deflection, displacement, any other parameters associated with the engagement of the instrumented engagement element and the borehole, and combinations thereof. In some embodiments, the engagement sensor 432 measures forces directly or via one or more other parameters calibrated for force (e.g., for calculating forces). The engagement sensor 432 may include strain gauges, Hall effect sensors, magnets, capacitive sensors, spring sensors, any other sensors for sensing the dynamics associated with the engagement of the borehole, and combinations thereof.

[0073] In some embodiments, sensor 411 includes a rotation sensor 434. Sensor data manager 421 can receive one or more signals from rotation sensor 434 as rotation data 435. Rotation data 435 may include one or more rotation measurements acquired by rotation sensor 434, for example, a rotational orientation corresponding to engagement data 433. In some embodiments, rotation data 435 measures the rotational movement of one or more sensors 411 (e.g., engagement sensor 432). For example, a BHA component implementing engagement sensor 432 may rotate within or relative to the borehole. Rotation of the BHA (e.g., including a drill bit, reamer, stabilizer, RSS, other BHA components, or combinations thereof) may facilitate and / or correspond to the acquisition and / or measurement of engagement data 433 by engagement sensor 432. In some embodiments, rotation data 435 may not measure the rotational movement of engagement sensor 432, but may instead measure the rotational orientation of engagement data 433 relative to the borehole. For example, rotational data 435 may be measurements of one or more (e.g., static) aspects and / or characteristics of the borehole, and rotational data 435 may be used to oriented join data 433 by associating or mapping one or more data features in join data 433 with borehole characteristics of rotational data 435. For example, aspects and features may be associated to combine downhole data to reflect the actual orientation of borehole characteristics. For example, as Figure 7-1 As shown, the mating data 433 can be aligned based on the corresponding aspects and / or features of the borehole.

[0074] In some embodiments, sensor data manager 421 stores rotational data to data storage device 426. For example, sensor data manager 421 may store rotational data 435 as part of sensor data 427. In this way, downhole imaging system 420 may receive rotational data 435, and rotational data 435 may be accessed by one or more components of downhole imaging system 420, for example, as engagement data 433 for mapping or orientation.

[0075] In some embodiments, sensor 411 includes depth sensor 436. Sensor data manager 421 may receive one or more signals from depth sensor 436 as depth data 437. Depth data 437 may include one or more depth measurements acquired by depth sensor 436, for example, corresponding to the depth of a downhole tool. Depth data 437 may correspond to the depth at which engagement data 433 (or any other downhole measurement 417) is acquired. For example, depth data 437 may indicate the depth of the downhole tool at all instances of engagement data 433. In another example, depth data 437 may indicate the depth of the downhole tool at some instances of engagement data 433 (e.g., at instances of interest in engagement data 433). Depth data 437 may be acquired based on the timing and / or duration of one or more downhole operations. In some embodiments, depth data 437 is associated with rotation data 435. For example, rotation data 435 may identify and / or track each rotation of the downhole tool, and depth data 437 may indicate the depth corresponding to each rotation. In this manner, depth data 437 can facilitate mapping to a depth associated with one or more portions of sensor data 427. In some embodiments, sensor data manager 421 stores depth data 437 as part of sensor data 427. In this way, downhole imaging system 420 can receive depth data 437, and depth data 437 can be accessed by one or more components of downhole imaging system 420.

[0076] In some embodiments, sensor 411 includes a lithology sensor 438. Sensor data manager 421 can receive one or more signals from lithology sensor 438 as lithology data 439. Lithology data 439 may include one or more measurements corresponding to the lithology and / or mineralogical properties of a formation. For example, lithology data 439 may include one or more measurements corresponding to the physical properties of a formation. Measurements may be acquired based on density, resistivity, gamma rays, nuclear spectrum, the magnitude and shape of portions of the formation, any other physical properties, and combinations thereof. Lithology data 439 may facilitate the creation or generation of borehole images, such as virtual core images, as will be discussed in detail herein.

[0077] In some embodiments, lithological data 439 is acquired during borehole drilling. For example, a lithological sensor 438 may be included as part of a BHA. In some embodiments, the lithological sensor 438 is not part of a BHA (such as a wire tool). In some embodiments, lithological data 439 is not acquired during borehole drilling. For example, lithological data 439 may be acquired by analyzing cuttings brought to the surface. In some embodiments, lithological data 439 is acquired during drilling. In some embodiments, lithological data 439 is acquired after drilling operations are stopped or paused. In some embodiments, a sensor data manager 421 stores lithological data 439 as part of sensor data 427. In this way, the downhole imaging system 420 can receive lithological data 439, and lithological data 439 can be accessed by one or more components of the downhole imaging system 420.

[0078] In some embodiments, the downhole imaging system 420 (more specifically, the sensor data manager 421) and other than Figure 4 Data communication may be performed with one or more sensors 411 other than those shown. For example, the sensor data manager 421 may receive downhole measurements 417 from gyroscopes, accelerometers, 1 and / or 2 and / or 3 axial force sensors, light sensors, sound sensors, sensors for measuring electrical properties, temperature sensors, pressure sensors, fluid flow sensors, any other sensors for making measurements related to downhole operations and / or drilling, and combinations thereof. In some embodiments, the sensor data manager 421 does not communicate with... Figure 4 One or more sensors 411 shown receive downhole measurements 417. In this way, sensor data manager 421 can receive downhole measurements 417 from any combination of sensors 411 (including those shown and any other sensors) to facilitate one or more techniques described herein.

[0079] As described above, the downhole imaging system 420 includes a data storage device 426. The data storage device may include various types of data stored thereon, such as sensor data 427. In some embodiments, the data storage device 426 includes borehole data 431. Borehole data 431 may include and / or identify information about the borehole and / or formation. For example, borehole data 431 may include and / or identify the borehole's orientation, length, angle, azimuth, dip, magnitude, other characteristics, or combinations thereof. In some embodiments, borehole data 431 identifies one or more aspects of the borehole relative to the formation. For example, borehole data 431 may identify geographic information associated with the borehole, such as GPS coordinates, latitude and longitude, altitude, geographic location and / or orientation relative to other boreholes or geographic features, basic orientation of the borehole, any other borehole information, or combinations thereof. In this way, borehole data 431 may facilitate the association and / or orientation of one or more portions of sensor data 427 relative to the formation or relative to a geographic and / or global reference frame. For example, one or more techniques described herein may be used to associate and / or orient data relative to the borehole. Borehole data 431 (e.g., geographical and / or global characteristics of borehole data 431) can facilitate the association of that data with respect to stratigraphy or with orientation data within a global framework. This can, for example, help to associate one or more data features and / or borehole features with the geological features of the stratigraphy in which the borehole is located.

[0080] In some embodiments, at least a portion of the borehole data 431 is input to the downhole imaging system 420. For example, geographic information associated with the borehole may be provided to the downhole imaging system 420 (e.g., by a user). In some embodiments, one or more portions of the borehole data 431 may be identifiable by the downhole imaging system 420. For example, the downhole imaging system 420 may communicate with one or more sensors (e.g., via a sensor data manager 421) that can detect and / or measure one or more portions of the borehole data 431. In another example, the downhole imaging system 420 may communicate with one or more computing devices (e.g., drilling rigs) (e.g., via a communication module 425) and may receive one or more portions of the borehole data 431 from these computing devices. In this way, the borehole data 431 may include any data related to a global reference frame of the formation.

[0081] As described above, the downhole imaging system 420 includes a mapping engine 422. The mapping engine 422 can receive one or more portions of sensor data 427 from the sensor data manager 421. For example, the sensor data manager 421 can send engagement data 433 and / or rotation data 435 to the mapping engine 422. The mapping engine 422 can receive any other data accessible to the downhole imaging system 420. The mapping engine 422 can map one or more portions of the data to one or more other portions of the data to generate mapped data 428. For example, the mapping engine 422 can associate a specific instance in the engagement data 433 with a specific angle or rotational position within the borehole based on the rotation data 435 (e.g., to generate oriented engagement data as described herein). In another example, the mapping engine 422 can map oriented engagement data to a geographic or global reference frame based on borehole data 431. In another example, the mapping engine 422 can associate a specific instance in the engagement data 433 with a specific depth within the borehole based on depth data 437. In some embodiments, the mapping engine 422 maps the data by generating or quantifying one or more relationships between datasets. For example, mapping engine 422 can fit a best-fit line to one or more datasets, fit one or more datasets to a line or curve, compensate and / or adjust one or more datasets to correlate with other datasets, correlate one or more datasets with other data, or any other techniques, and combinations thereof. Mapping engine 422 can map any combination of sensor data 427 (or any other data accessible to downhole imaging system 420) as described herein. In this way, mapping engine can generate mapped data 428, which can facilitate one or more of the imaging and / or feature detection techniques described herein.

[0082] In some embodiments, the mapping engine 422 transmits data and / or delivers it to one or more components of the downhole imaging system 420. For example, the mapping engine 422 may send data to a feature detection manager 423. In another example, the mapping engine 422 may transmit data to an image generation engine 424. In yet another example, the mapping engine 422 may transmit data to a communication module 425. In some embodiments, the mapping engine transmits mapping data 428. In some embodiments, the mapping engine transmits sensor data 427, for example, without mapping one or more portions and / or combinations of sensor data 427. The mapping engine 422 may send any other data and / or combinations of data.

[0083] Figure 5An example information flow between components of a downhole imaging system 520 according to at least one embodiment of the present disclosure is illustrated. The downhole imaging system 520 includes a sensor data manager 521 and a mapping engine 522. The sensor data manager 521 can communicate data with one or more sensors and can receive downhole measurements from one or more sensors. The sensor data manager 521 can transmit sensor data to the mapping engine 522.

[0084] According to at least one embodiment of this disclosure, sensor data manager 521 transmits engagement data 533 and rotation data 535 to mapping engine 522. In some embodiments, mapping engine 522 maps engagement data 533 to rotation data 535 and generates oriented engagement data 542. For example, one or more specific instances of oriented engagement data 542 may correspond to one or more rotation angles within the borehole (e.g., 95° within the borehole).

[0085] In some embodiments, rotational data 535 measures the rotational movement of a downhole tool. For example, the rotational sensor associated with rotational data 535 may include a gyroscope, accelerometer, magnetometer, RPM sensor, any other sensor for measuring rotational motion, and combinations thereof. Coupling data 533 may be time-domain coupling data, and mapping engine 522 may map the time-domain coupling data to rotational data 535 to generate oriented coupling data 542 (e.g., force or other dynamics relative to rotational position and / or angle). Rotational data 535, in this manner as a measure of the movement of the downhole tool, can facilitate the acquisition of rotational data 535 during downhole activities such as drilling with a drill bit, reaming with a reamer, stabilizing with a stabilizer, and steer with RSS.

[0086] In some embodiments, rotational data 535 measures the rotational position of the downhole tool, or measures one or more aspects (e.g., static aspects) of the borehole associated with the rotational position of engagement data 533. For example, a rotational sensor may measure and / or detect one or more (e.g., static) aspects of the borehole (including the orientation and / or angular position of these aspects), and a mapping engine 522 may associate these aspects with one or more instances of engagement data 533 to generate oriented engagement data 533 (e.g., to generate oriented engagement data 542). In some embodiments, the rotational sensor measures aspects of the borehole after the engagement sensor (e.g., an instrumented engagement element) has passed or traversed a given position of the borehole. For example, the rotational sensor may be located at a different position on the drilling tool assembly than the engagement sensor. In another example, the rotational sensor may be implemented downhole (e.g., on a cable tool) after drilling operations have stopped or paused (e.g., when the drill string is pulled from the borehole).

[0087] In this manner, in at least one embodiment, the mapping engine 522 can generate oriented engagement data 542 by mapping engagement data 533 to rotation data 535. In some embodiments, the mapping engine 522 transmits the oriented engagement data 542 to one or more components of the downhole imaging system 520. In some embodiments, the mapping engine stores the oriented engagement data 542 in a data storage device of the downhole imaging system 520 (e.g., as a...). Figure 3 Mapping data 328).

[0088] Figure 6 An example information flow between components of a downhole imaging system 620 according to at least one embodiment of the present disclosure is illustrated. The downhole imaging system 620 includes a mapping engine 622 and an image generation engine 624. The mapping engine 622 can map together various combinations of data accessible to the downhole imaging system 620, as described herein. The mapping engine 622 can send data (e.g., mapped data) to the image generation engine 624.

[0089] According to at least one embodiment of this disclosure, mapping engine 622 sends oriented engagement data 642. The oriented engagement data 642 may be engagement data mapped to rotational data so as to be locally oriented relative to an angle or rotational position within the borehole. In some embodiments, mapping engine 622 sends the oriented engagement data 642 to image generation engine 624.

[0090] In some embodiments, image generation engine 624 generates image data 630. Image data 630 may include one or more of a plot, graph, image, picture, map, or any other visual representation. Image generation engine 624 may generate image data 630 based on data received from mapping engine 622. For example, image data 630 may be generated based on orientation engagement data 642. Image data 630 may illustrate a visual representation of orientation engagement data 642. For example, image data 630 may illustrate a specific instance of engagement of orientation engagement data 642 relative to the rotational position or local angle of engagement data within the borehole. Image data 630 may substantially resemble a picture or photograph of the borehole, or more specifically, a picture or photograph of a portion of the borehole engaged or removed by an instrumented engagement element of a downhole tool. For example, discrete intervals, instances, or groups of orientation engagement data 642 may be represented by individual pixels, which, when compiled together, present a photographic representation of the borehole.

[0091] Image data 630 may include or may show or visually distinguish the orientation of engagement data 642. For example, data features may be represented in image data 630 by different colors and / or different color shading. In some embodiments, data features correspond to one or more revolutions (e.g., continuous revolutions) of the downhole tool. Data features may correspond to one or more borehole features. For example, data features may be identified in image data 630 as one or more fractures, cracks, veins, etc., relative to the local orientation of the borehole.

[0092] In some embodiments, borehole features correspond to and / or may help identify one or more geological features in the strata where the borehole is located. For example, a mapping engine can map global geographic data (e.g., Figure 4 The borehole data 431 is mapped to oriented joint data 642. In this way, the joint data can be oriented not only locally relative to the borehole, but also globally, relative to a larger global reference frame (e.g., the formation's reference frame), or a combination thereof. For example, the mapping engine can map local angles and / or rotational positions in the borehole using global directions and / or angles (such as a basic direction and / or azimuth (an angle measured clockwise from north)). In some embodiments, image data 630 includes and / or indicates (e.g., illustrates) a global reference frame. In this way, image data 630 can illustrate and / or may help determine one or more geological features of the formation based on mapping the oriented joint data 642 to a global reference frame.

[0093] Image generation engine 624 is not limited to generating image data 630 based on orientation-based junction data 642, but can generate image data 630 based on any data. For example, image data 630 (and the techniques described in relation to image data 630) can illustrate any combination of sensor data described herein (whether mapped or not). For example, image data 630 can illustrate junction data relative to depth data. Image data 630 can illustrate any combination of sensor data relative to borehole data described herein. In this way, image generation engine 624 can generate image data 630 comprising any number of images illustrating any amount and / or combination of data accessible to downhole imaging system 620.

[0094] Figure 7-1 Figures 7-6 are exemplary image data generated by an image generation engine of a downhole imaging system according to at least one embodiment of the present disclosure. In some embodiments, image data is generated based on any data and / or combinations of data received by the image generation engine.

[0095] In some embodiments, the image generation engine generates images based on orientation-based joining data (e.g., joining data relative to the local orientation of the borehole (e.g., based on rotation data)). Figure 7-1 As shown, the image generation engine can generate image data 730-1. Image data 730-1 may include at least a partial description of orientational bonding data. For example, the image generation engine may apply color scale 743 to the magnitude of the orientational bonding data. Color scale 743 may represent the magnitude of the orientational bonding data based on color or color shading. Color scale 743 may have a minimum value 743-1 and a maximum value 743-2, where the color and / or color shading are at opposite ends of the spectrum. For example, the minimum value 743-1 may be represented by dark color, dark shading, high point density, other visual magnitude indications, or combinations thereof, and the maximum value 743-2 may be represented by light color, light shading, low point density, other visual magnitude indications, or combinations thereof (or vice versa). The orientational bonding data may be segmented into discrete intervals, and color or color shading may be assigned from color scale 743 based on the bonding amount associated with the discrete interval. For example, the discrete interval may be a single measurement (e.g., based on sampling frequency or angle), or it may be a combination of two or more single measurements (e.g., an average value). In this way, discrete intervals with smaller values ​​can be represented by darker colors, and discrete intervals with larger values ​​can be represented by lighter colors (and vice versa). In this way, the orientation-based joining data can be segmented and transposed using color stops 743 into multiple pixels 744 of image data 730-1.

[0096] In some embodiments, pixels 744 are positioned and / or oriented adjacent to each other based on the rotational position and / or borehole angle 741-1 associated with pixel 744. For example, each row resolution of image data 730-1 may consist of sequential pixels corresponding to sequentially joined measurements from the same rotation of the downhole tool. In this way, image data 730-1 can span from 0° borehole angle 741-1 on the first side 745 of the image to 360° borehole angle 741-1 on the second (opposite) side 746 of the image. The borehole angle 741-1 from 0° to 360° can represent a local reference frame for the borehole. Therefore, adjacent (horizontal) resolution lines in image data 730-1 can represent sequential rotations of the downhole tool within the borehole. For example, as Figure 7-1 As shown, the revolutions of the downhole tool are displayed as a sequential decrease in image data 730-1. In this way, the orientation engagement data can be transposed into a photographic representation that is substantially similar to a borehole (or a portion of a borehole engaged by instrumented engagement elements).

[0097] Image data 730-1 may represent or illustrate one or more borehole features. For example, some borehole features may correspond to higher or lower engagement measurements from engagement sensors. These differences (or variations) in magnitude can be shown in image data 730-1. More specifically, image data 730-1 may show cracks in one or more fissures (e.g., voids) of fissure 747 as regions of lower magnitude. Image data 730-1 may illustrate substrate 748 (e.g., formation material) as regions of higher magnitude. The borehole features shown in image data 730-1 may aid in identifying one or more borehole features of interest as described herein (and one or more geological features of interest once oriented to a global reference frame).

[0098] In some embodiments, the image generation engine incorporates and / or displays data and / or combinations of data other than (or instead of) alignment engagement data. For example, image data 730-1 may show or indicate the depth of a downhole tool or the depth associated with alignment engagement data. For example, instead of (or in addition to) the revolutions in image data 730-1, depth may be shown or indicated. In this way, image data 730-1 may indicate the depth (e.g., the depth below the surface) where one or more borehole features are located.

[0099] In some embodiments, the image generation engine generates image data based on borehole data (e.g., geographic data associated with a global reference frame of the borehole). For example, such as Figure 7-2 As shown, the image generation engine can generate image data 730-2. Image data 730-2 can show joined data of (local) orientation relative to a global reference frame. For example, image data 730-2 may include one or more indications of one or more basic directions. In some embodiments, image data 730-2 includes an indication of a global angle or azimuth (degrees clockwise from north). Thus, Figure 7-2 The borehole features shown can be identified as geological features of the strata or associated with geological features of the strata.

[0100] The various image data described herein can help characterize one or more aspects of the formation in which the borehole is located. For example, certain geological features may be of interest in determining where subsurface resources (such as hydrocarbons or geothermal energy) may be located. Certain geological features may be of interest in determining well completion strategies. In this way, in at least one embodiment, image data generated by an image generation engine may be advantageous for the efficient and effective operation of the drilling system, as described herein.

[0101] In some embodiments, the image generation engine generates image data having one or more three-dimensional aspects (or partial three-dimensional aspects). For example, such as Figure 7-3As shown, the image generation engine can generate image data 730-3. Image data 730-3 may include a depiction of a cylinder or partially cylindrical shape. For example, image data 730-2 may include or illustrate a substantially hollow cylinder or cylindrical surface representing a drill hole. In some embodiments, image data 730-3 is Figure 7-1 Image data 730-1 (e.g., flat) is rotated or wound to generate a cylindrical shape. The cylindrical shape can facilitate the visualization or conceptualization of boreholes. This can help identify one or more borehole features. The cylindrical shape can also help oriented image data 730-3 relative to a geographic or global reference frame to determine one or more geological features of a formation, as described herein. For example, a cylindrical image can show a borehole in its correct orientation relative to a global reference frame. This can help identify and / or determine the location of one or more geological features in the formation corresponding to the borehole features shown in the borehole (e.g., the borehole features shown in the cylindrical image of image data 730-3).

[0102] In some embodiments, the image generation engine generates image data that illustrates or combines two or more images. For example... Figure 7-4 As shown, the image generation engine can generate image data 730-4. Image data 730-4 can be based on two or more sets of data and / or combine two or more images. For example, two or more sets of engagement data and / or orientation engagement data can be acquired and / or generated from two or more sensors (e.g., acquired with two or more instrumented engagement elements of a drill bit). Two different images representing boreholes (or portions of boreholes engaged or removed by each instrumented engagement element) at different radii of the downhole tool can be generated. Two images can be combined to generate image data 730-4. Image data 730-4 can provide additional resolution or additional information about the borehole. For example, image data 730-1, 730-2, and 730-3 can be limited to information captured or measured in a two-dimensional surface represented by rotation of the downhole tool at a specific radius. However, image data 730-4, composed of two or more images, can provide additional information by combining two or more two-dimensional surfaces associated with different radii of the downhole tool. Any number of images corresponding to different radii can be combined to generate image data 730-4.

[0103] In some embodiments, supplementary data is interpolated between two or more images of image data 730-4. The space between images, or the gaps between data from two images, can be filled or augmented with supplementary (interpolated) data to generate a stereoscopic three-dimensional representation of the borehole. For example, the junction data of two sets of orientations can be the basis for two images, and the junction data of supplementary orientations can be interpolated from the junction data of the two sets of orientations or from the two images. In this way, image data 730-4 can be made more robust by providing and / or showing more junction data via a stereoscopic three-dimensional representation. This can help to better identify boreholes and / or geological features in image data 730-4, for example, by increasing the confidence that borehole features identified in image data 730-4 are actually present in the borehole. For example, borehole features appearing on more than one image in multiple images of image data 730-4 can correspond to an increased probability (e.g., the opposite of sensor error) that the indicated borehole features are actually present in the borehole. In this way, various types of images can be generated from sensor data to represent one or more aspects of the borehole and / or formation.

[0104] In some embodiments, the image generation engine generates virtual core samples of the borehole. For example, such as... Figure 7-5 As shown, the image generation engine can generate image data 730-5. Image data 730-5 can at least partially incorporate and / or represent lithological data. The lithological data can correspond to one or more characteristics and / or physical properties of a formation (or more specifically, a portion of a formation removed by downhole tools and / or instrumented bonding elements, hereinafter referred to as "formation core"). Image data 730-5 can represent lithological data relative to or applied to bonding data (or oriented bonding data). As an example, Figure 7-1 Image data 730-1 illustrates junction data for areas with relatively high and / or low (and / or intermediate or other) magnitudes. In this way, image data 730-1 can illustrate one or more data features, borehole features, geological features, other downhole features, or combinations thereof. This can be illustrated by applying lithological data to the junction data for orientation (e.g., Figure 7-1 Image data 730-5 is generated from image data 730-1. For example, this can illustrate one or more aspects of the material composition, grain or crystal size, and orientation of one or more aspects of the formation core. Image data 730-5 can show other characteristics of the formation core, such as formation boundaries, formation boundary orientation, mineral composition (or other mineralogical properties), chemical composition (or other chemical properties), texture, porosity, permeability, any other characteristics of the formation core, and combinations thereof. In this way, in at least one embodiment, image data 730-5 can be a virtual core of a borehole or formation core.

[0105] Virtual core samples from image data 730-5 can offer numerous benefits. For example, virtual core samples providing lithological data can inform decisions regarding drilling techniques, equipment selection, completion strategies, etc., based on one or more physical characteristics of the formations indicated by the virtual core. For instance, knowing information about the material composition of the formation can help identify formations more prone to collapse or erosion during drilling, formations more likely to have high oil and gas production, formation permeability, other formation characteristics, or combinations thereof. In this way, virtual core samples can aid in making critical decisions regarding the operation of the drilling system.

[0106] Figure 8 An example information flow between components of a downhole imaging system 820 according to at least one embodiment of the present disclosure is illustrated. In some embodiments, the downhole imaging system 820 includes a mapping engine 822 and a feature detection manager 823. As described herein, the mapping engine 822 can map together various combinations of data accessible to the downhole imaging system 820. The mapping engine 822 can send data (e.g., mapped data) to the feature detection manager 823.

[0107] Feature detection manager 823 may receive and / or access any data accessible to downhole imaging system 820. For example, feature detection manager 823 may receive sensor data, mapping data (e.g., orientation engagement data), image data, borehole data, any other type or form of data, and combinations thereof. According to at least one embodiment of this disclosure, feature detection manager 823 receives mapping data 828. Feature detection manager 823 may receive mapping data 828 from mapping engine 822, or may access the data storage device of downhole imaging system 820 to receive data. Mapping data 828 may be any data that has been at least partially mapped to any other data (e.g., sensor data). For example, mapping data may be orientation engagement data as described herein. In some embodiments, mapping data 828 is orientation engagement data that has been mapped to a global reference frame, for example, based on borehole data as described herein.

[0108] In some embodiments, the feature detection manager 823 detects data feature data in the data it receives. For example, the feature detection manager may perform one or more operations on the data from the downhole imaging system 820 to analyze the data and detect data features. As described herein, a data feature may be one or more instances of interest in the data (e.g., instances of force or changes in force at a threshold level). In some embodiments, a data feature may be an instance of interest in the data due to the periodicity of the instance. For example, one or more data features may occur periodically relative to the rotational orientation of the data or relative to the rotation of the downhole tool. Data features may appear in substantially the same or similar or adjacent locations with respect to each cycle or rotation. In this way, multiple and / or consecutive rotations of the data (e.g., of the downhole tool) may together form a data feature, or a data feature may be of interest due to the repetitiveness and / or periodicity of the data feature. In this way, frequently occurring and / or periodic data features may correspond to and / or indicate one or more borehole features and / or geological features.

[0109] The feature detection manager 823 can detect data features in any data and / or combinations of data (e.g., mappings) it receives. For example, the feature detection manager 823 can detect features in mapped data 828. In another example, the feature detection manager 823 can detect data features in oriented joining data, as described herein. The feature detection manager can also detect data features in image data it receives, for example, from the image generation engine of the downhole imaging system 820.

[0110] According to at least one embodiment of this disclosure, a feature detection manager 823 detects data features in oriented junction data mapped to and / or oriented to a global reference frame of the strata. In this way, the detected data features may correspond to geological features of the strata, as described herein. Also in this way, in at least one embodiment, the determination of geological features of the strata may be based on mapping oriented junction data to a global reference frame.

[0111] In some embodiments, the feature detection manager 823 provides indications of detected data features. For example, the feature detection manager 823 may generate feature data 829. Feature data 829 may include one or more flags, tags, markers, or alarms, or combinations thereof, indicating the detected data features. In some embodiments, feature data 829 indicates detected data features, for example, regarding or relative to data received and / or input to the feature detection manager 823. In some embodiments, feature data 829 indicates detected data features separate from the input data. The feature detection manager 823 may store feature data 829 in the data storage device of the downhole imaging system 820.

[0112] In some embodiments, the feature detection manager 823 facilitates the detection of one or more data features. For example, the feature detection manager 823 may incorporate one or more inputs from a user to identify, detect, verify, or authenticate data features or combinations thereof. The feature detection manager 823 may present data and / or facilitate the presentation of data to a user (e.g., through printout, readout, graphical user interface, or a combination thereof) to receive user input associated with the detected data features. In this way, user interaction with the downhole imaging system 820 can be incorporated into the detection of data features by or utilizing the feature detection manager 823.

[0113] In some embodiments, feature data 829 indicates and / or facilitates the detection of one or more borehole features. For example, the detected data features may correspond to one or more physical features (e.g., slots) present and / or detected in the borehole. The detected data features may be locally oriented relative to the borehole (e.g., orientation-based engagement data) and correspond to borehole features in this way. Thus, feature data 829 may indicate, for example, the presence (or detection) of a slot in the borehole at a given angle (e.g., 95°).

[0114] In some embodiments, feature data 829 indicates and / or facilitates the detection of one or more geological features. For example, the detected data features may correspond to one or more physical features (e.g., fractures) about a larger stratum in which the borehole is located. The detected data features may correspond to geological features relative to a global formation orientation (e.g., based on mapping the alignment data to a global reference frame). Thus, in at least one embodiment, feature data 829 may indicate, for example, that the stratum has fractures oriented in a given direction (e.g., from east to west).

[0115] In some embodiments, the feature detection manager 823 includes and / or implements one or more machine learning models to generate feature data 829 and / or detect one or more features. For example, the machine learning model may receive one or more inputs, such as sensor data, mapping data, image data, borehole data, any other data from the downhole imaging system 820, or combinations thereof, and may generate one or more outputs, such as data features, borehole features, and geological features, or combinations thereof. In the example, the machine learning model may be trained to detect one or more geological features of a formation based on received globally oriented junction data. The machine learning model may implement one or more of classification models, regression models, decision tree models, clustering models, association models, any other models, and combinations thereof.

[0116] Training data can be used to train machine learning models. For example, sensor data, mapping data, image data, etc., corresponding to known boreholes or portions thereof can be provided as training features, and an indication of one or more geological features (or the absence of geological features) can be provided as ground reality. The machine learning model can implement one or more machine learning network layers (e.g., neural network layers). For example, a machine learning model can include input layers, hidden layers, output layers, and combinations thereof. The input layer can encode input data features corresponding to the input data into a numerical representation. The hidden layer can map and / or encode the input data into a feature vector. The output layer can process the feature vector to decode geological feature information from the input data to identify and / or predict geological features. The loss model can determine the error and / or loss amount corresponding to the predicted indication of geological features (or the absence of geological features) output by the machine learning model (e.g., by comparison with ground reality). The loss model can provide feedback to the machine learning model to adjust the machine learning model (e.g., adjust one or more layers). In this way, the machine learning model can be iteratively adjusted or trained to learn a set of best-fit parameters that accurately generate indications of geological features (or the absence of geological features) in the strata. In this way, the geological features of the formation can be determined based on any data from the downhole imaging system 820.

[0117] In some embodiments, the feature detection manager 823 performs one or more operations on the received image data (e.g., image data 730-1 to 730-5). For example, the feature detection manager 823 may alter, filter, smooth, reduce noise, or segment the image data. This can facilitate the detection of one or more features (e.g., data features, borehole features, or geological features) in the data. For example, the feature detection manager 823 may alter the image data to locate discrete data objects in the image data, which can help identify data features. In some embodiments, the feature detection manager 823 stores the altered image data as feature data 829 in the data storage device of the downhole imaging system 820.

[0118] In some embodiments, the feature detection manager 823 morphologically opens the image data. For example, erosion and dilation operations can be applied to the image data to remove small data objects and / or smooth object boundaries while preserving larger structures in the image data. In another example, objects that may contact and / or overlap in the image data can be separated while preserving their magnitude and / or shape. In this way, in at least one embodiment, unwanted structures can be removed from the image data and / or image noise can be reduced. This can facilitate the identification of, for example, geological features of interest in the data. For example, the image data may include one or more geological features of different types. A first type of geological feature can be identified in the image, and these features can be removed while a second type of geological feature is preserved in the image data by morphologically opening the image data. In another example, the first type of geological feature can be highlighted or distinguished from the second type of geological feature by morphologically opening the image data. In this way, in at least one embodiment, the image data can be filtered to remove unwanted features, and / or separate and / or distinguish features of interest.

[0119] In some embodiments, a first portion of image data is morphologically opened based on a first type of geological feature (e.g., based on a first structured element), and a second portion of image data can be morphologically opened based on a second type of geological feature (e.g., based on a second structured element). In some embodiments, the first and second portions of image data are combined after morphological opening to together illustrate the first and second types of geological features. This can facilitate the removal of different types of geological features and / or unwanted geological features from the image data. Image data can be morphologically opened 2, 3, 4, 5, or more times based on 2, 3, 4, 5, or more types of geological features. In this way, any number of types of geological features can be identified, removed, highlighted, differentiated, etc.

[0120] In some embodiments, the feature detection manager 823 extracts summary statistics from the image data. For example, the summary statistics may be associated with the dimension, orientation, dynamics (such as force), frequency of occurrence, or any other characteristic (e.g., geological features) of objects identified in the image data, or combinations thereof. The feature detection manager 823 may calculate and / or generate the mean, median, percentile, standard deviation, range, quartiles, other statistical values, or combinations thereof for one or more characteristics of discrete objects identified in the image data. The summary statistics may be presented in the form of histograms, curves, tables, plots, graphs, any other representation, or combinations thereof. The summary statistics may be stored as feature data 829 in the data storage device of the downhole imaging system.

[0121] Figure 9An example information flow between components of a downhole imaging system 920 according to at least one embodiment of the present disclosure is illustrated. In some embodiments, the downhole imaging system 920 includes a mapping engine 922 and a communication module 925.

[0122] In some embodiments, the communication module 925 receives data. For example, the communication module 925 may receive sensor data, mapping data, image data, feature data, borehole data, any other data accessible to the downhole imaging system 920, or a combination thereof. In some embodiments, the communication module 925 receives data from the mapping engine 922. In some embodiments, the communication module 925 receives data by accessing the data storage device of the downhole imaging system 920. According to at least one embodiment of this disclosure, the communication module may receive orientation engagement data 942 (e.g., from the mapping engine 922). The orientation engagement data 942 may include engagement data based on rotational data relative to the local orientation of the borehole, as described herein. The communication module 925 may transmit any data it receives.

[0123] The communication module 925 can be configured to communicate with one or more downhole devices 919 (e.g., drilling devices, milling devices, reaming devices, stabilizing devices, steering devices, other downhole devices, or combinations thereof). In some embodiments, the communication module 925 is configured to communicate with the downhole device 919 via a physical data connection. For example, the communication module 925 may include or communicate with one or more physical data ports for electronically transmitting information via cable and / or wired connections. In some embodiments, the communication module 925 is configured to communicate wirelessly with the downhole device 919. For example, the communication module 925 can be configured to wirelessly communicate using Bluetooth, Near Field Communication (“NFC”), Wi-Fi, LoRa, Industrial Internet of Things (“IoT”) protocols, or any other form of wireless communication. In some embodiments, the communication module 925 is configured for remote wireless communication, such as GPS, radio, cellular networks, etc. In this respect, wireless communication can have the benefits of faster, more efficient, or more convenient transmission and / or data transfer.

[0124] In some embodiments, downhole device 919 includes computing devices located at the surface of the borehole. For example, downhole device 919 may include computing devices associated with the drilling rig of the drilling system, mobile devices, or any other type of computing device, and communication module 925 may transmit data to the computing devices at the surface. In some embodiments, downhole device 919 includes computing devices located within the borehole. For example, one or more components of the drilling system located within the borehole may include computing devices, and communication module 925 may transmit data to the computing devices within the borehole. One or more components of downhole imaging system 920 may be located within the borehole or at the surface. For example, computing devices implementing downhole imaging system 920 may include computing devices located on downhole tools and / or may include surface computing devices. In this way, communication module 925 may transmit data to any number of downhole devices 919 located at any location relative to the drilling system.

[0125] Figure 10 A flowchart is shown for a method 1060 or a series of actions for using a downhole imaging system as discussed herein, according to at least one embodiment of this disclosure. Although Figure 10 Actions according to one embodiment are shown, but alternative embodiments may omit, add, reorder, or modify them. Figure 10 Any action shown.

[0126] Method 1060 may include action 1061 identifying engagement data from an engagement sensor. The engagement data may correspond to engagement with a borehole. For example, a downhole tool may include an instrumented engagement element with an engagement sensor. The instrumented engagement element may be located and / or positioned within the downhole tool to engage the borehole wall. The engagement data may correspond to engagement between the instrumented engagement element and a borehole in the formation. In some embodiments, engagement data is acquired or measured during operation of the downhole tool. For example, engagement data may be acquired while drilling with a drill bit. In some embodiments, the instrumented engagement element is located in the blades of the downhole tool. In some embodiments, the engagement sensor is a force sensor, and the engagement data is force data.

[0127] Method 1060 may include an action 1062 identifying rotational data from a rotational sensor. For example, the rotational data may correspond to the rotational orientation of engagement data relative to the borehole. The rotational sensor may acquire or measure the rotational data. For example, the rotational sensor may include one or more of a magnetometer, inclinometer, gyroscope, other rotational sensors, or combinations thereof. In some embodiments, the rotational data is acquired during operation of the downhole tool (e.g., during drilling).

[0128] Method 1060 may include an action 1063 of mapping the joining data to rotational data to generate oriented joining data. For example, one or more instances of the joining data may be mapped to or associated with one or more instances of rotational position or angle of the rotational data. In this way, the joining data may be oriented relative to the borehole (e.g., locally). In some embodiments, the oriented joining data is mapped to a global reference frame. For example, the oriented joining data may be mapped to one or more of the borehole's azimuth, dip, latitude and longitude, other reference frames, or combinations thereof.

[0129] In some embodiments, mapping the joint data includes generating an image of the borehole. Generating the image of the borehole may be based on oriented joint data. The image may present and / or illustrate the oriented joint data. In other words, the image may present and / or illustrate the joint data relative to rotational data. The image may illustrate the geological features of the formation. In some embodiments, generating the image is based on mapping the oriented joint data to depth data. For example, the image may illustrate the oriented joint data relative to depth data. In some embodiments, generating the image includes applying color scales as described above to represent the magnitude of the oriented joint data. In some embodiments, the image may be generated during downhole operations such as drilling (e.g., using downhole tools).

[0130] In some embodiments, mapping the junction data includes determining geological features of the formation. For example, a geological feature may be a fracture or crack in the formation. Geological features may be determined based on mapping the oriented junction data to a global reference frame. For example, mapping the oriented junction data to a global reference frame may include mapping the oriented junction data to one or more of the following: borehole azimuth, borehole dip, borehole latitude and longitude, other reference frames, or combinations thereof. In some embodiments, determining geological features includes defining data features and identifying one or more instances of data features associated with multiple consecutive revolutions of the downhole tool. For example, a data feature may correspond to a threshold variation in the magnitude of the oriented junction data. In some embodiments, the method includes transmitting the oriented junction data to the drilling rig.

[0131] Figure 11 A flowchart is shown for a method 1160 or a series of actions for using a downhole imaging system as discussed herein, according to at least one embodiment of this disclosure. Although Figure 11 Actions according to one embodiment are shown, but alternative embodiments may omit, add, reorder, or modify them. Figure 11 Any action shown.

[0132] Method 1160 may include action 1161 identifying engagement data from an engagement sensor. The engagement data may correspond to engagement with a borehole. For example, a downhole tool may include an instrumented engagement element with an engagement sensor. The instrumented engagement element may be located and / or positioned within the downhole tool to engage the borehole wall. The engagement data may correspond to engagement between the instrumented engagement element and a borehole in the formation. In some embodiments, engagement data is acquired or measured during operation of the downhole tool. For example, engagement data may be acquired while drilling with a drill bit. In some embodiments, the instrumented engagement element is located in the blades of the downhole tool. In some embodiments, the engagement sensor is a force sensor, and the engagement data is force data.

[0133] Method 1160 may include an action 1162 of identifying depth data from a depth sensor. The depth data may correspond to the depth of the engagement data relative to the borehole. In some embodiments, the depth data is acquired during the operation of the downhole tool (e.g., during drilling).

[0134] Method 1160 may include an action 1163 of mapping joint data to depth data to generate mapped joint data. In some embodiments, the mapped joint data is sent to a drilling rig. In some embodiments, mapping the joint data includes generating an image of the borehole based on the mapped data. For example, the image may present the joint data relative to depth data. The image may show one or more geological features of the formation. In some embodiments, mapping the joint data includes determining borehole features based on mapping the joint data to the depth data.

[0135] Figure 12 A flowchart is shown for a method 1260 or a series of actions for using a downhole imaging system as discussed herein, according to at least one embodiment of this disclosure. Although Figure 12 Actions according to one embodiment are shown, but alternative embodiments may omit, add, reorder, or modify them. Figure 12 Any action shown.

[0136] Method 1260 may include an action 1261 identifying engagement data from an engagement sensor. The engagement data may correspond to engagement with a borehole. For example, a downhole tool may include an instrumented engagement element with an engagement sensor. The instrumented engagement element may be located and / or positioned within the blades of the downhole tool. The engagement data may correspond to engagement between the instrumented engagement element and a borehole in the formation. In some embodiments, engagement data is acquired or measured during operation of the downhole tool. For example, engagement data may be acquired while drilling with a drill bit. In some embodiments, the engagement sensor is a force sensor, and the engagement data is force data.

[0137] Method 1260 may optionally be performed from action 1261 to one or both of actions 1262 and 1263. For example, method 1260 may perform action 1262 to identify rotational data from a rotation sensor. For example, the rotational data may correspond to the rotational orientation of the engagement data relative to the borehole. Alternatively, method 1260 may perform action 1263 to identify depth data from a depth sensor. For example, the depth data may correspond to the depth of the engagement data relative to the borehole. In this way, method 1260 may include either action 1262 or action 1263.

[0138] Method 1260 may include action 1264 of identifying lithological data from a lithology sensor. For example, the lithological data may correspond to one or more physical properties of a formation.

[0139] Method 1260 may include an action 1265 of mapping joint data. For example, the joint data may be mapped to lithological data. Additionally, depending on which of actions 1262 or 1263 is performed in the method, the joint data may be mapped to either rotational data or depth data (or both). In this way, mapped joint data can be generated. In some embodiments, mapping the joint data includes generating a virtual core image of the borehole based on the mapped joint data. For example, the virtual core image may show lithological data relative to the joint data. The virtual core image may show the geological features of the formation. In some embodiments, mapping the joint data includes determining the geological features of the formation based on the mapped joint data.

[0140] Figure 13 A flowchart illustrating a method or series of actions for using a downhole imaging system as discussed herein, according to at least one embodiment of this disclosure, is shown. Although Figure 13 Actions according to one embodiment are shown, but alternative embodiments may omit, add, reorder, or modify them. Figure 13 Any action shown.

[0141] Method 1360 may include action 1361 identifying engagement data from an engagement sensor. The engagement data may correspond to engagement with a borehole. For example, a downhole tool may include an instrumented engagement element with an engagement sensor. The instrumented engagement element may be located and / or positioned within the blades of the downhole tool. The engagement data may correspond to engagement between the instrumented engagement element and a borehole in the formation. In some embodiments, engagement data is acquired or measured during operation of the downhole tool. For example, engagement data may be acquired while drilling with a drill bit. In some embodiments, the engagement sensor is a force sensor, and the engagement data is force data.

[0142] Method 1360 may include action 1362 defining data features in the conjoined data. For example, data features may correspond to one or more instances of interest in the conjoined data, such as measurements exceeding a threshold level or changes in measurements exceeding a threshold level.

[0143] Method 1360 may include action 1363 to determine geological features of the formation. Determining geological features may be based on identifying multiple instances of data features, each instance occurring periodically with respect to rotation of the downhole tool. For example, data features may occur during multiple rotations of the downhole tool (e.g., consecutively). Data features may occur at the same or similar (or adjacent) locations with respect to rotation of the downhole tool. This may indicate or may be associated with physical features of the borehole repeatedly sensed by engagement sensors, and in this way, engagement data may correspond to or may be attributed to geological features in the formation.

[0144] Figure 14 A flowchart is shown for a method 1460 or a series of actions for using a downhole imaging system as discussed herein, according to at least one embodiment of this disclosure. Although Figure 14 Actions according to one embodiment are shown, but alternative embodiments may omit, add, reorder, or modify them. Figure 14 Any action shown.

[0145] Method 1460 may include action 1461 identifying first engagement data from a first engagement sensor. The first engagement data may correspond to a first engagement with a borehole. For example, a downhole tool may include a first instrumented engagement element having a first engagement sensor. The first instrumented engagement element may be located and / or positioned within the cutting edge of the downhole tool. The first engagement data may correspond to a first engagement of the first instrumented engagement element with a borehole in the formation. In some embodiments, the first engagement data is acquired or measured during operation of the downhole tool. For example, the first engagement data may be acquired while drilling with a drill bit. In some embodiments, the first engagement sensor is a first force sensor, and the first engagement data is first force data.

[0146] Method 1460 may include action 1462 identifying second engagement data from a second engagement sensor. The second engagement data may correspond to a second engagement with the borehole. For example, the second engagement sensor may be included on a second instrumented engagement element implemented on a downhole tool (or a second downhole tool).

[0147] In another example, a second engagement sensor may be included on the first instrumented engagement element. For example, first engagement data and second engagement data may correspond to the engagement of the first instrumented engagement element with the borehole wall. The first engagement data and second engagement data may each correspond to different aspects of the engagement between the first instrumented engagement element and the borehole. For example, the first and second engagement data may each represent different dynamics (e.g., force and strain). In another example, the first and second engagement data may each represent the same dynamics, but in different ways, or relative to different axes (e.g., normal force and shear force). Thus, the first and second engagement data may correspond to the engagement of the same (first) instrumented engagement element with the borehole, but due to differences in data characteristics, they may correspond to the first and second engagements of the engagement element (respectively) with the borehole.

[0148] In some embodiments, second engagement data is acquired or measured during the operation of the downhole tool. For example, the second engagement data may be acquired while drilling with a drill bit. In some embodiments, the second engagement sensor is a second force sensor, and the second engagement data is second force data.

[0149] Method 1460 may include action 1463 of mapping first bonding data to second bonding data. This may generate mapped bonding data. For example, one or more instances of the first bonding data may be mapped to or associated with one or more instances of the second bonding data. In some embodiments, mapping the first and second bonding data may be based on the relationship between the first and second bonding data. For example, mapping may include fitting a best-fit line to the first and second bonding data. Mapping may include fitting the first and second bonding data to a curve or a straight line. Mapping may include adjusting and / or compensating the first and / or second bonding data to associate them with another set of data (or any other data). Mapping may include any other techniques for associating the first bonding data with the second bonding data, as well as combinations of techniques discussed herein.

[0150] Figure 15 Some components that may be included within a computer system are shown. One or more computer systems may be used to implement the various devices, components, and systems described herein.

[0151] Computer system 1500 includes processor 1501. Processor 1501 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 1501 can be referred to as a central processing unit (CPU). Although in Figure 15The computer system 1500 shows only a single processor 1501, but in alternative configurations, a combination of processors (e.g., ARM and DSP) can be used.

[0152] Computer system 1500 also includes memory 1503 that is in electronic communication with processor 1501. Memory 1503 can be any electronic component capable of storing electronic information. For example, memory 1503 can be embodied as random access memory (RAM), read-only memory (ROM), disk storage medium, optical storage medium, flash memory in RAM, onboard memory included in the processor, erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), registers, etc., including combinations thereof.

[0153] Instruction 1505 and data 1507 may be stored in memory 1503. Instruction 1505 may be executed by processor 1501 to implement some or all of the functions disclosed herein. Executing instruction 1505 may involve using data 1507 stored in memory 1503. Any of the various examples of modules and components described herein may be implemented, in part or in whole, as instruction 1505 stored in memory 1503 and executed by processor 1501. Any of the various examples of data described herein may be data 1507 stored in memory 1503 and used during the execution of instruction 1505 by processor 1501.

[0154] The computer system 1500 may also include one or more communication interfaces 1509 for communicating with other electronic devices. The communication interface 1509 may be based on wired communication technology, wireless communication technology, or both. Some examples of the communication interface 1509 include Universal Serial Bus (USB), Ethernet adapter, wireless adapter operating according to the Institute of Electrical and Electronics Engineers (IEEE) 1102.11 wireless communication protocol, and Bluetooth. ® Wireless communication adapter and infrared (IR) communication port.

[0155] Computer system 1500 may also include one or more input devices 1511 and one or more output devices 1513. Some examples of input devices 1511 include keyboards, mice, microphones, remote control devices, buttons, joysticks, trackballs, touchpads, and light pens. Some examples of output devices 1513 include speakers and printers. A particular type of output device typically included in computer system 1500 is a display device 1515. Display devices 1515 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 1517 may also be provided for converting data 1507 stored in memory 1503 into text, graphics, and / or moving images (as applicable) displayed on display device 1515.

[0156] Various components of the computer system 1500 can be connected together via one or more buses, which may include power buses, control signal buses, status signal buses, data buses, etc. For clarity, the various buses are... Figure 15 It is shown as bus system 1519.

[0157] Unless specifically described as being implemented in a particular manner, the techniques described herein can be implemented in hardware, software, firmware, or any combination thereof. Any features described as modules, components, etc., may also be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be implemented at least in part by 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 may be organized into routines, programs, objects, components, data structures, etc., which may perform specific tasks and / or implement specific data types, and may be combined or distributed as needed in various embodiments.

[0158] Computer-readable media can 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 storage medium (device). A computer-readable medium carrying computer-executable instructions is a transmission medium. Therefore, by way of example and not limitation, embodiments of this disclosure may include at least two distinct types of computer-readable media: a non-transitory computer-readable storage medium (device) and a transmission medium.

[0159] Non-transitory computer-readable storage media (devices) and transmission media can both be temporarily used to store or carry software instructions in the form of computer-readable program code that allows the execution of embodiments of the present disclosure. Non-transitory computer-readable storage 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 devices (e.g., CD, DVD, HDDVD, Blu-ray, etc.), storage devices (e.g., disk storage devices, magnetic tape storage devices, floppy disks, etc.), flash memory or other solid-state storage devices or memories, or any other non-transmission medium 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 as software, hardware, firmware, or a combination thereof, or stored in software, hardware, firmware, or a combination thereof.

[0160] 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, and / or other electronic devices. 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 communication networks and / or data links, carrier waves, wireless signals, 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] 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 (and vice versa). For example, computer-executable instructions or data structures received via a network or data link can be buffered 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.

[0162] Industrial application

[0163] This disclosure includes numerous practical applications having the features described herein, which provide benefits and / or solve problems associated with identifying geological features and / or characterizing formations. Some example benefits are discussed herein in conjunction with a variety of features and functionalities provided by downhole imaging systems implemented on one or more computing devices. It should be understood that the benefits explicitly discussed in relation to one or more embodiments described herein are provided by way of example only and are not intended to exhaustively list all possible benefits of downhole imaging systems, nor are they intended to limit the scope of the claims.

[0164] For example, identifying and / or mapping the geological features and / or structure of formations or reservoirs can be crucial for the effective planning and execution of drilling operations. The downhole imaging techniques discussed in this paper can detect and / or facilitate the detection of geological features of formations, such as fractures, cracks, formation boundaries, formation angles, etc. Identifying and / or understanding such geological features can be invaluable for determining, for example, where subsurface resources may be located, how to drill through and / or penetrate certain formations, completion strategies, risk factors associated with certain formations, and other factors. Therefore, implementing the downhole imaging techniques described herein to detect and / or map the geological features of formations can provide significant cost, time, and / or resource savings by offering a better understanding of the formation being drilled and increased confidence in features assumed to exist within the formation.

[0165] In addition to the usual detection of geological features, the downhole imaging techniques described herein can generate images of boreholes to facilitate the identification and / or confirmation of geological features. For example, junction measurements associated with a geological feature can be transformed into photographic images of the borehole, which can help determine the location, orientation, size, or general presence of the geological feature. In fact, the downhole imaging techniques described herein can substantially provide photographs of the borehole.

[0166] Furthermore, some conventional borehole surveying and / or characterization methods require specialized tools to be implemented in the borehole by stopping or pausing drilling operations. In some cases, removing drilling tools from the borehole to perform conventional imaging techniques results in costly downtime for the drilling system. The borehole images described herein can be generated based on data acquired during drilling operations, and in some cases, images can also be generated during drilling operations or in real time. In this way, formations can be mapped and / or characterized without the downtime costs of some conventional methods, thus saving costs and resources. Therefore, various and / or any number of images of the borehole can be generated, for example, at any depth of the borehole and / or for any duration (e.g., length) of the borehole. In contrast, the downtime associated with some conventional borehole characterization techniques can impose practical limitations on the extent or duration to which such techniques can be implemented. In practice, the imaging techniques described herein can be practically implemented to image any part (or the entirety) of the borehole with virtually no operational limitations on duration, detail, etc.

[0167] Some conventional borehole exploration and / or characterization methods require specialized tools implemented in the borehole as part of the drilling tool assembly and / or as part of the BHA, such as Measurement While Drilling (MWD) and / or Logging While Drilling (LWD) tools. MWD and LWD tools are typically implemented above or above one or more downhole (e.g., drilling) tools, such as drill bits or reamers. MWD and LWD tools can perform measurements and / or facilitate the generation of borehole-associated images. However, because these tools are located above the drilling tools (e.g., up to 100 feet), any information collected by these measurement tools can only be used to make delayed decisions about the operation of drilling tools located further below the borehole. In other words, MWD and LWD tools cannot be practically implemented to make real-time decisions about, for example, the current junction and / or current formation associated with one or more drilling tools. In contrast, the techniques described herein can be implemented to perform measurements at the junction of one or more drilling tools with the formation. In this way, real-time information related to the proximity of the drilling tools can be used to inform decisions about the operation of the drilling tools.

[0168] Furthermore, while conventional MWD and LWD tools can acquire measurements and / or facilitate the generation of borehole images, such measurements and / or images typically have limited resolution. The imaging technique disclosed herein can generate images with improved resolution compared to, for example, conventional borehole images. The manufacture and downhole implementation of MWD and LWD imaging tools are also typically very expensive. Exposing expensive instruments to harsh downhole environments carries the possibility of instrument damage or loss. In contrast, the imaging technique described herein can be achieved through simple and inexpensive instrumentation combined with joining elements that may have been designed and / or configured to withstand harsh downhole environments.

[0169] Furthermore, a technique commonly used to collect and / or analyze specific information about formations is the acquisition of core samples. Special drill bits are used downhole to remove borehole samples and bring them to the surface so they can be analyzed to gather information about the formation. This can be expensive and time-consuming, as it requires stopping drilling operations and removing downhole tools from the borehole. The imaging technique described in this paper can generate virtual core images by incorporating lithological data (e.g., data associated with the physical properties of the formation) into the aforementioned images. In this way, a virtual representation of the core sample can be analyzed to characterize the formation in largely the same way as conventional methods, but without the costly downtime. Therefore, virtual core images can offer significant cost and resource savings compared to conventional core sampling techniques.

[0170] The following non-limiting examples illustrate various permutations considered herein.

[0171] In some embodiments, a method of imaging a formation includes identifying engagement data from an engagement sensor corresponding to engagement with a borehole in the formation. In some embodiments, the engagement sensor is located on an instrumented engagement element of a downhole tool, and the engagement data corresponds to the engagement of the instrumented engagement element with the borehole. In some embodiments, the engagement sensor is a force sensor, and the engagement data is force data. In some embodiments, the engagement data is transmitted to a drilling rig. In some embodiments, engagement measurements are acquired during drilling. In some embodiments, rotational data is identified from a rotation sensor, the rotational data corresponding to the rotational orientation of the engagement data relative to the borehole. In some embodiments, the rotational data is transmitted to the drilling rig. In some embodiments, the rotational data is acquired during drilling. In some embodiments, the engagement data is mapped to the rotational data to generate oriented engagement data. In some embodiments, the oriented engagement data is transmitted to the drilling rig. In some embodiments, borehole features are determined based on the oriented engagement data. In some embodiments, an image of the borehole is generated based on the oriented engagement data, wherein the image presents the engagement data relative to the rotational data, and wherein the image shows one or more geological features of the formation. In some embodiments, depth data is identified from a depth sensor, the depth data corresponding to the depth of the engagement data relative to the borehole. In some embodiments, depth data is acquired during drilling. In some embodiments, the depth data is sent to a drilling rig. In some embodiments, junction data is mapped to depth data to generate mapped junction data. In some embodiments, the mapped junction data is sent to a drilling rig. In some embodiments, borehole features are determined based on the mapped junction data. In some embodiments, an image of the borehole is generated based on the mapped junction data, wherein the image presents the junction data relative to depth data, and wherein the image shows one or more geological features of the formation. In some embodiments, lithology data is identified from a lithology sensor, wherein the lithology data is associated with one or more physical properties of the formation. In some embodiments, lithology data is acquired during drilling. In some embodiments, the method further includes transmitting the lithology data. In some embodiments, junction data is mapped to lithology data based on depth associated with the lithology data to generate mapped junction data. In some embodiments, the mapped junction data is sent to a drilling rig. In some embodiments, an image of the borehole is generated based on the mapped junction data, wherein the image presents the junction data relative to lithology data, and wherein the image shows one or more geological features of the formation. In some embodiments, the image is a virtual core image of the borehole. In some embodiments, the borehole data is identified corresponding to a global reference frame of the formation in which the borehole is located. In some embodiments, drilling information is transmitted to the drilling apparatus.In some embodiments, junction data is mapped to borehole data oriented relative to a global reference frame of the formation, wherein the mapping generates globally oriented junction data. In some embodiments, globally oriented junction data is transmitted. In some embodiments, junction data is mapped to one or more of the borehole azimuth, borehole dip, and borehole latitude and longitude. In some embodiments, geological features of the formation are determined based on the globally oriented junction data. In some embodiments, an image of the borehole is generated based on the globally oriented junction data, wherein the image presents the junction data relative to a global reference frame of the formation, and wherein the image shows one or more geological features of the formation. In some embodiments, an image of the borehole is generated at least partially based on the junction data. In some embodiments, generating the image includes applying color scales to represent the magnitudes of the junction data. In some embodiments, the image is generated while drilling using a downhole tool. In some embodiments, the resolution of each row of the image corresponds to the rotation of the downhole tool. In some embodiments, geological features of the formation are determined at least partially based on the junction data. In some embodiments, determining the geological features of the formation includes defining data features corresponding to threshold variations in the magnitudes of the junction data; and identifying one or more instances of data features associated with multiple consecutive rotations of the downhole tool. In some embodiments, the geological features are fractures or cracks in the formation. In some embodiments, the instrumented engagement element is located on the blade of the downhole tool.

[0172] In some embodiments, a method for imaging a formation includes: identifying engagement data from an instrumented engagement element of a downhole tool having an engagement sensor, the engagement data corresponding to engagement of the instrumented engagement element with a borehole in the formation; identifying rotational data from a rotation sensor, the rotational data corresponding to a rotational orientation of the engagement data relative to the borehole; mapping the engagement data to the rotational data to generate oriented engagement data; and generating an image of the borehole based on the oriented engagement data, wherein the image presents the engagement data relative to the rotational data, and wherein the image shows one or more geological features of the formation. In some embodiments, depth data is identified from a depth sensor, the depth data corresponding to the depth of the engagement data relative to the borehole surface, wherein image generation is further based on mapping the oriented engagement data to the depth data, and wherein the image shows the oriented engagement data relative to the depth data. In some embodiments, second engagement data is identified from a second engagement sensor, the second engagement data corresponding to engagement with the borehole; second rotation data is identified from the rotation sensor, the second rotation data corresponding to a second rotational orientation of the second engagement data relative to the borehole; and the second engagement data is mapped to the second rotation data to generate engagement data with a second orientation, wherein an image of the borehole is generated based on the engagement data with the orientation and the engagement data with the second orientation. In some embodiments, generating the image includes generating supplementary orientation engagement data by interpolation from the engagement data with the orientation and the engagement data with the second orientation. In some embodiments, an instrumented engagement element corresponds to a first radius of the downhole tool, and a second instrumented engagement element corresponds to a second radius of the downhole tool.

[0173] In some embodiments, a method for mapping a formation includes: identifying engagement data from an instrumented engagement element of a downhole tool having an engagement sensor, the engagement data corresponding to engagement of the instrumented engagement element with a borehole in the formation; identifying rotational data from a rotation sensor, the rotational data corresponding to the rotational orientation of the engagement data relative to the borehole; mapping the engagement data to the rotational data to generate oriented engagement data; and determining geological features of the formation based on mapping the oriented engagement data to a global reference frame. In some embodiments, depth data is identified from a depth sensor, the depth data corresponding to the depth of the engagement data relative to the borehole surface, wherein determining geological features is also based on mapping the oriented engagement data to the depth data. In some embodiments, the rotation sensor includes one or more of a magnetometer, a tiltmeter, and a gyroscope.

[0174] In a downhole drilling environment, a computer-implemented method for mapping formations in a downhole drilling environment is described. The computer-implemented method includes: identifying engagement data from an instrumented engagement element of a downhole tool having an engagement sensor, the engagement data corresponding to engagement of the instrumented engagement element with a borehole in the formation; identifying rotational data from a rotation sensor, the rotational data corresponding to the rotational orientation of the engagement data relative to the borehole; mapping the engagement data to the rotational data to generate oriented engagement data; and sending the oriented engagement data to the drilling apparatus.

[0175] In some embodiments, a method for determining the geological features of a formation includes: receiving sensor data from a downhole sensor implemented on an instrumented engagement element of a downhole tool, wherein the sensor data corresponds to engagement between the instrumented engagement element and a borehole in the formation; defining data features in the sensor data; and determining the geological features of the formation based on multiple instances of data features that periodically occur relative to rotation of the downhole tool. In some embodiments, the downhole sensor is implemented on an instrumented engagement element of the downhole tool, and wherein engagement data corresponds to engagement between the instrumented engagement element and the borehole. In some embodiments, the downhole sensor is an engagement sensor, and wherein the sensor data is engagement data.

[0176] In some embodiments, the method of mapping a formation includes: identifying first engagement data from a first engagement sensor, the first engagement data corresponding to an engagement with a borehole in the formation; identifying second engagement data from a second engagement sensor, the second engagement data corresponding to an engagement with the borehole; and mapping the first engagement data to the second engagement data to generate mapped engagement data. In some embodiments, the first engagement sensor is included on a first instrumented engagement element implemented on a downhole tool. In some embodiments, the second engagement sensor is included on a second instrumented engagement element implemented on a downhole tool. In some embodiments, the second engagement sensor is included on the first instrumented engagement element. In some embodiments, the first engagement data is first engagement data, and the second engagement data is second engagement data.

[0177] Embodiments of borehole imaging technology have been described primarily with reference to wellbore drilling operations; the borehole imaging technology described herein can be used in applications other than drilling out of a borehole. In other embodiments, the borehole imaging technology according to this disclosure can be used outside of wellbores or other downhole environments used for exploring or producing natural resources. For example, the borehole imaging technology of this disclosure can be used in boreholes used for laying utility pipelines. Therefore, the terms “wellbore,” “bore,” etc., should not be construed as limiting the tools, systems, components, or methods of this disclosure to any particular industry, field, or environment.

[0178] This document describes one or more specific embodiments of the present disclosure. These described embodiments are examples of the technology currently disclosed. Additionally, to provide a concise description of these embodiments, not all features of actual embodiments may be described in the specification. It should be understood that in the development of any such actual implementation, as in any engineering or design project, many embodiment-specific decisions will be made to achieve the developer's specific goals, such as complying with system-related and business-related constraints, which may vary from embodiment to embodiment. Furthermore, it should be understood that such development work can be complex and time-consuming, but it remains a routine task of design, fabrication, and manufacturing for those skilled in the art who benefit from this disclosure.

[0179] The articles “a,” “an,” and “the” are intended to indicate the presence of one or more elements in the preceding description. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that additional elements may be present in addition to those listed. Furthermore, it should be understood that references to “one embodiment” or “an embodiment” in this disclosure are not intended to be construed as excluding the existence of additional embodiments that also include the described features. For example, any element described with respect to embodiments herein may be combined with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values ​​used herein are intended to include that value, as well as other values ​​that are “about” or “approximate” to that value, as will be understood by one of ordinary skill in the art as covered by embodiments of this disclosure. Therefore, the values ​​should be interpreted broadly enough to cover values ​​that are at least sufficiently close 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.

[0180] In view of this disclosure, those skilled in the art should recognize that equivalent constructions do not depart from the spirit and scope of this disclosure, and various changes, substitutions, and modifications can be made to the embodiments disclosed herein without departing from the spirit and scope of this disclosure. Equivalent constructions including the functional "device plus function" clause are intended to cover structures described herein as performing the stated function, including structural equivalents operating in the same manner and equivalent structures providing the same function. The applicant expressly states that no claim invokes a device plus function or other functional claims except those claims that use the word "device" in conjunction with the relevant function. Every addition, deletion, and modification to the embodiments falling within the meaning and scope of the claims will be covered by the claims.

[0181] As used herein, the terms “approximately,” “about,” and “substantially” refer to quantities close to the stated quantity, which still perform the desired function or achieve the desired result. For example, the terms “approximately,” “about,” and “substantially” can refer to quantities less than 5%, less than 1%, less than 0.1%, and less than 0.01% of the stated quantity. 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.

[0182] This disclosure may be practiced in other specific forms without departing from the spirit or characteristics thereof. The described embodiments are to be considered illustrative rather than restrictive. Therefore, the scope of this disclosure is indicated by the appended claims rather than the foregoing description. Variations within the meaning and scope of equivalents of the claims will be included within their scope.

Claims

1. A method for imaging geological formations, comprising: Identify engagement data from engagement sensors, the engagement data corresponding to engagement with boreholes in the formation; Identify rotational data from a rotation sensor, the rotational data corresponding to the rotational orientation of the engagement data relative to the borehole; and The joining data is mapped to the rotation data to generate oriented joining data.

2. The method of claim 1, wherein the engagement sensor is located on an instrumented engagement element of the downhole tool, and wherein the engagement data corresponds to the engagement of the instrumented engagement element with the borehole.

3. The method of claim 1, wherein the engagement sensor is a force sensor and the engagement data is force data.

4. The method of claim 1, further comprising generating an image of the formation associated with the borehole based on the alignment data, wherein the image presents the alignment data relative to the rotation data, and wherein the image shows one or more geological features of the formation.

5. The method of claim 4, wherein generating the image includes applying color scales to represent the magnitude of the alignment data.

6. The method of claim 1, further comprising determining the geological features of the strata based on mapping the alignment data of the orientation to a global reference frame.

7. The method according to claim 6, wherein determining the geological characteristics of the strata comprises: Define data features corresponding to threshold changes in the magnitude of the engagement data of the stated orientation; and Identify one or more instances of data features associated with multiple consecutive revolutions of a downhole tool.

8. The method according to claim 6, wherein the geological feature is a fissure or crack in the stratum.

9. The method of claim 6, wherein mapping the alignment data to the global reference system comprises mapping the alignment data to one or more of the azimuth of the borehole, the dip angle of the borehole, and the latitude and longitude of the borehole.

10. The method of claim 1, further comprising transmitting the orientation engagement data to the drilling apparatus.

11. The method of claim 1, wherein the engagement data and the rotation data are each acquired during drilling using downhole tools.

12. A method for mapping strata, comprising: Identify engagement data from engagement sensors, the engagement data corresponding to engagement with boreholes in the formation; Identify depth data, which corresponds to the depth of the engagement data relative to the borehole; and The joining data is mapped to the depth data to generate mapped joining data.

13. The method of claim 12, wherein the engagement sensor is located on an instrumented engagement element of the downhole tool, and wherein the engagement data corresponds to the engagement of the instrumented engagement element with the borehole.

14. The method of claim 12, further comprising generating an image of the borehole based on the junction data of the mapping, wherein the image presents the junction data relative to the depth data, and wherein the image shows one or more geological features of the formation.

15. The method of claim 12, further comprising determining borehole features based on mapping the joint data to the depth data.

16. The method of claim 12, wherein the engagement data and the depth data are acquired during drilling using downhole tools.

17. The method of claim 14, further comprising transmitting the mapping connection data to the drilling apparatus.

18. A method for imaging strata, comprising: Identify engagement data from engagement sensors, the engagement data corresponding to engagement with boreholes in the formation; Identify rotational data from a rotation sensor or depth data from a depth sensor, wherein the rotational data corresponds to the rotational orientation of the engagement data relative to the borehole, and wherein the depth data corresponds to the depth of the engagement data relative to the borehole; Lithological data is identified from lithological sensors, where the lithological data corresponds to one or more physical properties of the formation; and The joint data can be mapped to the lithological data and the rotation data to generate mapped joint data, or the joint data can be mapped to the lithological data and the depth data to generate mapped joint data.

19. The method of claim 18, further comprising generating a virtual core image of the borehole based on the junction data of the mapping, wherein the virtual core image shows lithological data relative to the junction data, and wherein the virtual core image shows geological features of the formation.

20. The method of claim 18, further comprising determining the geological features of the strata based on the junction data of the mapping.

21. A method for determining the geological characteristics of strata, comprising: Receive engagement data from the engagement sensor, wherein the engagement data corresponds to the engagement with the borehole in the formation; Define the data characteristics in the joining data; and The geological characteristics of the formation are determined by identifying multiple instances of data features that appear periodically with respect to the rotation of the downhole tool.

22. The method of claim 21, wherein the engagement sensor is implemented on an instrumented engagement element of a downhole tool, and wherein the engagement data corresponds to the engagement of the instrumented engagement element with the borehole.

23. The method of claim 21, wherein the engagement sensor is a force sensor, and wherein the engagement data is force data.

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