Patent Publication Number: US-10323504-B2

Title: Techniques for determining an angular offset between two objects

Description:
This application claims priority to U.S. application Ser. No. 62/341,998, filed on May 26, 2016, entitled “System and Method for Determining an Angular Offset Between Two Objects,” and U.S. application Ser. No. 62/487,473, filed on Apr. 19, 2017, entitled “Techniques for Determining an Angular Offset Between Two Objects,” the contents of which are incorporated herein by reference. In addition, the contents of U.S. application Ser. No. 62/284,406, filed on Sep. 29, 2015, entitled “ACCU-Scribe, being an improvement in drilling technology,” are also incorporated herein by reference. 
    
    
     BACKGROUND 
     A variety of techniques are utilized in the oil and gas field when creating a new borehole or well. Drilling techniques may vary depending on the type of formation, the location of the rig, the product to be extracted, etc. During formation of the borehole, a well-bore plan, or other previously designed plan for drilling the borehole, is implemented via a computing system or human operations, in conjunction with the borehole assembly, to ensure accurate drilling measurements. Accurate drilling measurements ensure that the reservoir of product, such as oil and/or gas, is reached during the drilling process. 
     The borehole assembly may include a directional tool, such as a Measurement While Drilling (MWD) tool, often having internal computers that use accelerometers and magnetometers to determine the direction of the tool heading, otherwise referred to as the high-side of the tool. A downhole tool, such as a drilling motor, mud motor, or any other suitable downhole tool, may also be utilized. The downhole tool may include a bent housing located at a bottom end of the tool, such as the bottom end of the drilling motor. 
     While the downhole tool does not have computer technology within itself, it may be attached to the directional tool during drilling operations. The directional tool may operate according to the well-bore plan, thereby controlling the direction of the downhole tool according to the well-bore plan. When the directional tool and downhole tool are attached, the heading of the directional tool and the heading of the downhole tool may be different. The heading of the various drilling tools may be indicated by a high-side marking, or other indicator, that is marked on the exterior of the drilling tool. 
     The offset between the directional tool heading and the downhole tool heading, referred to as the angular offset or scribe line offset (SLO), needs to be accounted for and provided to the computing device, or employee, controlling the well-bore plan to ensure accurate drilling. If the SLO is not accounted for, the drilling measurements may have inaccuracies that can lead to drilling issues and mistakes, such as missing the product reservoir, leading to costly time delays and even abandonment of the borehole. 
     Conventional techniques for calculating the SLO are often left to human approximations. For example, conventional techniques include a rig employee using line of sight to roughly estimate the SLO. An employee may stand at the base of the downhole tool, beneath a directional tool suspended above, and estimate the SLO between a high-side marking indicating the heading of the directional tool and a high-side marking indicating the heading of the downhole tool. This method of calculating the SLO leaves room for significant human error as little accuracy can be ensured using human estimations alone. For example, a drilling employee may be standing at a distance of seventy feet, or longer, below the high-side marking of the directional tool, making it very difficult to visually estimate the offset between the heading of the directional tool and the heading of the downhole tool. Mistakes in the directional-drilling measurements can lead to problems drilling the wellbore, and even abandonment, resulting in costly and time-consuming setbacks. 
     In addition, safety issues can also be of concern. The drilling environment can be filled with many hazardous conditions related to drilling machinery and operations. For example, requiring that an employee stand below a suspended MWD during drilling operations can lead to increased risk of human injury. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The detailed description is set forth with reference to the accompanying figures. In the figures, the left-most digit(s) of a reference number identifies the figure in which the reference number first appears. The use of the same reference numbers in different figures indicates similar or identical items. 
         FIG. 1  illustrates an example drilling rig implementing an angular offset apparatus according to some examples. 
         FIG. 2  illustrates a first side view of a sensing component of an angular offset apparatus according to some examples. 
         FIG. 3  illustrates a first perspective view of the sensing component of  FIG. 2 . 
         FIG. 4A  illustrates a second perspective view of the sensing component of  FIG. 2  in an unlatched configuration. 
         FIG. 4B  illustrates a third perspective view of the sensing component of  FIG. 2  in a latched configuration. 
         FIG. 5A  illustrates an example drilling assembly implementing a target component of an angular offset apparatus according to some examples. 
         FIG. 5B  illustrates a perspective view of the target component of  FIG. 5A . 
         FIG. 5C  illustrates a perspective view of the bottom surface of the target component of  FIG. 5A . 
         FIG. 6  illustrates a perspective view of an example drilling assembly implementing another embodiment of an angular offset apparatus according to some examples. 
         FIG. 7  illustrates an example architecture of the control system of the angular offset apparatus of  FIG. 1 . 
         FIG. 8A  illustrates an example graphical user interface implemented with the example architecture of  FIG. 7 . 
         FIG. 8B  illustrates another example graphical user interface implemented with the example architecture of  FIG. 7 . 
         FIG. 8C  illustrates another example graphical user interface implemented with the example architecture of  FIG. 7 . 
         FIG. 9  illustrates an example flow diagram showing an illustrative process for determining a scribe line offset (SLO) using the angular offset apparatus of  FIG. 1 . 
         FIG. 10  illustrates a side view of another embodiment of a sensing component of an angular offset apparatus according to some examples. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure is directed to techniques for determining an angular offset, or scribe line offset (SLO), for use in drilling a wellbore during oil and gas operations. In some examples, a sensing component and a target component may be implemented for use in calculating the SLO for a particular oil and gas rig. For example, the sensing component may be placed adjacent to a first drilling tool of the rig and the target component may be placed adjacent to a second drilling tool. The sensing component and the target component may be placed opposite each other within the rig environment. For example, the sensing component may be placed adjacent to the rig floor, adjacent to a downhole tool, and the target component may be suspended above the rig floor, adjacent to a directional tool. Each tool may also include a high-side marking which indicates the high-side, or heading, of the tool. 
     The sensing component may be implemented to collect various data associated with the heading, indicated by the high-side marking, of the directional tool or downhole tool. For example, the sensing component may be located adjacent to the high-side marking of the downhole tool and collect image data of the target component, located adjacent to the high-side marking of the directional tool. The sensing component may collect data related to the target component to calculate the SLO between the high-side marking of the downhole tool and the high-side marking of the directional tool. The calculated SLO may then be provided to the rig computer(s), such as the directional tool computer(s), to ensure accurate and timely drilling measurements are used to plan the trajectory of drilling the wellbore. In some implementations, the sensing component and target component may be placed on the drilling tools and in the rig environment throughout the course of drilling operations (e.g. during the laying down or picking up of the borehole assembly), resulting in the ability to have at or near real-time SLO calculations, further reducing the risk of drilling complications due to SLO errors and the need for drilling employees to be on site for SLO-related operations. 
     The sensing component may implement one or more sensors designed to collect data related to imaging, local positioning, heat, light (i.e., including electromagnetic radiation of any frequency), etc. The sensing component may be securely attached adjacent to the high-side marking of a drilling tool, which indicates the heading of the tool, and may be located opposite the target component. Exact placement of the sensing component may vary depending on the weight restrictions and drilling requirements of the rig. For example, the sensing component may be securely attached adjacent to the high-side marking of a downhole tool in some examples or may be securely attached adjacent to the high-side marking of a drilling tool in other examples. In additional examples, the sensing component may be placed adjacent to a top-drive located above both the drilling tool and the directional tool. The sensing component may also implement a microcontroller, a wireless communication device, and an energy source, among other components, to provide the sensing data to an external device for processing. Alternatively, the sensing component may process the sensing data locally. 
     The target component may implement various marking and/or indicator components, as well as local positioning sensors. For example, the target component may implement an LED array that includes one or more markings indicating pre-determined increments, as well as an indicator that is aligned with a drilling tool high-side marking. As described above with respect to the sensing component, exact placement of the target component may vary with each rig and multiple example placements will be described herein. 
     In some examples, the sensing component may be located at a downhole tool near the rig floor and the target component may be located at a directional tool that is suspended above the rig floor. Both the sensing component and the target component may be located at external high-side markings of the downhole tool and the directional tool, respectively. The sensing component may implement one or more imaging sensors, such as cameras configured to capture stationary or rotational image data or video data, configured to gather image data of the target component. The image data may then be transmitted to an external computing system to determine the SLO. 
     In other examples, the sensing component may implement one or more sensors configured to detect light, including electromagnetic radiation of any frequency, emitted from a target component. For instance, the target component may implement one or more light emitting components, such as a laser, where at least one of the light emitting components may be aligned, either manually or through an automated process, with the external high-side marking of a directional tool. The light detecting sensor(s) of the sensing component may be configured to detect light from the light emitting component(s) of the target component to determine the SLO. 
     In still further examples, the sensing component and the target component may be implemented as part of a local positioning system for determining the SLO of a rig environment. In this example, the sensing component and the target component may each implement one or more antennas or beacons that are placed adjacent to the high-side marking of the directional tool and the high-side marking of the downhole tool. The local positioning system may use beacon data to calculate the locations/positions of the high-sides of the directional tool and the downhole tool using any number of methods such as triangulation, trilateration, multilaterion, etc. The location/position data of the high-sides can then be transmitted to a computing device and used to calculate the SLO. 
     The techniques, systems, and devices described herein improve the safety and accuracy of oil and gas drilling operations, such as during the picking up and laying down of the borehole assembly. For example, the systems and methods for determining the angular offset between two objects described herein helps ensure that an accurate SLO can be calculated for directional drilling operations. In addition, in some examples, real-time calculations may be achieved. In contrast to the traditional methods of calculating an SLO using visual estimations alone, the systems and methods described below utilize sensing and target components, along with computer technologies, to calculate a precise SLO that minimizes the margin of error associated with visual estimations. 
     In addition to the oil and gas related implementations described above, the techniques, systems, and examples described herein may be implemented in technology areas related to type-fitting, welding, construction, architecture, surveying and dimensional analysis, mining, natural resource wells, pipeline fittings, safety designs, etc. 
     These and other examples are described below in more detail with reference to the representative architecture illustrated in the accompanying figures. 
       FIG. 1  illustrates an example drilling rig environment  100  implementing an angular offset apparatus  102  according to some examples. In this example, the angular offset apparatus  102  includes a sensing component  104 , a target component  106 , and a computing device  108 . 
     In some examples, the sensing component  104  is placed adjacent to the high-side marking of a downhole tool  116 . The sensing component  104  may implement one or more sensors configured to collect data related to imaging, local positioning, heat, light (i.e., including electromagnetic radiation of any frequency), etc. For instance, in the illustrated example, the sensing component  104  implements two sensors  110 ,  112  that are mounted on the exterior of the downhole tool  116 . However, in other examples, any number of sensors may be implemented in various configurations. 
     In some examples, at least one of the sensors  110 ,  112  may be aligned with a high-side marking of the downhole tool  116  to serve as an origin point for determining the scribe line offset (SLO). In other examples, the sensors  110 ,  112  may not be aligned with the high-side marking of the downhole tool  116  and may be placed adjacent to other locations within the rig environment  100 . In these instances, the sensing component  104  may include an indicator mark that indicates the location of the high-side marking of the downhole tool  116 . The sensing component may also include markings that allow for the offset between the sensors  110 ,  112  and the indicator mark aligned with the high-side marking of the downhole tool  116  to be calculated and used when determining the SLO. 
     In further examples, the target component  106  may be placed adjacent to the high-side marking of a directional tool  114 . The target component may include one or more indicators placed adjacent to the high-side marking of the directional tool  114  that are visible and able to be detected by the sensors  110 ,  112  of the sensing component  104 . For example, the target component  106  may include a collar with lined markings, such as LED markings, each spaced a pre-determined distance apart. At least one of the lined markings may be unique to indicate the high-side marking of the directional tool  114 . For instance, the unique lined marking may include a perpendicular hash mark, or some other marking to distinguish the unique lined marking from the rest of the lined markings. 
     In some examples, the sensors  110 ,  112  may include imaging sensors configured to collect image data of the target component  106 . In particular, sensors  110 ,  112  may take stationary photos from each side of the downhole tool  116 . In some examples, the sensors  110 ,  112  may also rotate about the downhole tool  116  to capture 360-degree image data of the target component  106  and rig environment  100 . The captured image data may be transmitted via wireless or wired technology for processing at the computing device  108 . For example, the captured image data may be transmitted to a cloud-based system where the image data can be stored and/or computations performed. During processing, image rendering may be performed, an aspect ratio may be set, combined images may be generated, image recognition techniques may be applied, etc. For example, the dimensions of multiple images may be compared, altered, or combined. For instance, images from each of the sensors  110 ,  112 , showing images captured from each side of the downhole tool  116 , may be combined to show a 360-degree view of the downhole tool  116  and target component  106 . The combined image rendered, or the individual images, may then be used to determine the location of the high-side marking of the directional tool  114 . 
     Using calculations pre-programmed into the computing device  108 , the computing device  108  can determine the angular offset between the location of the two high-side markings of the directional tool  114  and the downhole tool  116 , otherwise referred to as the scribe line offset (SLO). The use of imaging data and computerized calculations helps significantly improve the accuracy of the SLO value, as opposed to conventional techniques that utilize line of sight alone. In addition, the placement of the sensing component  104  and the target component  106  within the rig environment can enable the real-time calculation of the SLO offsite, decreasing the number of crew members required onsite and improving the safety of the rig environment  100 . 
     Further, each rendered image may be marked with a unique serial number and/or other identification information, such as information related to the equipment in the rig environment  100 . Marked images may be stored for subsequent recall. Identifying and storing each rendered image helps keep a running log of each image used to calculate each SLO for accountability and use by the rig crew. In some examples, the rendered images may be stored in cloud-based storage, servers, or other storage applications. 
     In some examples, the placement of the sensing component  104  and the target component  106  may vary according to the rig environment, design considerations, etc. For example, the target component  106  could be mounted onto a tool located above the directional tool  114 , such as a top-drive. In this example, the target component may still be aligned with a high-side marking of the directional tool  114  while mounted above the top-drive. In other examples, the sensing component  104  and target component  106  may be mobile. For instance, the sensing component  104  and the target component  106  may be implemented in conjunction with flight capable instruments, such as drone technology. In further examples, the sensing component  104  may be mounted on the directional tool  114  and the target component  106  may be mounted on the downhole tool  116 . 
     In other embodiments, representing variations of the implementations shown in  FIG. 1 , an angular offset apparatus may implement a sensing component that includes one or more sensors designed to detect light from a target component, such as from lasers that are included in the target component. This embodiment is described in greater detail with respect to  FIG. 6  below. Additional and/or alternative examples include detecting indicator(s) produced via non-visible light or various frequencies of electromagnetic radiation. 
     In still further embodiments, representing variations of the implementations shown in  FIG. 1 , an angular offset apparatus may implement a local positioning system. The local positioning system may implement one or more beacons or antennas, or other apparatuses capable of collecting and transmitting local positioning data. Each antenna may be located at the high-side of a drilling tool, such as the directional tool  114  and the downhole tool  116  illustrated in  FIG. 1 . In this embodiment, a grid system is determined and components of the local positioning system may be placed adjacent to known locations. For example, four local positioning components, may be placed adjacent to four corners of the drilling environment  100 , with each of the four components placed adjacent to a known location. In other examples, any number and configuration of local positioning components may be implemented according to the unique drilling environment. 
     To calculate the SLO, each beacon or antenna may ping off the known locations and collect data, including the time period needed for the ping to travel to the local positioning component from each beacon or antenna, the time period needed for the ping to return to each beacon or antenna from the local positioning component, and information regarding where each beacon or antenna is located, such as the at the high-side marking of a drilling tool to which the antenna or beacon is attached. The collected data may then be provided to the computing device  108  and, utilizing the collected data, the angular offset, or SLO, is determined by the computing device  108 . The SLO may then be accounted for in the well-bore plan and ultimately provided to the directional tool  114  via the computing device  108  to be accounted for during drilling operations. 
       FIG. 2  illustrates a first side view of an example sensing component  200  of the angular offset apparatus (e.g., angular offset apparatus  102 ) described herein. The sensing component  200  is shown placed around the outside perimeter of a downhole tool  202  used during drilling operations, including during the picking up or laying down of the borehole assembly, which includes tooling such as a drilling motor or mud motor. 
     In this example, the sensing component  200  implements two imaging sensors  204 ,  206  configured to capture image content and placed adjacent to opposite ends of the downhole tool  202 . One of the imaging sensors  204 ,  206 , referred to as an origin camera, may be placed adjacent to the external high-side marking (not shown) of the downhole tool  202  to help determine an approximate origin location of the imaging sensors  204 ,  206 . Knowing the origin location of the imaging sensors  204 ,  206  helps determine the scribe line offset (SLO) by providing information such as the location of the high-side marking of the downhole tool  202  (i.e. the origin of the offset of the rig) as well as helping to set the aspect ratio of the image content. In other embodiments, the imaging sensors  204 ,  206  may be placed away from the high-side marking of the downhole tool  202 . In this embodiment, the offset between the sensors  204 ,  206  is determined and accounted for when calculating the SLO. 
     In some examples, the image content may include image data, captured by the imaging sensors  204 ,  206 , showing a marker or indication of the location of a second high-side marking of another drilling tool, such as a directional tool, of the bottom hole assembly (BHA). The location of the directional tool high-side marking, along with the location of the high-side marking of the downhole tool  202 , may be used to determine the SLO, sometimes referred to as the angular offset, of the two high-side markings with increased precision and accuracy. 
     In the illustrated example, the sensing component  200  is shown attached to the downhole tool  202  at an external high-side marking (not shown). To attach the sensing component  200  to the downhole tool  202 , the sensing component  200  implements a mounting mechanism that can be latched and unlatched for attachment and removal, respectfully, of the sensing component  200 . The mounting mechanism may implement one or more attachment fasteners  208 ,  210 , one or more transport mechanisms  212 ,  214 , one or more mounting brackets  216 ,  218 ,  220 ,  222 , and one or more connecting brackets  224 ,  226 . The mounting mechanism helps ensure that that sensing component  200  is aligned with the center line of the downhole drilling  202  when mounted. 
     In some examples, the attachment fasteners  208 ,  210  are located on the mounting mechanism and configured to secure the components of the mounting mechanism in the desired configuration. In this example, the attachment fasteners  208 ,  210  include a bolt assembly. However, any fastener meeting the weight and safety requirements of the sensing component  200  and the rig environment may be used. 
     In addition, the transport mechanisms  212 ,  214  may allow for a user, such as a rig employee, to transport the sensing component  200  for placement on the downhole tool  202 . For example, the transport mechanisms  212 ,  214  may include one or more handle grips. The sensing component may be lifted manually by the one or more transport mechanisms  212 ,  214 , or via machinery utilizing the transport mechanisms  212 ,  214 , depending on the drilling rig, weight of the sensing component  200 , difficulty of placement, and safety considerations. The transport mechanisms  212 ,  214  may also be configured to allow for rotation of components of the mounting mechanism, such as the mounting brackets  216 ,  218 ,  220 ,  222 . 
     In some instances, the connecting brackets  224 ,  226  may be located at a first end and a second end of the transport mechanisms  212 ,  214 . The connecting brackets  224 ,  226  may be opened or closed to allow for the attachment and removal of the sensing component  200 . The connecting brackets  224 ,  226  may run parallel to the imaging sensors  204 ,  206  and may serve as the connecting structure between the two imaging sensors  204 ,  206 . 
     Further, the mounting brackets  216 ,  218 ,  220 ,  222 , may include a disc or ring that wraps around exterior housings  228 ,  230 ,  232 ,  234  of the imaging sensors  204 ,  206 . The mounting brackets  216 ,  218 ,  220 ,  222  are configured to hold the imaging sensors  204 ,  206  at a fixed location and prevent migration. The mounting brackets  216 ,  218 ,  220 ,  222  may be permanently fixed to the exterior housings  228 ,  230 ,  232 ,  234  or may be detachable, allowing for the placement and removal of the imaging sensors  204 ,  206 . In some examples, exterior housings  228 ,  230 ,  232 ,  234  may be placed on the external body of the imaging sensors  204 ,  206  and may serve as a protective outer housing, or explosion-proof housing. 
     In addition, while the sensing component  200  illustrated in  FIG. 2  is removable, alternative examples may include a sensing component  200  that is permanently attached to a drilling tool. Also, the sensing component  200  may not implement a mounting mechanism and may be attached to the downhole tool  202  via alternative attachment means. For example, the mounting mechanism may be a separate component, independent of the sensing component  200 , that may be attached to the downhole tool or may be manufactured as a part of the downhole tool. The sensing component  200  may also be modular in nature, and may be attached to the independent mounting mechanism at a later time. For example, the sensing component  200  may implement numerous sensors that each may be attached separately to a mounting mechanism. 
     Still further, the sensing component  200  may be attached to the downhole tool  202  by other attachment or mounting means. For example, the sensing component  200  could be attached to the downhole tool  200  by a spring-loading mounting mechanism. The spring-loading mounting mechanism may implement a collar with one or more springs that allows the sensing component  200  to be attached to downhole tools varying in diameter. In addition, the sensing component  200  may be attached to downhole tools with straps or magnetic components that can be placed around the exterior of the downhole tool  202 . 
     In some examples, the sensing component  200  may also implement a wireless antenna  236 . The wireless antenna  236  is shown mounted to the exterior housing  228 , in this particular example. However, the wireless antenna  236  may be placed adjacent to any location on the sensing component  200  where the wireless antenna  236  is able to transmit wireless signal data. In some examples, the sensing component  200  may not implement a wireless antenna  236  at all, but instead may implement other wireless technology, such as short range or long range wireless communication. 
     The sensing component  200  may also implement one or more imaging sensor backplates  250 ,  252 . The imaging sensor backplates  250 ,  252  may include a transparent panel, such as a glass or plastic plate, that may be hinged to allow for opening and closing. The imaging sensor backplates  250 ,  252  may be placed over one or more control panels operable to control the imaging sensors  204 ,  206 . The control panel(s) may include manual control components such as a thumbpad. The control panel(s) may be used for manual control of the imaging sensors  204 ,  206  should wireless control become disabled or unavailable. For example, each control panel may be used to activate wireless components, power components, etc. of the imaging sensors  204 ,  206 . In addition, the imaging sensor backplates  250 ,  252  may implement one or more backplate fasteners  238 ,  240 ,  242 ,  244 ,  246 ,  248 . The backplate fasteners  238 ,  240 ,  242 ,  244 ,  246 ,  248  may be configured to secure the imaging sensor backplates  250 ,  252  in a closed position, or allow the imaging backplates  250 ,  252  to be moved to an open position. 
     In further examples, the sensing component may implement one or more protective lenses  254 ,  256 . The protective lenses  254 ,  256  may be configured to attach over a surface of the imaging sensors  204 ,  206  to prevent foreign substances, such as water or oil, from penetrating the imaging sensors  204 ,  206 . The protective lenses  254 ,  256  may include an acrylic glass panel, but other materials may be used depending on the drilling environment, the product being produced, the imaging component being protected, and other considerations. 
     In some instances, the sensing component may implement a rotatable handle  258 . The rotatable handle  258  may be configured to spin freely on a threading system to secure the mounting mechanism to the downhole tool  202 , or allow the removal of the mounting mechanism. The rotatable handle  258  may enable the tightening and loosening of the mounting mechanism. In particular, the rotatable handle  258  may close or open the connecting brackets  224 ,  226  for attachment and removal, respectively, of the sensing component  200  to the downhole tool  202 . The rotatable handle  258  may be permanently fixed to the sensing component  200  or may be detachable, dependent on the sensing component  200  configuration. In other examples, another suitable fastening component may be used in lieu of the rotatable handle  258 . 
     The exact number and arrangement of the sensing component  200  components described above may vary according to the specific angular offset apparatus, drilling rig configuration, and other considerations. For example, in the illustrated example, the sensing component  200  implements two imaging sensors  204 ,  206  and thus implements four mounting brackets  216 ,  218 ,  220 ,  222 , located at opposite ends of the imaging sensors  204 ,  206 . In other examples, the sensing component may implement one imaging sensors, rotatable around the exterior of the downhole tool  202 , to allow for a 360-degree image, and may implement only one mounting bracket, as described below with regard to the embodiment of  FIG. 10 . Or, the sensing component may implement some other plurality (e.g., three, four, eight, twenty, etc.) of imaging sensors, which can be stationary or rotatable, which may result in a different configuration of mounting bracket(s). Thus, since other sensing component  200  configurations may implement a different number of sensors or the sensors may have a different arrangement, varied components may be implemented. 
     Note that the design and implementation of the angular offset apparatus shown in  FIG. 2  is not a limiting embodiment. Other designs may be considered and implemented according to the environment, requirement, and design considerations described herein. 
       FIG. 3  illustrates a first perspective view of the sensing component of  FIG. 2 . In the illustrated example, one of the imaging backplates  250  is shown in an open configuration and the other imaging backplate  252  shown in a closed configuration. The open configuration of imaging backplate  250  shows the backplate fasteners  238 ,  240 ,  242  in an unfastened, or loosened, position, allowing the imaging backplate  250  to be opened to expose a control panel. The control panel allows manual control of the imaging sensor  204  if remote control is disabled or unavailable. The closed configuration of imaging backplate  252  shows the backplate fasteners  244 ,  246 ,  248  in the fastened, or tightened, position, ensuring that the imaging backplate  252  remains in the closed position. When the imaging backplate  252  is in the closed position, the control panel of the imaging sensor  206  is not exposed to the rig environment and manipulation of or damage to the control panel is minimized. 
     In other examples, other materials and structures may be used for placement over the control panel(s). For example, the imaging backplates  250 ,  252  may be fixed in the closed position and controlled wirelessly. In some examples, a larger or smaller component may be placed over the control panel(s). In further examples, the imaging backplates  250 ,  252  may include high compressive strength and tensile resistant materials. 
       FIG. 4A  illustrates a second perspective view of the sensing component  200  of  FIG. 2  in an unlatched configuration. In the illustrated example, the rotatable handle  258  is rotated to allow the mounting mechanism to be in the unlatched configuration. The unlatched configuration allows for the connecting brackets  224 ,  226  to be expanded open and for the sensing component  200  to be removed from the downhole tool  202 . When the connecting brackets  224 ,  226  are in the opened/unlatched configuration, they are able to receive the downhole tool  202 . 
       FIG. 4B  illustrates a third perspective view of the sensing component of  FIG. 2  in a latched configuration. In this example, the rotatable handle  258  is rotated to allow the mounting mechanism to be in the latched configuration. The latched configuration allows for the connecting brackets  224 ,  226  to be rotated to a closed position and for the sensing component  200  to be securely mounted to the downhole tool  202 . 
     For example, the mounting mechanism may implement a sensing component latching mechanism  404  located adjacent to the rotatable handle  258  and operable by way of the rotatable handle  258 . For example, the latching mechanism may include a threaded bolting system that is loosened or tightened, or opened or closed, by way of the rotatable handle  258 . In other examples, other latching mechanisms may be used such as magnets, brackets, straps, etc. 
     In addition, in  FIGS. 4A and 4B , at least one of the connecting brackets  224 ,  226  may implement an indicator. For example, in the illustrated examples, connecting bracket  252  implements an arrow  402 . The arrow  402 , may be utilized to indicate a location of interest. In one example, the arrow  402  may indicate the location of a high-side marking of the downhole tool  202 . The arrow  402 , enables the sensing component  200  to be aligned with the high-side marking. The alignment of the arrow  402  with the high-side marking may be manual or automated. For example, the arrow  402  may be placed adjacent to the high-side marking by a rig employee. 
     In some examples, one of the imaging sensors  204 ,  206  may be aligned with the arrow  402 , to serve as an origin point for the SLO calculations. In other examples, the imaging sensors  204 ,  206  may be located at other locations along the connecting brackets  224 ,  226  or within the rig environment. In these examples, the connecting brackets  224 ,  226  may also include one or more indicators that represent a unit of measurement, such as an angular increment, that can be used to determine the offset between the imaging sensors  204 ,  206  and the arrow  402 . The offset between the imaging sensors  204 ,  206  and the arrow  402 , indicating the high-side marking of the downhole tool  202 , may then be accounted for in the SLO calculation. 
     In other examples, the sensing component  200  may implement one or more alignment sensors that can help determine if the arrow  402  is aligned with the high-side marking. In one instance, the alignment sensor(s) may collect image data of the placement of the sensing component  200  at the downhole tool  202 . In this example, the alignment sensor(s) may be located on the top surface or bottom surface of the sensing component  200 , or placed adjacent to the inner portion of the sensing component  200 . The image data may be processed to verify whether the sensing component  200  is aligned with a high-side marking of the downhole tool  202 . In the case of improper alignment, the sensing component  200  may be manually re-aligned. Alternatively, the image data may be analyzed and, along with an electronic alignment mechanism, may allow for an automated re-alignment of the sensing component  200  or manual re-alignment, via an onsite employee or a remote device operated by an offsite employee, to align the sensing component with the high-side marking of the downhole tool  202 . For instance, one of the sensors  204 ,  206  or the arrow  402  of the sensing component  200  may be aligned with the high-side marking of the downhole tool  202 . 
       FIG. 5A  illustrates an example drilling assembly implementing a target component  500  of an angular offset apparatus according to some examples. In the illustrated example, the target component  500  includes a collar  502 , a target component latching mechanism  504 , and a hinge mechanism  506 . The target component  500  is shown mounted at the directional tool  508 , located above a sensing component  510  mounted at a downhole tool  512 . However, in other embodiments, the target component  500  may be located below the sensing component  510  or elsewhere on the rig, depending on the rig configuration. 
     In some examples, the hinge mechanism  506  of the target component  500  is configured to allow the target component  500  to open when the target component latching mechanism  504  is unsecured. For instance, when the target component latching mechanism  504  is in the unsecured configuration, the target component  500  may hinge at the hinging mechanism  506  to create an opening in, or separation of, the target component to allow for placement or removal of the target component  500 . The opening allows for the target component  500  to be placed around the outer diameter of the directional tool  508 . 
     Once the target component  500  is placed around the directional tool  508 , the target component  500  is aligned with the directional tool high-side marking  514 . Once aligned, the target component  500  may hinge to the closed position and secured in place with the target component latching mechanism  504 . The target component  500  may also be secured in place adjacent to the directional tool  508  by other attachment mechanisms such as magnets, straps, a bolting mechanism, etc. 
     In this example, the target component  500  is manually aligned with the directional tool high-side marking  514 . However, in other examples, the target component  500  may be remotely and/or automatically aligned. For example, the target component  500  may include one or more sensors, such as imaging sensors, that may collect image data associated with the placement of the target component  500 . The image data may be analyzed and used for aligning the target component  500  automatically and/or remotely. For instance, a unique marking of the target component may be aligned with the directional tool high-side marking  514  automatically and/or remotely. 
     In some examples, the target component  500  may also include one or more markings  516  on a surface of the target component  500  visible to the sensing component  510 . The marking(s)  516  may indicate a pre-determined value that can be used to calculate the scribe line offset (SLO) between the downhole tool high-side marking  518  and the directional tool high-side marking  514 . For example, each marking of the marking(s)  516  may represent a certain degree increment of the 360 degrees of the target component  500 . The downhole tool high-side marking  518  may serve as the origin point for the SLO calculation. The SLO may be calculated by measuring the marking(s)  516 , representative of a certain degree value, defining the offset between the downhole tool high-side marking  518  and the directional tool high side marking  514 . 
     In other examples, the high-side markings  514 ,  518  may be implemented as any identifying component. For example, the high-side markings  514 ,  518  may include an identifier of any shape, size, and material, such as an arrow or lighted indicator. In addition, the high-side markings  514 ,  518  may include a separate identifier that can be placed on a drilling tool at any time to indicate the high-side of the tool. 
       FIG. 5B  illustrates a perspective view of the bottom surface of the target component  500  of  FIG. 5A . The target component  500  includes the collar  502 , the target component latching mechanism  504 , and the hinge mechanism  506 . The target component  500  also includes marking(s)  516 , representative of a pre-determined degree value, used to calculated the SLO between the directional tool high-side marking  514  and the downhole tool high-side marking  518 . 
     While degree values are used in the illustrated example, any form of measurement may be used in conjunction with the marking(s)  516  and, subsequently, the SLO. For example, units of length, diameter, inner diameter, etc. may be used to divide and mark the target component  500  into pre-determined units measurable to determine the SLO between the directional tool high-side marking  514  and the downhole tool high-side marking  518 . 
       FIG. 5C  illustrates another perspective view of a bottom surface of the target component  500  of  FIG. 5A . The target component  500  includes one or more markings  516  indicating a degree value of the 360 degrees of the target component  500 . The marking(s)  516  may also have labeled reference points, which are indicated by the letters “A-H” in the illustrated example. However, any labels may be used. 
     In this example, the target component  500  further implements a laser component (not shown) that emits a light beam  520 . The light beam  520  indicates the location of the directional tool high-side marking  514 . The light beam  520  may ensure proper alignment between the target component  500  and the directional tool high-side marking  514 . For example, the light beam  520  may also be detected by one or more sensing components located on the sensing component  510 . The sensing component data may be analyzed to ensure that the light beam  520  is aligned with the directional tool high-side marking  514 . Proper alignment maximizes accuracy for calculating the SLO between the directional tool  508  and the downhole tool  512 . 
     In other examples, the target component  500  may implement other components to indicate the directional tool high-side marking  514 . For example, the target component  500  may implement a unique marking, such as a marking with a cross-hair, an LED light, or any other marking or indicator visible to the sensing component  510  and able to be detected by the sensor(s) of the sensing component  510 . 
       FIG. 6  illustrates a perspective view of an example drilling assembly implementing another embodiment of an angular offset apparatus  600 . In the illustrated example, the angular offset apparatus  600  includes a collar component  602  and a marking component  604 . The collar component  602  may include a mounting mechanism  606  and one or more light projecting components  608 . The marking component  604  may include one or more sensor(s)  610 . 
     In some examples, the collar component  602  may implement a mounting mechanism  606  that includes one or more spring-loaded mounting mechanisms located on the inner diameter of the collar component  602 . The spring-loaded mounting mechanisms may expand and contract to allow mounting of the collar component  602  to drilling tools of varied diameters and configurations. The collar component  602  may also implement one or more light projecting components  608  located on a bottom surface of the collar component  602 . For example, the collar component  602  may implement one or more lasers configured to project light in a downward direction towards the marking component  604 . 
     The marking component  604  may implement one or more sensor(s)  610  configured to detect light projected from the light projecting component(s)  608  and collect associated light data. For example, the marking component  604  may implement one or more sensor(s)  610  aligned with the high-side marking of the downhole tool  612  to indicate the high-side marking. The collar component  602  may be mounted at a high-side marking (not shown) of the directional tool  614 , with at least one light projecting component directly aligned with the high-side marking of the directional tool  614  at the start of a rotation, and thus being used as the light projecting origin point. 
     In some examples, to calculate the angular offset, or SLO, the collar component  602  may rotate about the drilling assembly, at a fixed location, and the sensor(s)  610  may be configured to detect when the light projecting component(s)  608  pass the sensor(s)  610  and collect light data associated with the detection. The light data may be transmitted, either via wired or wireless technology, to a computing device  616  for processing. The light data may be analyzed to determine at what degree of rotation of the collar component  602  the sensor(s)  610  detected the light from the light projecting component(s)  608 . From this analyzed light data, along with the known light projecting origin point, the SLO may be calculated for use in directional drilling operations. 
     In further examples, the collar component  602  may be fixed and the marking component  604  may rotate. For example, the collar component  602  may have one or more light projecting components  608  fixed at the high-side marking of the directional tool  614 . The marking component  604  may rotate about the downhole tool  612  and the sensor(s)  610  may collect data including when the sensor(s)  610  detect light projected from the light projecting component(s)  608 . The marking component  604  may include one or more sensor(s)  610  aligned with the high-side of the downhole tool  612  at the start of rotation, serving as the known sensor origin point. In some examples, the rotation may take place by way of a bearing system, magnetic tracks, a gear and motor unit, or automatically via other mechanical means. 
     The collected data may be transmitted, either via wired or wireless technology, to a computing device  616  for processing. The data may be analyzed to determine at what degree of rotation the sensor(s)  610  of the marking component  604  detected light emitted from the light projecting component(s)  608 . From this analyzed light data, along with the known sensor origin point, the SLO may be calculated. 
     In the illustrated example, the collar component  602  is mounted on a directional tool  614  and the marking component  604  is mounted on a downhole tool  612 . However, in some embodiments, the collar component  602  and the downhole tool  612  may be mounted at different locations, depending on weight requirements, safety considerations, the rig environment and tooling, and other considerations. For example, the collar component  602  may be mounted at the downhole tool  612  and the marking component  604  may be mounted at the directional tool  614 . 
     In other examples, the sensor(s)  610  may be replaced with reflective surfaces, such as mirrors or any other material with a mirror finish, that are able to reflect light from the light projecting component(s)  608  back towards the collar component  602 . In this example, the collar component  602  may implement one or more sensors able to detect light from the light projecting component(s)  608  to calculate the SLO. In addition, the collar component  602  may also implement other components such as a protective housing. 
       FIG. 7  illustrates an example architecture of a control system  700  that can include one or more computing devices. In some cases, the control system  700  can include the computing device  108  of  FIG. 1 . The computing device may include, for example, a mobile phone, a tablet, a laptop computer, a desktop computer, an electronic notepad, a server computing device, etc. In additional implementations, the control system  700  can be implemented in a cloud-computing architecture. The control system  700 , collectively comprises processing resources, as represented by processor(s)  702 , input/output device(s)  704 , communication interface(s)  706 , and one or more computer-readable storage media  708 . 
     Processor(s)  702  can represent, for example, a CPU-type processing unit, a GPU-type processing unit, a Field-Programmable Gate Array (FPGA), another class of Digital Signal Processor (DSP), or other hardware logic components that can, in some instances, be driven by a CPU. For example, and without limitation, illustrative types of hardware logic components that can be used include Application-Specific Integrated Circuits (ASICs), Application-Specific Standard Products (ASSPs), System-on-a-Chip Systems (SOCs), Complex Programmable Logic Devices (CPLDs), etc. In at least one example, an accelerator can represent a hybrid device, such as one from ZYLEX or ALTERA that includes a CPU course embedded in an FPGA fabric. In various embodiments, the processor(s)  702  can execute one or more modules and/or processes to cause computing device(s) to perform a variety of functionalities, as set forth above and explained in further detail in the following disclosure. Additionally, each of the processor(s)  702  can possess its own local memory, which also can store program modules, program data, and/or one or more operating systems. 
     The computer-readable storage media  708  may include volatile and nonvolatile memory, removable and non-removable media implemented in any method or technology for storage of information, such as computer-readable instructions, data structures, program modules, or other data. Such memory includes, but is not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, RAID storage systems, or any other medium which can be used to store the desired information and which can be accessed by a computing device. 
     Several modules such as instruction, data stores, and so forth may also be stored within the one or more computer-readable media  708  and configured to execute on the processor(s)  702 . For example, the one or more computer-readable media  708  may store a sensor data receiving and processing module  710 , a directional tool high-side determination module  712 , a downhole tool high-side determination module  714 , a scribe line offset (SLO) determination module  716 , and a graphical user interface (GUI) generation/presentation module  718 . The one or more computer-readable media  708  may also store data, such as target component marking data  720 , that includes data related to markings on the target component such as the unit of measurement, increment value, etc. 
     In some examples, the sensor data receiving and processing module  710  is configured to receive and process sensor data from a sensing component, such as the sensing component  104  of  FIG. 1 . For example, the sensors  110 ,  112  of the sensing component  104  may collect image data that is transmitted to the control system  700  via wired or wireless means. The sensor data receiving and processing module  710  may receive the image data and process the data. Processing the data may include parsing the image data for quality, compiling a number of images into a composite image, dimensional analysis, mechanical analysis, nondestructive testing, nondestructive evaluation, maintenance analysis, fatigue and failure analysis, etc. Further, each image or composite image may be marked with a unique serial number and/or other identification information, such as information related to the equipment in the rig environment. Marked images may be stored for subsequent recall. Identifying and storing each rendered image helps keep a running log of each image used to calculate each SLO for accountability and use by the rig crew. Storage may take place on a server system, cloud-based storage platforms, or other storage applications. 
     In further examples, the directional tool high-side determination module  712  may use the composite image to determine the location of the high-side marking of the directional tool  114 . For example, the directional tool high-side determination module  712  may use image data from the sensing component  104  showing the high-side marking of the directional tool  114 , or an indicator located on the target component  106 , to determine the location of the high-side of the directional tool  114 . In some examples, various alignment mechanisms may be used, as well as user selections, to ensure the proper determination of the high-side marking of the directional tool  114 . For example, a user may select various boundary points, in a graphical user interface, to align the composite image with an overlay image or axis to determine the correct location of the high-side marking of the directional tool  114 . 
     The downhole tool high-side determination module  714  may use the composite image to determine the location of the high-side marking of the downhole tool  116 . For example, one of the sensors of the sensing component  104  may be aligned with the high-side marking of the downhole tool  116 . Thus, the location is determined by analyzing the image data from the sensing component  104  aligned with the high-side marking of the downhole tool  116 , where a horizontal axis of the image is therefore aligned with the high-side marking of the downhole tool  116 . In other examples, various sensors may collect data from the inner diameter of the sensing component  104  to determine the location of the high-side marking of the downhole tool  116 . For instance, one or more imaging sensors, such as cameras, may be placed in a way to allow collection of image data of the exterior of the downhole tool  116 . In still further examples, the sensing component  104  may have an indicator aligned with the high-side marking of the downhole tool  116 . Sensor data associated with the indicator may be used to determine the location of the high-side marking of the downhole tool  116  or the offset between the indicator and the sensors of the sensing component  104 . For instance, one or more imaging components may be configured to collect image data of the location of the indicator. 
     The scribe line offset determination module  716  may then use the determined directional tool high-side marking location and the downhole tool high-side marking location to determine the SLO, or angular offset between the high-sides of the directional tool  114  and the downhole tool  116 . The SLO may be determined using trigonometric functions and analysis, in some examples. 
     The graphical user interface (GUI) generation/presentation module  718  may generate and cause the presentation of graphical user interface(s). For example, the GUI generation/presentation module  718  may generate and cause the presentation of the graphical user interface(s) describe below with reference to  FIGS. 8A-C . 
     As noted above, the control system  700  may include one or more input or output devices. The input/output device(s)  704  may include one or more user display screens that enable a user to select at least a portion of an image that is used by the sensor data receiving and processing module  710 , directional tool high-side determination module  712 , downhole tool high-side determination module  714 , and scribe line offset determination module  716  to calculate the SLO. Examples of the various input/output device(s)  704  are described in greater detail with respect to  FIGS. 8A-C  below. 
     In addition, in some examples the control system  700  may also include one or more communication interfaces  706 , which may support both wired and wireless connection to various networks, such as cellular networks, radio, short range or long range wireless communication networks, shortrange or near-field networks (e.g., Bluetooth®), infrared signals, local area networks, wide area networks, the Internet, and so forth. For example, the communication interface(s)  706  may allow the computing device  700  to provide the SLO determined by the scribe line offset determination module  716  to the directional tool  114 . 
       FIGS. 8A-C  illustrate various graphical user interface examples  800 ,  802 ,  804  that can be presented via the input/output device(s)  704  as described above with reference to  FIG. 7 . The graphical user interface examples  800 ,  802 ,  804  include graphical user interfaces displayed to a user to allow the user to interact with the image data collected by the sensors  110 ,  112  of the sensing component  104 . Once the necessary image data has been selected, the scribe line offset (SLO) may be calculated. 
       FIG. 8A  illustrates the first graphical user interface  800 . In some examples, the first graphical user interface  800 , which may be presented via the input/output device(s)  704  of a computing device, such as a display of computing device  108 , may allow for selection of a primary image. The primary image may include image data collected by either, or both, of the sensors  110 ,  112 , described above with reference to  FIG. 1 . The first graphical user interface  800  may include a browsing option that allows the user to browse from among all of the image data that has been collected from the sensors  110 ,  112 . 
       FIG. 8B  illustrates the second graphical user interface  802 . The second graphical user interface  802 , which may be presented via the input/output device(s)  704  of a computing device, such as the display computing device  108 , may allow for selection of a secondary image. The secondary image may include image data collected by either, or both, of the sensors  110 ,  112 . For example, if the user has selected image data collected by the first sensor  110  as the primary image, the user may select image data collected by the second sensor  112  as the secondary image. Including a primary image collected by the first sensor  110  and a secondary image collected by the second sensor  112  allows the computing device  108  to render a composite image. In some cases, the composite image can include a 360-degree view of the target component  106 . In other examples, the user may choose from among various composite images previously rendered. The first graphical user interface  800  may include a browsing option that allows the user to browse from among the image data that has been collected from the sensors  110 ,  112 . The primary image or the secondary image, or both, may include the image data showing the high-side marking of the directional tool  116 . 
       FIG. 8C  illustrates the third graphical user interface  804 . The third graphical user interface  804 , which may be presented via the input/output device(s)  704  of a computing device, such as the display of computing device  108 , may allow for a user to position certain reference points to align the image with the interface overlay  806 . In this example, the interface overlay  806  includes a horizontal line  808  and a perpendicular line  810  that intersect, along with a dashed circle  812 . The interface overlay  806  may enable a user to align the interface overlay  806  with image data to determine a SLO. The interface overlay  806  may be configured according to the design of the sensing component  104  and the target component  106 . For instance, the sensing component  104  and the target component  106  may be designed to place the downhole tool  116  and the directional tool  114  in the center of and parallel to the sensing component  104  and the center of and parallel to the target component  106 , respectively. This design allows for alignment of the interface overlay  806  with the image data. 
     In some examples, the interface overlay  806  also includes two solid dots  814 ,  816  and one diamond marking  818  that help align the dashed circle  812  with the target component image  820 , previously selected as the primary image in graphical user interface  800 . In this example, the target component image  820  includes markings of the letters “A” through “H,” with each letter representing a certain increment of the 360-degree circle. 
     The two solid dots  814 ,  816  may be placed adjacent to two outer diameter locations of the target component  106  shown in the target component image  820 . The placement of the two solid dots  814 ,  816  helps align the dashed circle  812  of the interface overlay  806  with the target component  106  in the target component image  820 . The alignment of the target component and the dashed circle helps set the bounds of the 360-degree circle of the target component and the dashed circle  812 . The diamond marking  818  is aligned with a third boundary of the target component of the target component image  820  and helps further set the bounds of the 360-degree circle of the target component and the dashed circle  812 . 
     In some examples, an open circle  824  is located at the intersection of the horizontal line  808  and a perpendicular line  810 . This intersection is aligned with the center of the sensing component drilling tool, such as the downhole tool  116 , which the sensing component  104  is attached to, which may further be aligned with the high-side marking. A horizontal axis reference point  822 , represented by an open dashed circle, is also placed at the bounds of the dashed circle  812  along the horizontal axis. This horizontal axis reference point  822  is represented by a patterned circle and represents the location of the high-side marking of the sensing component drilling tool, such as the downhole tool  116 , to which the sensing component is attached. 
     Next, in some examples, the user may then select a calculation point. The calculation point is identified on the graphical user interface  804  by the diamond marking  818 . To determine the scribe line offset (SLO), the chosen calculation point, indicated by the diamond marking  818 , is first identified. Next, the location of the target component drilling tool high-side marking, such as the directional tool  114 , is determined with reference to the markings. While the location of the high-side marking may be known from the image data collected by the sensing component  104 , the location of the target component drilling tool high-side marking with reference to the markings “A” through “H” may not be known or may not be visible in the chosen primary image. 
     In this illustration, the chosen calculation point is represented by the letter “G.” The target component drilling tool high-side marking is known to be at a position located at position “A,” however the label associated with the high-side marking may not be known. Since the unmarked location of the target component high-side marking is known, along with the increment or unit associated with each marking, the chosen calculation point “G” can be used to determine that the target component high-side marking is positioned at marking “A.” 
     To determine that the target component high-side marking is located at marking “A,” the angular offset between the chosen marking point “G” and the target component high-side marking point “A”  826  is determined. For example, if the target component high-side marking is known to be located 90 degrees clockwise from the marking “G,” and each marking “A-H” is known to represent 45 degrees, the system can deduce that the target component marking is located two markings from “G” at marking “A.” Once the target component high-side marking reference point “A”  826  is known, along with the horizontal access reference point  822 , representing the location of high-side marking of the sensing component drilling tool, the SLO between the target component drilling tool high-side marking and the sensing component drilling tool high-side marking is determined. 
       FIG. 9  illustrates an example flow diagram showing an illustrative process for determining a scribe line offset (SLO), or angular offset, using the angular offset apparatus  102  of  FIG. 1  and the control system  700  of  FIG. 7 . The processes are illustrated as a collection of blocks in a logical flow diagram, which represent a sequence of operations, some or all of which can be implemented in hardware, software or a combination thereof. In the context of software, the blocks represent computer-executable instructions stored on one or more computer-readable media that, which when executed by one or more processors, perform the recited operations. Generally, computer-executable instructions include routines, programs, objects, components, data structures and the like that perform particular functions or implement particular abstract data types. Also, a computing device is part of a system having multiple computing devices in communication with each other and/or one or more cloud services. 
     The order in which the operations are described should not be construed as a limitation. Any number of the described blocks can be combined in any order and/or in parallel to implement the process, or alternative processes, and not all of the blocks need be executed. For discussion purposes, the processes herein are described with reference to the frameworks, architectures and environments described in the examples herein, although the processes may be implemented in a wide variety of other frameworks, architectures, or environments. 
     As noted above,  FIG. 9  illustrates an example flow diagram  900  illustrating example processes for determining a scribe line offset (SLO), or angular offset, using the angular offset apparatus  102  of  FIG. 1 . For example, as discussed above, a sensing component  104 , a target component  106 , and a computing device  108  may be used to determine the SLO of a rig environment. The computing device may implement a control system such as the control system  700  described above with respect to  FIG. 7 . 
     At operation  902 , the sensor data is received. For example, the sensor data may be received by the control system  700  of the computing device  108 . In this example, the sensor data receiving and processing module  710  of control system  700  may receive the sensor data for processing. In some instances, the sensor data is transmitted, either wirelessly or via a wired configuration, to the control system  700 . For example, the one or more sensors of a sensing component may implement a wireless antenna, such as the wireless antenna described above with reference to  FIG. 2 , that is able to transmit the sensor data to the control system  700  of the computing device  108 . In other examples, the one or more sensors may be hard-wired to an external device to transmit the sensing data to the computing device  108 . In further examples, any long range or short range wireless communication methods may be used. 
     In some instances, the received sensor data is collected via one or more sensors, such as sensors  110 ,  112  of the sensing component  104  described above. For instance, the sensors  110 ,  112  may include imaging sensors configured to collect image data of the target component  106 . In other instances, the sensor data may include sensor data related to local positioning, heat, light (i.e., including electromagnetic radiation of any frequency), etc. For example, the one or more sensors may be designed to detect light from the target component  106 , such as from lasers that are included in an example target component. Additional and/or alternative examples include one or more sensors configured to detect indicator(s) produced via non-visible light. 
     At operation  904 , the sensor data is processed. The sensor data is processed, for example, by the sensor data receiving and processing module  710 . For instance, the sensor data receiving and processing module  710  may process the image data collected by sensors  110 ,  112  of the sensing component  104 , and may produce a composite image for analysis by the other modules of the control system  700 . As another example, the sensor data may be received from light detecting sensors such as the sensor(s)  610 , described in  FIG. 6 , configured to detect from the light projecting component(s)  608 , is processed. 
     At operation  906 , the marking data is accessed. For instance, the target component marking data  720  may be accessed to retrieve previously stored data regarding the unit of measurement represented by each marking, the increment value of each marking, the marking labels, etc. In some examples, such as when implementing a local positioning system, the marking data may include the known location of the beacon or antenna. In still further examples, the marking data may include the known location that a sensor or marking/indicator component is placed at along the downhole tool or directional tool, such as a high-side marking location that has been stored in the control system  700 . 
     At operation  908 , the high-side location of the directional tool is determined. For example, the high-side location of the directional tool  114  is determined. For instance, the directional tool high-side determination module  712  may analyze the composite image to determine the location of the high-side marking of the directional tool  114  that the target component  106  is aligned with. As described above, the alignment of the target component  106  with the high-side marking of the directional tool  114  may be indicated in a number of ways, including a unique marking, an LED light, a laser beam, etc. that is shown in the composite image. Other methods for determining the location of the high-side marking of the directional tool  114  are also described above with respect to  FIGS. 8A-C . 
     In other examples, the directional tool high-side determination module  712  may analyze local positioning data from one or more local positioning antennas or beacons. As described above, the location of the high-side marking of a directional tool may be determined by establishing a grid system (e.g. placing one or more local positioning components in an environment), placing an antenna or beacon at the directional tool, and measuring the time period needed for a ping from the antenna or beacon to travel to the local positioning component and the time period needed for the ping to travel back to the antenna or beacon. The directional tool high-side determination module  712  may then use the measured time periods, along with the known location/placement information of the antenna or beacon accessed at operation  910 , to determine the location of the high-side of the directional tool. In still further examples, the location of the high-side of the directional tool may be known from the marking data that is accessed at operation  906 . 
     At operation  910 , the high-side location of the downhole tool is determined. For example, the downhole tool high-side determination module  714  may be used to determine the high-side location of the downhole tool. For instance, at least one sensor of the sensors  110 ,  112  of the sensing component  106  may be aligned with the high-side marking of the downhole tool  116  at a known location, serving as the origin location. The origin location data may be pre-programmed into the sensing component  106  and transmitted to the control system  700 . In alternative examples, sensors may be located along the inner surface of the sensing component  106  that may be used to determine the location of the high-side marking of the downhole tool  116 . In still further examples, markings along the sensing component  106  may help determine an offset between the high-side marking of the downhole tool  116  and the sensor. Other methods for determining the location of the high-side marking of the downhole tool  116  by utilizing input from a user via a graphical user interface are also described above with respect to  FIGS. 8A-C . 
     In other examples, the downhole tool high-side determination module  714  may analyze local positioning data from one or more local positioning antennas or beacons. As described above, the location of the high-side marking of a downhole tool may be determined by establishing a grid system (e.g. placing one or more local positioning components in an environment), placing an antenna or beacon at the downhole tool, and measuring the time period needed for a ping from the antenna or beacon to travel to the local positioning component and the time period needed for the ping to travel back to the antenna or beacon. The downhole tool high-side determination module  714  may then use the measured time periods, along with the known location/placement information of the antenna or beacon, to determine the location of the high-side of the downhole tool. 
     At operation  912 , the SLO is determined. The SLO is determined, for example, by the scribe line offset determination module  716 . For instance, once the location of the high-sides of the directional tool and the downhole tool are known, as well as the target component marking data, the scribe line offset determination module  716  may determine the SLO, or angular offset, between the high-side of the directional tool and the high-side of the downhole tool. In some examples, a user may utilize the marking data to help determine the SLO. For example, the user may pick reference points, or markings, to be used to calculate the SLO as described above with respect to  FIGS. 8A-H . At operation  914 , the SLO may be provided to the user and the directional tool via the communication interface(s)  704  for use in directional drilling operations. 
       FIG. 10  illustrates a perspective view of another example sensing component  1000  of the angular offset apparatus described herein. In this example, the sensing component  1000  implements one imaging sensor  1002  placed at a downhole tool or drilling tool and configured to capture image content. For example, the sensing component  1000  may be placed at an external high-side marking of a downhole tool or drilling tool of a drilling environment. The sensing component  1000  may rotate about the downhole tool or drilling tool to capture sensor data associated with the drilling environment. 
     In this example, the imaging sensor  1002  may be placed adjacent to an external high-side marking (not shown) of a downhole tool (not shown) at the start of a rotation to help determine an approximate origin location of the imaging sensor  1002 . Knowing the origin location of the imaging sensor  1002  may help determine the scribe line offset (SLO) by providing information such as the location of the high-side marking of the downhole tool (i.e. the origin of the offset of the rig) as well as helping to set the aspect ratio of the image content or helping to determine other significant values needed for the SLO calculation. In other embodiments, the imaging sensor  1002  may be placed away from the high-side marking of the downhole tool. In some embodiments, the sensing component  1000  itself may include a marking or indicator that may be aligned with an external high-side marking of a tool that may help align the imaging sensor  1002  with the external high-side marking at the start of the rotation. 
     In some examples, the image content may include image data, captured by the imaging sensor  1002  during a rotation about the tool. For example, if the sensing component  1000  is placed adjacent to an external high-side marking of a downhole tool (not shown), the image content may include image data showing a marker or indication of the location of a second high-side marking of another drilling tool, such as a directional tool, of a bottom hole assembly (BHA). The location of the drilling tool high-side marking, along with the location of the downhole tool high-side marking, may be used to determine the SLO, sometimes referred to as the angular offset, of the two high-side markings with increased precision and accuracy. 
     In the illustrated example, the sensing component  1000  implements a mounting mechanism  1004  that can be latched and unlatched for attachment and removal, respectfully, of the sensing component  1000 . The mounting mechanism may be similar in design to the mounting mechanism describe above with respect to  FIG. 2 . For example, the mounting mechanism  1004  may implement various components such as one or more attachment fasteners  1006 ,  1008 , one or more transport mechanisms  1010 ,  1012 , one or more mounting brackets  1014 ,  1016 , and one or more connecting brackets  1018 ,  1020 , similar in design and function to those described above with respect to  FIG. 2 . The mounting mechanism  1004  may help ensure that that sensing component  1000 , or a marking or indicator of the sensing component  1000 , is aligned with the center line of the downhole drilling tool, or other tool, when mounted. 
     The mounting mechanism may further implement a sensing component latching mechanism  1022 . The latching mechanism  1022  may be located adjacent to a rotatable handle (not shown) and operable by way of the rotatable handle. For example, the latching mechanism may include a threaded bolting system that is loosened or tightened, or opened or closed, by way of the rotatable handle. In other examples, other latching mechanisms may be used such as magnets, brackets, straps, etc. The latching mechanism  1022  and rotatable handle may be similar in design and function to those described above with respect to  FIG. 2 . 
     In some examples, the sensing component  1000  may further implement one or more imaging sensor backplates (not shown), one or more backplate fasteners  1024 ,  1026 , one or more protective lenses  1028 , one or more exterior housings  1030 , and a wireless antenna (not shown) similar in design and function to those described above with respect to  FIG. 2 . The wireless antenna may be placed adjacent to any location on the sensing component  1000  where the wireless antenna is able to transmit wireless signal data. In some examples, the sensing component  1000  may not implement a wireless antenna at all, but instead may implement other wireless technology, such as short range or long range wireless communication. 
     In this example, the sensing component  1000  also implements a rotation assembly about which the imaging sensor  1002  rotates. For instance, in the illustrated example, the sensing component  1000  implements a roller bearing assembly  1032  allowing for the imaging sensor  1002  to rotate 180 degrees about a tool. In other examples, other rotation assemblies may be implemented, such as a magnetic rotation assembly, and the rotation assembly may be manually or automatically controlled, via other mechanical means. 
     For example, in  FIG. 10 , the embodiment shown is manually controlled and the sensing component  1000  implements a release mechanism  1034 . The release mechanism  1034  may include a handle. In some instances, when the release mechanism  1034  is lifted the imaging sensor  1002  becomes mobile and may be manually rotated along the roller bearing assembly  1032 . In other instances, when the handle is lowered, or released from the lifted position (as shown in  FIG. 10 ), the imaging sensor  1002  becomes stationary and is not able to be rotated about the roller bearing assembly  1032 . The release mechanism  1034  allows the imaging sensor  1002  to be stationary in a desired position to capture image data. In other examples, the sensing component  1000  may be automatically controlled via mechanical means and may be controlled either locally or externally to the sensing component  1000 . 
     In some examples, the imaging sensor  1002  rotates about the roller bearing assembly  1032  to capture image data of the drilling environment. The imaging sensor  1002  may capture image data in a continuous or non-continuous manner while in rotation. For example, the imaging sensor  1002  may capture image data continuously throughout the rotation about the roller bearing assembly  1032 . In other examples, the imaging sensor  1002  may capture image data only at the beginning and end of the rotation. For instance, the imaging sensor  1002  may capture image data while at a first end  1036  of the roller bearing assembly  1032  and while at a second end  1038  of the roller bearing assembly  1032 , resulting in image data spaced 180 degrees apart. The first end  1036  of the roller bearing assembly  1032  may include a marker or indicator that aligns with an external high-side marking of tool, such as a downhole tool or drilling tool, to which the sensing component  1000  is attached. 
     The non-continuous image data may be processed and utilized for calculating the SLO. During processing, image rendering may be performed, an aspect ratio may be set, combined images may be generated, image recognition techniques may be applied, etc. For instance, the image data captured at the beginning and end of the rotation, such as at first end  1036  of the roller bearing assembly  1032  and at the second end  1038  of the roller bearing assembly  1032 , may be combined to render a 360 degree image of the drilling environment. 
     In addition, while the sensing component  1000  illustrated in  FIG. 10  is removable, alternative examples may include a sensing component  1000  that is permanently attached to a drilling tool. Also, the sensing component  1000  may not implement a mounting mechanism  1004  and may be attached to a tool via alternative attachment means. For example, other mounting mechanisms may be separate components, independent of the sensing component  1000 , that may be attached to the desired tool or may be manufactured as a part of the tool. The sensing component  1000  may also be modular in nature, and may be attached to an independent mounting mechanism at a later time. 
     Still further, the sensing component  1000  may be attached to a tool, such as a downhole tool, by other attachment or mounting means. For example, the sensing component  1000  could be attached to the downhole tool by a spring-loading mounting mechanism. The spring-loading mounting mechanism may implement a collar with one or more springs that allows the sensing component  1000  to be attached to downhole tools varying in diameter. In addition, the sensing component  1000  may be attached to downhole tools with straps or magnetic components that can be placed around the exterior of the downhole tool. 
     The exact number and arrangement of the sensing component  1000  components described above may vary according to the specific angular offset apparatus, drilling rig configuration, and other considerations. For example, in the illustrated example, the sensing component  1000  implements one imaging sensor  1002  and thus implements two mounting brackets  1014 ,  1016 , located at opposite ends of the imaging sensor  1002 . In other examples, the sensing component may implement two imaging sensors, rotatable around the exterior of a tool, and may implement four mounting brackets, as described above with respect to the embodiment of  FIG. 2 . Or, the sensing component may implement some other plurality (e.g., six, ten, twenty, etc.) of imaging sensors, which can be stationary or rotatable, which may result in a different configuration of mounting bracket(s). Thus, since other sensing component  1000  configurations may implement a different number of sensors, or the sensors may have a different arrangement, varied components may be implemented. 
     Note that the design and implementation of the angular offset apparatus shown in  FIG. 10  is not a limiting embodiment. Other designs may be considered and implemented according to the environment, requirement, and design considerations described herein. 
     Although the subject matter has been described in language specific to structural features, it is to be understood that the subject matter defined in the appended claims is not necessarily limited to the specific features described. Rather, the specific features are disclosed as illustrative forms of implementing the claims.