CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to and the benefit of the filing date of U.S. Provisional patent Application No. 63/421,017, filed October 31, 2022, the entirety of which is hereby incorporated by reference herein.

FIELD

[0002] The disclosure relates to systems and methods for determining orientation of a core sample.

BACKGROUND

[0003] Conventionally, in downhole surveying during drilling applications, core samples are obtained through the use of core drilling systems that comprise outer and inner tube assemblies. In operation, a cutting head is attached to the outer tube assembly so that rotational torque applied to the outer tube assembly can be transmitted to the cutting head. A core is generated during the drilling operation, with the core progressively extending along the elongated axis of the inner tube assembly as drilling progresses. Typically, w hen a core sample is acquired, the core within the inner tube assembly is fractured, and the inner tube assembly and the fractured core sample contained therein are then retrieved from within the drill hole, typically by way of a retrieval cable lowered down the drill hole. Once the inner tube assembly has been brought to ground surface, the core sample can be removed and subjected to the desired analysis.

[0004] It is desirable for analysis purposes to have an indication of the orientation of the core sample relative to the ground from which it w as extracted. This is complicated in that it is common to drill at an angle relative to the vertical. For efficiency and accuracy of the mineralogical record, it is desirable to determine the orientation and survey position of each core's position underground before being drilled out and extracted. Such orientation and survey positions allow" for the subsequent production of a three dimensional map of underground mineral/rock content.

[0005] One common w ay of obtaining an indication of the orientation of a core sample is through use of an orientation spear comprising a marker (such as a crayon) projecting from one end of a thin steel shank, the other end of which is attached to a wireline. The orientation spear is lowered down the drill hole, prior to the inner tube assembly being introduced. The marker on the orientation spear strikes the facing surface of material from which the core is to be generated, leaving a mark thereon. Because of gravity, the mark is on the lower side of the drill hole. The inner tube assembly is then introduced into the outer tube assembly in the drill hole. As drilling proceeds, a core sample is generated within the inner tube assembly. The core sample so generated carries the mark which was previously applied. Upon completion of the core drilling run and retrieval of the core sample, the mark provides an indication of the orientation of the core sample at the time it was in the ground.

[0006] Other conventional technologies use core orientation units attached to core inner tubes and back-end assemblies to determine the correct orientation of the drilled out core sample after a preferred predetermined drilling distance intervals during drilling. These core orientation units typically measure rotational direction of the core sample before extraction. On retrieval at the surface of the hole, the rotational direction can be determined by electronic means and the upper or lower side of the core material physically ‘marked’ for later identification by geologists.

[0007] Coupled with the core orientation system, a survey instrument is conventionally used. In this technique, at periodic depths, the survey instrument is lowered down the drill hole to determine azimuth (angular measurement relative to a reference point or direction), dip (or inclination) and any other required survey parameters. These periodic depth survey readings are used to approximate the drill-path at different depths. Together with the rotational position of the extracted core (from the core orientation device), the three dimensional subsurface material content map can be determined.

SUMMARY

[0008] Described herein, in various aspects, is a method comprising determining, by a tool of a drill string, an indication that vibration of the drill string is below a threshold level. The drill string comprises a core barrel containing core and a core barrel orientation measurement device configured to measure at least one core barrel orientation parameter and store a plurality’ of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with the plurality- of orientation values. A time stamp based on an input from an operator can be stored. An interval during which vibration of the drill string is beloyv the threshold level can be identified. Based on the time stamp being within the interval, a core barrel orientation time can be confirmed. A stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time can be obtained.

[0009] In one aspect, a system comprises a drill string. The drill string comprises a core barrel configured to receive core therein and a core barrel orientation measurement device configured to measure at least one core barrel orientation parameter and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with each orientation value of the plurality of orientation values. The system further comprises a tool that is configured to detect vibrations of the drill string. The system further comprises a computing device comprising an input device; at least one processor; and a memory' in communication with the at least one processor. The memory' comprises instructions that, when executed by the at least one processor, cause the at least one processor to receive, from the input device, an operator input indicative of a planned core break and cause, upon receiving from the input device the operator input indicative of the planned core break, the memory' to store a time stamp.

[0010] In one aspect, a method comprises determining, by a first tool of a drill string, a first indication that vibration of the drill string is below a first threshold level. The drill string comprises a core barrel containing core and a core barrel orientation measurement device configured to measure at least one core barrel orientation parameter and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated yvith the plurality of orientation values. A first interval associated with the first indication that vibration of the drill string is below the first threshold level is identified. A second indication that vibration of the drill string is below a second threshold level is determined by a second tool of a drill string. A second interval associated with the second indication that vibration of the drill string is below the second threshold level is identified. A core barrel orientation time is confirmed based on the first interval and the second interval. A stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time is obtained.

[0011] In one aspect, a system comprises a drill string. The drill string comprises a core barrel configured to receive core therein and a core barrel orientation measurement device configured to measure at least one core barrel orientation parameter and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated yvith each orientation value of the plurality' of orientation values. A first tool is configured to detect vibrations of the drill string. A second tool that is configured to detect vibrations of the drill string.

DESCRIPTION OF THE DRAWINGS

[0012] FIG. 1A is a schematic diagram depicting an exemplary drilling system having a drill string positioned within a borehole as disclosed herein. Figure IB is a cross-sectional view of an exemplary' drilling system having a drill string, an outer tube assembly, a drill bit, and an inner tube assembly positioned within a borehole as disclosed herein. Figure 1C is a schematic diagram depicting an exemplary drilling system having a drill string positioned within a borehole, with the drill string being shown in cross-section. Figure ID is an isolated side view of an exemplary drill string as disclosed herein.

[0013] FIG. 2A is a side view of a portion of an exemplary drill string as disclosed herein. FIG. 2B is a cross-sectional side view depicting the portion of the drill string depicted in FIG. 2A. As shown, the drill string can comprise a proximal adapter that houses processing circuitry as disclosed herein. Optionally, the proximal adapter can be a “wireless sub” as further disclosed herein. FIG. 2C is a side view of a portion of an exemplary drill string as disclosed herein showing a downhole sub.

[0014] FIG. 3A is a schematic diagram of a side of a portion of an exemplary inner tube assembly as disclosed herein. FIG. 3B is a schematic diagram of a side cross-section of the inner tube assembly depicted in FIG. 3A. As shown, the inner tube assembly can comprise a core barrel head assembly that houses processing circuitry’ as disclosed herein.

[0015] FIG. 4 is a side view of an exemplary outer tube assembly and drill bit as disclosed herein.

[0016] FIG. 5 is a schematic diagram depicting exemplary processing circuitry housed within an adapter of a drill string as disclosed herein.

[0017] FIG. 6 is a schematic diagram depicting exemplary processing circuitry housed within a core barrel head assembly of an inner tube assembly as disclosed herein.

[0018] FIG. 7 is a schematic diagram depicting the wireless communication between the processing circuitry of an inner tube assembly, the processing circuitry of a drill string adapter, and a remote display device as disclosed herein.

[0019] FIG. 8 is a perspective view of a wireless sub in accordance with embodiments disclosed herein. [0020] FIG. 9 is a system for determining core barrel orientation as disclosed herein.

[0021] FIG. 10 is another system for determining core barrel orientation as disclosed herein.

[0022] FIG. 11 is another system for determining core barrel orientation as disclosed herein.

[0023] FIG. 12 illustrates a remote computing device in communication with the wireless sub as in FIG. 8, the remote computing device showing a user interface.

[0024] FIG. 13 is an exemplary environment comprising a computing device in accordance with embodiments disclosed herein.

[0025] FIG. 14 shows an exemplary data set correlated with time along an x-axis according to at least one aspect disclosed herein.

[0026] FIG. 15 shows an exemplary data set correlated with time along an x-axis according to at least one aspect disclosed herein.

[0027] FIG. 16 is a block diagram of an exemplary system configured to use machine learning as disclosed herein.

DETAILED DESCRIPTION

[0028] The present invention now will be described more fully hereinafter with reference to the accompanying drawings, in which some, but not all embodiments of the invention are shown. Indeed, this invention may be embodied in many different forms and should not be construed as limited to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements. Like numbers refer to like elements throughout. It is to be understood that this invention is not limited to the particular methodology and protocols described, as such may van'. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to limit the scope of the present invention.

[0029] Many modifications and other embodiments of the invention set forth herein will come to mind to one skilled in the art to which the invention pertains having the benefit of the teachings presented in the foregoing description and the associated draw ings. Therefore, it is to be understood that the invention is not to be limited to the specific embodiments disclosed and that modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.

[0030] As used herein the singular forms “a,” “an,” and “the” can optionally include plural referents unless the context clearly dictates otherwise. For example, use of the term “a tool” can represent disclosure of embodiments in which only a single such tool is provided, and in alternative aspects, can represent disclosure of embodiments in which a plurality of such tools are provided.

[0031] All technical and scientific terms used herein have the same meaning as commonly understood to one of ordinary skill in the art to which this invention belongs unless clearly indicated otherwise.

[0032] Ranges can be expressed herein as from “about” one particular value, and/or to “about” another particular value. When such a range is expressed, another aspect includes from the one particular value and/or to the other particular value. Similarly , when values are expressed as approximations, by use of the antecedent “about,” it will be understood that the particular value forms another aspect. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint. Optionally, in some aspects, when values are approximated by use of the antecedent “about,” it is contemplated that values within up to 15%, up to 10%, up to 5%, or up to 1% (above or below) of the particularly stated value can be included within the scope of those aspects. Similarly, if further aspects, when values are approximated by use of “approximately,” “substantially,” and “generally,” it is contemplated that values within up to 15%, up to 10%, up to 5%, or up to 1% (above or below) of the particularly stated value can be included within the scope of those aspects.

[0033] As used herein, the term “proximal” refers to a direction toward a drill rig or drill operator (and away from a formation or borehole), while the term “distal” refers to a direction away from the drill rig or drill operator (and into a formation or borehole).

[0034] As used herein, the terms “optional” or “optionally” mean that the subsequently described event or circumstance may or may not occur, and that the description includes instances where said event or circumstance occurs and instances where it does not. [0035] The word “of’ as used herein means any one member of a particular list, but when such a list is described, it is contemplated that embodiments directed to any combination of the members of such list are also disclosed.

[0036] It is to be understood that unless otherwise expressly stated, it is in no way intended that any method set forth herein be construed as requiring that its steps be performed in a specific order. Accordingly, where a method claim does not actually recite an order to be followed by its steps or it is not otherwise specifically stated in the claims or descriptions that the steps are to be limited to a specific order, it is in no way intended that an order be inferred, in any respect. This holds for any possible non-express basis for interpretation, including: matters of logic with respect to arrangement of steps or operational flow; plain meaning derived from grammatical organization or punctuation; and the number or type of aspects described in the specification.

[0037] The following description supplies specific details in order to provide a thorough understanding. Nevertheless, the skilled artisan would understand that the apparatuses, systems, and associated methods of using the apparatuses and systems can be implemented and used without employing these specific details. Indeed, the apparatuses, systems, and associated methods can be placed into practice by modifying the illustrated apparatus and associated methods and can be used in conjunction with any other apparatus and techniques conventionally used in the industry.

[0038] With reference to FIGS. 1 A-7, disclosed herein, in various aspects, is a drilling system 100 that is configured to acquire data during drilling operations. In these aspects, the data can relate to one or more events or conditions in a borehole 210 formed within a formation 200. In exemplary aspects, the drilling system 100 can comprise a drill string 10 and an inner tube assembly 40 configured for positioning within the drill string.

[0039] FIGS. 1A and 1C illustrate surface portions of exemplary drilling systems 100, and FIG. IB illustrates a subterranean portion of the drilling system. The surface portion of the drilling system 100 shown in FIGS. 1 A and 1C includes a drill head assembly 130 that can be coupled to a mast 150 that in turn can be coupled to a drill rig in a conventional manner. The drill head assembly 130 can be configured to have a drill rod 12 coupled thereto. As illustrated in FIGS. 1A and 1C, the drill rod 12 that is coupled to the drill head assembly 130 can in turn couple with additional drill rods 12 to form a drill string 10. The drill rod 10 and/or an outer tube assembly (as further disclosed herein) can be coupled to a drill bit 70 configured to interface with the material to be drilled, such as a formation 200. The drill head assembly 130 can be configured to rotate the drill string 10 and/or outer tube assembly in a conventional manner. In particular, the rotational rate of the drill string 10 and/or outer tube assembly can be varied as desired during the drilling process. Further, the drill head assembly 130 can be configured to translate relative to the mast 150 to apply an axial force to the dnll string and/or outer tube assembly to urge the drill bit 70 into the formation 200 during a drilling process. The drill head assembly 130 can also generate oscillating forces that are transmitted to the drill string 10 and/or outer tube assembly. These forces can be transmitted through the drill string 10 and/or outer tube assembly to the drill bit 70.

[0040] The drilling system 100 can also include an inner tube assembly 40 positioned within the drill string 10, which in turn is positioned within a drill hole (borehole) 210. Optionally, the borehole 210 can be lined with an outer casing 125 as is known in the art, and the drill string 10 can be received within the outer casing. The inner tube assembly 40 can include a wireline 110, an overshot assembly 120, at least one inner tube 60 (also referred to herein as a core barrel), and a core barrel head assembly 42. In the illustrated example, the at least one inner tube 60 can be coupled to the core barrel head assembly 42, which in turn can be removably coupled to the overshot assembly 120. When thus assembled, the wireline 110 can be used to lower the inner tubes 60, the overshot assembly 120, and the core barrel head assembly 42 into position within the drill string 10. In exemplary aspects, the drilling system 100 can comprise a sled assembly 140 that can move relative to the mast 150. As the sled assembly 140 moves relative to the mast 150, the sled assembly may provide a force against the drill head assembly 130, which may push the drill bit 70, the core barrel head assembly 42. the drill rods 12 and/or other portions of the drill string 10 further into the formation 200, for example, while they are being rotated.

[0041] As shown in FIGS. 1C-1D. the core barrel head assembly 42 can include a latch mechanism 62 that is configured to lock the core barrel head assembly (and, consequently, the at least one inner tube 60) in position at a desired location within the drill string 10. In particular, when the inner tube assembly 40 is lowered to the desired location, the latch mechanism 62 associated with the core barrel head assembly 42 can be deployed to lock the core barrel head assembly into position relative to the drill string 10. In exemplary aspects, the latch mechanism 62 can comprise a latch body 65 having a first member 66 and a sleeve 68 as disclosed in, for example and without limitation, U.S. Patent No. 8,869,918, entitled “Core Drilling Tools with External Fluid Pathways;’ which is incorporated herein by reference in its entirety. The overshot assembly 120 can also be actuated to disengage the core barrel head assembly 42. Thereafter, the at least one inner tube 60 can rotate with the drill string 10 due to the coupling of the inner tubes 60 to the core barrel head assembly 42 and of the core barrel head assembly to the drill string 10.

[0042] At some point, it may be desirable to trip the at least one inner tube 60 to the surface, such as to retrieve a core sample. To retrieve the at least one inner tube 60, the wireline 110 can be used to lower the overshot assembly 120 into engagement with the core barrel head assembly 42 (for example, via a spearhead assembly 64 as is known in the art). The core barrel head assembly 42 may then be disengaged from the drill string 10 bydrawing the latches into the core barrel head assembly. Thereafter, the overshot assembly 120, the core barrel head assembly 42, and the at least one inner tube 60 can be tripped to the surface.

[0043] While a wireline type system is illustrated in FIG. IB, it will be appreciated that the drilling system 100 can optionally be adapted for use in other applications, including, for example and without limitation, reverse circulation (RC), sonic, or percussive drilling operations. Optionally, in exemplary aspects, the drill string 10 can comprise one or more continuous coiled-tube dnll rods. In these aspects, it is contemplated that the inner tube assembly 40 can remain within the drill string (i.e., not be retrievable from the drill string) and can comprise a fixed sub or adapter at its distal end. Further, although illustrative embodiments depict surface drilling, it is contemplated that embodiments disclosed herein can be used in underground drilling operations.

CORE ORIENTATION SYSTEMS

[0044] The disclosed drilling system can comprise a plurality of devices for determining a time between cessation of drilling a core sample and breaking of the core from the formation (i.e., a core break). The system can log a plurality of core barrel orientation measurements and store the core barrel orientation measurements with respective associated time values. The determined times betw een cessation of drilling the core sample and the core break can be related to an associated orientation measurement of the core barrel at the time prior to core break. In this way, an orientation of the core sample prior to separation from the formation can be determined. The respective determined times of the plurality of devices can be compared to check and confirm accuracy of the determined times. In this way, false times not actually associated with core orientation prior to core break can be detected.

[0045] Referring to FIG. 9, the drilling system 100 can comprise the drill string 10, the drill string comprising the core barrel 60 that is configured to receive core therein. The drilling system 100 can comprise at least one core barrel orientation measurement device 45 that is configured to measure at least one core barrel orientation parameter and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with the orientation values. With further reference to FIG. 6, the core barrel orientation measurement device 45 can comprise at least one accelerometer 48 (e.g., a three-axis accelerometer) and/or a gy roscope or other measurement device 54, as further described herein. The at least one core barrel orientation parameter can comprise a rotational orientation of the core barrel. In some optional aspects, the at least one core barrel orientation parameter can further comprise, for example, dip, and/or azimuth. In various aspects, the at least one core barrel orientation parameter can be measured at consistent intervals (e.g., every minute), at random intervals, or upon a condition, such as cessation of drilling.

[0046] At least one tool (referred to herein also as an adapter) 20 that is configured to measure vibrations can be coupled to, and form part of, the drill string. In some optional aspects, the tool 20 can be configured to remain outside of the borehole. For example, the tool 20 can couple to and form a proximal portion of the drill string 10. Referring also to FIG. 10, in further aspects, the tool 20 can be a downhole tool 20’ as illustrated herein. Referring also to FIG. 11, in still further aspects, the system 100 can comprise both a downhole tool 20’ and a tool 20 that is configured to remain outside the borehole. The tool(s) 20/20’ can be configured to detect vibrations of the drill string and as well as low or zero vibration. The low or zero vibration can correspond to an interval during which drilling is ceased in order to perform a core break. Accordingly, the tool 20 can comprise a computing device (e.g., a microcontroller comprising a processor 47 (FIG. 6)) that is configured to (a) determine an indication that that vibration of the drill string is below a threshold level, and (b) identify an interval associated with the indication that vibration of the drill string is below the threshold level. For example, the tool 20 can store a start time and an end time of the interval, or the tool can store a start time and a duration of the interval associated with the indication that vibration of the drill string is below the threshold level. In other aspects, it is contemplated that the tool can store the detected vibrational data, and the interval can be determined (optionally, at a later time) by another computing device. In still further aspects, the vibration data can be displayed on a display, and an operator can manually identify the interval.

[0047] A computing device 500 (e.g., optionally, a handheld device) can enable an operator to save a time stamp indicative of a time (e.g., a planned core break). The computing device 500 can comprise an input device. For example, the computing device 500 can be configured to provide an operator with an interface. The interface can enable the operator to store a time stamp indicative of a planned core break. For example, after stopping drilling in preparation of and in advance of the planned core break, the operator can, via the input device, cause the computing device 500 to store the time stamp. In some optional aspects, the computing device 500 can be a tablet, a smartphone, a laptop, or a desktop computer. More generally, the computing device 500 can be configured in accordance with various further embodiments and described herein with reference to computing device 1001 and FIG. 13.

[0048] Each of the core barrel orientation measurement device 45, tool(s) 20, and computing device 500, can have synchronized clocks. For example, each can have a clock that is started at the same time (e.g., at the beginning of drilling), or each can have a clock that is set to a universal time, such as the time of day. In this way, the time stamp and the interval (associated with the indication that vibration of the drill string is below the threshold level) can be compared and associated with the core barrel orientation parameter(s) acquired by the at least one core barrel orientation measurement device at a particular time.

[0049] FIG. 14 illustrates exemplary data captured by the core barrel orientation measurement device 45, tool 20. and computing device 500. For example, the tool vibrational data 302 is shown dropping below the threshold T at the interval start time 306 and rising above the threshold at the interval end time 308. In some aspects, the tool vibrational data 302rising above the threshold T can correspond to resuming drilling. In other aspects, tool vibrational data 302 rising above the threshold T can correspond to a core break. Core barrel orientation data from the core barrel orientation measurement device can be collected at orientation measurement times 304 provided (regularly or irregularly) spaced intervals. As illustrated in FIG. 14, across the duration shown, three core orientation measurements are taken during the interval in which vibration data is below the threshold, and four are taken outside of the interval. The operator time stamp 310 is within the interval, providing confirmation that the time stamp provided by the operator corresponds to a time when the core barrel orientation likely is not moving. The three core orientation measurements taken during the interval can, therefore, be used as confirmed core barrel orientation measurements.

[0050] Thus, the time stamp 310 caused by the operator can be compared to the interval to confirm that each is associated with a position of the core barrel between cessation of drilling the core sample and the core break. For example, the time stamp 310 being within the interval can confirm that the time of the time stamp properly correspond to the time prior to separation of the core from the formation. Thus, the time stamp being within the interval can be indicative of a time during which the core barrel is in position prior to core break.

That is. the orientation of the core barrel during said interval that includes the time stamp can correspond to a confirmed orientation of the core barrel after cessation of drilling the core sample and prior to the core break. Accordingly, the at least one core barrel orientation parameter acquired by the at least one core barrel orientation measurement device during the interval can be obtained. The orientation of the core barrel can then be associated with the orientation of the core sample. For example, in some aspects, the core orientation of the core can be understood to be the orientation of the core barrel. In other aspects, slipping or other relative movement between the core and the core barrel can be accounted for.

[0051] Determining that the time stamp and the interval are not in agreement (e.g., the time stamp not being within the interval) can be indicative of a false time stamp. For example, the time stamp being outside of (or absent from) the interval can indicate that drilling was ceased, but a core break was not then performed. In other aspects, the time stamp being outside of the interval can indicate that the drill string moved between the time stamp and the core break, and, thus, the orientation at the time stamp (selected by the operator) may not be accurate.

[0052] Optionally, the time stamp and the interval can manually be compared by an operator (e.g., by viewing a screen that displays the data illustrated in FIG. 14). In other aspects, a computing device can determine agreement between the time stamp and the interval, thereby confirming a core barrel orientation time (that is, a time after drilling and before the core break at which core barrel orientation measurements correspond to the position of the core barrel before and at core break). The core barrel orientation time can be a discrete time within the interval or the interval itself. For example, the memory of the computing device 500 can comprise instructions that, when executed by the at least one processor of the computing device, cause the at least one processor to confirm, based on the time stamp and the interval, the core barrel orientation time. Confirmation of the core barrel orientation time can be performed by determining that the time stamp is within the interval. Optionally , the computing device 500 can further be configured to obtain a stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time. The core barrel orientation time can be a time within the interval at which a core orientation was stored by the core barrel orientation measurement device. If the time stamp is outside the interval, the computing device 500 can provide an indication (e.g.. a warning) that the core break time may not be accurate.

[0053] In further aspects, a second computing device (e.g., computing device 1001 that is different from the computing device that permits the operator to cause the time stamp) can relate the time stamp and the interval. The second computing device can be, for example, a remote or cloud computing device. The second computing device can have a memory that comprises instructions that, when executed by the at least one processor, cause the at least one processor to confirm, based on the time stamp and the interval, a core barrel orientation time. For example, the computing device can determine whether the time stamp is between the interval start time 306 and the interval end time 308. In some optional aspects, the second computing device can further obtain a stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time. The second computing device can be configured to communicate (either directly or indirectly) with the first computing device 500, the tool(s) 20, and the core barrel orientation measurement device 45. The second computing device can, therefore, receive the time stamp and the interv al and the stored core barrel orientation parameter(s) and respective time values associated with the orientation values. Although the first and second computing devices 500, 1001 are shown in communication with downhole instruments such as the tool 20’ and the core barrel orientation measurement device 45 via dotted lines in FIGS. 9-11, it is contemplated that, in some optional aspects, the first and second computing devices can be in communication with the dow nhole instruments only upon removal of the downhole instruments from the borehole (e.g., via wireless communication as further disclosed herein).

[0054] In some aspects, the tool 20 can be configured to detect a shockwave corresponding to a core break. The shockwave can have a unique vibrational signature such as, for example, a short duration and a different vibrational amplitude than drilling. Optionally, the tool 20 can store a second time stamp corresponding to the time of the core break. In these aspects, the core barrel orientation time can be confirmed based by determining that the interval is prior to the shockwave (or the second time stamp).

[0055] In some aspects, vibration of the drill string can be measured by an accelerometer of the tool 20. The accelerometer can be configured to measure a plurality of acceleration values. The indication that vibration of the drill string is below the threshold level can comprise at least one acceleration value of the plurality of acceleration values being below an acceleration threshold. In some optional aspects, the at least one acceleration value is zero, corresponding to an acceleration below a minimum measurable threshold of the accelerometer.

[0056] Referring to FIGS. 9 and 10, a method can comprise storing a time stamp based on an input from an operator. An interval during which vibrations obtained by a tool 20 (or downhole tool 20’) of a drill string 10 are below a threshold level can be determined. For example, an operator can identify the interval during which the vibrations are below the threshold level. In further aspects, a computing device can determine the interval.

[0057] A core barrel orientation time can be determined based on the time stamp being within the interval. As stated herein, the core barrel orientation time can be the interval during which the vibrations obtained by the tool of the drill string are below the threshold level. In other aspects, the core barrel orientation time can relate to the interval. For example, the core barrel orientation time can be a discrete time within the interval. A stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time can be obtained. In some aspects, the respective time that corresponds to the core barrel orientation time comprises a time value between a start time of the interval during which vibration of the drill string detected by the tool 20 is below the threshold level and the time stamp.

[0058] In some aspects, an accelerometer of the tool of the drill string can measure a plurality of acceleration values. The interval during which vibration of the drill string is below the threshold level can comprise an interval during which at least one acceleration value of the plurality of acceleration values is below an acceleration threshold. In some aspects, the at least one acceleration value can be zero, corresponding to an acceleration below a minimum measurable threshold of the accelerometer. [0059] The core barrel orientation parameter can be associated with an orientation of the core.

[0060] Optionally, a shockwave corresponding to a core break can be detected. Obtaining the stored orientation value can comprise obtaining a stored orientation value associated wi th a time prior to the shockwave.

[0061] The core barrel orientation measurement device can measure the at least one core barrel orientation parameter. The plurality of orientation values associated with the at least one core barrel orientation parameter and the respective time values associated with the plurality of onentation values can be stored.

[0062] In some aspects, identifying the interval during which vibration of the drill string is below the threshold level can comprise storing a start time and an end time. In other aspects, identifying the interval during which vibration of the drill string is below the threshold level can comprise storing a start time and a duration of the interval.

[0063] In further aspects and with reference to FIGS. 11 and 15, the drilling system 100 can comprise at least two tools 20, and the two tools can collect data (e.g., vibrational data) that can be checked against each other to confirm the core barrel orientation time. The drill system 100 can comprise the drill string 10, the drill string comprising the core barrel 60 that is configured to receive core therein. The drilling system 100 can comprise at least one core barrel orientation measurement device 45 that is configured to measure at least one core barrel orientation parameter and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with the orientation values. The core barrel orientation measurement device 45 can comprise at least one accelerometer 48 (e.g., a three-axis accelerometer) and/or a gyroscope or other measurement device 54, as further described herein with reference to FIG. 6. The at least one core barrel orientation parameter can comprise a rotational orientation of the core barrel. In some optional aspects, the at least one core barrel orientation parameter can further comprise, for example, dip, and/or azimuth. In various aspects, the at least one core barrel orientation parameter can be measured at consistent intervals (e.g., every minute), at random intervals, or upon a condition, such as cessation of drilling.

[0064] A first tool (e.g., tool 20) and a second tool (e.g., tool 20’) can be coupled to, and form part of, the drill string. The first tool can be configured to detect vibrations of the drill string. The second tool can be configured to detect vibrations of the drill string. As described herein, in some aspects, the first and second tools can each comprise accelerometers, and the detection of vibrations can comprise measurements of acceleration values.

[0065] In some aspects, and with further reference to FIGS. 11 and 15, the system can further comprise a computing device 500 comprising at least one processor and a memory in communication with the at least one processor. The memory can comprise instructions that, when executed by the at least one processor, cause the at least one processor to confirm, based on the vibrational data 320 detected by the first tool 20 and the vibrational data 322 detected by the second tool 20’, a core barrel orientation time. For example, the vibrational data of each of the first and second tools 20, 20' being less than respective thresholds Tl, T2 can correspond to pauses in drilling. The first and second tools 20, 20’ can respectively detect respective first and second intervals during which the vibrations are below the respective thresholds. The computing device 500 can determine an overlap between the first and second intervals. Thus, the first and second tools 20, 20’ can serve to check each other to confirm that the detected low or zero vibrations correspond to a cessation of drilling that precedes a core break.

[0066] In still further aspects, the system 100 can comprise a computing device that permits an operator to provide an additional time stamp 310. Accordingly, the time stamps based on vibrational measurements from each of the first and second tools 20, 20’ and the operator time stamp can be used to confirm the core barrel orientation time.

[0067] The system 100 can optionally receive an operator input indicative of a planned core break and store a time stamp based on the operator input. For example, the computing device 500 (or a separate computing device 1001) can comprise an input device. The memory of said computing device can comprise instructions that, when executed by the at least one processor, cause the at least one processor to: receive, from the input device, an operator input indicative of a planned core break; and cause, upon receiving from the input device the operator input indicative of the planned core break, the memory to store a time stamp.

[0068] The indication that vibration of the drill string is below the first and second threshold levels can comprise at least one acceleration value of the plurality of acceleration values being below' a respective acceleration threshold. In some aspects, the first and second threshold levels can be the same. For example, in some aspects, the at least one acceleration value of the plurality of acceleration values of each accelerometer being below a respective acceleration threshold can be measured as zero by the accelerometers, corresponding to an acceleration below a minimum measurable threshold of the accelerometers.

[0069] Referring to FIGS. 11 and 15, a method of using the system 100 illustrated in FIG. 11 can comprise determining, by the tool 20 of the drill string 10, a first indication that vibration of the drill string is below a first threshold level. A first interval can be associated with the first indication that vibration of the drill string is below the first threshold level. For example, the first interval can have an interval start time 324 at which the vibration of the drill string as measured by the tool 20 falls below the first threshold level and an interval end time 326 at which the vibration of the drill string as measured by the tool 20 rises above the first threshold level.

[0070] The tool 20’ of a drill string can determine a second indication that vibration of the drill string is below a second threshold level. A second interval associated with the second indication that vibration of the drill string is below the second threshold level can be identified. For example, the second interval can have an interval start time 328 at which the vibration of the drill string as measured by the tool 20’ falls below the second threshold level T2 and an interval end time 330 at which the vibration of the drill string as measured by the tool 20’ rises above the second threshold level T2. A core barrel orientation time can be confirmed based on the first interv al and the second interval. A stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time can then be obtained.

[0071] The method can further comprise measuring, by an accelerometer of the first tool of the drill string, a plurality of acceleration values. The indication that vibration of the drill string is below the first threshold level can comprise at least one acceleration value of the plurality of acceleration values being below an acceleration threshold. In some aspects, the at least one acceleration value is zero, corresponding to an acceleration below a minimum measurable threshold of the accelerometer.

[0072] The core barrel orientation parameter can be associated with an orientation of the core.

[0073] In some aspects, the core barrel orientation time can be confirmed based on the first interval and the second interval by determining that (and when) the first interval and second interval overlap. [0074] In some aspects, a shockwave corresponding to a core break can be detected (for example, using one or more sensors as disclosed herein). The obtained stored orientation value can be associated with a time prior to the shockwave.

[0075] In some aspects, the method can further comprise storing a time stamp based on an input from an operator. The core barrel orientation time can be confirmed based on the first interval, the second interval, and the time stamp. For example, the core barrel orientation time can be the overlap of the first and second interval if the time stamp is within said overlap. In this case, the stored orientation value of the plurality of orientation values associated with a respective time value within said overlap can then be obtained.

[0076] Further details of exemplary tools 20 are provided in U.S. Patent Application Publication No. 2021/0079780, filed September 11, 2020, the entirety of which is hereby incorporated by reference herein.

[0077] Referring to FIGS. 2A-4, in one aspect, the drill string 10 can have a longitudinal axis 16 and comprise at least one drill rod 12 and at least one adapter 20 coupled to the at least one drill rod. In this aspect, each adapter 20 of the at least one adapter can comprise processing circuitry 22 and cooperate with the at least one drill rod 12 to define an interior 14 of the drill string 10. For example, it is contemplated that at least one adapter 20 can comprise a hollow annular body, with the inner diameter of the adapter defining the interior 14 of the drill string 10. Optionally, it is contemplated that each adapter 20 can define an enclosed interior portion that is configured to house at least a portion of the processing circuitry 22 of the adapter. For example, it is contemplated that the processing circuitry 22 can be enclosed within the walls of the adapter. In other exemplary configurations, the processing circuitry 22 can be affixed or otherwise attached to the inner diameter of the adapter 20 (that defines the interior 14 of the drill stnng 10), sealed to a portion of the exterior of the adapter 20 using epoxy or other sealant materials, embedded into, housed, or at least partially received within an annular or partially annular slot or cavity defined in a wall of the adapter 20. In additional aspects, it is contemplated that an outer diameter of the adapter 20 can correspond to an outer diameter of the drill string 10.

[0078] In exemplary aspects, the drilling system 100 can further comprise a drill bit 70. Optionally, in these aspects, the drill bit 70 can be operatively coupled to a distal end of the drill string 10. Alternatively, in these aspects, the drilling system 100 can further comprise an outer tube assembly 80 having a distal end 82 that is operatively coupled to the drill bit 70. It is contemplated that the outer tube assembly 80 can comprise at least one outer tube 84 as is know n in the art.

[0079] In further exemplary aspects, it is contemplated that the inner tube assembly 40 can comprise at least one inner tube (core barrel) 60 positioned between the core barrel head assembly 42 and the drill bit 70 relative to the longitudinal axis 16 of the drill string 10.

[0080] In exemplary aspects, the interior 14 of the drill string 10 can be configured to receive wireline tooling as further disclosed herein, an inner tube assembly 40, and/or drilling fluid as further disclosed herein. Thus, in exemplary aspects, the adapter can be configured to receive (and permit passage of) the wireline tooling, inner tube assembly, outer tube assembly, and/or drilling fluid as it moves through the drill string 10. Optionally, in some aspects, the adapter can be configured to only permit passage of drilling fluid. In further exemplary aspects, and as shown in FIGS. 2A-2B, the at least one adapter 20 of the drill string 10 can comprise a proximal adapter coupled to a proximal end of the drill string. Optionally, in these aspects, the at least one adapter 20 can comprise only a proximal adapter. In exemplary aspects, the at least one adapter 20 of the drill string 10 can be configured for threaded engagement with one or more drill rods 12 of the drill string in a conventional manner. In further exemplary aspects, it is contemplated that the at least one adapter 20 of the drill string 10 can comprise a plurality of adapters that are axially spaced relative to the longitudinal axis 16 of the drill string, with one or more of the adapters comprising processing circuitry ⁷ as disclosed herein. In these aspects, it is contemplated that the plurality of adapters can be configured to enhance telemetry impulses in longer drill strings.

[0081] In an additional aspect, and with reference to FIGS. 1A-1D and 3A-3B, the inner tube assembly 40 can have a core barrel head assembly 42 and processing circuitry 46. In this aspect, the core barrel head assembly 42 can define an interior cavity 44, and the processing circuitry 46 can be positioned within the interior cavity of the core barrel head assembly. In wireline drilling systems, it is contemplated that the interior of the inner tube assembly 40 can be used to capture samples, whereas the interior cavity of the core barrel head assembly 42, which is separated from the interior of the inner tube assembly 40 that collects the samples, can be a suitable location for the processing circuitry 46. Optionally, in exemplary aspects, it is contemplated that the inner tube assembly can comprise additional processing circuitry ⁷ positioned at other locations along the longitudinal axis 16 of the drill string 10. Optionally, in further exemplary aspects, it is contemplated that the processing circuitry 46 can be positioned at other locations within the inner tube assembly 40. For example, in non-wireline drilling operations, it is contemplated that the processing circuitry 46 can be positioned distally within the inner tube assembly 40, optionally within a distal string adapter (not shown).

[0082] In operation, the processing circuitry' 46 of the inner tube assembly 40 can be configured to detect mechanical impulses generated during drilling operations within the borehole 210. For example, the processing circuitry 46 of the inner tube assembly 40 can be configured to detect and process mechanical impulses generated from down-hole tooling interactions or drill string drilling vibrations. It is contemplated that the processing circuitry 46 of the inner tube assembly 40 can be further configured to wirelessly transmit signals indicative of the mechanical impulses to the processing circuitry 46 of the at least one adapter 20 of the drill string 10. In operation, the processing circuitry 22 of the at least one adapter 20 of the drill string 10 can be configured to wirelessly transmit signals indicative of the mechanical impulses to a remote location outside the borehole 210. For example, and with reference to FIG. 7, it is contemplated that the processing circuitry 22 of the at least one adapter 20 of the drill string 10 can comprise a wireless transmitter 25 that is configured to wirelessly transmit signals indicative of the mechanical impulses to a display device 300 positioned outside the borehole 210. In exemplary aspects, the display device 300 can comprise a wireless receiver 310 that is configured to receive the wireless signals generated by the wireless transmitter 25 of the processing circuitry’ 22 of the drill string 10. Optionally, in these aspects, it is contemplated that the display device 300 can be provided as part of a remote drilling operator station, which can optionally comprise a computing device. In various optional aspects, it is contemplated that the display device 300 can be a portable (e.g., handheld) display device. In exemplary aspects, the wireless transmitter 25 of the processing circuitry 22 of the drill string 10 can be an ultrasonic transmitter that is configured to transmit ultrasonic signals corresponding to the detected mechanical impulses. In these aspects, it is contemplated that the wireless receiver 310 of the display device 300 can be an ultrasonic receiver that is configured to wirelessly receive the ultrasonic signals generated by the wireless transmitter 25 of the processing circuitry 22 of the drill string 10. In use, it is contemplated that the ultrasonic signals generated by the processing circuitry 22 of the drill string 10 can be configured to travel through metallic components of the drilling system 100. Further details directed to use and transmission of ultrasonic signals are disclosed in International Patent Application Publication No. WO/2012/045122, filed October 7, 2011, the entirety of which is hereby incorporated by reference herein. Although the wireless signals described above are ultrasonic and mechanical impulse signals, it is contemplated that other wireless signal formats, such as Wi-Fi, infrared, and BLUETOOTH, can be used. However, in some applications, it is contemplated that these alternative formats can lead to undesired exposure, proximity, and/or line-of-sight requirements that are avoided when using ultrasonic signals and mechanical impulses. For example, it is contemplated that Wi-Fi and BLUETOOTH signals can be difficult to process when a wireline system is drilling with mud (or other drilling fluid). It is further contemplated that that other signal formats (e.g., infrared laser) can be used. For example, infrared laser signals can be particularly beneficial in drilling operations such as, for example, reverse circulation, sonic, and/or air drilling.

[0083] In exemplary aspects, and with reference to FIG. 6, the core barrel orientation measurement device 45 can be embodied as the processing circuitry 46 of the inner tube assembly 40. The processing circuitry 46 of the inner tube assembly 40 can comprise a processor 47, such as, for example and without limitation, a microcontroller. In other aspects, the processing circuitry 46 of the inner tube assembly 40 can comprise at least one accelerometer 48 (e.g.. a multi-axis accelerometer) positioned in communication with the processor 47. In additional aspects, the processing circuitry 46 of the inner tube assembly 40 can comprise an electro-mechanical impulse generator 50 positioned in communication with the processor 47 and configured to send mechanical impulse signals to the processing circuitry 22 of the at least one adapter 20 of the drill string 10. Optionally, the processing circuitry 46 of the inner tube assembly 40 can comprise at least one fluid pressure sensor 52 that is positioned in communication with the processor 47 and configured to detect at least one drilling condition as further disclosed herein. Optionally, the processing circuitry 46 of the inner tube assembly 40 can comprise at least one additional measurement device 54 positioned in communication with the processor 47. In exemplary non-limiting aspects, the at least one additional measurement device 54 can comprise at least one temperature sensor and/or at least one gy roscope (e.g., multi-axis gyroscope). Optionally, it is contemplated that the at least one accelerometer 48 can comprise a combined accelerometer and gyroscope.

[0084] In an additional aspect, and as shown in FIG. 3B, the inner tube assembly 40 can comprise a power source 56 positioned in electrical communication with the processing circuitry 46 of the inner tube assembly 40. Optionally, in this aspect, the power source 56 of the inner tube assembly 40 can comprise a battery (e.g., a Lithium ion battery ). Optionally, in further aspects, the inner tube assembly 40 can comprise a pow er generator 58 that is electrically coupled to the power source 56 (e.g., batten’) to re-charge the power source during drilling operations. In one optional aspect, the power generator 58 can be a piezoelectric power generator that harvests energy' from drilling percussion or vibration (e.g., the vibrations and forces produced by the drill string during drilling operations). In another optional aspect, the power generator 58 can be a turbine generator that is driven by flow of drilling fluid during drilling operations. Thus, in this aspect, it is contemplated that the power generator 58 can be positioned in fluid communication with the drilling fluid during drilling operations. In a further optional aspect, the power generator 58 can be a rotary' and brushless- induction generator that is configured to be driven by relative rotational movement between the inner tube assembly and the drill string.

[0085] In further exemplary aspects, and with reference to FIG. 5, the processing circuitry 22 of at least one adapter 20 of the drill string 10 can comprise a processor 23, such as, for example and without limitation, a microcontroller. In other aspects, the processing circuitry' 22 of at least one adapter 20 of the drill string 10 can comprise at least one accelerometer 24 (e.g., a multi-axis accelerometer) positioned in communication with the processor 23. Optionally’, in additional aspects, the processing circuitry 22 of at least one adapter 20 of the drill string 10 can comprise an electro-mechanical impulse generator 26 that is positioned in communication with the processor 23 and configured to send mechanical impulse signals to the processing circuitry 46 of the inner tube assembly 40. In these aspects, it is contemplated that the processing circuitry 46 of the inner tube assembly 40 can be configured to detect the mechanical impulse signals generated by the electro-mechanical impulse generator 26 of the processing circuitry’ 22 of the drill string 10. In operation, it is contemplated that the processing circuitry’ 22 of the at least one adapter 20 of the drill string 10 can be configured to receive control signals from a remote location outside the borehole 210. Optionally, the processing circuitry 22 of the at least one adapter 20 of the drill string 10 can comprise at least one additional measurement device 28 positioned in communication with the processor 23. For example, it is contemplated that the at least one additional measurement device 28 can comprise a temperature sensor and/or a gyroscope (e.g., a multiaxis gyroscope). Optionally, it is contemplated that the at least one accelerometer 24 can comprise a combined accelerometer and gyroscope.

[0086] In an additional aspect, each adapter 20 of the drill string can comprise a power source 30 positioned in electrical communication with the processing circuitry 22 of the adapter. Optionally, in this aspect, the power source 30 of at least one adapter 20 of the drill string 10 can comprise a battery (e.g., a Lithium ion battery). Optionally, in a further aspect, at least one adapter 20 of the drill string can comprise a power generator 32 that is electrically coupled to the power source 30 (e.g., battery) to re-charge the power source during drilling operations. In one optional aspect, the power generator 32 can be a piezoelectric power generator that harvests energy from drilling percussion or vibration (e.g., the vibrations and forces produced by the dnll string during drilling operations). In another optional aspect, the power generator 32 can be a turbine generator that is driven by flow of drilling fluid during drilling operations. Thus, in this aspect, it is contemplated that the power generator 32 can be positioned in fluid communication with the drilling fluid during drilling operations. In a further optional aspect, the power generator 32 can be a rotary and brushless-induction generator that is configured to be driven by relative rotational movement between the inner tube assembly and the drill string.

[0087] It is further contemplated that the processing circuitry 22 of the at least one adapter 20 of the drill string can be configured to determine the times at which mechanical impulse data is detected by the processing circuitry 46 of the inner tube assembly 40. In exemplary aspects, at least one of the processing circuitry 22 or the processing circuitry 46 can comprise a clock that provides time information to the processing circuitry 22. Thus, the processing circuitry 22 can use the time information provided by the clock to determine the times at which mechanical impulse data is detected by the processing circuitry 46 of the inner tube assembly 40. In exemplary aspects, it is contemplated that the clock can be a 25 MHz or a 4 GHz clock for establishing the times of events w ithin electronic systems as is known in the art. Optionally, in exemplary aspects, the processing circuitry 22 can be configured to be driven entirely by the clock in checking the outputs of one or more of the sensors disclosed herein. Alternatively, it is contemplated that the processing circuitry 22 can communicate with the clock to establish an interrupt-driven system for checking the outputs of one or more of the sensors disclosed herein.

[0088] Referring to FIG. 8, the wireless sub 400 (e.g., the tool 20) can comprise various sensors for monitoring various aspects of drilling and drilling-associated activities, such as, for example, core retrieval. In some aspects, mounting the wireless sub 400 in-line allow s for detecting drill string mechanical impulses, such as, for example, axial and torsional vibrations resulting from dynamic load response. These axial and torsional vibrations can be associated with vibrational signatures that correspond to various operating conditions, such as a likelihood of drill string deformation. Accordingly, measured vibrations can provide information including, but not limited to, an indication of imminent permanent twisting deformation overload. An operator can receive an indication of such vibrational signatures and stop drilling or change the drilling parameters to prevent damage to the drill string. As should be understood, in further aspects, mechanical impulses detected by the wireless sub 400 are not limited to vibrations.

[0089] According to some aspects, the wireless sub 400 can couple to the drill string via an adapter sub or with one or more quick-attach adapter subs. A direct coupling of the wireless sub 400 to the drill string (so that the wireless sub 400 forms part of the drill string) enables the wireless sub to measure the vibrations of the drill string. Optionally, the wireless sub 400 can attach to the drill string below the drill rig’s top drive unit or to a “Kelly rod” in a hollowspindle chuck-drive unit. As should be understood, a Kelly rod is a drill rod that is maintained at the top of the drill string while additional drill rods are added or subtracted below it. In some optional aspects, the wireless sub 400 can be mated directly to the Kelly rod. In further aspects, an adapter sub can couple a drilling unit of a top-drive drill rig to the wireless sub 400. Vibrations of the drill rig can be dampened through the top-drive unit and drill string adapter sub (e.g., adapter subs for top-drive rigs) or through the chuck-drive and Kelly rod. Accordingly, the wireless sub 400 can be at least partially isolated (or completely or substantially completely isolated) from the vibrations of the drill rig. This configuration can be contrasted with, for example, vibration sensors in a floating sub that receive vibrations from the drill rig, which mask the vibrations from the drill string and inhibit detection of drill string vibrational signatures.

[0090] According to some aspects, the wireless sub 400 can be maintained outside of the borehole 210 throughout a drilling or mining operation. That is, during drill string makeup, drill rods can be added distally of the wireless sub 400. In maintaining the wireless sub 400 outside of the borehole, the wireless sub 400 is not constrained to a maximum diameter that is less than that of the borehole. Rather, the wireless sub 400 can optionally have a diameter that is greater than the operative diameter of the drill bit or greater than the operative diameter of the borehole. Accordingly, the wireless sub can be sufficiently rigid and can be packaged with sufficient batteries for a long battery life. Further, in maintaining the wireless sub at the proximal end of the drill string and outside the borehole, the wireless sub can optionally maintain constant direct communication with a remote computing device. [0091] Referring to FIG. 12. the computing device 500 can provide an interface for providing information to the operator. Optionally, the remote computing device 500 can receive an input from the operator (e.g., via a touchscreen, keypad, or other input device) and communicate said input to the wireless sub 400. For example, the remote computing device 500 can optionally receive operator input to adjust settings on the wireless sub 400 or poll the wireless sub 400 for data. The remote computing device 500 can receive additional information from other sources such as sensors on the drill rig.

[0092] In various optional aspects, the remote computing device 500 can display information such as, for example, weight on bit, rod force, torque on bit, drilling fluid pressure, rotational speed, penetration rate, fluid flow rate, and depth. The remote computing device 500 can receive operator inputs such as, for example, depth, drilling status, and miscellaneous event logs. Optionally, the event logs can be automatically associated with a depth and/or time. The remote computing device can further report metrics (optionally, automatically), such as, for example, average torque, average fluid pressure, average rotation speed, average weight on bit, average penetration rate, and/or average fluid flow rate. Such information, inputs, and metrics can be provided in a conventional fashion, based on outputs and/or signals received from various sensors and/or determinations made by a processor of a computing device (e.g., the remote computing device 500).

Computing Device

[0093] FIG. 13 shows a computing system 1000 including an exemplary configuration of a computing device 1001 for use with the drilling system 100. In some aspects, the computing device 1001 can be embodied as the remote computing device 500 (FIG. 16), as disclosed herein. In further aspects, it is contemplated that a separate computing device, such as, for example, a tablet, laptop, or desktop computer can communicate with the system 100 and can enable the operator to interface with the system 100.

[0094] The computing device 1001 may comprise one or more processors 1003, a system memory' 1012, and a bus 1013 that couples various components of the computing device 1001 including the one or more processors 1003 to the system memory 1012. In the case of multiple processors 1003, the computing device 1001 may utilize parallel computing. [0095] The bus 1013 may comprise one or more of several possible types of bus structures, such as a memory bus, memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures.

[0096] The computing device 1001 may operate on and/or comprise a variety of computer readable media (e.g., non-transitory). Computer readable media may be any available media that is accessible by the computing device 1001 and comprises, non-transitory, volatile and/or non-volatile media, removable and non-removable media. The system memory 1012 has computer readable media in the form of volatile memory, such as random access memory (RAM), and/or non-volatile memory, such as read only memory (ROM). The system memory 1012 may store data such as drilling data 1007 (i.e., data from signals received by the wireless sub) and/or program modules such as operating system 1005 and data logging software 1006 that are accessible to and/or are operated on by the one or more processors 1003.

[0097] The computing device 1001 may also comprise other removable/non-removable, volatile/non-volatile computer storage media. The mass storage device 1004 may provide non-volatile storage of computer code, computer readable instructions, data structures, program modules, and other data for the computing device 1001. The mass storage device 1004 may be a hard disk, a removable magnetic disk, a removable optical disk, magnetic cassettes or other magnetic storage devices, flash memory cards, CD-ROM, digital versatile disks (DVD) or other optical storage, random access memories (RAM), read only memories (ROM), electrically erasable programmable read-only memory (EEPROM), and the like.

[0098] Any number of program modules may be stored on the mass storage device 1004. An operating system 1005 and data logging software 1006 may be stored on the mass storage device 1004. One or more of the operating system 1005 and data logging software 1006 (or some combination thereof) may comprise program modules and the data logging software 1006. Drilling data 1007 may also be stored on the mass storage device 1004. Drilling data 1007 may be stored in any of one or more databases known in the art. The databases may be centralized or distributed across multiple locations within the network 1015.

[0099] A user may enter commands and information into the computing device 1001 using an input device (not shown). Such input devices comprise, but are not limited to, a keyboard, pointing device (e.g., a computer mouse, remote control), a microphone, a joystick, a scanner, tactile input devices such as gloves, and other body coverings, motion sensor, and the like. These and other input devices may be connected to the one or more processors 1003 using a human machine interface 1002 that is coupled to the bus 1013, but may be connected by other interface and bus structures, such as a parallel port, game port, an IEEE 1394 Port (also known as a Firewire port), a serial port, network adapter 1008, and/or a universal serial bus (USB).

[0100] A display device 1011 may also be connected to the bus 1013 using an interface, such as a display adapter 1009. It is contemplated that the computing device 1001 may have more than one display adapter 1009 and the computing device 1001 may have more than one display device 101 1. A display device 1011 may be a monitor, an LCD (Liquid Crystal Display), light emitting diode (LED) display, television, smart lens, smart glass, and/ or a projector. In addition to the display device 1011, other output peripheral devices may comprise components such as speakers (not shown) and a printer (not shown) which may be connected to the computing device 1001 using Input/ Output Interface 1010. Any step and/or result of the methods may be output (or caused to be output) in any form to an output device. Such output may be any form of visual representation, including, but not limited to, textual, graphical, animation, audio, tactile, and the like. The display 1011 and computing device 1001 may be part of one device, or separate devices.

[0101] The computing device 1001 may operate in a networked environment using logical connections to one or more remote computing devices 1014a,b,c. A remote computing device 1014a, b,c may be a personal computer, computing station (e.g., workstation), portable computer (e g., laptop, mobile phone, tablet device), smart device (e g., smartphone, smart watch, activity tracker, smart apparel, smart accessory ), security and/or monitoring device, a server, a router, a network computer, a peer device, edge device or other common network node, and so on. Logical connections between the computing device 1001 and a remote computing device 1014a, b,c may be made using anetwork 1015, such as a local area network (LAN) and/or a general wide area network (WAN). Such network connections may be through a network adapter 1008. A network adapter 1008 may be implemented in both wired and wireless environments. Such networking environments are conventional and commonplace in dwellings, offices, enterprise-wide computer networks, intranets, and the Internet. It is contemplated that the remote computing devices 1014a,b,c can optionally have some or all of the components disclosed as being part of computing device 1001. In some

T1 optional aspects, the remote computing devices 1014a,b,c can be in direct communication with each other and the computing device 1001.

Machine Learning

[0102] In various aspects, machine learning can be used to analyze vibration data as disclosed herein. For example, machine learning can be used to determine thresholds. Machine learning can further be used to differentiate vibrational signatures of particular events. In some aspects, based on timing of different vibrations, it is contemplated that the duration of high vibrations or low vibrations can be indicative of different events. For example, a particular duration of low detected vibrations can be indicative of a core break, whereas another duration of low detected vibrations can be indicative of a pause in drilling but without a core break. As another example, a relatively brief duration of vibrations can be associated with a core break. In further aspects, different amplitudes of vibrations can correspond to different events. It is contemplated that machine learning can be used to train the system as disclosed herein to detect or confirm one or more events. The machine learning can be performed, for example on computing device 1001 (FIG. 13).

[0103] Turning now to FIG. 16, a system 800 is shown. The system 800 may be configured to use machine learning techniques to train, based on an analysis of one or more training data sets 810A-810B by a training module 820, at least one machine learning-based classifier 830 that is configured to classify vibrational data subsets in a vibrational data set as indicative of or not indicative of a particular attribute(s) (e.g., events, such as a core break or a pause before a core break) of a corresponding vibrational data set. The training data set 810A (e.g., a first portion of the vibrational data set) may comprise labeled vibrational data subsets (e.g., labeled as indicative of or not indicative of a particular attribute(s) of a corresponding vibrational data set). The training data set 810B (e.g., a second portion of the vibrational data set) may also comprise labeled vibrational data subsets (e.g., labeled as indicative of or not indicative of a particular attribute(s) of a corresponding particular event). The labels may comprise “indicative of a particular event'’ and “not indicative of a particular event.’'

[0104] The second portion of the vibrational data set may be randomly assigned to the training data set 810B or to a testing data set. In some implementations, the assignment of data to a training data set or a testing data set may not be completely random. In this case, one or more criteria may be used during the assignment, such as ensuring that similar numbers of vibrational data subsets with different labels are in each of the training and testing data sets. In general, any suitable method may be used to assign the data to the training or testing data sets, while ensuring that the distributions of sufficient quality and insufficient quality labels are somewhat similar in the training data set and the testing data set.

[0105] The training module 820 may train the machine learning-based classifier 830 by extracting a feature set from the first portion of the vibrational data set in the training data set 810A according to one or more feature selection techniques. The training module 820 may- further define the feature set obtained from the training data set 810A by applying one or more feature selection techniques to the second portion of the vibrational data set in the training data set 810B that includes statistically significant features of positive examples (e.g., vibrational data subsets indicative of a particular attribute(s) of a corresponding event) and statistically significant features of negative examples (e.g., vibrational data subsets not indicative of a particular attribute(s) of a corresponding particular event).

[0106] The training module 820 may extract a feature set from the training data set 810A and/or the training data set 810B in a variety of ways. The training module 820 may perform feature extraction multiple times, each time using a different feature-extraction technique. In an embodiment, the feature sets generated using the different techniques may each be used to generate different machine learning-based classification models 840. For example, the feature set with the highest quality metrics may be selected for use in training. The training module 820 may use the feature set(s) to build one or more machine learning-based classification models 840A-840N that are configured to indicate whether or not new vibrational data sets contain or do not contain vibrational data subsets indicative of a particular attribute(s) of the corresponding particular event.

[0107] The training data set 810A and/or the training data set 810B may be analyzed to determine any dependencies, associations, and/or correlations between extracted features and the sufficient quality/insufficient quality labels in the training data set 810A and/or the training data set 810B. The identified correlations may have the form of a list of features that are associated with labels for vibrational data subsets indicative of a particular attribute(s) of a corresponding particular event and labels for vibrational data subsets not indicative ofthe particular attribute(s) of the corresponding particular event. The features may be considered as variables in the machine learning context. The term “feature,” as used herein, may refer to any characteristic of an item of data that may be used to determine whether the item of data falls within one or more specific categories. By way of example, the features described herein may comprise one or more particular event attributes. The one or more particular event attributes may include an amplitude, a duration, a relative variation, and/or the like. In other aspects, the one or more particular event attributes can be or include a change relative to another vibrational data subset to determine, for example, a core break.

[0108] A feature selection technique may comprise one or more feature selection rules. The one or more feature selection rules may comprise a particular event attribute and a particular event attribute occurrence rule. The particular event attribute occurrence rule may comprise determining which particular event attributes in the training data set 810A occur over a threshold number of times and identifying those particular event attributes that satisfy the threshold as candidate features. For example, any particular event attributes that appear greater than or equal to 8 times in the training data set 810A may be considered as candidate features. Any particular event attributes appearing less than 8 times may be excluded from consideration as a feature. Any threshold amount may be used as needed.

[0109] A single feature selection rule may be applied to select features or multiple feature selection rules may be applied to select features. The feature selection rules may be applied in a cascading fashion, with the feature selection rules being applied in a specific order and applied to the results of the previous rule. For example, the particular event attribute occurrence rule may be applied to the training data set 810A to generate a first list of particular event attributes. A final list of candidate features may be analyzed according to additional feature selection techniques to determine one or more candidate groups (e.g., groups of particular event attributes). Any suitable computational technique may be used to identify' the candidate feature groups using any feature selection technique such as filter, wrapper, and/or embedded methods. One or more candidate feature groups may be selected according to a filter method. Filter methods include, for example, Pearson’s correlation, linear discriminant analysis, analysis of variance (ANOVA), chi-square, combinations thereof, and the like. The selection of features according to filter methods are independent of any machine learning algorithms. Instead, features may be selected on the basis of scores in various statistical tests for their correlation with the outcome variable (e.g., vibrational data subsets that is indicative of or is not indicative of a particular attribute(s) of a corresponding particular event). [0110] As another example, one or more candidate feature groups may be selected according to a wrapper method. A wrapper method may be configured to use a subset of features and train a machine learning model using the subset of features. Based on the inferences that draw n from a previous model, features may be added and/or deleted from the subset. Wrapper methods include, for example, forward feature selection, backward feature elimination, recursive feature elimination, combinations thereof, and the like. In an embodiment, forward feature selection may be used to identify one or more candidate feature groups. Forward feature selection is an iterative method that begins with no features in the machine learning model. In each iteration, the feature which best improves the model is added until an addition of a new feature does not improve the performance of the machine learning model. In an embodiment, backward elimination may be used to identify one or more candidate feature groups. Backward elimination is an iterative method that begins with all features in the machine learning model. In each iteration, the least significant feature is removed until no improvement is observed on removal of features. Recursive feature elimination may be used to identify one or more candidate feature groups. Recursive feature elimination is a greedy optimization algorithm which aims to find the best performing feature subset. Recursive feature elimination repeatedly creates models and keeps aside the best or the worst performing feature at each iteration. Recursive feature elimination constructs the next model with the features remaining until all the features are exhausted. Recursive feature elimination then ranks the features based on the order of their elimination.

[OHl] As a further example, one or more candidate feature groups may be selected according to an embedded method. Embedded methods combine the qualities of filter and wrapper methods. Embedded methods include, for example. Least Absolute Shrinkage and Selection Operator (LASSO) and ridge regression which implement penalization functions to reduce overfitting. For example, LASSO regression performs LI regularization which adds a penalty equivalent to absolute value of the magnitude of coefficients and ridge regression performs L2 regularization which adds a penalty equivalent to square of the magnitude of coefficients.

[0112] After the training module 820 has generated a feature set(s). the training module 820 may generate a machine learning-based classification model 840 based on the feature set(s). A machine learning-based classification model may refer to a complex mathematical model for data classification that is generated using machine-learning techniques. In one example, this machine learning-based classifier may include a map of support vectors that represent boundary features. By way of example, boundary features may be selected from, and/or represent the highest-ranked features in, a feature set.

[0113] The training module 820 may use the feature sets extracted from the training data set 810A and/or the training data set 810B to build a machine learning-based classification model 840A-840N for each classification category (e.g., each attribute of a corresponding particular event). In some examples, the machine learning-based classification models 840 A- 840N may be combined into a single machine learning-based classification model 840. Similarly, the machine learning-based classifier 830 may represent a single classifier containing a single or a plurality of machine learning-based classification models 840 and/or multiple classifiers containing a single or a plurality of machine learning-based classification models 840.

[0114] The extracted features (e g., one or more particular event attributes) may be combined in a classification model trained using a machine learning approach such as discriminant analysis; decision tree; a nearest neighbor (NN) algorithm (e.g., k-NN models, replicator NN models, etc.); statistical algorithm (e.g., Bayesian networks, etc.); clustering algorithm (e.g., k-means, mean-shift, etc.); neural networks (e.g., reservoir networks, artificial neural networks, etc.); support vector machines (SVMs); logistic regression algorithms; linear regression algorithms; Markov models or chains; principal component analysis (PCA) (e.g., for linear models); multi-layer perceptron (MLP) ANNs (e.g.. for non-linear models); replicating reservoir networks (e.g., for non-linear models, typically for time series); random forest classification; a combination thereof and/or the like. The resulting machine learningbased classifier 830 may comprise a decision rule or a mapping for each candidate particular event attribute to assign a vibrational data subset(s) to a class (e.g., indicative of or not indicative of a particular attribute(s) of a corresponding vibrational data set).

[0115] The candidate particular event attributes and the machine learning-based classifier 830 may be used to predict a label (e.g., indicative of or not indicative of a particular attribute(s) of a corresponding vibrational data set) for results in the testing data set (e.g.. in the second portion of the plurality of vibrational data sets ). In one example, the prediction for each result in the testing data set includes a confidence level that corresponds to a likelihood or a probability that the corresponding vibrational data subset (s) is indicative of or is not indicative of a particular attribute(s) of a corresponding vibrational data set. The confidence level may be a value between zero and one, and it may represent a likelihood that the corresponding vibrational data subset(s) belongs to a particular class. In one example, when there are two statuses (e.g., indicative of or not indicative of a particular vibrational data subset(s) of a corresponding vibrational data set), the confidence level may correspond to a value p, which refers to a likelihood that a particular vibrational data subset belongs to the first status (e.g., indicative of the particular attribute(s)). In this case, the value I-p may refer to a likelihood that the particular vibrational data subset belongs to the second status (e.g., not indicative of the particular attribute(s)). In general, multiple confidence levels may be provided for each vibrational data subset and for each candidate vibrational data subset attribute when there are more than two statuses. A top performing candidate vibrational data subset attribute may be determined by comparing the result obtained for each vibrational data subset with the known sufficient quality /insufficient quality status for each corresponding vibrational data set in the testing data set (e.g., by comparing the result obtained for each vibrational data subset wi th the labeled vibrational data subsets of the second portion of the vibrational data sets). In general, the top performing candidate event attribute for a particular attribute(s) of the corresponding vibrational data set will have results that closely match the known indicative of /not indicative of statuses.

[0116] The top performing vibrational data subset attribute may be used to predict the indicative of/not indicative of particular events of a new vibrational data set. For example, a new vibrational data set may be determined/received. The new vibrational data set may be provided to the machine learning-based classifier 830 which may, based on the top performing event attribute for the particular attribute(s) of the corresponding vibrational data subset, classify the vibrational data subset of the new vibrational data set as indicative of or not indicative of the particular attribute(s).

[0117] The application may provide an indication of one or more user edits made to any of the attributes indicated by any created or deleted attributes to the computing device. For example, the user may edit any of the attributes indicated by the machine learning-analyzed data by dragging some of its points to desired positions via mouse movements in order to optimally delineate depictions of boundaries of the attribute(s). For example, referring to FIG. 15, the user can drag start and end points of an event along the x-axis. As another example, the user may draw or redraw parts of the machine learning-analyzed data via a mouse. Other input devices or methods of obtaining user commands may also be used. The one or more user edits may be used by the machine learning module to optimize the machine learning model. For example, the training module 820 may extract one or more features from output analyses containing one or more user edits as discussed above. The training module 820 may use the one or more features to retrain the machine learning-based classifier 830 and thereby continually improve results provided by the machine learning-based classifier 830.

[0118] A method may be used for generating the machine learning-based classifier 830 using the training module 820. The training module 820 can implement supervised, unsupervised, and/or semi-supervised (e.g., reinforcement based) machine learning-based classification models 840. The method illustrated is an example of a supervised learning method; variations of this example of training method are discussed below, however, other training methods can be analogously implemented to train unsupervised and/or semi-supervised machine learning models.

[0119] The training method may determine (e.g., access, receive, retrieve, etc.) first vibrational data sets associated with one or more events (e.g., first vibrational data sets) and second vibrational data sets associated with one or more events (e.g., second vibrational data sets). The first vibrational data sets and the second vibrational data sets may each contain one or more result datasets associated with vibrational data sets, and each result dataset may be associated wi th a particular attribute. Each result dataset may include a labeled list of results. The labels may comprise ‘“event attribute" and ‘“non-event attribute.’'

[0120] The training method may generate a training data set and a testing data set. The training data set and the testing data set may be generated by randomly assigning labeled results from the second vibrational data sets to either the training data set or the testing data set. In some implementations, the assignment of labeled results as training or test samples may not be completely random. In an embodiment, only the labeled results for a specific event type and/or class may be used to generate the training data set and the testing data set. In an embodiment, a majority' of the labeled results for the specific event type and/or class may be used to generate the training data set. For example, 75% of the labeled results for the specific event type and/or class may be used to generate the training data set and 25% may be used to generate the testing data set. [0121] The training method may determine (e.g., extract, select, etc.) one or more features that can be used by, for example, a classifier to differentiate among different classifications (e.g., “event attribute” and “non- event attribute.”). The one or more features may comprise a set of result attributes. In an embodiment, the training method may determine a set features from the first vibrational data sets. In another embodiment, the training method may determine a set of features from the second vibrational data sets. In a further embodiment, a set of features may be determined from labeled results from an event type and/or class different than the event type and/or class associated with the labeled results of the training data set and the testing data set. In other words, labeled results from the different event type and/or class may be used for feature determination, rather than for training a machine learning model. The training data set may be used in conjunction with the labeled results from the different event type and/or class to determine the one or more features. The labeled results from the different event type and/or class may be used to determine an initial set of features, which may be further reduced using the training data set.

[0122] The training method may train one or more machine learning models using the one or more features. In one embodiment, the machine learning models may be trained using supervised learning. In another embodiment, other machine learning techniques may be employed, including unsupervised learning and semi-supervised. The machine learning models trained may be selected based on different criteria depending on the problem to be solved and/or data available in the training data set. For example, machine learning classifiers can suffer from different degrees of bias. Accordingly, more than one machine learning model can be trained, and then optimized, improved, and cross-validated.

[0123] The training method may select one or more machine learning models to build a predictive model (e.g., a machine learning classifier). The predictive model may be evaluated using the testing data set. The predictive model may analyze the testing data set and generate classification values and/or predicted values. Classification and/or prediction values may be evaluated to determine whether such values have achieved a desired accuracy level.

[0124] Performance of the predictive model described herein may be evaluated in a number of ways based on a number of true positives, false positives, true negatives, and/or false negatives classifications of events in vibrational data sets. For example, the false positives of the predictive model may refer to a number of times the predictive model incorrectly classified a event(s) as indicative of a particular atribute that in reality was not indicative of the particular atribute. Conversely, the false negatives of the machine learning model(s) may refer to a number of times the predictive model classified one or more events of a vibrational data set as not indicative of a particular atribute when, in fact, the one or more events are indicative of the particular atribute. True negatives and true positives may refer to a number of times the predictive model correctly classified one or more events of a vibrational data set as sufficiently indicative of a particular atribute or not indicative of the particular atribute. Related to these measurements are the concepts of recall and precision. Generally, recall refers to a ratio of true positives to a sum of true positives and false negatives, which quantifies a sensitivity of the predictive model. Similarly, precision refers to a ratio of true positives a sum of true and false positives.

Exemplary Aspects

[0125] In view of the described products, systems, and methods and variations thereof, herein below are described certain more particularly described aspects of the invention. These particularly recited aspects should not however be interpreted to have any limiting effect on any different claims containing different or more general teachings described herein, or that the “particular” aspects are somehow limited in some way other than the inherent meanings of the language literally used therein.

[0126] Aspect 1: A method comprising: determining, by a tool of a drill string, an indication that vibration of the drill string is below a threshold level, the drill string comprising: a core barrel containing core; and a core barrel orientation measurement device configured to: measure at least one core barrel orientation parameter; store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with the plurality of orientation values; storing a time stamp based on an input from an operator; identifying an interval during which vibration of the drill string is below the threshold level; confirming, based on the time stamp being within the interval, a core barrel orientation time; and obtaining a stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time.

[0127] Aspect 2: The method of aspect 1, wherein the tool of the drill string is a downhole tool.

[0128] Aspect 3: The method of aspect 1, wherein at least a portion of the drill string is within a borehole, wherein the tool remains outside of the borehole.

[0129] Aspect 4: The method of any one of the preceding aspects, further comprising measuring, by an accelerometer of the tool of the drill string, a plurality of acceleration values, wherein the interval during which vibration of the drill string is below the threshold level comprises an interval during which at least one acceleration value of the plurality of acceleration values is below an acceleration threshold.

[0130] Aspect 5: The method of aspect 4, wherein the at least one acceleration value is zero, corresponding to an acceleration below a minimum measurable threshold of the accelerometer.

[0131] Aspect 6: The method of any one of the preceding aspects, further comprising associating the core barrel orientation parameter with an orientation of the core.

[0132] Aspect 7: The method of any one of the preceding aspects, further comprising detecting a shockwave corresponding to a core break, wherein obtaining the stored orientation value comprises obtaining a stored orientation value associated with a time prior to the shockwave.

[0133] Aspect 8: The method of any one of the preceding aspects, further comprising: measuring, by the core barrel orientation measurement device, the at least one core barrel orientation parameter; and storing the plurality of orientation values associated w ith the at least one core barrel orientation parameter and the respective time values associated with the plurality of orientation values. [0134] Aspect 9: The method of any one of the preceding aspects, wherein identifying an interval during which vibration of the drill string is below the threshold level comprises storing a start time and an end time.

[0135] Aspect 10: The method of any one of the preceding aspects, wherein identifying an interval during which vibration of the drill string is below the threshold level comprises storing a start time and a duration of the interval.

[0136] Aspect 11 : The method of any one of the preceding aspects, wherein the respective time value that corresponds to the core barrel orientation time comprises a time value between a start time of the interval during which vibration of the drill string is below the threshold level and the time stamp.

[0137] Aspect 12: A system comprising: a drill string, the drill string comprising: a core barrel configured to receive core therein; and a core barrel orientation measurement device configured to: measure at least one core barrel orientation parameter; and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with each orientation value of the plurality of orientation values; a tool that is configured to: detect vibrations of the drill string; a computing device comprising: an input device; at least one processor; and a memory in communication with the at least one processor, wherein the memory comprises instructions that, when executed by the at least one processor, cause the at least one processor to: receive, from the input device, an operator input indicative of a planned core break; and cause, upon receiving from the input device the operator input indicative of the planned core break, the memory to store a time stamp.

[0138] Aspect 13: The system of aspect 12, wherein the memory comprises instructions that, when executed by the at least one processor, cause the at least one processor to: confirm, based on the time stamp and the detected vibrations of the drill string, a core barrel orientation time.

[0139] Aspect 14: The system of aspect 13, wherein the memory comprises instructions that, when executed by the at least one processor, cause the at least one processor to: receive data corresponding to the detected vibrations of the drill string; and confirm, based on the time stamp and the data corresponding to the detected vibrations of the drill string, a core barrel orientation time by: determining an interval during which vibration of the drill string is below a threshold level; and confirming that the time stamp is within the interval.

[0140] Aspect 15: The system of aspect 13, wherein the tool is configured to: determine an indication that that vibration of the drill string is below a threshold level; and store an interval during which vibration of the drill string is below the threshold level; wherein the memory comprises instructions that, when executed by the at least one processor, cause the at least one processor to: confirm, based on the time stamp and the detected vibrations of the drill string, a core barrel orientation time by confirming that the time stamp is within the interval.

[0141] Aspect 16: The system of any one of aspects 13-15, wherein the memory of the second computing device comprises instructions that, when executed by the at least one processor, cause the at least one processor to: obtain a stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time. [0142] Aspect 17: The system of aspect 12, wherein the computing device is a first computing device, the system further comprising a second computing device, wherein the second computing device comprises: at least one processor; and a memory in communication with the at least one processor, wherein the memory comprises instructions that, when executed by the at least one processor, cause the at least one processor to: confirm, based on the time stamp and the detected vibrations of the drill string, a core barrel orientation time.

[0143] Aspect 18: The system of aspect 17, wherein the memory of the computing device comprises instructions that, when executed by the at least one processor, cause the at least one processor to obtain a stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time. [0144] Aspect 19: The system of any one of aspects 12-18, wherein the tool of the drill string is a downhole tool.

[0145] Aspect 20: The system of any one of aspects 12-18, wherein the tool of the drill string is configured to remain outside of the borehole.

[0146] Aspect 21 : The system of any one of aspects 12-20, wherein the tool of the drill string is configured to detect a shockwave, wherein the memory of the computing device comprises instructions that, when executed by the at least one processor, cause the at least one processor to obtain a stored orientation value that is associated with a time prior to the shockwave.

[0147] Aspect 22: The system of any one of aspects 12-21, wherein the tool comprises an accelerometer that is configured to measure a plurality of acceleration values, wherein the tool is configured to determine the indication that the vibration of the drill string is below the threshold level based on at least one acceleration value of the plurality of acceleration values being below an acceleration threshold.

[0148] Aspect 23: A method comprising: determining, by a first tool of a drill string, a first indication that vibration of the drill string is below a first threshold level, the drill string comprising: a core barrel containing core; and a core barrel orientation measurement device configured to: measure at least one core barrel orientation parameter; and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with the plurality of orientation values; identifying a first interval associated with the first indication that vibration of the drill string is below the first threshold level; determining, by a second tool of a drill string, a second indication that vibration of the drill string is below a second threshold level; identifying a second interval associated with the second indication that vibration of the drill string is below the second threshold level; confirming, based on the first interval and the second interval, a core barrel orientation time; and obtaining a stored orientation value of the plurality of orientation values associated with a respective time value that corresponds to the core barrel orientation time.

[0149] Aspect 24: The method of aspect 23, w herein the one of the first tool or the second tool of the drill string is a downhole tool.

[0150] Aspect 25: The method of aspect 24, wherein at least a portion of the drill string is within a borehole, w herein the other of the first tool or the second tool remains outside of the borehole.

[0151] Aspect 26: The method of any one of aspects 23-25, further comprising measuring, by an accelerometer of the first tool of the drill string, a plurality of acceleration values, wherein the indication that vibration of the drill string is below' the first threshold level comprises at least one acceleration value of the plurality of acceleration values being below an acceleration threshold.

[0152] Aspect 27: The method of aspect 26. wherein the at least one acceleration value is zero, corresponding to an acceleration below a minimum measurable threshold of the accelerometer.

[0153] Aspect 28: The method of any one of aspects 23-27, further comprising associating the core barrel orientation parameter with an orientation of the core. [0154] Aspect 29: The method of any one of aspects 23-28. wherein confirming, based on the first interval and the second interval, the core barrel orientation time comprises determining that the first interval and second interval overlap.

[0155] Aspect 30: The method any one of aspects 23-29, further comprising detecting a shockwave corresponding to a core break, wherein the obtained stored orientation value is associated with a time prior to the shockwave.

[0156] Aspect 31 : The method of any one aspects 23-30, further comprising: measuring, by the core barrel orientation measurement device, the at least one core barrel orientation parameter; and storing the plurality of orientation values associated with the at least one core barrel orientation parameter and the respective time values associated with the plurality of orientation values.

[0157] Aspect 32: The method of any one of aspects 23-31, further comprising storing a time stamp based on an input from an operator. wherein confirming, based on the first interval and the second interval, the core barrel orientation time comprises confirming, based on the first interval, the second interval, and the time stamp, the core barrel orientation time.

[0158] Aspect 33: A system comprising: a drill string, the drill string comprising: a core barrel configured to receive core therein; and a core barrel orientation measurement device configured to: measure at least one core barrel orientation parameter; and store a plurality of orientation values associated with the at least one core barrel orientation parameter and respective time values associated with each orientation value of the plurality of orientation values; a first tool that is configured to detect vibrations of the drill string; and a second tool that is configured to detect vibrations of the drill string.

[0159] Aspect 34: The system of aspect 33, further comprising a computing device comprising: at least one processor; and a memory in communication with the at least one processor, wherein the memory comprises instructions that, when executed by the at least one processor, cause the at least one processor to: confirm, based on the vibrations detected by the first tool and the vibrations detected by the second tool, a core barrel orientation time.

[0160] Aspect 35: The system of aspect 34, wherein the computing device further comprises an input device, wherein the memory comprises instructions that, when executed by the at least one processor, cause the at least one processor to: receive, from the input device, an operator input indicative of a planned core break; and cause, upon receiving from the input device the operator input indicative of the planned core break, the memory to store a time stamp.

[0161] Aspect 36: The system of any one of aspects 33-35, wherein one of the first tool or the second tool is a downhole tool, and the other of the first tool or the second tool is configured to remain outside of the borehole.

[0162] Although the foregoing invention has been described in some detail by way of illustration and example for purposes of clarity of understanding, certain changes and modifications may be practiced within the scope of the appended claims.