System and method for determining rotational oscillations of a drill string

Abstract

Embodiments of the present disclosure are directed to a tangible, non-transitory computer-readable medium storing instructions executable by one or more processors, wherein the instructions cause the one or more processors to determine a threshold associated with an axial acceleration oscillation amplitude at a drill bit, wherein the drill bit is part of a drilling system. The instructions also cause the one or more processors to receive an operating parameter value of the drilling system, compare the operating parameter value to the threshold value, and adjust an operation of the drilling system in response to comparing the operating parameter value to the threshold value.

Description

Technical Field

[0001] The present disclosure relates generally to downhole drilling systems and, more particularly, to controlling the operation of a drill string based on rotational movement of the drill string. Background Art

[0002] This section is intended to introduce the reader to various aspects of the art that may be relevant to various aspects of the present technology, which will be described and / or claimed below. It is believed that this discussion helps to provide the reader with background information to promote a better understanding of various aspects of the present disclosure. Therefore, it should be understood that these statements should be read from this perspective and not as any form of admission.

[0003] Oil and gas industry processes include the exploration, drilling, logging, extraction, transportation, refining, retailing, etc. of natural resources such as oil, gas, and water. Natural resources may be located underground, and therefore, drilling systems may be used to perform certain processes. For example, a drilling system may form a borehole underground to discover, observe, analyze, and / or extract natural resources.

[0004] However, it is now recognized that when drilling, high frequency rotary oscillations may occur which produce large torsional stresses on near-bit drilling components, which can lead to structural failure. In some cases, such as when drilling with a positive displacement motor, it may be difficult to detect these high frequency rotary oscillations directly, especially when there is no suitable instrumentation below the motor in the drill string, because these oscillations are confined below the positive displacement motor. Summary of the invention

[0005] The following sets forth an overview of certain embodiments disclosed herein. It should be understood that these aspects are presented only to provide the reader with a brief overview of these certain embodiments, and these aspects are not intended to limit the scope of the present disclosure.

[0006] High frequency rotary oscillations caused by the drill string boring a borehole may be localized below the motor of the drill string. These oscillations may be difficult to detect directly because suitable measuring instruments are typically not available below the motor. The presently disclosed systems and methods may indirectly determine, analyze and / or quantify the oscillations by determining the axial vibrations generated by the effect of the rotary oscillations on the cutting action of the drill bit of the drill string. Accelerometers, strain gauges or other suitable instruments above the motor may be used to detect the axial vibrations that may not be localized below the motor.

[0007] Relative to various aspects of the present disclosure, there may be various improvements of the above-mentioned features. Other features may also be incorporated into these various aspects. These improvements and additional features may exist alone or in any combination. For example, the various features discussed below with respect to one or more illustrated embodiments may be incorporated into any of the above-mentioned aspects of the present disclosure alone or in any combination. Again, the brief overview given above is intended only to familiarize the reader with certain aspects and backgrounds of the embodiments of the present disclosure, and is not limited to the claimed subject matter.

[0008] In an embodiment, a tangible, non-transitory computer-readable medium may store instructions executable by one or more processors, wherein the instructions may cause the one or more processors to determine a threshold associated with an axial acceleration oscillation amplitude at a drill bit that is part of a drilling system. The instructions may also cause the one or more processors to receive an operating parameter value of the drilling system, compare the operating parameter value to the threshold value, and adjust the operation of the drilling system in response to comparing the operating parameter value to the threshold value.

[0009] In an embodiment, a drilling system may include a drill string having a drill bit, wherein the drill string may rotate and drive the drill bit to engage the drill bit with a borehole. The drilling system may also include a sensor that may detect an operating parameter value of the drilling system, and a control system communicatively coupled to the drilling system. The control system may include a threshold determination engine that may determine a threshold value associated with an axial acceleration oscillation amplitude at the drill bit; a processor; and a storage device that may store instructions. The instructions may cause the processor to receive an operating parameter value detected by the sensor, compare the operating parameter value to a threshold value, and adjust the operation of the drilling system in response to comparing the operating parameter value to the threshold value.

[0010] In an embodiment, the method of the present disclosure may include determining a threshold associated with an axial acceleration oscillation amplitude at a drill bit as part of a drilling system, receiving an operating parameter value detected at a detection location of the drilling system, comparing the operating parameter value to the threshold, and adjusting operation of the drilling system in response to comparing the operating parameter value to the threshold. BRIEF DESCRIPTION OF THE DRAWINGS

[0011] Various aspects of the present disclosure may be better understood by reading the following detailed description and referring to the accompanying drawings, in which:

[0012] Figure 1 is a schematic diagram of a drilling system having a drill string according to an embodiment of the present disclosure;

[0013] Figure 2 According to the embodiment of the present disclosure Figure 1 A partial view of a bottom hole assembly of a drilling system;

[0014] Figure 3 The processing according to the embodiment of the present disclosure Figure 1 A schematic diagram of a system for calculating operating parameters of a drilling system;

[0015] Figure 4 Each plot over a period of time according to an embodiment of the present disclosure is shown. Figure 1 a graph of corresponding oscillation parameters of the drilling system; and

[0016] Figure 5 It means that the embodiment of the present disclosure can be used to operate Figure 1 A flow chart of a method of simultaneously mitigating rotational oscillations of a drill string in a drilling system based on operating parameter values ​​determined by sensor data. DETAILED DESCRIPTION

[0017] One or more specific embodiments of the present disclosure will be described below. These described embodiments are merely examples of the currently disclosed technology. In addition, in order to provide a brief description of these embodiments, all features of the actual implementation may not be described in the specification. It should be understood that in the development of any such actual implementation, such as in any engineering or design project, many implementation-specific decisions must be made to achieve the developer's specific goals, such as complying with system-related and business-related constraints, which may vary from one implementation to another. In addition, it should be understood that such development work may be complex and time-consuming, but for ordinary technicians who benefit from this disclosure, it will be a routine task of design, fabrication and manufacturing.

[0018] When introducing elements of various embodiments of the present disclosure, the articles "a," "an," and "the" are intended to indicate the presence of one or more elements. The terms "comprising," "including," and "having" are intended to be inclusive and mean that there may be additional elements in addition to the listed elements. Additionally, it should be understood that reference to "one embodiment" or "an embodiment" of the present disclosure is not intended to be interpreted as excluding the existence of other embodiments that also include the recited features.

[0019] The present disclosure relates to a drilling system that uses a drill string to form an underground borehole, such as for the exploration and / or production of natural resources (e.g., oil, gas, water). The drilling system can rotate the drill string and drive the drill string to form a borehole. That is, the drilling system can operate the drill string so that the drill bit of the drill string engages with the underground geological formation. During the operation of the drilling system, the movement of the drill string can be determined and used to adjust the operation of the drilling system. For example, during the operation of the drilling system, a part of the drill string may vibrate or oscillate due to, for example, the rotation of the drill string, the engagement of the drill string with the geological formation, the interaction of the components of the drill string, and the interaction with the drilling fluid of the guide drill string. The vibration or oscillation of the drill string can be determined when operating the drill string. Typically, vibration or oscillation is a fast and repeated motion (e.g., moving in a cyclic manner). For example, such motion can include radial oscillation, axial oscillation, and / or rotational oscillation, which will be further described herein.

[0020] In some cases, such oscillations may negatively affect the performance of the drilling system. For example, using conventional systems, relatively high frequency (e.g., above 50 Hz) rotational oscillations are often present at the drill bit that may affect the structural integrity of the drill string and / or limit the performance of the drill string. However, it may be difficult to detect the characteristics of the rotational oscillations at the drill bit. In particular, the drill string may include a motor that drives the drill bit. However, the motor may be positioned near the drill bit and thus isolate certain movements of the drill bit from the movement of the rest of the drill string above the motor. That is, during operation of the drilling system, the drill bit moves relative to the rest of the drill string. Therefore, the rotational oscillations of the drill string detected above the motor may not accurately reflect the rotational oscillations of the drill bit (which is located below the motor).

[0021] Furthermore, movement of the drill bit may not be effectively detected via conventional methods, and / or information detected at the drill bit may not be effectively communicated elsewhere in the drilling system. For example, because the drill bit may rotate at a different rate than the rest of the drill string, the drill bit may not be wired to communicatively couple the drill bit with the rest of the drill string. Additionally or alternatively, monitoring for rotational oscillations may be impractical, such as when the cost of implementing components for detecting rotational oscillations is prohibitive. As a result, the presence of high frequency oscillations at the drill bit may not be easily detected.

[0022] Thus, according to the present disclosure, determining the rotational oscillations at the drill bit based on detectable operating parameters can indirectly enable the determination of the presence of high frequency oscillations at the drill bit. Typically, the rotational oscillations at the drill bit are coupled to the axial motion of the drill string, which is easier to detect than the rotational oscillations. Thus, the axial motion of the drill string, such as the axial acceleration oscillations, can be detected and used to determine the rotational oscillations of the drill bit. Furthermore, while the above examples focus on the analysis of the frequency of the rotational oscillations, other characteristics, such as the amplitude of the rotational oscillations, can be analyzed in addition or alternatively.

[0023] In some embodiments, it can be determined via simulation and / or historical measurement data that the amplitude or amplitude range of the axial acceleration oscillations corresponds to the presence of rotational oscillations having a particular frequency (e.g., relatively high frequencies, such as greater than 50 Hz, associated with rotational oscillations at the drill bit that may affect the structural integrity of the drill string and / or limit the performance of the drill string). As an example, an operating parameter of the drill string (e.g., axial acceleration) can be detected via a sensor (e.g., an accelerometer or strain gauge) of the drill string. The operating parameter can be used to determine the amplitude of the axial acceleration oscillations. The determined amplitude of the axial acceleration oscillations can then be used to infer the presence, severity, and / or other characteristics of the rotational oscillations at the drill bit.

[0024] Although the present disclosure primarily discusses determining the presence of high frequency rotational oscillations at the drill bit, it should be understood that the presence of high frequency rotational oscillations at other locations of the drill string may additionally or alternatively be determined. In this manner, the operating parameters may be used to determine the characteristics of the rotational oscillations at any location along the drill string. In any case, the operation of the drill string may be adjusted based on the determined characteristics of the rotational oscillations.

[0025] To help illustrate the techniques described in this article, Figure 1 An example embodiment of a drilling system 10 at a well site is shown, where the drilling system 10 may be used to form a borehole 12 (e.g., a wellbore) through a geological formation 14 that may be onshore or offshore. The drilling system 10 may include a drill string 16 suspended within the borehole 12, and the drilling system 10 may have a bottom hole assembly (BHA) 18 that includes a drill bit 20 at its lower end, where the drill bit 20 engages the geology 14. In the present disclosure, the drill bit 20 may include any cutting structure (e.g., a cutter, a reamer, and / or the like) that may be used to engage and cut the geological formation 14.

[0026] The drilling system 10 also includes a surface system 22 that provides rotation and drive for the drill string 16. In some embodiments, the drilling system 10 may include a kelly system having a rotary table 24, a kelly 26, a hook 28, and a rotating swivel 30. The drill string 16 may be coupled to the hook 28 via the kelly 26 and the rotating swivel 30. The rotating swivel 30 may be suspended from the hook 28, which is attached to a travel block (not shown) that drives the drill string 16 relative to the surface system 22 along an axis 32 passing through the center or approximately the center of the borehole 12. In addition, the rotating swivel 30 may allow the drill string 16 to rotate relative to the hook 28, and the rotary table 24 may be rotated in a rotation direction 33 to drive the drill string 16 to rotate concentrically about the axis 32. Alternatively, the drilling system 10 may be a top drive system that rotates the drill string 16 via an internal drive (e.g., a rotary motor) of the rotating swivel 30. That is, the drilling system 10 may not use the rotary table 24 and the kelly 26 to rotate the drill string 16. Rather, an internal drive of the rotating swivel 30 may drive the drill string 16 to rotate concentrically about the axis 32 relative to the hook 28 in a rotational direction 33 .

[0027] In any case, as the surface system 22 rotates the drill string 16, the surface system 22 may also drive the drill string in an axial direction to engage the drill string 16 with the geological formation 14. For example, the drill string 16 may be driven through the borehole 12 into the geological formation 14 along a first axial direction 34, which may be a generally downward vertical direction. Additionally, the drill string 16 may be moved out of the borehole 12 in a second axial direction 36 that is opposite to the first axial direction 34. That is, the second axial direction 36 may be an upward, generally vertical direction. The combined axial and rotational movement of the drill string 16 may facilitate engagement of the drill string 16 with the geological formation 14. Although in Figure 1 Although a vertical direction is described in the example of the drilling system 10, it should be understood that the drilling system 10 can extend the borehole in a wide variety of directions and / or angles, including vertical, horizontal or lateral, and / or any other angle or orientation within the geological formation. For example, the axis 32 can be vertical, horizontal or angled and can vary along the length of the borehole 12, and the axial directions 34, 36 can be any pair of directions that are opposite to each other at a given depth.

[0028] The surface system 22 may also include mud or drilling fluid 40, which may be directed into the drill string 16 to cool and / or lubricate the drill bit 20. Additionally, the drilling fluid 40 may exert mud pressure on the geological formation 14 to reduce the likelihood of fluid from the geological formation 14 flowing into and / or out of the borehole 12. In some embodiments, the drilling fluid 40 may be stored in a pit 42 formed at the well site. A pump 44 may fluidly couple the pit 42 and the swivel 30, wherein the pump 44 may deliver the drilling fluid 40 to the interior of the drill string 16 via a port in the swivel 30, thereby causing the drilling fluid 40 to flow downwardly through the drill string 16 in the first axial direction 34. The drilling fluid 40 may also exit the drill string 16 via a port in the drill bit 20 and flow into the borehole 12 toward the surface (e.g., toward the surface system 22). While drilling, drilling fluid 40 may circulate upward in the second axial direction 36 through the annular region between the exterior of the drill string 16 and the wall of the borehole 12, thereby carrying drill cuttings away from the bottom of the borehole 12. Once at the surface, the returning drilling fluid 40 may be filtered and transported back to the pit 42 for recirculation and reuse.

[0029] Figure 1 The BHA 18 of the exemplary drilling system 10 may include various downhole tools, such as a logging while drilling (LWD) module 120 and / or a measurement while drilling (MWD) module 130. In general, the downhole tools may help determine the performance of the drill string 16, such as by determining parameters of the drill string 16, the surrounding geological formations 14, etc. It should also be understood that more than one LWD module 120 and / or MWD module 130 may be employed. For example, the BHA 18 may include an additional LWD module 120A and / or an additional MWD module 130A positioned adjacent to the drill bit 20. Thus, references to the LWD module 120 may also refer to the LWD module 120A, and references to the MWD module 130 may also refer to the MWD module 130A, as well as references to other such or similar modules.

[0030] LWD module 120 and / or MWD module 130 may each be housed in a particular type of drill collar and may include one or more types of logging tools. Typically, LWD module 120 may include capabilities for measuring, processing, and storing information, and MWD module may include one or more devices for measuring characteristics of drill string 16 and / or drill bit 20 and for communicating with surface equipment (e.g., of surface system 22). Figure 1 In the drilling system 10, the LWD module 120 and / or the MWD module 130 may include, for example, one or more of the following types of measurement devices: a bit pressure measurement device, a torque measurement device, a bending measurement device, a vibration measurement device, an impact measurement device, a stick-slip measurement device, a direction measurement device and / or an inclination measurement device.

[0031] In certain embodiments, the MWD module 130 may also include a device for generating electrical energy. For example, the MWD module 130 may include a mud turbine generator that generates electrical energy from the flow of the drilling fluid 40. In additional or alternative embodiments, the drilling system 10 may include a power source 148, such as a generator and / or an electrical energy storage device, that supplies energy to the drilling system 10. In any case, the electrical energy may be used to operate various aspects of the drilling system 10, such as to control the BHA 18.

[0032] The BHA 18 may also include a motor 150 and / or a rotary steerable system (RSS) 152 that regulates the operation of the drill bit 20 to engage the geological formation 14. For example, the RSS 152 may orient the drill bit in a desired direction while the motor generates continuous rotation to engage the drill bit 20 to drill the borehole 12. It should be appreciated that generating continuous rotation may enable better transport of drilled cuttings to the surface, thereby better cutting the borehole 12, limited stresses imposed on the drill bit 20 by the geological formation 14, etc. In addition, the RSS 152 may enable control of the engagement of the drill string 16 with the geological formation 14. As an example, the RSS may enable communication between the drill string 16 and the surface system 22. Thus, the surface system 22 may control the direction or path of the drill string 16 to form the borehole 12 and / or the manner in which the drill string 16 engages the geological formation 14 (e.g., the rotation of the drill string 16). In certain embodiments, the drill string 16 may include an additional tube 154 coupling the drill bit 20 to the motor 150 and / or the RSS 152.

[0033] In some embodiments, a data processing system 160 may be communicatively coupled to the drilling system 10. The data processing system 160 may be any electronic data processing system that may be used to perform the systems and methods of the present disclosure. For example, the data processing system 160 may include one or more processors 162, such as a general-purpose microprocessor, a dedicated processor (ASIC), and / or a field programmable logic array (FPGA). The one or more processors 162 may execute instructions stored in a memory 164 and / or a storage device 166, which may be a read-only memory (ROM), a random access memory (RAM), a flash memory, an optical storage medium, a disk drive, etc. For example, the instructions may be used to adjust the operation of the drilling system 10, including the operation of the drill string 16.

[0034] In some embodiments, the data processing system 160 may also include a user interface 168 that enables a user, such as a human user, a virtual user, a machine-based automated system, etc., to interact with the data processing system 160. For example, a user may input features and / or instructions (e.g., control commands) to the data processing system 160 via the user interface 168. In embodiments, the user interface 168 may include buttons, a keyboard, a microphone, a mouse device, a touch pad, and / or the like. It should be understood that the user interface 168 may also include a display, which may be any suitable electronic display for visual representation of information (such as a graphical representation of the collected data).

[0035] In addition, the data processing system 160 may include an input / output (I / O) port 170 that enables the data processing system 160 to communicate with various electronic devices. For example, the I / O port 170 may enable the data processing system 160 to be directly coupled to another electronic device (e.g., a mobile device) so that data can be transferred between the data processing system 160 and the electronic device. The I / O port 170 may additionally or alternatively enable the data processing system 160 to be indirectly coupled to other electronic devices. In another example, the I / O port 170 may enable the data processing system 160 to be coupled to a network such as a personal area network (PAN), a local area network (LAN), and / or a wide area network (WAN). Therefore, in some embodiments, the data processing system 160 may receive data (e.g., as a signal) from another electronic device (e.g., a base station control system) and / or transmit data to another electronic device via the I / O port 170.

[0036] The data processing system 160 may be a local component of the drilling system 10 (e.g., in the BHA 18), a device located near the drilling operation (e.g., at or near the surface system 22), and / or a remote data processing device located remotely from the drilling system 10, such as a mobile computing device (e.g., a tablet, a smartphone, a laptop) or a server remotely from the drilling system 10. In any case, the data processing system 160 may process downhole measurements in real time or at some time after the data is collected. In general, the data processing system 160 may store and process collected data, such as data collected in the BHA 18 via the LWD module 120, the MWD module 130, and / or any suitable telemetry (e.g., an electrical signal pulsed through the geological formation 14, or mud pulse telemetry using the drilling fluid 40).

[0037] Figure 2 According to the embodiment of the present disclosure Figure 11 is an enlarged schematic diagram of a portion of a BHA 18 of a drilling system 10. When the drilling system 10 is in operation, the drill string 16 may be driven to move in a first axial direction 34 and a second axial direction 36 along the axis 32, and the drill string 16 may also be driven to rotate concentrically about the axis 32 in a rotational direction 33. However, it should be understood that operation of the drill string 16 (e.g., the drill bit 20) may cause certain portions of the drill string 16 to vibrate or oscillate unintentionally. As an example, when the drilling system 10 is in operation, certain portions of the drill string 16 may oscillate rotationally, axially, and / or radially. For reference, axial oscillation refers to movement of the drill string 16 in the first and second axial directions 34, 36. Rotational oscillation refers to rotation of the drill string 16 about the axes 32, 32, such as rotation about the axis 32 in a rotational direction 200. Radial oscillation refers to movement of the drill string 16 transversely or laterally to the axis 32. In other words, radial oscillation may cause the drill string 16 to deflect laterally relative to the axis 32, and may be a mixture of rotational oscillation and lateral movement.

[0038] In general, it should be understood that any oscillatory motion described herein may include cycles of repeated displacement of the drill string 16. Thus, each oscillatory motion may include a corresponding amplitude, which is the maximum displacement of the drill string; and a corresponding frequency, which is the number of cycles of the motion of the drill string 16 that occur in one second. In addition, the corresponding amplitude and frequency within a particular oscillatory motion may vary over time. For example, an oscillatory motion (e.g., an axial oscillation) may vary based on the axial velocity or drilling rate (ROP) of the drill bit 20 entering the geological formation 14. The varying oscillatory motion may result in varying amplitudes and / or frequencies.

[0039] The illustrated embodiment of the BHA 18 can detect vibration and oscillatory motion of the drill bit 20. For example, the BHA 18 can include a sensor 202 that detects an operating parameter indicative of the oscillatory motion of the drill bit 20. In some embodiments, the sensor 202 can be an accelerometer (e.g., a piezoelectric accelerometer) that detects acceleration of the drill string 16 in the first and second axial directions 34, 36, for example. In additional or alternative embodiments, the sensor 202 can be a strain gauge that detects deformation of the drill string 16 (e.g., axial strain) and / or stress applied to the drill string 16. In other embodiments, the sensor 202 can be a pressure sensor that detects fluid pressure within the drill string 16; a radial accelerometer or strain gauge that detects bending motion (e.g., bending stress, bending strain) of the drill string 16; and / or other types of sensors.

[0040] The sensor 202 may be communicatively coupled to a control system 204 that processes and / or transmits the operating parameters detected by the sensor 202. The control system 204 may be part of the data processing system 160, or the control system 204 may be a separate system communicatively coupled to the data processing system 160. In some embodiments, the sensor 202 may be part of the MWD module 130, and the control system 204 may be considered to be part of the LWD module 120. It should be understood that the sensor 202 and / or the control system 204 may be components of other suitable parts of the drilling system 10. Indeed, the sensor 202 may be located outside the borehole 12 (e.g., at or near the surface system 22), may be part of the motor 150, etc. In certain embodiments, multiple sensors 202 may be used, each of which may detect the operating parameters and / or other operating parameters. In such embodiments, multiple values ​​of the operating parameters may be detected, and the control system 204 may use a representative value (e.g., a mathematical average) of the multiple values. In any case, the control system 204 may include a memory 164 that stores instructions to process information detected by the sensor 202, and / or may include a processor 162 that executes the instructions. In some embodiments, the control system 204 may also include an I / O port 170 to enable the control system 204 to be communicatively coupled to other electronic devices.

[0041] In certain embodiments, the motor 150 may localize the movement of the drill bit 20 relative to the rest of the drill string 16. For example, the motor 150 may attenuate, enhance, or otherwise cause a difference between the movement of the rest of the drill string 16 relative to the drill bit 20. In this manner, the operating parameter detected by the sensor 202 may not directly represent the behavior of the drill bit 20. Therefore, the control system 204 may process the operating parameter to infer the behavior of the drill bit 20. For example, the control system 204 may infer, calculate, or otherwise associate the operating parameter detected by the sensor 202 with the presence of high-frequency rotational oscillations at the drill bit 20. That is, the control system 204 may determine and set a specific threshold associated with the operating parameter, wherein the threshold indicates the presence of high-frequency rotational oscillations. In other words, determining that a specific threshold has been exceeded may indicate the presence of high-frequency rotational oscillations at the drill bit 20. The inference, calculation, or association of the operating parameter with the high-frequency rotational oscillations at the drill bit 20 and / or the threshold may be determined via simulation, modeling, and / or identifying trends in historical data.

[0042] As will be appreciated, axial motion (e.g., axial oscillations) may be generated based on the rotational oscillations. Thus, by determining such axial motion, the nature of the rotational oscillations (e.g., the amplitude of the rotational oscillations) may be inferred. Since determining the rotational oscillations via measurements or detections from sensors may be difficult and / or impractical, using the characteristics of the axial oscillations to infer or determine the rotational oscillations may enable the operation of the drilling system 10 to be adjusted to limit the presence of high frequency rotational oscillations.

[0043] Figure 3 1 is a schematic diagram of a computing system, such as a rotational oscillation determination system 230, that can process operating parameters of the drilling system 10 according to an embodiment of the present disclosure. As shown, the rotational oscillation determination system 230 includes a control system 204 communicatively coupled to a sensor 202. Thus, the control system 204 can receive a detected operating parameter (e.g., an accelerometer or a strain gauge) of the sensor 202. The control system 204, via the processor 162, can perform an operation in response to receiving the detected operating parameter, such as processing, storing, transmitting, etc., to determine or infer the rotational movement of the drill string 16. In some embodiments, the processor 162 can perform an operation on a component of the drilling system 10 based on receiving the detected operating parameter. As an example, the control system 204 can be further communicatively coupled to the drill string 16. Based on the detected operating parameter and / or the determined rotational movement of the drill string 16, the control system 204 can adjust the rotation of the drill string, change the flow rate of the drilling fluid 40 directed to the drill string 16, suspend the operation of a component of the drill string 16, and the like. In certain embodiments, the control system 204 may be communicatively coupled to the user interface 168 of the data processing system 160. Thus, the control system 204 may transmit certain information to the data processing system 160 for use on the user interface 168. By way of example, the control system 204 may receive, analyze and / or process the operating parameters and generate a visualization based on the operating parameters, such as a graph of the detected operating parameters as they change over time. The user interface 168 may then display the generated graph for the user to view.

[0044] In additional or alternative embodiments, the control system 204 may be communicatively coupled to other components. In one example, an input device 234 may be coupled to the control system 204, for example, via the I / O port 170. The input device 234 may receive information (e.g., a detected operating parameter of the drilling system 10) from the control system 204, and / or the input device 234 may transmit information (e.g., a previously detected operating parameter of another drilling system 10) to the control system 204. The control system 204 may use the information transmitted by the input device 234 to adjust how the control system 204 may operate.

[0045] Continue to refer Figure 3 , the illustrated embodiment of the control system 204 also includes a threshold determination engine 232 that sets a particular threshold associated with the operating parameter to indicate the presence of high frequency rotational oscillations at the drill bit 20. In certain embodiments, the threshold determination engine 232 may set the threshold based on simulation, modeling, and / or historical trend data analysis of operations on the drill string 16 to determine the associated oscillation characteristics of the drill string 16. The simulation, modeling, and / or historical trend data analysis may establish a relationship between the amplitude of the axial acceleration oscillations at the drill bit 20 and the frequency of the rotational oscillations at the drill bit 20. That is, it may be determined that the amplitude value of the axial acceleration oscillations at the drill bit 20 corresponds to having a high frequency present at the drill bit 20. Based on the established relationship between the amplitude of the axial acceleration oscillations at the drill bit 20 and the presence of high frequency rotational oscillations at the drill bit 20, the threshold determination engine 232 may set the threshold to correspond to the high frequency rotational oscillations at the drill bit 20. In other words, the threshold set by the threshold determination engine 232 may be the amplitude value of the axial acceleration oscillations at the drill bit 20 that corresponds to the presence of high frequency rotational oscillations at the drill bit 20.

[0046] As mentioned, the rotational oscillations may be localized below the motor 150, and therefore, measurement or detection of such rotational oscillations may be difficult. However, high frequency rotational oscillations may produce some axial motion of the drill string 16, which may be detected or determined by the sensor 202 (e.g., a geostable control collar of the RSS 152). That is, the operating parameters detected by the sensor 202 may be related to the axial motion of the drill string 16. Therefore, by detecting such operating parameters, the control system 204 may determine that high frequency rotational oscillations are present.

[0047] As will be appreciated, the operating parameters detected by the sensor 202 may be correlated to the axial acceleration oscillation amplitude at the drill bit 20. In other words, the sensor 202 may detect an operating parameter (e.g., axial acceleration, axial strain) of the drill string 16, and the control system 204 may use the detected operating parameter to determine (e.g., calculate) a corresponding axial acceleration oscillation amplitude at the drill bit 20. The control system 204 may then use the axial acceleration oscillation amplitude at the drill bit 20 to determine whether high frequency rotational oscillations are present at the drill bit 20.

[0048] For example, the control system 204 may approximate the axial acceleration oscillation amplitude at the location or position of the sensor 202 (i.e., the detection or measurement location) by determining the root mean square (RMS) of the axial acceleration (as detected by the sensor 202) at the detection location, as shown in Equation 1 below:

[0049]

[0050] Among them, A sensoris the axial acceleration oscillation amplitude at the detection position under gravitational acceleration (g), a is the axial acceleration detected by the sensor 202 at the detection position under g, and is the average value of the axial acceleration detected by the sensor 202 at the detection position under g over a period of time. In additional or alternative embodiments, A may be determined via other methods, for example, via peak-to-peak calculation of the detected axial acceleration values, a rainwater flow calculation algorithm, etc. sensor , instead of using Equation 1.

[0051] In certain embodiments, the axial acceleration oscillation amplitude at the detection location (e.g., which may be determined via operating parameters detected by the sensor 202) may be slightly different from the axial acceleration oscillation amplitude at the drill bit 20 (e.g., which may be used to predict the presence of high-frequency rotational oscillations at the drill bit 20). As a result, the control system 204 may convert the axial motion detected by the sensor 202 to determine the axial motion at the drill bit 20. For example, a conversion calculation or estimation may be performed based on additional simulation, modeling, historical trend data analysis, algorithmic calculation, or other suitable techniques to establish a conversion ratio between the axial acceleration oscillation amplitude at the detection location and the axial acceleration oscillation amplitude at the drill bit 20. The following Equation 2 represents the relationship between the axial acceleration oscillation amplitude at the detection location and the axial acceleration oscillation amplitude at the drill bit 20:

[0052] A bit =RA sensor Equation 2

[0053] Among them A bit is the axial acceleration oscillation amplitude of the drill bit 20, A sensor is the axial acceleration oscillation amplitude determined via the operating parameters detected by sensor 202, and R is a conversion ratio established through additional simulation, modeling, historical trend data analysis, algorithmic calculation, or other suitable techniques. The control system 204 can then use A as determined via Equation 2 bit , for example by adding A bit A comparison is made to a threshold value set by the threshold determination engine 232 to predict the presence of high frequency rotational oscillations.

[0054] If sensor 202 detects axial acceleration (eg, sensor 202 is an accelerometer), control system 204 may determine A by directly inserting the detected axial acceleration into equations 1 and 2. sensor and A bit, to determine the presence of high frequency rotational oscillations. If sensor 202 detects axial strain (e.g., sensor 202 is a strain gauge), control system 204 calculates A by first determining acceleration and / or velocity based on the detected axial strain and then using the determined acceleration and / or velocity. sensor and A bit Additionally or alternatively, the control system 204 may convert the detected axial strain into axial stress, determine the velocity based on the converted axial stress and the axial resistance of the drill string 16 at the detection location, and use the determined velocity to determine the acceleration to calculate A based on equations 1 and 2. sensor and A bit , to determine the presence of high-frequency rotational oscillations.

[0055] In further embodiments, other types of sensors and / or operating parameters may be used to determine the presence of high frequency rotary oscillations at the drill bit 20. In one example, a pressure sensor may be implemented near the drill bit 20 to detect the pressure of a fluid column within the drill string 16 (e.g., at a location above the drill bit 20 and below the motor 150). Simulations may then be performed and / or historical trend data may be analyzed to establish a relationship between the pressure at the drill bit 20 and a characteristic of the rotary oscillations (e.g., the amplitude of the rotary oscillation amplitude). The threshold determination engine 232 may then set a threshold based on the established relationship between the pressure at the drill bit 20 and the characteristic of the rotary oscillations. As an example, the threshold determination engine 232 may select a pressure value that indicates the presence of high frequency rotary oscillations at the drill bit 20. Still further, the BHA 18 may also include a sensor that detects radial oscillations, such as a radially mounted accelerometer and / or strain gauge oriented to measure deflection of the drill string 16. A relationship between radial oscillations and rotational oscillations may then be established at the drill bit 20 via simulation and / or analysis of historical trends, and the threshold determination engine 232 may set a threshold based on the radial oscillations (eg, the frequency of the radial oscillations).

[0056] As should be appreciated, the data detected by the sensor 202 may be filtered to improve the accuracy of the detected operating parameters. That is, the sensor 202 and / or the control system 204 may filter the detected data that is not caused by vibrations of the drill string 16 during operation of the drilling system 10. As an example, the sensor 202 and / or the control system 204 may filter out data associated with motion of the drill string 16 caused by sources other than the drilling system 10 (e.g., motion caused by gravity). To this end, the sensor 202 may apply a filter (e.g., a bandpass filter) that discards data having specific characteristics associated with motion of the drill string 16 caused by sources other than the drilling system 10 (e.g., low frequency data), while retaining data that does not have the specific characteristics (e.g., motion of the drill string 16 caused by the drilling system 10). Filtering out frequencies above the rotational oscillation characteristic improves the sensitivity of the measurement (e.g., by eliminating high frequency noise that is primarily electronic in nature).

[0057] In certain embodiments, other oscillation parameters of the drill string 16 may be determined. For example, the drill string 16 may have rotational oscillations of different frequencies (i.e., rotational oscillations of different modes), where multiple modes may be considered high-frequency rotational oscillations. The lowest frequency (i.e., lowest mode) of the high-frequency rotational oscillations of the existing drill string 16 and the corresponding motion in the axial and / or radial directions caused by the high-frequency rotational oscillations may generally be represented by the following equation 3:

[0058] f=2L / c Equation 3

[0059] Where f is the frequency of the rotational oscillation in Hertz (Hz), L is the length of the tube 154 below the motor, and c is the speed of the rotational wave, where c is 3200 meters per second. The exact frequency of the axial acceleration oscillation may depend on the geometry of the drill string 16, such as the geometry of the motor 150 and / or components (e.g., the tube 154 below the motor 150). Typically, the exact rotational frequency of the lowest mode will be lower than the rotational frequency f given in equation 3. In certain embodiments, the frequency may alternatively be determined by simulation or modeling in conjunction with detailed geometric information about the drill string 16 and the drill bit 20 to establish a more accurate frequency value. In other cases, the most important mode of the high-frequency rotational oscillation is not the mode of the lowest mode, but rather the mode of the higher mode (e.g., a frequency that is an integer multiple of the frequency in the lowest mode). Thus, the frequency of the high-frequency rotational oscillation may be a multiple of the frequency f of equation 3. In other words, the frequency f may be multiplied by an integer n to equal a specific frequency of the high-frequency rotational oscillation of different modes. In any case, such a frequency may be determined by simulation and / or modeling.

[0060] Furthermore, the drilling speed can be determined by the following equation 4:

[0061] ROP=A bit / 2πf Equation 4

[0062] Where ROP is the drilling rate through the geological formation 14 in meters per second (m / s), f is the frequency of the high frequency rotary oscillation when the rotary oscillation is at full amplitude, and Abit is the amplitude of the axial acceleration oscillation at the drill bit 20. The frequency f can be determined by a measurement device, such as performing a Fourier transform on data indicating the axial acceleration oscillation and determining the frequency at which the amplitude of the transformed data is maximum. Additionally or alternatively, the frequency f can be determined by calculation via equation 3. Thus, the control system 204 can determine the rate at which the drilling system 10 is cutting the geological formation 14 based on the amplitude of the axial acceleration oscillation. For example, ROP can represent the efficiency of the drilling system 10 drilling through the geological formation 14.

[0063] It should be understood that equations 1-4 and / or the above-described simulations, modeling, or algorithms may be modified based on the application of a particular drilling system 10. That is, due to differences in the geometry, components, physical properties, and / or operating characteristics of the drilling system 10, certain variables of equations 1-4 may be adjusted, converted, corrected, etc. Additionally or alternatively, it should be understood that different simulations may be performed, and / or historical trend data may be collected and / or analyzed for different types of drilling systems 10 to more accurately determine the relationship between the variables of equations 1-4. For example, different relationships may exist between the behavior of axial oscillations and rotational oscillations based on the geometry of the drill string 16, the components of the drilling system 10, the application of the drilling fluid 40 during operation of the drilling system 10, the characteristics (e.g., stiffness) of the geological formation 14, etc. Therefore, various simulations may be performed and / or historical trend data may be collected and / or analyzed, and equations 1-4 or the results of equations 1-4 may be adjusted to obtain more accurate results.

[0064] Figure 4 A first graph 260 and a second graph 262 are shown that plot respective detected oscillation parameters of the drilling system 10 over a period of time in accordance with an embodiment of the present disclosure. In particular, the first graph 260 plots a high frequency rotational oscillation amplitude 264 at the drill bit 20 at revolutions per minute (rpm) over a time 266 in seconds, while the second graph 262 plots an axial acceleration oscillation amplitude 268 at the drill bit 20 at g over a time 266. In particular, the first graph 260 and the second graph 262 illustrate certain values ​​of the axial acceleration oscillation amplitude that are produced when the high frequency oscillation amplitude is present.

[0065] In some embodiments, the first graph 260 and the second graph 262 may be generated based on simulation, modeling, and / or historical trend data analysis associated with the operation of the drill string 16. In one embodiment, the first sensor and the second sensor may be positioned on the drill string 16 without the motor 150 to reduce or eliminate movement at the drill bit 20 relative to the remainder of the drill string 16 that may be attributed to the motor 150. Thus, detection of oscillations at the detection point of the drill string 16 may substantially correspond to detection of oscillations at the drill bit 20. The first sensor may detect a rotational oscillation amplitude 264 of a rotational oscillation having a relatively high frequency (e.g., greater than 50 Hz) and generate the first graph 260. In the illustrated embodiment, the first sensor detects a rotational oscillation amplitude 264 of a rotational oscillation of the drill string 16 having a frequency of 192 Hz, although it should be understood that the first sensor may detect a rotational oscillation amplitude 264 of a rotational oscillation having any suitable frequency (e.g., 50 Hz, 100 Hz, 150 Hz, 200 Hz, etc.). At the same time, the second sensor may detect the axial acceleration oscillation amplitude at the drill bit 20 to generate the second graph 262. Thus, during a period in which the first and second sensors are operated to determine the relationship between the rotational oscillation amplitude 264 of the rotational oscillation having a relatively high frequency in the first graph 260 and the axial acceleration oscillation amplitude at the drill bit 20 in the second graph 262, the detection result of the first sensor in the first graph 260 may be compared with the detection result of the second sensor in the second graph 262. In additional or alternative embodiments, the first sensor may be disposed, for example, in the borehole 12 and detect the rotational oscillation amplitude 264 of the rotational oscillation of the drill string 16 having a relatively high frequency.

[0066] Comparing the first graph 260 and the second graph 262, the axial acceleration oscillation amplitude 268 appears to be consistent with the high-frequency rotation oscillation amplitude 264. In general, the presence of the high-frequency rotation oscillation amplitude 264 indicates the presence of a higher axial acceleration oscillation amplitude 268. In addition, when the high-frequency rotation oscillation amplitude 264 is not present, the axial acceleration oscillation amplitude 268 appears to be below a certain value. That is, as seen in the first graph 260, at certain times 265, the high-frequency rotation oscillation amplitude 264 is relatively low (e.g., at 50 rpm) or approximately zero, indicating that the high-frequency rotation oscillation is minimal or absent. The second graph 262 can then be used to determine the axial acceleration oscillation amplitude value corresponding to the time when the high-frequency rotation oscillation amplitude 264 is relatively low or approximately zero. In this particular example of the second graph 262, when the high-frequency rotation oscillation amplitude 264 is relatively low or approximately zero at time 265, the axial acceleration oscillation amplitude 268 is below about 0.25g (as shown by the dashed line 270).

[0067] In certain embodiments, the threshold determination engine 232 may set the threshold axial acceleration oscillation amplitude value based on a graph similar to the graphs 260, 262. That is, in the illustrated embodiment, the threshold determination engine 232 may set the threshold axial acceleration oscillation amplitude value at a particular value that is determined to correspond to the presence of high-frequency rotational oscillations. In certain embodiments, the threshold determination engine 232 may set the threshold value between a range, such as between 0.01 g and 1 g (e.g., 0.1 g, 0.2 g, 0.3 g), or any other suitable value or range of values ​​of the axial acceleration oscillation amplitude 268 corresponding to a time when the high-frequency rotational oscillation amplitude 264 is relatively low or approximately zero. In this manner, upon receiving an operating parameter value detected by the sensor 202, the control system 204 may convert (e.g., calculate) the operating parameter value into a corresponding axial acceleration oscillation amplitude value. Subsequently, the control system 204 may compare the corresponding axial acceleration oscillation amplitude value with the set threshold value to determine whether there is an excessive amount of high-frequency rotational oscillation amplitude 264.

[0068] In additional or alternative embodiments, the threshold determination engine 232 may set the threshold value based on the operating parameter detected by the sensor 202. For example, the threshold determination engine 232 may determine (e.g., via equations 1 and 2) an axial acceleration value, an axial or radial strain value, an axial or radial strain value, a pressure value, or any combination thereof (which may be detected by the sensor 202) that corresponds to a particular value of the operating parameter in which the presence of high-frequency rotational oscillations is determined. The threshold determination engine 232 may then set the threshold value to the determined operating parameter. In this manner, the control system 204 may compare the operating parameter value detected by the sensor 202 to the threshold operating parameter value without having to convert the detected operating parameter value to an axial acceleration oscillation amplitude value in order to determine the presence of high-frequency rotational oscillations. Advantageously, not converting each detected operating parameter value to an axial acceleration oscillation amplitude value may save computing resources, such as processing power, memory, storage space, and / or communication bandwidth.

[0069] Figure 5is a flow chart illustrating a method 300, which, in an embodiment, may be used to operate the drilling system 10 while mitigating rotational oscillations of the drill string 16 based on operating parameter values ​​determined by sensor data (e.g., provided by an accelerometer or strain gauge). As will be appreciated, the method 300 may be performed by the control system 204, the data processing system 160, or both. That is, instructions to perform the method 300 may be stored in a memory 164 and / or a storage device (e.g., storage device 166) of the control system 204 and / or the data processing system 160. Additionally or alternatively, the instructions to perform the method 300 may be stored in a separate electronic device that may be communicatively coupled to the control system 204 (e.g., via the I / O port 170). In any case, the processor 162 of the control system 204 and / or the processor 162 of the data processing system 160 may execute the instructions to perform the method 300.

[0070] At block 302, the processor 162 determines and sets a threshold associated with the amplitude of the axial acceleration oscillation at the drill bit 20. As described herein, the processor 162 may determine the threshold via simulation, modeling, and / or historical trend data analysis, and may set the threshold via the threshold determination engine 232. In some embodiments, the threshold may be automatically determined by the threshold determination engine 232. For example, the threshold determination engine 232 may analyze simulation results, modeling results, and / or historical trend data (e.g., analyzing the first graph 260 and the second graph 262) to determine and set an appropriate threshold. In additional or alternative embodiments, the threshold determination engine 232 may receive an input value (e.g., via user input) and set the threshold based on the input value.

[0071] In some embodiments, the threshold value may be the axial acceleration oscillation amplitude value at the drill bit 20 at which the processor 162 determines that there is high frequency rotational oscillation. Figure 4 The threshold value may be an axial acceleration oscillation amplitude value (e.g., 0.25 g) represented by dashed line 270 shown in the second graph 262 of FIG. 20. In additional or alternative embodiments, the threshold value may be an operating parameter value detected by sensor 202, wherein the operating parameter value corresponds to an axial acceleration oscillation amplitude value at the drill bit 20 at which the presence of high frequency rotational oscillations is determined. In other words, the threshold value may be based on the axial acceleration, strain, and / or stress detected by sensor 202, rather than based on the axial acceleration oscillation amplitude 268.

[0072] At block 304, the processor 162 receives an operating parameter value related to the amplitude of the axial acceleration oscillations at the drill bit 20. For example, the operating parameter value may be detected by and received from the sensor 202. That is, while the drilling system 10 is in operation, the sensor 202 may detect the operating parameter value and send the operating parameter value to the processor 162. For example, the operating parameter may be an axial acceleration, a strain, and / or a stress, each of which may be related to the amplitude of the axial acceleration oscillations detected at the drill bit 20 while the drilling system 10 is in operation.

[0073] At block 306, the processor 162 determines whether high frequency rotational oscillations are present by comparing the received operating parameter value associated with the axial acceleration oscillation amplitude at the drill bit 20 to the threshold value set at block 302. If the threshold value is based on the axial acceleration oscillation amplitude at the drill bit 20, the processor 162 may convert the received operating parameter value (e.g., via equations 1 and 2) to a corresponding axial acceleration oscillation amplitude value at the drill bit 20. The processor 162 may then compare the corresponding axial acceleration oscillation amplitude value at the drill bit 20 to a threshold axial acceleration oscillation amplitude value at the drill bit 20. If the threshold value is based on an operating parameter (e.g., axial acceleration, strain, or stress), the processor 162 may directly compare the received operating parameter value detected by the sensor 202 to the threshold operating parameter value.

[0074] At decision block 308, the processor 162 determines whether high-frequency rotational oscillations are present based on whether the received operating parameter value is greater than a set threshold. If the processor 162 determines that high-frequency rotational oscillations are not present (e.g., the received operating parameter value is not greater than the set threshold), the processor 162 may not adjust the operation of the drilling system 10. As long as the processor 162 determines that high-frequency rotational oscillations are not present, the processor 162 may repeat blocks 304-308, wherein the sensor 202 continues to detect operating parameter values ​​associated with the amplitude of the axial acceleration oscillations at the drill bit 20, and the processor 162 continues to compare these operating parameter values ​​to the set threshold.

[0075] At block 310, in response to determining in decision block 308 that high frequency rotational oscillations are present (e.g., the received operating parameter value is greater than a set threshold), the processor 162 adjusts the operation of the drilling system 10. In certain embodiments, the processor 162 may adjust the operation of the drilling system 10 in response to a single determination that the received operating parameter value is greater than the set threshold. In other words, once it is determined that the received operating parameter value exceeds the set threshold, the processor 162 may adjust the operation of the drilling system 10. In additional or alternative embodiments, the processor 162 may adjust the operation of the drilling system 10 in response to determining that the received operating parameter value exceeds the set threshold a certain number of times over a period of time. In yet other embodiments, the processor 162 may adjust the operation of the drilling system 10 if the average of the received operating parameter values ​​over a period of time exceeds the set threshold. Still further, the received operating parameter value may be used in conjunction with other information (e.g., fatigue models for inferring torsion angles and torque cycles) to determine additional operational data (e.g., the remaining fatigue life of a component or portion of the drill string 16). The processor 162 may then adjust the operation of the drilling system 10 based on the determined additional operational data.

[0076] In any case, adjusting the operation of the drilling system 10 may include, for example, adjusting the flow rate of the drilling fluid 40, the rotation rate of the drill string 16, the rate at which the drill string 16 is driven along the axis 32, and / or another operation of the drilling system 10 (e.g., via the processor 162 or any other suitable controller, control system, or processing system or device). In an embodiment, the operation of the drilling system 10 may be adjusted based on a characteristic of the received operating parameter value, such as the amount by which the received data exceeds a set threshold.

[0077] After adjusting the operation of the drilling system 10, the processor 162 may again execute blocks 304-308 to determine whether high-frequency rotational oscillations are still present, in which case the processor 162 may further adjust the operation of the drilling system 10. In some embodiments, after adjusting the operation of the drilling system 10, a certain amount of time may elapse before further adjustments are made to the operation of the drilling system 10. That is, the operation of the drilling system 10 may be allowed to reach a balanced performance state before the processor 162 determines whether high-frequency rotational oscillations are present and whether further adjustments are to be made to the operation of the drilling system 10.

[0078] It should be understood that the method 300 may include steps not mentioned in the present disclosure. That is, these steps may be performed before the step at box 302 is performed, after the step at box 310 is performed, or in the middle of any step in the method 300. For example, after determining that the operation of the drilling system 10 is adjusted when the received operating parameter value is greater than the set threshold, the processor 162 also determines other operating conditions of the drilling system 10 (e.g., the rotation speed of the drill string 10 or the weight applied to the block of the traveler to drive the drill string 10). In this way, the processor 162 can mark such operating conditions as being associated with the time when the received operating parameter value is greater than the set threshold. The processor 162 can then avoid such operating conditions in subsequent drilling operations and thus limit the occurrence of high-frequency rotational oscillations when operating the drilling system 10. In another example, the processor 162 can use the received operating parameter value for subsequent determination of the threshold set at box 302 of the drilling system 10 or other drilling systems 10.

[0079] The above specific embodiments have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the specific forms disclosed, but to cover all modifications, equivalent forms and alternative forms that fall within the scope of the present disclosure.

[0080] The technology presented and claimed herein is cited and applied to material objects and specific examples that arguably improve the practical nature of the art and is therefore not abstract, intangible, or purely theoretical. In addition, if any claim appended to this specification contains one or more elements designated as "means for performing a function..." or "steps for performing a function...", it is intended that such elements should be interpreted under 35 U.S.C. § 112(f). However, for any claim containing elements designated in any other manner, such elements should not be interpreted under 35 U.S.C. § 112(f).

Claims

1. A tangible, non-transitory computer-readable medium storing instructions executable by one or more processors, wherein: The instructions are configured to cause the one or more processors to: receiving a value of an operating parameter detected at a detection location and a threshold value associated with an axial acceleration oscillation amplitude at a drill bit, wherein the drill bit is part of a drilling system; converting the operating parameter value into a corresponding axial acceleration oscillation amplitude at a detection position value of the drilling system; converting the corresponding axial acceleration oscillation amplitude at the detection position into the axial acceleration oscillation amplitude at the drill bit; comparing the axial acceleration oscillation amplitude at the drill bit with a threshold value; determining the presence of high frequency rotational oscillations occurring in the drilling system while drilling based on a comparison of the axial acceleration oscillation amplitude at the drill bit with a threshold value; and While drilling, operation of the drilling system is adjusted in response to determining the presence of high frequency rotational oscillations occurring in the drilling system.

2. The tangible, non-transitory computer-readable medium of claim 1, wherein: Determining the presence of high frequency rotational oscillations occurring in the drilling system indicates the presence of high frequency rotational oscillations at the drill bit.

3. The tangible, non-transitory computer-readable medium of claim 2, wherein: High-frequency rotational oscillations at the drill bit correspond to rotational oscillations having a frequency greater than 50 Hz.

4. The tangible, non-transitory computer-readable medium of claim 1, wherein: The threshold is determined via simulation, modeling, historical trend data analysis, user input, or any combination thereof.

5. The tangible, non-transitory computer-readable medium of claim 1, wherein: The operating parameter value includes an acceleration value, a strain value, a stress value, a pressure value, a previous operating parameter value associated with the radial oscillation, or any combination thereof, detected at a detection location of the drilling system.

6. The tangible, non-transitory computer-readable medium of claim 1, wherein: Adjusting the operation of the drilling system includes adjusting the flow rate of drilling fluid directed to the drill bit, the rate at which the drill bit rotates, the rate at which the drill bit is driven, or any combination thereof.

7. The tangible, non-transitory computer-readable medium of claim 1, wherein: Adjusting the operation of the drilling system is responsive to determining that a corresponding axial acceleration oscillation amplitude at the drill bit exceeds the threshold, determining that the corresponding axial acceleration oscillation amplitude at the drill bit exceeds the threshold a certain number of times within a period of time, determining that an average of a plurality of corresponding axial acceleration oscillation amplitudes at the drill bit exceeds the threshold within another period of time, or any combination thereof.

8. The tangible, non-transitory computer-readable medium of claim 1, wherein: The threshold value indicates that the value of the axial acceleration oscillation amplitude at the drill bit is 0.1 g to 0.5 g.

9. The tangible, non-transitory computer-readable medium of claim 1, wherein the operating parameter value comprises a pressure value detected at a detection location of the drilling system.

10. A drilling system comprising: a drill string including a drill bit, wherein the drill string is configured to rotate and drive the drill bit to engage the drill bit with a borehole; a sensor configured to detect a value of an operating parameter of the drilling system at a detection location on the drill string; and a control system communicatively coupled to the drilling system, wherein the control system comprises: a threshold determination engine configured to determine a threshold value associated with an axial acceleration oscillation amplitude at the drill bit; Processor; and A storage device configured to store instructions configured to cause a processor to: receiving an operating parameter value detected by a sensor while drilling; In response to receiving the operating parameter value, converting the operating parameter value into a first axial acceleration oscillation amplitude at the detected position value; converting the first axial acceleration oscillation amplitude at the detection position into the axial acceleration oscillation amplitude at the drill bit; comparing the axial acceleration oscillation amplitude at the drill bit with a threshold value; determining that the axial acceleration oscillations at the drill bit indicate the presence of high frequency rotational oscillations based on a comparison of the amplitude of the axial acceleration oscillations at the drill bit with a threshold value; and While drilling, operation of the drilling system is adjusted in response to determining that axial acceleration oscillations at the drill bit are indicative of the presence of high frequency rotational oscillations.

11. The drilling system according to claim 10, wherein: The drill string includes a motor configured to orient the drill bit in a desired direction and maintain rotation of the drill bit during operation of the drilling system, wherein the motor decouples the drill bit from a detection location of the drill string.

12. The drilling system according to claim 10, wherein: The sensor includes a strain gauge configured to detect an axial strain or a radial strain of the drill string, or another strain gauge configured to detect an axial stress or a radial stress applied to the drill string.

13. The drilling system according to claim 10, wherein: The sensor includes a filter configured to remove data having a specific frequency.

14. The drilling system according to claim 10, characterized in that The sensor includes a pressure sensor configured to detect pressure exerted on the drill string.

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