MITIGATING HIGH FREQUENCY TORSIONAL OSCILLATION IN A DRILLING SYSTEM

Description

CROSS-REFERENCE TO RELATED APPLICATION(S)

The present disclosure claims priority from U.S. Prov. Appl. No. 63/726,707, filed on Dec. 2, 2024, herein incorporated by reference in its entirety.

BACKGROUND OF THE DISCLOSURE

Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores.

Downhole drilling systems may include one or more rotating components. During operation, the rotating components may perform a variety of operations, including power generation, drilling, reaming, casing cutting, milling, steering, and other rotary operations. When rotating, the components may experience various types of vibrations, including axial, lateral, and torsional vibrations. Vibrations or oscillations may fatigue components of downhole tools (e.g., housings, shafts, etc.), increase wear, decrease tool effectiveness, or otherwise damage downhole tools.

SUMMARY

In some aspects, the techniques described herein relate to a method for high frequency torsional oscillation (HFTO) mitigation in a wellbore. A HFTO mitigation system receives torque measurements and vibration measurements for a drill string. The HFTO mitigation system generates a plurality of frequency modes for the drill string using a physical model of the drill string. The HFTO mitigation system applies an HFTO model to the torque measurements and the vibration measurements to identify an HFTO mode. When the HFTO mode correlates with one of the plurality of frequency modes, the HFTO mitigation system adjusts at least one of a weight on bit or a rotational rate of the drill string.

In some aspects, the techniques described herein relate to a method for high frequency torsional oscillation (HFTO) mitigation. A HFTO mitigation system measures, at a downhole tool, torque measurements with a strain gauge connected to the downhole tool, and vibration measurements with an accelerometer connected to the downhole tool. Based on the torque measurements and the vibration measurements, the HFTO mitigation system identified an HFTO mode for the downhole tool. The HFTO mitigation system compares the HFTO mode to a frequency mode to generate an HFTO score. Based on the HFTO score, the HFTO mitigation system prepares a recommendation to reduce HFTO by adjusting one or both of rotational rate or weight on bit.

In some aspects, the techniques described herein relate to a drilling system, including: a drill string including a downhole tool; a torque sensor connected to the downhole tool; an accelerometer connected to the downhole tool; a processor and memory, the memory including instructions that cause the processor to: receive torque measurements from the torque sensor and vibration measurements from the accelerometer; generate a plurality of frequency modes for the drill string using a physical model of the drill string and the downhole tool; apply an HFTO model to the torque measurements and the vibration measurements to identify an HFTO mode; and when the HFTO mode correlates with one of the plurality of frequency modes, adjust at least one of a weight on bit or a rotational rate of the drill string.

This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 is a representation of a drilling system, according to at least one embodiment of the present disclosure.

FIG. 2 is a representation of an HFTO mitigation system, according to at least one embodiment of the present disclosure.

FIG. 3 is a flowchart of a method for mitigating HFTO, according to at least one embodiment of the present disclosure.

FIG. 4 is a flowchart of a method for mitigating HFTO, according to at least one embodiment of the present disclosure.

FIG. 5 is a flowchart of a method for mitigating HFTO, according to at least one embodiment of the present disclosure.

FIG. 6 is a flowchart of a method for mitigating HFTO, according to at least one embodiment of the present disclosure.

FIG. 7 is a representation of a computing system, according to at least one embodiment of the present disclosure.

DETAILED DESCRIPTION

This disclosure generally relates to devices, systems, and methods for identifying and mitigating high frequency torsional oscillations (HFTO) and other vibrational motions. For instance, downhole systems may experience a variety of motions, vibrations, and oscillations. In some embodiments, the movements are associated with drilling activities. For example, one or more downhole tools may rotate to degrade a formation or other downhole materials. The downhole tools may include a rotating bit, mill, or reamer. The engagement of a downhole tool and/or drill string with downhole materials, the flow of drilling or production fluids against or through a downhole tool, or other conditions may cause vibrations, torsional oscillations, and other motions. For the purposes of this disclosure, the terms HFTO, vibrations, oscillations, and other motions may be used interchangeably, unless otherwise stated, and may refer to vibrations in or exhibited by any component of a drilling system, such as axial vibrations, lateral vibrations, torsional vibrations, and HFTO. Left unchecked, HFTO and other vibrational motion may damage, increase wear, or increase fatigue on one or more components of the downhole system, and combinations thereof. Of course, vibrations and oscillations may be a concern in other downhole contexts apart from drilling (e.g., testing, perforating, production, artificial lift, etc.), and a downhole environment should not be limited to drilling systems.

In accordance with at least one embodiment of the present disclosure, an HFTO mitigation system may receive torque and vibration measurements from downhole sensors. The downhole sensors may include torque sensors and vibration sensors located at a downhole tool. Using the torque and vibration measurements, the HFTO mitigation system may generate HFTO modes of the drill string. The HFTO modes may be representative of the vibratory and oscillatory motion experienced by the drilling system, including a frequency and magnitude of the vibratory and oscillatory motion.

The HFTO mitigation system may identify, based on a physical model of the drilling system. The physical model may incorporate all the physical aspects of the drilling system, including the surface equipment at a surface location, downhole equipment, equipment diameter, equipment length, connections, hole trajectory, hole geometry, formation properties, drilling fluid properties, any other physical aspects of the drilling system, and combinations thereof. In some embodiments, the physical model may incorporate dynamic aspects of the drilling system, such as rotational rate, weight on bit (WOB), torque, tripping rate (e.g., travelling block speed, run-in-hole (RIH), pull out of hole (POOH)), drilling fluid flow rate, drilling fluid pressure, any other dynamic aspect, and combinations thereof.

The physical model may generate multiple frequency modes for the drilling system. The frequency modes may include vibrational and frequencies at which the magnitude of the vibratory motion is relatively high. For example, the frequency modes may include resonance frequencies or other frequencies in which the displacement of the drilling equipment may be maximized. In some embodiments, the frequency modes may identify nodes and antinodes of the drilling system. A node may be a point along the drill string of no or minimum displacement. An antinode may be a point of maximum displacement. The frequency modes may identify the locations of the nodes and the antinodes and the associated displacement at the antinodes. In some embodiments, the physical model may identify frequency modes in which the displacement results in damage to equipment in the drilling system.

In accordance with at least one embodiment of the present disclosure, the HFTO mitigation system compares the identified HFTO modes to the frequency modes. The HFTO mitigation system may determine whether the HFTO mode matches or correlates with a frequency mode that is likely to result in damage to the drilling system by comparing the HFTO mode to the frequency mode. When this occurs, the HFTO mitigation system may adjust one or more drilling parameters to adjust the HFTO mode. For example, the HFTO mitigation system may adjust the rotational rate and/or the WOB. This may change the dynamic conditions of the drilling system, thereby changing the HFTO mode. In some embodiments, adjusting the drilling parameters may reduce damage based on HFTO, thereby increasing the operating lifetime of the drilling system.

In some embodiments, the HFTO model and/or a recommendation model that recommends that changes in drilling parameters may include an artificial intelligence model trained to identify HFTO modes, identify frequency modes, correlate the HFTO modes to the frequency modes, and identify the changes on the HFTO modes with changes in the drilling parameters. In accordance with at least one embodiment of the present disclosure, the HFTO mitigation system may train the HFTO model based on the changes to the drilling parameters. For example, the HFTO mitigation system may, after preparing the changes to the drilling parameters, continue to monitor the torque and vibration measurements. The HFTO mitigation system may train the HFTO model using the torque and vibration measurements measured after adjusting the drilling parameters. This may train the HFTO model to identify how changes in the drilling parameters impact the HFTO modes.

In accordance with at least one embodiment of the present disclosure, the HFTO mitigation system may implement the HFTO model and/or the recommendation model in real-time. For example, the HFTO mitigation system may receive HFTO measurements from downhole, identify the HFTO mode, and prepare recommendations to adjust drilling parameters (or automatically adjust drilling parameters) in real-time. In this manner, the HFTO mitigation system may implement mitigating actions and reduce HFTO before HFTO can cause damage to the drilling system. In some embodiments, the HFTO mitigation system may identify the HFTO modes using historical or previously recorded vibration or oscillation data, and identify how changes in the drilling parameters changed the HFTO mode. In this manner, the HFTO mitigation system may utilize historical or previously recorded data to further refine the HFTO model and/or the recommendation model and/or prepare adjustments to operating parameters to prevent damaging HFTO from occurring.

By way of background, FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (BHA) 106, and a bit 110, attached to the downhole end of drill string 105.

The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, for lifting cuttings out of the wellbore 102 as it is being drilled, for controlling influx of fluids in the well, for maintaining the wellbore integrity, and for other purposes.

The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or damping tools, other components, or combinations of the foregoing. The BHA 106 may further include a directional tool 111 such as a bent housing motor or a rotary steerable system (RSS). The directional tool 111 may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. In some cases, at least a portion of the directional tool 111 may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, or true north. Using measurements obtained with the geostationary position, the directional tool 111 may locate the bit 110, change the course of the bit 110, and direct the directional drilling tool 111 on a projected trajectory. For instance, although the BHA 106 is shown as drilling a vertical portion 102-1 of the wellbore 102, the BHA 106 (including the directional tool 111) may instead drill directional or deviated well portions, such as directional portion 102-2.

Examples of directional tools 111 and/or steering systems may include “push-the-bit” systems, “point-the-bit” systems, hybrid systems, any other system, and combinations thereof. In a push-the-bit system, actuator pads may extend from the directional tool 111 to contact the wellbore wall. The actuator pads may apply a force against the wellbore wall, which may push the bit away from the actuator pad. Other examples of push-the-bit systems may include RSS systems, non-rotating (with respect to the hole) eccentric stabilizers (e.g., displacement-based systems). Steering is achieved by creating non co-linearity between the drill bit and at least two other touch points.

In point-the-bit systems, the axis of rotation of the bit 110 is deviated from the local axis of the BHA 106 in the general direction of the desired path (target attitude). The borehole is propagated in accordance with the customary three-point geometry defined for example by upper and lower stabilizers and the hole reaming cutters. The angle of deviation of the drill bit axis coupled with a finite distance between the lower and middle touch points results in the non-collinear condition for a curve to be generated. This may be accomplished, for example, by a fixed bend at a point in the BHA 106 close to the lower stabilizer or flexure in the drill bit drive shaft distributed between the upper and lower stabilizers.

In general, the drilling system 100 may include additional or other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.

In some embodiments, the BHA 106 may include a downhole motor to power for downhole systems and/or provide rotational energy for downhole components (e.g., rotate the bit 110, drive the directional tool 111, etc.). The downhole motor may be any type of downhole motor, including a positive displacement pump (such as a progressive cavity motor) or a turbine. In some embodiments, a downhole motor may be powered by the drilling fluid flowing through the drill pipe 108. In other words, the drilling fluid pumped downhole from the surface may provide the energy to rotate a rotor in the downhole motor. The downhole motor may operate with an optimal pressure differential or pressure differential range. The optimal pressure differential may be the pressure differential at which the downhole motor may not stall, burn out, overspin, or otherwise be damaged. In some cases, the downhole motor may rotate the bit 110 such that the drill string 105 may not be rotated at the surface, or may rotate at a different rate (e.g., slower) than the rotation of the bit 110.

The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials such as earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, and combinations thereof. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other downhole materials, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface or may be allowed to fall downhole. In still other embodiments, the bit 110 may include a reamer. For instance, an underreamer may be used in connection with a drill bit and the drill bit may bore into the formation while the underreamer enlarges the size of the bore.

During operation, the equipment of the drilling system 100 may experience vibratory motion, such as HFTO. As discussed herein, HFTO may result in damage to one or more elements of the drilling system 100. For example, HFTO may result in damage to the elements of the BHA 106, such as the bit, the directional drilling system (including the directional tool 111), the MWD, the LWD, expandable tools such as reamers and casing cutters, communication systems such as mud pulse telemetry, connections between subs and drill strings, any other portion of the BHA 106, and combinations thereof. In some embodiments, HFTO may result in damage to surface equipment, such as the drill rig 103, the top drive, the turn table, the kelly, the standpipe, the pumping equipment, any other surface equipment, and combinations thereof.

HFTO may be caused by the motion of the elements of the drilling system 100. In particular, HFTO may be caused by motion of elements of the BHA and the contact of the BHA with the wellbore walls of the wellbore 102. The locations of nodes and antinodes of HFTO may indicate the impact of the HFTO on the drilling system. For example, the motion resulting from HFTO at or near certain elements of the BHA 106 may damage these elements of the BHA 106. Identifying the nodes and antinodes may facilitate an understanding of the motion at a particular location along the BHA 106, including motion that may result in damage at the BHA 106.

An HFTO mitigation system may identify the frequency modes of the drilling system 100. For example, the HFTO mitigation system may apply a physical model to the drilling system 100. The HFTO mitigation system may apply the physical model to the current state of the drilling system 100 to generate the frequency modes based on the current state of the drilling system 100. The current state of the drilling system 100 may include various aspects of the drilling system 100, including the specific equipment used, the location of the equipment, the length of the equipment, the geometry of the wellbore, the trajectory of the wellbore, any other aspects of the drilling system 100, and combinations thereof.

Using the aspects of the drilling system 100, the physical model may identify one or more frequency modes. The frequency modes may include, various vibrational and oscillatory frequencies, the location of nodes (including nodes based on contact of the BHA 106 and/or the drilling tool assembly 104 with the wellbore wall of the wellbore 102) and antinodes along the length of the drill string 105 and BHA 106, and the maximum displacement at the antinodes. The physical model may identify frequency modes which may result in damage to elements of the drilling system 100. For example, based on the displacement and location of the antinodes, the physical model may identify when damage to certain elements of the drilling system 100 is likely to occur when the drilling system 100 is experiencing that particular frequency mode.

The HFTO mitigation system may collect and monitor torque and vibration measurements for the drilling system 100. To collect the torque and vibration measurements, the drilling system 100 may include one or more sensors on the BHA 106 and/or the drill string 105. Torque sensors may collect torque measurements. The torque sensors may include any sensor that is capable of measuring torque, such as one or more strain gauges oriented to measure stress on the elements of the BHA 106 and/or the drill string 105. Vibration sensors may include accelerometers connected to the elements of the drilling system and arranged to measure a magnitude and direction of the vibratory motion.

The HFTO mitigation system may, using the torque measurements and the vibration measurements, identify an HFTO mode for the drilling system 100. The HFTO mode may be a representation of the frequency of vibration and the measured locations of the nodes and antinodes of the vibration experienced by the drilling system 100. The HFTO mitigation system may compare the identified HFTO mode to the frequency modes generated by the physical model. When the HFTO mode matches or correlates with the physical model, the HFTO mitigation system may determine that the HFTO mode may result in damage to the drilling system 100 by comparing the HFTO mode to the frequency modes.

The HFTO mitigation system may, based on the HFTO mode and the corresponding physical model, adjust one or more drilling parameters in the drilling system 100. For example, the HFTO mitigation system may adjust the rotational rate. Adjusting the rotational rate may adjust the torque and/or vibrational pattern of the BHA 106 and/or the drill string 105. In some examples, the HFTO mitigation system may adjust the WOB (e.g., the HFTO mitigation may adjust the hookload at the drill rig 103). Adjusting the WOB may adjust the torque and/or vibrational pattern of the BHA.

The HFTO mitigation system may continuously monitor the HFTO mode to mitigate harmful HFTO. For example, the HFTO mitigation system may monitor the torque measurements and the vibration measurements after adjusting the rotational rate and/or the WOB. Based on the updated torque and vibration measurements, the HFTO mitigation system may identify whether the HFTO mode has changed. In some embodiments, based on the updated torque and vibration measurements, the HFTO mitigation system may identify whether the risk of damage to the drilling system 100 based on HFTO has been reduced or mitigated. In this manner, the HFTO mitigation system may prevent or reduce damage to the drilling system 100 based on HFTO.

In accordance with at least one embodiment of the present disclosure, the HFTO mitigation system may monitor for and identify other operational modes for the drilling system. For example, the HFTO mitigation system may monitor for and identify for stick slip conditions. The HFTO mitigation system may analyze whether a stick slip event is occurring. The HFTO mitigation system may analyze whether stick slip and HFTO have been mitigated, and/or identify whether the HFTO mode is impacting stick slip. In this manner, the HFTO mitigation system may mitigate other potentially damaging conditions downhole.

The HFTO mitigation system may identify damaging HFTO at any location. For example, a processor at the BHA 106 (such as the computing systems at the MWD) may receive the torque and vibration measurements. In some embodiments, the BHA 106 may determine the HFTO mode. In some embodiments, the BHA may determine the frequency mode. In some embodiments, the BHA 106 may identify the changes to the drilling parameters based on the comparison between the HFTO mode and the frequency mode. The BHA 106 may have limited transmission capacity to transmit information to the surface. Performing at least a portion of these calculations downhole may reduce the transmission bandwidth uphole.

In some embodiments, a processor at the surface may perform one or more of the calculations to identify the changes to drilling parameters. For example, the surface processor may receive the torque and vibration measurements and calculate the HFTO mode at the surface. In some examples, the surface processor may calculate the frequency mode based on the elements of the drilling system 100. In some examples, the surface processor may receive the HFTO mode and determine the changes to the drilling parameters based on the HFTO mode and the frequency mode. In some examples, the surface processor may implement the changes to the drilling parameters identified by the BHA 106 downhole.

FIG. 2 is a representation of an HFTO mitigation system 212, according to at least one embodiment of the present disclosure. Each of the components of the HFTO mitigation system 212 can include software, hardware, or both. For example, the components can include one or more instructions stored on a computer-readable storage medium and executable by processors of one or more computing devices, such as a client device or server device. When executed by the one or more processors, the computer-executable instructions of the HFTO mitigation system 212 can cause the computing device(s) to perform the methods described herein. Alternatively, the components can include hardware, such as a special-purpose processing device to perform a certain function or group of functions. Alternatively, the components of the HFTO mitigation system 212 can include a combination of computer-executable instructions and hardware.

Furthermore, the components of the HFTO mitigation system 212 may, for example, be implemented as one or more operating systems, as one or more stand-alone applications, as one or more modules of an application, as one or more plug-ins, as one or more library functions or functions that may be called by other applications, and/or as a cloud-computing model. Thus, the components may be implemented as a stand-alone application, such as a desktop or mobile application. Furthermore, the components may be implemented as one or more web-based applications hosted on a remote server. The components may also be implemented in a suite of mobile device applications or “apps.”

The HFTO mitigation system 212 may monitorfor and prepare mitigating recommendations based on the presence of potentially damaging HFTO. The HFTO mitigation system 212 may include HFTO sensors 214 connected to at least a portion of the drilling system. The HFTO sensors 214 may monitor the drilling system for vibratory and oscillatory motion. The HFTO sensors 214 may include any type of sensor. For example, the HFTO sensors 214 may include torque sensors 216. The torque sensors 216 may measure the torque that is applied to the rotating elements of the drilling system. For example, the torque sensors 216 may measure the torque that is applied to elements of the BHA and/or to pipes in the drill string. The torque sensors 216 may be any type of torque sensor. For example, the torque sensors 216 may include strain gauges. The torque sensors 216 may include a set of strain gauges that are arranged to measure torque in both rotational directions, including a first strain gauge or a first set of strain gauges arranged to measure torque in a first direction and a second strain gauge or a second set of strain gauges arranged to measure torque in a second direction opposite the first direction. The strain gauges may include quarter-bridge, half-bridge, or full Wheatstone bridge arrangements, or any other arrangement of strain gauges.

The HFTO sensors 214 may further include vibration sensors 218. The vibration sensors 218 may be any type of sensor that may measure vibratory motion. For example, the vibration sensors 218 may include one or more accelerometers. The accelerometers may measure the acceleration forces experienced by the structure to which they are attached, including the direction and magnitude of the acceleration. The accelerometers may be connected to the drilling system in multiple places. For example, the accelerometers may be connected to the drilling system along a length of the drilling system to identify acceleration and movement patterns in the drilling system. In some embodiments, the vibration sensors 218 may measure a displacement of the structure.

The HFTO mitigation system 212 includes an HFTO model 220. The HFTO model 220 may receive the torque measurements from the torque sensors 216 and the vibration measurements from the vibration sensors 218 to identify an HFTO mode of the drilling system. The HFTO model 220 may, using the torque measurements and the vibration measurements, identify an HFTO mode. The HFTO mode may include an identification of the nodes and antinodes of the motion of the drilling system.

The HFTO sensors 214 may be arranged in any manner. For example, the HFTO sensors 214 may include a series of sensors that are arranged along a length of a portion of the drilling system. Arranging the HFTO sensors 214 along the length of the drilling system may allow the HFTO model 220 to identify the change in the vibrations and oscillations along the length of the drilling system. This may facilitate improved identification of the HFTO mode of the drilling system.

In some embodiments, the HFTO sensors 214 may be arranged along the length of the BHA. For example, the BHA may include components that may be subject to damage due to HFTO. Monitoring torque and vibration at the BHA may allow the HFTO model 220 to more precisely identify HFTO, thereby improving the mitigation actions.

In some embodiments, the HFTO sensors 214 may be arranged along the length of the drill string. In some embodiments, the HFTO sensors 214 may be arranged along the length of one or more drill pipe segments uphole of the BHA. In some embodiments, the HFTO sensors 214 may be arranged along the entirety of the length of the drill string to the surface. This may facilitate improved identification of HFTO in the drilling system.

In some embodiments, the HFTO sensors 214 may communicate the torque measurements and the vibration measurements to the surface via a communication system on the BHA, such as a mud pulse telemetry system, a wireless telemetry system, and so forth. In some embodiments, the drilling system may include wired drill pipe. The HFTO sensors 214 may be connected to the wired drill pipe, and the torque measurements and vibration measurements may be communicated to the surface via the wired drill pipe.

The HFTO mitigation system 212 may further include a physical model 222. The physical model 222 may include a model that receives the physical elements of the drilling system as inputs and generates frequency modes as outputs. As discussed herein, the frequency modes may include vibratory and oscillatory motions, including frequency, displacement magnitude, and the projected locations of nodes and antinodes.

In some embodiments, the physical model 222 may identify frequency modes that may cause damage or increased wear on the drilling system. For example, the physical model 222 may identify frequency modes that have a displacement that may be damaging to portions of the drilling system. In some examples, the physical model 222 may identify frequency modes that have a frequency that is at or near a resonance frequency for one or more portions of the drilling system, which may cause damage to the drilling system.

An HFTO identifier 224 may compare the HFTO mode identified by the HFTO model 220 to the frequency modes identified by the physical model 222. The HFTO identifier 224 may determine whether the HFTO mode is the same as or close to one of the frequency modes by comparing the HFTO mode to the frequency modes. Put another way, based on the HFTO mode and the frequency modes, the HFTO identifier 224 may identify whether the vibratory and/or oscillatory motion experienced by the drilling system may result in damage to the drilling system.

A recommendation engine 226 may prepare a recommendation to adjust one or more drilling properties based on the HFTO mode and the associated frequency mode. The recommendation engine 226 may prepare a recommendation to adjust the drilling properties to adjust the HFTO mode. In some embodiments, the recommendation engine 226 may adjust the drilling properties to adjust the HFTO mode to increase the frequency of the vibrations and oscillations. In some embodiments, the recommendation engine 226 may adjust the drilling properties to adjust the HFTO mode to decrease the frequency of the vibrations and oscillations. In some embodiments, the recommendation engine 226 may adjust the drilling properties to adjust the HFTO mode away from the identified frequency mode(s) that may result in damage to the drilling system.

The recommendation engine 226 may prepare any recommendation to adjust the drilling properties of the drilling system. For example, the recommendation engine 226 may prepare a recommendation to adjust the rotational rate of the drilling system. Adjusting the rotational rate may adjust the torque applied to the drilling system. For example, reducing the rotational rate may reduce the torque applied to the drilling system, and increasing the rotational rate may increase the torque applied to the drilling system.

In some examples, the recommendation engine 226 may prepare a recommendation to adjust the hookload at the drill rig of the drilling system. Adjusting the hookload may include adjusting the speed at which the moving block moves in the drilling system. Adjusting the hookload may adjust the WOB of the drilling system. For example, increasing the hookload may increase the WOB and decreasing the hookload may decrease the WOB.

In some embodiments, the WOB may impact the torque on the drilling system. For example, an increased WOB may result in an increased torque (such as due to increased friction forces on the drilling system) and a decreased WOB may result in a decreased torque. Thus, increasing the WOB may result in increased torque, and decreasing the WOB may result in decreased torque.

In some embodiments, to reduce the damage to the drilling system, the recommendation engine 226 may prepare the recommendation to reduce the torque and/or the WOB. This may reduce the magnitude of the forces on the drilling system during oscillation, including reducing the displacement and/or the magnitude of the oscillating torque.

In some embodiments, the recommendation engine 226 may prepare a recommendation to adjust the frequency of HFTO in the drilling system. In some embodiments, the recommendation engine 226 may prepare a recommendation to adjust the locations of the nodes and antinodes of HFTO in the drilling system. This may facilitate reduced impact of HFTO in the drilling system.

Adjusting the frequency and/or locations of nodes and antinodes of the HFTO may be complex, based on the torque, the WOB, and the geometry of the wellbore. In some embodiments, the recommendation engine 226 may apply a machine learning (ML) or artificial intelligence (AI) model to the torque measurements and the vibration measurements from the torque sensors 216. For example, the HFTO mitigation system 212 may include an adjustment model 228. The adjustment model 228 may include a ML or an AI model that may be trained to identify associations between adjustments to the rotational rate and hookload, the physical parameters of the physical model 222, and the torque and vibration measurements. The recommendation engine 226 may request, from the adjustment model 228, an adjustment to mitigate damage from HFTO. The adjustment model 228 may receive as inputs, the physical model 222 and the torque and vibration measurements from the HFTO sensors 214. The adjustment model 228 may prepare an output that includes the recommendation to drilling parameter adjustments.

The ML model discussed herein may be any type of ML or AI model. For example, the ML model may include a supervised ML model, including annotated inputs annotated with the HFTO mode and/or changes in parameters or changes in the HFTO measurements based on changes in parameters. The ML model may include any type of model, including one or more of a linear regression model, a gradient boosting model, a random forest model, a deep neural network, any other ML model, and combinations thereof.

In accordance with at least one embodiment of the present disclosure, the HFTO mitigation system 212 may implement the recommendation from the recommendation engine 226. For example, the HFTO mitigation system 212 may cause the adjustments to the drilling system to be implemented. After implementing the recommendation, the HFTO sensors 214 may continue to monitor updated torque and vibration on the drilling system. The HFTO model 220 may identify the changed HFTO mode, and the HFTO identifier 224 may determine whether the changed HFTO mode corresponds with the frequency modes identified by the physical model 222.

The resulting torque and vibration measurements and HFTO mode may be used to further train the adjustment model 228. For example, the adjustment model 228 may be fine-tuned based on the adjustments to the drilling parameters and the changes in the torque and vibration measurements and HFTO mode. This may further improve the accuracy and/or relevance of the adjustment model 228. The recommendation engine 226, based on the adjustment model 228, may then generate an updated recommendation to reduce HFTO. The updated recommendation may then be used to adjust the drilling parameters. In this manner, the HFTO mitigation system 212 may facilitate continuous monitoring and improvement in the drilling system.

In some embodiments, the adjustment model 228 may be initially trained on offset wellbores, or previously drilled wellbores having similar parameters. In some embodiments, the adjustment model 228 may be fine-tuned based on changes made to the drilling parameters in the existing wellbore. In this manner, the adjustment model 228 may be fine-tuned to increase the accuracy and/or relevance of the recommendations based on measured conditions in the wellbore.

In some embodiments, the HFTO mitigation system 212 may be used to design drilling systems. For example, based on an identified wellbore trajectory and anticipated drilling conditions, the physical model 222 may identify planned frequency modes. The HFTO identifier 224 may identify whether the planned frequency modes may result in damage to the drilling system. Based on the planned frequency modes and the physical model 222, the recommendation engine 226 may prepare a recommendation for operating parameters. In some embodiments, the recommendation engine 226 may prepare a recommendation for drilling equipment that may reduce the likelihood of damaging HFTO, including the various equipment utilized in the BHA, as discussed herein.

The HFTO mitigation system 212 may further include an HFTO scoring engine 229. The HFTO scoring engine 229 may prepare an HFTO score for the HFTO mode. The HFTO score may be a representation of the level of severity of the HFTO in the HFTO mode. For example, the HFTO score may be a ranking of the level of damage that the drilling system may experience when subjected to the HFTO mode. In some examples, the HFTO score may be a ranking of the speed in which damage may be incurred based on the HFTO mode. In some embodiments, the HFTO score may be a combination of the level of damage and the speed in which the damage may be incurred.

The HFTO score may be based on the comparison between the HFTO mode and the frequency mode. In some embodiments, a higher HFTO score may be associated with a higher degree of correlation between the HFTO mode and the frequency mode, and a lower HFTO score may be associated with a lower degree of correlation between the HFTO score and the frequency mode. In some embodiments, the HFTO score may be based on the frequency mode. For example, a frequency mode associated with a greater amount of damage and/or a faster speed to accrue damage may be associated with a higher HFTO score.

The HFTO score may be used by the recommendation engine 226 to generate the recommendation. For example, the recommendation engine 226 may generate a recommendation for a larger change in drilling parameters based on a higher HFTO score. A smaller HFTO score may result in a relatively lower change in drilling parameters. Generating the recommendation based on the HFTO score may result in increased drilling efficiency by reducing or preventing overcorrection of the drilling parameters to correct for HFTO.

As discussed herein, the HFTO mitigation system may further train the recommendation engine 226 and the adjustment model 228 to generate recommendations. In some embodiments, the updated recommendations may result in an updated HFTO score. The updated HFTO score may be more accurate and/or more representative of potential damage to the drilling system based on the HFTO.

FIG. 3-6, the corresponding text, and the examples provide a number of different methods, systems, devices, and computer-readable media of the HFTO mitigation system. In addition to the foregoing, one or more embodiments can also be described in terms of flowcharts comprising acts for accomplishing a particular result, as shown in FIG. 3-6. FIG. 3-6 may be performed with more or fewer acts. Further, the acts may be performed in differing orders. Additionally, the acts described herein may be repeated or performed in parallel with one another or parallel with different instances of the same or similar acts.

As mentioned, FIG. 3 illustrates a flowchart of a series of acts or a method 330 for HFTO mitigation, according to at least one embodiment of the present disclosure. While FIG. 3 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 3. The acts of FIG. 3 can be performed as part of a method. Alternatively, a computer-readable medium can comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 3. In some embodiments, a system can perform the acts of FIG. 3.

As discussed herein, the HFTO mitigation system may measure torque and vibration measurements at a drilling system at 332. Based on the torque and vibration measurements, an HFTO identifier may determine the HFTO mode for the drilling system at 334. The HFTO mitigation system may determine at 336 whether the HFTO mode matches or correlates with a damaging frequency mode, or a frequency mode associated with damage to the drilling system. If the HFTO mode is not associated with a damaging frequency mode, the HFTO mitigation system may continue to monitor the drilling system by measuring torque and vibration and determining the HFTO mode.

If the HFTO mode matches or correlates with a damaging frequency mode, the HFTO mitigation system may adjust one or more drilling parameters at 338. For example, if the HFTO mode matches or correlates with a damaging frequency mode, the HFTO mitigation system may adjust one or both of the rotational rate or the hookload.

After adjusting the drilling parameters, the HFTO mitigation system may measure the change in torque and vibration. For example, the HFTO mitigation system may measure second torque measurements and second vibration measurements. The HFTO mitigation system may measure a changed HFTO mode and determine whether the changed HFTO mode matches or correlates with one or more of the damaging frequency modes. The HFTO mitigation system may continue to monitor torque and vibration and adjust the drilling parameters.

In some embodiments, the method 330 may be at least partially performed downhole. For example, one or more drilling tools at the BHA may measure the torque and vibration measurements, determine the HFTO mode, and determine whether the HFTO mode matches or correlates with the damaging frequency modes. In some embodiments, the BHA may transmit the HFTO mode to the surface. In some embodiments, the BHA may transmit the adjustments to the drilling system to the surface for the surface drilling system to implement. In this manner, the HFTO mitigation system may be automated or at least partially automated.

As mentioned, FIG. 4 illustrates a flowchart of a series of acts or a method 440 for HFTO mitigation, according to at least one embodiment of the present disclosure. While FIG. 4 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 4. The acts of FIG. 4 can be performed as part of a method. Alternatively, a computer-readable medium can comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 4. In some embodiments, a system can perform the acts of FIG. 4.

As discussed herein, the HFTO mitigation system may measure torque and vibration measurements at a drilling system at 432. Based on the torque and vibration measurements, an HFTO identifier may determine the HFTO mode for the drilling system at 434. The HFTO mitigation system may determine at 436 whether the HFTO mode matches or correlates with a damaging frequency mode, or a frequency mode associated with damage to the drilling system. If the HFTO mode is not associated with a damaging frequency mode, the HFTO mitigation system may continue to monitor the drilling system by measuring torque and vibration and determining the HFTO mode.

If the HFTO mode matches or correlates with a damaging frequency mode, the HFTO mitigation system may adjust one or more drilling parameters at 438. For example, if the HFTO mode matches or correlates with a damaging frequency mode, the HFTO mitigation system may adjust one or both of the rotational rate or the hookload.

After adjusting the drilling parameters, the HFTO mitigation system may measure the change in torque and vibration. For example, the HFTO mitigation system may measure second torque measurements and second vibration measurements. The HFTO mitigation system may measure a changed HFTO mode and determine whether the changed HFTO mode matches or correlates with one or more of the damaging frequency modes.

In some embodiments, the adjusted drilling parameters, the updated torque and vibration measurements, and the changed HFTO mode may be used to train an AI or ML adjustment model at 442. The HFTO mitigation system may identify how the changes in the drilling parameters impact the torque and vibration measurements, and therefore the associated HFTO mode. This may improve the accuracy and/or relevance of the adjustment model. In this manner, the recommended drilling parameter adjustments may be improved, thereby reducing or preventing damage to the drilling system based on HFTO.

As mentioned, FIG. 5 illustrates a flowchart of a series of acts or a method 500 for HFTO mitigation, according to at least one embodiment of the present disclosure. While FIG. 5 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 5. The acts of FIG. 5 can be performed as part of a method. Alternatively, a computer-readable medium can comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 5. In some embodiments, a system can perform the acts of FIG. 5.

A HFTO mitigation system may receive torque measurements and vibration measurements for a drill string at 501. The HFTO mitigation system may generate a plurality of frequency modes for the drill string using a physical model of the drill string at 502. The HFTO mitigation system may apply an HFTO model to the torque measurements and the vibration measurements to identify an HFTO mode for the drilling system at 503. The HFTO mitigation system may, when the HFTO mode correlates with one of the plurality of frequency modes, adjust at least one of a weight on bit or a rotational rate of the drill string at 504.

As mentioned, FIG. 6 illustrates a flowchart of a series of acts or a method 600 for HFTO mitigation, according to at least one embodiment of the present disclosure. While FIG. 6 illustrates acts according to one embodiment, alternative embodiments may omit, add to, reorder, and/or modify any of the acts shown in FIG. 6. The acts of FIG. 6 can be performed as part of a method. Alternatively, a computer-readable medium can comprise instructions that, when executed by one or more processors, cause a computing device to perform the acts of FIG. 6. In some embodiments, a system can perform the acts of FIG. 6.

A HFTO mitigation system may measure, at a downhole tool, torque measurements with a strain gauge connected to the downhole tool and vibration measurements with an accelerometer connected to the downhole tool at 601. The HFTO mitigation system may, based on the torque measurements and the vibration measurements, identify an HFTO mode for the downhole tool at 602. The HFTO mitigation system may compare the HFTO mode to a frequency mode to generate an HFTO score at 603. Based on the HFTO score, the HFTO mitigation system may prepare a recommendation to reduce HFTO by adjusting one or both of a rotational rate or weight on bit at 604.

FIG. 7 illustrates certain components that may be included within a computer system 700. One or more computer systems 700 may be used to implement the various devices, components, and systems described herein.

The computer system 700 includes a processor 701. The processor 701 may be a general-purpose single or multi-chip microprocessor (e.g., an Advanced RISC (Reduced Instruction Set Computer) Machine (ARM)), a special purpose microprocessor (e.g., a digital signal processor (DSP)), a microcontroller, a programmable gate array, etc. The processor 701 may be referred to as a central processing unit (CPU). Although just a single processor 701 is shown in the computer system 700 of FIG. 7, in an alternative configuration, a combination of processors (e.g., an ARM and DSP) could be used.

The computer system 700 also includes memory 703 in electronic communication with the processor 701. The memory 703 may be any electronic component capable of storing electronic information. For example, the memory 703 may be embodied as random access memory (RAM), read-only memory (ROM), magnetic disk storage media, optical storage media, flash memory devices in RAM, on-board memory included with the processor, erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM) memory, registers, and so forth, including combinations thereof.

Instructions 705 and data 707 may be stored in the memory 703. The instructions 705 may be executable by the processor 701 to implement some or all of the functionality disclosed herein. Executing the instructions 705 may involve the use of the data 707 that is stored in the memory 703. Any of the various examples of modules and components described herein may be implemented, partially or wholly, as instructions 705 stored in memory 703 and executed by the processor 701. Any of the various examples of data described herein may be among the data 707 that is stored in memory 703 and used during execution of the instructions 705 by the processor 701.

A computer system 700 may also include one or more communication interfaces 709 for communicating with other electronic devices. The communication interface(s) 709 may be based on wired communication technology, wireless communication technology, or both. Some examples of communication interfaces 709 include a Universal Serial Bus (USB), an Ethernet adapter, a wireless adapter that operates in accordance with an Institute of Electrical and Electronics Engineers (IEEE) 802.11 wireless communication protocol, a Bluetooth® wireless communication adapter, and an infrared (IR) communication port.

A computer system 700 may also include one or more input devices 711 and one or more output devices 713. Some examples of input devices 711 include a keyboard, mouse, microphone, remote control device, button, joystick, trackball, touchpad, and lightpen. Some examples of output devices 713 include a speaker and a printer. One specific type of output device that is typically included in a computer system 700 is a display device 715. Display devices 715 used with embodiments disclosed herein may utilize any suitable image projection technology, such as liquid crystal display (LCD), light-emitting diode (LED), gas plasma, electroluminescence, or the like. A display controller 717 may also be provided, for converting data 707 stored in the memory 703 into text, graphics, and/or moving images (as appropriate) shown on the display device 715.

The various components of the computer system 700 may be coupled together by one or more buses, which may include a power bus, a control signal bus, a status signal bus, a data bus, etc. For the sake of clarity, the various buses are illustrated in FIG. 7 as a bus system 719.

The embodiments of the HFTO mitigation system have been primarily described with reference to wellbore drilling operations; the HFTO mitigation systems described herein may be used in applications other than the drilling of a wellbore. In other embodiments, HFTO mitigation systems according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, HFTO mitigation systems of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers'specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.