High-frequency torsional oscillation detection by means of electric machine

Abstract

A system and method of detecting vibration of a drill string in a borehole. A drill string is transferred into a borehole, the drill string comprising a motor comprising a stator and a movable element movable relative to the stator rotating the drill string in the borehole. The control circuit determines a first amplitude of vibration of the drill string by measuring a signal indicative of movement of a movable element in the motor due to rotation of the drill string, and controls downhole operation of the drill string based on the detected first amplitude of vibration.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of the earlier filing dates of U.S. application serial number 63 / 494,333, filed on April 5, 2023, and U.S. application serial number 18 / 627115, filed on April 4, 2024, the entire disclosures of which are incorporated herein by reference. Background Art

[0003] In the resource recovery industry, a drill string is conveyed downhole to drill a borehole. For drilling purposes, the drill string includes a drill bit attached to a bottom hole assembly (BHA), which is connected to a drill pipe extending to a surface location. During downhole operations, high-frequency torsional oscillations (HFTOs) of the drill string may occur. The vibration shape, frequency, and amplitude (modal shape) of HFTOs depend primarily on the drill bit design type, the rock formation hardness, and the drilling parameters applied during the drilling operation. Also relevant are the rotational frequency of the drill string, the mass distribution within the drill string, and the torsional stiffness of the drill string. Optional conventional vibration sensors (including magnetometers and accelerometers) are typically positioned close to the drill bit to detect HFTOs. If a conventional vibration sensor happens to be located in a node of a torsional vibration mode, the sensor outputs only a small signal or no signal. However, HFTOs can still propagate upward from the drill bit through the BHA, resulting in significant HFTOs at other points along the BHA. Therefore, there is a need for a reliable system and method for detecting HFTOs in a BHA during drilling operations using existing technology. Summary of the Invention

[0004] A method for detecting vibration of a drill string in a borehole is disclosed. The method includes: conveying a drill string into a borehole, the drill string including a motor, the motor including a stator and a movable element, the movable element being movable relative to the stator; rotating the drill string in the borehole; determining, via a control circuit, a first amplitude of vibration of the drill string by measuring a signal indicating movement of the movable element in the motor due to the rotation of the drill string; and controlling, via the control circuit, downhole operation of the drill string based on the detected first amplitude of vibration.

[0005] This document also discloses a system for detecting vibrations of a drill string in a borehole. The system includes a motor in the drill string. The motor includes an electromagnet, a stator, a movable element capable of moving relative to the stator, and control circuitry. The control circuitry is configured to: control the magnetic field of the electromagnet; measure a signal indicating relative movement of the movable element relative to the stator due to vibrations of the drill string; determine a first amplitude of the vibrations of the drill string using the measured signal; and control downhole operations of the drill string based on the detected first amplitude of the vibrations of the drill string. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The following description should not be read as limiting in any way. Similar elements in the various figures are numbered similarly:

[0007] Figure 1 A drilling system in an illustrative embodiment is shown;

[0008] Figure 1A A drilling BHA and modal shape of torsional vibration is shown;

[0009] Figure 2 A detailed parts section of a bottom hole assembly of a drilling system is shown;

[0010] Figure 3 A timeline of various parameters affected by high frequency oscillation is shown; and

[0011] Figure 4 A detailed view of a tubular linear motor is shown. DETAILED DESCRIPTION

[0012] A detailed description of one or more embodiments of the devices and methods disclosed herein is presented with reference to the accompanying drawings.

[0013] Reference Figure 1A drilling system (100) is shown in an illustrative embodiment. The drilling system (100) includes a drill string (102) extending from a platform (106) at a surface location (108) into a borehole (104). The drill string (102) includes a drill bit (110) disposed at a bottom end and a bottom hole assembly (BHA) (112) uphole from the drill bit (110). The BHA (112) includes downhole components such as a downhole telemetry device (114) in communication with a surface decoder device (116) at the platform (106). The downhole telemetry device (114) can be a mud pulse generator and transmits pressure pulse signals from a downhole location to the surface through drilling fluid flowing within the drill string (102) to be received at the surface decoder device (116). The pressure pulses are formed by an electrical device (120) (such as a motor) housed within the downhole telemetry device (114). The motor can include an electric motor that drives a plunger of a plunger valve or a rotating or oscillating rotor or a shear valve in a mud pulse generator. During drilling, drilling fluid is pumped downhole through an inner bore of the drill string (102) to exit the drill string (102) through drill bit nozzles in the drill bit (110). The fluid then returns uphole through the borehole (104) within an annulus formed between the drill string (102) and the borehole (104) wall, thereby carrying cuttings out of the borehole. Thus, the drill string (102) and the borehole (104) are generally filled with drilling fluid. The BHA (112) can also include a mud motor (124) that includes a stator and a rotor, also referred to herein as a movable element. The mud motor (124) is driven or powered by drilling fluid flowing through the drill string (102) and the stator and produces rotation of the rotor. The mud motor (124) is configured to rotate the drill bit (110). The BHA (112) can include one or more formation evaluation devices (FE devices) (126) or components, such as a density measurement device, an acoustic travel time device, a pressure testing device, and a resistivity measurement device. To detect the orientation and drilling direction of the BHA (112) in the formation, the BHA (112) includes a measurement-while-drilling (MWD) tool (128) that includes directional sensors such as a magnetometer configured to measure the earth’s magnetic field and an accelerometer configured to measure gravity. In embodiments, the MWD tool (128) includes the telemetry device (114) and an electrical generator, such as an alternator. To detect drilling dynamics parameters, the BHA (112) can include a drilling dynamics measurement device (131) that includes sensors such as one or more accelerometers, one or more magnetometers, one or more bend sensors (e.g., strain gauges), one or more axial load sensors (e.g., load cells), and one or more temperature sensors.The sensors in the dynamic measurement device (131) are configured to detect the measurement signals at a high sampling rate, such as at least 1000 Hz, to resolve high dynamic processes, such as torsional vibrations. In an embodiment, the drill string (102) can include another electrical device or motor (130) that performs various operations downhole, such as, for example, an alternator in a downhole generator that converts the energy of the flow of drilling fluid into electrical energy. The BHA (112) can include any number of motors for various downhole operations or purposes, such as the motor (120) in a mud pulse generator and the motor (130) in a generator or any additional motors. One or more of the motors (120, 130) can be located inside the BHA (112) at any location along the longitudinal axis (A) of the BHA (112) and the drill string (102) and at a distance from the drill bit (110). Wherein the locations along the longitudinal axis (A) of the motor (120) and the motor (130) or any additional motors are different and the distances from the drill bit (110) are different. That is, the motor (120), the motor (130), and the additional motors are not located at the same location along the longitudinal axis (A) of the BHA (112). The motor (120) can be at a distance D2 from the drill bit (110) and the motor (130) can be at a distance D1 from the drill bit. As used in this application, a motor has a housing and the housing includes an electrical coil, such as an electrical coil in an electromagnet. The motor also includes a magnet, such as an electromagnet or a permanent magnet. The motor includes a moving part and a non-moving part, such as a rotor and a stator in an electric motor or an alternator. The electrical coil can be located in one of the moving part or the non-moving part. The magnet can be located in the other of the moving part or the non-moving part. In an embodiment, the motor also includes a resolver or an encoder.

[0014] The surface controller (118) at the surface location (108) can be used to control the operation of the drill string (102) (e.g., drilling operations) by changing drilling parameters of the drill string (102), such as the rotational speed (revolutions per minute, RPM) of the drill string (102) and the drill bit (110), the flow rate of the drilling fluid, and the weight applied to the drill bit (weight on bit, WOB). The downhole controller (119) is included in the BHA (112) and is configured to automatically control the operation of the drill string (102) without the interaction of the surface controller (118) or a human. The downhole controller (119) can control the drilling direction, control the downhole data acquisition (FE device), control the communication with the surface controller (118). The drilling direction can be controlled by adjusting the kick-off section (AKO) in the orienting downhole motor or controlling a steering device (not shown) in the BHA, such as a rotary steerable unit. The drill string can be operated by the surface controller (118) or the downhole controller (119) based on the HFTO detected by the motor and / or the conventional vibration sensors.

[0015] In one embodiment, the drill string (102) can include a conventional vibration sensor (122) disposed at or near the drill bit (110) or at any other location in the BHA (112). The conventional vibration sensor (122) is a velocity sensor, an accelerometer, or a magnetometer. The conventional vibration sensor (122) is configured to detect vibrations, including high frequency torsional oscillations (HFTO), that can be generated during drilling, for example, by cutting forces at the drill bit (110) or mass imbalances in components of the BHA (112) such as the mud motor (124). The effects of HFTO can include, but are not limited to, a reduction in rate of penetration (ROP) of the drilling process, a reduction in quality of downhole measurements (FE data), and excessive fatigue and wear of downhole components, tools, and / or devices. If no additional vibration sensors are present in the BHA (112) in addition to the conventional vibration sensor (122), the presence and amplitude of these propagating HTFO can not be detected by the single conventional vibration sensor (122). For example, if the single conventional vibration sensor (122) is located in a node of the torsional vibration mode, the sensor (122) outputs only a small signal or no signal despite the fact that significant HFTO can be occurring at other points in the BHA (112). In one embodiment, a second vibration sensor positioned near an anti-node of the torsional vibration mode is capable of detecting the HFTO. Thus, utilizing at least two vibration sensors, such as a conventional vibration sensor and an additional vibration sensor of some type, allows for detection of the modal shape of the HFTO oscillations propagating along the drill string (102). The particular modal shape is associated with a natural frequency of the BHA (112) or drill string (102). The second vibration sensor can be another conventional vibration sensor or can be a different type of vibration sensor. In various embodiments, the second vibration sensor can be a device or part of a device already present in the drilling BHA (112) for another downhole operation or purpose, such as a motor used within a mud pulse generator or an alternator used for power generation. The motor can be part of a measurement-while-drilling tool, which typically includes a power generation module (alternator) and a telemetry device such as a mud pulse generator. In alternative embodiments, the motor can be included in any other component of the BHA (112), such as a formation evaluation device (e.g., a pressure testing device) or a coring device. The motor in the BHA (112) has a dedicated purpose or is intended to perform a dedicated downhole operation, such as power generation, pressure pulse signal generation, coring bit rotation (coring bit motor), etc. Utilizing the motor for multiple purposes or multiple downhole operation purposes in order to also detect torsional vibrations allows for space savings for a dedicated conventional vibration sensor. In addition to this, the number of devices in the BHA (112) is reduced, which devices require maintenance and can potentially fail, resulting in costly non-productive time in the operation of the drill string.

[0016] HFTO oscillations or vibrations are used in the same broad sense of repetitive and / or periodic movement or periodic deviations in the mean value such as mean position, mean velocity, mean acceleration, mean force and / or mean torque as disclosed herein. In particular, these terms are not intended to be limited to harmonic deviations but can include all kinds of deviations such as, but not limited to, periodic, harmonic and statistical deviations. As understood by the skilled person, there are different vibrations such as lateral, axial and torsional vibrations. For example, both stick / slip of the entire drill string and HFTO are types of torsional vibrations. Torsional vibrations can be excited by a self-excitation mechanism due to the interaction of the drill bit or any other cutting structure such as a reamer with the formation. The main point of distinction between stick / slip and HFTO is the frequency and typical mode shape. For example, HFTO has a frequency typically above 50 Hz, in contrast to stick / slip torsional vibrations which typically have a frequency below 1 Hz. Furthermore, the excited mode shape of stick / slip is typically the first mode shape of the entire drill string, whereas the mode shape of HFTO can be of higher order and is typically localized to a smaller portion of the drill string and relatively high at the excitation point which can be the drill bit or any other cutting structure such as a reamer or any contact between the drill string (102) and the formation (e.g. by stabilizers). HFTO or torsional vibrations are generally represented by oscillatory tangential acceleration, where tangential here refers to the direction tangential to the circumference of the BHA or downhole component in a cross-section perpendicular to the longitudinal axis (A) of the BHA or downhole component.

[0017] Figure 1A A BHA (112) of the drill string (102) in an illustrative embodiment is shown. The BHA (112) includes a conventional vibration sensor (122) positioned near the drill bit (110) or anywhere else in the BHA. The conventional vibration sensor (122) is capable of detecting high frequency torsional oscillations (HFTO). In various embodiments, the conventional vibration sensor (122) can be a velocity sensor, a set of accelerometers, a magnetometer, etc. Figure 1AVarious torsional vibration modes are further illustrated: Mode 1, Mode 2, Mode 3, and Mode 4. Each torsional vibration mode is characterized by its mode shape (amplitude (i.e., along the BHA) and frequency and its nodes and antinodes, which occur at various locations along the BHA (112). Modes 1 and 2 have high amplitudes at the location of the conventional vibration sensor (122), while Modes 3 and 4 have small amplitudes (or nodes) at the location of the conventional vibration sensor (122). However, the amplitudes of Modes 3 and 4 can be significant at locations away from the conventional vibration sensor (122). The motor (120) is located at a location (132) along the longitudinal axis (A) of the BHA (112). At the location (132), the amplitude of Mode 3 (i.e., amplitude (134)) and the amplitude of Mode 4 (i.e., amplitude (136)) are significant. In one embodiment, the motor (120) acts as an additional sensor (such as a second vibration sensor) for detecting vibration modes (such as Modes 3 and 4) that would otherwise not be detectable or identifiable by only a single conventional vibration sensor (122) in the BHA. The motor (120) acts as an additional or second vibration sensor. Identifying the mode shape of a vibration mode requires at least two vibration sensors placed at different locations along the longitudinal axis (A) of the BHA (112). The second vibration sensor (motor 120) in combination with the conventional vibration sensor (122) (velocity sensor, accelerometer, or magnetometer) can verify or identify the occurrence of a particular HFTO mode (vibration mode) by matching the frequency and amplitude (mode shape) to the HFTO modes derived from simulations (e.g., modal analysis) performed for a particular BHA (e.g., BHA (112)). In the simulations, the BHA (112) can be represented by a BHA model that defines various diameters, material properties, locations of component connections, locations of particular devices (FE devices, mud motors, steering units, MWD tools, stabilizers, etc.). The simulations can be performed at the surface before or after the downhole operation. In an alternative embodiment, the simulations can be performed downhole using the downhole controller (119) during the downhole operation.

[0018] Figure 2A detailed view of a component segment (200) of an electric machine (120) in an implementation is shown. The component segment (200) is located inside a downhole component or tool in the BHA (112), such as, for example, a telemetry device (114). The downhole component includes a main body (201). The main body provides an interior space, such as, for example, an inner bore (203). The component segment (200) of the electric machine (120) is located within the interior space of the main body (201) of the BHA (112). The interior space can also allow drilling fluid (232) to flow through the downhole component on its way from the surface to the bottom end of the BHA (drill bit (110)). The drilling fluid (232) can flow around the component segment (200) of the electric machine (120). An outer surface of the main body (201) defines an annular bore wall between the BHA (112) and the borehole wall. The outer surface of the main body (201) is in contact with the drilling fluid flowing through the annular bore on its way from the bottom end of the drill bit back to the surface. The component segment (200) includes an electric motor (202) disposed in a housing (204). An outer surface of the housing (204) can be in contact with the drilling fluid. The housing (204) is mechanically coupled to the BHA (112), such as, through a MWD tool or downhole telemetry device (114). In an implementation, the electric machine (120) is coupled to the main body (201) of the downhole component. The housing (204) is coupled to an inner surface of the main body (201) of the downhole component. The coupling of the electric machine (120) to the downhole component of the BHA (112) ensures that vibrations acting on the BHA (112) are transmitted to the electric machine (120) that detects the vibrations. Typically, the housing (204) of the electric machine (120) is positioned along a central axis of the BHA (112) or drill string (102). The central axis is parallel to the longitudinal axis (A) and represents the axis of rotation of the BHA (112) or drill string (102).

[0019] The electric motor (202) includes a stator (206) and a rotor (208). The stator (206) is stationary relative to the body (201). The rotor (206) is rotatable relative to the stator (206) and the body (201). The stator (206) includes electromagnets (210), and the rotor (208) includes magnets, such as permanent magnets (212). The electromagnets (210) include one or more electrical coils. In embodiments, the electromagnets include a magnetic core. In various embodiments, the stator (206) includes a plurality of electromagnets, and the rotor (208) includes a plurality of magnets. The plurality of magnets of the rotor (208) interact with the plurality of electromagnets of the stator (206) to produce rotation of the rotor (208). The electromagnets (210) are powered and controlled by a control circuit (214), which can include an electronic module or electronic circuit or processor, a current and / or voltage measurement module, and a power source. The control circuit (214) is disposed in the BHA, such as, for example, in the telemetry tool (114) or the MWD tool, and is connected to the electromagnets (210) by a first transmission line (216). In other embodiments, both the stator (206) and the rotor (208) can include electromagnets, or the stator (206) can include permanent magnets and the rotor can include electromagnets. For example, a rotor shaft (222) couples the rotor (208) to additional elements, such as components for mud pulse telemetry, a rotary shear valve, or a coring bit. The rotor shaft (222) is guided by bearings (230) that allow the rotor shaft (222) to rotate. The axis of rotation (B) of the rotor (208) of the electric motor (120) coincides with the central axis of the BHA (112). The rotor itself has an inertia or is connected to an inertia (such as the inertia of the additional elements). Tangential forces caused by torsional vibrations acting on the BHA (112) also act on the inertia associated with the rotor (208) of the electric motor (120). In this way, the torsional vibrations cause the rotor (208) of the electric motor (120) to rotate or oscillate around the central axis of the BHA (112) and the axis of rotation of the rotor (208).

[0020] A resolver (218) (or encoder) measures the angular position of the rotor (208) relative to the stator (206) and generates a resolver signal indicative of this angular position. The resolver or encoder can be a magnetic device, an optical device, or a mechanical device. The resolver (218) sends the resolver signal to the control circuit (214) via a second transmission line (220). The control circuit (214) receives the resolver signal and determines the angular position of the rotor (208) relative to the stator (206) from the resolver signal. The control circuit (214) compares the angular position to a desired angular position and controls the current used at the electromagnets (210) of the stator (206) to control, modify, or adjust the timing of the electromagnets (210) to adjust the angular position of the rotor (208) to the desired angular position. Desired angular position as used herein refers to the angular position of normal rotor movement in the normal use of the motor. In this document, normal use is also referred to as the first intended use or first operational operational use of the motor, such as driving a pulser valve, driving a coring bit, generating electrical power, or measuring length. Torque applied to the rotor (208) (e.g. related to torsional vibrations acting on the inertia) creates a deviation between the actual angular position of the rotor and the target angular position (desired angular position) of the rotor. This deviation in turn causes an increase in current, which the controller detects and which the controller uses to bring the actual angular position of the rotor back into agreement with the target position. Torque can be applied to the motor for a variety of reasons, including inertia-induced torque. When subjected to angular acceleration (due to torsional vibrations), the inertia from the additional elements and the rotor itself creates a torque at the rotor shaft (222) that causes an increase in current, which is used by the controller to control the motor as described herein. Tangential forces caused by torsional vibrations acting on the BHA (112) also act on the inertia of the additional elements associated with the rotor (208) of the motor (120). In this way, the torsional vibrations cause superimposed rotation or oscillation of the rotor (208) within the stator (206) of the motor (120) and about the central axis of the BHA and the rotational axis (B) of the rotor (208). The superimposed rotation or oscillation is caused by the torsional vibrations acting on the downhole components including the motor (120). The superimposed rotation or oscillation is superimposed on the rotation or oscillation of the rotor in the motor (120) that is related to the first intended use of the motor (120). The second intended use (second downhole operational use) of the motor (120) is to detect torsional vibrations and / or to detect torsional vibration modes. That is, the motor (120) is installed in the BHA (112) for a first purpose or to perform a first downhole operation. In a drilling operation, the motor is used for the first purpose but also for a second purpose or to perform a second downhole operation, such as detecting torsional vibrations in a vibration sensor use. The additional use of the motor (120) as a vibration sensor is referred to as a dual purpose use or dual downhole operational use.The dual purpose use of the motor (120) in the BHA (112) allows for detection of vibrations at locations along the longitudinal axis (A) of the BHA (112) at which conventional vibration sensors are not installed.

[0021] Accordingly, the angular position of the rotor (208) can be disturbed by the HFTO present on the motor (120) housed in the downhole telemetry device (114). When the HFTO is applied to the drill string (102) and transmitted to the components of the BHA (112) housing the motor (120), the resulting tangential acceleration of the inertia associated with the rotor (208) creates a torque at the electric motor (202) and at the rotor (208), affecting the relative angular position or movement between the stator (206) and the rotor (208). This affected relative position or movement is due in part to the inertia of the rotor shaft (222) and the rotor (208) and additional components coupled to the rotor (208) along the rotor shaft (222) that are accelerated by the HFTO acting on the inertia of the additional components and the inertia of the rotor (208). The resolver (218) measures this relative movement of the rotor (208) with respect to the stator, and the control circuit (214) corrects for this relative movement by controlling the motor signal sent to the electromagnets (210) to bring the angular position of the rotor (208) with respect to the stator (206) back to the desired angular position. The motor signal can be a current signal or a voltage signal. In various embodiments, the control circuit (214) controls the amplitude of the current signal. The amplitude of the current signal is proportional to the amplitude of the relative torsional acceleration, and thus proportional to the amplitude of the HFTO. Accordingly, the control circuit (214) can control the voltage of the motor signal transmitted to the electromagnets (210). As described, the control circuit (214) can use the resolver signal to detect torsional vibrations of the BHA (112). In alternative embodiments, the control circuit (214) can use the voltage induced in the electromagnet coils in the stator (206) caused by the movement of the rotor (208). The rotor (208) includes a magnet (permanent magnet or electromagnet). The movement of the rotor (208) includes normal movement (desired movement) based on the first intended use of the motor (120). Superimposed on this normal movement is movement caused by torsional vibrations acting on the BHA (112) and the inertia associated with the rotor (208) that is sourced from the drilling process in the drilling operation. The superimposed movement of the rotor (208) within the stator (206) causes a change in magnetic flux in the electromagnet coils of the stator (206), resulting in an electromotive force that manifests as a voltage. The polarity of this voltage is opposite to the polarity of the applied voltage (back emf) controlled by the control circuit. Accordingly, the back emf modifies the voltage from the control circuit (214) to the electromagnets of the motor (120). This effect allows the control circuit (214) to detect torsional vibrations via the control signal to the electromagnets of the stator (206).

[0022] In one embodiment, the electric machine (120) is an alternator and is used to generate electrical energy in the BHA (112). The electrical energy can be used by the mud pulse generator to power the electric motor driving the pulse generator valve, to power the electric motor of the coring bit, or to power the hydraulic pumps in the BHA (112). The electrical energy can also be used to power the electronic boards used in the BHA (112) to control downhole operations, process data, store acquired data provided by downhole sensors, control hydraulic units, and other operations. Since the alternator is similarly designed as a motor, it can be used to detect vibrations in the same manner as previously described with respect to the electric machine (120) Figure 2 ) The alternator includes a rotor and a stator (206). The stator (206) can include coils as part of the electromagnet, and the rotor (208) can include permanent magnets or electromagnets. In an alternative embodiment, the rotor includes coils as part of the electromagnet, and the stator (206) can include permanent magnets or electromagnets. The turbine is connected to the rotor (208). When the turbine is rotated, such as by the flowing drilling fluid (232), the rotor (208) rotates and induces a voltage in the electromagnet coils in the stator (206). If the rotation or oscillation of the rotor (208) caused by vibrations (e.g., torsional vibrations) is superimposed to the rotation of the turbine, a back electromotive force (voltage or current at the coils) can be detected at the coils in the stator. The control circuit (214) is used to analyze the voltage or current at the coils and detect vibrations. In Figure 1 , the electric machine (120) can be a pulse motor, and the electric machine (130) can be an alternator. Both electric machines can be used in a dual-purpose usage modality. The electric machine (120) is used as a pulse motor (electric motor) and as a vibration sensor, and the electric machine (130) is used as a generator (alternator) and as a vibration sensor. Together with the conventional vibration sensor (122) in Figure 1 , the three vibration sensors will be at three different locations in the BHA (112) along the longitudinal axis (A) of the BHA (112), thereby allowing not only detecting the occurrence of torsional vibrations, but also identifying the torsional vibration modal shape. Two vibration sensors are used to identify the vibration modal by analyzing the vibration data acquired by the two vibration sensors. Thus, the electric machine (120) and the electric machine (130) used in a dual-purpose usage modality are sufficient to detect and identify the vibration modal. Alternatively, the electric machine (120) together with the conventional vibration sensor (122) in a dual-purpose usage, or the electric machine (130) together with the conventional vibration sensor (122) in a dual-purpose usage, are sufficient to detect and identify the vibration modal.

[0023] Figure 3A timeline (300) is shown of various parameters affected by high frequency torsional oscillations. A first plot (302) shows motor current (also referred to herein as a vibration signal detected by the motor) in amperes (A) along its ordinate axis. A second plot (304) shows tangential acceleration (also referred to herein as a vibration signal detected by a conventional vibration sensor) in units of gravitational acceleration (g) along its ordinate axis. The conventional vibration sensor here is an acceleration sensor. The first plot (302) and the second plot (304) share the same abscissa, which shows time (e.g., in seconds (sec)). Figure 3 The length of the time interval shown is 190 minutes or 11.400 seconds. The left vertical line corresponds to 0 seconds and the right vertical line refers to 100 minutes or 6000 seconds. The vibration signal detected by the motor and the vibration signal detected by the conventional vibration sensor are stored in memory and analyzed by the control circuit (214).

[0024] Referring to the second plot (304), the time period shown includes a low tangential vibration region (306) with no or relatively small HFTO amplitude (small tangential acceleration) and a high tangential vibration region (308) of HFTO where there is significant HFTO amplitude (large tangential acceleration). The low tangential vibration region (306) can be one or more regions and the high tangential vibration region can be one or more regions.

[0025] Referring now to the first graph (302), both the raw or unfiltered data set (310) of the current signal and the filtered data set (312) of the current signal are shown. The filtered data set can include data filtered for noise reduction. The low amplitude of the current signal corresponds to the low tangential vibration region (306). The high amplitude of the current corresponds to the high tangential vibration region (308). This amplitude difference can be seen in both the unfiltered data set (310) and the filtered data set (312). The no HFTO or no vibration average current (314) shows the average of the current amplitude corresponding to the low vibration region (306). This average current (314) can correspond to typical or normal operation of the motor (130), such as driving a mud pulse telemetry valve. Normal operation assumes that no HFTO is acting on the motor (120). This average can be used as a baseline current signal, also referred to herein as a baseline signal. The baseline signal can be used to calculate a threshold (e.g., a threshold current) that can be used to indicate a need for HFTO mitigation, such as performing a mitigation operation. The threshold current can be experimentally defined using torsional vibration data recorded in drilling operations and correlated to a wear state or failure occurrence. The threshold current is then related to the torsional vibration amplitude that causes wear or component failure in the BHA (112). In alternative embodiments, the threshold current can be related to the amplitude of the baseline signal. The threshold current can be defined as a multiple of the baseline signal. In one embodiment, the threshold can be defined as twice the current value of the amplitude of the baseline signal. For example, if the current measured in the high tangential vibration region exceeds twice the amplitude of the baseline signal current, the HFTO is defined as detected. In embodiments, the threshold current can be defined as any multiple (1.5 times, 3 times, 10 times, etc.) of the amplitude of the baseline signal current. In one or more embodiments, the threshold is related to the standard deviation of the amplitude baseline signal. HFTO mitigation can include adjusting the drilling operation, such as adjusting an operating parameter. The operating parameter adjusted to mitigate the HFTO can include the weight on bit (WOB), the rotational speed (RPM), the flow rate of the drilling fluid, or the drilling direction.

[0026] The high vibration average current (316) shows the average of the current amplitude corresponding to the high tangential vibration region (308). The high vibration average current (316) can be compared to the baseline signal. When the high vibration average current (316) exceeds a threshold current, the presence of an HFTO is detected. Additionally, when an HFTO is present, not only can its presence be detected, but its amplitude and frequency can be detected. Using the high detection sampling rate of the current signal (e.g., 1000 Hz), the instantaneous amplitude and frequency of the HFTO can be derived by filtering the current signal and subtracting the average current signal when no HFTO is present from the filtered signal. The control circuit (214) analyzes the recorded current signal (vibration signal detected by the motor) to determine the frequency content. The analysis can include a Fast Fourier Transform (FFT), a Power Spectral Density analysis (PDS), or another alternative frequency analysis technique. When the high vibration average current (316) exceeds a threshold current established by the baseline signal, an alert can be transmitted from the downhole telemetry device (114) to the surface decoder device (116). In another embodiment, the controller can detect the instantaneous amplitude and frequency of the HFTO and transmit these values to the surface. In response, the controller (118) or operator can control or adjust the drilling parameters applied to the drill string (102) to reduce the magnitude or presence of the HFTO (mitigation operation). For example, the controller (118) or operator can reduce the RPM or WOB or a combination of these.

[0027] In various embodiments, the current signal corresponding to the high tangential vibration region (308) can be compared to the current signal corresponding to the low vibration region (306) in the time domain or in the frequency domain (FFT). When the comparison is made in the frequency domain, the frequency of the HFTO in the high tangential vibration region can also be detected.

[0028] Figure 4A detailed view of another type of motor located in the drill string (102), such as a tubular linear motor (400), is shown. The tubular linear motor (400) is used to detect vibrations in the drill string. Depending on the orientation relative to the longitudinal axis of the drill string, the linear motor can detect axial or lateral vibrations in a similar manner to how a rotary motor can detect torsional vibrations. The linear motor includes a stator (402) and a mover (401), also referred to herein as a movable element. The stator (402) surrounds the mover and the mover is movable within the stator (402). The stator (402) is stationary relative to the drill string (102). The mover includes a plurality of magnets (403), typically permanent magnets. The stator (402) includes a plurality of electromagnets (404), each including an electrical coil (405) and a magnetic core. The electromagnets are located in a stator iron (406). The pole orientation of the magnets (403) in the mover forms a magnetic field that is 90 degrees relative to the magnetic field formed by the plurality of electromagnets (404). Typically, the linear motor operates on a three-phase power supply to provide current to the plurality of electromagnets (404) in the stator (402). The varying phase between adjacent electromagnets (404) and the corresponding varying orientation of the resulting magnetic field in the stator (402) interacts with the magnetic field of the magnets (403) in the mover (401) and moves the mover (401) relative to the stator (402). Acceleration acting on the inertia of the mover (401) due to drill string vibrations causes a change in the current provided to the electromagnets (404) in the stator (402) by the power supply (counter electromotive force). A control circuit (406) connected to the plurality of electromagnets (404) by a transmission line (407) controls the current provided to the plurality of electromagnets (404). The control circuit (406) is configured to measure the current or voltage and detect changes in the current or voltage on the power provided to the plurality of electromagnets (404), thereby providing a current signal or a voltage signal. Analysis of the current or voltage signal allows detection of vibrations of the drill string and determination of the vibration amplitude and frequency, as previously described. The linear motor can include an encoder (408) that monitors the movement of the mover relative to the stator (402). In one embodiment, the control circuit (406) can detect vibrations of the drill string by measuring and analyzing the encoder signal. Other linear motor types exist, such as core motors or U-slot motors, which can be used in place of the tubular linear motor to detect vibrations. The mover (401) can be coupled to additional elements, such as a component to be moved by the mover. The additional elements (not shown) increase the inertia of the mover, making the mover more sensitive to vibrations. As described for the rotary motor, the linear motor located in the drill string is used for dual-purpose use. The first purpose use of the linear motor can be to drive a downhole robotic arm, to drive a piston valve, to process and store a core after it is drilled, to measure displacement, to activate various downhole operations such as extracting pads or blades. The second purpose use is as a vibration sensor. The mover of the linear motor includes a longitudinal axis (T).When the longitudinal axis (T) of the mover extends along the longitudinal axis (A) of the drill string, the linear motor can detect axial vibrations. The longitudinal axis (T) of the mover can be parallel to the longitudinal axis (A) of the drill string, or can be at a small angle, such as between 0.1 and 10 degrees, from the longitudinal axis (A) of the drill string. When the longitudinal axis (T) of the mover of the linear motor extends perpendicular to the longitudinal axis (A) of the drill string, the linear motor can detect lateral vibrations. The longitudinal axis (T) of the mover can be at 90 degrees to the longitudinal axis (A) of the drill string, or can be slightly off perpendicular, such as between 0.1 and 10 degrees off perpendicular, from the longitudinal axis (A) of the drill string. The tubular linear motor (400) is located inside a housing (not shown). The housing including the tubular linear motor can be located inside the drill string and inside the body of a downhole component (not shown), such as inside a bore of the downhole component. In this case, the housing with the linear motor is in contact with the downhole fluid flowing through the bore. In an alternative embodiment, the linear motor can be located in a collar (not shown) of a downhole component of the drill string. In this case, the linear motor is housed in a recess of the collar and can be isolated from the downhole environment by a cover. In another embodiment, a solenoid surrounding a magnet or magnetic material, when used with a valve of a plunger-based mud pulser (solenoid valve), can be used to detect vibrations of the drill string. In this embodiment, the current provided to the solenoid to move the magnet to close or open the valve is monitored by a control circuit to detect and analyze vibrations. In this embodiment, the first purpose of the solenoid valve is valve movement, and the second purpose is vibration detection. In yet another embodiment, a linear variable differential transformer (LVDT) can be used to detect vibrations. In this embodiment, the first purpose of use of the LVDT is measurement of linear displacement, and the second purpose of use of the LVDT is vibration detection by observing the back electromotive force caused by vibrations of the drill string, which is transferred to the movable component of the LVDT.

[0029] Some embodiments of the foregoing disclosure are illustrated below:

[0030] Embodiment 1. A method of detecting vibrations of a drill string in a borehole, the method comprising: conveying the drill string into the borehole, the drill string including an electric motor, the electric motor including a stator and a movable element, the movable element being movable relative to the stator; rotating the drill string in the borehole; determining, via a control circuit, a first amplitude of the vibrations of the drill string by measuring a signal, the signal being indicative of movement of the movable element in the electric motor due to rotation of the drill string; and controlling, via the control circuit, downhole operations of the drill string based on the detected first amplitude of the vibrations.

[0031] Embodiment 2. A method according to any preceding embodiment, wherein detecting the first amplitude of the vibration of the drill string comprises measuring at least one of: (i) current; and (ii) voltage, the voltage being supplied to a coil located within the motor.

[0032] Embodiment 3. A method according to any of the preceding embodiments, wherein detecting the first amplitude of the vibration of the drill string includes detecting a signal of at least one of: (i) a rotary transformer; and (ii) an encoder associated with the movable element in the motor.

[0033] Embodiment 4. The method of any preceding embodiment, wherein controlling the downhole operation comprises performing a mitigation operation when the detected first amplitude of the vibration exceeds a threshold.

[0034] Embodiment 5. A method according to any of the preceding embodiments, wherein the drill string includes a longitudinal axis, and the motor and vibration sensor are located at different positions along the longitudinal axis in the drill string, the method further comprising: using the vibration sensor to determine a second amplitude of the vibration of the drill string, and using the first amplitude of the vibration of the drill string and the second amplitude of the vibration of the drill string to identify a vibration mode of the vibration of the drill string.

[0035] Embodiment 6. The method of any preceding embodiment, wherein the vibration sensor is one of an accelerometer and a magnetometer.

[0036] Embodiment 7. The method of any preceding embodiment, wherein the vibration sensor is another motor in the drill string.

[0037] Embodiment 8. The method of any preceding embodiment, wherein identifying the vibration mode of the vibration of the drill string comprises using simulation.

[0038] Embodiment 9. A method according to any preceding embodiment, wherein the electric machine is one of a motor and an AC generator.

[0039] Embodiment 10. The method according to any preceding embodiment, wherein the vibration of the drill string is a high frequency torsional oscillation (HFTO).

[0040] Embodiment 11. The method of any preceding embodiment, further comprising determining, using the control circuit, a frequency of the detected first amplitude of the vibration of the drill string.

[0041] Embodiment 12. A system for detecting vibrations of a drill string in a borehole. The system includes a motor in the drill string and a control circuit. The motor includes an electromagnet, a stator, and a movable element movable relative to the stator. The control circuit is configured to: control a magnetic field of the electromagnet; measure a signal indicative of a relative movement of the movable element relative to the stator due to vibrations of the drill string; determine a first amplitude of the vibrations of the drill string using the measured signal; and control a downhole operation of the drill string based on the detected first amplitude of the vibrations of the drill string.

[0042] Embodiment 13. The system of any preceding embodiment, wherein the measured signal is at least one of: (i) a current; and (ii) a voltage provided to the electromagnet.

[0043] Embodiment 14. The system of any preceding embodiment, further comprising a resolver or an encoder, wherein the measured signal is at least one of: (i) a resolver signal; and (ii) an encoder signal.

[0044] Embodiment 15. The system of any preceding embodiment, wherein the movable element is one of a rotor and a mover.

[0045] Embodiment 16. The system of any preceding embodiment, wherein the vibrations are high frequency torsional oscillations (HFTOs).

[0046] Embodiment 17. The system of any preceding embodiment, wherein the motor is one of a motor and an alternator.

[0047] Embodiment 18. The system of any preceding embodiment, further comprising a vibration sensor in the drill string, the motor and the vibration sensor being located at different locations along a longitudinal axis of the drill string, wherein the control circuit is configured to determine a second amplitude of the vibrations of the drill string using the vibration sensor, and to identify a vibration mode of the vibrations of the drill string using the first amplitude of the vibrations of the drill string and the second amplitude of the vibrations of the drill string.

[0048] Embodiment 19. The system of any preceding embodiment, wherein the vibration sensor is one of an accelerometer and a magnetometer.

[0049] Embodiment 20. The system of any preceding embodiment, wherein the vibration sensor is another motor in the drill string.

[0050] The use of the terms "a" and "an" and "the" and similar referents in the context of describing the application (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should be noted that the terms "first," "second," and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The terms "about," "substantially," and "approximately" are intended to encompass the error associated with measuring a particular quantity, based on the equipment available at the time of filing the application. For example, "about" and / or "substantially" and / or "approximately" can include a range of ± 8% or 5%, or 2% of a given value.

[0051] The teachings of the present disclosure can be used in a variety of well operations. These operations can involve treating a formation, a fluid residing in the formation, a wellbore, and / or equipment in the wellbore, such as production tubing, with one or more treatment agents. The treatment agents can be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Exemplary treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, corrosion inhibitors, cementing agents, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers, and the like. Exemplary well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water injection, cementing, and the like.

[0052] While the application has been described with reference to one or more example embodiments, it will be understood by those skilled in the art that various changes can be made and equivalents can be substituted for elements thereof without departing from the scope of the application. In addition, many modifications can be made to adapt a particular situation or material to the teachings of the application without departing from the essential scope thereof. Therefore, it is intended that the application not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this application, but that the application will include all embodiments falling within the scope of the claims. Also, in the drawings and the specification, there have been disclosed exemplary embodiments of the application and, although specific terms are employed, they are used in a generic and descriptive sense only and not for purposes of limitation, otherwise, the scope of the application thus not to be construed as being limited to the specific embodiments set forth herein but to include all embodiments falling within the scope of the claims.

Claims

1. A method of detecting vibrations of a drill string (102) in a borehole (104), the method characterized by: transmitting the drill string (102) into the borehole (104), the drill string (102) including an electric machine (120, 130), the electric machine (120, 130) including a stator (206, 402) and a movable element (208, 401), the movable element (208, 401) being movable relative to the stator (206, 402); rotating the drill string (102) in the borehole (104); determining, via a control circuit (214), a first amplitude of the vibrations of the drill string (102) by measuring a signal indicative of movement of the movable element (208, 401) in the electric machine (120, 130) due to rotation of the drill string (102); and controlling, via the control circuit (214), a downhole operation of the drill string (102) based on the detected first amplitude of the vibrations.

2. The method of claim 1, wherein detecting the first amplitude of the vibrations of the drill string (102) includes measuring at least one of: (i) a current; and (ii) a voltage provided to a coil (405) located inside the electric machine (120, 130).

3. The method of claim 1, wherein detecting the first amplitude of the vibrations of the drill string (102) includes detecting a signal of at least one of: (i) a rotary transformer (218); and (ii) an encoder (408) associated with the movable element (208, 401) in the electric machine (120, 130).

4. The method of claim 1, wherein controlling the downhole operation includes performing a mitigation operation when the detected first amplitude of the vibrations exceeds a threshold value.

5. The method of claim 1, wherein the drill string (102) includes a longitudinal axis (A), and the electric machine (120, 130) and a vibration sensor (122) are located in the drill string (102) at different locations along the longitudinal axis (A), the method further characterized by determining a second amplitude of the vibrations of the drill string (102) using the vibration sensor (122), and identifying a vibration mode of the vibrations of the drill string (102) using the first amplitude of the vibrations of the drill string (102) and the second amplitude of the vibrations of the drill string (102).

6. The method of claim 5, wherein the vibration sensor (122) is one of an accelerometer and a magnetometer.

7. The method of claim 1, wherein the electric machine (120, 130) is one of a motor (202) and an alternator.

8. The method of claim 1, further characterized by: determining, using the control circuit (214), a frequency of the detected first amplitude of the vibrations of the drill string (102).

8. The method of claim 1, wherein the electric machine (120, 130) is a motor (202) and the control circuit (214) is a motor controller (212).

9. A system for detecting vibrations of a drill string (102) in a borehole (104), the system characterized by: a motor (120, 130) in the drill string (102), the motor (120, 130) comprising an electromagnet (210), a stator (206, 402), and a movable element (208, 401) movable relative to the stator (206, 402); a control circuit (214) configured to: control a magnetic field of the electromagnet (210); measure a signal indicative of a relative movement of the movable element (208, 401) relative to the stator (206, 402) due to the vibrations of the drill string (102); determine a first amplitude of the vibrations of the drill string (102) using the measured signal; and control a downhole operation of the drill string (102) based on the detected first amplitude of the vibrations of the drill string (102).

10. The system of claim 9, wherein the measured signal is at least one of: (i) a current; and (ii) a voltage provided to the electromagnet (210).

11. The system of claim 9, further characterized by a rotary transformer (218) or an encoder (408), wherein the measured signal is at least one of: (i) a rotary transformer signal; and (ii) an encoder signal.

12. The system of claim 9, wherein the movable element (208, 401) is one of: a rotor (208) and a mover (401).

13. The system of claim 9, wherein the motor (120, 130) is one of: a motor (202) and an alternator.

14. The system of claim 9, further characterized by a vibration sensor (122) in the drill string (102), the motor and the vibration sensor (122) being located at different positions along a longitudinal axis of the drill string (102), wherein the control circuit (214) is configured to: determine a second amplitude of the vibrations of the drill string (102) using the vibration sensor (122); and identify a vibration mode of the vibrations of the drill string (102) using the first amplitude of the vibrations of the drill string (102) and the second amplitude of the vibrations of the drill string (102).

15. The system of claim 14, wherein the vibration sensor (122) is one of: an accelerometer and a magnetometer.

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